David Rosenthal - Vice President of Investor Relations and Secretary

Edward Westlake - Crédit Suisse AG Evan Calio - Morgan Stanley Mark Gilman - The Benchmark Company, LLC John Herrlin - Societe Generale Cross Asset Research Paul Cheng Pavel Molchanov - Raymond James & Associates, Inc. Douglas Leggate - BofA Merrill Lynch Faisel Khan - Citigroup Inc Doug Terreson - ISI Group Inc. Paul Sankey - Deutsche Bank AG Iain Reid - Jefferies & Company, Inc. Blake Fernandez - Howard Weil Incorporated

Good day, and welcome to this Exxon Mobil Corporation Second Quarter 2011 Earnings Conference Call. Today's call is being recorded. At this time, for opening remarks, I would like to turn the call over to the Vice President of Investor Relations and Secretary, Mr. David Rosenthal. Please go ahead, sir.

Good morning, and welcome to ExxonMobil's second quarter earnings call and webcast. The focus of this call is ExxonMobil's financial and operating results for the second quarter of 2011. I will refer to the slides that are available through the Investor section of our website. Before we go further, I would like to draw your attention to our customary cautionary statement shown on Slide 2. Moving to Slide 3. We provide an overview of some of the external factors impacting our results. The global economy and energy markets are being influenced by slower growth and continued uncertainty in the macro environment. A sustained economic recovery remains elusive as a result of persistent sovereign debt concerns, sluggish business investment and lower consumer spending. Energy market continued to see strengthening in crude oil prices in the second quarter, while U.S. natural gas prices showed a modest increase. Downstream industry refining and marketing margins also improved during the quarter, while commodity Chemical margins weakened slightly. Turning now to the second quarter financial results as shown on Slide 4. ExxonMobil's second quarter 2011 earnings, excluding special items, were $10.7 billion, an increase of $3.1 billion from the second quarter of 2010. Our effective tax rate for the quarter was 45%. Earnings per share for the quarter, excluding special items, were $2.18, up $0.58 from a year ago. The corporation distributed more than $7 billion to shareholders in the second quarter through dividends and share purchases to reduce shares outstanding. Of that total, $5 billion was distributed to purchase shares. Share purchases to reduce shares outstanding are expected to be $5 billion in the third quarter of 2011. CapEx from the second quarter was $10.3 billion, up $3.8 billion from the second quarter of 2010, reflecting the increase on our U.S. unconventional activities, including the recently completed acquisition of the Phillips Companies. Across our diverse portfolio, we continue to invest in robust projects through the business cycle to help meet global demand for crude oil, natural gas and finished products. Our cash generation remains very strong with $14.4 billion in cash flow from operations and asset sales. At the end of the second quarter, cash and marketable securities totaled $10.3 billion, and debt was $16.5 billion. The next slide provides additional detail on second quarter sources and uses of funds. Over the quarter, cash and marketable securities decreased from $13.2 billion to $10.3 billion. The combined impact of strong earnings, depreciation expense, higher working capital and the benefit of our ongoing asset management program yielded $14.4 billion of cash flow from operations. Uses included additions to plant, property and equipment or PP&E of $7.8 billion and shareholder distributions of $7.3 billion. Additional financing and investing reduced our cash and marketable securities by $2.2 billion including the acquisition of the Phillips companies. We will now provide a review of segmented results starting on Slide 6. ExxonMobil's second quarter 2011 earnings of $10.7 billion increased $3.1 billion or 41% from the second quarter of 2010. Upstream earnings increased $3.2 billion, while Downstream earnings improved by $136 million. Chemical earnings were essentially flat. Higher corporate and financing expenses decreased earnings $174 million versus the second quarter of 2010 due mainly to the absence of favorable tax items. Corporate and financing expenses remain within our continued guidance of $500 million to $700 million per quarter. As shown on Slide 7, ExxonMobil's second quarter 2011 earnings of $10.7 billion were in line with the first quarter of 2011 mainly due to higher Downstream earnings, offset by slightly lower Chemical and Upstream earnings. Moving next to the second quarter business highlights and beginning on Slide 8. We will begin with an update on a number of our Upstream liquids projects. During the quarter, we fully funded the Banyu Urip project on the Cepu Block in Indonesia. The full field development is expected to recover $450 billion oil equivalent barrels of reserves and deliver gross production of 165,000 barrels per day via a 60-mile pipeline to an offshore floating storage and offtake vessel in the Java Sea. In Eastern Canada, we achieved early oil production from the first well of the Hibernia Southern Extension project. Project development will continue over the next few years, including drilling more wells and providing water injection capability with full production plateau anticipated in 2014. We also continue to ramp up activity in Iraq and currently have 5 drilling rigs operating. Current gross production is approximately 340,000 barrels per day. We are also progressing front-end engineering and agreements for the common seawater supply project. And lastly, we continue to make strong progress at Kearl, where we are currently 68% complete with construction. Turning now to our exploration activities on Slide 9. Beginning in the Black Sea, where ExxonMobil holds 6.6 million net acres, the Deepwater Champion drillship arrived in the second quarter. We are now drilling in the Kastamonu exploration well in the Turkish Black Sea. We expect to have results from this high-risk, high-potential exploration well later this year. In the U.S. Gulf of Mexico, where ExxonMobil holds 2.1 million net acres, we made a significant oil discovery with the Hadrian-5 exploration well, which commenced drilling in March, 3 days after receiving permit approval from the Bureau of Ocean Energy Management. As recently reported, the Hadrian-5 wildcat confirmed the presence of a second oil accumulation in Keathley Canyon block 919. The well encountered 475 feet of net oil pay and a minor amount of gas. We are drilling ahead to deeper objectives and have encountered an additional 250 feet of net oil pay to date. Combined with our other Keathley Canyon blocks, we estimate a recoverable resource of more than 700 million oil equivalent barrels, making this one of the largest discoveries in the Gulf of Mexico in the last decade. More than 85% of the resource is oil. We're also working with our joint venture partners and other lessees in the areas to determine the best way to safely develop these resources as rapidly as possible. Turning now to the Phillips acquisition on Slide 10. ExxonMobil concluded the acquisition of the Phillips companies on June 2, 2011. The Phillips transaction included 317,000 net acres across the heart of the rapidly growing Marcellus Shale play and nearly doubles ExxonMobil's acreage to more than 700,000 net acres in the play. XTO will manage the Phillips assets from the recently established Appalachia Division headquartered in Pittsburgh, Pennsylvania. Given the proximity