ConocoPhillips (COP) Q2 2012 Earnings Report, Transcript and Summary

Welcome to the Q2 2012 ConocoPhilips 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 Ms. Ellen DeSanctis, Vice President, Investor Relations and Communications. Ms. DeSanctis, you may begin.

Thank you, Kim, and good morning to everybody. Again, thank you for joining us on this ConocoPhilips second quarter earnings call. I'm in the room today with Ryan Lance, our Chairman and CEO; and Jeff Sheets, our EVP and Chief Financial Officer. And before I turn the conference over to those 2 gentlemen, let me make a few administrative comments. First of all, we -- you'll notice, we've provided a lot of new information with today's disclosure. And of course, that's to help you understand the business better. We've provided segment data on each of our regions in addition to some data on our Corporate statements, and I just want to let people know, Vladimir and I will be available after the call to help you sort through those details as needed. In addition, I want to remind you that our presentation materials for the call today can be found on our website and a transcript to this call will be posted again to our website, hopefully by no later than tomorrow morning. And then finally, if you'll advance to Slide 2, you'll note our cautionary statement. We will make some forward-looking statements during today's webcast and actual results could differ materially from the expectations we shared today. The factors that could cause these results to differ are listed in this cautionary statement, as well as in our periodic filings with the SEC. And now, it is my pleasure to turn the call over to Ryan Lance.

Thank you, Ellen, and thank you all for joining the call today. So I reflect back and in mid-April, we laid out our plans for the newly independent ConocoPhilips and today represents our first quarterly call to update you on those plans. I'm looking forward to your questions at the end as well. So I'll begin my comments on Slide 3 and cover some of our key second quarter highlights. Strategically, the second quarter was certainly an eventful one. Less than 100 days ago, we completed the spinoff of our Phillips 66 company. And while we were prepared for the event, it's really hard to know until that event actually shows up how things go. But I'm pleased to say that I think we hit the ground running, and I certainly couldn't be prouder of our employees. They certainly stepped up in a pretty big way. So in addition to completing the Phillip 66 spinoff, we continue to make progress on our divestiture program. This is a strategic program that's important for completing the repositioning of the ConocoPhilips and adding financial flexibility to the company. In the quarter, we generated about $0.5 billion of proceeds from asset sales in the North Sea, and we continue to advance our progress on other assets. We still estimate that our announced program will be complete by mid-2013. I also include a point about our unconventional and our conventional exploration program as a strategic highlight. We made progress in the corner -- in the quarter on these important activities with more to come in the year. And I'll speak about our exploration activities in more detail in a moment because this is an important part of our plans for the future, and we have a lot of going on in this area. Operationally, the business ran well in the quarter. We achieved the high end of our estimated production range for the quarter at 1.54 million barrels equivalent per day. Key production highlights include our ongoing strong performance from unconventional assets in the Lower 48, led by our Eagle Ford development and from our oil sands in Canada. Our major projects have progressed notably, our APLNG and in the second quarter, we advanced at Train 2 towards FID and recently announced that milestone. Both Jeff and I will cover some additional details about our operational performance in later comments. Moving to the financial themes. Clearly, our strong operational quarter was overshadowed by weaker commodity prices. This translated to lower income and cash flow for the quarter compared to prior periods. It's important to note that our diversified portfolio helped buffer some of the impact of weaker North American commodity prices. This allowed us to generate $1.5 billion of adjusted earnings or $1.22 of adjusted earnings per share. Excluding working capital, we achieved $3 billion in cash from operations. What's important to note is that this cash flow number reflects the fact that we had a number of high margin production offline due to planned turnarounds in this quarter. In other words, the $3 billion should not be considered ratable. And finally, we purchased 3.1 billion of ConocoPhilips shares in the quarter, representing a total of about 52 million shares and through 6 months, we've delivered on our goal of repurchasing $5 billion worth of shares. So in summary, we had a strong quarter strategically and operationally, delivering on several important fronts. While commodity prices softened, we stayed focused and delivered on things we can control to meet our commitment for growth, financial returns and yield over the long-term. So if you turn to Slide #4, I'd like to address the state of the business and put some perspective around the focus areas and the priorities for the rest of the year and beyond. As I already mentioned, the business is running well and that's absolutely key. We are focused on delivering our programs and plans safely, on-time and on budget. Our major growth projects are on track and these include our Lower 48 unconventional resource plays, as well as our major growth projects in the Canadian oil sands, the North Sea projects in the U.K. and Norway, APLNG and our Malaysian deepwater projects. These are the major projects that will underpin our long-term goal to deliver 3% to 5% with margin expansion at flat prices. Aside from the major projects, the base business is also running well. As you know, second and third quarters are typically high season for maintenance downtime, but we have those activities well in hand. Finally, we continue to start our dry gas drilling and deferred capital to the liquids-rich plays. As I mentioned a minute ago, our exploration program continues to gain momentum. This is an aspect of the business that we are reemphasizing in the new ConocoPhilips, and I'd like to give you some highlights of that. First, I should note that though I