David Rosenthal – VP, IR

Faisal Khan – Citi Ed Westwick – Credit Suisse Blake Fernandez – Howard Weil Robert Kessler – Tudor, Pickering, Holt & Co. Doug Leggate – Bank of America Merrill Lynch Evan Calio – Morgan Stanley John Hurling – Societe Generale Paul Sankey – Deutsche Bank Paul Cheng – Barclays Allen Good – Morningstar Pablo Mockonoff – Raymond James Iain Reid – Jefferies & Co.

Good day, and welcome to this Exxon Mobil’s corporation’s Second Quarter 2013 Earnings Conference Call. (Operator Instructions). Today’s call is being recorded. And at this time, for opening remarks, I would like to turn the call over to the Vice President of Investor Relations and Secretary, Mr. David Rosenthal. Please go ahead, sir.

Good morning, and welcome to Exxon Mobil’s second quarter earnings call and webcast. The focus of this call is Exxon Mobil’s financial and operating results for the second quarter of 2013. I will refer to the slides that are available through the Investors section of our website. Before we go further, I would like to draw your attention to our 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 growth remained constrained in the second quarter. U.S. economy continues to be sluggish after first quarter GDP growth was revised downward. China’s economic growth continues to lag expectations while European economies remain weak. Energy markets delivered mixed result in the second quarter. The quarterly average crude oil price declined more $10 barrels per barrel from the first quarter. Narrowing the spread with WTI. While U.S. natural gas prices increased. Global industry refining margins were essentially flat with increases in the U.S. margins offset by weakness in Europe and Asia Pacific. Chemical commodity product margins declined across the quarter. Turning now to the second quarter financial results as shown on Slide 4, Exxon Mobil’s second quarter 2013 earnings were $6.9 billion, a decrease of $9.1 billion from the second quarter of 2012. Mainly reflecting the absence of prior gains associated with the Japan restructuring and divestments. Earnings per share for $1.55. The corporation distributed $6.8 billion to shareholders in the second quarter through dividends and share purchases to reduce shares outstanding. Of that total, $4 billion was used to purchase shares. CapEx in the second quarter was 10.29 billion and 22 billion for the first six months of 2013 in line with anticipated spending plans. Cash flows from operations and asset sales was $8 billion. At the end of the second quarter cash totaled 5 billion and debt was $19.4 billion. The next slide provide additional detail on second quarter sources and uses of funds. Over the quarter cash decreased from $6.6 billion to 5 billion. Earnings, depreciation expense, changes in working capital and other items including equity company dividend and our ongoing asset management program yielded $8 billion of cash flow from operations and asset sales. Uses included addition to plant property in equipment of $8.7 billion and shareholder distribution of 6.8 billion. Additional financing and investing activities increased cash by $5.9 billion. Share purchases to reduce shares outstanding are expected to be $3 billion in the third quarter. Moving on to slide six and the review of our segmented result. Exxon Mobil second quarter 2013 earnings of $6.9 billion decreased 9.1 billion from the second quarter of 2012 reflecting the absence of prior gains associated with the Japan restructuring and divestments. In the sequential quarter comparison shown on slide seven. Earnings decreased by about $2.6 billion across all segments. Guidance for corporate and financing expenses remained $500 million to $700 million. Turning now to the upstream, financial and operating results and stating on slide eight. Upstream earnings in the second quarter were $6.3 billion. Down $2.1 billion from the second quarter of 2012. Higher natural gas realization mainly in the U.S. partly offset by lower crude oil realization increased earnings by $90 million. Worldwide natural gas realizations increased a $1 per thousand cubic feet while crude oil realization declined $4 per barrel. Production volume and mix effects had a small negative impact of $70 million. All other items mainly the absence again on prior year asset sales and the reimbursement of past exploratory cost to Rosneft for the Back Sea and –Sea joint ventures decreased earnings by about $2.1 billion. Upstream after tax earnings per barrel for the second quarter for 2013 were $17. Moving to slide nine, volumes declined by 78,000 oil equivalent barrels per day or 1.9% from the second quarter of last year. Liquids production was down 26,000 barrels per day as field declined and divestments were mostly offset by increased production from liquid rich place in the U.S. project ramp ups and lower down time. Natural gas production was down 307 cubic feet per day. As field decline mainly in the U.S. and lower entitlement volumes were partly offset by higher European demand lower downtime in several countries including Qatar and project ramp up. Note that entitlement impacts were all price and stand related. Turning now to the sequential comparison and starting on slide ten. Upstream earnings decreased by $722 million versus the first quarter of 2013. Realizations reduced earnings by about $360 million as worldwide crude oil and natural gas realizations decreased by $5.84 per barrel and $0.56 per 1,000 cubic feet respectively. Volume and mix effects decreased earnings by about $300 million mainly due to lower European seasonal gas demand. Other items had a small net negative impact of about $70 million as the higher cost in Russia, mentioned in the quarter-on-quarter comparison were mostly offset by several small positive items. Moving on to slide 11. Oil equivalent volumes were down about 7% sequentially. Liquids production was essentially flat, compared to the first quarter. Higher plant down time and field decline were mostly offset by improved reliability and project ramp-ups. Natural gas production was down 1.8 million cubic feet per day versus the last quarter, mainly due to lower seasonal demand in Europe. Our year-to-date volume performance is in in line with the projection presented at the analyst meeting in March with strong uptime performance, increased North America unconventional liquids production and higher European gas demand offsetting this lower than anticipated ramp-up at Pearl. We remain on target to meet the 2013 volume outlook presented at the analyst meeting. Moving now to the downstream financial and operating results and starting on slide 12. Downstream earnings for the quarter were $396 million, down $6.3 billion from the second quarter of 2012, due primarily to the absence of the $5.3 billion gain associated with the Japan restructuring. In addition lower refining margins reduced earnings by $510 million. Volume and mix effects decreased earnings by 370 million, reflecting significant planned refinery maintenance activity across all regions. Turning to slide 13, sequentially second quarter downstream earnings declined by almost $1.2 billion. Lower overall refining margins, including unfavorable price timing effects in the U.S. decreased earnings by $170 million. Volume and mix effects decreased earnings by 540 million, reflecting significant planned refinery maintenance activity at Juliette and Torrance in the U.S. and Strathcona, Saudi Arabia, Augusta and Singapore outside the U.S. This was the highest quarterly planned maintenance activity over the past five years. Other items reduced our earnings by $440 million primarily due to the absence of first quarter asset sale gains and costs associated with the Dartmouth Refinery conversion. Moving now to the chemical, financial and operating results, starting on slide 14; second quarter chemical earnings were $756 million, down $693 million versus the second quarter of 2012. Lower specialty product margins reduced earnings by $100 million. Higher commodity product volumes driven by strong polyethylene demand increased earnings by $120 million. The absence of the gain associated with the Japan restructuring decreased earnings by $630 million while all other items decreased earnings an additional $80 million. Moving to slide 15, sequentially second quarter chemical earnings decreased by $381 million. Lower margins mainly due to weaker aromatics prices reduced earnings by $200 million while an improved sales mix provided a $30 million offset. Higher plant maintenance expenses associated with Singapore’s new steam cracker start up and the absence of gains from prior quarter asset sale decreased earnings by 210 million. Moving next to the second quarter business highlights beginning on slide 16. We continue to advance our portfolio of high quality upstream projects which we expect will deliver the liquids growth presented at the analyst meeting in March. The Kearl oil sands development continues to produce pipeline quality crude. We continue to ramp up production, having now run two of the three froth treatment trains individually as well as concurrently and achieved rates of 35,000 barrels per day through each. The third train is ready for initial operation and its startup will enable production to increase 110,000 barrels per day in the coming months. The Kearl expansion project is on budget, ahead of plan and now over 40% complete. We are using existing Kearl initial development contractors for efficiency and continuity and achieving higher productivity as a result. The expansion project is scheduled for start-up in 2015. The Julia initial development project was sanctioned during the second quarter and is expected to