Exxon Mobil Corporation (XOM) Q3 2010 Earnings Report, Transcript and Summary

Good day, and welcome to the Exxon Mobil Corporation Third Quarter 2010 Earnings Conference Call. [Operator Instructions] At this time, for opening remarks, I would like to turn the call over Vice President of Investor Relations and Secretary, Mr. David Rosenthal. Please go ahead, sir.

Good morning, and welcome to Exxon Mobil's Third Quarter Earnings Call and Webcast. The focus of this call is Exxon Mobil's financial and operating results for the third quarter of 2010. We 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 cautionary statement shown on Slide 2. Statements of future events or conditions are forward-looking statements. Actual results, including resource recoveries, volume growth and project outcomes, could differ materially due to factors I discussed and factors noted in our SEC filings. Please see Factors Affecting Future Results and the Form 8-K we furnished this morning, which are available through the Investors Section of our website. Please also see the Frequently Used Terms and the 2009 financial and operating review on our website. This material defines key terms I will use today and shows Exxon Mobil's net interest in specific projects. Moving to Slide 3, we have provided an overview of some of the external factors impacting third quarter results. We continue to see the effects of mixed economic activity, with ongoing uncertainty in the United States and Europe, offset in part by a stronger growth in the developing world, mainly in the Asia-Pacific and Latin American regions. The pace of the global economic recovery and the resulting near-term supply and demand balances have been impacted by these effects. Crude oil prices remained well above levels of a year ago. Natural gas prices and Downstream margins have also shown improvement relative to 2009. Chemical margins have improved relative to last year, but have been negatively impacted by new industry capacity coming online. Now turning to the third quarter financial results, as shown on Slide 4. Exxon Mobil's third quarter 2010 earnings, excluding special items, were $7.4 billion, an increase of $2.6 billion from the third quarter of 2009. Earnings per share, excluding special items were $1.44, up $0.46 from a year ago. The corporation distributed more than $5.2 billion to shareholders in the third quarter through dividends and share purchases to reduce shares outstanding. Of that total, $3 billion was distributed to purchase shares. Share purchases to reduce shares outstanding are expected to increase to $5 billion in the fourth quarter of 2010. CapEx in the third quarter was $8.8 billion, up $2.3 billion from 2009, primarily due to the inclusion of XTO activity and unfavorable foreign exchange impacts. 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. At the end of the third quarter, our cash balance was $12 billion and debt was just over $18 billion after reducing the XTO debt assumed in the acquisition by over $3 billion. Moving to Slide 5. Exxon Mobil's earnings, excluding special items, increased $2.6 billion from the third quarter of 2009, reflecting strong results across all business lines. Upstream earnings increased $1.5 billion, driven by higher crude oil and natural gas prices and significant volume growth. The Downstream saw notable improvement over the 2009 third quarter, with an increase in earnings of $835 million, largely due to stronger industry Refining margins. Chemicals continued its solid performance as earnings increased $353 million on stronger margins. Corporate and Financing expenses were $506 million during the quarter, up $23 million versus the third quarter of 2009. As shown on Slide 6, Exxon Mobil's earnings, excluding special items, declined $210 million from the second quarter of 2010. Upstream earnings increased $131 million, primarily due to volume growth. While Downstream earnings were down $60 million due to lower industry margins. Chemical earnings decreased from the second quarter by $139 million on lower commodity margins. Compared with the second quarter of 2010, Corporate and Financing expenses increased by $142 million, mainly due to the impact of retiring a portion of XTO's long term debt. Moving next to the Upstream results on Slide 8. During the quarter, Exxon Mobil began production from the Odoptu field, the latest development phase of the Sakhalin-1 project in far eastern Russia. This region is one of the most challenging sub-arctic environments in the world. The project is performing well and current production is approximately 50,000 barrels of oil per day. Employing world-class extended rig drilling, the project started up on schedule and within development cost expectations. Since start up of the first phase at Chayvo in 2005, the Sakhalin-1 project has produced over 270 million barrels of oil for export to world markets. Moving to the United States, our LNG terminal at Golden Pass on the Texas Gulf Coast recently received a commissioning cargo. Once commissioning activities are complete, the start up of this terminal will represent the final stage of the integrated project between Exxon Mobil and Qatar Petroleum that includes the entire LNG supply chain, production, liquefaction, LNG ships and LNG receiving terminals. Our four trains in Qatar with annual capacity of 7.8 million metric tons each are all running at capacity. And our Al Khaleej Gas Phase 2 domestic gas project continues to benefit from strong local demand. These facilities are well positioned to help meet the growing global gas demand in Asia, Europe and the United States. Moving to Slide 9. Exxon Mobil continues to make good progress in Iraq. We have completed our six-month contract milestones, including submission of the rehabilitation plant and the work program and budget. We have awarded contracts for well work over operations, camp refurbishment and offices. And recently commenced well work and tie-in activities. We remain on our original timetable for execution and production ramp-up. Moving to Slide 10. The initial development of our Kearl Oil Sands Project in Canada is on schedule to commence operations by year end 2012, with construction now approximately 25% complete. Our original plan developed Kearl in three phases to produce more than 300,000 barrels of oil per day. However, by leveraging recent learnings, we reconfigured the project include debottlenecking and expansion phases, which will increase production to the regulatory limit of approximately 345,000 barrels per day. We expect the spending profile early in the project to be higher as a result of revisions to comply with the changing regulatory