David Rosenthal - VP, Investor Relations & Secretary

Doug Leggate - Bank of America Evan Calio - Morgan Stanley Robert Kessler - Tudor, Pickering, Holt Doug Terreson - ISI Allen Good - Morningstar Investment Blake Fernandez - Howard Weil Arjun Murti - Goldman Sachs Faisel Khan - Citigroup Pavel Molchanov - Raymond James Edward Westlake - Credit Suisse Paul Cheng - Barclays Iain Reid - Jefferies

Good day ladies and gentlemen and welcome to the Exxon Mobil Corporation Third Quarter 2012 Earnings Conference Call. Please note, today’s conference is being recorded. At this time, for opening remarks, I would like to turn the conference over to the 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 2012. I will refer to the slides that are available through the Investors section of our website. Before we begin today, I would like to say a few words of support for those who have been impacted by Hurricane Sandy, which I know includes many people listening to today's call. Our thoughts are with you as you work to recover from the effects of the storm which has touched so many lives along the East Coast. We are doing everything we can in our operations to help support the recovery effort. Now returning to Exxon Mobil’s results; but 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. Global economic uncertainty continued in the third quarter with further weakness in Europe and Japan. The European growth rate is estimated to remain negative in the third quarter following the contraction in the second quarter. Meanwhile, Japan is likely to decelerate further. The US economy marginally improved versus the second quarter and China’s growth rate decline moderated versus prior quarters. Energy markets improved in the third quarter with higher crude oil and US natural gas prices and stronger industry refining margins versus the second quarter. Although, US commodity chemical margins remained strong, Europe and Asia margins showed continued weakness. Turning now to the third quarter of financial results as shown on Slide 4; Exxon Mobil’s third quarter 2012 earnings were $9.6 billion, a decrease of $760 million from the third quarter of 2011. Earnings per share for the quarter were $2.09, down $0.04 from a year ago. The corporation distributed $7.6 billion to shareholders in the third 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 fourth quarter of 2012. CapEx in the third quarter was $9.2 billion, up 7% from the third quarter of 2011. Our cash generation remained strong with $14 billion in cash flow from operations and asset sales. At the end of the third quarter 2012, cash totaled $13.3 billion and debt was $12.4 billion. The next slide provides additional detail on third quarter sources and uses of funds. Over the quarter, cash decreased from $18 billion to $13.3 billion. The combined impact of strong earnings, depreciation expense and the benefit of our ongoing asset management program yielded $14 billion of cash flow from operations and asset sales. Uses included additions to plant, property and equipment or PP&E of $8 million and shareholder distributions of $7.6 billion. Additional financing and investing activities decreased our cash by $3.1 billion, primarily due to the redemption of the SeaRiver deferred interest debentures. Moving on to Slide 6 and a review of our segment results; Exxon Mobil’s third quarter 2012 earnings of $9.6 billion decreased $760 million or 7% from the third quarter of 2011, primarily due to lower gains from asset sales and lower upstream volumes, partly offset by higher refining margins. Upstream earnings decreased $2.4 billion, while downstream earnings improved by $1.6 billion. Chemical earnings were down $213 million and corporate and financing expenses were favorable by $263 million, primarily due to tax items. Guidance for corporate and financing expenses remained at $500 million to $700 million per quarter. As shown on Slide 7, Exxon Mobil’s third quarter 2012 earnings decreased by $6.3 billion compared with the second quarter of 2012, mainly due to lower gains on asset sales. Moving next to third quarter business highlights and beginning on Slide 8; we continue to advance our global portfolio of high quality upstream projects. In Nigeria, the Satellites Phase 1 project continues to progress towards first oil in the fourth quarter of 2012. Drilling has commenced on two of the three platforms. The project will have a peak capacity of 70,000 gross barrels per day. : Construction is also progressing at the Papua New Guinea LNG project which remains on schedule for a 2014 startup. In the third quarter, we completed both the hydro testing of the 250 mile offshore pipeline and structural steel construction on the LNG plant trains. Drilling commenced at Hides with the first of two rigs and the final site preparation is underway for the second drilling rig. Turning now to slide nine and an update on our Gulf of Mexico opportunities. At Hadrian North, we drilled two appraisal wells in the quarter and we are analyzing the results and will incorporate the findings into our development planning. Our current development basis is 100,000 barrel per day capacity, new build semi-submersible floating production system. Exxon Mobil has also begun drilling our Hummer Shallow prospect located in Walker Ridge Block 674 near the Jack St. Malo development. Also during the quarter Exxon Mobil acquired a 20% working interest in the Phobos prospect which is five miles south of Exxon Mobil’s Hadrian South discovery. Additionally, we acquired a 35% working interest in the foreign prospect located about 30 miles Northeast of Exxon Mobil’s Julia discovery. Phobos is expected to spud by year end 2012 and drilling will begin at Thorn in 2013. Turning now to our activities in the Black Sea on Slide 10; Exxon Mobil has established the material acreage position in the Northern Black Sea across Ukraine, Romania and Russia totaling approximately 3.5 million net acres. In August, the Ukrainian Government awarded the offshore Skifska Block to a group of investors led by Exxon Mobil. Our bid combined the extensive deepwater experience, technological expertise, financial strength and the environmental protection capabilities of Exxon Mobil, Shell and OMV Petrom with the local expertise of the National Oil Company, Nadra Ukrainy. Exxon Mobil will be the project operator and we are currently negotiating the joint operating agreement and production sharing agreement. In Romania, where we had a discovery earlier in the year, we are preparing to commence additional 3D seismic acquisition in late 2012 and have begun preparations for additional exploration drilling in late 2013 or early 2014. In the Russian sector of the Black Sea processing of the newly acquired 3D seismic is underway. We will be utilize this information to develop our exploration drilling plans with drilling targeted to begin in late 2014 or early 2015. Turning to Slide 11, during the quarter, we continue to progress our strategic cooperation agreement with Rosneft. We recently completed acquisition of 2D and 3D seismic surveys in the Kara Sea. In addition, geotechnical and oceanographic data were collected of potential drill well locations. Following completion of prospect definition and permitting, exploration drilling is expected to begin in the 2014, 2015 timeframe. To advance Arctic drilling technology, we've signed an agreement in September to evaluate concepts for the development of a gravity based shallow water rig that can withstand extreme ice, wind, wave and temperature conditions. The structure will be designed to be installed on the seabed, refloated and moved to multiple drilling sites. Studies have commenced on the state-of-the-art design, which could significantly increase the safety and efficiency of expiration in the Kara Sea. On shore West Siberia, we are developing a work program for selective Rosneft license blocks which will include geological studies and drilling, with drilling planned as early as next year. A pilot program will determine the technical feasibility of developing these tight oil reserves. In support of these exploration