talk about exploration, I talk about it through 2 lenses: a conventional lens and an unconventional lens. And we have a lot of activity in both our unconventional and conventional programs throughout the year and in this second quarter. In the unconventional plays, we continue to test liquids-rich opportunities in North America. We have pilot programs actively underway and in place like the Niobrara, the Wolfcamp, the Duvernay and the Avalon. We are also evaluating several other opportunities, some of which are associated with ConocoPhilips' massive land position in the Lower 48 and Western Canada. With approximately 21 million net acres, much of it held by production, we have access to some potentially impactful unconventional plays. One example that I'd like to share with you this morning is the Mancos Shale in the San Juan Basin. We are the largest lease holder in the San Juan Basin today with 900,000 acres held by production. We have been actively reviewing our extensive data across the Mancos', in the gas, the liquids-rich, and the oil window, and plan to test the play later in the year. Other companies are actively testing the play now, which means we are effectively derisking the play with other people's money. If the play is successful, we have years and years of drilling activity ahead. It's opportunity like these, in our backyard, adjacent to where we have operating and infrastructure and expense, and already held by production, they are what create long-term running room for the company in this unconventional space. Internationally, we're currently getting ready to pilot test our 11 million-acre unconventional shale position in Australia's Canning Basin. Now let me move to the conventional side. We made significant progress here in this quarter as well. During the quarter, we spud 3 nonoperated wells in the deepwater Gulf of Mexico. That appraisal well was spud on the Shenandoah prospect and 2 wildcat wells were started at the Bioko and Coronado prospects. We continue to build our deepwater prospect inventory in the Gulf of Mexico, largely focused on the Paleogene play. We added a significant chunk of acreage late last year and as well, we now hold more than 325 blocks in the Gulf of Mexico. Finally, earlier this year, we added significant conventional acreage positions in Angola and in Bangladesh, and we're undertaking seismic activities in both those areas right now. So we're busy in the exploration area and we think this is an important part of the business, where we are very effectively positioning for future growth and taking advantage of good opportunities as they arise. This, combined with our 43 billion barrel resource space, is revising optionality to our growth. On the business development side, we're very focused on completing our announced asset sale program. We have targeted selling $8 billion to $10 billion of assets by mid-2013. We have several packages on the market today. When we started this divestiture program, we understood some of the assets would take some time to sell but overall, I'm pretty pleased with the progress that we're making. This year to date, we've sold about $1.6 billion of assets with several more currently in the process. We're being patient, at date [ph] we remain committed to getting the program completed, but we'll do that at acceptable prices. With the year half over and the spinoff complete, we have scrubbed our capital outlook for 2012. We now believe we have good visibility on the rest of the year, and estimate 2012 capital spending to be about $16 billion. This includes the impact of pushing out the expected timing of asset sales, some of which have quite a lot of capital spending associated with them. It also includes the impact of some incremental exploration spending I just mentioned, as well as some incremental investments for infrastructure in the Eagle Ford area to ensure that we're not constrained in that development. Although commodity prices have weakened for all of industry, we continue to believe that our growth projects are robust enough to justify our planned investment at a range of prices. These are projects that will generate growth, margin improvement and returns for the longer term. For this reason, we did not think it's prudent to reduce our capital at this time, given that we're investing for a long-term value creation. So some of the questions we get, I hope this next slide starts to address and it looks at our funding sources and uses of these in a bit more detail. So this slide lays out our current thinking on our investment priorities and the actions we'll take to fund our growth programs and maintain financial flexibility over the course of 2012 and 2013. It summarizes our sources of cash on the left and our uses of cash by priority on the right. On the sources side, we have cash on hand of roughly $6 billion today, plus incoming cash from operations. And of course, cash from operations will vary according to price. So we expect to generate cash proceeds from asset sales of between $8 billion and $10 billion over the course of the next year and we have balance sheet capacity if needed. That consensus views of cash from operations, the sum of this column for 2012 and 2013 combined, could be as much as $40 billion without going to the balance sheet. On the right-hand side of this chart, we have the uses for the cash listed by priority. Our top priority for spending is to fund our dividend. We believe that a company our size should distribute about 20% to 25% of our annual cash flows through the cycles back to our shareholders. Our next priority is to fund our capital program at roughly $15 billion annual level. Over the next 2 years, the sum of our expected dividends and annual capital program is roughly $36 billion. So in the current environment, we have sufficient sources from cash, cash flows and asset sales to cover our highest priority uses, funding our dividend and investing in our capital programs and modestly reducing our debt levels. We think this allocation make sense and creates long-term value for our shareholders. Higher levels of asset sale proceeds or higher cash from improved commodity prices would give us the opportunity to consider additional share repurchases. On the other hand, if prices were to cycle down for an extended period of time, we would adjust our capital program and use the balance sheet's capacity as needed. So now, let me turn over the call to Jeff and he'll cover our financial and our segment reviews.

