David S. Rosenthal – Vice President, Investor Relations

Douglas T. Terreson – International Strategy & Investment Group, Inc. Ed G. Westlake – Credit Suisse Securities Doug Leggate – Bank of America/Merrill Lynch Evan Calio – Morgan Stanley Paul Y. Cheng – Barclays Capital Blake Fernandez – Howard Weil Inc. Faisel Khan – Citigroup Pavel Molchanov – Raymond James & Associates John Herrlin – Societe Generale Iain Reid – Jefferies & Co. Paul Sankey – Deutsche Bank Allen Good – Morningstar

Good day, and welcome to this Exxon Mobil Corporation’s Second Quarter 2012 Earnings Conference Call. As a reminder, today’s conference is being recorded. At this time, for opening remarks, I would like to turn the call over to the Vice President of Investor Relations and Secretary, Mr. David Rosenthal. Please go ahead, sir. David S. Rosenthal: 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 2012. 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 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 growth slowed in the second quarter, primarily due to continued weakness in European Union. The U.S. and Japanese economies are also expected to show declines from first quarter levels. China growth, while still robust, continues to weaken than prior year levels. Energy markets were mixed in the second quarter, with lower crude oil and natural gas prices while industry refining margins increased from the first quarter. Although U.S. chemical margins remained strong, Europe and Asia commodity margins continued at near bottom-of-cycle conditions. Turning now to the second quarter financial results as shown on Slide 4. Exxon Mobil's second quarter 2012 earnings were $15.9 billion, an increase of $5.2 billion from the second quarter of 2011. Second quarter earnings included a net impact of $7.5 billion associated with divestments and one-time tax related item. Earnings per share for the quarter were $3.41, up a $1.23 from a year ago. The corporation distributed $7.7 billion to shareholders in the second quarter through dividends and share purchases to reduce shares outstanding, of that total $5 billion was distributed to purchase shares. Share purchases to reduce shares outstanding are expected to be $5 billion in the third quarter of 2012. CapEx in the second quarter was $9.3 billion, down 9% from the second quarter of 2011 primarily due to the absence of acquisitions made in the second quarter of last year. Our cash generation remained strong with $13.9 billion in cash flow from operations and asset sales. At the end of the second quarter 2012, cash totaled $18 billion and debt was $15.6 billion. The next slide provides additional detail on second quarter sources and uses of fund. Over the quarter, cash decreased from $19.1 billion to $18 billion. The combined impact of strong earnings, depreciation expense, working capital and the benefit of our ongoing asset management program, yielded $13.9 billion of cash flow from operations and asset sales. The $9.6 billion in working capital and other primarily reflects eliminations or gains on asset sales, increased working capital and tax items. Uses included additions to plant, property and equipment or PP&E of $8.3 billion and shareholder distributions of $7.7 billion. Additional financing and investing activities increased our cash by $1 billion. Moving on to slide six and the review of our segmented results. Exxon Mobil’s second quarter 2012 earnings of $15.9 billion, increased $5.2 billion or 49% from the second quarter of 2011, primarily due to gains from asset sales partly offset by one-time tax item. Upstream earnings decreased to $183 million, while downstream earnings improved by $5.3 billion. Chemical earnings were up $128 million, and corporate and financing expenses were flat. Corporate and financing expenses remain within our continued guidance of $500 million to $700 million for quarter. As shown on slide seven, Exxon Mobil’s second quarter 2012 earnings increased by $6.5 billion compared with the first quarter of 2012. Moving next to second quarter business highlights and beginning on slide eight. We continue to advance our global portfolio of high quality upstream projects. In Angola, the Kizomba Satellites Phase 1 project achieved first oil in May ahead of schedule. The initial phase has a peak production capacity of 100,000 gross barrels of oil per day, and will cover a total of approximately 250 million barrels from the Mavacola and Clochas fields. The development is located 95 miles of the coast of Angola and water depths of approximately 4,500 feet. Phase 1 of the project includes 18 wells with subsea tiebacks to the existing Kizomba A&B floating production, storage and offloading vessels, thus optimizing the capabilities of on block facilities to increase current production levels without requiring an additional FPSO vessel. In Nigeria, we completed the installation of three well head platforms as part of the Nigeria Satellite project. These are the first offshore platform structures to be fully constructed in Nigeria. The project is on schedule to start-up in late 2012 with peak capacity of 70,000 gross barrels per day. We also completed the installation of the Arkutun-Dagi gravity-based structure, offshore Saklan Island in Russia. We are currently progressing pipeline tie in with topside installation scheduled for 2013. The project will have a peak production capacity of 90,000 gross barrels per day and is on schedule to start up in 2014. Construction is also progressing at the Papua New Guinea LNG project which remains on schedule for 2014 start up. The entire 250 mile offshore pipeline has been installed, and over 105 miles or approximately 60% of the onshore portion of the main gas pipeline have been welded. At the LNG plant, pipe wrecks and heavy equipment are being installed on the process strength and piling on the jetty is complete. Additionally, mobilization and commissioning of the first two new drill rigs was ongoing during the quarter. The second rig is being mobilized to hide, with drilling expected to begin later this year. Also during the quarter, two rigs began drilling in Hadrian North in the Gulf of Mexico to further appraise the resource. The results from these wells will be incorporated into the overall development plan. And finally, the Kearl Initial Development project is now 94% complete. All modules have been transported from the United States and integration of the modules into the plant facilities is progressing. The project is on schedule to start up later this year. And turning now to Slide 9, we continue to make progress on our strategic cooperation agreement with Rosneft. In June, we signed agreements with Rosneft to jointly develop tight oil reserves in Western Siberia and establish an Arctic Research Center for offshore development. This agreement combines the strengths of our two companies, Exxon Mobil’s technology leadership in tight oil and unconventional resource development and Rosneft’s direct knowledge and experience of Western Siberia’s geology and conventional production. In the near future, we will develop a work program for selected Rosneft license blocks which will include geological studies and drilling with drilling planned as early as next year. A pilot program will be established to determine the technical feasibility of developing these reserves. The Arctic Research Center will provide a full range of services to support all stages of our joint venture oil and gas development on the Arctic shelf, including ice monitoring and management, logistics, and the design of ice resistant offshore vessels, structures and Arctic pipelines. Safety standards will be a priority for the center, which will have its own special marine incident warning and prevention center. In addition, we progress joint exploration activities in the Black Sea where seismic acquisition is now complete. We remain on schedule to commence seismic acquisition in the Kara Sea later this year. Exploration drilling is expected to being in 2014-2015 timeframe, as soon as prospect mapping is complete and a rig is contracted. Turning now to conventional exploration on slide 10; in the quarter, we achieved continued success in our conventional exploration portfolio. In Tanzania, we drilled a second exploration well with our partner Statoil. As indicated by the operator, this well has confirmed the discovery of approximately 2 