environments and specific sites conditions, with full lease development still yielding attractive unit development costs. We also continued to progress our global portfolio of high-quality liquids projects. Slide 11 provides an update on several of these projects. At Hibernia, the south extension project received approval for the development plan. The southern extension will be produced using the current Hibernia gravity base structure facility that will require additional drilling to access the resource. The plan is to drill production wells from the Hibernia platform and water injection wells from a combination of platform and subsea drilling. Platform drilling for the southern extension unit is currently planned to begin in late 2011 or early 2012. The Hebron Project is progressing and first oil is anticipated before the end of 2017. We recently awarded our front-end engineering and design contract for the top sides and plan to award the gravity base structure contract before the end of the year. In addition, we continue to progress a number of worldwide oil drilling programs. For example, we have recommenced drilling on our Ringhorne Platform in Norway, and have an ongoing program at Barrow in the U.K. sector of the North Sea. We have also ongoing programs in Nigeria, Equatorial Guinea, Chad, Angola, Canada and the United States. Turning now to our unconventional portfolio and starting on Slide 12. The ongoing integration of XTO is progressing well and the transfer of existing technology and experience will provide significant benefits. As an example, we are progressing consolidation of unconventional activities to leverage XTO's experience and operational capabilities in place such as the Eagle Ford, Haynesville and Marcellus. During the quarter, Exxon Mobil finalized a merger agreement with Ellora Energy. This acquisition has increased our position in the attractive Haynesville Bossier plays by 46,000 acres and added current production and pipeline capacity. In addition, our gas marketing team is working with XTO to optimize shipping, processing and marketing activities across our United States portfolio. We are also capturing reverse integration benefits in legacy Exxon Mobil operations both in the United States and overseas. Recently, a team from XTO shared best practices to optimize our evaluation and development planning activities in Canada, Indonesia and Germany. XTO brings a rich data set including thousands of core samples and an extensive fuel testing database, which our research lab will leverage to further our proprietary shale research. We also continued to see low attrition rates. Overall, we are very pleased with how the XTO integration is proceeding and the potential benefits we see over the long term. Moving to Slide 13. In Canada, the Horn River Basin is a world-class Devonian shale gas resource that is currently in the evaluation stage. We hold over 300,000 net acres and are one of the largest net acreage holders in the basin. In the 2009, 2010 winter dealing season, we drilled eight vertical wells and two horizontal wells. Completion and testing operations were completed on the two horizontal wells in August of this year. Five wells are planned for the next drilling season which will begin in late 2010 or early 2011. Additionally, we completed the 2009, 2010 non-operating drilling program and testing operations are currently underway. Moving to Slide 14. In Europe, we have commenced drilling our first coal bed methane well in Germany, and are implementing a work program to evaluate the shale gas and coal bed methane potential of our acreage. In Indonesia, we hold respective coal bed methane acreage in the Barito Basin totaling approximately 290,000 net acres. We plan to conduct pilot tests to evaluate the viability of Indonesian coal bed methane as a gas resource and expect to initiate exploration drilling in December of 2010, followed by pilot testing in the first half of 2011. We have drilled our fourth exploration well in the deepwater Block SC 56 in the Sulu Sea in the Philippines and have discovered natural gas. We have now encountered natural gas in three of the four wells drilled to date and are analyzing data from all the wells to determine future plans. Turning now to the Upstream operating results and starting on Slide 15. Upstream earnings in the third quarter were $5.5 billion, up $1.5 billion from the third quarter of 2009. Upstream after-tax earnings per barrel were $13.34. As you will see in the 10-Q, which will be filed next week, third quarter upstream earnings included a positive $150 million contribution from XTO's operations. Higher crude oil and natural gas realizations increased Upstream earnings by over $1 billion. Worldwide, crude oil realizations were up almost $8 a barrel and natural gas realizations were up early $0.70 per 1,000 cubic feet from the third quarter of 2009. Earnings further increased by $270 million due to higher volume and mix effects, driven by project volumes in Qatar and the addition of XTO, partly offset by net field decline. All other effects increased earnings by $150 million, primarily due to favorable tax items. Moving to Slide 16. Oil equivalent volumes increased 21% from the third quarter of last year. Entitlement volume effects, including price and spend impacts and PSC net interest reductions, decreased volumes by 21,000 barrels per day, while lower OPEC quota effects increased volumes by 31,000 barrels per day. Divestments reduced volumes by 1,000 barrels a day. Excluding the impact of entitlement effects, OPEC quotas and divestments, production was up 750,000 barrels per day or just over 20%, with the addition of XTO volumes and project ramp ups in Qatar partly offset by net field decline. Liquids production increased 86,000 barrels per day or nearly 4% from the third quarter of last year as project ramp ups in Qatar and the addition of XTO volumes more than offset net field decline. Gas volumes increased over 4 billion cubic feet per day or about 50% from the third quarter of 2009, driven by Qatar and XTO. Turning now to the sequential comparison and starting on Slide 17. Versus the second quarter of 2010, Upstream earnings increased about $130 million. Realizations increased earnings by $90 million, and stronger gas realizations in Europe and Qatar were partly offset by lower global crude oil realizations. Higher volume and mix effects increased earnings by $160 million, driven by lower maintenance activities and project ramp ups in Qatar and the addition of XTO. This was partly offset by a decline in seasonally lower natural gas demand in Europe. All other items decreased earnings by $120 million due