develop more than 190 million gross barrels of oil with start-up in 2016. The initial development phase is being designed for daily production of 34,000 gross barrels of oil and includes six wells with subsea type tie-backs to the Jack and St. Malo production facility. Front-end engineering design has been completed and the engineering, procurement, and construction contracts has been awarded. The field is estimated to have nearly 6 billion barrels of resource in place. Hebron construction activities continue with commencement of concrete ports for the gravity-based structure as well as fabrication of living quarters and drilling support module. Oil recovery from the project is estimated at 700 million gross barrels with upside potential. The platform is designed for production of 150,000 barrels of oil per day. First oil is anticipated around the end of 2017. Turning now to slide 17 and an update on our efforts to progress global LNG projects and opportunities. The map to the left of the chart provides an overview of our LNG business, displaying gross existing production capacity of 64 MTA. The site’s currently under construction and a number of future opportunities being evaluated. The PNG LNG project construction is currently 88% complete and is achieving project milestones towards a 2014 startup. Commissioning activities for the first train at the LNG plant are ongoing while construction activities for the second train continue. Progress also continues at the Hides gas conditioning plant for equipment including gas turbine generators and utility systems that’s being received and installed. We are also advancing expansion opportunities, including negotiations with NOL Corporation and Pacific LNG on the future development of the Elk, Antelope resource. Major terms have already been agreed and should negotiations successfully conclude Exxon Mobil is proposing that 4.6 TCF of the gas resource from the Elk Antelope field be used to underpin the construction of an additional train at the PNG LNG project site, subject to partner and government agreement. Construction at Gorgon is now 65% complete. Installation of the first subsea trees at [Jens] has commenced and offshore pipeline installation is ongoing. Moving now to North America, Golden Pass Products, our venture with Qatar Petroleum International recently initiated the FERC pre-filing process setting the stage for essential permitting activity associated with the design, environment and construction of a proposed project to produce and export up to 15.6 MTA of LNG. Golden Pass Products already has an export for free trade agreement countries and awaits approval of its non-free trade agreement license from the Department of Energy. Exxon Mobil and Qatar Petroleum International also signed a commercial framework agreement in the second quarter which demonstrate the project’s readiness to succeed based on its technical, financial and marketing capabilities. In Western Canada Exxon Mobil and Imperial Oil recently filed an application with the National Energy Board for LNG export license to support the further assessment of the potential development of a natural gas liquefaction terminal on the Northwest of British Columbia. The export license requested is for up to 30 MTA for a period of 25 years. If developed the natural gas liquefaction plant LNG storage and marine loading facilities are anticipated to be in vicinity of either the [Kiddie map] or [Inaudible] areas. We also continue to assess other LNG opportunities in Alaska, Australia, Russia and Tanzania. A range of factors will be considered before any final investment decision is made, in particular the fiscal and regulatory regime market conditions and capital cost. Turning now to slide 18 and an update on our exploration activities. In June Rosneft and Exxon Mobil announced the completion of several milestones under the 2011 strategic corporation agreement, including joint venture formation for the Kara Sea and Black Sea projects. Collection of seismic data within both regions is underway and drilling operations are set to begin in 2014. As we announced previously Exxon Mobil and Rosneft agreed to increase the scope of their strategic cooperation by adding seven new blocks in the Russian Artic spanning approximately 150 million acres. We have now entered into more definitive foundation agreements for joint ventures to explore within these areas. Foundation agreements are also now in place for our joint venture Tide Oil project in West Siberia where data gathering is underway in preparation for drilling. Rosneft holds a 51% interest and Exxon Mobil has a 49% interest in this project. Turning to Romania. Exxon Mobil and OMB Petron have successfully completed acquisition of the largest ever Black Sea 3D seismic survey on the Neptune D Block, covering more than 2,300 square miles. This survey will be used to continue the evaluation of the Domino Discovery as well as to evaluate additional exploration potential on the Block. In the Gulf of Mexico we recently spud the Maui deepwater prospect on Walker Ridge Block 282 after acquiring a 33% in the prospect during the first quarter. Turning now to slide 19 an update on our unconventional liquids activities. In the Bakken play our gross operated production recently hit its highest level ever surpassing 60,000 oil equivalent barrels per day. For the quarter the equivalent production increased by 74% over the prior year quarter. This strong growth reflects higher per well production rates due to optimized drilling and completion practices and the shift to more pad development. For example after writing 20% in 2012, peak 30 day flow rates had increased another 15% in 2013. We have also commenced evaluation of multiple ventures in the Three Forks Reservoir as part of a larger Bakken project involving XTO and our upstream research company. This initiative has a goal of increasing recovery, identifying further drilling and completion efficiencies and better defining resource size and distribution across our 580,000 net acres of leasehold. In June of 2013 we started operations at a new cryogenic gas processing plant in Southwestern Pennsylvania. Located in Butler County this 340 acre facility we’ll recover marketable liquid from Marcellus gas production. Two gas compressor stations feed the facility which is designed to treat approximately 125 million cubic feet per day of natural gas. More than 45 wells are expected to be contributing to production process at the plant by year end. In our Appalachian operations we hold nearly 700,000 prospective net acres across the Marcellus and the Utica Shale plays. The liquids rich Woodford Ardmore shale in South Central Oklahoma remains our most attractive and active unconventional play with 12 operated rigs. During the quarter we closed on a small bolt-on acquisition adding to our core Ardmore area and increasing our total acreage position to more than 280,000 acres. In the quarter gross operated production reached 31,000 oil equivalent barrels per day, up 73% over the prior year quarter. As noted in our March analyst meeting we are expanding the play into the overlying Caney shale. In the second quarter three Caney wells were completed and brought online, as we continue to delineate the reservoir across our acreage. Additionally our first Caney well is being completed in the Marietta area Southwest of the Ardmore Basin where the initial Wordford well in April 2012 had a 30 day peak flow rate of just over 700 barrels per day of oil and 1.4 million cubic feet per day of natural gas. Turning now to the Downstream chemical highlights and starting on Slide 20. We recently announced expansions to increase Group two premium lube basestock production capacity at our Baytown and Singapore Refineries. These expansion projects build on Exxon Mobil’s strong manufacturing base at these two world scale facilities. Exxon Mobil is the largest producer of basestock for use in lubricant manufacturing in the world and these projects will help us strengthen our position as one of the industry’s leading global suppliers of high quality lube basestocks. These expansions will employ Exxon Mobil proprietary technologies and increase production capacity of high value premium lube base stocks by 30%. Both projects are expected to start-up by early 2015. Turning now to Slide 21 on the Singapore Chemical Plant Expansion Project, during the quarter Exxon Mobil Chemical began producing ethylene from the facility’s second world scale steam cracker, more than doubling steam cracking capacity at the site and significantly increasing specialties capacity. We are now able to produce Exxon Mobil proprietary specialty elastomers and Metallocene based polyethylene in the Asia Pacific region. Integrated with the existing petrochemical plant and powered by a 375 megawatt co-generation plant the new steam cracker is among one of the most energy efficient in our portfolio. The Singapore Petrochemical Plant is well positioned to serve growth markets in Asia Pacific while leveraging our feedstock flexibility in dozens of new technologies. In conclusion, in the second quarter we earned $ 6.9 billion, generated 4 8 billion in cash flow, invested $10.2 billion in the business and distributed $6.8 billion to our shareholders. We maintain a long term perspective on our business with a relentless focus on operational excellence and disciplined investing through the business cycle. As discussed in the business highlights we continue to progress a unique set of profitable growth opportunities which position us well to deliver long term shareholder value. That concludes my prepared remarks and I will now be happy to take your questions.