trillion cubic feet of recoverable gas. This follows our first exploration well on the block, which discovered approximately 5 trillion cubic feet of recoverable gas. We also made a gas discovery on acreage in North Western Papua New Guinea, and have commenced drilling of a second well in the Highlands. This exploration activity is designed to support expansion studies for a third train at our Papua New Guinea LNG project. Also during the quarter, we drilled our third well in Vietnam which encountered additional gas. Results from this well are being evaluated. In light of the encouraging results in Romania, planning for further exploration activity is underway. We expect to begin acquisition of a new 3D survey on the Neptune license by year end. And finally, we were high bidder on 22 blocks in the recent Central U.S. Gulf of Mexico lease sale. Moving on to slide 11, we continue to advance our growing portfolio of high potential unconventional assets in liquid rich plays like the Bakken, the Woodford Ardmore and the Neuquen Basin in Argentina. In the Bakken, we have moved into a development phase across our roughly 400,000 net acre leasehold. In the first half of 2012, we turned 40 wells to sales, nearly double the pace of 2011. In the second quarter of 2012, our gross operated Bakken production increased by 60% over the prior year quarter. Since our entry into the play, we have more than doubled gross operative production to approximately 32,000 oil equivalent barrels per day. In the Woodford Shale and the Ardmore Basin, we completed a strategic bolt-on acquisition adding 58,000 acres of leasehold and just over 4,000 oil equivalent barrels per day of production. This brings our total Woodford Ardmore acreage to approximately 260,000 net acres and expands our resource potential beyond the 600 million oil equivalent barrels previously estimated. In the second quarter, we utilized 10 rigs to delineate our acreage, to evaluate optimal well spacing and continue development activity. : Turning out to slide 12, on the North American chemical growth project, during the quarter, Exxon Mobil Chemical filed permit applications to progress plans for a world scale, petrochemical expansion that our integrated Baytown, Texas complex. The project includes a new ethane cracker with up to 1.5 million tons per annum on ethylene capacity, which will see two new 650,000 tons per year premium polyethylene lines situated at the nearby Mont Belvieu plastics plant. The proposed expansion capitalizes on the abundant and growing supply of North America natural gas liquids to economically supply the rapidly growing global demand for high performance polyethylene products. These metallocene based premium resins deliver sustainability benefits such as lighter packaging weight, lower energy consumption, and reduced emissions. Required government reviews and approvals are expected to take about a year after which Exxon Mobil will make a final investment decision. If progressed, a 2016 start-up would be anticipated. Turning now to the Saudi Elastomers project on slide 13, during the quarter, the KEMYA 50-50 joint venture partners Saudi Basic Industries Corporation and Exxon Mobil announced the decision to proceed with construction of the specialty elastomers project at Al-Jubail, Saudi Arabia. This continues a long history of Exxon Mobil investment in the Kingdom and represents a significant broadening of KEMYA’s product portfolio. The facility will have the capacity to produce up to 400,000 tons per year of specialty products including synthetic rubber, thermoplastic specialty polymers and carbon black to serve local markets, the Middle East and Asia. Project completion is expected in 2015. Turning now to the upstream financial and operating results and starting on slide 14, upstream earnings in the second quarter were $8.4 billion, down $183 million from the second quarter of 2011. Realization has decreased earnings by $870 million due primarily to lower crude oil and U.S. natural gas realizations, which declined by more than $8 per barrel and $2 per thousand cubic feet respectively. Production mix and volume effects negatively impacted earnings by $330 million, due mainly to the impact of lower entitlement volumes, base decline and divestments, partly offset by the ramp-up of Nigeria and Angola projects. All other items are nearly gains from asset divestments and lower exploration expense, partly offset by one-time tax items and higher production operating expenses increased earnings by $1 billion. Upstream after-tax earnings per barrel for the second quarter of 2012 were $22.12. Moving to Slide 15, oil equivalent volumes decreased by 5.6% from the second quarter of last year, mainly due to the impact of lower entitlement volumes, decline and divestments. Volumes were positively impacted by the ramp up of projects in Nigeria and Angola and less downtime. Excluding the impacts of entitlement volumes, OPEC quota effects and divestments, production was essentially flat. Turning now to the sequential comparison and starting it on Slide 16. Upstream earnings increased by $556 million versus the first quarter of 2012. Lower crude oil and natural gas realizations negatively impacted earnings by more than $700 million, as crude oil realizations decreased by more than $10 per barrel and average gas realizations decreased by $0.60 per thousand cubic feet. Production mix and volume effects decreased earnings by $480 million due to a decline and seasonal gas demand in Europe, base decline and lower entitlement volumes, partly offset by the ramp up of projects in Nigeria and Angola. Other items, including gains from asset divestments, lower exploration expense and favorable Forex, partly offset by one-time tax items, increased earnings by $1.8 billion. Moving now to Slide 17, oil equivalent volumes were down 8.8% from the first quarter of 2012 resulting from a decrease in seasonal gas demand in Europe, base declined on lower entitlement volumes, partly offset by the ramp up of projects in Nigeria and Angola. Excluding the impacts of entitlement volumes, OPEC quota effects and divestments, production was down 7.6%. Year-to-date, oil equivalent volumes decreased 5.5% compared to the first six months of 2011. First half 2012 volumes associated with the 3% full-year decline outlook, provided at the Analyst Meeting in March are shown on Slide 18. Operational performance was slightly ahead of plan, benefitting from the early startup of the Nigeria Usan and Angola Satellites projects and strong base performance. First half 2012 prices most notably in February through April were higher than our March Analyst Meeting outlook basis of $111, and negatively affected first half volumes due to both permanent and price related entitlements. In the second half of 2012, successful startup of several projects and continued strong base performance will support our 2012 volumes. Moving now to the downstream, financial, and operating results and starting on slide 19. Downstream earnings in the second quarter were $6.6 billion, up $5.3 billion from the second quarter of 2011. The driver for the increase was a $5.3 billion gain associated with the Japan restructuring, which was completed on June 1. This gain was partly offset by unfavorable Forex effects, one-time tax items, and increased maintenance activities. Improved refining margins, mainly in the U.S. and Europe increased earnings by $650 million. Moving to slide 20. sequentially, second quarter downstream earnings increased by $5.1 billion, primarily due to the Japan restructuring and improved refining margins partly offset by Forex effects, increased refinery maintenance and one-time tax items and the absence of first quarter gain on asset sales. Turning now to the chemical, financial, and operating results starting on slide 21. second quarter chemical earnings were $1.4 billion, up $130 million versus the second quarter of 2011. Margins decreased earnings by 150 million, as lower commodity margins were only partly offset by improved specialty margins. Volume and mix effects decreased earnings by $100 million mainly reflecting weaker demand in Europe. Other factors increased earnings by $380 million, which includes $630 million associated with the Japan restructuring, partly offset by unfavorable Forex effects. Moving to slide 22. sequentially, second quarter chemical earnings increased by $750 