to our current operations in Southwestern Pennsylvania, the addition of the Phillips acreage will create significant value by leveraging regional synergies and also makes ExxonMobil a leading leaseholder in the Marcellus. The Phillips properties currently produce 50 million net cubic feet per day of natural gas, which includes both shallow gas and deeper Marcellus production. Turning now to our total U.S. unconventional portfolio on Slide 11. In the U.S., XTO is currently managing total resources of 76 trillion cubic feet equivalent, which represents an increase of almost 70% from what was initially recognized at the time of the merger. As shown in the chart, nearly 2/3 of the resource additions are from revisions and corporate transfers, demonstrating the benefit of the XTO merger. The revisions resulted from buy-the-bid activities such as down spacing, additional development and new plays. Over 12 trillion cubic feet equivalent of resource additions have been added through acquisitions, including the 2010 Ellora-Haynesville-Bossier and Petrohawk-Fayetteville acquisitions, the 2011 acquisition of the Phillips companies and several other low-cost acquisitions. These resources were added at an average cost of approximately $0.28 per thousand cubic feet equivalent. Turning now to our global unconventional portfolio on Slide 12. ExxonMobil has a diverse portfolio of the emerging unconventional resource opportunities with access to more than 10 million net acres in North and South America, Europe and Southeast Asia. Beginning in Argentina, we hold approximately 240,000 net acres in the prospective Neuquen Basin and will begin drilling in the fourth quarter of 2011. In Canada, we are continuing drilling in the Cardium and the Horn River basins. In Columbia, we are preparing to begin core hole drilling in the fourth quarter to evaluate heavy oil potential. In Poland, we are preparing for well testing. And in Germany, we are progressing permit approvals for our well testing program. In China, we are progressing opportunities with the Chinese national oil companies to apply ExxonMobil's leading-edge technology to develop unconventional gas resources. Finally, in Indonesia, we've commenced coal bed methane drilling in the quarter and are now on our third well in the Barito Basin. These opportunities represent a large and growing global portfolio of unconventional assets with the potential for significant value creation through the application of ExxonMobil's advanced technologies and XTO's strong operational and technical expertise. Turning now to the Upstream financial and operating results starting on Slide 13. Upstream earnings in the second quarter were $8.5 billion, up $3.2 billion from the second quarter of 2010. Stronger crude oil and natural gas realizations increased earnings by $3.6 billion as crude oil realizations increased approximately $36 per barrel, and gas realizations increased $1.42 per kcf. Production mix and volume effects decreased earnings by $480 million due mainly to the impact of lower entitlement volumes, downtime and decline, partly offset by the ramp-up of Qatar and Iraq projects and the addition of XTO. Additionally, earnings were negatively impacted by the timing of lifts. Upstream after-tax earnings per barrel were $21.35. Moving to Slide 14. Oil equivalent volumes increased 10% from the second quarter of last year, mainly due to growth in our U.S. unconventional resource business and the impact of Qatar and Iraq project ramp-up. Volumes were, however, negatively impacted by lower entitlement volumes, divestments, downtime, lower gas demand in Europe and decline. Turning now to the sequential comparison starting on Slide 15. Versus the first quarter of 2011, Upstream earnings decreased by $134 million. Stronger realizations improved earnings by $1.2 billion as crude oil realizations increased over $11 per barrel. Production mix and volume effects decreased earnings by a $1.1 billion due mainly to lower seasonal demand in Europe, higher maintenance and the impact of lower entitlement volumes. Additionally, earnings were negatively impacted by the timing of liftings. Other items, primarily higher exploration and operating expenses, decreased earnings by $310 million. Moving to Slide 16. Oil equivalent volumes decreased 9% from the first quarter of 2011 due mainly to lower seasonal demand in Europe, downtime and the impact of lower entitlement volumes. The facilities that experienced downtime during the second quarter of 2011 are now essentially up and running. Lastly, I'll note that year-to-date oil equivalent volumes increased 10% or over 400,000 oil equivalent barrels per day compared to the first 6 months of 2010. Excluding the impacts of entitlement volumes, quota effects and divestments, production was up over 12% and remains consistent with the 2011 volume guidance we communicated at the March Analyst Meeting of 3% to 4% growth versus 2010. For further data on regional volumes, please refer to the press release and IR supplement. Moving now to the Downstream financial and operating results starting on Slide 17. Downstream earnings in the second quarter were $1.4 billion, up $136 million from the second quarter of 2010. Improved margins increased earnings by $60 million, primarily driven by improved industry refining margins. Continued benefits from our refining optimization activities contributed $150 million in volume and mix effects while other factors were a negative $70 million. Moving to Slide 18. Sequentially, second quarter Downstream earnings increased $257 million. Higher industry refining and marketing margins increased earnings by $350 million, while volume and mix effects decreased earnings by $50 million. Other factors were a negative $40 million. Turning now to the Chemical financial and operating results and starting on Slide 19. Second quarter Chemical earnings were $1.3 billion, resulting in a record $2.8 billion of earnings for the first half of 2011. This performance demonstrates the value of our balanced portfolio of commodity and specialty businesses, integrated world scale facilities, premium products and technology application that delivers superior feedstock advantage. Second quarter earnings were essentially even with the second quarter of 2010. Increased Chemical margins contributed $120 million, driven by strong demand. Volume and mix effects lowered earnings by $90 million, mainly due to higher plant maintenance activities. Other effects decreased earnings by $80 million. Moving to Slide 20. Sequentially, second quarter Chemical earnings decreased $195 million. Lower margins decreased earnings by $80 million, primarily due to weaker global aromatics margins. Other effects decreased earnings $110 million due mainly to higher turnaround and maintenance cost and some unfavorable tax benefits. Moving to Slide 21. While we manage our Downstream and Chemical businesses separately, we continue to capture benefits from the unique integration and optimization of these businesses. Looking at our combined Downstream and Chemical results, second quarter earnings were $2.7 billion. Moving to Slide 22. ExxonMobil's second quarter financial and operating performance was strong and reflects the ability of our business model and competitive advantages to deliver strong results. As we continue to focus on operational excellence, deploy high-impact technologies and leverage our unparalleled global integration, ExxonMobil remains well positioned to maximize long-term shareholder value. That concludes my prepared remarks. I would now be happy to take your questions.

