Jeffrey Woodbury – VP, IR and Secretary

Ed Westlake – Credit Suisse Phil Gresh – JPMorgan Doug Terreson – ISI Evan Calio – Morgan Stanley Asit Sen – Cowen and Company Blake Fernandez – Howard Weil Jason Gammel – Jefferies Roger Read – Wells Fargo Allen Good – Morningstar Investment Research Paul Cheng – Barclays Ian Reid – BMO Ryan Todd – Deutsche Bank Paul Sankey – Wolfe Research Alastair Syme – Citi John Herrlin – Societe Generale Guy Baber – Simmons & Company Pavel Molchanov – Raymond James

Good day, and welcome to the ExxonMobil Corporation Third Quarter 2014 Earnings Conference Call. Today’s call is being recorded. At this time I would like to turn the call over to Vice President of Investor Relations and Secretary, Mr. Jeff Woodbury. Please go ahead, sir.

Thank you, ladies and gentlemen good morning, and welcome to ExxonMobil’s third quarter earnings call. The focus of this call is ExxonMobil’s financial and operating results for the quarter. And I’ll 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 statements shown on Slide 2. Turning now to Slide 3, let me begin by summarizing the key headlines from our third quarter and year-to-date performance. First, ExxonMobil’s financial results reflect the strength of the integrated business model, which creates unique competitive advantages and allows us to generate long-term shareholder value regardless of market fluctuations over the business cycle. Second year-to-date cash flow from operations and asset sales fully covered our net investments in the business and robust shareholder distributions. And third, we continue to meet our operational and projective development objectives. Upstream production volumes for 2014 remain on track to average 4 million oil-equivalent barrels per day by year end, as the company delivers new production from project start-ups and work programs. All of which are enhancing our financial performance. Now moving to slide 4, we provide an overview of some of the external factors impacting our results. Global economy showed mixed results in the third quarter. In the U.S., the economy continued to expand at a moderate pace, however China’s economic growth tapered slightly, while the European economy showed further sign of weakness. As you know crude oil prices decreased sharply and Henry Hub gas prices also weakened. The WTI spread to brand, narrowed whereas global industry refining margins were essentially flat as stronger European margins were offset by weaker margins in the U.S. And finally, chemical commodity and specialty margins strengthened during the quarter. Turning now to the financial results shown on slide 5. ExxonMobil’s third quarter earnings were $8.1 billion or $1.89 per share. Corporation distributed $5.9 billion to shareholders in the quarter through dividends and our share repurchase program. Share purchases to reduce shares outstanding, were $3 billion. CapEx was 9.8 billion in the quarter and just over $28 billion year-to-date, down 14% when compared to the first 9 months of 2013. Cash flow from operations in asset sales were $12.5 billion and at the end of the quarter cash totaled $5 billion and debt was just shy of $22 billion. Next slide provides additional detail on third quarter sources and uses of funds. Over the quarter, cash decreased by $1.3 billion from 6.3 billion to $5 billion. Earnings, depreciation expense, changes in working capital and other items in our ongoing asset management program, yielded $12.5 billion of cash flow from operations and asset sales. Uses included net investments in the business, of $7.9 billion, and our shareholder distributions of $5.9 billion. Share purchases to reduce shares outstanding’s are expecting to continue at $3 billion in the fourth quarter of 2014. Now moving to slide 7 and a review of our segmented results. ExxonMobil’s third quarter earnings of $8.1 billion, increased by $200 million from the third quarter of 2013 as you can see higher downstream, and chemical margins were partly offset by lower upstream liquids realizations and higher corporate and financing expenses. In the sequential quarter comparison shown on slide 8, earnings decreased by $710 million. Lower gains on upstream asset sales were partially offset by higher downstream and chemical earnings. Our guidance for corporate and financing expenses remains at $500 million to $700 million per quarter. Turning now to the upstream financial operating results starting on slide 9. Upstream earnings in the third quarter were $6.4 billion, a decrease of $297 million versus the third quarter of 2013. Realizations decreased earnings by $670 million driven by lower liquid prices, and in this regard on a worldwide basis, crude oil realizations decreased by $10.48 per barrel. And worldwide natural gas realizations decreased by $0.42 per thousand cubic feet, as lower European realizations were partly offset by higher U.S. gas prices. Notably, favorable sales mix effects increased earnings by $340 million. Higher margin, production growth in Papua New Guinea, Angola, and North America as well as the net over lift, were partly offset by higher planned maintenance activities, lower entitlements and fuel decline. Moving to slide 10, excluding the impact of the Abu Dhabi onshore concession expiry, our oil equivalent production decreased by 1% compared to the third quarter of last year. Importantly liquid’s production was up 14,000 barrels per day, increased production from onshore U.S. work programs, Canada and Angola were partly offset by divestment in tax in Iraq and Canada as well as scheduled maintenance in U.S., Nigeria