activities, Exxon Mobil and Rosneft have been conducting technical studies on areas of interest, including visits to existing field and facilities. Moving on to slide 12, we also continue to focus on high potential, liquids-rich, unconventional opportunities in North America, highlighted by activity in the Bakken, Woodford Ardmore, and Western Canada. In the United States, approximately two-thirds of our operated rigs are drilling liquids-rich opportunities, up from about 20% at the beginning of 2011. On September 20, Exxon Mobil and its subsidiary XTO Energy announced the signing of an exchange agreement with Denbury to acquire 100% of their Bakken shale assets, which consists of 196,000 net acres in North Dakota and Montana, and production is expected to be more than 15,000 net oil equivalent barrels per day when the deal closes. The agreement will increase Exxon Mobil holdings in the Bakken region by about 50% to nearly 600,000 acres, resulting in a significant presence in one of the major US growth areas for onshore oil production. Additionally, this acreage is located close to current XTO development areas generating further efficiencies. The Woodford Shale and the Ardmore basin of Southern Oklahoma comprises our most active unconventional drilling program with 10 operated rigs delineating and developing more than 260,000 net acres of leaseholds. In addition, we are advancing infrastructure projects to optimize the liquids-rich production from this area. For example, construction was recently completed on a 117 mile natural gas gathering pipeline from our operations of Southern Oklahoma to processing facilities in North Texas. In Western Canada, Exxon Mobil announced an agreement on October 17 with Celtic Exploration in which Exxon Mobil Canada will acquire 545,000 net acres in the liquids-rich Montney shale, 104,000 net acres in the Duvernay shale and additional acreage in other areas of Alberta. Current gross production on the acreage to be acquired is 72 million cubic feet per day of natural gas, and 4,000 barrels per day of crude, condensate and natural gas liquids. These new assets will complement our existing North American unconventional portfolio. Our financial and technical strength will enable us to maximize resource value by leveraging the experience of XTO Energy which has expertise in developing tight gas, shale oil and gas and coal bed methane. Turning now to the upstream financial and operating results and starting on slide 13; upstream earnings in the third quarter was $6 billion, down $2.4 billion from the third quarter of 2011. Realizations decreased earnings by $130 million due primarily to lower crude oil and US natural gas realizations, which declined by $2.31 per barrel and $1.40 per thousand cubic feet respectively. Production mix and volume effects negatively impacted earnings by $700 million, due to the impact of lower entitlement volumes base decline and down time partly offset by the ramp up of Angola and Nigeria projects. All other items primarily lower gains from asset sales and unfavorable tax and foreign exchange effects decreased earnings by $1.6 billion. Upstream after tax earnings per barrel for the third quarter of 2012 were $16.39. Moving to slide 14, oil equivalent volumes decreased by 7.5% from the third quarter of last year, due to the impact of base decline, lower entitlement volumes, divestments and down time. Volumes were positively impacted by the ramp up of projects in Angola and Nigeria. Excluding the impacts of the entitlement volumes, OPEC quarter effects and divestments, production was down 2.9%. Turning now to sequential comparison starting on slide 15; upstream earnings decreased by $2.4 billion versus the second quarter of 2012. Higher crude oil and US natural gas realizations positively impacted earnings by $340 million. As crude oil realizations increased by $0.77 per barrel and US gas realization increased $0.54 per thousand cubic feet. Production mix and volume effects decreased earnings by $540 million due to base decline, down time, lower entitlement volumes and seasonal demand in Europe. Other items including lower gains from asset sales and higher expenses decreased earnings by $2.2 million. Moving to slide 16, oil equivalent volumes were down 4.6% from the second quarter of 2012 due to down time, base decline, seasonal demand in Europe and lower entitlement volumes, partly offset by the ramp up of projects in Angola. Excluding the impacts of entitlement volumes OPEC quota effects and divestments production was down 3.6%. On slide 17, we showed the year-to-date 2012 volumes associated with the expected 3% full year decline provided at the analyst meeting in March. Operational performance through the third quarter was slightly below forecast, reflecting the timing of work program execution, duration of down time events, particularly in the North Sea and the efficient use of capital in Iraq which is lower net volumes. Additionally, the continued focus on enhancing profitability through the shifting of North American drilling to liquids-rich opportunities has contributed to the variance. While the year-to-date Brent crude price of $112 per barrel is near the basis of our March Analyst meeting outlook, prices in the first half of 2012 mostly notably in February through April were higher than our outlook, which negatively affected volumes due to both permanent and price related entitlement. Fourth quarter volumes will be supported by seasonal demand, project startups and completion of schedule downtime. Moving now to the downstream financial and operating results and starting on slide 18. Downstream earnings in the third quarter were $3.2 billion, up 1.6 billion from the third quarter of 2011, as we continue to optimize our refineries by fully utilizing operational and fleet flexibility and the integration with lubes and chemical. Improved margins mainly in North American and European refining increased earnings by $850 million. Volume and mix effects decreased earnings by $20 million, due to lower earnings associated with asset sold largely offset by favorable refining optimization effects. Other items included a gain on the sale of our downstream business in Switzerland, favorable ForEx and lower operating expenses increased earnings by $780 million. Turning to slide 19, sequentially third quarter downstream earnings decreased by $3.5 billion. Improved margins primarily in refining increased earnings by $650 million. Volume and mix effects, mainly driven by lower plan maintenance and refining optimization activity increased by $300 million. Other items reduced earnings by $4.4 billion, primarily due to the absence of a gain associated with the Japan restructuring, partly offset by the gain from the sale of our downstream business along with favorable ForEx and lower operating experience expenses. Moving now to the chemical, financing and operating results and starting on slide 20, third quarter chemical earnings was $790 million, down $213 million versus the third quarter of 2011. Margins decreased earnings by a $150 million namely due to lower olefins, and polyethylene utilization. Other items decrease earnings by $60 million, mainly due to unfavorable foreign exchange impacts. Moving to slide 21; sequentially third quarter chemical earnings decreased by $659 million. Weaker margins mainly in Europe decreased earnings by $90 million. Other items, primarily the absence of the gain associated with the Japan restructuring, decreased earnings by $590 million. Moving to slide 22, Exxon Mobil’s third quarter financial and operating performance reflects the value of our integrated business model and other competitive advantages. We earned $9.6 billion, generated $14 billion in cash flow, invested $9.2 billion in the business and distributed $7.6 billion to our shareholders. As we continue to focus on operational excellence, deploy high impact technologies and leverage our unparallel global integration. Exxon Mobil remains well positioned to maximize long-term shareholder value. That concludes my prepared remarks. I would now be happy to take your questions.