[Operator Instructions] We'll go first to Doug Terreson at ISI. Doug Terreson - ISI Group Inc.: I have a question, really just kind of a clarification. In the Upstream, you mentioned that the other item, which was fairly meaningful this quarter, was -- which was $310 million was exploration and something else. What was that something else, number one? And number two, was most of the delta this quarter exploration?

You're looking sequential at the $310 million? Doug Terreson - ISI Group Inc.: Right.

Yes. The primary items there were the higher exploration expense as well as some higher production OpEx associated with the maintenance activities I mentioned. Doug Terreson - ISI Group Inc.: Okay. And then together, that added up to a decent sales number. The $150 million in refining and marketing and Chemicals, just generally, what were those?

Oh, on the volume mix effects? Doug Terreson - ISI Group Inc.: The other item, sequential?

Oh, sequential. Okay. Doug Terreson - ISI Group Inc.: Yes. Sorry.

Yes. If you're looking sequentially on the Downstream earnings, the $40 million, there's really nothing significant to highlight. We did have some higher maintenance OpEx that I mentioned. That was the primary driver there. Doug Terreson - ISI Group Inc.: Same in Chemicals? Is that the way to think about it?

In Chemicals, if you're looking at both, actually sequentially and quarter-over-quarter, it's really higher turnaround OpEx, the primary drivers there. Doug Terreson - ISI Group Inc.: Okay. And also, you guys have obviously been very successful in the deepwater Gulf of Mexico, and I think you said you haven't TD-ed the exploration well yet. But so maybe earlier -- early, but do you have an idea as to future evaluation and approximate timing for that play? And also, is there transportation infrastructure in the area?

Well, if you look at what we're doing in the area -- and again, we do have a very nice oil discovery there. And as we've mentioned publicly, we are going to work with our partners and other lessees in the area, particularly with the Lucius discovery, to take that well and include it with their reserve so that we can give that production on safely and rapidly. The rest of the block, of course, we have both the Hadrian North discovery, which is a standalone oil discovery that will not be included in that unit. We're working on what the optimal development scenario in that might be. And we've also announced that the Hadrian South discovery, which is gas, will also be processed up through the assets in the Lucius discovery, again, to get that gas to market. So it's very fortunate that we have the ability to monetize a big portion of those reserves quickly, but at the same point, we're pretty excited. We're still drilling, and we got a lot of additional evaluation and appraisal to do out there. So it's a good success story and a nice opportunity to get some production on pretty quickly.

Next we'll move to Blake Fernandez of Howard Weil. Blake Fernandez - Howard Weil Incorporated: Just wanted to clarify on Hadrian while we're talking that -- you mentioned that the incremental 250 feet of pay, I wanted to just confirm, is that over and above what you had previously reported in the press release? And if so, does that indicate potential upside to the 700 million BOE?

The answer to that is yes to both of your questions. That's an addition to what we had announced earlier, and it certainly provides some upside. And also, as you know, it's normal in the -- in this business that there will also be some redetermination opportunities as we progress the current development of the Hadrian-5 well. So again, good news so far, lots more to look at and evaluate. And certainly, we'll be evaluating the upside, and we'll assess the total that we have once we hit TD. Blake Fernandez - Howard Weil Incorporated: Okay. Great. And my second question, Dave, was on CapEx. If you look at the run rate for the first half of the year, it's an average of about $9 billion a quarter, which would kind of suggest about $36 billion total, which is maybe a couple of billion above what your guidance is. I'm just curious, does second half of the year likely fall off a bit? Or you may be trending above where guidance was?

Well, I think the first thing to note is if you take out the Phillips acquisition, the CapEx in the first half is right in line with what we talked about at the March Analyst Meeting. So ex any acquisition opportunities that come along, I really don't have any different guidance than what we talked about earlier in the year.

We'll take our next question from Mark Gilman at The Benchmark Company. Mark Gilman - The Benchmark Company, LLC: If you could just help me and clarify, in your sources and uses of funds and that reconciliation, exactly where is the Phillips acquisition showing up. I thought it was in the additions to PP&E. And then there's this $2.2 billion item, which I guess, even with your comment, I still don't quite understand what it represents. Was there debt associated with Phillips and that's part of that $2.2 billion?