Thank you. (Operator’s instructions). And we will take the first question from Faisal Khan with Citi. Please go ahead. Faisal Khan – Citi: If you could elaborate a little bit more on the refining downtime, I know you said that this is the most downtime you’ve had in the last five years. But I looked at the last two quarters in a row, throughput has been relatively lower versus kind of 4Q last year and 3Q last year. Can you discuss kind of how these plants are coming back online and how it is going to trend for the rest of the year?

Yeah, if you look across the year, the first quarter also had a high turnaround work load, so if you look at how we are doing this year, the first quarter was high but the second quarter was even higher. And certainly if you look prior to this year, over the last five years, it was considerably higher than normal. In fact about 9% of our capacity was offline for plant maintenance in the quarter and we typically averaged about 4% to 5%. Faisal Khan – Citi: Okay, and then going forward is this all these plants back up and running or are you still have a significant amount of downtime?

No, these activities is now behind us and by and large all those units are back on line and up and running. And the other thing I will mention, Faisal, is we have a long standing practice of implementing improvement projects, minor projects anytime we have these large facilities down for an extended time. And we are certainly taking advantage of that opportunity and we’ve done a few things at each of the sites to further improve the advantages that they have. Julia would be an example in the Midcon where we have done a few things to help improve our distillate production there. So big downtime all of it planned, all of it coming back up. And we are looking forward to the third quarter and getting these things again back up and running and producing product. Faisal Khan – Citi: Okay, then last question from me on U.S. upstream capital expenditure looks like it kicked up really significantly from the first quarter this year to about 2.6 billion. Can you tell what is going on in the U.S. CapEx and in the trend going forward are you ramping up your program in different areas or how is that progressing.

Yeah, we did see a little if you are looking at a quarter-over-quarter in the U.S. upstream CapEx was up a just a little bit. It wasn’t anything in particular. I can point to. We are doing, we have added some rigs, drilling activity is a little higher and just a number of other spend across the business. Faisal Khan – Citi: Okay, fair enough. I was looking from the first quarter to the second quarter it and looked like a big ramp up. Is that increased rig activity or is that – I thought you guys were cutting back on CapEx in North America, on the rig cap but that was one of the things that came out at the analyst meeting but maybe I am wrong?

Yeah I am sorry Faisal what you are looking sequentially we are up, we had a couple of minor XTO-based acquisitions. We added some more acreage in the Woodford that I mentioned and we had a couple of other items. Additionally drilling was up quarter-on-quarter sequentially by about $100 million. We did have also a net increase in rig activity by a couple of rigs. So it’s continuing the program of ramping up the production capability of the liquids and also taking advantage occasionally when we have an opportunity to bolt on a nice piece of acreage that fits in one of our big areas. Faisal Khan – Citi: It makes sense. Thanks for the time. I appreciate it.