Thank you, Mr. Rosenthal. (Operator Instructions) And our first question will come from Doug Leggate with Bank of America. Doug Leggate - Bank of America: I've got a couple please, one-on-one follow-up I should say. I understand at the Analyst Day you gave as an indication that production would be done this year but it seems that it’s slicing a little harder than certainly we expected and at the same time the capture rate that is you know as the earnings against your weighted revenues has deteriorated somewhat this quarter. So I am just wondering if there's, that you still feel confident in the medium-term outlook and if you have something unusual in this quarter in part to the earnings capture and I’ve got a quick follow-up please.

Let me first address Doug the volume decline. As I mentioned in the chart, my prepared remarks, we are only slightly below what the outlook would have generated if not for again as I mentioned the price and entitlement effects of the higher crude prices earlier in the year and some divestments. I will say that when you look at the slight underperformance if you will on the operation side, a piece of that effect, a big piece of that bar is the fact that we've been able to generate the production volumes that we were looking to get in Iraq with less capital being expended. So because we expended less capital and we are more efficient. We didn't get as many barrels back. We've also had some extended downtime a little more than we thought particularly in the North Sea and some other areas but other than that just some timing and some work program and some of the other things I mentioned but other than that we are pretty much online with what we were looking at. If you are looking at the capture rate in particular in the upstream, I think the biggest driver there of course is going to be the mix of the volumes that we had and where we had some of that downtime across the quarter in Kazakhstan and some other areas that we had some downtime North Sea, etcetera, other than that when you look at the other earnings effects not a lot in there in terms of items other than the fact that we were about a billion less quarter-over-quarter, this quarter on asset divestitures. So I think if you sort those things out, we're pretty much as we would have expected to be. Doug Leggate - Bank of America: Great. Thank you. My follow-up there is hopefully fairly quick. There is always been a lot of other deltas this quarter, the other items that you talked about but again, just like last quarter, they are not as big but they are still fairly sizeable particularly in the downstream. So I guess there is two points to my question. The first one is, would you be able to quantify the absolute impacts of the major parts from disposals in the foreign exchange effects as opposed to the relative impact and this is an observation. At what point, or what is the philosophical reason for not providing the absolutes on a quarterly basis because it would be extremely helpful if you were able to do that?