Thank you, Ryan, and good morning, everyone. I thought I would start this portion of the call with a list of some of the key drivers that underpinned our financial and operating performance for the quarter. These are drivers that either affected our segments across the board or represent some noteworthy impact to our financials. The first is no surprise, North American crude, bitumen and natural gas, and NGL prices continue to trend lower and we'll have more detail on that on the next slides. In terms of production, our volumes came in as planned with a solid performance across our portfolio. Ryan stepped through a few of these, but as a reminder, our Lower 48 Shale and Canadian oil sands achieved production increases, which were somewhat offset by unusually heavy planned maintenance efforts and the impact of dispositions. Generally, operating costs were as expected and dispositions also had some impact on our financials and we'll cover that as we go through the segments. I'd also note that the format of the slides we're using this morning are quite different from our previous earnings calls, with a lot more information being presented about each of our geographic operating segments. What's also different is that we'll be providing outlook information as we go through the presentation instead of all at once at the end of the presentation as we have done in previous earnings calls. So if you move to Slide 7, we'll start the discussion with a discussion of our realized prices. About 55% of our production consists of liquids and about 45% consists of natural gas. Of the 55% that's liquids, about 30% is tied to Brent or international prices, which were strong early in the quarter and began to decline later in the quarter. The remaining 20% of liquids is tied to North American crude markers, NGL or bitumen prices. And this production continues to be adversely impacted by wide crude differentials. On the natural gas side, about 45% of our portfolio, roughly 20% consists of international gas. That's gas outside of North America. For LNG, which actually enjoyed a relatively strong pricing this quarter. And the remainder of gas consists of North American natural gas, which, of course, continues to be challenged. On the right side of this chart, we presented the second quarter price realizations compared to prior periods. Now this highlights the commodities that were weaker versus stronger in those periods, and our overall price declined about $6 from a year ago and about $5 from the first quarter. The key takeaway from this slide is that we're -- that we benefit somewhat from a diversified global portfolio. About 55% of our mix was not affected by weaker North America pricing. As our major projects come online, our production mix shifts more to liquids and natural gas -- liquids and international gas, and this will help improve our margins and cash flow growth in the future. So let's move to Slide 8, and talk about total company production. As Ryan mentioned, our production was 1.54 million BOE per day, on target with our expectations. This was down 97,000 BOE per day from the same period last year. At a high level, you can see that this decrease can be bucketed roughly 1/3 to dispositions, which Vietnam, Statfjord and Alba; about 1/3 to downtime in Australia, Alaska and Canadian oil sands; and about 1/3 to natural gas declines in North America, driven by decreased activities and curtailments. And what it also shows us that our growth offset base decline, accounting for over 110,000 BOE per day compared to last year. The bulk of the growth coming from the Eagle Ford, Bakken, Permian and oil sands assets. In a moment, I'll provide more detail on production by segment, let me first give you some guidance for production estimates for the rest of the year. We expect third quarter production to be between 1.475 million and 1.525 million BOE per day. Most to the expected drop from the second quarter to the third quarter is due to planned downtime in Alaska and the U.K. Our full year production estimate is now expected to be between 1.565 million and 1.585 million BOE per day and this includes the impact of dispositions. Now I'll turn to our adjusted earnings on Slide 9. Now this slide shows the 7 new reporting segments for our company. We'll go through in detail in each of these segments in subsequent slides, and there's also additional information along with the historical data in the supplemental tables included in the press release. Although we operated well, our results compared to prior quarters were adversely impacted by the combination of lower commodity prices and lower production as we discussed on the previous slides. Lower 48 and Canada were affected by natural gas prices that were down more than 50%, NGL prices down more than 20% and Canadian bitumen prices down more than 20%. The biggest volume-related impacts to earnings were the asset dispositions in Europe, lower production in China and the turnarounds in Australia. Our second quarter adjusted earnings were $1.535 billion versus $2.31 billion a year ago. Now I'll turn to the segment slide, beginning with Alaska on Slide 10. Our legacy asset in Alaska continues to operate well and provides strong earnings and production performance. Production was 215,000 BOE per day, down from a year ago. The lower production was driven by natural gas field decline, partially offset by improved drilling performance and lower unplanned downtime. In the quarter, we completed a major turnaround at Kuparuk on schedule and on budget. Adjusted net income for the segment was $551 million, roughly equivalent to a year ago. In the third quarter, we have additional turnarounds planned, which we estimate will lower sequential production by 40,000 to 50,000 BOE per day. Looking forward, Alaska's segment, where we have opportunities to mitigate decline from incremental exploitation opportunities, and we retain the option from some longer-term projects such as LNG exports and ANS gas. Our future developments from Alaska are contingent upon some improved fiscal terms. So next, we'll move to the Lower 48 and Latin America segments, which is on Slide 11. In this segment, we continue to advance several high-margin growth projects across our asset base. Total production for the quarter was 441,000 BOE per day, approximately 16,000 BOE per day higher than last year. The growth over last year was driven by our liquids-rich plays in the Eagle Ford, Bakken and Permian. And then this growth was partially offset by natural gas declines across the portfolio. Eagle Ford, Bakken and Permian average production in the second quarter this year was 61,000, 25,000 and 51,000 BOE per day, respectively. Our total production of 137,000 BOE per day from these 3 plays was 54,000 BOE per day higher than a year ago. So looking more broadly across the Lower 48 portfolio, liquids production was up 24% and natural gas production declined 8%. This reflects our shift in capital to liquids plays and away from dry gas drilling. Although we saw year-over-year production growth in the Lower 48, the net income results from the second quarter were lower due to a 50% drop in natural gas prices and a 23% drop in NGL prices. This reduces net income $119 million for this segment. In the second quarter, we had a total of 31 drilling rigs, comprised of 17 at the Eagle Ford, 8 in the Bakken and 6 in the Permian. And we expect to maintain a tunnel of 27 rigs through the end of this year. A majority of the acreage in the Bakken and the Permian is held by production and we expect to have the Eagle Ford acreage held by mid-2013. And based on the positive results we're seeing to date on these liquids-rich shale plays, we expect that we've identified extensive development potential over the next several years. As Ryan mentioned earlier, we are resuming high impact deepwater Gulf of Mexico exploration and appraisal activities. We would expect to have some results by either late this year or early next year. So next, we'll