ConocoPhillips (COP) Q2 2011 Earnings Report, Transcript and Summary

Welcome to the Second Quarter 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, Corporate and Investor Relations. Mr. Reasor, you may begin.

Thank you, Kim. Good morning, and welcome to ConocoPhillips Second Quarter Earnings Conference Call. We appreciate your interest in our company. I'm joined today by Jeff Sheets, Senior Vice President of Finance and our Chief Financial Officer. As we normally do, we'll provide a summary of our key financial and operating results for the second quarter as well as an outlook for the remainder of 2011. We'll also provide you with a brief update on the repositioning of ConocoPhillips as 2 separate leading energy companies as we announced 2 weeks ago. You can find our presentation material in the Investor Relations section of the ConocoPhillips website. Before we get started, I'd like to take a look at the Safe Harbor statement that we've shown on the next slide. It's a reminder that we will be making forward-looking statements during the presentation and during the question-and-answer session. Actual results may differ materially from what we present today, and factors that could cause actual results to differ 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, who will take you through our prepared remarks and presentation. Jeff?

Thanks, Clayton. I'll start on Slide 2, which highlights some of our second quarter results. During the second quarter, we had adjusted earnings of $3.4 billion. That's $2.41 a share. That compares to adjusted earnings of $1.63 a share in the second quarter of 2010. During the quarter, we generated cash from operations of $4.44 per share. This was a good quarter for the company. We ran well both in E&P and R&M. Second quarter production was 1.64 million BOE per day. Our global refining utilization was 91% during the quarter. We generated $6.3 billion in cash from operations. Our annualized return on capital employed was 15% for the quarter, and our cash return on capital employed was 24%. Also, during the quarter, we distributed $4 billion in cash to our shareholders in the form of shareholder distributions -- share repurchases and dividends. Our repurchase of 42 million shares this quarter represented about 3% of our shares outstanding. In our earnings release this morning, we highlighted that in addition to creating value for our shareholders at ConocoPhillips, activities also contribute substantially to job creation and economic growth. Slide 3 recaps some of the numbers associated with our activities for the first half of the year. During the first half of 2011, the company spent $6.5 billion on operating expenses, which supported 30,000 jobs at ConocoPhillips, as well as jobs at our suppliers and contractors. A further $6.1 billion was invested in capital projects, which help to create new energy supplies, and also fuel additional job creation. $7.7 billion was paid to local, state and federal governments in the form of income, production and severance taxes. And in addition, ConocoPhillips distributed $6.6 billion to a wide shareholder base, which includes numerous state and local pensions and investment funds, which benefit millions of individual U.S. investors and retirees. So let's turn to Slide 4 to discuss some of the details of our performance for the quarter. Our total company adjusted earnings were $3.4 billion. That's up about $950 million compared to the second quarter last year. Our E&P segment was improved over a $1 billion due to higher prices, which were offset by higher taxes. R&M adjusted earnings were basically unchanged from a year ago. In the second quarter of 2010, our earnings included $430 million related to our ownership interest in LUKOIL. And since we have now sold our interest in LUKOIL, we don't have similar earnings as part of our second quarter 2011 results. Our other segments adjusted earnings improved by $290 million as a result of lower corporate expenses, higher and then higher chemicals and mid-stream earnings. So next, we'll look at more in detail our segment earnings, starting with production in our Upstream business, which is highlighted on Slide 5. The second quarter production was 1.64 million BOE per day. That's down 5% or 93,000 BOE per day from the second quarter of last year. The decline from the second quarter last year was a result of asset dispositions and the loss of our production from Libya. Asset dispositions negatively impacted production by around 62,000 BOE per day. This primarily reflects dispositions in Canada and the Lower 48. Of that 62,000 BOE per day, 16,000 BOE per day was North America natural gas. So if you exclude the impact of our asset dispositions and the loss of production from Libya, our second quarter 2010 production would have been 1.623 million BOE per day. In the second quarter of 2011, we produced 1.64 million BOE per day. And the changes there include a decline of 28,000 BOE per day in our North America natural gas production, which was offset by an increase, a net increase of 45,000 BOE per day of liquids production and International gas production. So stepping back and looking at all the changes from 2010 to 2011 second quarter numbers, you can see that the declines in production that we've had are primarily attributed to declines in North America natural gas production and a loss of our production in Libya, which are both relatively lower margin portions of our portfolio. Looking at our production on a per-share basis, we see that our production has increased 4% from the second quarter of 2010 to the second quarter of 2011. So now I'll turn to E&P earnings on Slide 6. E&P adjusted earnings for the quarter were $2.6 billion. That's up $1 billion from the same quarter a year ago. This increase is largely driven by higher prices, offset by higher taxes and to a smaller extent, by lower sales volume. So even though production was down 93,000 barrels per day, the impact of those reduced volumes was only about $100 million. Now as we just discussed, the volume reductions in the quarter compared