primarily to unfavorable foreign exchange impacts. Moving to Slide 18. Oil equivalent volumes increased over 11% from the second quarter of 2010. Entitlement volume effects, including price and spend impacts and PSC net interest reductions, decreased volumes by 1,000 barrels per day, while lower OPEC quota effects increased volumes by 4,000 barrels per day. Divestments reduced volumes by 1,000 barrels per day. Excluding the impact of entitlement effects, OPEC quotas and divestments, production was up 455,000 barrels per day or just over 11%. Lower maintenance activities and project ramp ups in Qatar and the addition of XTO volumes more than offset decline in seasonally lower demand in Europe. Liquids production increased 96,000 barrels per day or just over 4%. And natural gas production increased over 2 billion cubic feet per day or about 22%. For further data on regional volumes, please refer to the press release and the IR supplement. Moving now to the Downstream and starting on Slide 20. In Refining, we continue to progress our multi-year program of global investments targeted at increasing the supply of lower sulfur motor fuels. We recently commissioned facilities at our Baytown, Texas and Baton Rouge, Louisiana refineries which will increase lower sulfur diesel supply in the United States. Our investments in hydrotreating facilities at our Antwerp, Belgium refinery are nearing completion. And finally, construction has commenced at our Sriracha, Thailand refinery to produce lower sulfur diesel and gasoline. As shown on Slide 21, earlier this month, our Lubricants business announced a multi-year sponsorship agreement with two-time NASCAR Sprint Cup Champion, Tony Stewart in Stewart-Haas Racing beginning in 2011. The new agreement allows Exxon Mobil to build on Mobil 1's official motor oil of NASCAR designation, and shows our ongoing commitment to NASCAR. It also illustrates Mobil 1's lubricant technology leadership, while supporting continued market growth. Mobil 1's association with NASCAR demonstrates Exxon Mobil's outstanding product performance under extreme driving conditions, and showcases the engine protection and fuel economy our technology delivers to both NASCAR drivers and race fans. Turning now to the Downstream operating results starting on Slide 22. Downstream earnings in the third quarter were $1.2 billion, up $840 million from the third quarter of 2009. Higher industry Refining margins partly offset by lower marketing margins, increased earnings by $300 million. Volume and mix effects increased earnings by $150 million, including the benefits from our Refining optimization efforts. Other factors increased earnings by $390 million, mainly due to gains on asset sales and positive foreign exchange impacts. Moving to Slide 23. Sequentially, third quarter Downstream earnings decreased by $60 million. Lower margins decreased earnings by $390 million, reflecting weaker industry Refining and marketing margins. Volume and mix effects increased earnings by $110 million, largely due to lower plant maintenance activity. Other factors increased earnings by $220 million, including favorable foreign exchange effects. Turning now to our Chemical business and starting on Slide 25. During the quarter, Exxon Mobil continued to progress the expansion of our integrated Chemical and Refining complex in Singapore. The expanded steam cracker will use Exxon Mobil's state-of-the-art proprietary technology to achieve substantial feed flexibility and increase energy efficiency. In addition, the expanded complex will produce a range of premium products to capture demand growth in Asia. The expansion will add over 2.5 million metric tons of capacity per year to the existing site. The anticipated mechanical completion and start-up activities will be phased in beginning later this year and will continue through 2011. Additionally, as we highlight on Slide 26, the third quarter included significant scheduled maintenance activities and plant improvements as more than 50% of our planned 2010 turnarounds worldwide were initiated this quarter. As an example, our facility in Kawasaki, Japan doubled its capability to produce lighter feedstocks, which will improve its competitiveness across broader market conditions. These planned maintenance activities play a pivotal role in our commitment to operational excellence. In addition, we continued to use these scheduled downtimes to incorporate improvements that help extend our leadership in areas such as energy efficiency and feedstock flexibility. Turning now to the Chemical operating results and starting on Slide 27. Third quarter Chemical earnings were $1.2 billion, up $350 million from the third quarter of 2009. Stronger margins improved earnings by $370 million, driven by continued strong feedstock advantage and higher realizations. Volume and mix effects increased earnings by $50 million. Volumes increased 3%, reflecting the Fuji on startup, as well as continued recovery from the depressed demand levels seen in 2009. Other effects decreased earnings by a total of $70 million. While we manage our Downstream and Chemical businesses separately, we continue to capture benefits from the unique integration and optimization of these businesses. Our combined third quarter earnings were $2.4 billion, up $1.2 billion from third quarter 2009, reflecting the competitive advantage of our integrated Downstream and Chemical business model. Moving to Slide 28. Sequentially, third quarter Chemical earnings decreased by $140 million. Lower margins decreased earnings by $220 million, especially in Asia, with the start up of new industry capacity. Positive volume and mix effects increased earnings by $60 million. Other effects increased earnings by $20 million. Moving to Slide 30. Exxon Mobil's third quarter earnings and operating performance were strong and reflect the ability of our business model and company strengths to deliver superior results. We maintained a continuous focus on operational excellence and improving upon our industry-leading safety performance. We continued the successful execution of our long term investment plan, and we are moving forward on the flawless integration of XTO's world-class organization into our existing portfolio of high-quality assets. Our performance in the quarter includes the benefit of strong project and facility uptime in all of our business segments, providing further evidence of our disciplined and consistent approach across all of our business lines. With our unparalleled financial strength, Exxon Mobil remains well positioned to deliver on our plans. That concludes my prepared remarks. I would now be happy to take you're questions.