move to our Canadian segment on Slide 12. Canadian production was 268,000 BOE per day in the second quarter, up 6,000 BOE per day versus the same period last year, driven by a ramp-up in oil sands production. New production growth of 22,000 BOE per day was offset by natural gas asset disposition, natural gas curtailment from lower well performance as a result of restricted capital investments in our natural gas fields. As you can see on the production charts, liquids as a proportion of our total segment production increased compared to last year. Liquids volumes were up year-over-year 19%, while natural gas declined 9%. Again, like the Lower 48 segment, this shift can -- should start to show up as improved margins over time. So even though our Canadian business operated well, segment earnings reflected significantly lower bitumen prices, increased WTI, WCS spreads and lower natural gas and NGL prices. As a result of these factors and given that 62% of our total production in Canada is attributable to natural gas and NGLs, adjusted net income was a negative $94 million for the quarter, compared to a positive $82 million in the second quarter of 2011. It's important to note that this segment has generated positive operating cash flow year-to-date. So even with gas prices at recent lows, the cash flows from this segment are important sources of cash for redeploying into our growth programs. The company's oil sands projects continue to perform well with production growth from Christina Lake Phase III, and Surmont Phase I. This resulted in increased bitumen production of 20,000 BOE per day compared to the second quarter of 2011. Additionally, the Surmont Phase II development and further SCCL expansion phases are underway and should lead to further production growth over the next several years. In May, we received approval from the Alberta government to proceed with the Narrows Lake oil sands project. And the project is anticipated to have gross production capacity of 130,000 BOE per day, to be developed in 3 phases starting in 2017. So next, we'll move to the Europe segment on Slide 13. Second quarter production in Europe decreased by 42,000 BOE per day to 236,000 BOE per day. This was primarily driven by natural gas field decline and by natural field decline in Britannia, Ekofisk and J-Block, downtime in the Statfjord and the Alba asset dispositions. Net income in Europe was $414 million, down $119 million from last year. Commodity prices held up in this segment relatively well compared to the North American markets. And positive FX impacts slightly improved income this quarter. In the near term, we expect volumes in this segment to decline. Now volumes will begin to increase when the Jasmine project comes online in 2013 and when additional North Sea projects at Clair, Ekofisk South and Eldfisk II start up. And one additional point, I'll remind you, is that the U.K. recently enacted legislation with -- which restricts corporate tax relief on decommissioning cost to the 50% tax rate, retroactive back to March of 2012. And we anticipate in the third quarter 2012 that our earnings would be reduced by approximately $175 million due to the remeasurement of these deferred tax liabilities. So I'll turn to Slide 14 and talk about our Asia Pacific and Middle East segment. Production in this segment was 270,000 BOE per day, down approximately 85,000 per day from the second quarter of 2011. This reduction was driven by the curtailment of the Peng Lai production, the disposition of Vietnam business unit and by the safe completion of a 41-day turnaround at the Darwin LNG project. At of -- the end of the second quarter, Peng Lai was producing 30,000 BOE per day, net. We are seeking approval for our final operating and development plan, but continue to ramp up production under an interim production resumption plan. Compared to the same period last year, adjusted net income decreased by $167 million to $789 million. This decrease was driven by 24% lower volumes, slightly offset by improved LNG prices and lower DD&A. The second production train at APLNG was sanctioned in July and project financing agreements were signed during the second quarter. The project is on track for first deliveries of LNG in 2015. Concurrent with project sanctions, ConocoPhilips further reduced its working interest in the project to 37.5%. In Malaysia, development continues on several projects, including the deepwater Gumusut oil field off the coast of Sabah. The natural gas Kebabangan field, and the oilfields at Malikai and Siakap North-Petai. Finally, we anticipate beginning our pilot program in the Canning Basin as Ryan mentioned in the third quarter. So I'll move to our International segment on Slide 15. This segment includes our assets in Russia, Caspian and Africa. Production was 112,000 BOE per day, up from 88,000 BOE per day a year ago. Now this increase was primarily due to the restart of our operations in Libya, partially offset by declines in Russia. Net income was a negative $19 million, driven by lower crude prices, high taxes and foreign exchange impacts. And for the company overall, the FX losses on this segment generally offset the FX gains that I talked about in Europe. As we've indicated in the past, we are actively marketing some of these assets in this segment as part of our $8 billion to $10 billion divestiture program. So the final reporting segments I'll talk about is on Slide 20, our Corporate and Other segments. Since this is essentially a cost segment, adjusted earnings were a negative $225 million this quarter. The cost contained in this segment include net interest expense, corporate G&A, environmental cost, some FX impacts and our emerging businesses cost. A portion of the former Emerging Business segment that you will recall from the integrated ConocoPhilips, is now included as part of this Corporate and Other segment. For guidance purposes, I would suggest using a $1 billion annually for this Corporate segment, so roughly another $500 million for the second half of this year. So next, we'll turn to Slide 17 and talk about our operating segment margins and returns. The 4 pack -- the slides on this page summarize our key financial metrics for the quarter. In the short run, prices overshadow the operational and portfolio improvement successes we've had for the company -- as a company. Looking year-over-year at the second quarter, the drop in income per BOE is primarily driven by the $6 drop in realized prices we discussed earlier. And our cash contributions and our return on capital and cash return on capital metrics follow this same trend. And before turning the call back to Ryan to close up, I'll go through our year-to-date company cash flow on Slide 18. Today, we generated $7 billion of cash from continuing operations, which excludes an increase in working capital of about $600 million. We've also generated $1.6 billion from asset sales. To date, we have spent $8.2 billion in capital, which includes approximately $500 million of deepwater Angola exploration and Gulf of Mexico leasehold. It also includes a heavier spending on the APLNG project, and we expect in the balance of 2012. We paid $1.7 billion in dividends, continuing the same dividend rate as Caprice did in the integrated ConocoPhilips. Related to the repositioning, the net income impact -- the net impact, cash flow impact of the spinoff of Phillips 66 was $5.7 billion. This was a combination of all of the operating, investing and spin-related transactions for the operations of what the assets that are now in Phillips 66. During the first 2 quarters of the year, we also repurchased $4.9 billion of our shares and that left us with $6 billion in total cash at the end of June, including $5 billion in restricted cash and $1 billion in cash and cash equivalents. During the third quarter of this year, we expect to begin using some of these cash balances to reduce our debt balance. So with that, I'll turn it back to Ryan for some closing comments.