to the quarter a year ago were primarily from lower margin barrels. In the cost and other category, this was a help relative to -- this quarter relative to the second quarter last year. This was driven by lower DD&A, partially offset by some increases in other taxes and operating expenses. At the bottom of the slide, you can see the results broken down between U.S. and International. You can see that we had improvements in both U.S. and International adjusted earnings, as well as increases in realized prices. So I'll move on to Slide 7, and talk about some of our E&P unit metrics. Income per BOE improved to $17 a barrel from $9 a barrel a year ago, and cash per BOE improved to $29 a BOE compared to $22 a year ago. The majority of this improvement is attributed to stronger commodity prices. However, we are also starting to see the benefit of the shift in our production towards higher margin barrels. So turning to R&M earnings on Slide 8. Our adjusted R&M earnings improved by $20 million over the same quarter last year. Margins and other market impacts increased earnings by $63 million, which reflects a $205 million increase in U.S. Refining margins, offset by roughly $145 million decrease in International Refining margins. International Refining margins decreased despite slightly increased market cracks due to inventory impacts and lower secondary product margins, which are a result of higher crude prices. In the second quarter, we saw a decrease in R&M earnings of around $20 million from lower volumes compared to the second quarter of last year. This was driven primarily by lower domestic Refining volumes, partially offset by higher International Refining volumes. The lower domestic Refining volumes largely relate to unplanned downtime at the Sweeny and Bayway refineries, as well as a turnaround and planned maintenance activities at the San Francisco and Los Angeles refineries. Our Refining capacity utilization rate for the second quarter was 90% in the U.S. and 96% internationally. Compared to the second quarter last year, we saw operating cost increased about $18 million, but this was primarily driven by foreign exchange impacts. Take a look at R&M unit metrics on Slide 9. The per barrel metrics for Refining and Marketing increased compared to the first quarter this year, and are basically flat with where we were in the second quarter of last year. So second quarter net income per barrel this year was $2.58, and the cash contribution is $3.32. So we'll take a look at results from our other operating segments on Slide 10. Our Chemicals segment posted another strong quarter with earnings of $199 million, which is up from $138 million a year ago. This increase is primarily due to higher ethylene and polyethylene margins, as well as increased equity earnings from CPChem's interest and ventures in the Middle East. Midstream earnings of $130 million were more than double the earnings we had from that segment a year ago, and this is primarily related to higher natural gas liquids prices. Corporate expenses of $203 million for this quarter compared to $367 million a year ago. This improvement is primarily driven by foreign exchange impacts and lower interest expense. So we'll move to Slide 11, and look at our cash flow from operations for the second quarter. We generated $5.4 billion in cash from operations this quarter, excluding a $900 million decrease in working capital, which also benefited cash from operations. In the first quarter, we saw a working capital decrease of about $2 billion -- a working capital increase, excuse me, of about $2 billion. The decrease this quarter is primarily related to reductions in inventory in our Downstream business. These working capital numbers are going to fluctuate from quarter-to-quarter, but we expect these changes to average 0 over time. We generated $160 million in cash proceeds from dispositions in the second quarter. Dispositions during the quarter included some E&P assets in Western Canada, as well as some technology and transportation assets. We funded a $3.1 billion capital program that was $2.8 billion in E&P and $300 million in our R&M business. Our distributions to the shareholders this quarter amounted to $4 billion, which included the repurchase of 42 million shares at a cost of $3.1 billion, and $900 million paid out as dividends. Share repurchases since we started our program in 2010 have totaled $8.7 billion, which represents about 9% of our shares outstanding. We ended the quarter with $5.5 billion in cash and $2.6 billion in short-term investments, so $8.1 billion in total cash and short-term investments. Turning to Slide 12. We'll take a look at our capital structure. Our capital employed is essentially flat with where it was at the end of 2010 with small increases in equity and small decreases in debt. Our equity increased by about $1.5 billion. The combination of income and some foreign exchange impacts were offset, largely offset by share repurchases and dividends. Our debt-to-total cap remains at 25%, which is in line with our target. In the second half of 2011, we expect to retire about $500 million of maturing debt. So we'll move to the next slide, and talk about our capital efficiency metrics. Both our ROCE and cash returns improved in the second quarter, driven by the growth in earnings and cash flow. Our annualized ROCE for the second quarter was 15%. If you look at the Upstream part of our business, ROCE was 17% and Downstream was 13%. That completes the review of the second quarter 2011 results. I'll wrap up with some forward-looking comments before we open the line up to questions. So let me start with updates in a few areas. In R&M, we've had pretax turnaround expenses year-to-date of approximately $160 million, and we expect full year expenses to be around $350 million. And this is lower than the previous guidance of $450 million. We expect global Refining capacity utilizations to be in the low 90s in the second half of 2011. On the Upstream side of our business, when we look at the production for the rest of the year, we see the third quarter