and Russia. Natural gas production was down 319 million cubic feet per day as expected field decline in the U.S. and unfavorable entitlement impacts from pipeline gas in Qatar were partly offset by new high margin production from Papua New Guinea LNG. In short our volumes performance demonstrates the progress being made to high grade our portfolio mix with higher margin liquids and liquids linked gas production. As previously indicated we remain on track to produce 4 million oil-equivalent barrels per day in 2014. Turning now, to sequential comparison starting on slide 11, our upstream earnings decreased $1.5 billion dollars versus the second quarter. Realizations reduced earnings by $850 million with worldwide crude realizations down $7.29 per barrel and natural gas realizations down to $0.56 per 1000 cubic feet. Again, favorable sales mix effects, increased earnings by $460 million reflecting profitable growth in Papua New Guinea, Angola and Canada and a net overlift partially offset by lower seasonal demand in Europe. All other items reduced earnings by $1.1 billion primarily driven by the absence of the prior quarter Hong Kong power divestment gain. Upstream after tax per earnings per barrel were $18.65 excluding the impact of non-controlling interest volumes. Moving on to slide 12, volumes were essentially flat versus the second quarter. However liquids production was up 17,000 barrels per day due to growth in Angola and U.S. partly offset by higher planned maintenance in the U.S., Nigeria and Russia. Natural gas volumes were down 155 million cubic feet per day reflecting lower seasonal demand in Europe partly offset by a full quarter of Papua New Guinea LNG volumes. Moving now to the downstream financial, and operating results starting on slide 13, downstream earnings for the quarter, over $1 billion, up $432 million from the third quarter of 2013. Higher refining margins increased earnings by $820 million whereas volume and mix effects added another $100 million. All other items decreased earnings by $490 million which mainly due to unfavorable foreign exchange impacts. Turning to slide 14, sequentially third quarter downstream earning increased by $313 million, higher non-used refining margins increased earnings by $310 million positive volume and mix effects due to lower maintenance were offset by unfavorable foreign exchange and another effects. Moving now to Chemical financial and operating results shown on slide 15, third quarter chemical earnings were $1.2 billion up a $175 million versus the prior year quarter mainly due to high commodity product margins. Positive volume and mix effects were more than offset by increased planned maintenance activities. Moving to slide 16, sequentially our Chemical earnings increased by $359 million due to higher commodity and specialty product margins. Moving now to an update on our year-to-date cash flow growth shown on slide 17, strong year-to-date cash flow from operations and asset sales of $41.5 billion more than covered the net $22 million invested in the business and $17.6 billion distributed to our shareholders. Mainly cash is used for other financing activities including debt reduction. Overall free cash flow of $19.4 billion represented increase of $12 billion compared to the same period in 2013. This year year-to-date free cash will growth, reflects our strong operational performance, ongoing asset management program and disciplined capital allocation. Turning now to slide 18, I’d like to provide an update on project startups that will deliver profitable growth. We remain on track for a record startup year and planning to add 300,000 net-equivalent barrels per day of production capacity, that is indicative of the diversity of our resource base. We continue to demonstrate our world class project execution capabilities and have made significant progress during the year. For June, three major projects were started up as you know Papua New Guinea LNG came online a few months ahead of schedule and reached full capacity in July. In Angola, the CLOV reached full capacity in third quarter just a few months after first production and in Malaysia Damar started up in the first quarter. Recently, we achieved several additional project milestones. In Indonesia, the second well pad at the Banyu Urip project started up adding another 10,000 barrels per day of early production. Banyu Urip is now producing nearly 40,000 barrels per day. Construction of the central processing facilities as shown in picture is near complete and uploading offshore storage vessel which recently towed to its location for a final hookup. The project will reach full fuel capacity of 165,000 barrels per day in 2015. In Malaysia the tap is to enhance to oil recovering project which is the first large scale UR project in the country was completed. Project is utilizing a water alternating gas injection process to sweep remaining oil reserves to producing wells, increasing overall recovery. Also, the Qatargas II maintenance project was completed, enabling the venture to maintain 10 million tons of annual LNG production for the years to come. Project added well capacity a new onshore facilities for sulfur handling. In the fourth quarter we also expect to start up several additional major projects closing out our 2014 plans. In our offshore Sakhalin project in Russia, the first production well at Arkutun-Dagi is currently being drilled, offshore facility hook up and commissioning activities are nearing completion following the installation of platform top size this summer. Startup is anticipated around