No, Mark. Mark, thanks for the opportunity to clarify that. No, the entire $1.7 billion that we've paid for the Phillips acquisition is in that $2.2 billion number called additional financing and investing. That's what that amount is. It's not in addition to PP&E. Mark Gilman - The Benchmark Company, LLC: Okay. Was there debt associated with that acquisition, which I believe was a stock acquisition, not an asset acquisition?

No. There was no debt associated with that. Mark Gilman - The Benchmark Company, LLC: Okay. My second one, you referred in your comments to liftings and timing effects on the production numbers. Does that mean or should I assume that your liftings in the second quarter of '11 were lower than production? Or was that delta versus the year ago period associated with second quarter 2010?

No. That's a good question. Let me clarify that. We were underlifted in the second quarter by about, in absolute terms, 69,000 barrels a day. And we were underlifted in the second quarter of last year about 26,000. So the delta is an additional 43,000 barrels a day underlift. And then sequentially, the factor was actually a little bigger. We were in the delta. We were a little overlifted in the first quarter. So if we look at the delta between first and second quarter sequentially, we're net under-lift position of 87,000. Mark Gilman - The Benchmark Company, LLC: Try that last line one more time.

If you're looking sequentially, we were underlifted in the second quarter 69,000 barrels a day. We were overlifted a little bit in the first quarter 18,000 barrels a day. So that net between quarters was 87,000 barrels a day. Mark Gilman - The Benchmark Company, LLC: Okay. Got it. That 6,900 lift, any particular region?

The bulk of it was in West Africa and the North Sea. Mark Gilman - The Benchmark Company, LLC: So relatively high-margin barrels?

Yes.

Next, we'll move to Ed Westlake with Credit Suisse. Edward Westlake - Crédit Suisse AG: Just a question on this CapEx. I mean, obviously, you are still responding after the XTO acquisition and picking up acreage here and there. I mean, should we think of sort of $2 billion here and there as a reasonable addition to your organic CapEx over the next couple of years?

Ed, I really don't have an answer to that, because we don't have a specific target or objective. It's purely opportunistic. As I've mentioned before, we, of course, are pursuing resources around the world, including unconventional in the U.S., all the time. And when we find a really good opportunity, like the Phillips acquisition for example, where we can leverage either some already existing assets that we have or bring some technology to bear, we will take advantage of that opportunity. But again, it's all about increasing value and particularly, leveraging what we have in the base through the merger with XTO. As you kind of start to see on that chart that we showed, you're really starting to see how that acquisition has enabled the growth in that business that otherwise would have been very, very difficult to accomplish. And then in particular, when you look at the low-cost that these incremental reserves and acreage are adding, and you start to look across that portfolio and then in addition, the opportunities that may come along from the additional volumes from overseas, you really start to see kind of what might be the value created by this global portfolio of unconventional assets. And again, with XTO as the enabler, just a year ago, it's pretty remarkable that 12 months after this merger, we've gone from 45 TCF under management to 76. So we're pretty pleased with that progress. Edward Westlake - Crédit Suisse AG: Maybe asking it a slightly different way. At 76 TCF, do you think you've got enough? Or do you think there's still going to be opportunities to continue to...

Well, we never have enough. I hope we can find some additional opportunities. We're certainly pursuing those. And again, if we come across something that's attractive, that we can bring something to the party to get value that others can't, we will, of course, take advantage of that. And again, as we've said from day one, we're looking for large high-quality resources with upside potential, where we can generate some synergies with the technology and operating expertise that we have. And again, we're actively pursuing those things but without any specific target or objective. Edward Westlake - Crédit Suisse AG: And then one final question on the Downstream in the U.S. I guess, perhaps a smaller uptick q-on-q than I guess I was looking for given the margin environment. Could this just be that 1Q was particularly strong? Or it could that Q2, there was some operational hiccup? Can you give -- talk to any funds that might be between the sequential differences?

Sure. As you mentioned, we did see some nice margin improvement in the U.S., particularly not only along the Gulf coast but as you're well aware of, in the mid-con area. We did have some downtime and maintenance in the second quarter. In particular, we were able to basically get back some of the volumes we lost in the first quarter from weather in the Gulf Coast, but that was offset by some maintenance activities in our Midwest refinery in Joliet.

We'll take our next question from Paul Cheng from Barclays Capital.

Dave, in the -- we heard from some industry news magazine talking about Papua New Guinea your LNG project may have some high copper, that some delay due to the labor or the way how the construction. So can you give us an update on what's going on over there? And is that going to result in any delay of the project startup?

No, Paul. Thank you. I'd be happy to give an update on that project. Things are going quite well. As a matter of fact, the project is progressing well. We've got project execution underway, including all the infrastructure development, roads, bridges, site preparation, camps, et cetera. We're scaling up the mobilization of the contractors as we get into the larger facility build. In fact, we've recently completed some very key milestones, and the project continues as planned. So I mean there's always minor things that come up in any projects, and we manage those. But as we look forward, the project is on target to deliver first LNG in 2014.

Okay. Second question, in the second quarter, can you tell us then what is the production with cost from your Iraqi project? And also that you talked about the underlift in the second quarter and overlift in the first quarter. At the end of June, are you, from an inventory standpoint, very neutral or that you are underlift, overlift? As well as the -- in the second quarter, is there any meaningful asset sales gain or not?