million mainly associated with the Japan restructuring. Stronger margins increased earnings by $160 million, primarily due to lower feedstock costs. Volume and mix effects decreased earnings by $70 million mainly due to weaker demand in Europe. And finally moving to Slide 23. Exxon Mobil's second quarter financial and operating performance reflects the ability of our business model and competitive advantages to deliver strong results. As we continue to focus on operational excellence, deploy high-impact technologies and leverage our unparalleled global integration, 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. : Turning out to slide 12, on the North American chemical growth project, during the quarter, Exxon Mobil Chemical filed permit applications to progress plans for a world scale, petrochemical expansion that our integrated Baytown, Texas complex. The project includes a new ethane cracker with up to 1.5 million tons per annum on ethylene capacity, which will see two new 650,000 tons per year premium polyethylene lines situated at the nearby Mont Belvieu plastics plant. The proposed expansion capitalizes on the abundant and growing supply of North America natural gas liquids to economically supply the rapidly growing global demand for high performance polyethylene products. These metallocene based premium resins deliver sustainability benefits such as lighter packaging weight, lower energy consumption, and reduced emissions. Required government reviews and approvals are expected to take about a year after which Exxon Mobil will make a final investment decision. If progressed, a 2016 start-up would be anticipated. Turning now to the Saudi Elastomers project on slide 13, during the quarter, the KEMYA 50-50 joint venture partners Saudi Basic Industries Corporation and Exxon Mobil announced the decision to proceed with construction of the specialty elastomers project at Al-Jubail, Saudi Arabia. This continues a long history of Exxon Mobil investment in the Kingdom and represents a significant broadening of KEMYA’s product portfolio. The facility will have the capacity to produce up to 400,000 tons per year of specialty products including synthetic rubber, thermoplastic specialty polymers and carbon black to serve local markets, the Middle East and Asia. Project completion is expected in 2015. Turning now to the upstream financial and operating results and starting on slide 14, upstream earnings in the second quarter were $8.4 billion, down $183 million from the second quarter of 2011. Realization has decreased earnings by $870 million due primarily to lower crude oil and U.S. natural gas realizations, which declined by more than $8 per barrel and $2 per thousand cubic feet respectively. Production mix and volume effects negatively impacted earnings by $330 million, due mainly to the impact of lower entitlement volumes, base decline and divestments, partly offset by the ramp-up of Nigeria and Angola projects. All other items are nearly gains from asset divestments and lower exploration expense, partly offset by one-time tax items and higher production operating expenses increased earnings by $1 billion. Upstream after-tax earnings per barrel for the second quarter of 2012 were $22.12. Moving to Slide 15, oil equivalent volumes decreased by 5.6% from the second quarter of last year, mainly due to the impact of lower entitlement volumes, decline and divestments. Volumes were positively impacted by the ramp up of projects in Nigeria and Angola and less downtime. Excluding the impacts of entitlement volumes, OPEC quota effects and divestments, production was essentially flat. Turning now to the sequential comparison and starting it on Slide 16. Upstream earnings increased by $556 million versus the first quarter of 2012. Lower crude oil and natural gas realizations negatively impacted earnings by more than $700 million, as crude oil realizations decreased by more than $10 per barrel and average gas realizations decreased by $0.60 per thousand cubic feet. Production mix and volume effects decreased earnings by $480 million due to a decline and seasonal gas demand in Europe, base decline and lower entitlement volumes, partly offset by the ramp up of projects in Nigeria and Angola. Other items, including gains from asset divestments, lower exploration expense and favorable Forex, partly offset by one-time tax items, increased earnings by $1.8 billion. Moving now to Slide 17, oil equivalent volumes were down 8.8% from the first quarter of 2012 resulting from a decrease in seasonal gas demand in Europe, base declined on lower entitlement volumes, partly offset by the ramp up of projects in Nigeria and Angola. Excluding the impacts of entitlement volumes, OPEC quota effects and divestments, production was down 7.6%. Year-to-date, oil equivalent volumes decreased 5.5% compared to the first six months of 2011. First half 2012 volumes associated with the 3% full-year decline outlook, provided at the Analyst Meeting in March are shown on Slide 18. Operational performance was slightly ahead of plan, benefitting from the early startup of the Nigeria Usan and Angola Satellites projects and strong base performance. First half 2012 prices most notably in February through April were higher than our March Analyst Meeting outlook basis of $111, and negatively affected first half volumes due to both permanent and price related entitlements. In the second half of 2012, successful startup of several projects and continued strong base performance will support our 2012 volumes. Moving now to the downstream, financial, and operating results and starting on slide 19. Downstream earnings in the second quarter were $6.6 billion, up $5.3 billion from the second quarter of 2011. The driver for the increase was a $5.3 billion gain associated with the Japan restructuring, which was completed on June 1. This gain was partly offset by unfavorable Forex effects, one-time tax items, and increased maintenance activities. Improved refining margins, mainly in the U.S. and Europe increased earnings by $650 million. Moving to slide 20. sequentially, second quarter downstream earnings increased by $5.1 billion, primarily due to the Japan restructuring and improved refining margins partly offset by Forex effects, increased refinery maintenance and one-time tax items and the absence of first quarter gain on asset sales. Turning now to the chemical, financial, and operating results starting on slide 21. second quarter chemical earnings were $1.4 billion, up $130 million versus the second quarter of 2011. Margins decreased earnings by 150 million, as lower commodity margins were only partly offset by improved specialty margins. Volume and mix effects decreased earnings by $100 million mainly reflecting weaker demand in Europe. Other factors increased earnings by $380 million, which includes $630 million associated with the Japan restructuring, partly offset by unfavorable Forex effects. Moving to slide 22. sequentially, second quarter chemical earnings increased by $750 million mainly associated with the Japan restructuring. Stronger margins increased earnings by $160 million, primarily due to lower feedstock costs. Volume and mix effects decreased earnings by $70 million mainly due to weaker demand in Europe. And finally moving to Slide 23. Exxon Mobil's second quarter financial and operating performance reflects the ability of our business model and competitive advantages to deliver strong results. As we continue to focus on operational excellence, deploy high-impact technologies and leverage our unparalleled global integration, 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) We'll take our first question from Doug Terreson with ISI. Douglas T. Terreson – International Strategy & Investment Group, Inc.: Good morning, David. David S. Rosenthal: Good morning, Doug. How are you? Douglas T. Terreson – International Strategy & Investment Group, Inc.: I’m doing fine. My question is on foreign exchange, FX, asset sales, and tax items and specifically whether or not you have functional and geographical quantification on those items in Q2, I mean there was a pretty large lump in the quarter, and I just wanted to see if we could get little color and segmentation? David S. Rosenthal: Yeah, let me – why don’t I start with the items in the $7.5 million. Douglas T. Terreson – International Strategy & Investment Group, Inc.: Okay.