that we'll have increased maintenance and turnaround activities, primarily in Alaska, the U.K., Middle East. And then we expect fourth quarter production to increase to a level similar to what we've seen in the second quarter. And overall, for the year, we would expect production to be somewhere between 1.625 million and 1.65 million BOE per day. On July 19, 2011, the U.K. enacted legislation, increasing income tax rate, effective March 24, 2011. As a result, we expect to recognize a third quarter expense of approximately $110 million in the E&P segment related to the revaluation of deferred taxes, and $80 million due to higher taxes from the March 24 period through the end of June. On our guidance for DD&A and corporate expenses, we don't have any changes at this time. In Bohai Bay in China, we are working closely with the Chinese government in our co-venture, Sinoc, following the release of about 1,500 barrels of oil and oil-based drilling that occurred in June. We reported this incident to the Chinese authority immediately after it occurred. The cause is still under investigation, and we currently have about 17,000 BOE per day net of shut-in production. We expect the announcement of the final investment decision for the APLNG project soon. With the achievement of FID and as we've announced previously, the agreement with Sinopec to subscribe for a 15% equity interest in APLNG, we expect to recognize an after-tax loss of about $275 million during the third quarter related to the dilution of our interest in that project. So switching to North America. We continue to pursue adding to our high-quality unconventional resource opportunities. So far, in 2011, we've added about 340,000 acres to our North American resource plays. Activity levels in our Lower 48 liquids-rich shale plays continue to ramp up. Our current production at Eagle Ford is about 24,000 BOE per day. Well results there remain encouraging, but we do have some production curtailments due to third-party condensates trucking constraints. We are still -- we're getting about 75% liquids content at Eagle Ford. We're operating 13 rigs in this -- we operated 13 rigs in this play during the second quarter, and we expect to be up to 16 rigs there by year end. We are also planning to increase activity significantly in the Bakken and North Barnett plays during 2012, and we would expect that our rig count in these areas to nearly double by the end of 2012. Our second quarter production from these 2 areas was about 30,000 BOE per day. So as we continue to develop our Lower 48 opportunities, we continue to find opportunities from increased investments with strong economic returns. This year, we've already allocated an additional $500 million of our capital program to these activities. And as we look forward -- and we're currently working through our plans for increased investment levels in 2012. The key of executing the capital program in the Lower 48 is going to be our assessment of capacity and service providers, drilling rigs and completion crews and our ability to bring production online as quickly as production is increased, and that relates to the build out and access to infrastructure and takeaway capacity. On some International items, in Poland, our third well has been successfully drilled, and we've got a multi-stage frac over the horizontal section of that well. It's going to begin in the third quarter, and the fourth well is also expected to be spud in the third quarter. In Australia, the necessary permits have been received, and we plan to move forward with the exploration and appraisal program in the Greater Poseidon area starting in late 2011 and that will continue on into 2012. On the Downstream side, the core project, the Wood River is scheduled to be online in the fourth quarter. We expect that this project will generate a mid-teens return and our current projects, we would expect at current margins. We would expect that this project would add $200 million to $300 million of net annual cash flow. On our asset sales program, we are in various stages of marketing several assets as part of this program. Our plans to sell $5 billion to $10 billion of assets in 2011 and 2012 have not been impacted by our announcement of the repositioning and to separate the E&P and Downstream companies. These processes take time. We're making progress, and these processes will continue to include Downstream assets in our target to reduce refining capacity by 500,000 barrels per day remains in place. We also continue to repurchase shares, and we expect that we will do so at a rate similar to what we've done in the second quarter. So I'll conclude with a few comments about our recent announcement, which is Slide 15 in the presentation. So on July 14, we announced our intent to create 2 leading independent energy companies by spinning off our Downstream business into a new publicly held company. We believe that this was a compelling transformational event for our company, and we're convinced that this is the right thing to do long term for shareholder value. We see benefits of greater management focus, greater focus on capital allocation, less complexity in running these businesses going forward. While we recognize that the external environment has changed and will continue to change, and that both these companies will have the size and the scale to effectively compete in the environments going forward. Our assets and ability to grow will be more transparent externally post this transition, and we believe that the market will value this transparency. We understand that there is uncertainty about the exact allocation of assets and where the joint ventures will be, as well as what the capital structure will be for these companies and the management teams for these companies. And we expect to -- and we plan to provide you additional information on these items in September of this year. We also expect that we will be naming CEOs for both of these companies before the end of the year. So that concludes the prepared remarks, and we will open up the line for questions now.