All right, thank you.

Our next question will come from Ed Westwick with Credit Suisse. Please go ahead. Ed Westwick – Credit Suisse: Actually a follow-on from Faisal’s question. Good morning.

Good morning, Ed. Ed Westwick – Credit Suisse: Just on the, back in refining and chemicals. Do you think third quarter will be sort of fully clear or will you be fully back up sort of in the fourth quarter? Ed Westwick – Credit Suisse: We always have a little planned maintenance across the quarters and there will we some but if you look in across our major plans in the book of our maintenance and turnaround activity is behind us but we’ll always have a little bit, but particularly if you are really looking at the second quarter heading into the third quarter and the fourth quarter this year yeah there will be a much lower rate of maintenance activity. Ed Westwick – Credit Suisse: And you flagged Singapore startup cost, obviously a big plant. I mean any number that we could think about in terms of the sort of scale of that in the second quarter so that we can model it for the third quarter?

You know total OpEx in there was up a little bit. Singapore was an item but it’s not real significant in terms of order magnitude. So as we continue to ramp up a little bit you will see a little more there but nothing I would really signal out as being material. Ed Westwick – Credit Suisse: Okay then a general question on LNG. I mean obviously Canada is a big opportunity, Tanzania and the Golden Pass Exports, I mean do you think we’ll be talking about that at the analyst day next year with some granularity or you think it’s further off in the future?

I think as we typically do at the analyst meeting we’ll provide an update on all of those opportunities as they progress and hopefully by the end we can give you little more granularity in terms of expectations. But a number of things to look at and work on in the meantime. I think the good news for us is we have a number of potentially attractive large scale opportunities out there and we are assessing all of them and we look forward to talking about it more in March and of course particularly here in the U.S. we are dependent on getting the permit for non-free trade agreement countries to progress that project. But in the meantime as I mentioned in my remarks we are working on other permits and by the time we get to March we hope to be able to give you a good update on that. Ed Westwick – Credit Suisse: Thanks very much guys.

We’ll now go to Blake Fernandez with Howard Weil. Please go ahead. Blake Fernandez – Howard Weil: Hi, good morning David. Actually I want to stick on the Canadian LNG. It sounds like obviously we will get some more detail down the road but I had a general question for you with regard to the resource potential that you have to feed the facility, do you feel that you have adequate resources to feed it or would you rely somewhat on third-party gas, just any color there?

Yeah I think in general you know we have the resources available to feed that that doesn’t mean that we wouldn’t bring in some other but if you look across our resource base in Canada in particular the acreage that we got with the Celtic acquisition you look at the Horn River a number of other properties we have out there, we are pretty well positioned just internally to support a major LNG facility. And that’s why we are looking at it so hard but again it’s one of many projects but I think we are in pretty good shape. Blake Fernandez – Howard Weil: Okay, that’s great. Thanks. My second question is really on U.S. natural gas. It seems like the decline has slowed a little bit from what we witnessed in previous quarters and I am just curious if that’s a stabilization in activity levels or if some of the ramp-up you talked about with regard to Faisal’s question it may be and if that was in the gas window?

Well we do have obviously more drilling in these liquids rich plays. There is some gas obviously that comes out for that and that gets produced. And what’s you are generally seeing there is kind of the base decline rate that you have, particularly if you are looking sequentially across the quarters in the U.S. being offset by a little higher, higher production. So it’s really just the continuation of the program that we had in place. It does tend to stabilize. One of the things that’s interesting with some of these unconventional oils of these unconventional wells particularly on the gas side is you get all these tails that stack up and by and large that’s mitigating impact by itself. But we are also seeing very strong performance. I mentioned the Marcellus in particular but also in the Haynesville. So we’re tracking right along in general some of the things we talked about at the analyst meeting, in terms of well productivity, some of the benefits we’re getting from advanced completion technologies. You really starting to see that come into effect and in particular also on the liquid side. Whereas we talked about before we spent a lot of time after the XTO acquisition getting the Denbury trade dong a lot of delineation, a lot of appraisal working with the research folks on trying and improve our technologies. And now you are starting to see kind of the fruit of those efforts as we ramp things up. More pad drilling et cetera. So we talked about it before and I know you’ve been waiting to kind of see the results of Marietta at XTO capability, with Exxon Mobil’s technology and research. And I think we’re starting to see that come up and we look forward to continued production increases in those areas. Blake Fernandez – Howard Weil: I appreciate the color, David thank you.

Thank you.

And we’ll now go to Robert Kessler with TPH. Robert Kessler – Tudor, Pickering, Holt & Co.: Hi, David. Couple of questions if you don’t mind just to quantify some of the variance figures. One thing the Rosneft on that reimbursement amount paid to Rosneft for past exploratory costs and then the other one just quantification of the unfavorable price earnings effects and the downstream. I think you said there was part of 170 million sequential margin variance. But if you could just specify each of those in absolute terms?

Sure I’d be happy to. The Rosneft reimbursement of past costs was 220 million on an after tax basis. And if you look at the total price timing effects for the second quarter of 2013 they about 166 million in total, about 150 of that in the U.S. If you compare that to the first quarter we actually had a 32 positive. So if you are looking quarter-to-quarter sequentially in the U.S. that was about $183 million negative impact on a sequential basis. Robert Kessler – Tudor, Pickering, Holt & Co.: Very helpful. Thank you.

All right, thank you.

Next is Doug Leggate with Bank of America Merrill Lynch. Doug Leggate – Bank of America Merrill Lynch: Thank you. Good morning, David.

Good morning, Doug. Doug Leggate – Bank of America Merrill Lynch: David when we [travelled] this year you talked about [Rex] having a laser focus on efficiency gains, cost improvements and so on. If you look at the capture rate on your upstream margin this quarter, it doesn’t really seem to be a lot of movements. So I am wondering if you could share some of those initiatives on what our expectations should be coming out of that? And I got a follow up please.