Doug, let me have a couple of those. First of all, foreign exchange is one that’s impossible to give an absolute because you got both changes and impacts on your working capital balances. Those are specific. But when you are looking at the impacts on the earnings, it's really just a translation of margins and OpEx using exchange rates last quarter and this quarter. So you don’t have an absolute amount on that. If we look across the corporation though, I will tell you that quarter-to-quarter, the impact was very small and I am happy to talk about the details. If we go specifically to the downstream earnings, I think which is one you are interested in, if I am looking at downstream earnings, third quarter of ‘12 versus third quarter of ‘11, again you saw the nice margin bump there of $850 million that’s really clean, there is no lag effects or other things in there. We were just able to have all of our operations running strong and take advantage of the strong market that we saw there. On a $780 million, if I move over to the other column, I am happy to give you some additional color there. The biggest part in there was about just under $400 million for our divestments in the quarter favorable FOREX quarter-versus-quarter was another $300 million and the balance was favorable OpEx and that pretty much takes that out. Volume pretty minimal where we lost volumes in some of the divested assets we were able to make up those earnings by higher volumes and throughput and some of our other operations.

Your next question will come from Evan Calio with Morgan Stanley. Evan Calio - Morgan Stanley: Yeah, I just have a question related to the Celtic acquisition in the quarter and does this deal reflect any change or evolution in Exxon’s view of potential Canadian or British Columbian specific LNG export potential with your bigger Montney position now?

I don’t think it changes any of our views or thoughts we have going forward. The Celtic acquisition gives us an opportunity to pick up as I said about 545,000 net acres in the Montney that most of that acreage is near acreage we already have. So it’s very helpful to us. And it’s just a continuation of what you have seen for the last couple of years where we have taken advantage of opportunities to go out and acquire large tracks of promising acreage with high upside potential and both goes on to the XTO acquisition and in particular, I think what you have noticed over the last year or so is these acquisitions have tended to be more liquids-rich properties than the gas things that we added early on. So no change, I will say though that of course this gives us tremendous opportunities across North America, all of which we are looking at and as you mentioned. I think we mentioned before that we are in the early stages of assessing potential export options from Alaska from Western Canada and from the US Gulf Coast. So we are fortunate to have large resources in each of those areas and again as we develop our plans and go forward, I will have to more to say about that. But I would say it’s really a continuation of the strategy that we’ve had in place now for the last couple of years. Evan Calio - Morgan Stanley: That's great, and may be just one other follow-up if I may to those question, I mean on relating to upstream volumes. Can you quantify or discuss the turnaround activity [legacy] contributed to what’s your defining lower operational performance and I guess specifically and I guess your comments that may not but just confirm that does not or you don’t see that extending into the fourth quarter and I’ll leave it to that things?

Sure, if you look at, I think the best place to look at really where we see any impact of this downtime. If you look quarter-on-quarter, third quarter of ‘12 versus third quarter of ‘11 over in the net growth where we have the minus 125 about 40 of that is downtime across the number of areas most of its scheduled, you are well aware of we had some downtime at Qatar, Alaska and the North Sea and so that impact showed up there. You also see it, particularly if you are looking sequentially because as you know a lot of this downtime is seasonal, but the downtime effect between the third quarter this year and the second quarter of this year was about 90 KBD. So a significant effect; most of that production is pretty much back-up. We do have some continued downtime and operated by other’s properties in the North Sea, but other than that the rest of the production is coming up as we would have expected heading into the fourth quarter.

Thank you. And our next question will comes from Robert Kessler with Tudor, Pickering, Holt. Robert Kessler - Tudor, Pickering, Holt: A couple of quick ones from me. One, your US natural gas volumes declining quite considerably sequentially, I'm wondering if there's any anomalous items in there and of course we had hurricanes, I wouldn't have thought you would have been disproportionately exposed to that, what can we assume for a say normal decline rate in your US natural gas volumes going forward?

Yeah, if you look sequentially at our US gas I mean we had a little bit of impact from weather related activity, but it wasn’t large. You did see a decline sequentially of about 5%. Some of that was downtime, but the majority of it was kind of base decline and really the impact you are seeing as we are shifting rigs from drilling primarily gas plays to drilling liquid focused plays. And so the total rig count is down across the year and the proportion that's drilling liquids rich plays versus gas has gone up and so I think between that and some downtime that really accounts for the bulk of the reason we are down. As you look forward, I really don't have an outlook for you. It will be dependent on how we bring things along in the market and that sort of thing, but clearly you are seeing the impact of our changing focus from drygas to liquids rich opportunity. Robert Kessler - Tudor, Pickering, Holt: And then a conceptual one from me on M&A; your recent North American focused transactions have of course further increased your upstream weighting of capital employed to North America. Your US weighting alone was I think 46% in the upstream capital employed at the end of last year. Looking at future acquisition possibilities conceptually does Exxon Mobil apply any limit to the capital you plan to deploy to North America or would you continue to look at potential North American M&A the same way you look at opportunities globally?