[Operator Instructions] Our first question comes from Ed Westlake from Crédit Suisse. Edward Westlake - Crédit Suisse AG: So just firstly, on the Downstream spinoff, it's been a few weeks. Is there anything you can say in terms of the reaction of some your partners in some of the JVs that you've had, CPC Chem (sic) [CPChem], Sinoc and DCP Midstream?

No, it's really too early for us to make any comments on that. But those discussions have started. And until we've concluded those discussions, it would be premature for us to say anything. Edward Westlake - Crédit Suisse AG: Okay. And just on the disposals, I mean, obviously, you've done $1.9 billion so far this year out of the sort of $5 billion to $10 billion that you're looking for. Can you talk in any detail about sort of how much you think you could get done in the second half of the year out of that sort of 18-month program?

I think we'll just say that we're still on the $5 billion to $10 billion additional to the $7 billion we did in 2010, over 2011 and 2012. We have a lot of -- as I mentioned earlier, we have a lot of different transactions that we are working and then we would expect that we will be closing some additional transactions in 2011, and probably announcing some that will close in 2011. And really, that will close in 2012 later this year. We would -- so I would just, again, reiterate the same $5 billion to $10 billion range that we've said for the 2011, 2012 combined. Edward Westlake - Crédit Suisse AG: And then just on the final question on the Eagle Ford. Obviously, you're running into, as you say, a few production curtailments due to trucking. Pipelines is probably the way forward to get that crude out there. Can you just give us an update on when you will have your Eagle Ford production fully covered by pipeline export options?

Well, I think this is going to be a continually evolving aspect of this. We'll have additional capacity built out, and then we're also going to continue ramp-up production. And maybe just a couple of comments on the Eagle Ford overall. So in the second quarter, we averaged 21,000 barrels a day out there. We currently are producing around 24,000 barrels a day. We probably could be producing a little over 30 if we had no production constraints out there at all. So we'll have periods. We're going to catch up, and then we'll have periods, where we will fall behind again. But I would think as we move into 2012 and 2013, that we would expect to be out of the curtailment situation.

Our next question comes from Doug Terreson from ISI.

Jeff, I have a question about U.S. E&P. Your results were obviously very strong there even with the penalty of the new tax regime in Alaska. And on this point, my question is really twofold. One, whether you have an idea of the earnings effect of the rise in Alaskan taxes year-over-year. And two, whether you have an updated deal on the likely outcome or any timing of adjustments that may materialize up there?

Maybe we'll just kind of give you some numbers on Alaska production taxes. If you look at how much we paid in the first quarter, it was a little bit just under $500 million. If you look at what we paid in the second quarter in production taxes, it was just a little bit less than $800 million. So a substantial part of the increase in prices, of course, in Alaska goes towards higher production taxes. We don't anticipate any near-term movement on -- in the political front in Alaska.

Okay. And then secondly, your results in -- your returns in E&P are clearly improving between the higher profitability from the tar, oil sands and conventional, maybe some other places as well. And you do have new production over the next several years. But on the divestiture plan, I had -- I wanted to just ask whether or not the functional and geographical areas from which your sales are likely to unfold, meaning have there been movement or some areas more likely to be sold, others less. And if so, how is your program changed over the last couple of years, Jeff, if you think it has?

The program really hasn't changed, and we are in a situation where it's kind of the same situation we've been in since we -- even going back in the March Analyst presentation, where we've outlined what our targets are. But I've said that the nature of the things we're pursuing, it's probably best from a commercial perspective if we talk about them once they're nearing -- complete or nearing completion. So we're going to be probably not able to provide a lot of additional guidance on that. The same kind of production impact guidance that we gave back in March that this could be 50,000 to 100,000 barrels a day of incremental production that we're selling. It's still, we think, an appropriate way to look at it, and it can be a mix of things from all across our portfolio. I'm afraid I just -- with where we are in different aspects of this, there's not a lot more that we feel is appropriate to say at this time.

Our next question comes from Paul Sankey from Deutsche Bank.

On CapEx, I wonder, just firstly, can you just confirm your expectations for 2011 split between Upstream and Downstream? And I have a follow-up on that subject.

For 2011, we had a capital program of $13.5 billion, which is basically $12 billion Upstream and $1.5 billion Downstream and other. So it's kind of $1.2 billion in Downstream, and 300 in other. That's still pretty much where we are going forward for the rest of 2011 .

And then you announced in your comments a significant step up in U.S. activity. I assume, clearly, that will require more CapEx into 2012. Can you talk about -- maybe give us a bit more color on what you intend to spend on. And secondly, clearly, how much more you would be expecting to spend in 2012?

So we -- I mentioned in our early comments that we're going to allocate an incremental $500 million to developments in North America. I think we would anticipate that's going to come just from adjustments that we make in the overall program, a little bit slower spin perhaps on some projects than what we have initially anticipated to where the budget is going to end up in the same range, is what we've talked about earlier this year. We're taking a hard look now as what the 2012 level of expenditure is going to be in that area. But we could see that we could be up another $1 billion next year as we -- kind of help you with -- the possible range from where we were this year as we look at the breadth of our opportunities.

Well, I think we've said $14 billion to $15 billion in CapEx in 2012. And I would say there's no reason to change that at this point.

Yes, I mean, I'm just wondering if it was kind of incremental beyond that.

I don't think so. I think the capital that comes into Lower 48 was probably reallocated, as Jeff said, from other projects that may not be moving as quickly as we thought.

But that's something that as the rest of the year, as this year goes on and we get a little firmer on our 2012 plans, that we'll be able to provide more guidance on.

Right. And then thinking about the split companies, I assume that the CapEx levels, we expect it to be in line with what they were in the combined company, or am I wrong in that? And can you just talk a little bit more about the math that you have for growing the company as an Upstream stand-alone entity once you lose the free cash flow from the Downstream?