Sure. I think what I said was a little more broadly we had a laser focus on unit profitability. As we talked about at the analyst meeting where we acknowledged the fall back we’ve had in the upstream unit profitability, given the mix of our production since the XTO acquisition and just reinforcing that we are very aware of this. We’re working on it. Some of the portfolio projects that are coming online and particularly the liquids project are coming to fruition. We’ve talked about the mix impact we’re going to have over the next two or three years as all those liquids and liquids-linked projects come on. So there is not a specific OpEx program or something like that it’s top to bottom, it’s production, it’s margin capture, it’s bringing the projects online see any improvement in the earnings but also I will say as we always have, continued focus on operational excellence and cost management. So that’s ongoing. But it’s not anyone particular program. I will say if you take out the Rosneft seismic reimbursement and look at some of our unconventional liquid increases sequentially across the quarter and how things are trending. I think you’re going to see that upturn on a cost on a price constant basis here as we go forward. Doug Leggate – Bank of America Merrill Lynch: Thank you for that. My follow up I am afraid is the buybacks. I really just want to take frame this but oil prices were obviously lot stronger both domestically and internationally. You are targeting production goals with 90% weighted towards liquids and you had obviously a big one off working capital shift in the second quarter. So with that backdrop I know you don’t like to talk about the longer term outlook for buybacks. But conceptually why would you be pulling back on your buyback program given that backdrop and what is your tolerance for net debt and the balance sheet and I’ll leave it there?

Sure, let me add a little bit to your backdrop comments, because they are all quite valid to me. Let me add just a little of perspective on the buyback. If you look back over the past two years, so you look at 2011 and 2013 we bought back $20 billion in each of those two years in share buybacks. We also had over that, so $40 billion let’s call it for the two years combined. Over that same time period we had about $20 billion in debt proceeds from asset sales, so about 10 a year. So if you put those two together and you think about it we bought back $20 billion a year. 10 of it sourced from our operating activities and 10 sourced from proceeds from asset sale. Then if you come into 2013 and look at the first half we bought about $9 billion of shares back, have less than a $1 billion in proceeds from asset sales. So on equivalent basis we’ve already bought back a little over $8 billion in share buybacks, excluding the proceeds from asset sales. So if you look at it from that perspective the buyback actually remains quite strong. There is nothing magical about the $3 billion number for the third quarter other than we’ve just take look at like we always do expect the cash flows for the quarter, our needs, cash requirements and that sort of thing. And just came up with the $3 billion number. We’re also managing our capital structure this year and keeping that in line with our longer term objectives. But not any more complicated than that. Again I think sometimes people overlook the fact that asset management program that we had that last couple of years generated a significant amount of cash for us. And we returned all of that to the shareholder which I thought was very positive. So I hope that answers your question, if not I’d be happy to talk about it in little more detail.

We’ll go now to Evan Calio with Morgan Stanley. Evan Calio – Morgan Stanley: Hi. Good morning, David. I’ll look forward to the point assistants next time the call begins as well.

I’ll look into that. Evan Calio – Morgan Stanley: My first question on PNG. I mean it’s clearly a differentiated position for Exxon I know you discussed your negotiations required additional supply and you picked up some exploration acreage in the quarter. But could you discuss how additional expansion trend compared within your portfolio versus other projects that I know you have reviewed globally. And additionally with train one and two were I think in their five years from FID to expected first gas. I would presume expansion trains could be much faster than that. And based upon the availability of gas does Exxon envision replicating a (inaudible) style development here of a train per type of a concept. I have a follow-up.

Yeah, let me kind of start at the back of your question first. Clearly as would be true of your project once you’ve got all the facilities in play the pipelines the capacity the trains the utilities all the common facilities any addition is typically going to be quicker and have quite attractive incremental economics. So I wouldn’t want give a specific time frame on an additional train at Papua New Guinea beginning other than they say we have plenty of land space there, we have plenty of infrastructure. So we certainly have the ability to as rapidly as possible expand that facility over the course of the next few years and we do have a number of opportunities for gas we mentioned the [Interoil] discussions are going on we have had some success in exploration recently in Pingyang South and we have got some other exploration opportunities in the area. So we are optimistic on that. In terms of relative economics of Papua New Guinea versus other projects I wouldn’t want to give any specific comparisons or numbers other than to say we do view that project as quite attractive for us and we certainly look forward to bringing forward some expansion opportunities and continuing to improve further on those economics. Evan Calio – Morgan Stanley: Great that’s helpful and my second question if I can follow up on the buyback I mean that’s gone from five to four to three on a guidance basis with limited free cash flow in 3Q even if we see CapEx flat to down in 2014 we see some continued pressure on that buyback. So really the question is going to reiterate Doug’s question would you consider using the balance sheet or larger than normal asset sales to support the buyback going forward which is also historically supported your very high returns.

One of the things to keep in mind as we go forward particularly as you look into 2014 and you get kind of the ramp up in production and particularly liquids production that we showed you in the analyst meeting, at current prices, you could certainly expect increased cash flow right from operations. So I think as that goes up and remember most of these assets, these projects that we are bringing online in the next few year have two things. One they are either oil-based or oil linked gas and they are no decline kind of projects. So the CapEx requirement on a maintenance basis will be much lower than your typical oil projects and in the free cash flow generation out of that and the earnings impact were basically 90% of that increment tied to liquids. So you have to keep that in mind. When you think about, I guess the other one was using the balance sheet to buy shares. We manage the balance sheet really around to the whole capital structure that we want to manage and you have seen some increase in our debt levels here over the year. You might recall back three years ago after the XTO merger we had about $19 billion of debt on the books. We paid, most of that off over the ensuing years, got rid of that high cost debt. We have replaced that with low cost commercial paper. So we do continue to manage the balance sheet, manage the capital structure of firm but also always maintaining that balance sheet flexibility that we have talked about. So I wouldn’t make any specific guidance on use of leverage or the buyback going forward, other than to say we continue to focus on cash flow generation and returning as much of that cash flow back to the shareholders as possible in the form of both increasing dividends which we did again this year and the buybacks. Evan Calio – Morgan Stanley: Okay that’s helpful. And one last one if I could I missed it. On chemicals in the quarter were there any impacts of outages there particularly in the U.S. I think volumes were lower.