[Operator Instructions] We will take our first question from Mark Gilman with Benchmark.

I wonder if you might be able to provide a total DD&A number for the quarter and the portion of that, that burdened the $150 million earnings contribution from XTO which you identified? And I have a follow-up.

Sure, Mark. We don't really disclose the details of our individual OpEx components, so I won't be able to provide that information today.

It was a DD&A question, not OpEx. DD&A in the quarter overall and what portion of that burdened the $150 million earnings number that you identified for XTO.

If we look at the $150 million, I want to note that that was a positive number, a positive contribution for the quarter. But again, I don't have a detailed number to give you on the components of that, including DD&A.

You referenced the Ellora merger, I wonder if you could talk a bit about costs and production impact?

In the quarter, that acquisition really had a de minimis impact on both production and costs. If you look at just quarter-on-quarter given the timing, it was de minimis. But we are looking forward to the long-term benefits of that acquisition, which as I mentioned, added about 46,000 acres to our portfolio on those plays.

But no number for what the cost of the acquisition was?

No, I don't have that number for you.

We'll take our next question from Evan Calio with Morgan Stanley.

I have a question on the buyback. I know it's been described in the past as the flywheel. But your increase in the fourth quarter to $5 billion, primarily given where you're trending almost $10 billion under your CapEx guidance on the midpoint that your uses of cash, we're likely to see operating cash in the fourth quarter. I mean, do we read anything to that? Is CapEx coming in lower? Or are making more of a statement here with your buyback?

Yes, Evan, let me provide a little bit of clarity on both of those items. First, let's start with the buyback. There is no change. The buyback remains the flywheel of our cash flows. And as we look ahead in the fourth quarter and look at commodity prices and the business, we have made the decision to increase to the $5 billion level. I would say if we take a look at CapEx and start back at the outlook we gave everyone in March, we said we would spend about $28 billion this year. And although I don't have any firm outlook for the year, I would say if you take the $28 billion we mentioned and add in XTO, we'd be somewhere in the $30 billion to $31 billion for the year which should be consistent with that outlook. And I think we're pretty much on track to meet that. We've seen some upward pressure due to unfavorable ForEx. But over the course of the year, we'll see a lot of puts and takes. And again, I think we're pretty much on with our CapEx target that we had mentioned before and again, if you take into account the added activity from XTO.

Right. I have a different question, if I could, second question on U.S. production. Your international volumes were really strong. The U.S. volumes in both the oil and gas a little bit lighter than we would've expected. Has the combined activity slowed due to the gas price environment or high grading opportunities in the Gulf of Mexico kind of decline impact? Can you maybe help me to think about North American volumes?

Sure. When we look at our total North American volumes, we have seen the impact of both our ongoing operations as well as the addition of XTO. I will tell you, everything is coming on as we expected. There's been no slowdown in activity. In fact, as we've mentioned before, activity has ramped up over the last several months. And any other offset would be just normal decline in maintenance across our facilities, but no special effects that I can mention.

We will take our next question from Doug Terreson with ISI.

I had a question on the Downstream, specifically asset sales and Forex benefits were pretty significant versus the year ago and Q2. And so I want to see if you could provide some segmentation and maybe geographical color on that figure. Meaning, of the $220 million sequential delta, I couldn't tell from your comments what was asset sales and what were Forex and where were they?