Thanks, Jeff. And if you could turn to Slide 19, I'll try to wrap up a little bit. I think the takeaway that we'd like to have for you all for today's call is that the business is running well, and our plans are on track. The spinoff of Phillips 66 was a big milestone for the company, and it successfully launched ConocoPhilips as an independent E&P company. Operationally, we had a strong quarter, and that part of the business is delivering on our expectations. Certainly, our focus will remain on returning value to the shareholders through our dividends, and by executing on our major projects, our exploration programs and our asset sales. The asset sales are important because they generate proceeds that help fund our high return growth projects. And we certainly will keep a close watch on the macroenvironment and we believe the investments that we're making today are going to position the company to deliver on our long-term value proposition of 3% to 5% growth in production and margins, with improving absolute financial returns and combining a sector-leading yield. So that wraps up our summary that we had today, and look forward to the questions from the audience.

[Operator Instructions] And at this time, we have a question from Faisel Khan from Citi.

On Slide 5, I think you mentioned in your prepared remarks the amount of cash flow you expect to generate from operations under consensus estimates. I just want to clarify that, was that $40 billion, did you say? In '12 and '13?

No. The consensus cash from operations is not the $40 billion. We think per year it's in the $12 billion to $14 billion range.

$12 billion to $14 billion. Okay, great perfect.

Yes, so you add the $6 billion of cash on hand, plus what we expect to get from asset dispositions, is what adds up to the $40 billion, Faisel.

Okay. Got it. And then on Peng Lai, what's -- assuming you can get up to full operatable capacity, what is that potential number over the long-term, assuming you can get to your, all the permits in place and be able to get back to producing in all those fields?

Yes, I think you ought to think in terms of 110,000 to 120,000 barrels a day gross.

So net back to us is in the 40,000 to 50,000 BOE per day level.

Okay. Got you.

And we would -- that compares to around 60,000 before the events.

Okay, understood. And then at APLNG, given your reduced working interest now in that facility and also given the project financing that you have in place, what kind of spend or what kind of equity contributions will have to -- will you be obligated to make to APLNG over the next sort of year or 2?

So what we find is that over the second half of 2012, that the project financing and the fact that the additional interest that Sinopec is going to acquire as part of the final investment decision on the second train will fund most of the -- most of our capital requirements for the balance of the year. And then we'll see lower capital requirements on APLNG as primarily related to project financing next year as well.

Our next question comes from Paul Sankey from Deutsche Bank.

I'd very much like for you, your continued clarity and also, really, truly appreciate your level of disclosure that you give it. It's admirable. On the basic question of the cash flows, just one point, you didn't say anything about growing the dividend, but assume that's your aim.

Yes. Certainly, I think our strategic intent, we talked about is delivering 20%, 25% of our cash flows back to the shareholder, primarily through the dividend channel. And so as we grow our production, grow our earnings, grow our cash flows, that 20% to 25% is intended to grow as well.

Okay. I understand. It's actually also a very interesting target. I was going to move on to that, that the idea that you would give back around 25% of your cash flows. I guess what we're all struggling with is you mentioned that the consensus cash flows right now at $12 billion to $14 billion annually, which even arguably, I think, is on a relatively aggressive oil price forecast. So that's why it's helpful to see the uses of cash by priority. I guess what we're struggling with is the extent to which, over time, you're going to have to cut back that capital program. Could you just talk more, yet more about the sensitivity of the program and how much you could potentially cut that back to balance your cash flows over the longer term?

Yes. So a couple of comments there from Paul first. As I talked about, the company is going through some fairly significant production growth and growth that's occurring at fairly high margins. So if you think about it, it's going from production level 1.5 to 1.6 up to the 1.8 to 1.9 kind of level over several years, that adds significant cash flow and then, as we've talked before that regardless of the price environment we're in, by virtue of moving the portfolio more to liquids and as well moving it more to jurisdictions, which have lower taxes, we're going to see margin improvements. So as we look at out over the next several years, the difference between what we're generating in terms of cash and capital and dividends, of course, shrinks over time. What we're trying to lay out for you this morning is that in this interim time period where it may not be covered then, and then we have other sources of cash to balance that gap and then we think it makes sense to continue to invest in the capital that we have. Ryan, I don't know if you want comment on where we might cut capital if we end up, really, lower price environment?

Yes, certainly if -- so we've seen some drop off here from branded $120 down to arguably $100 reductions over the last -- through this last quarter. We still think Brent's in the $90-ish, $100 range is probably reasonable over the short-term. But if we saw some cycling down of prices and we felt like they were going to be here for 2 or 3 years, we would make adjustments to our capital program. We're doing some of that through our disposition process and -- but we've identified some high capital-requiring assets that we would like to dispose of. We've got capability to throttle back on some of our exploitations and in -- across all of North America, really across the whole global portfolio, and we would look at that as well. We want to continue some of our, what we think are the high-quality, high-margin, high return major projects. We're not going to whipsaw some of those right now, being some of our ones in the North Sea at, in Norway, the U.K., Malaysia, some of those we'd like to continue going. But we've got some optionality and in the portfolio, if we saw lower prices, we're going to persist for 1 year or 2.

Yes, I think we've experienced over time too, is that as prices come down, the activity levels come down across the industry. You'll get the same amount of scope done for a lesser amount of money as well.

Yes. The -- if I think about the relationship you have with between the SCCLs and the share repurchases, and the commitments you made essentially to buy back shares through the first half of the year, where are we sitting now on buybacks for the rest of 2012 and into the first half of 2013? And knowing what you're saying about asset sales and share repurchases because it feels like you might be in a position to actually pretty much stop the buyback now?

Well, we completed the $5 billion that we said we would fund through the first half the year. Our priorities have just kind of shifted with some of the reductions in the commodity prices that we've seen over the last quarter. So as we look out ahead, the asset sales and dispositions will be used to help fund our capital program. If we end up getting an increase in dispositions above kind of what we're forecasting, or if commodity prices ramp back up a little bit, then that would leave room for us to consider more share repurchase.

Is that saying that basically the share repurchase has stopped now?

Yes, they have stopped.

Our next question comes from Ed Westlake from Credit Suisse. Edward Westlake - Crédit Suisse AG, Research Division: Just that you've laid out how cash flow margins are going to rise and therefore, cash is going to expand over time. Just still running through these cash balance numbers, do you have a number, I mean, a rough range? Obviously we don't know what you're going to sell, but for the CapEx that is associated with the disposals?