Yeah we did have some planned maintenance but it was kind of minimum in terms of the impact in the U.S. Yeah one of the things we did see in the U.S. that was helpful was some increased polyethylene demand and that kind of helped our mix but we did have some downtime in a couple of areas but nothing real significant. Evan Calio – Morgan Stanley: Got it. Appreciate it.

Thank you.

John – with Society Generale is next. John Hurling – Societe Generale: Yeah hi. Two quick ones Dave. With respect to the Bakken you said you were going to combine your [exploitation] as to XTO folks with your technical people should we expect to see more of an activity ramp given the potential of Three Folks in the Williston?

Yeah I think it would be logical to assume overtime as we continue to develop that resource, particularly taking this kind of full field development approach that you would see us ramp-up activity overtime. I have to say and I kind of alluded to it in my opening comments we are really pleased with the progress we are making in Bakken. Again it’s pad drilling, it’s optimized completions, it’s change in the way some things are done, incorporating the learnings as we go along. One of the things we talked a little bit about is not yet in a hurry, you don’t want to drill a bunch of wells and then look back over your shoulder and wish you hadn’t done that quite yet because you have learned a bunch. So I think we have a pretty deliberate discipline pace of growth in both activity and production but the gains that we are seeing year-over-year, we would like to continue and do more and not yet too far out in front of that curve. John Hurling – Societe Generale: Okay, thanks. Next one from me is on the Tidal Oil pilot project with Rosneft. How long we will be in the science phase, next or so?

I think with unconventional resources in general we are going to be in science phase for a while. You know I think if you look at the West Siberia area tremendous opportunity for that joint-venture with us and Rosneft. We are in the process right now of gathering data but testing will begin this year. So that activity will startup before the end of the year depending on how that goes. That will determine the pace heading into next year but as we have done in all the other conventional we will prudent making sure we know what we have testing the resource itself, the quality of what we find underground and then looking for that commerciality determination but the area has plenty of infrastructure, plenty of support so if we can make it work we will get after it pretty quick. John Hurling – Societe Generale: Okay. Last one from me is Maui deepwater, can you give us any more information on that?

Yeah, Maui is drilling ahead. We have not reached the target depth yet so because of that you know I really wouldn’t want to say much more. Obviously in the next quarter we will have more to say on that. But the drilling is going fine as expected and we look forward to providing a little more update next time. John Hurling – Societe Generale: All right, thank you.

Hey, thank you Doug.

Next is Paul Sankey with Deutsche Bank. Paul Sankey – Deutsche Bank: Hi, good morning David.

Good morning, Paul. Paul Sankey – Deutsche Bank: David with respect to [inaudible] on this net income to barrel marginal barrel profitability can we just – sorry to do this but can we go back to this Rosneft deal first. If I look at the earnings year-over-year the variance in the other category was 2.07 billion. I think you said it was 220 million of that was Rosneft, is that correct?

Yeah that’s correct. Paul Sankey – Deutsche Bank: What’s the rest?

It’s very simple. All of the rest is the absence of asset sales from last year. We sold our Block 31 in Angola, we booked some of the Japan in there, we have some other minor sales but that 2.1 billion it’s 1.9 asset sales and 200 million for other reimbursement of past cost. Paul Sankey – Deutsche Bank: Got you. I mean I think generally speaking because we are as focused as Rex is on this issue it’s the more detail we can get on this [sort of noise] the better that would explain why the sequential earnings were down only 70 million in other would include the 220 of Rosneft, right?

Yeah, that’s correct. Paul Sankey – Deutsche Bank: So then there is obviously you know whatever it is 100 or something offset positive.

Yes. Paul, it’s a number of small items, nothing really big to point out but yeah I think the important thing there is just what you have noticed. It’s pretty clean on the other where you down all the factors in particularly given that we had a negative 200 million in there for the Rosneft cost. Paul Sankey – Deutsche Bank: Yeah, understood. The proceeds from the after-sales you also mentioned that you made a couple of acquisitions. Can we get some more detail on what the scale although you got 3 million of proceeds? I guess the acquisitions were in CapEx, right?

Yeah the acquisitions are in CapEx. I think all in less than a $100 million. I mean it wasn’t significant in the quarter. There were some small bolt-on. Paul Sankey – Deutsche Bank: That was the acquisitions. What were the sales upstream? Sorry, I missed that. Excuse me.

The sales that we had, we had some minor ones in the upstream just some minor ones there. Paul Sankey – Deutsche Bank: It was upstream.

Yeah, it was just a little bit of stuff there. Again net-net kind of there wasn’t a big deal. Paul Sankey – Deutsche Bank: And I think you quite deliberately reiterated your guidance as given at the analyst meetings for, I think it was for full year ‘12 is that what you referred to?

Yeah, I just wanted to reinforce two things for you, the volume outlook is unchanged and the CapEx outlook is also unchanged. Paul Sankey – Deutsche Bank: Okay, great, I have got a kind of a detail one which is unfortunate but then if you could extend into the overall North America picture, can you update us on the status and future for the Pegasus pipeline and then can you also talk about how you are going to move crude out of Canada down into major refining centers on the Gulf Coast, thank you.

Yeah, let me hit the second one first. We have the ability if you are really referring to Kearl we have got the pipeline capacity in place for 10,000 barrels per day to move that either into the U.S., some of that into Julia and also into our other Canadian refineries. If you are looking in general Western Canada crude down into the west coast we have made some other arrangements to offset, what was coming down Pegasus. So that really hasn’t had a big impact on us, on a net basis. If you look at the Pegasus pipeline incident, kind of broadly, I will tell you that the clean-up of that is going very well. We have removed all visible free standing oil from the environment. Many of the folks that were evacuated from their homes have completed re-entry process. So that’s going well. In terms of starting up that pipeline, you know, I really couldn’t give you an estimate on that or an outlook. We still got some more work to do to determine the details of the investigation around that incident and what caused it and that sort of thing. So until we have got that completely nailed down and can, you know, think about that over the rest of the line, I just can’t give you any update when that is going to be back in service. Paul Sankey – Deutsche Bank: Okay, so it is obviously now I think the interesting thing is, if I could say I believe it was built in 1940 that pipeline, right?