If you look at the Downstream earnings sequentially, in total, if you look at that other bar there, the $220 million that you mentioned, I can tell you the book it had is all Forex and that's the real factor in there.

And also, you guys have been very successful with your exploration effort in the Philippines and while I realize it were somewhat early in the play, it also seems to be becoming meaningful. And so I just wanted to see if you could comment on market potential over there and also the next steps for development that Exxon has in that area?

Yes, I would tell you, it's still a little early when we look at the size of that resource and the size of the acreage we have out there. Again, as I mentioned in my prepared remarks, of the four wells we drilled, we have found gas in three of them and that's encouraging. But we're still in the evaluation stage and it'd be a little premature to give you any kind of a market outlook or production time.

We will take our next question from Paul Cheng with Barclays capital.

Dave, you've mentioned about the asset sales already. Can you tell us then what is the actual asset sales gain in the quarter?

You're looking at Upstream, Downstream?

I guess both. I suppose that I mean Upstream is not having much of an asset sales gain and majority is in the Downstream.

If you're looking at the sequential earnings in the Downstream, if you look at...

Can you tell us then what is the actual asset sales gain. Is that just looking at, say, the change?

I really don't want to get into the details of the absolute values, Paul. But I can tell you that if we look at that quarter-on-quarter change in the other category, the $390 million, the bulk of that -- about half of that asset gain is quarter-on-quarter.

And how about in the Upstream?

If you look at our Upstream earnings on a quarter-to-quarter basis, I'll tell you, there's really not a big impact there. What we mainly saw there were some favorable tax items, but nothing else in that other bar really has to do with asset sales.

And Dave, do have any hedging gain or loss related to legacy hedging position of XTO in this quarter?

If we look at the hedging effects, when we look at those impacts going quarter-on-quarter, we do have an effect of about $50 million that we booked as a gain on those hedges as reflecting the decline in natural gas prices over the quarter.

A final one, if I could. Sakhalin-1, that's some news coming out from Russia talking about the possibility of the change in operatorship due to the increase in the budget, talking about a proposed news stop holding from the original budget. We understand that rumor rang over there. Can you give us any insight that have you actually been in discussion with the Russian authority? Or whether that's any true to some of the number being cited in the press?

Let me provide a little more color on the Sakhalin-1 project. As I mentioned in my prepared remarks, of course, we have started up the Odoptu field, that's a very successful project, on time, on budget, excellent performance and really continues a string of successes as we've develop that project going back several years. As we look forward and we look at the budget, I can tell you that there have been no material changes to the scope of work for the Sakhalin-1 project. The consortium is still working within the original budget that was approved by the ASB. And as you would expect, we're working closely with the government and our partners to continue the successful development of that project and those discussions are ongoing. And everybody has the same objective in mind and that's to continue the success of that project and delivering the economic benefits that are derived for all of the stakeholders. So I wouldn't really comment on any rumors or speculation other than to say we continue to book a string of successes at Sakhalin, and look forward to continuing producing and developing that resource.

We will take our next question from Doug Leggate with Bank of America Merrill Lynch.

I wanted to circle back on a couple of things on the buybacks. Rex, a couple of weeks, I guess a month or so ago when we all sat around the table with him, he basically made a comment that you guys would have been prepared to do the XTO deal all cash. And obviously, you ultimately did it all stock I think on his prompting, if I remember it correctly. I guess my point is if you're prepared to do it all cash, how sustainable is this on rate of buybacks? Is this more about trying to basically buyback the stock you issued from XTO, in other words, it's not so much of a flywheel anymore? Can you just give some color in the context that we all relate this on?

Yes, sure, Doug. Let me provide a little more clarity on that. There really is no change in our approach to the buybacks relative to any other use of our cash. What you're seeing in here and you saw in our results is we have had very strong net cash generation this year. Again, the business is performing well. You see the earnings increase and consistent with the way we've been using our cash and maintaining our flexibility and strong balance sheet. We find ourselves in a position to increase the buyback rate in the fourth quarter to $5 billion. But I wouldn't really try to draw any more conclusions with that or read anything into it other than we bought back $3 billion worth in the third quarter and we're going to buy back $5 billion in the fourth quarter.

If I could risk a double-barreled follow-up, if I may. Completely unrelated questions. The volumes, the moves run about sequentially in Africa and on Asia-Pac. Can you just give us some color as to what's going on there? And if I may circle back on Mark's earlier question, are you able to give us the cash flow contribution from XTO in the quarter?

Let me hit the volumes first. I think you mentioned specifically in Africa, we did see a decline in Africa on an OEB basis of about 35,000 barrels a day and that was in liquids, and that was really just some downtime that we had in Africa as well as normal decline. That bounces around if you look over at the sequential move in the third quarter versus the second quarter, you'll see our Africa liquids volumes are up 32 kbd, strong work programs over there and business performance. So just what I would consider the normal fluctuation quarter-to-quarter and what is a very large business for us. And then could you repeat your question on cash?