If you looked at -- had we disposed of kind -- a rough range, yes, if we would dispose of everything that was on our -- that they were contemplating as asset dispositions as of the beginning of this year, probably would have taken $1 billion to $1.5 billion of capital out of our -- out of this year's capital program. Edward Westlake - Crédit Suisse AG, Research Division: Right. And so that will free up that CapEx, plus maybe once APLNG is got through to invest more aggressively in shale?

Yes. I think as we look forward over the next -- right now, we would think that our capital expenditures in 2013 are going to be in the range of $15 billion. And that includes, as you mentioned, a fairly -- a continuation of the aggressive investment levels we're doing in the Lower 48 and in the resource plays. Edward Westlake - Crédit Suisse AG, Research Division: And then, obviously, as you look to the divisional disclosure, Canada is suffering, maybe you could take back in the Permian is suffering from low realizations. Apart from others, building pipes to help you get to higher realizations on the production you're getting there. I mean, can you talk through your strategy to try and maximize realization for those onshore assets?

Yes, Ed, we're -- we talked a little bit about that in terms of the 2012 capital that we see clarity on for the rest of the year and part of that is spending a fair amount of infrastructure to help our realizations and make sure we can move the product where it's getting bottlenecked and make sure we can get it sold. So we're doing a fair amount of that where it makes sense, where there's competition and where we can get to third parties for a reasonable cost, we will do that. But we're also focused on spending our own capital if we need to build our own infrastructure to make sure that we're maximizing the realizations. Edward Westlake - Crédit Suisse AG, Research Division: Final one for me, you mentioned the Mancos. Any other, any results you can share from them? And I do see your permitting down and your acreage down in Southern Louisiana, I mean, any results or targets that you are probing there?

Well, none that we would -- that I think we can disclose today, it's all a pretty competitive position. We want talk a little bit about of the Mancos because, obviously, we've got a lot of that acreage held by production. So we're still studying that and hope to have results later this year.

Our next question comes from Arjun Murti from Goldman Sachs.

Just wanted to clarify the stock buyback commentary. I think we've always thought that future asset sales, those proceeds would be used to buy back shares. It sounds like it's not probably as direct going forward, it will be a function of what cash you have available, is that accurate?

Yes, I think that's fair, Arjun.

Yes, that's great. And then, in terms of the -- so you're going to spend $16 billion in capital this year, you have the kind of $15 billion-ish number for next year in long-term. Does that contemplate the $8 billion to $10 billion of asset sales? Or would that $15 billion-ish kind of number come down once you're finished with your asset sales?

No, we think that that's -- as we look at the portfolio, look at the opportunities that, look what we've added in the North American on conventionals, we look out over time and $15 billion feels like a pretty reasonable kind of capital figure, if that -- if commodity prices hang in at kind of today's level or even a bit softer.

That's great. That make sense. And then just last one for me, some of the peer companies in Australia LNG has had some budget increases, I'm -- my understanding is you all had more of a contingencies built into your budget. But just wondering if you could comment on what you're seeing down there and how good you do feel about the current budget?

Yes. I know we have seen some announcements. When we came out, we felt like all along, Arjun, that 1 Train project or a 2-train project in Curtis Island was about $20 billion. That was our estimate a couple of years ago, and we're -- we haven't seen anything to think that, that would be any different. I think the, we -- I think the other projects are just now realizing what it's going to cost if the -- on Curtis Island.

Our next question comes from Jason Gammel from Macquarie.

I had a few more on APLNG, if I could, please. First of all, on the Upstream program, I believe you guys are actually a fair bit ahead of the other projects that are going forward in Queensland. But can you talk about what type of a forward drilling program that you need to have to match the Upstream with the Downstream requirements, I guess, in terms of number of wells to be drilled and then also in terms of rigs that you would need to run?

Yes, might have to get back with you on the specifics with that, but I -- we would think we're running today a 3, 4 rig program, and feel like we've got, with the efficiencies that we're gaining and the number of wells we're drilling on a daily and a monthly basis, we're ramping up the well count in front of the start up of the first train. So when the first train's ready to come online in 2015, we'll have the supply ready to go. And then we're continuing to drill because 6 to 9 months later, the second train will come online so we continue to drill and have the Upstream capacity available for that.

Sure. And then, in fact this was the logistics are obviously fairly difficult, trying to match that number of wells with the requirement that you have, so do you feel that the arrangements that you have commercially with the domestic market and some of the other projects give you more flexibility in how you manage that Upstream process?

Yes, I think we're probably uniquely positioned there, because we're selling over 200 million a day to the domestic market today, and we've got the ability to dewater wells and throw wells into the domestic market in knots. We've got a lot more flexibility to be able to manage our available capacity on the front-end to make sure when the plant's ready to go, that we can deliver the gas to the plant.

And then one more on APLNG if I could, please. You mentioned that you have project financing in place. Can you talk about, just in rough numbers, what percentage of the overall capital requirements will come from the project financing facility?

Yes, the project financing that was completed was the agreements were signed back in the second quarter is an $8.5 billion project financing, so it's so roughly 40% of their requirements.

Great. And just, how much cumulative cash flow would you need to generate -- to repay whatever principle amount you have to do first and fund any contingency accounts before APLNG could start dividending cash back to you?

Well, the repayment of the financing happens over a long period of time, so as soon as APLNG starts stuff, it will start paying out a dividend.

Okay. So you wouldn't have contingency account funding that would have to come in front of dividend payments to the partner group?

No. I mean, it's going to be part of what gets funded overall with the project, so when we start up we will begin to make distributions.

Our next question comes from Blake Fernandez from Howard Weil.

If I could just tack on to the APLNG question. So I'm just curious, you've sanctioned the second Train, obviously, that helps with scalability and efficiency, and should improve overall return. So just curious, given the second quarter return on capital employed for the entire company at around 11%, do you think this project will be accretive to overall returns?