Yes, yes. Paul Sankey – Deutsche Bank: David, I look forward to seeing you in September, thank you.

All right, thank you.

Next is Paul Cheng with Barclays. Paul Cheng – Barclays: Hey, guys, good morning.

Good morning, Paul. Paul Cheng – Barclays: Two questions, David. In the second quarter, is there any one-off or some more unusual tax adjustment or inventory gain on those in any of your division that we should be aware?

No, Paul this is actually a pretty clean quarter along those lines. Paul Cheng – Barclays: Secondly, that Dave, I think you talked about the success story that you guys have in the Woodford and also in some of the unconventional play like Bakken. Can you give us a rough idea that how much is the total unconventional liquid production today that you are running at net to the company and also within that the percentage between the split oil, condensate and NGL?

Paul, I don’t have the breakdown of unconventional liquids relative to conventional, certainly what we are seeing, if you look at how we are doing particularly sequentially in the U.S. where I think our liquid production are basically quarter over quarter our liquid production flat, what you are seeing is unconventional increase in liquid production is offsetting declines. And so you’ve got you normal decline on the conventional being offset by the unconventional. But I don’t have those two numbers. Paul Cheng – Barclays: Is that something that you guys will be willing to share and we could take it offline now or you could have someone to shooting me an email.

I think those kind of details will probably hold for a broader update in our analysts meeting in March. I think the important thing for us is this ramp up that we are seeing and the year- over-year increase that I have mentioned in my prepared remarks and again in particular the ability to grow these volumes at a lower capital cost as time goes on and a lower OpEx but I do understand your question. And I would look for an opportunity down the road to be a little bit more specific on that. Paul Cheng – Barclays: And on the unconventional liquid, are your guys operating cost per unit or per barrel are they higher or about the same or lower than your average portfolio in the U.S.?

I don’t know that I have that specific number in terms of coming up with conventional average cost versus an unconventional. Again Paul I think the important thing for us is to continue to ramp down those Op costs ramp up the well productivity as we depend on those unconventional liquids to offset the decline in the conventional. So I don’t have a split out in the cost for you along those lines but again as this portfolio goes forward you will see an increasing amount in unconventional liquids offsetting and then growing more than the decline on the unconventional. But we’ll also look for opportunity at the next analyst meeting to talk about that a little more as these volumes come up. Paul Cheng – Barclays: All right. Thank you.

We’ll now go to Allen Good with Morningstar. Allen Good – Morningstar: Good morning, David.

Good morning, Allen. Allen Good – Morningstar: Just a follow up question on your commentary related to the asset sales reporting, share repurchases in the past. First of all if there any current marketing of assets now that will be significant to potentially support the repurchases later this year and next? And then secondly on that point when you evaluate aftersales or the future potential of assets do you expect the returns on those future of those assets in the future relative to what you could potentially get on returns on buying your own stock and the valuation of your own stock so as the repurchase of – or use of proceeds factors into whether you decide to sell an asset or not?

Let me answer that second one. First those are two completely separate decisions. The decision to sell assets is sometimes it’s strategic, like our decision to get out of owned and operated retail stores in the U.S. which also ties into the other part of asset sales which is they are worth more to somebody than they are to us and so often times when we look at something that looks like a strategic benefit for us it turns out that it marries up quite with an economic advantage for someone else. When you look across our other assets either an upstream, downstream or chemicals it’s a very simple analysis. What this things worth to us looking at both upside potential and downside potential and then how does that compare to the value, to a potential purchaser and when the latter is greater than the former generally speaking we’ll conclude an asset sale and a lot of those sales are opportunistic, where people approach us asking to buy assets. So we don’t have a program. We don’t have a target or an objective where they come along and they are attractive we go ahead and do it. And that kind of leads into – I really can’t comment on future sales because as I said so many of those come about because we get approached by people and don’t have any way to look at that. But I will say we did see a very successful program over the last couple of years and again as I mentioned earlier that cash flowed directly to our shareholders. But what we might do next quarter, next quarter or next year I just, I don’t know and couldn’t comment on. Allen Good – Morningstar: Okay. Thanks. And my second question relates to the factors that you outlined as far as [direction] relative to tracking of LNG project with respect to Australia and I understand you are going to pursue FLNG down there and the development of Scarborough. Is anything else beside that potential with respect to regulatory or capital cost in Australia that had may be abated in the past call six months to a year that made that project a bit more attractive than it maybe was a year or two ago relative to the rest of your portfolio?

We haven’t seen a big change in terms of the cost structure. We are evaluating the potential of FLNG at the Scarborough prospect and those evaluations continue but again I would want a position that relative to any other project either already in the portfolio or one that we’re looking at. Again it’s nice to have the wide geographic flexibility we have and the opportunity set for LNG. So you got a lot of things in play as I mentioned fiscal term stability, capital cost in particular areas, infrastructure and that sort of thing, as well as the market of those things which serve. So as we bring along this portfolio and evaluate it we’ll be looking at different technologies FLNG is an example of that. Also different sizes the facilities and different locations and that sort of things. So we’ll continue to progress that but don’t have an outlook for FID and cost or any of those or certainly not relative competitiveness. Allen Good – Morningstar: Okay, thanks. And just one quick one. I am sorry if I missed it. But on Asian gas volumes in the quarter was there a reason whether it be PSC or turnaround effect for the decline that’s sequentially there?

If you’re looking sequentially we had some downtime was a big piece of that. And then there also some price and spend impact on entitlements in the gas area there. But nothing outside of that unknown there. Allen Good – Morningstar: Thank you very much.

All right. Thank you.

And we go to Pablo Mockonoff with Raymond James. Pablo Mockonoff – Raymond James: Thanks for taking my question. First just a quick one on PNG, LNG any sense of when you’re looking to make a decision project extension on [inaudible]?