$7.5 billion, I’m sorry. The primary item in there was $6.5 billion associated with the Japan restructuring. Douglas T. Terreson – International Strategy & Investment Group, Inc.: Right.

Okay. And the segmentation of that $6.5 billion was $5.3 billion in Japan, I mean in the Downstream, $600 million in Chemical, $400 million in corp and fin, and about $100 million in the Upstream. And the balance of the $7.5 billion really related to gains on asset sales in the Upstream primarily Angola Block 31 and a number of tax related items. Douglas T. Terreson – International Strategy & Investment Group, Inc.: Okay. And also in A&P business there was commentary that several of the major integrated gas projects in Australia faced cost overruns that is the most budget contingencies were appropriate at the time. So I wanted to get your insight in the trends and investment performance versus budget in Australia, because Exxon has been in the country for many years and given that you have significant holdings besides the integrated gas you obviously hold a unique perspective. So any trends that you could highlight or provide insight into would be appreciated.

Yeah, I'll make a general comment, and then for specific project updates I’d recommended that you [to talk] with the operator of any specific project. But in general over the last couple of years, we have seen some foreign exchange issues with the Australian dollar as well as across the board there have been some cost pressures on labor; and I think those have been well documented in the industry. That's all part of normal project management for us, and you have to find ways to offset those, I think the important things on some of these large projects in addition to cost management is to ensure that the project stays on schedule and comes up on time, and that generally is the focus. But again, if you had a specific project in mind, I’d recommend you ask the operator for any specific update. Douglas T. Terreson – International Strategy & Investment Group, Inc.: Sure, thanks a lot.

And we’ll take our next question from Ed Westlake with Credit Suisse. Ed G. Westlake – Credit Suisse Securities: Hey, good morning David. David S. Rosenthal: Good morning, Ed. Ed G. Westlake – Credit Suisse Securities: Just two quick questions, first the buyback. I mean obviously, you’re still maintaining a $5 billion; you did get some good sources and uses of cash from acquisitions. And [dragging] in Europe is making comments which is helping the oil price. But if we do see a slowdown, how do you think about the rate of buybacks being appropriate, and if the earnings starting to support the buybacks, do you see enough disposals in the pipeline to compensate? David S. Rosenthal: Ed, I really won’t want to comment or provide any guidance on forward expectations with regard to allocation of funds. Other than to say, there is no change in our ongoing view of that, and as you know our first priority just find all of our attractive investment opportunities, after that is to pay a growing dividend and you recall we did raise the dividend 21% earlier this year. And then after that, it’s the share buyback to maintain our capital structure and return excess cash to shareholder. So no change in our approach and we’ll see as the year goes along to how the cash flows turn out given the conditions in the market, but no change in our approach. Ed G. Westlake – Credit Suisse Securities: Thanks. And then just a specific one on the operations. Asia gas volumes were being pretty steady for a number of quarters until the second quarter of 2012, was that maintenance or was that a PSC effect in terms of a tranche kicking in somewhere. David S. Rosenthal: Yeah, let me provide a little more clarity on that, because your question also gets to the main factor if you look at our volume breaks and you look at the entitlement effects that you saw there. And really the impact you’re seeing in Qatar, and I want you know that that unlike the RasGas and Qatargas, LNG trains, the AKG projects, which as you know supports domestic gas sale, does operate under a development and production sharing agreement. And during the quarter that project became cost current and that did impact both the volumes that you see in the region that we noted, as well as the entitlement volumes that we talked about. As far as performance, performance is expected in the region and all the countries there and the assets that we operate. And again the real impact is AKG becoming cost current. Ed G. Westlake – Credit Suisse Securities: And it’s fair to think about domestic prices being lower than the other project, so that would have a lesser impacts on cash flow than the headline production? David S. Rosenthal: Yeah, that would be a correct assumption. Ed G. Westlake – Credit Suisse Securities: Thanks, very much David. David S. Rosenthal: All right; thank you, Ed.