Well, actually on Asia-Pac also because I was under the impression that Qatar was already up plateau last quarter. So if you could give some color on cash flow from XTO, please?

Sure. If you look at the Asia-Pac and Middle East volumes at our supplement they are up about 139,000 on liquids and another 1.9 billion on gas. That's quarter versus last quarter. If you look sequentially, we're up also about 60 kbd on the liquids and 819 million on the gas. And so yes, that's basically the projects ramping up in demand in contrary in Qatar. And we also saw some lowered scheduled maintenance. So I think the good news, Doug, is what I mentioned earlier. As we sit here today, all four of those mega trains are running at full capacity and the performance and up-time have been outstanding. And so the fluctuation that you see quarter-on-quarter sequentially is really just the continued good performance and a little lower maintenance. If we look at I think your other question was on cash flow from XTO? We never really disclose details of cash flows on any particular piece of our business or resource. And so I don't think we're in a position to offer that today.

We will take our next question from Robert Kessler with Simmons & Company. Robert Kessler - Simmons & Company: I want to know what your thoughts are with respect to the average utilization rate of that facility for about the next 6 months or so. Just looking at U.K., spot prices being quite a bit above the U.S. Henry Hub, it would seem advantageous to ship most of your cargoes to Europe instead of Golden Pass. But is there some factor to consider there, maybe in the contracts or otherwise that would result in a higher utilization rate at Golden Pass and when will it assume from the spot price differential?

Sure. Let's step back and start with the commissioning of the LNG terminal in Golden Pass. The commissioning has begun. We've got a commissioning cargo in there, the ship came in recently. That commissioning process is typically a two- to three-month effort, and we're focused on doing that and getting that done right and making sure all that hardware we put on the ground is working properly. Beyond that, it's a little too early to be talking about what's going to happen after that. The important thing for us is to get that thing up and running. And again as I mentioned, make sure that it works. But down the road as we've mentioned, quite often, we have tremendous flexibility in our ability to place cargoes out of Qatar, around the world. We will always be looking for market opportunities that allow us to generate the maximum value based on those market conditions. And I would expect that strategy to continue going forward without being any specific on any one country or LNG receiving terminal. We got a great LNG business, very flexible, all of the assets are up and running. This will be the commissioning of our third LNG terminal, which kind of gets everything up and running. And we'll see the full benefit and value generated from the strategy that we will now have in place and finished up on. So we're really excited about this. Robert Kessler - Simmons & Company: And then with respect to CapEx, you mentioned the inflationary effect of foreign exchange on capital expenditures for the quarter. Can you quantify that? And then I'm probably not going to get to far with the second component of the question, but any thoughts on the rate of change for total CapEx next year versus this year?

Yes, if we look at the effect on CapEx this quarter from foreign exchange rates, it was about $400 million. And looking forward, I think the second part of your question is next year, really don't have any updated outlook for you. Obviously, we'll look forward to updating that and talking about that in the March Analyst Meeting.

We will take our next question from Faisel Khan with Citigroup.

I was wondering if you could give us a little more color on your LNG spot sales. Can you give us an idea in the quarter kind of where most of those cargoes were headed? Was it Arctic? Mostly were going to Asia where pricing seems to be a little bit higher than the second quarter.

I don't have any of the specific details by geography or by specific terminal. I can confirm that we are making spot sales in all of those regions that you mentioned and certainly taking advantage of market differentials and the ability to optimize and maximize the earnings out of those shipments. But in terms of getting specific, I really don't have those for you other than just to pick up on your comment. The ability to move cargoes around to take advantage of what various markets provide is a true strength of the business that we have in place, and we are certainly looking to maximize the value from that.

In the North American gas market, can you give us an idea of where your rig count is right now? In North America, where you expect it to trend by the end of the year?

Are you talking on an industry rig count or...

No, yours. Exxon Mobil rig count.

I think we've got about 68, 70 rigs running today consistent with where we were in the past.

And do you expect that to kind of remain the same going to the end of the year?

As we look out to the end of the year, I think essentially, plus or minus, you would expect to see that in that 70 category. I don't think there'll be any major changes up for now.

Last question, just on the Upstream side. Was there any sort of underliftings or unscheduled maintenance or downtime across your Upstream portfolio that we may have missed?

If you look quarter on quarter, third quarter this year versus third quarter last year, we would have about 50 kbd in that category.

And we will take our next question from Jacques Rousseau with RBC Capital Markets.

I just have a question on the balance sheet. It looks as though your debt declined from about $20 billion to $18 billion versus last quarter, and you mentioned in your comments that you retired buyback about $3 billion or so of XTO debt. So should we assume that the factor to tie this out of the increase to short-term debt?