I think APLNG will be accretive to overall returns in the long-term, but it will be a challenge to our overall returns in the near-term. And that's pretty consistent with all long-life projects where you end up putting a lot of capital on the books upfront and then you get that back over a long a period of time. So it's probably not accretive in the short-term. It will be accretive in the long-term.

But it is -- then the issue there is the reason you've seen us dilute from our -- are willing to sell equity to a marketing entity to purchase a portion of the project and our willingness to be able to do that and that's caused us to go from the 50% down the 37.5%, and we're looking for -- probably some opportunities for some further dilution at APLNG.

Okay, great. The second question was on the exploration front. Ryan, I know you gave us a few impact wells going down on the Gulf of Mexico. I was just curious, is there anything else globally that we should be aware of that could be high-impact? And then I know you mentioned Angola, seismic, could you give us an idea of when we may spud the first well there?

I think we're looking in Angola the end of 2013, early 2014 for a well. We're in the middle of capturing 3D seismic. I think we pretty much completed our initial program in Bangladesh and we'll get that data in, so that well is probably pushed out. The other one I would probably point out in terms of impact is we're kind of at front end of our Poseidon appraisal program in the Browse Basin of Australia, but that will be a, probably a year-long, 5 or 6 well program.

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

A couple of things for me. When you did the separation, Ryan, you projected or you laid out all these projections, there was one point that we're assuming $120 Brent at that time. The margin improvement assumption of 3% to 5%, I guess, had that as a backdrop. If you have to reset, I'm guessing why haven't you reset your assumptions to what the futures curve looks like right now, and would that change the margin improvement? That's my first question.

Well the, yes, I know we continue to get some of those questions, Doug. I just remind everybody, we, when we came out in April and we described that a little bit, were trying to describe what current prices were and how the margin of an improvement. The important part is this, we look at the portfolio, and we look at where we're investing the money, whether you pick $120 or $100 or $90 oil or $80 oil, our margin is going to improve on a flat price basis, and we believe the 3% to 5% is coming at a flat price. So it's not reliant on $120. So as we look at our plans today, and we look at the investments that we're making relative to the existing portfolio, our margins are going to be improving over the next 3 to 5 years, and we -- the absolute production growth and the margin growth is coming. And we're investing in things that are changing the mix in the portfolio, and are changing the tax burden on the company as well.

I just have a couple of other quick ones, if I may add. As usual it's -- I guess this is where my confusion comes in. It's related to that issue of mix. So when we look at Australia LNG, and that's a very large part of your incremental organic growth. I certainly had discussions with your team about this, but the implied, the IRR presented on Australia LNG which shows 8% to 10% at your internal assumptions, can you share with us what -- how those assumptions differ your cash flow assumptions, in other words $120 oil, because what I'm trying to figure out is, in the world oil price assumption was so much of your growth coming from APLNG, how does that then jive with the incremental improvement in cash margin, that 8% to 10% IRR?

So if I may, a couple of clarifications there, Doug. So the 8% to 10% IRR is not what you would have at $120 oil price. And we seem to be doing much better than that, $120 oil price. So when we talk about margins, we're talking about cash margins. So when the APLNG starts up, you're getting a significant return of, you're getting a return on your capital, you’re getting your capital back as well. So the cash margins is going to be pretty robust on that project, kind of regardless of what price environment that we're in. So that those -- that will be a significant source of cash for us upon start up.

What I'm trying to figure out, Jeff, is well, can you share with us what commodity assumption does equate to 8% to 10?%.

That was more on a $90 tough type price environment.

Okay. So $90 per barrel, would that still be accretive to cash margins?

Yes.

Okay. Final one then for me is on the disposals, the $8 billion to $10 billion, can you give us some scale of production and cash flow associated with those? And I'll leave it at that.

From a production standpoint, like we said before, it would depend upon the mix, because there is a, in that $8 billion to $10 billion is a mix of assets that are currently producing and currently not producing. So impacts on current production are probably in the 50,000-barrel a day type range, and depending upon the mix, it could vary from plus or minus 25,000 barrels a day on either side of that. Then cash flows, I don't think I have a number that we can throw out to you on that.

Our next question comes from Iain Reid from Jefferies. Iain Reid - Jefferies & Company, Inc., Research Division: Jeff, could I just go back to your comments on the U.K. part of the business. And you were talking about the impact of the tax change on abandonment. And you mentioned a number, which is going to affect, I think you said third quarter earnings. Can you just confirm what that is, and whether it's a onetime charge? And with the kind of ongoing effect on DD&A could be?

It's a one -- that is a one-time charge of around $175 million, and that just really reflects the fact that when the U.K. increased tax rates earlier, or it was last year, up to around the 62% range, they said they might be coming out later with some restrictions on how much you could deduct on abandonment obligations. What they've done that now, and said that only 50 -- you only get 50% tax relief on abandonment obligations. That mark of our deferred tax liability down to reflect that change is what the $175 million should be. So it's to be a onetime special item type event in the third quarter. Iain Reid - Jefferies & Company, Inc., Research Division: And there won't any kind of ongoing effect on your DD&A per barrel rate?

There could be some, no, no, no, there isn't, because it's just -- that's just a -- that's a before tax item. Iain Reid - Jefferies & Company, Inc., Research Division: Okay. And secondly, on NGL pricing, there's going to be a fair amount of investments in infrastructure, et cetera. I just wanted to -- when you look at these very depressed prices you're getting in the Lower 48, how long you expect those to have such a big margin to oil prices going forward? And whether you've thought about any sort of hedging program, for that? Obviously, it's not great to under hedge now, but whether that's something we should might want to look to protect in the future?