We’ll now go to Doug Leggate with Bank of America/Merrill Lynch. Doug Leggate – Bank of America/Merrill Lynch: Thanks. Hi, David. David S. Rosenthal: Hi, Doug. How are you today? Doug Leggate – Bank of America/Merrill Lynch: Not too bad, thank you. I wanted to go back to one of the events during the quarter which was I guess your official exit from Poland. And I just wanted to get your updated prognosis on shale gas in Europe generally and (inaudible) that’s one of the biggest producers obviously in Northwest Europe. What are your implications for you gravitating back to work exports of LNG in the well 48? And I have another follow-up please. David S. Rosenthal: Those are two distinctly different questions. When we look at Poland, we did drill and complete and test two wells, one in each of the two basins that we were in there. And we did not have any demonstrated, sustained commercial hydrocarbon flow from either of those two wells. and so we have decided to end our exploration activities in Poland at this time. Now as you look across Europe, there are a number of other opportunities and a number of other countries, the people are looking at including ourselves. And so I wouldn’t draw any conclusions in any one country or across Europe, it’s early days. We have set off and as you look around the world that all the unconventional resource opportunities, they’re all different; they’re all in the early stages of evaluation. And it’s going to take some time to figure that up. Now I will mention, because we haven’t talked about it in a little while, our holdings in Germany. and as you know, we have a very large acreage position in Germany and we continue to want to actively explore that. as you know, we've had some permitting issues there over the last year or so that has held that program up. I can’t tell you that the expert dialog group that has been studying this issue for a while has reported their findings unlike many other similar studies and findings across the world, including the U.S., this group do not see any fundamental, environmental, or other risk aspects that would argue against the exploration and production of natural gas from unconventional reservoirs. So with that study out, we are in the process now of working on getting our – working with the regulators particularly in the local areas and the community at large to progress our exploration plants and get the permits necessary to progress. So again, I think every country is different, every unconventional resource opportunity is different and it would be tough to make any geographic conclusions at this time. Now if we switch over to the potential for LNG exports out of North America, we are continuing to study those options both in the U.S. and in Canada, as you know, we have vast unconventional holdings in both of those locations. We have a lot of optionality, a lot of flexibility; we do have some assets in the ground already to import LNG. So we are continuing to study all that and look at our options and the economics and more on that as time goes on. Doug Leggate – Bank of America/Merrill Lynch: Thanks, David. I guess I was thinking that, I look probably European gas would impact your gas decision as well I hope that was one question. If I could try a second is a very quick follow-up on, there is some second half of this question, you didn’t give the FX or the tax impacts by division, if you could that would be really helpful? I’ll leave it there, thanks. David S. Rosenthal: Sure. Let me first give you the foreign exchange impacts, if you are looking at the second quarter of ’12 versus the second quarter of ’11, we had about a negative $200 million delta on Forex in the downstream and then another two… Doug Leggate – Bank of America/Merrill Lynch: I apologize for interrupting, could you give us the absolute as opposed to the deltas is that possible? David S. Rosenthal: I don’t actually have the absolute number, Ed, I have – Doug, I’m sorry, the deltas again I think if you are just looking at (inaudible) it’s $200 million negative in downstream and 200 in chemical, but I don’t have the absolutes. Doug Leggate – Bank of America/Merrill Lynch: All right, thanks very much. David S. Rosenthal: Okay. Thank you.

I will now go to Evan Calio with Morgan Stanley. Evan Calio – Morgan Stanley: Good morning, David. David S. Rosenthal: Good morning, Evan. Evan Calio – Morgan Stanley: How are you doing? A question on Kara, I know you mentioned the project start-up in the back half of the year. How should we expect volumes in 3Q and 4Q and what’s the volumetric plant there in the start-up and then somewhat related, I guess, I believe that the 50% goes to Exxon refineries and then 50% into the market? I guess we should assume that (inaudible) refineries first, and is there any feedstock change, being used system as a result of that? David S. Rosenthal: Sure, sure. Let me hit the status of the project. first, it’s progressing very well, as I mentioned, we’re 94% complete, and I got the modules in place and that we’re in the U.S. and we’re progressing towards a late start-up. That start-up is probably a December start-up. Our intention is to ramp up to 110,000 barrels per day of production from that. but to give you a quarterly number or a specific timing would be real difficult, because again, if you’re not going to start up till December, it won’t have a huge impact. Evan Calio – Morgan Stanley: And what’s the expected maybe trajectory to either kind of gross, 110 gross? David S. Rosenthal: Yeah. We’ll be ramping that up, obviously from the time we’d start up into the next year. I don’t have a specific ramp up profile, other than to say as safely as possible and with the operations running, we’ll ramp up to that 110 as quickly as possible. But I don’t have a specific timeline for you right now. Evan Calio – Morgan Stanley: Great. But from the feedstock? David S. Rosenthal: I'm sorry… Evan Calio – Morgan Stanley: On the feedstock… David S. Rosenthal: The first thing I’d say is, I wouldn’t necessarily say we have a 50/50 mix of what’s going to our refineries versus what’s going to go into the market, the other part of your comment is correct, we will optimize in general to displace the placement of those barrels, but certainly having the flexibility of our own refineries in Canada as well in the Midwest, we’ll be able to optimize those first, and then put the balance in the barrels. But that will change depending on the market, which is you know has been fairly volatile recently. And so if I gave you a split today that may or may not be the split six months ago, but you’re certainly spot on with your comment about us optimizing first into our refineries, and then the balance going into the market so that we can maximize the value of all the barrels really across the whole refining circuit. Evan Calio – Morgan Stanley: Okay, and if I may just – thank you. If I may just one other question. David S. Rosenthal: Sure. Evan Calio – Morgan Stanley: Thanks for the update of on the PNG LNG project and it sounds like you are really moving along well there. I mean, can you remind us of how much gas excluding, I guess these recent discoveries is behind that development, and whether – are further discoveries necessary for potential expansion opportunities there? David S. Rosenthal: If you look at, first if you look at the trains, those are to 6.6 trains will start-up in 2014, and as I recall the total resource back in that is up about 9 Tcf. Evan Calio – Morgan Stanley: Okay. So you need additional discoveries likely to expand right? David S. Rosenthal: Yeah, and that's what I said, earlier that two things are going on, we are certainly studying the opportunity for a third train, and the positive news is we’re having exploration success this year in drilling some wells and we have an active exploration program ongoing with a lot of additional acreage that we have available to us. So it’s a positive story with the steel we got going in the ground now; it’s a positive story on the exploration front. So we’ll continue to focus on getting what we have up and running while steadying for further expansion and optimization. Evan Calio – Morgan Stanley: Great, thank you. Thanks for taking my question. David S. Rosenthal: Thank you for the questions.