Yeah, let me step back, that's a good question. As we step back and look at our total capital budget and where we put our CapEx, we really don't have any limits in terms of type of resource or geographic focus. We pursue all of the attractive opportunities that are out there. As you look across the last several years you tended to see us sometime putting more CapEx into oilsands or unconventional plays or LNG, but all of that is really reflective of the opportunities as they are presented and our ability with our strong financial strength to basically take advantage of anything that's out there that's on offer that we think will provide shareholder value. As you've seen over the last couple of years, the bulk of that has been through internally generated CapEx, but there's also been some selective acquisitions and so I would say going forward you'll see us continuing to do what we've been doing, which is to look at all the opportunities that are out there on offer and taking advantage of any opportunity we have to really enhance the portfolio of our assets with the focus continued on the long term, you know, if you look at all the things we've been doing over the last couple of years, they are all focused on bringing really long term legacy projects up and get them running and then continuing to add to our resource space, our opportunities for the future. So I wouldn't see anything different going forward than what we've been doing; but we will continue to look for attractive opportunities wherever they present themselves.

Thank you. Next, we will hear from Doug Terreson with ISI. Doug Terreson - ISI: Some of the global competitors are indicating that global oil demand maybe gravitating lower again and on this point, given your global perspective, I wanted to see if you could provide insight into some of the demand trends that Exxon Mobil is seeing around the world and specifically whether you guys are witnessing any deterioration in this area? And then second, just for Exxon specifically, R&M was clearly strong in the quarter, but the company didn’t seem to benefit to the degree that some of the competitors did and while you talked about some of the cost factors a minute ago, was there anything unusual on downtime, either planned or unplanned that affected results and if so do you have any quantification in that area?

Let me start at the first one there with the global oil demand, I don't think we're seeing anything different than what others are seeing and what you're reading in the press in terms of demand particularly say in Europe and Japan and some other areas. We’ll be putting out our own update here in December on our view of global oil demand, but, again from our perspective, I wouldn't have anything to offer any different than what you are seeing out there, what you are talking about. Doug Terreson - ISI: Okay.

The R&M results, as you mentioned, were really strong. Again, I have to say, you know, we were able to have very good operations up time able to take advantage in particular in the U.S. of the discounted feeds, both heavy Canadian feeds as well as WTI linked crude and so we are optimizing those across our Mid-Continent refineries and you are seeing some of those impacts showing up in the bottomline. If you are looking at downtime, I think it was the rest of your comment in the downstream? Doug Terreson - ISI: Yeah, was it unusual in the period?

You saw a little bit more in the second quarter and less in the third quarter as we came out just to give you a little more color, if you were looking sequentially from third quarter of ’12 on to again, I am sorry the third quarter versus the second quarter, we did see some lower OpEx of somewhere between $100 million and $200 million you would have seen there to the quarters and that would have helped that. But again, the bulk of the earnings driven by good operations and favorable margin impacts.

Thank you. And next we’ll hear from Allen Good with Morningstar Investment. Allen Good - Morningstar Investment: Just a question on the M&A; obviously you mentioned some of the activities you have had relatively probably a little bit more than some of your competitors off late. Can you talk a little bit about the characteristics that Exxon looks at when you go out there and survey those market opportunities that are out there and some of the things that may be you have learned from XTO since acquisition as far as what may be the better plays or any sort of knowledge you have gained from XTO that helps you to better delineate on those market opportunities as far as acquisitions go?

Yeah let me, I’ll actually start with your second question and back up in to the first. Clearly, one of the synergies that we anticipated getting with the XTO acquisition that have been realized in the last couple of years is the ability to utilize the expertise and now as they had combined with some of our technology advances to better analyze and evaluate properties that are out there. And you’ve seen that, if you look at some of the acquisitions we made in the U.S. of properties and some of the deals we have done elsewhere and up in Canada, a lot of the ability to properly evaluate the resource potential of those properties and assign value to them stems from directly from the organization that came with the XTO acquisition and that is working just as we had planned. As you look at M&A or any other resource opportunity capture, we look for the same thing in all of them. We do have a high quality large resource with upside potential; that has to be number one. Do we think we can bring some synergistic value to those reserves and perhaps get a better return than someone else could and that comes from either technology that we bring to the table, R&D work or operational expertise that allows us to then again get a better value for that and they might otherwise would have. And then we look for other more obvious synergies around contiguous properties to what we have or other ways of filling in a portfolio to perhaps be able to pursue a larger strategy. So M&A versus outright capture of these resources, the criteria for us remains the same and we really don't differentiate between the two. Allen Good - Morningstar Investment: And then just second question, could you update us on the North America rig count. I believe you were close to 250 in the last quarter and you Don mentioned that I think over half of it is in liquids-rich place, are you continuing to move drilling away from dry gas at this stage.

Yeah, as we look to cross the quarter we ended at about 50 rigs. We are probably close to that today maybe a rig or two less as we speak, and two-thirds of those rigs are drilling the liquids-rich opportunities and in particular I mentioned the Woodford Ardmore is an area of high activity for us, the Bakken of course, an area of high activity and the Permian is another area of high activity for us. So you do see this shift going into the areas that are more liquids-rich. As you go forward without giving any specific counts, you could expect to see us continuing to pursue those liquids-rich opportunities particularly in the areas that I mentioned, but I don't have a specific outlook for you in terms of total rig count going forward.

Next we will heal from Blake Fernandez with Howard Weil. Blake Fernandez - Howard Weil: You briefly mentioned LNG and I was hoping you could maybe give us an update on where you stand in the application process out of the US Gulf Coast and then maybe more broadly you kind of mentioned the potential from Western Canada, Alaska. Could you maybe rank order where you see the best opportunities if possible, I know its early days yet but.