year-end and the field is expected at add 90,000 barrels of oil per day at peak production. In the Gulf of Mexico hook up and commissioning activities for both the Hadrian South and Lucius developments are underway. At Hadrian South we finished drilling the two subsea wells earlier this year. And installation of the subsea facilities for tieback to the Lucius far is now complete. Startup of both projects is expected before year-end. In Canada the Cold Lake Nabiye project is moving into the final stages of completion. Hydro testing and commissioning activities are occurring in support of plant startup and steam injection is expected around the end of the year. This project will add another 40,000 barrels per day to Cold Lake production. I would now like to turn to slide 19 for an update on U.S. onshore liquids growth; we are generating significant cash flow by growing high margin liquids production in the U.S. primarily in unconventional place. In the Bakken our resource base is now approaching 1 billion oil crude and barrels and gross operated production is up more than six fold since we first entered the play in 2008. The Bakkan remains our most active conventional play and is the liquids growth engine in U.S. Gross operated production has increased 38% year-on-year reflecting higher activity levels. Currently running 13 rigs up from 10 in the third quarter of 2013, net increase, new wells brought online by 25% year-on-year. We continue to achieve strong results and increased efficiencies through our development drilling in the core areas. Optimizing completions and leveraging pad development, in this regard drilling and completion costs have been reduced by 25% since 2011. We also successfully employed our proprietary extract technology to reduce costs by eliminating the need for multiple plugs, normally required for fracking. In the Woodford shale, we’re running 10 rigs, gross operated oil equivalent production in the liquids rich Ardmore Marietta area has increased by 25% year-on-year, driven my more completions, strong well performance and the move to pad development. Year two, well completion times have decreased significantly, reducing costs and increasing the number of wells drilled per rig year. Although rig counts have remained basically flat, we have increased the number of new wells by 33% year-on-year. In 2014, we also increased drilling activity in the Marietta basin, timed with the completion of infrastructure there. We’re encouraged by the initial work in Marietta, which has an even higher proportion of liquids in the Ardmore area. And lastly 8% year-on-year on a large legacy production base reflecting tripling the number of rigs we had in the third quarter of 2013, along with approximately six conventional productions. We continuously look for opportunities to add attractive acreage 4,000 net acres in the heart of the expanding Wolfcamp play, as shown on the map in blue. Turning now to slide 20 for an update on our exploration activities. In Romania, drilling activities at Domino-2 are complete; the well was drilled to gather more information on the 2012 Domino discovery to assess the size of the resource and its commerciality. Domino-2 is being followed by the Pelican South-1 wildcat, which is currently being drilled. Additional exploration targets are also planned. In Tanzania, Statoil and ExxonMobil made a seventh discovery in block 2. Giligiliani-1 well discovered gas in the western part of block 2. The well confirmed an additional trillion cubic feet of gas in place, bringing the total estimated resource in place up to 21 trillion cubic feet. In Argentina, drilling and testing continue in the Vaca Muerta, where we have drilled and successfully tested 2 ExxonMobil operated horizontal wells. The Bajo del Choique X-2 well flowed at an average initial rate of 770 barrels of oil per day, and is currently on the long-term test. And I’ll note that this is the highest unconventional oil production rate test in Argentina. The La Invernada X-3 well began testing at September with encouraging initial results, although still clinging up. Our active program continues with additional drilling and testing later this year and into 2015. And finally, in Russia, we successfully drilled the University-1 well in the Kara Sea. I can confirm that the well did encounter hydrocarbons, however results are under evaluation, it would be premature to comment any further at this time. Well was safely plugged and abandoned and the rig has departed to location. So in conclusion, today’s presentation provides a summary of our year-to-date performance, ExxonMobil’s strong financial operating results, demonstrate the value of our integrated business model and unique competitive advantages. Total earnings were $26 billion, reflecting solid operating performance across all of our businesses and our ongoing asset management program. And the upstream production of 3.9 million, oil-equivalent barrels per day remain in line with our plan as we add new production from project start-ups and work programs. We continue to improve our production mix with unit profitability increasing from $18 per barrel in 2013 to just over $21 per barrel year-to-date. A strong operating results combine with our disciplined capital allocation approach, generate a robust free cash flow of $19.4 billion, an increase of $12 billion compared to the same period in 2013. This favorable performance enabled us to maintain industry leading, shareholder distributions at $17.6 billion. That concludes my prepared remarks, and now we’d be happy to take your questions.