We will now go to Paul Cheng with Barclays. Paul Y. Cheng – Barclays Capital: Hi, Dave. Good morning. David S. Rosenthal: Good morning, Paul. How are you? Paul Y. Cheng – Barclays Capital: Very good. Two quick questions. You’ve been quite active in building in Gulf of Mexico and had good success, are you now, all set with all your rig requirements for the next say one or two years or is that you will meet additional requirement there? David S. Rosenthal: Well, if you look at what we’re doing now in the Gulf of Mexico, probably the biggest thing we got going right now, is the two wells that we’re drilling simultaneously at Hager & North as we continue to look at that resource. As we go on through the year, we are looking at the possibility of another well in the Gulf before year-end. But we’re now talking about a specific rig line or what’s contracting, and what’s not, what I could tell you is we do have flexibility around the rig fleet. We are planning for a sustained exploration program. And when we look at the opportunities and the rig availabilities and the assets that we have under contracts, I think we’re well positioned to progress the program, I don’t see any constraints or any holds up in terms of equipment availability. Paul Y. Cheng – Barclays Capital: Dave, if your current rig, the contract expand into let’s say 2013 and 2014 or that is expanding this year? David S. Rosenthal: Paul, I really wouldn’t want to comment specifically on rigs and lease arrangements and that sort of thing, those are all part of commercial nature of the business, and so really wouldn't want to get into any specifics on that. Paul Cheng – Barclays Capital, Inc.: Okay, sure. The second question that – you have to – I have to apologize, yeah, probably due to my ignorance. Given the low natural gas price over the last 12 months in the U.S., if the natural gas price stay at say $2 to $3 dollar per Mcf range, is there a circumstance that would force you guys that to look at your open reserve booking from the XTO and also that any way down for separately how is the accounting from that standpoint? David S. Rosenthal: Yeah, Paul if we step back just a little bit obviously that is a very large resource that we acquired in the XTO acquisition. Some of it is book to prove reserves, bought a whole lot of it is really in the resource base. And so, when you look at prices and the volatility of those prices, and what's going on, I don't think when you look at our outlook going forward that we see ourselves really getting into the issues that you're talking about without getting into any specifics on accounting, and reserve reporting. I'm confident that if you look at that resource and what we've got book now in the conservative nature, with which we tend to book proved reserves, I’m not expecting there to be any issues in that area. Paul Cheng – Barclays Capital, Inc.: So, should we assume that the ceiling test you would be allowed to use your own internal long-term price deck? David S. Rosenthal: Yes, if you look at that ceiling test as far as I know, you do use your own long-term expectation for those prices. Paul Cheng – Barclays Capital, Inc.: Okay. David S. Rosenthal: Thank you.

I will now go to Blake Fernandez with Howard Weil. Blake Fernandez – Howard Weil Inc.: David, good morning. I have a couple of questions for you on two different projects. one is back to the Gulf of Mexico and Julia, I know there are some issues with the government a while back and as I understand, you’ve worked that out and you’ve now retained the block. Can you just give us an update on, if I recall, it seemed to be fairly large discovery, any update on timing and activity out there? David S. Rosenthal: Sure. I’ll be happy to give you an update on that. as you know, we did drill that first exploration well in 2007, it was successful. we did have some issues with the Department of Interior around that license. I can confirm that the comment that you made, yes, those issues have been resolved. And in fact, if I look across the second quarter, we are working on the development plans for that. in fact, we are really progressing in the technical validation program at this time and front-end engineering and development. and late in the quarter, we did place some initial long lead equipment items. So if you look at the whole broader schedule, we are progressing as rapidly as appropriate. but again, we’re already in the process of ordering long lead programs, working on the development plan and the evacuation plan. So that project is progressing. Blake Fernandez – Howard Weil Inc.: Okay, great, thank you. And then the other one was actually on the Tanzania, it sounds like you’ve got about 7 TCF discovered to-date. I’m wondering for one, how much need in order to justify development? and secondly, my understanding is that government will not approve multiple development. So it’s almost a bit of a race to see who is going to have the first move or advantage, I’m just curious if there’s any update on your activity there? David S. Rosenthal: Yeah. Let me hit the first question on the results in Tanzania, that has been today a very successful exploration effort for us. We have said that the first well looks like we got about 5 Tcf of developable reserves there, and then the second well looks like we got about 2; so, for a total of 7 Tcf. I can tell you we are continuing with our exploration activities, we got some additional seismic going on this year, and may even put another well before the end of year. So that's all going very well. I would want to give a specific number in terms of what's required for an LNG project, because it could have multiple aspects to developing that. and so I wouldn’t want to give specific number there. In terms of the race to get a project underway, I’m not aware of any constraints on that program. It is still early days in that whole area of East Africa as you know. There has been a tremendous amount of activity and some successful discoveries, but to start discussing order of projects and who gets there first and that sort of thing, I think it probably will be premature to talk about that. Blake Fernandez – Howard Weil: Okay, fair enough. Thank you, David. David S. Rosenthal: Thank you.