Okay, Paul. Let me track all 3 of these. Okay. When we look at the Iraq project, as we typically don't give individual country volume numbers, I don't have a specific number for you from Iraq. I think the key issue in Iraq is the progress that we're making there. That's going very well. We got 5 rigs running. I got production that grossed up to about 340,000 barrels a day. We're meeting our milestones, and we're working on the infrastructure necessary to continue to grow volumes. As you know, the actual production that you might record in any given quarter is really going to be a function of the price in that quarter as you divide your total revenue by the price to get the barrel. So I don't think that number would be as meaningful as really letting everybody know that the activity level is up. The production is up. We're meeting our expectations, and things are going pretty well in Iraq. If we look at the underlift position, I mentioned that in the second quarter, we were underlifted, on an absolute basis, about 69 kbd. And that's kind of where we are at the end of the second quarter.

So you're underneath by about 69 at the end.

Yes.

Okay. And then in terms of asset sales gain, is there any meaningful asset sales gain in the second quarter? Given your cash proceeds on asset sales is about in the $1.7 billion, and your CapEx base is pretty low, so I presume that you have some decent asset sales gain.

We have an ongoing asset management program, and we've had some nice sales this year already. Of course, we had sales in the first quarter that we talked about. And in the second quarter, we did sell our gas-led assets in Europe, and we did book a -- an asset gain on that. I don't have a specific number for it, but that is included. When you look -- and if you look quarter-on-quarter, in the second quarter, where we have the $60 million other effect, that asset gain is in that number.

Dave, then asset sales, you say your gas is in international E&P?

I'm sorry. Excuse me. Could you repeat?

The gain that you report, under which segment?

Oh, yes. That'll be in the non-US E&P, in the Upstream.

We'll go next to Faisel Khan in Citigroup. Faisel Khan - Citigroup Inc: It's Faisel from Citi. I just wanted to go back to your comments on the resources you've kind of -- the resource evolution of XTO.

Sure. Faisel Khan - Citigroup Inc: And I want to tie that, if I can, to the production volumes you've seen over the last few quarters. It seems like overall U.S. gas production volumes are relatively flat over the last few quarters, and oil production is relatively flat too. So can you talk to me a little bit about the underlying growth of those assets and where we are today?

Sure. If you're looking at the -- let's talk about the XTO first and looking at that chart. Of course, the chart I showed is really the evolution of the resource base itself. And so most of that is acreage that we're just now evaluating the pricing and drilling and that sort of thing, so you don't see a whole lot of production from those resource adds just yet. If you're looking at overall liquids and gas volumes in the U.S, if you're looking quarter-on-quarter this year versus last year, you do see about 72,000 barrels a day increase in liquids. The bulk of that, of course, comes from XTO. And then you do see in the U.S. about a 2.4 BCF a day increase in gas, the bulk of that, of course, coming from XTO. So that gets you year-over-year. When you're looking sequentially first quarter into the second quarter, U.S. liquids are flat, and that does reflect some improvement in the XTO volumes, offset by decline in downtime effect. Gas, as well, in the U.S., about flat quarter-on-quarter sequentially, and that's just reflecting just kind of the normal decline offset by the work programs. And we also had, you might recall, a sale of some Gulf of Mexico assets, and that's contributing a little bit to the overall U.S. numbers there. But overall, things are just as we expected. Faisel Khan - Citigroup Inc: So overall, you continue to expect this portfolio to grow production in the U.S. over the foreseeable future?

Oh, sure. I mean, as we said in our -- in the Analyst Meeting, we do expect that production to grow over time as we develop and bring some of these resources online. But of course, that takes a little time. And it's over time, but we're working on it very aggressively. Faisel Khan - Citigroup Inc: Last question for me. On the -- in your refinery throughput volumes in Asia Pacific, the fourth -- it looks -- it's in the fourth quarter into the first quarter. Those numbers went down for maintenance. And I thought -- in the second quarter, I thought your numbers will come back up. It looks like volume has ticked down sequentially in Asia Pacific first quarter, second quarter. I'm just wondering if you missed some sort of downtime of maintenance activity.

Well, it is. We did have continued maintenance, and it was actually a little higher even sequentially second quarter versus first quarter. So, second quarter was a big maintenance and turnaround quarter for us, in general, across the regions. But yes, you did see it in the Asia Pacific area. Faisel Khan - Citigroup Inc: Okay. Is that -- are those facilities back up and running now at 100%?

Yes, 100%. I know that most of that maintenance and downtime is up and running, and certainly, the turnaround, we're getting behind it.

We'll go next to Evan Calio with Morgan Stanley. Evan Calio - Morgan Stanley: Two questions. As you discussed, Exxon clearly lead the foray into unconventional gas and oil globally, and my questions are on Polish shale. I know you're -- I know we're approaching some important industry well results in the next few months. You have a second well in 4Q. I guess with XTO's expertise, why not a faster ramp-up in Poland, where we have very attractive royalties, receptive host country, at least with the rash of hydro frac-ing concerns and oil-linked commodity prices? I mean, why not a faster ramp there? And maybe you can discuss your recent farm out of 49% interest of the Podlasie Basin to Total.

Sure. Let me step back and give you an overall update on Poland. Actually, we are progressing our activities there fairly rapidly. We had a 3D seismic acquisition program that we concluded in April of this year, and we've got -- we are currently processing those surveys on one of the concessions. And also, we have drilled -- we drilled one well that we suspended in February. We drilled another well that we suspended in April. And well test activity on those wells is underway, and we would expect to have those results sometime in the fall. So we are progressing what we would view as pretty aggressively here. And one of the things that, of course, helps that is the ability to leverage the XTO resources and have them help work on this and both define the appraisal program as well as understand what we have there as we move forward. Evan Calio - Morgan Stanley: Yes. With local services, recently, one of your competitors locked up Halliburton in a contract. I mean, how do you see availability of services? And how are you proceeding to make sure that you have what you need to develop that resource?