Thank you Mr. Woodbury [Operator Instructions]. And we’ll first go to Ed Westlake – Credit Suisse. Ed Westlake – Credit Suisse: Yes, and may I say welcome on behalf of [Indiscernible] to the new role.

Thank you Ed. Ed Westlake – Credit Suisse: So obviously your net income margins probably surprised most people, they seem to go up as the oil price pulled back. You’ve got new projects obviously coming on-stream, and I can see that your exploration expense was a little bit low, which is kind of non-cash. But can you give us some color as to why you think net income per barrel went up in the U.S. and international? Little surprised.

Yeah, I mean we broadly say Ed that it starts with the integrated business model. You’re all very aware that we’ve got a very cyclical nature of our business, and our business model is focused on creating shareholder value by participating through that whole value chain. So it provides robust earnings performance despite the cyclical nature. If you think about just the overall upstream unit performance, as I said, we’re up year-to-date versus 2013, by about $3 per barrel. Half of that is asset management impacts, another half improved profitability, primarily due to improved liquids mix as well as higher profitability around our gas projects, really good progress by the organization, in improving the higher margin production, as I said in the presentation. Ed Westlake – Credit Suisse: Okay and a second unrelated question just around Kearl, I mean obviously that is a big project and there is the Kearl expansion and potential de-bottlenecking maybe just give us an update of the latest status, and a bit more detail there, thank you.

Sure, thanks for that Ed. Kearl, as we’ve said many times, is a long life asset, it’s advantaged. Obviously it’s advantaged because of the prior technology that we’ve implemented where it foregoes the need for an upgrade. Overall, I’d say that we’re making progress quarter-on-quarter on Kearl. Currently we’re consistently producing over 100,000 barrels of oil per day, as we ramp up production there; we’re clearly identifying opportunities where we can further enhance the facility reliability. I will say that we did take a turnaround in September, for planned maintenance, and all of these learning’s are being fully integrated into the expansion project. As you know, we talked about the importance of capturing the learning’s from the initial development, and that was a key element of their investment decision to progress right into the expansion. Likewise as we get more and more comfort with the operability of the initial development, those learning’s are being integrated in the expanse project as well. So overall, we’re really pleased with the asset, as I said; it’s a long life asset that’s going to provide very stable productions. And quite frankly Ed, we’re in our sweet spot right now, we have – this is what we do very, very well in terms of our project execution, and then optimizing our operations to make sure that we maximize the value –

Thank you. We’ll now go to Phil Gresh, JPMorgan. Phil Gresh – JPMorgan: Hey good morning.

Good morning Phil. Phil Gresh – JPMorgan: Just kind of following up on the question about the margin lift in the quarter and past couple of quarters, just kind of wondering how you would think about, how we should think about the next year or so. And what’s the potential benefit you could see, in particular from cost levers. As we’ve seen the oil price come down, what leverage do you think you can pull around cost and/or CapEx?

Yeah Phil that’s a great question, I mean clearly the market has seen some changes with prices. I don’t think any of us should be surprised given the oversupply and continued economic weakness. I’ll go right back Phil, toward the value of our integrated business model, which really does position us well to capture shareholder value; it is the cyclical nature of the business. Quite frankly the market controls the price, and what we need to focus on are the variables that we do control. And to your question, those include things like effectively managing our development and operating costs, maximizing our reliability, and then optimizing the value of the molecules through the integrated business model. All along that, that has been a fundamental main stay of our corporation. And then as a key element of how we manage that, and it’s always around optimizing that the cost structure within our assets that we are maximizing the value from the resources. Phil Gresh – JPMorgan: And just as a clarification could you tell us how much of the 2015 CapEx is locked in at this point, what kind of flexibility you have?