We did take out about $1 billion of commercial paper during the quarter.

And is this something you see as an option to help support the buyback program?

No, I wouldn't look at it in that regard. It's more if you step back and just look at our overall capital structure, look at the balance sheet, look at the opportunities that the market's offering us. And it was just opportune for us to step into the CP market this quarter and take out about $1 billion at very attractive rates. But I wouldn't read anymore into that other than that. It was just our normal ongoing management of the capital structure. And again, taking advantage of the what the market has on offer.

You had mentioned before in terms of corporate costs, I believe, a range of $500 million to $700 million per quarter. Any thoughts on how that may change with the XTO deal?

No, and I would say, if you look back over the last many quarters, I know that number has jumped around a bit. But I would confirm that on an ongoing basis, you would expect to see our corporate thin numbers to come in anywhere in that $500 million to $700 million range. But I don't have any other guidance. But yes, $500 million to $700 million is what we would expect going forward.

We will take our next question from Ed Westlake with Credit Suisse. Edward Westlake - Crédit Suisse AG: Just another way perhaps of getting at the cash flow numbers, could you just give a total group DD&A? I know we'll get them in the Q next week, but if you just have the group DD&A on the cash flow statement and any change in working capital that would be helpful.

Sure, if we look at the total DD&A for the company in the third quarter of '10, it was $3.9 billion and that was up $1 billion from the three quarter of '09. Edward Westlake - Crédit Suisse AG: And any changes in working capital?

Yes, if we look quarter-on-quarter, it was about $1 billion related to a change in accrued payables positive. Edward Westlake - Crédit Suisse AG: And then just moving to exploration. Obviously, you have a Black Sea well. I think it was meant to complete in Q3, where are we on that? Are we expecting results? Or have you got some results you could share? It was a partner well, actually.

Yes, that was a partner well. We did complete that well in the third quarter. We did expensed that well. However, we did see hydrocarbon shows, which did provide evidence of a working hydrocarbon system. And we are continuing to further evaluate the data from that well which as you would expect, will help us on our upcoming exploration program. But yes, we are finished with that well. Edward Westlake - Crédit Suisse AG: On the U.S. liquids, you have 357 in Q2 which was down a bit against Q1 because of maintenance in the offshore Gulf of Mexico. Obviously, you bounced back a little bit perhaps not as much as you would have thought with XTO. Is there still some maintenance impact in the U.S. liquids?

Well, if you look at our U.S. liquids, we did get a nice uplift of course on XTO, but that was partly offset by decline across the portfolio. Edward Westlake - Crédit Suisse AG: So nothing unusual?

No, nothing unusual.

We will take our next question from Blake Fernandez with Howard Weil.

David, I was trying to get a quick update on BM-S-22 in Brazil. As I understand it, they was originally going to spud I believe it was this month, but that got pushed back a month or two. I was trying to get an update on what's going on out there?

If you look at that third well, I think we have said all along we were expecting to spud that in the fourth quarter. It looks like we're still on track to do that. We expect to begin that operation in December.

So the rig is secured and everything is ready to go for December?

Yes, we are on schedule for a December start.

And the second question I had for you, one of your peers yesterday announced that they are shutting in some North American natural gas with the idea of selling those volumes down the road once prices improve. I'm just curious, is Exxon considering anything like that?

What I can tell you if we're looking at that business, we have not shut in any gas wells.

So activities continues to ramp, as you suggested earlier, and no shut in volumes?

Activity continues on the pace that we've been running and we have not shut in any wells.

We will take our next question from Pavel Molchanov with Raymond James. Pavel Molchanov - Raymond James & Associates: Just a question about Greenland. I think you guys participated in one of the recent licensing rounds. Can you give us a sense of when you might begin exploration there?

If we look at our portfolio and particularly hone in on Greenland, you're right, we do have some acreage in the Greenland area. But I really can't give you a specific timeframe in terms of when specific activities might happen. We are evaluating on an ongoing basis some seismic work that we've done and interpreting that. But I don't have a specific date, for example, if you are looking at wells or anything. Still early days in Greenland a lot of acreage, a lot to analyze and I would really say we're still in the evaluation phase there. Pavel Molchanov - Raymond James & Associates: And follow-up, if I may, on XTO. Relative to June 26, is the rig count on the legacy XTO properties kind of up, down or flattish?

I think if you were to take a starting point being the end of June, it's about flat where we are today, plus or minus a rig or two, but we we're essentially flat.

We will take our next question from Paul Sankey with Deutsche Bank.

David, can I just read around a bit more in the hedging subject? Did you say that it was a $50 million gain that you got?

Yes.

Is that the realized gain or it's just that it's less than you would think it would be given the position that we know XTO is in?