Well, clearly, getting services is a challenge to the broader industry as we all advance our plans there. I can tell you, without being specific in terms of contracts that we have in place that we don't have any issues with services and getting the facilities we need. And so we're moving right along. And again, there's no obstacle in the way of progress, and we continue to progress that fairly rapidly. Evan Calio - Morgan Stanley: Okay. A second question on international gas realizations. It's typically been well correlated with a lagged Brent. Some correlations have been dropping, which I guess would be a function in mix in Qatar volumes. I mean can you give me -- provide any regional delivery destination on uncontracted LNG volumes generally? And then I guess it would be interesting to know what percent was moving into Asian markets, where slopes are north of 14 today?

Sure. Let me hit the latter one and then I'll come back to the former one. There really hasn't been any change in the delivery destinations of the LNG coming out of Qatar. As we've said before, about 2/3 of it is heading into the Asia Pac area. And the other third, which is a core spot, some of that's going to Europe. Some of it's going into the Asia Pac area. So I think that strategy is working out very well. We did see when you look at the price realization, a bit of a mix effect in the quarter. We did have some downtime on the LNG trains, but that volume was offset by higher flowing gas deliveries into the local market. As we've talked about before, the realizations in the margins in the local market are less than what you see, obviously, in the delivered LNG. So we did have a mix effect on the overall realization that you saw in our international gas business. Evan Calio - Morgan Stanley: And just one last question on a matter of clarification. I think on volumes, you said in your remarks that volumes off-line in the quarter were -- they were out for maintenance or back. Were you referencing both European and Qatar gas volumes?

Yes. As we look out at where we have the maintenance and downtime over the quarter and again, a lot of that -- of course, a lot of that is your normal scheduled maintenance that you have seasonally in the second quarter, and so we saw some of that. And yes, that maintenance -- if you look at that maintenance by and large, that's back online. We do still have some stuff we're working on, but all of it is either online or coming online and will be up shortly.

Our next question comes from Iain Reid at Jefferies. Iain Reid - Jefferies & Company, Inc.: Can I ask 2 questions? On the resource base you're showing there for XTO, what you've managed to, obviously, improve significantly since the day of the merger, can you say how much of that is liquids in terms of the way you've determined the resource?

I don't have the exact split with me. I can tell you, obviously, the bulk of it is going to be gas. I know there is some liquids content in there, but I just don't -- I don't have the breakdown of that resource. Iain Reid - Jefferies & Company, Inc.: Okay. I'm just thinking more generally about your unconventional gas in the U.S. in particular. I think you've made statements about trying to shift some of your activities towards oil. Could we expect to see quite a lot of that resource remaining undeveloped at this sort of level of gas prices? Or how do you think about the kind of short-term economics of developing this enormous resource now in the U.S.?

Yes. Let me make a couple of comments on that. Certainly, we are optimizing the rigs and equipment that we have in the human resources that we have available to the highest return opportunities, which of course, does include trying to optimize that mix between liquids and gas volumes. And we're actively pursuing that, as are others, and that's going quite well. I will tell you, in the U.S., when we're looking at our gas wells, all of our gas wells are economically attractive that we're drilling. We have a paced development of the gas resources. We're fortunate that we have very few leases that we have to drill the hole. We've got a very high percentage held by production or fee property, so we're really able to maximize the returns we're getting and optimize where we're locating our drilling activities. So as we look out today, we've got between 65 and 70 rigs running, and those rigs are drilling economically attractive rigs even at today's prices. Iain Reid - Jefferies & Company, Inc.: And how many of those rigs are drilling oil prospects or unconventional prospects?

Let's see. I don't know that I have that detailed breakdown. Clearly, when you look at the size and the relative size of our resource, most of them, of course, are in gas. I can tell you, just as an example, we've got 7 rigs running in the Bakken, whereas -- that's up, as you know, from the rigs that were running at the time of the merger. So we continue to progress that. And of course, we do have a number of rigs running in the Eagle Ford. If I recall right, that's probably left about 2 rigs running in the Eagle Ford, for example, and we continue to access those resources as quickly as possible. So I would say, in summary, other than the Bakken and the Eagle Ford, anywhere we have an opportunity to optimize a rig and get it on liquids production, we're certainly doing that. Another area, although I don't have the exact rig count, we're pursuing tight oil in West Texas. That's just another example of where we've ramped up that activity here recently. So overall, again, it's take that resource, optimize your people and your equipment for the highest-impact wells. And that could be liquids, and it could also be very attractive gas wells. Iain Reid - Jefferies & Company, Inc.: Just ask one more clarification, actually, which I think I missed earlier. What was the absolute volume number in terms of maintenance in the quarter in the Upstream?

Sure. If I look at maintenance -- absolute level of maintenance in the Upstream, for the quarter, we had about an extra 37,000 barrels a day if you look at what we're doing in the second quarter of 2011 versus the second quarter of '10. And sequentially, it is probably a more important number to you. If I look sequentially first quarter to second quarter, we had right at 100,000 barrels a day additional maintenance in the second quarter compared to the first quarter.

And next, we'll move to Doug Leggate at Bank of America Merrill Lynch. Douglas Leggate - BofA Merrill Lynch: I'm sorry to lever this maintenance issue. I -- clearly, there's -- there seems to be an issue relating to the kind of margins that came off-line. Could you quantify please the, if possible, order of magnitude as to the absolute maintenance off-line in the second quarter as opposed to the deltas versus prior quarters? And if I may dig a little bit into Qatar in particular, because my understanding is you kind of got $1, $1.50 type domestic prices versus oil link prices internationally. So if you could maybe quantify how much Qatari volumes are off-line also? And I've got a quick follow-up please.