Sure, let's start with the Golden Pass opportunity that we are assessing. We did early in October, we received authorization from the US Department of Energy to export domestically produced natural gas as LNG from Golden Pass to nations that have existing Free Trade Agreements. So we do have that approval in hand. I can also tell you that we have recently filed an application with the US Department of Energy to explore LNG to non-FDA countries, and we will see how that application process proceeds. I have to say that when we look at all of these activities, they really are all in the early days and no decisions have been made. Again, we are very fortunate to have a material high quality gas resource in both the US Gulf Coast and in Western Canada and Alaska, and it would be way premature to try to rank order those other than to say they are all high quality resources for us and we are looking at all of the options available to monetize those resources including again early days on assessing the viability of LNG exports from anyone of those three regions. Blake Fernandez - Howard Weil: Yeah, fair enough. The second question was on the Gulf of Mexico shelf, as I understand that you had formed maybe a JV with a smaller EMT player to target I guess a deep oil play similar to what some of your peers are doing on the gas side for deep gas. I'm just curious if you had any updates on that, and if I'm not mistaken there was going to be a well [spun] toward the end of the year.

Yeah, I don't have a specific update with regard to that joint venture. We do have that transaction as was publicly discussed, but I really wouldn't have any update particularly near term on what our activities are going to be on that. And I'll just mention though if you look across the broader Gulf of Mexico, you do see a nice increase in activity as we continue to develop some of these properties that we have captured over the last couple of years I mentioned some of those in our prepared remarks and we're very excited about getting some of these wells down and continuing to broader exploration phase, which as you mentioned, has a number of partners and a number of structures but all in a very good opportunity for us and one we're pursuing pretty quickly.

The next question will come from Arjun Murti with Goldman Sachs. Arjun Murti - Goldman Sachs: Just a few follow ups on some of the North America type question. So you have been pretty clear you pulled back on some of the gas drilling in the US and we saw a little bit of that decline show up. When you kind of slow down the drilling in unconventional, the decline is going to be pretty precipitous. So just wondering maybe the follow up to the earlier question, you know, is 5% just the beginning of what could be a more rapid decline in your gas production or is there something that is not fully apples-to-apples about this decline and it won't be as bad or worse going forward?

I don’t have a specific outlook for you, Arjun, but I will note that there are a number of factors in addition to just some of the shifting of these rigs. We did have some downtime in the quarter, and if you look at this year versus last year, you will recall we did have some asset sales last year and we're seeing a little bit of that. But again, if you look just over the couple of last quarter in particular, downtime and then just normal decline associated with this, but I don’t have a decline rate for you or go-forward in outlook. We will see how things go. I will tell you, in some areas, we've been actually able to keep the volumes flat, while reducing the rigs due to efficiencies we have gained, rates of drilled wells and that sort of thing. So we have been able to offset some of this decline in rigs with some improved operations and productivity. Arjun Murti - Goldman Sachs: In terms of the shift Dave to liquids-rich would you say you have made the shift now or is there still more gas rigs to come out of the rig count?

What you will see as we’ll continue to have this focus on the liquids-rich place exactly how many more rigs might move I don’t have a specific number for you. We do have contractual obligations that we have to meet and other commitments which will keep us drilling some dry gas wells, but we evaluate this thing on an ongoing basis literally day-to-day and month-to-month in terms of how we optimize the rigs we have available to us, what the market is generating, or how the wells are performing. So I really wouldn’t have a forward look for you. Arjun Murti - Goldman Sachs: And Dave may be just lastly on the same topic, clearly you are increasingly are some liquids-rich, you mentioned the Permian, the Bakken some of these places. In terms of having that show up visibly in your US liquids oil volumes, I’m going to assume there is some lag for that to happen none that you can comment on that at all?

You are seeing that show up in the liquids volumes as some of this ramp up; and again most of what we have been doing in these areas for the last several months is been delineating what we have, appraising what we have been doing, looking at what the optimum parameters are for developing thee fields. So now you are starting to see us ramp up on the production side particularly in the Bakken where we are up, I think just under 50% year-on-year if you look at the third quarter. So you are starting to see some of that. You will start to see some of that in the other areas as well; the Woodford Ardmore for example and the Permian as we continue to move into more of a development mode. So I don't have the number for you other then to say yes, if you look at those fairly small declined rates on US liquids, you are seeing the impact of normal decline on our conventional field being offset somewhat by ramp ups in some of those other areas. I will say, if you take out the Alaska and just look at the lower 48, our liquids volumes are actually up quarter-versus-quarter and sequentially. So, some of that downtime is masking some of that performance. Arjun Murti - Goldman Sachs: That's helpful, thank you so much.

Our next question will come from Faisel Khan with Citi Group. Faisel Khan - Citigroup: I want to go back to the production outlook for a second. In your analyst meeting, you guys discussed how production capacity will grow at some blade through 2015, and given your comments around decreased drilling of national gas in US also so that matter decreased investment in Iraq and potentially an exit from southern Iraq and I am just trying to figure out how does this impact your future production capacity gross targets, and to that reserve replacement too?