So NGLs, as we've pointed out, are around, globally, about 9% of our production and the Lower 48 and Canadian portion of that is like 6% or 7% of our production. As we look across over time, if you roll the clock forward several years, our NGL production, we would anticipate to be relatively flat and with our growth is going to be coming from crude oil production. So we don't have increasing exposure to NGLs going forward. I think we see that the market is going to be fairly soft, particularly for ethane in the near term, which is what's really driving down the overall price of NGLs. And -- but that will get solved with all the capacity expansions that you're hearing, talked about in the chemicals side of the business right now. So we don't think it's a long-term phenomenon, but that kind of low NGL price is going to attract additional investments. Iain Reid - Jefferies & Company, Inc., Research Division: Okay. And my last one, I'm going to go back to APLNG, I'm afraid, the other guys have announced big increases, also talked about the translation effects of the Aussie dollar, and I presume, that when you launch this project, you were looking at a much lower level of the Aussie dollar versus U.S. dollar. So is that -- does that $20 billion budget you have, do you cover this kind of big increase in Aussie dollar exchange rates? Because I believe that's a very substantial portion of the overall CapEx is denominated in local currency?

It is. I mean, that number reflects our current estimates with the way the market looks now on the Australian dollar, but -- and that continues to be, like with the other projects, that continues to be one of the larger exposures we have on the project is, is if there is a further weakening of the U.S. seller relative to the Aussie dollar. Iain Reid - Jefferies & Company, Inc., Research Division: So is it fair to say you've probably used up all contingency you had initially on that project?

No, I wouldn't say that. I'd say that we feel like the numbers that we had out there now still has contingency in them.

Our next question comes from Paul Cheng from Barclays.

First, I want to echo to early comment that wanted to thank you for the expand disclosure, very helpful and I appreciate it. But just one possible request, that since that you're going to break out the earnings by different regions, can you also break out your exploration expense in the future by the corresponding region? That would be helpful in the modeling. And that, Ryan, in your presentation that you give the production and the margin improvement target, do you have a proven reserve growth target?

Yes, certainly, Paul, we expect, over time to be more than replacing the production. So we haven't come out and said exactly what it is, but it's -- clearly targets over 100%. It'll be lumpy and there'll be years when it probably dramatically exceeds it, and years when it will be right at it.

Should we assume that you were trying to hold your RDP rates flat, or were -- that's not really a target?

I don't think about, Paul, trying to hold RDP flat. In fact, as we shift our investments in some of these higher-margin, the profile of the some of these investments, I actually expect our RDP will go down a little bit over time, not a lot or not, but will trend down versus trying to trend flat.

Okay. And Jeff, on the asset sale, I just want to clarify that. $8 billion to $10 billion -- does it, for 2012 and '13, does it already include the $1.6 billion year-to-date and also the expected farm down of the -- on the APLNG?

So we do include -- we think about that number as a 2012 and 2013 number. The farm down on APLNG ends up being a contribution into the joint venture, so it's not an asset sale, so.

Okay, so APLNG is not included, but the $1.6 billion year-to-date is included?

That's correct.

And since I've got you, Jeff, that I think you guys have an open leak [ph] in the second quarter around 29,000-barrel per day. What region that if it's -- come from? And also as of the end of June 30, you guys balance or still net overweight? Open leaks [ph]?

Paul, we'll have to get back to you on that. I don't have that right in front of me.

We'll get back to you, Paul.

Our final question comes from Jeff Dietert from Simmons & Company. Guy A. Baber - Simmons & Company International, Research Division: This is Guy Baber here in for Jeff. I was hoping you guys could talk a little bit more about current and planned activity levels and what you're seeing in the Permian basin? And specifically wondering if you had any update with respect to pilot programs in the Avalon and the Wolfcamp? Any comments there will be appreciated.

Well, we, yes, we've got quite a bit of activity going on as Jeff described earlier, we have 6 or 7 rigs running in the Permian basin and those are all targeting some of the existing conventional opportunities that we have. But largely focused on the unconventionals. It's mostly liquids investments in all of the Permians, so we're active in piloting and drilling both the Wolfcamp and some of the other plays in the Permian basin. So yes, we're pretty active there right now. Guy A. Baber - Simmons & Company International, Research Division: Okay. And then also, I had a strategic portfolio management type of question, but Ryan, as you look at the existing portfolio, are there any gaps or areas where you're lacking exposure now that you would like to enhance your position? And then relatedly, internationally, the focus has largely been on OECD geographically for one at risk, and that's worked well for you all. And should we assume that that remains the case going forward? And that would -- would that preclude you from potentially entering some of these international plays that may offer significant long-term resource potential, but do carry a higher risk profile? And I'm thinking of some plays like East Africa for one, or even Kurdistan region of Iraq, any comments there will be appreciated.

Well, I mean, as I look at the portfolio, I'd say we're more after low-cost to supply opportunities, whether that's gas or oil, where we can make a competitive rate of return within our portfolio. As I look at that today, you see are heavily focused on unconventionals in North America because we see a lot of opportunity that are working well. We've got a great position, and so, large part of our investments are going there. But internationally, I'd say as we've -- as you see from our exploration, we're growing our deepwater position, and that's not only in the Gulf of Mexico, but also Angola and the subsalt opportunity there, Bangladesh, we're offshore Sabah island in Malaysia, so you'll see some things that we're doing in the deepwater. We think the liquids-focused deepwater investments make a lot of sense. So I think as we think about it, going around, it's really opportunity by opportunity but looking for a good low-cost to supply and looking for areas. So even playing the Barents Sea in Norway makes sense to us right now, and you've seen us capture some acreage positions up there. So I, we -- in terms of holes, don't think we have a hole that we're really trying to plug. We're just really focused on value and focused the returns and making sure that what we do go after and capture competes well within our existing portfolio. As you said, we're largely OECD today, so we can take on a little bit more risk in terms of political risk and something like that if we think the returns are going to be competitive.

Okay, thank you, everybody. Go ahead, Kim.

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