Doug, I don't have any specific details on the absolute amounts of the downtime. I can tell you if you're looking sequentially in Qatar, we had about 27,000 barrels oil equivalent a day off-line as we did some work there. But that's the delta. I don't know what the absolute amounts were between the quarters. But we did see, sequentially, some maintenance activity there. Douglas Leggate - BofA Merrill Lynch: Would it be fair to characterize the 27,000 as moving from oil link to something in a $1, $1.50 type level?

Well, I think you could see it as moving from delivered LNG as instead going in flowing gas into the country. I don't want to quote any prices or differentials, but as we've talked about before, the flowing gas in the domestic market sells at a much lower price than our delivered LNG does. Douglas Leggate - BofA Merrill Lynch: Got it. My follow-up is just a very quick one. I don't know if you mentioned this earlier, and if you did, I apologize. I was late getting on the call. Cash flow, what was the working capital impact in the quarter? Because it looked a bit light relative to what the run rate should probably have been. I'll leave it there.

Sure. If you're looking just in the second quarter, we did see a working capital build of about $2 billion in the quarter. Douglas Leggate - BofA Merrill Lynch: Great stuff and any thoughts on how the share buybacks evolved beyond the third quarter given the current environment?

No. I don't have any guidance to give on that other than in the third quarter, we intend to purchase another $5 million worth of shares.

We'll go next to Paul Sankey at Deutsche Bank. Paul Sankey - Deutsche Bank AG: David, we've been obviously over a lot of this various stuff. But just on the European gas volumes, can you clarify what looks like a 20% down move year-over-year in volumes? I think you were -- excuse me, 3.26 BCF a day down to 2.69. I know that it's probably worth passing what you've previously said into an answer on this, but what was the kind of dynamic behind that down move?

Yes. If we look at that -- the move down of notionally 600 a day -- you're talking about quarter-on-quarter, second quarter? Paul Sankey - Deutsche Bank AG: Yes.

Actually, about 1/3 of that was European demand, just lower demand quarter-on-quarter. And then the bulk, the rest of it was just normal decline, and we also had some downtime, additional downtime in the second quarter. Paul Sankey - Deutsche Bank AG: Okay. I assume -- I know I can check the dates, but you can probably just tell me that you're not bringing any LNG into the U.S. market.

Yes, we're not bringing any LNG to speak of into the U.S. market. Paul Sankey - Deutsche Bank AG: When we were together earlier this year, you did say that you will use changing on exports of LNG from the U.S. Can you update us on that, please?

Well, I remember discussing this, because I don't think I said our views have changed. I said we, like everybody else, of course, are always analyzing all the opportunities that might be out there. Some folks are already announcing and discussing plans that they have. And what I can clarify for you is that we don't currently have any plans to either re-export LNG or export LNG from the U.S. market. But again, we have a lot of gas, and we're continually evaluating all the opportunities to bring that gas to market. Paul Sankey - Deutsche Bank AG: Yes, I think that should clarify. I think what you're saying is that 2, 3 years ago, you would have thought exports were totally out of the question. Whereas now, it becomes a bet on whether or not these differentials, these price, these regional price differentials will hold for...

Yes. Clearly, for those who are looking at this and when you got to talk about building liquefaction capacity in the U.S., you're either making that 25- or 30-year bet on the continued spread between European spot prices and U.S. spot prices as they exist today, or you're going to find a way to get that gas to the Far East. So yes, 3 or 4 years ago, I don't think anybody was talking about it. As we've noted across the industry, there are folks talking about it, but we'll need to see how that progresses over time. Paul Sankey - Deutsche Bank AG: Sure. I think what you've also said, more or less, is that, really, you're going to continue pursuing the XTO business model, I guess, with the merger of the best practices of both companies but essentially, the business model of quite aggressive growth and acquisitions on an ongoing basis. And it seems that you've kept up the pace of XTO acquisitions since the takeover. Is it fair to say that we should -- and I think Ed Westlake was referring to this -- consider that to be the business model going forward and therefore, as we've seen in this quarter's results, add in an extra slug of acquisition capital on top of the guidance of I think $33 billion to $37 billion a year of CapEx that you gave us at the Analyst Meeting?

Paul, let me answer that kind of in 2 separate ways. Yes, the XTO model is continuing. We are -- we have been able to acquire both a lot of small acreage positions in terms of getting acreage that's surrounding acreage that we already have. And we don't talk about those, but those are all going. And then we have, as I mentioned, between last year and this year, in just 12 months, made some really nice opportunistic acquisitions at very attractive prices to what we have. So assuming that we can continue to find these things and we're looking at them, I don't have a number for you or anything to put in the model other than to say as these things come up, and we find them, and they have the same characteristics as what we've been looking at, yes, you would -- I would expect us to take advantage of those opportunities. Particularly again, given the leverage we get from that XTO organization and where it's located and what they already have and the ability to add these things without adding a lot of overhead and without having to change organizations and do that sort of thing, these things are very attractive. And we certainly hope we'll continue to have these opportunities, but I just wouldn't have any guidance in terms of a number, because it could be a fairly wide range. Paul Sankey - Deutsche Bank AG: Yes, I understand. On the pipelines, firstly, could you update us on the near Billings spill? Any news that you would want to share with us on that? And secondly, are you intending to do anything to address the big spread that we have between these inland crudes obviously manifested in the Brent-WTI spread? Have you -- what's your view on that and any potential investments you would make to address that spread?