First of all, I don't have a new outlook on the outer years. We are just in the process of pulling our plan together and looking at what the future looks like. I don't have any updates, and of course we will provide an update in March at the Analyst meeting. I will say if you look at all the big projects that we have gone on out there that we've been building for sometime. Those are all in the process of starting up as planned. The projects we had this year in Angola and Nigeria as we look out a little further of course the start up of the Kearl project and then as we move into the following years the Banyu Urip project in Indonesia and all the other launch projects Papua New Guinea LNG (inaudible) Gorgon, all of those projects that we got still going in the ground, all of those are still in the plan and that portfolio remains very strong. So I don't have an update around on that. And the second part of your question Faisel. Faisel Khan - Citigroup: Yeah David on Southern Iraq, I mean what are your plans in the country?

Yeah, if we look at Iraq, the comment I made was we are now producing right at about 430,000 barrels a day of oil right on plan and the good news is strictly that we've been able to do that a little more efficiently than we had expected but I don't have any other update on Iraq other than that. We continue to work and continue to meet our contractual commitments. Faisel Khan - Citigroup: Just one last question, on your chemicals business, on the expansion of your Singapore facility can you give us a status update on that and what (inaudible) facility is operating, its up and running and if you are moving products into the markets.

Sure. The simple answer would be yes to all three of those questions. The project is nearing mechanical completion and as we talked about before several of the various pieces of that project have been progressively starting up. We were able to produce for example metallocene based polymers here earlier in the year. We do have product qualification activities underway for those products. So the overall project is coming right along. The very last project to reach mechanical completion is the steam cracker and we do expect completion of that by year end. So we would certainly expect to be mechanically complete and on track for starting that large investment up and moving that product into the market. So the project is doing well. The Asia Pacific area as you well know is kind of looking at bottom of cycle margins right now. Not surprisingly that remains a cyclical business and one of our strengths has been for a long time investing through these cycles with very strong a year or two ago, it’s weak now, this project as you can well imagine is really designed for the long-term while we remain very bullish on growth in that part of the area. So the long-term view remains the same. The project is on schedule to start up and to be mechanically complete by the end of the year and then we will progress the ramp up of that as we go through the first part of next year.

Our next question will come from Pavel Molchanov with Raymond James. Pavel Molchanov - Raymond James: Two quick ones on Celtic if I may, as I'm sure you saw the Canadian government recently vetoed a purchase by another operator of a domestic oil & gas company. Any concerns about getting approvals for the Celtic purchase?

Our approval process is the same as everyone else’s and we are progressing through that. We have a long history of operating in Canada. We've been there a long time and we are looking forward to getting through the approval process and closing on that deal and moving forward with our plans for those resources. Pavel Molchanov - Raymond James: Okay and assuming the deal goes through and given what you said about curtailing dry gas drilling across North America, is it safe to say that you would pull back on the current, relative to the current level of drilling activity across Celtic’s acreage?

I don’t have any outlook today on exactly what specifics we would be doing with that once the deal closes. The deal hasn’t closed yet. So it would be premature for me to make any comments about our plans going forward.

Thank you. Next we will hear from Edward Westlake with Credit Suisse. Edward Westlake - Credit Suisse: Just two quick earnings questions. If I turn to slide 15, this is the upstream sequential 3Q to 2Q. Obviously there is a $2.2 billion negative other and $1.1 billion of it is assets sales but can you give us some color on to what the other $1 billion is in terms of the changes, for downstream, that’s helpful.

Yeah, if you're looking at this sequential, this is the sequential that you're looking at. Edward Westlake - Credit Suisse: Yeah, 2Q versus 3Q.

Yeah, there are couple of other factors in there. OpEx is a negative $200 million, foreign exchange is a negative $100 million and then the combination of asset sales and tax items is about $1.8 million. And the main driver of the OpEx and tax related, we did have the change in the UK tax but if you roll it all up, just think about OpEx a couple hundred million, FOREX $100 million, taxes a $100 million in the balance in the asset sales and tax items. Edward Westlake - Credit Suisse: And those tax items were, were any of those deferred whether it was ongoing?

Yeah, some of those were deferred. Edward Westlake - Credit Suisse: And then just on the chemical business in the US, obviously Baytown had some disruption in the first half I guess 3Q was it been a good result, is that a fair kind of run rate for the macro conditions that we are in Q3 or were there any disruptions in the US portfolio for chemicals?

No, we didn’t really have any disruptions of any consequence kind of normal operations and nothing really to speak off kind of like the downstream; our chemical operations ran well in the third quarter and no major items. Edward Westlake - Credit Suisse: And then coming to my question on cash and buybacks etcetera, obviously [Europe] your ending cash at the end of the quarter was lower than the beginning of the quarter because $14 billion of cash flow doesn’t cover the dividend plus buybacks plus the spent on this large mega projects. Are you comfortable to let cash balances fold or is this some kind of statements about the future cash earnings power of Exxon as these big projects come on which means that ultimately this level of buybacks is appropriate?

Yeah, I think the first thing I will note Ed is that we did spend $3 billion of our cash when the SeaRiver debentures matured in the quarter. So that was a $3 billion hit there. In terms of overall strategy around cash, no change in our approach there, we maintained sufficient cash to run the operations and keep our flexibility for doing other things in the business but really don’t have any particular change or outlook in terms of cash or debt. We will just optimize that as we go forward depending on business conditions.