And then I’ll go to Faisel Khan with Citi. Faisel Khan – Citigroup: Thank you, David. Good morning. David S. Rosenthal: Good morning, Faisel. How are you? Faisel Khan – Citigroup: Good, how are you doing there? David S. Rosenthal: I’m fine. Faisel Khan – Citigroup: I am wondering if you could elaborate a little bit more on what’s going on with U.S. natural gas production. it looks like it peaked at about 4 Bcf a day in the fourth quarter of last year and it’s been coming down steadily. I was wondering if that’s the function of your shift in rig count in the lower 48. David S. Rosenthal: It's a number of factors. You have to start at the top of that with base decline, across the conventional resources and decline that we’re seeing there. If that’s going to be partly offset by the increases in unconventional gas production. But as you pointed out, we have seen a shift and that shift continues in our rig count, to the liquids-rich plays. So the program itself is, as I described before, we are managing across the entire portfolio, which does include continuing to delineate, appraise, and evaluate the dry gas areas, while at the same time, focusing the drilling on the liquids-rich plays. And the other thing that we’ve had in there, we have had some divestments, you might recall we had one in the Gulf of Mexico a year or so ago and that would decline – would have an impact there. So, it’s really a combination of decline, divestments, some shifting of rigs and then offset by the production increase that we’ve seen in the unconventional resources at XTO. Faisel Khan – Citigroup: Okay. And I believe at the Analyst Meeting, you guys talked about how you were running maybe just under 70 rigs, I am not sure if it’s still the right number or not. but it seemed like you had shifted to 50% of those rigs were now drilling in liquids-rich plays. Can you give us an update on where you are with that sort of mix in rig count? David S. Rosenthal: Yeah, sure. We have continued to both reduce the absolute number of rigs running. I think we averaged about 57 across the quarter. We’re currently in about 51 rigs in total, and without giving a specific percentage, I can tell you the majority of those rigs are working on liquids and liquid-rich plays and that obviously would be a continuation of the trend that you are seeing over the last few quarters. Faisel Khan – Citigroup: Thanks David. And last question from me. On Slide 16, where you talked about the first quarter to second quarter sort of progression of earnings for Upstream. The $1.76 billion sort of other, and you said, part of that was Angola and part of that was favorable FX. Was the FX sort of movement, was that a absolute number or was there a big change quarter-to-quarter because of something in the first quarter? David S. Rosenthal: No, again it was kind of small, it was less than a $100 million and that would be the change quarter-on-quarter. So within that bar, it's not a big effect either way. Faisel Khan – Citigroup: Okay, great. Thanks for the time, I appreciate it. David S. Rosenthal: All right, thank you.

And we’ll now go to Pavel Molchanov with Raymond James. Pavel Molchanov – Raymond James & Associates: Thanks very much. Two related question about Rosneft, if I can. First one is as you know Rosneft has public said, they are talking to BP about the potential TNK acquisition. If that happens how do you see that changing your relationship with them. And second question on the same point, has Exxon contemplated buying the TNK-BP stake? David S. Rosenthal: Actually my answer would be the same to both of those questions. I really couldn't provide any comment on either what others in the industry are doing or anything that we might have gone on and are thinking about. Pavel Molchanov – Raymond James & Associates: I appreciate it. David S. Rosenthal: All right, thank you.

I will now go to John Herrlin with Societe Generale. John Herrlin – Societe Generale: Yes, hi David. Unconventional liquids was about 5% or 6% of the U.S. oil production or liquids production. How big do you want to make that on a going forward basis? I mean, how large a ramp should we anticipate? David S. Rosenthal: That's a question I really couldn't answer because I have no idea what the forward projections are going to look like. Obviously there's a lot of activity, a lot of plays, we are certainly heavily involved both as I mentioned in the ramp-up of our existing fields like we have at the Bakken, but also in the pursuit and capture of a number of attractive acreage holdings like we mentioned in the Woodford Ardmore and the Utica. So from an Exxon Mobil perspective, I can tell you as we move out of these delineation appraisal and valuation of programs into full development, you'll continue to see the ramp-up that I mentioned in my prepared remarks, particularly in places like the Bakken and then in some of the other areas. But we don't have a target and I couldn't give you a target for the industry. It's really just going to depend on how quickly these new opportunities that us and others are finding. You can get in and get those online and then of course you need the midstream infrastructure to evacuate those volumes and get them to market and to the extent that you're producing NGLs, there is other midstream infrastructure that has to be put into process. So, there's a lot of opportunity, a lot of nice ramp-up kind of across the board as you mentioned. But it would certainly be hard for me to give any indication of what kind of ultimate target might be either for us or the industry in general. John Herrlin – Societe Generale: Thanks I was only asking about Exxon. But thanks David. David S. Rosenthal: Okay, all right.

And then I’ll go to Ian Reid with Jefferies. Iain Reid – Jefferies & Co.: Hi, David. Good morning. David S. Rosenthal: Hey Iain. How are you doing? Iain Reid – Jefferies & Co.: I’m doing very well actually. And couple questions, firstly and thinking about your U.S. onshore operations at the moment. Have you got an updated number for either capital employed in U.S. onshore or return on capital employed, which you’re generating at the moment? David S. Rosenthal: No, we don’t typically give that level of detail, Ian. So, I wouldn’t have either of the capital employed number or the return on that. Iain Reid – Jefferies & Co.: Okay, all right. Second question is about dividends. Obviously you’ve made a pretty substantial increase in your dividend payments. I just wonder when you are thinking about that and how do you factor in potential changes in dividend taxes, withholding taxes in the U.S., is that something you think about or is this kind of more fundamental change or increase you’ve made? David S. Rosenthal: A number of factors as you would guess go into the whole decision-making process about the allocation of cash and that sort of thing. Though, I wouldn’t want to comment on any one specific factor or even to speculate ultimately what the tax situation might look like or changes that we might see in the upcoming several months. So, again a number of factors we think about, we don’t try to speculate a whole lot about the future from the standpoint that you mentioned, so I really wouldn’t have a specific comment on that. Iain Reid – Jefferies & Co.: So, was there something investors were kind of pressing you to look at rather than as a kind of add-on to the existing share buyback, was that part of the rational? David S. Rosenthal: We spend a lot of time talking to our investors about a number of things; dividends are one, share buybacks are another. Not all of the investors are interested or have a waiting to any one particular disposition over another, some have one preference and others have another. We do spend some time looking at the competitiveness of both our total distributions and the breakout of those and we do look at that. But in particular on a specific input or a specific factor in the analysis, I wouldn’t give any waiting to one over the other. We do spend time taking all the factors into consideration and of course that includes input we get directly from our shareholders. Iain Reid – Jefferies & Co.: Okay. Last question please on Vietnam; I believe you proved up quite a substantial amount of gas now that with these three wells following on from, last year’s discovery. And any numbers you want to share with us about what sort of level of reserves you proved up, you gave us obviously something on Tanzania and maybe you can also talk about the forward program on that? David S. Rosenthal: Sure, I can tell you. We are not as far along in assessing what we have in Vietnam as we were in Tanzania. We’re still evaluating the wells there. We had one well that was not successful and two that were, and so we’re still in the early days. So looking at that we got a lot of work to do, lot of evaluation to do and to assess that we are looking at additional seismic and other expiration activity. But little early to start giving you resource numbers at this time. Iain Reid – Jefferies & Co.: All right, David. Thanks for that. David S. Rosenthal: Thanks so much.