Yes, so I think as we look generally at the Upstream part of our business, it is, of course, influenced by the level of commodity prices. But we generally feel like as you look over time, that it generates the cash necessary to fund the investment program and to fund the dividend, that some years it may be a little bit generate more cash than CapEx plus dividends, some of the year, it may be a little bit less than that. But both of these entities, when we set up a capital structure for them, we're going to create them with a lot of financial flexibility. So they're both capable of handling fluctuations in commodity prices, and continuing to invest capital through the cycle. So we don't anticipate that, that suggests any real change in our Upstream strategy. And the Upstream strategy is still going to be about converting resources to reserves, improving -- shifting the portfolio to higher-margin production, improving returns on capital, improving -- growing production on an absolute basis and on a per-share basis. And we'll be providing more information about this as we talk in more detail about these companies. But I mean, you'll see, I think, both these companies are going to have the financial flexibility to pursue the capital programs that make sense for them.

Yes, I mean, correct me if I'm wrong, but I believe that you think the Upstream would generate around $17 billion of cash flow from operations, at I think $85 oil, which will then cover the $3.3 billion dividend and leave you the remainder to try and grow, I think, at 3%. Is that correct?

Those numbers sound about right. I think we will be, of course, talking in more detail about the outlook on both these companies as the rest of this year progresses.

Sure. And then finally, I think that the statement was you intend to continue buying back stock until you achieve absolute volume growth. That would imply, clearly, that you would be buying back stock throughout 2012?

Yes, I think what we've said is that we're going to continue to buy back. We talked a little bit -- the guidance we've given is the share repurchase that we're doing through 2011. We've authorized $11 billion in total. And that we would anticipate that we're going to do the majority of that in 2011. And then we'll continue to evaluate, as always, the relative balance of investment versus share repurchases going forward.

I guess to give yourself financial flexibility in terms of balance sheet, you might be thinking about less buyback in order to generate strong in 2012, in order to generate stronger balance sheets for the 2 separate entities?

Yes, I don't think we really are in a position to comment about 2012 buybacks. At this time, it's just always a part of our decision-making, and on how we're balancing the opportunities for investment versus the opportunities for share repurchase.

Our next question comes from Iain Reid from Jefferies. Iain Reid - Jefferies & Company, Inc.: A couple of questions. Jim, I heard you say on APLNG about the write down you have to take. But also, could you clarify whether you're going to take a 1-train FID there, or whether you think you'll be in a position having sold enough gas to take a 2-train FID?

Well, we'll clarify that when we make our FID decision. But if we end up in a 1-train FID, it would be 1 train with building out the infrastructure for the second train. And then we would anticipate making a second train decision, once we got a little bit more clarity on the marketing of the volumes for the second train. Iain Reid - Jefferies & Company, Inc.: Okay. So it's not based in terms of the marketing status of that?

No, we don't really have anything that we're in a position to talk about at this time. Iain Reid - Jefferies & Company, Inc.: But you are intending to sell presumably some of the Upstream assets to the buyers and coming on the second train, I believe?

Yes, there's a potential that, that will occur. But I think we would not anticipate that we will be selling the level of interest that we would -- we sold to Sinopec as part of marketing the first train. Generally, the buyers that we're having discussions with on the second train, if they desire equity, they desire equity in the same levels that Sinopec was after. Iain Reid - Jefferies & Company, Inc.: Okay. Second question is, is it possible to give some quantification of the benefit you got in the Mid-Continent in this quarter in terms of the WTI discount, say, compared to the first quarter?

I don't think we will give precise numbers on that. It's a strong quarter for the Downstream operations. In the second quarter, in the strong areas where the Mid-Continent -- there also -- there was a fair strength in the Gulf Coast and the West Coast had fairly respectful margins as well. The East Coast refineries continue to struggle with margins, but we don't have a breakdown between regions that we're ready to share. Iain Reid - Jefferies & Company, Inc.: Okay. And last one, your full year outlook in terms of production, does that includes kind of an embedded assumption on disposals, or is that just how you see the business as it is today?

Well, I could kind of see it how we see the business as it is today. I think -- we still think that we will be making additional disposals in 2011 or announcing additional ones in 2011 that we'll close in 2012. I think those are likely to be weighted later in the year to where they're not going to have significant impacts on production for 2011.

So just to be clear, that's an absolute number that -- Libya, obviously, we've taken Libya volumes out, and we've taken the impact of asset sales so far this year, which is a relatively small amount, maybe 5 a day or less out of that number. Iain Reid - Jefferies & Company, Inc.: Okay. All right. And finally, just one question on Libya. Have you had any discussions with the potential new -- well, obviously, ongoing new government, but the rebels, as they're called at the moment or independent people, about any of your assets which they may control now?

We're not in any position to have discussions with any group like that.

Our next question comes from Paul Cheng from Barclays Capital.