Yeah, so just a little bit more about the CapEx, if I could step back a moment, as you all know our CapEx has grown through years, and it peaked in 2013 at about $42.5 billion. And that was largely driven by a deliberate decision to progress several high value upstream research projects, upstream resource projects that were ready and matured to move forward. And now we’re trailing down to what I consider a more of a normal spin pattern of just shy of $37 billion. Now the upstream has dropped off a little bit more than the down – it’s dropping off little more than that as the downstream in chemical are increasing their spend pattern. But you can appreciate a lot of these projects that are in current progress, that if that CapEx profile will continue into the future. Our guidance is no different Phil, in terms of about just shy of $37 billion a year for the next couple, and we continue to invest to the cyclical nature of our business. Phil Gresh – JPMorgan: Okay. And then my second question would be, you obviously have a very strong balance sheet and stronger free cash flow generation, arguably stronger than most of your peers. So you’re in a pretty unique position to be potentially more aggressive in this period of weaker oil prices. So maybe you could comment about how you would think about that bigger picture, whether it’s the buyback program or opportunities with the portfolio?

Yeah Phil, I would tell you, I think you assess it up pretty good, clearly the financial flexibility we have with our current debt levels in our triple credit rating position us very well to respond to potential investment opportunities, whether that be additional resource developments, investment in our downstream or chemical business that provide us advantaged benefits to the industry. It really requires us to be able to maintain a very disciplined approach to capital allocation through the business cycle, while at the same time providing industry leading shareholder distributions. So if you think about our capital allocation approach, it’s first and foremost, invest in all of our attractive business opportunities that are accretive to average unit profitability and returns. Second is to continue to pay our reliable and growing dividends, and I’ll remind everybody that our dividends have grown about 10% a year over the last 10 years. And then lastly is, to return the cash to our shareholders through our share buyback program. As we’ve said in the past, our operating cash flows remain the primary source of funding for both of our capital requirements and our shareholder distributions. But we’ll access the financial markets when and if needed to meet commitments or capture opportunities.

Thank you. And we’ll now hear from Doug Terreson, ISI. Doug Terreson – ISI: Good morning Jeff.

Good morning Doug. Doug Terreson – ISI: So my question, regards to margin and profitability improvement as well. And you covered the mix of effects on new projects in – Abu Dhabi but you also mentioned asset management. So my question is whether these benefits that you guys are getting from asset management or of the strategic or operational variety. And so just some clarification on what you mean by that?

Yeah so as you know asset management has been a core component of how we manage our business. We’re constantly looking across the portfolio to assess how we could maximize the value of our assets, either through development or finding alternative means to go ahead and monetize those assets. So as a result, as you know, we have, had a very healthy program in terms of our divestment activities. In terms of our unit profitability, as I said year-on-year 2013, 2014-2013 the part of that increase in unit profitability was associated with our asset management efforts. By the way the example Doug, let me just remind you over the last 10 years, for instance, in our downstream we have reduced our refining capacity by more than 1 million barrels a day. Associated with divestment of about 20 plus refineries, we’ve divested over 200 fuel terminals, 38 blending plants and 6000 miles of pipeline. So it’s a very active program to make sure that we’re maximizing the value to shareholder, but also positioning us strategically to continue to perform at an industry leading pace in the future. Doug Terreson – ISI: Let me ask you one other question about this. So the company’s always done really well optimizing cost, but has there been, and has always been, a pressure on your cost for that reason but, is there a, maybe a step up in the effort to deliver sustained cost improvements that also may be affecting the results over the last few quarters?

We always focus on cost management, our cost structure Doug. I’d tell you that regardless of where we are in the business cycle, that is a fundamental part of our D&A is, how do we become even more efficient than we’ve had historically? And that’s not only through the highly qualified people we have working here at ExxonMobil but also the application, the technologies that we have in order to position ourselves in a, even a more effective manner to increase the value of those molecules. Doug Terreson – ISI: Okay. Thanks a lot.