Sure. Let me hit the Silvertip pipeline incident first. And I'd like to say right up front that we deeply regret that incident, and we are fully committed to completing the cleanup, learning about what happened there, how to prevent something like it from happening again and really maintaining our focus on effective cleanup and remediation of the impacting area and taking care of the folks that were impacted by this incident. Progress is going very well. We got about 800 people working out there on that, and the cleanup is progressing very well. When we look at Billings, Billings is still running at reduced rates. We are working on the logistics to be able to supply feed to that refinery other than what used to come through the pipeline. We have begun some preliminary work on replacing the pipeline, including discussions on permitting requirements and that sort of thing, lining up equipment and materials. I can't give you a time as when we might be fully restored there, but we are progressing that at the same time, again, as we are progressing the cleanup and the impacts from the initial spill. If we looked more broadly at our supplier organization and what's going on today, in the mid-con in particular and folks talking about, as we all know, the constraints there that are generating this wide spread, we are, as we talked about before, optimizing to the extent possible not only the advantage you can get in the mid-con with the Brent-WTI spread, but also, when you look at our refining circuit all the way from Canada, all the way down to the U.S. Gulf Coast, we continue to optimize our own feed plates and really to process a number of advantaged crudes including the Canadian heavy crudes, shale oil, other heavy crudes, shale oil that's coming out of the U.S. So a lot of those things are advantaged to a Brent or an LLS crude, for example. And to the extent we're able to get those and run them into our refining circuit, we're certainly doing so. So it's not just the WTI-Brent, in fact, in the mid-con but also the ability to move these other crudes into your refineries, again, both in Canada and the Gulf Coast. And we are actively pursuing that, and that's reflected in some of the volume mix impacts that you see.

I've got the idea. There's probably one minute to go on this call, but are you using rail at all?

Are we using rail to move crudes? Paul Sankey - Deutsche Bank AG: Yes.

Yes, I believe we're moving some of our Bakken crude out by rail.

And next we'll go to John Herrlin of Societe Generale. John Herrlin - Societe Generale Cross Asset Research: Your international exploration expense was about $0.5 billion higher than normal. Could you attribute it to projects? Or were you spending more on seismic? What was going on there internationally?

If you look internationally at the exploration expense, the driver there for the increase, we had some dry hole expense in the Philippines and also in Vietnam in the quarter. John Herrlin - Societe Generale Cross Asset Research: Okay. You gave the one piece for your unconventional reserve adds to -- or 3P at $0.28. What about 1P for the unconventional, for proven?

I don't have a number just for the proven. The way we look at this, really, is how much acreage are we getting and what are we paying for it? And then as we look at that total resource base that's out there, what are we getting? And how much were we paying for that? And annually, as we always do and we'll do that in February, we'll do a more robust reserves reporting of the proved as well as the unproved. The real purpose of the chart today was just kind of to step back at the one year post merger mark and kind of give you folks an update on the progress we've made in just a short year in terms of leveraging what we got at the merger and really showing the advantages that we're getting now in the resource base and also, tell you from a transition standpoint things continue to go very well. Attrition remains low. Management team is still in place, and the organization is working hard on the opportunities they had at the time of the merger and then all the opportunities that we've added over the last 12 months. So when you think strategically about the acquisition and the objectives we laid out at the time, we talked about the merger. Those objectives are being met, and we're very pleased with the progress and very excited about the future. John Herrlin - Societe Generale Cross Asset Research: Okay. Two more. You mentioned the attrition rate. What is low percentage-wise?

We're not quoting percentage. It’s equivalent to what it's been prior to the merger, the same rates kind of that people have had before. It's fairly low. But again, I think the important thing for us is 13 months after the merger, it's remaining low, and it's -- it just hasn't been an issue for us. John Herrlin - Societe Generale Cross Asset Research: Okay. With the Phillips acquisition, are you capitalizing most of that?

Yes, we'll be capitalizing that acquisition. John Herrlin - Societe Generale Cross Asset Research: Okay. Last one for me. As you get more unconventional, as you start losing things like West African output, I think a lot of people have been getting around the question of maybe you're losing higher-margin barrels, and you're going to more cost-intensive type activities on a unit basis. Should we assume that your operating cost Upstream are going to start to increase a little bit?

When you look across our portfolio and the diversity, both from a resource standpoint as well as a geographic standpoint, at any given time, depending on how we're bringing those volumes onstream, you might see upturns and downturns in both profitability and unit cost. A lot of these things come on in big chunks. Obviously, bringing Qatar on over the last few years had an impact. We've talked about the impact Kearl will have in some of the other major projects. So I wouldn't want to make an overall judgment as to what to expect going forward. I mean, in quarter-to-quarter, of course, as we saw this quarter, you do you see impacts of things like exploration expense. [indiscernible] Going forward, [indiscernible] one way or the other.

And we'll go to Pavel Molchanov at Raymond James. Pavel Molchanov - Raymond James & Associates, Inc.: I'll squeeze this one in. Since the last call, we've seen yet another one of your peer companies split into upstream and downstream halves. And of course, we've seen others gradually divesting refineries. Exxon's been kind of absent from that process. Just wanted to get your thoughts on that industry dynamic.

Well, I really can't speak for some of our competitors and what they're doing with their business plans. Clearly, when we look at our Downstream business and the tremendous value we generate with integration with the Chemicals business and how that whole portfolio is generating the types of earnings and the types of returns that you've seen them generate over the last couple of years, every time we look at this, we conclude that our integrated model combined with our global functional organization just delivers what we've referred to in the past as a "sum of the parts plus" kind of valuation. And so for ExxonMobil, as long as we can continue to maintain that advantage and in fact, increase it through technology advances in some of the investments we're making, I think you'll see, over time, that model will continue to work for us. Now if it's broken for others or others don't see the same kind of advantage that we do, it's not surprising that you might see some different approaches, but I wouldn't classify it as lagging some of the others. I'd really view it as just continuing to take advantage of the unique situation we have and the competitive advantages we get out of that and continue to exploit it. Okay. Thank you all very much.

And that does conclude today's conference. Again, thank you for your participation.