Several quick question. In Qatar, what is the net to the company in oil sand, in liquid and gas in the second quarter?

I don't think we have disclosed either the volume or the price on LNG, Paul, specifically to Qatar.

Okay. I presume it's already in full production, right?

It is.

Okay. Kind of in the -- for your full year guidance in production, what's the assumption you used in terms of the Bohai Bay shut in?

Well, as Jeff said, we are down 17,000 barrels a day. I think production prior to the shut in of that production was around 60. I'm not sure what we've promised as far as when those volumes come back on, but...

That's part of the range that we're giving on that numbers. I mean, we are having conversations now with the authorities in China about, well, the incident overall and the timing of the restart of production.

Jeff, can you tell me that, what's the range you assume in that, your guidance for Bohai Bay?

No, we're not...

0 to 17.

Yes, well...

Okay. Form 10, when you guys are going to file?

On the spin out?

Yes.

We're working through details of the schedule right now. We would like to get in a position to where we file the IRS ruling request in the fourth quarter of this year.

But the Form 10 should be before that, right?

Well, yes, it will be different. It will be around the same time frame, and there'll be iterations on the Form 10.

Right. So we should not expect that's some time, say, in the third quarter? It will be a fourth quarter event?

I think that's probably right, Paul.

Okay. Jeff, does any of your joint venture partners, when you guys originally signed the agreement that give them the right, such as share for Cenovus, if there's a change in control, they will have the right to acquire your interest, or that force it on you. If there are any agreement of that form, or they don't really have the right, or that the spinoff does not constitute as a change of control.

There are rights. We're not giving any of the details. Each of our partners have various rights that we need to work through as we decide which entity each of the joint ventures goes into. And we're not really free to discuss exactly what those rights are, but those discussions have started with each of our partners.

Okay. So you're saying that some of them do have rights that could acquire or made the right of the acquiring your interest?

Well, they're more along the lines of rights of the first refusal but....

Is the spin-off considered as a change of ownership or a change of control?

Not -- well, in what context? I think we'd have to say that in terms of the documents that govern each of the joint ventures, there's different definitions of how an event like -- in different ways, and how an event like this would be treated that don't really fall into a change in control type categorization. So I don't think we can really answer that question as yes, no. The agreements, again, are more complex than that.

Two final question. One, Kashagan, is that one of the asset, the company, being considered for divestment, given that some of your partner look like that have signal that they may be selling their share already given they're top [ph] of that in that projects?

Yes, I probably just have to go back to the same kind of answer that we've given on asset sales before, is that as we move through asset sales program, there are certain assets where we're working on and having discussions about, where it's probably not appropriate to give a lot of -- it doesn't help us commercially to give a lot of the details about that. So we don't really want to get into saying it's this particular asset or that particular asset that we're working on at this time.

Okay. That's fair. And final one, Jeff, I know that you guys have indicated you're going to continue the share buyback program at least for this year at about $1 billion a month. Just curious that the thinking behind -- when given that by next year, you're going to have a 2 separate company, 2 new management leadership, that who's going to be the CEO, not going to be from the existing senior management team in some way. So what's the thinking behind that to take into consideration whether that the company should stop their share buyback and they offer sales to give perhaps their maximum financial and operating flexibility to the new team? You also say that if we're going to continue in this way by the time we come to the end of the year or early next year, the bulk of your cash on hand is probably going to use up 25% debt-to-capital ratio, if not, high. But on the other hand, that is not extremely low to provide them a lot of flexibility either. So wondering there, how the consideration or thinking -- or that they're thinking in the existing management team or the board?

So if you look at where we started the year, we started the year with around $10 billion in cash. We're generating strong cash from our operations this year, which is kind of really more than fund the capital and the dividend program. So as in share repurchase, we'd be adding to that cash balance. And at the same time, we're continuing to -- with an asset sales program that we think is going to add proceeds in 2011 and 2012. You raised a good question. So when we look at this, so we think about the amount of financial flexibility that we have based on cash we started with, cash from operations that we're generating, continued asset sales program. We think that we can execute the share repurchase program we've talked about for 2011 and still have the levels of cash, the levels of -- end up with levels of debt in these entities that will provide us quite a bit of financial flexibility. So we're still quite comfortable that we are not doing something that would diminish the ability of either of these companies to really have all the financial flexibility they need going forward by repurchasing shares in 2011.

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

I got a couple of quick ones. Actually, a few quick ones if I run through them. Just a point of clarification on the production guidance, at least, Jeff. What is the expected scale of production that will be sold in the remaining $5 billion $10 billion program? And just to be clear, I assume the guidance, as you pointed, any sales would likely not affect 2011, just want to be clear that, that is indeed the case.

Yes, so I think the guidance we've given on production impact from $5 billion to $10 billion asset sales program is 50 to 100...

million barrels a day...

Yes, we haven't really come off that number.

And that's still to go, Clayton, or has any of that been done already?

Well, I think the first half of the year, maybe 5 a day. Yes, I think you can essentially say, Doug, that it's still to go.