Look, Paul, that's an excellent question and without trying to get too detailed in what can be some complicated accounting. As you know, we had mark-to-market all of those hedges at the acquisition. And on that basis, of what the contracts were hedged at and what the strip was at the time, at those sales had proceeded along those lines, the difference between the hedged price and the price that we have had marked that at, that would have gone into cash flow and still does. What you did see across the quarter is that the gas price decline and therefore, it was below the price that we actually restated those hedges out of the quarter and that small piece does flow into earnings. So the bigger piece goes into cash flows, doesn't go into earnings. And the smaller piece associated with the decline in prices relative to the end of June strip did go into earnings and that was about $50 million.

And these hedge positions, I think you've stated you will unwind? What's the status of that now?

For the schedule that you've seen publicly, we're going to let those unwind as time goes on.

I guess my point was you're not doing anything other than just letting them roll?

No change in how we're going to approach this business.

And the other one for me, I'm not sure if you'll give me this, but could you give us your capital employed on September 30 as broken down by division?

No, Paul, I don't have the capital employed in total or broken down by division right now.

But there is a number here on Page 9 of the release which is the capital employed at September 30, right?

I mean, yes, I'm sorry, I don't have any of the division breakdowns for you.

We will take our next question from Jason Gammel with Macquarie.

David, I just have a couple of questions on the drilling schedule. First of all, with the moratorium within the Gulf of Mexico, have you given any consideration as to when you might permit another well in the Gulf? When you'll be active in drilling again? And if there are further opportunities to pickup acreage given what are potentially some big increases in the cost structure there?

Let's go back and talk a little bit about the moratorium. First thing I'd like to say is that we are pleased that the government is recognizing the industry's commitment to enhance safety standards and response capability in lifting the moratorium. As you would expect, we are continuing to review the details of the announcement, the changes in the rules and standards that we all have to abide by. And we're in the process of analyzing that and looking at what impacts that might have on us. I can tell you as we look forward in the near term, you'll recall that at the time of the moratorium, we were preparing to drill our next Hadrian well in our discovery in the Gulf of Mexico. And we are planning to submit in the near term, our revised permit application in order to get that drill underway.

Are you seeing any opportunities to far more incremental drilling activities, David?

Without being specific certainly and mention anything individually, we are always looking at opportunities that are out there. Oftentimes, there are changes in the market and changes in the business environment that do generate opportunities for us. But I would say nothing special or different, just doing what we always do which is looking at what's out there, what's on offer. We can find a way to add value to something. We certainly look at it seriously, but that's an ongoing business for us.

If I could just turn to the Black Sea briefly, I believe you contracted a rig to move into the Black Sea. Can you talk about when you might be able to start the first well there and what your plan for drilling in terms of timing and number of wells would be?

I think as we've mentioned before, we do have a new build rig that's going to be heading into the Black Sea to drill our acreage position there. As we look forward to next year, I think you would expect to see us being able to spud that first well sometime in the first half of 2011.

And do you think you'll keep that rig in the Black Sea for a while, David or maybe farm our some slots to other operators there?

Yes, we certainly plan to keep that rig in the Black Sea for quite a while. I wouldn't want to talk about who's going to utilize, what percentage of it, but yes, it will be in there.

We will take our next question from Mark Gilman with Benchmark.

David, as the activity in Iraq where it's going to ramp up, can you help us with some guidance as to how you will report your activity and volumes there?

Of course, it's a little early there in the project. As I mentioned, we have met our six-month milestones. We have awarded some contracts to get the work going, but as that ramp up progresses, we would certainly as we head up to our production targets, we would certainly expect to report the volumes as they're produced next year. And so I don't think there's anything out of the ordinary there.

So you'll report production prior to the time you were in remuneration piece?

Mark, I'm not sure about the exact details in terms of the timing. But certainly, as we ramp up production and get to our initial production targets per the product, we'll be reporting production volumes.

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

One, I assume you don't have much of an inventory gain or loss in the quarter, do you?

No, we didn't see much of an inventory gain or loss as a whole in the quarter.

And secondly, going back to Iraq, if we assume that -- I just want to understand from a timeline standpoint from the time that you will be able to actually start doing the work over activity and drilling activity in Iraq, how long it would take before we will start to see you would be able to get the production up to the 10% range?

Paul, I don't have a specific timeframe to give you. We will meet any specific production targets. As you know, this is a long-term effort that we have underway. I can tell you that per our schedule and our milestones, what we were expecting things proceeding on track. We do things have underway, as I mentioned, contracts led. We would expect to reach our initial production targets sometime in 2011. But in terms of any more specific timing other than that, I really couldn't give you a more specific date.

Dave, can you tell us whether you actually now start drilling in the field or you're just doing a slight preparation?

Well, we got a number of activities that are underway in the field, some of which I mentioned in my remarks starting initially of course with a lot of well work over his. And are proceeding to drilling but as we sit here today, we're really working on the work over and tie-ins and the major drilling efforts are still to come.

I want to thank everybody for their time today and the questions and appreciate the time in the call.

That does conclude today's conference. Thank you for your participation.