No, I really don’t have an outlook on that. We’re still in the commercial discussion on the potential for expansion. So until those concluded it would be difficult to give any forward guidance on timing after that. Other than we’re working on it and if those negotiations are successfully concluded we’ll be in a better position to talk about the going forward timeframe. Pablo Mockonoff – Raymond James: Okay. And then segment from me we’ve seen a number of large western players getting into the Vaca Muerta in Argentina in a pretty big way. Can we just get an update on where things stand with your JVs down there with I guess it’s America’s Petrogas.

Sure, I think as you’re probably aware we’ve got a huge position in the Vaca Muerta. We were kind of early mover into that area. We’ve got a 11 blocks totaling over 800,000 net acres in the Neuquén Basin. And of course we’re targeting the potential of the Vaca Muerta. We did have number of wells that we drilled last year and into this year. Some of those are on test. And others are being completed and we will be testing going forward. We do have a fairly active operated plan for the balance of this year and we’ll get a few more wells down there over the course of the year. The real key there is to kind of figure out where the windows are for the liquid versus the gas figure out what you got how it looks and not drill more wells then you need to define that resource. So we’re pleased. The early results are encouraging and we continue to progress and like I mentioned minute ago we’re looking forward to drilling our operated wells the rest of this year and give you a little better update as we progress. Pablo Mockonoff – Raymond James: Right, appreciate it very much.

We go now to Iain Reid with Jefferies. Iain Reid – Jefferies & Co.: Hi, David. How are you?

I am good Ian. How are you? Iain Reid – Jefferies & Co.: I am doing very well. Got a few things. Firstly on just coming back share buyback. Just wondering when you look at share buybacks and dividends. Do you kind of look at those together, because you’re ramping down the share buyback at the same time you increased dividends payments fairly significantly. So do you look at that as kind of total shareholder return number? I know you’re moving if you’re like more towards dividends rather than share buybacks consciously or is it more about this disposal impact you were talking about earlier?

Let me talk about the dividends first. I think the most important thing to think about the dividend is we have a track record and certainly talked about on a go forward basis the objective of always growing that dividend overtime. The rate at which we’ve grown that dividend over the last several years has varied a little bit although if you average it out over the last five or ten years it’s been substantial. We did take a 20% hike in the dividend in 2012 and other 10% almost 11% this year. And I think as we talked about it in the analyst meeting that was to, in response to both desires of our shareholders and also to remain competitive in the marketplace. So if you just hold that aside on the dividend than you get to the buyback and the buyback is of course driven by cash flow that’s available to give back to the shareholder. And buybacks give us great flexibility in terms of managing cash and capital structure. And so I wouldn’t combine that with the dividend. They’re separate and managed in that manner. I think as you look back over the last few years at the sheer level of total distributions to the shareholders they have been quite impressive and again we have grown the dividend to meet those needs and then the rest of the cash has gone back in the form of the buybacks. Iain Reid – Jefferies & Co.: Okay. second one is I was curious about this what you are talking about in terms of refining capacity being significantly down in the because if you look at it on a sequential basis it is down but not significantly compared to the first quarter. So is there anything else in these refining numbers which could explain the kind of really weak performance other than just the cost of what you are doing and also the downtime you are talking about?

Sure a big piece of the actually impact on earnings really comes from the fact that a lot of the refineries were down or some of our higher margin refineries for example our Julia refinery in the Midwest was down for two full months and that’s without giving a specific number I can tell you that’s a big chunk of what you are seeing in that earnings number. So it’s not the just the amount of throughput or the amount of value that was lost but the mix of those refineries as well. Iain Reid – Jefferies & Co.: And last one just on tax rates if you don’t mind, your tax rate kicked up fairly substantially in this quarter compared to second quarter of last year is that a purely mix effect or some of your competitors have being talking about the impact of the stronger dollar on deferred tax balances. So is this something we might see kind of maintain, at elevated rates if the dollar remain strong or is it something you would expect to reverse with refinery becoming little bit more profitable?

Yeah let me hit that, if you are looking for example the last year’s second quarter and this year’s second quarter the biggest impact of that there is the difference the tax rate on earnings and some of divestments and restructurings that we have. Aside from that if you are looking sequentially this year it is purely the mix effect where we are making our money upstream versus downstream U.S. non-U.S., so a geography there and you saw the results much different in terms of the downstream quarter-on-quarter. I don’t think foreign exchange rates are having an effect on us and going forward I don’t have a specific number for you but if you kind of look back over the last several quarters and take out the impact of the big restructuring divestment we have kind of been in that kind of mid to upper 40s range. And so again, I don’t have a specific outlook for you but if you take away a couple of those anomalies that’s kind of where we have been. Iain Reid – Jefferies & Co.: All right, David that’s very kind. Thanks very much.

Thank you.

And we will take our last question from Faisal Khan with Citi. Please go ahead. Faisal Khan – Citi: Thanks David. Just have a follow up. Could you just [stress] how are you dealing with this [REMS] issue in the U.S. for refining and downstream where you guys fairly balanced or you do that more blending capacity that you gasoline production capacity and how retail and marketing sort of help mitigate some of that?

The answer to that is yes, we are a net purchaser of [REMS] but I will tell you we are pretty well balance we do generate the majority of our credit by blending our biofuels directly. So while it is an impact on us it’s not real significant I think the more broader issue is that arena is really the RFS mandate and approaching hitting the blend wall next year from an industry perspective and it’s not going to be matter of [REMS] pricing but just the fact that the [REMS] will be come in sufficient and compliance with the RFS mandate is just going to be infeasible. So [REMS] are an issue it’s topic but the more broader issue going forward is going to be the RFS mandate heading into 2014. Faisal Khan – Citi: Okay. So just a comparable I am looking at your results for the quarter I shouldn’t see any sort of material impact from Faisal [REMS] in the quarter?

No not at all. Faisal Khan – Citi: Okay great. Thanks.

And that does conclude our quarter and answer session for today I would like to turn it back to David Rosenthal for any additional or closing remarks.

Thank you. I just want to thank everybody for time and questions today. We appreciate you being with us on the call and look forward to visiting with you next quarter. So thank you very much.

And thank you for your remarks. That does conclude our conference for today. Thank you for your participation for today. And you may disconnect.