Got it. And China, the 17,000 barrels a day, have you knocked that out of your guidance for the second half of year as well? So the guidance is net of that 17,000, or do you assume it comes back again?

No, we assume that we will be returning those fields to production, the B and C platform in Bohai will return to production. And the question is just what the timing of that will be...

About when it is.

But it's in the guidance for the second half? Is it included or it's excluded?

Well, it's part of the variability that we see in potential outcomes for the second half.

And from the standpoint that we didn't have that production in July. We included that impact. But you're looking at a 25,000-barrel a day variance, and it's awfully tough to get -- that's a pretty small number on a 1.65 million a day.

We're just not really -- we can't be a lot more accurate than that in estimating production.

Got it. I understand there is a lot of confidentiality around Qatar. So I'm not optimistic on this one, Clayton, but let me give it a go.

That's a good way to start the question.

Well, my understanding is that some of the other very large LNG projects have multi-year tax breaks. Does that also apply to you guys?

Yes, I think that falls in the category of commercial terms that we can't disclose.

Okay. I'll figure out maybe the answer. I'll just try another couple of quick ones, and then I'll let someone else for the go. I guess the last operating question is really the liquids-rich plays, Eagle Ford, Bakken. Can you just give us an update as to how your acreage position is evolving there? It looks as if you're -- I'm guessing you're continuing to add and bolt on as you move towards those high-margin barrels, so an update there. And then my last one is strategic, but I'll let you answer that, and then I'll go to the strategic one...

So as we-- no, I think we have very substantial positions in those plays already that we acquired quite a while ago. We will -- the acreage that we have added, and we're talking about the 340,000 acres that we have added have been in developing plays, and not in the Eagle Ford, Bakken and Barnett. I think we see what the -- or we see a lot of running room with the acreage we have already, multi-year development at Eagle Ford. We talk about looking at the Bakken and Barnett, and then increasing activity there based on our existing acreage. We find that acreage is going at a very handsome price right now in those areas. And so we're looking to add acreage to other places and more perspective, not as developed plays and building and concentrating on building out and exploiting the acreage, which we have previously acquired in the Eagle Ford, and the Bakken and the Barnett.

Okay. And the last one for me is really -- is maybe it’s actually maybe one for Jim rather than yourself, Jeff. But in the context of going back through the last year and the very successful asset program or sales program, I should say, you started off with Syncrude. And one of the glaring, I guess, disconnects that you can see in the market is the value you've given Cenovus versus, let's see, your assets that you share with Cenovus now. Of course, there's no -- the chance that you all is going to get split in 2, I'm guessing. I'm just curious as to why, when Jim's comments in the separation call, he said, "It doesn't really matter to him if production is 1.6, 1.5, 1.4 in terms of getting value recognition." At least, that was my recollection. Why, in light of what management has done to date, trying to get the value recognition with restructuring your interest in the Cenovus equivalent assets, and maybe trying to achieve that kind of valuation, why is that not an option, or is it an option? And I'll leave it there.

Okay. See, I'm not sure if I understood there what you're suggesting we might do with our Cenovus -- with our assets in the partnership with Cenovus. We, just generally, this all kind of gets to the transparency questions and one of the things that we think will be beneficial to as we go forward when we have even calls such as this one. The subject is focused on one area, and we will be, I think, providing more information and more focus on either just the Upstream or just the Downstream assets. And we think that increased transparency will cause a better understanding of what our asset base is going to be.

Yes, I guess the issue, Jeff, is you released an awful lot of value from Syncrude that wasn't arguably being reflected in the stock. And if you look at the fully integrated oil sands project, in other words, the Christina Lake and so on, all the way down to Woods River, is essentially the same thing, and you're not getting the value for that. So why would you make a decision on Syncrude, that you wouldn't look to maybe separate out what is clearly been given a very hefty market value and in the case of Cenovus for almost exactly the same assets? I guess...

Well, yes, well, I think maybe the answer there is really more about Syncrude than it is about SCCL, and if you think about...

They're really not the same types of assets given our ownership and the running room that we had in Syncrude versus SCCL.

Yes, really differently that way too. Yes, just kind of expand on it, Clayton [ph]. I mean what in Syncrude was a 9% interest in a very large, very solid strong asset for which there was a very good market for in -- and for which we could do the sale in a way that was tax efficient for us. So all of those things led us to say, "Well, we can get more value, obviously, for Syncrude by marketing that asset than it was worth to us, keeping it just from a net present value perspective." And really, on all of our asset, sales transactions, our guiding principle is we're driven by what's the net present value, the cash flows that we anticipate we're going to get out of these projects versus the value, the after-tax value of our sales proceeds. We're not really doing asset sales. We're doing asset sales because we think we can get more value as we look at it just from a cash flow perspective through selling the asset than we can by retaining the asset. It's not really because we're trying to say, well, this asset or that asset is or is not contributing to our overall market valuation.

Our next question comes from Philip Weiss from Argus Research.