Now we will go to Paul Sankey with Deutsche Bank Paul Sankey – Deutsche Bank: Hi, David. David S. Rosenthal: Hi, Paul. How are you doing? Paul Sankey – Deutsche Bank: Fine, thank you. Apologies, I’m traveling today, so I got on the call late. But I did want to ask you about your specials and the way you declare them. I guess the question is, I completely don't understand what – why you depend those specials, in the table of specials, but then immediately say, there were lot of specialists? David S. Rosenthal: Paul, let's talk just a minute about in term of specials, and I think, I can address your question. Really, you have to think about two different considerations when you're talking about special items. The first that I'd offer you is, if look at this from an Exxon Mobil perspective both asset divestments, and acquisitions that become a normal part of our ongoing operations. We talked at the Analyst Meeting in March about the level of divestments that we've had. If I just look across the last four or five years, I think we've had $26 billion in proceeds and about $11 billion in earnings. So, this is an ongoing piece of the business for us. Some quarters the numbers are a little larger than others, but in terms of divestments being special they are part of the business. I think the other thing to consider is that the use of the term special items has in fact evolved over time, driven in part by updated SEC guidance on the use of non-GAAP terms. And we are certainly in compliance with that updated guidance and paying attention to it, and it has evolved over the last few years. So, if you take those two factors into consideration, I think, you know what we've reported here this quarter is consistent with both of those. Paul Sankey – Deutsche Bank: So is that SEC definition a question materiality then or and I think the other – find very odd, David, is that you continue to publish this table of zeros, which just kind of seems inefficient quite frankly, but can you just talk a bit more about what you are saying about the SEC. I understand your argument that the divestments are an ongoing part of your business and therefore shouldn't be considered special. I think that’s [fine] the SEC bit. David S. Rosenthal: Sure, without getting into the weeds here, I can tell you that is not really a materiality look. It’s really around the desire for the SEC for company to not describe a charge or gain as the non-recurring infrequent or unusual event unless it meets certain criteria, and that includes a look back as well as a look forward. So, if you're looking back and you've been doing this stuff in the past, and you look forward, and you think that you might have these type of events in the future, the SEC guidance as to not call those non-recurring infrequent unusual special or whatever term, you want to use, and again that has happened over time. In terms of the table and efficiency, I'll tell you it's possible. I’m not saying that we'll never report a special items, because we may, I’m just saying that when we look at the guidance in our business, none of the earnings impact that you saw in the quarter qualified to be the ‘special items'. Paul Sankey – Deutsche Bank: If I could just follow-up on Paul Cheng, and is kind of related. I think you were saying that would very, very unlikely be a write down related to XTO, because I guess what you're implying a very conservative in booking what is essentially a very, very large resource. David S. Rosenthal: Yeah, I think it's a couple of things, Paul, it's the conservative nature for which we book things to proved reserves, and it's also our outlook for natural gas prices. If you look broadly and look at our energy outlook, we don't have an outlook over the long-term, the prices are going to remain at current levels, and that's consistent with our investment plans, it's consistent with our energy outlook and it's really consistent with the long-term way that we're going about developing these resources. Paul Sankey – Deutsche Bank: Okay, David thanks. I think, I understand, I just wondering, is the SEC going back to that allows you to use your own long-term planning assumption for nat gas prices as regard to booking? David S. Rosenthal: Yeah, that's correct. Paul Sankey – Deutsche Bank: Okay, that’s good. Thank you.

And we’ll now go to Allen Good with Morningstar. Allen Good – Morningstar: Good morning, David. Just one quick question on the lower 48 activity, it looks like you made pretty good progress in reducing the rig count there and moving towards liquids-rich plays, but if we look back sort of a year ago, you were at 70 rigs and natural gas prices were at $4. and then certainly they’ve made quite a recovery off the lows, we saw earlier this quarter and whether that’s sustainable or not, it’s certainly a question, but is the $4 level to think about that Exxon will maybe potentially return to gas drilling or given the low base of rigs, you are working off now, there certainly have to be different conditions where you would revisit some of these gas plays that you’ve moved away from over the past six months? David S. Rosenthal: I think the answer to the question, and what you’re seeing us doing is really more reflective of our longer-term approach to this. We are still drilling in dry gas areas. We do continue to drill wells in order to work on our delineation, and our evaluation of those plays to make sure that again over the long-term, we want to be in a position to maximize the recovery and maximize the value generation from those resources, so that hasn't changed. What you have seen that we've talked about is both a reduction in the total rig count, and some of that of course is in response to the short-term pricing that’s happened. In addition, the move of – a lot of the rigs over liquids and liquids-rich is really both to start to delineate and appraise and think about developing our new acreage like the Woodford Ardmore, again as well as wrapping up in the Bakken. In fact, I think I heard the other day we're up about 10 rigs in the Bakken, out of those 51. We really don’t have a price trigger to any big extent. You might do something a little different at the margin in any given quarter depending on prices. but when you really look at the overall plan and the overall strategy, it continues to be with a very long-term view of this, very large, very high quality source we got. Allen Good – Morningstar: Okay. In the short-term though, do you expect that 51 rigs total you’re currently running? Is that enough to do everything you want to do as far as evaluating those plays and driving production on liquid-rich plays or would we expect during short-term to see that rig count continue to fall? David S. Rosenthal: I really don't have an outlook going forward for the rig count. We continue to progress the program, and we could see some variability around the number that I mentioned, but I really couldn’t give you an outlook in terms of either direction or rig count specifically. Allen Good – Morningstar: Okay, thank you very much. David S. Rosenthal: Bye, thank you very much.

It appears there are no further questions at this time. Mr. Rosenthal, I’d like to turn the conference back to you for any additional or closing remarks. David S. Rosenthal: No I’d just like to thank everybody on the call today and thank you for your questions and we look forward to visiting you again next quarter. So thank you very much.

Ladies and gentlemen, that does conclude today’s conference call. Thank you for your participation.