Thank you. Next we will hear from Paul Cheng with Barclays Capital. Paul Cheng - Barclays: I have pleased for three really short questions. First, on the versus the second quarter, you indicate that production job 39,000 barrels per day due to entitlement, I would assume that's all we need to change in [POV] in some of your project. The question is that do you any major projects about to change their POVs that over the next one to two years?

Let me talk about the first one. I will give you a little more color on that 39,000 barrels a day Paul. It was about half was permitted to net interest impacts and the other half was on price and expense, so kind of a mixture there and neither one of having a significant impact. Going forward when we look at near-term production of course the biggest factor for us is the price because that drives how many barrels you get to recover your cost as well as how quickly through the transit. So looking forward here particularly near-term, I don't have an outlook number to provide you specific to what the sequential price expend impacts might be but again the biggest factor there is crude price. Paul Cheng - Barclays Capital: Do you have any major project that is above, that potentially could be they move to the next [PR] ratio within the next one or two years, you have the current oil price stay?

Paul, I really I don't have any specifics along those lines in terms of our project by project. We will really talk again about the make up of our volumes going forward when we visit with you in March and so I’ll probably just hold any comments about future volume outlooks to that time when we can kind of ramp in the whole story for you. Paul Cheng - Barclays Capital: Okay, can you tell us that what is your total share oil production in the third quarter or as of this point and breakout between the oil and gas.

If you are looking at our unconventional volumes, you know I don't have a total for you on that Paul or a split between oil & gas, you know I think the important thing is as you are looking at the progress that we are making against some of these improvements we are making year-over-year in the Bakken in particular for example and some of the other areas. I think that the progress we are making in those fields particularly as we transition from delineation and appraisal into more development is probably more important than the absolute production that we are seeing on that and the progress that we are making, but I really don't have a specific number for you. Paul Cheng - Barclays Capital: Just quick one, last one, do you have the absolute venue of the after sales (inaudible) in the quarter and also do you have any meaningful inventory gains or price finalization impact for your long haul [barrel] under water in this quarter.

Yeah, let me hit that second question and then I will back up to the first one. If you look at the absolute number in the third quarter, it’s almost zero in terms of all the price timing, price finalization, long haul crudes. We did have a negative effect in the second quarter, but if you look at our absolute results in the third quarter there really wasn’t anything there. And then if you were looking at the absolute value of the divestments in the third quarter, that was about $400 million and the biggest item there was the downstream divestment of our business in Switzerland.

And next we will hear from Ian Reid with Jefferies. Iain Reid - Jefferies: I just got a couple of quick questions about your international assets. On Kurdistan, do you want to give us your thinking about the drilling program there and when we should be looking forward to the results etcetera.

Yeah, Iain I have to say I really don't have any comments on Kurdistan at all to offer today. Iain Reid - Jefferies: Really, but you do have a program going on there.

Yeah, like I said I really just don't have any comment on Kurdistan today. Iain Reid - Jefferies: Okay. Papua New Guinea, what's the status of the planning for train 3. You obviously mentioned pretty good mentioned from the first two trains. I believe train 3 is in the works that when should we look for FID on that.

Yeah, let me first back up just a second and let you know that our primary focus of course is on our existing projects. That project has come along very well and we are on schedule for startup in 2014 and that's our primary focus. If you look at how we are doing on the exploration side, I think we have a number of opportunities in the area and we have a very active broad explorations program going on. We have had some success this year in the Tingyang well. So that's looking good. Obviously as we continue to evolve and mature our resource space in the area, we will be looking at options for monetizing those resources and I can’t give you any outlook in terms of when we will make final decisions on any opportunities but we are in the early stages looking up we have, thinking about what we might want to do and I would of course include a potential additional train of Papua New Guinea but all of that will be depending upon the exploration success that we have and how we look going forward but in the meantime, I think the really positive news for the shareholders is the project is progressing and progressing well. And the areas are looking very promising for us. Iain Reid - Jefferies: Could just comment on PNG, I know you didn’t take up the form out, which also is offering in the exploration areas. Does that kind of indicates, you got enough of PNG or what was you thinking there?

I wouldn't want to make any comment on any thoughts or rumors or speculation on deals that we've done or not done. We're looking at a lot of things but again I wouldn't make any specific comment on any particular potential transactions. Iain Reid - Jefferies: Okay, so the last one. I think you can help me with. West Siberia tight oil what's the kind of structure of the contracts or the agreement there with Rosneft. Are you carrying them through this or what are the kind of, any idea about outlying cost and volumes etcetera?

If you are looking at West Siberia, we are as I mentioned looking at, we're already actively studying and what we are going to do in that pilot program, hope to get a well down in the first quarter. In terms of specific details of the commercial arrangements there, probably, premature to be talking about that given where we are in the stage. So I won't be able to help you on that question after all. Iain Reid - Jefferies: But you do have 30% interest, is that the way it would?

Yeah, it’s two-thirds, one-third Rosneft and Exxon Mobil.

At this time, we have no further questions in the queue. Mr. Rosenthal, I will turn the conference back over to you for any additional or closing remarks.

I would just like to thank everybody for your participation today. I know many of you are probably participating under some probably fairly difficult personal situation. So I wish you all the best. In that regard, thanks for the good questions and I’ll look forward to seeing you in about three months. So thank you very much.

Thank you. And again that does conclude our conference for today. We thank you for participation. Your may now disconnect.