First question I have for you. In the past, you talked about having an interest in acquiring acreage should it become available on the Gulf. And I was wondering if there's any changes to that in light of your comments about allocating more money to the Eagle Ford.

No, I don't think so. We still have an interest in acquiring acreage in the Gulf. But in particular, we have interest in acquiring exploration acreage because we try to build out what our investment portfolio is going to be longer term. So the expenditures that we talked about are kind of higher expenditures in the Lower 48 are for 2011, 2012, 2013-type investments. When you talk about adding things in the Gulf of Mexico, you're adding things that are more, perhaps, some near-term exploration expenditures. But really, well, the larger expenditures are going to come later in the life, and that helps build our portfolio in the 2015 and beyond timeframe. So yes, it's a good question. No change in our interest level in the Gulf of Mexico assets.

And then the next question I have, realizations. I know that with the relationship that we have among the various types of crudes right now, that your realizations have improved, and then that's helping the Upstream results. And I was just wondering what kind of thoughts you might have as to how long that's going to last, and if it's going to get any wider, and that kind of thing.

Well, I think we'll continue to see that happen over time.

Are you talking specifically about the margin expansion that we're seeing or the improvement in margins that comes from greater liquids production versus gas or...

No, I'm talking more just about the difference between light Brent and WTI and Louisiana light.

No, so more on the Downstream side then?

No, here, I'm just thinking, when I look at your realizations relative to where prices came in for the second quarter, they've gone up. And so I'm just trying to figure out how long that may -- what your view is on how long that spread may last. I know there's a downstream benefit as well, but I'm thinking on terms of what you're selling your oil for.

Yes, I'm not -- I don't know that I really thought about given the question in that way.

So realizations, they've improved in some areas. I guess, in part, because our costs in those areas or our listings in those areas may be different in the second quarter than first quarter. But why don't we take that one offline and come back to you?

Okay. That's fine. And then just want -- Clayton, I just to confirm that debt pay down that you mentioned, that's just maturing debt. It's not in the other...

That's right. That's just the maturity that we have in the fourth quarter.

Our final question comes from Blake Fernandez from Howard Wheel.

Question on the new acreage that you've added, the 343,000 acres. I know you said it was developing plays. For one, I was going see if you could elaborate a little more on any specific areas on that. And then in conjunction with that, you mentioned the new Canadian shale play, hoping maybe to get some color on whether that's oil or gas, or when you may start drilling there.

So just generally, maybe just some broad characterization on the acreage that we've added. It's maybe 2/3 in Canada and 1/3 in the Lower 48. We find ourselves in a position that we don't really want to say a lot more than that, because we still continue to acquire acreage. And it's a competitive world out there, and we don't really want to give a lot of color on exactly where we're acquiring acreage.

And obviously, we're looking for liquids rich, right? So they shales -- unconventional that we're going after is going to be more from a liquid's perspective than a gas perspective.

Okay. And on Canada -- so again, liquids there, and any idea on when you may start testing?

Well, I don't know. I guess I don't know what the exploration program is around this acreage. I can't imagine us doing anything this year. I think the exploration program in 2011 is probably set. So I would -- I'm going to guess and say it's going to be a 2012 program. Jeff, do know any more?

No. I think it's something that kind of will fall in the categories as we talked about finance for these -- in more detail for these companies going forward that, that will be -- and we talk about our exploration program going forward that's -- more color on that.

It's consistent with this idea of exploiting some of the existing acreage that we have onshore, and adding to our unconventional base in North America.

Okay. And last one for you, Clayton, I know we've talked in the past about your Permian and Bakken and Eagle Ford, and I think the original expectation was to add more capital to Eagle Ford due to some constraints takeaway, capacity cost, et cetera up in the Bakken or maybe even Permian. Has that landscape changed at all? I know, obviously, you've mentioned some issues with Eagle Ford, but if you could just give us a lay of the land on how those 3 look?

Yes, so Eagle Ford, the results are all in line with our expectations, and they're encouraging. In terms of liquid content, in terms of well productivity, we're managing through the infrastructure questions there. As I mentioned, we're increasing rig counts in Eagle Ford going kind of from 13 in the second quarter, where we think we'll be up to 16. So we are continuing to expand the pace of that development.

But in capital spend, there's estimated still at Eagle Ford, around a $1.3 billion to $1.5 billion a year, so in 2011. And the reference that Jeff made earlier about Bakken and Barnett, which are incrementally $0.5 billion, would be into those areas rather than into Eagle Ford.

Okay. And I guess I'm fishing -- is that an indication...

And Permian will be part of that, as well, Blake.

Okay. But is that an indication that constraints, some of the constraints you're initially seeing are beginning to kind of alleviate a bit or...

Well, that level of spending is consistent with what we think we can have prompt off-take for.

This concludes our question-and-answer session. I'll now turn the conference back to Mr. Reasor for closing remarks.

Great. Thanks, Kim, and thanks, everybody, for your participation in the call. We think we're doing a lot of good things at ConocoPhillips, and look forward to the next time we're able to talk with you. Have a great day.

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