And we’ll now go to Evan Calio, Morgan Stanley. Evan Calio – Morgan Stanley: Hey good morning Jeff.

Good morning Evan. Evan Calio – Morgan Stanley: Yeah, this is somewhat related to the cash flow question and discipline. What drives you to forward the 4Q buyback guidance at 3 billion, given the sequential commodity price drop or seasonality refining and that should do cash in 3Q and maybe in general what would commodity price do you need to slow the fly wheel or buyback or what the balance sheet, just kind of underwrite that through any potential downturn?

Evan, I would fall back on what I indicated previously on our capital allocation approach. It’s a decision that we manage internally around, whether our cash requirements in order to invest in the opportunities that we have in our portfolio. Its making sure that we continue to return cash to our shareholders through the dividend. And then we make a unique decision internally around how much additional cash are we to go ahead and distribute to our shareholders – stock buyback program. Evan Calio – Morgan Stanley: At this moment it’s a quarterly-by-quarterly assessments in those kind of an up and down overtime. Is that how it’s approached?

Yeah Evan I’d say it’s probably much more continual than that, but generally speaking there is, if you will, a decisive point on each quarter to decide what we’re going to do in the next – near future.

And moving on we’ll hear from Asit Sen, Cowen and Company. Asit Sen – Cowen and Company: Thanks and good morning.

Good morning Asit. Asit Sen – Cowen and Company: So two unrelated questions, first thanks for the color on U.S. onshore liquids, but wondering if you could quantify your production during the quarter if you could from U.S. and conventional.

Yeah, you bet Asit. Let me just share with you, the largest part of our unconventional U.S. liquids growth is in the Permian, Bakken and Woodford. And in total those are producing in excess of $210,000 barrels a day now. And as I said in my prepared comments it is, it has really been a significant progress over the last several quarters. I’d give you a little more color to that by saying that about 40% of that is in the Bakken, 35% in the Permian and the rest is in the Woodford. Great progress, I couldn’t be more proud of the folks there at XTO and the success they’ve had here in the recent past. Asit Sen – Cowen and Company: Thanks, very helpful. And second on LNG, could you comment on how global LNG pricing adjust to lower oil prices in comparison. There is a four to six month lag, but I wonder if you could comment on that?

Yeah, I mean broadly speaking the specifics of our LNG commercial agreements are confidential, but let me use Papua New Guinea as an example a majority of the Papua New Guinea volumes are contracted in excess of 95%. They are linked to a crude price and as crude price varies, so does that LNG.

Thank you we’ll now hear from Blake Fernandez, Howard Weil. Blake Fernandez – Howard Weil: Good morning Jeff, thanks for taking the question. Over the past six months or so, you’ve announced a couple of investments in the downstream in Europe, which seems a little bit countered to what we’ve seen from peers. We’re basically trying to reduce their capital employed in the area. And I’m just curious if Exxon is maybe taking a different view on the macro longer-term. Or if it’s a scenario where you feel you have superior assets where, over time maybe just capacity rationalization occurs. And you’re last standing with an unattractive asset?

Yeah. Blake thanks for the question and the interest in that area. Clearly we are stepping out and distinguishing ourselves, but let me step back just a little bit and talk about the European portfolio and then the downstream investments. I mean clearly Europe is disadvantaged by overcapacity. And some of which is driven by the lower cost feedstock in the U.S. and the Middle East. This sector will continue to rationalize existing capacity. ExxonMobil’s European assets though are advantage versus our peers due to the more efficient operations. And the integration that we have with our chemicals and lubricants manufacturing businesses. So you’ll see us continue to invest in the business cycle in order to enhance our advantage position. Now specific to those investments, they are always focused around key areas like lowering our raw material costs, increasing our higher value product yields, expanding logistics capability and flexibility. And then our main stay of reducing the operating cost structure. Ultimately to high grade the products to capture market demand. So if I focus specifically by way of example on the investment in the Antwerp delayed coker, that’s around investing in conversion capacity to take lower product, lower yield product, such as the fuel oil and convert it to disciplined advantage where we have higher volume and more margins. Blake Fernandez – Howard Weil: Thanks. I’ll take one more if I could, you may not be able to answer this, but you mentioned the discovery in the Kara Sea which University-1. If I’m not mistaken I’ve read some press article suggesting that Rosneft may decide to pursue the additional drilling on their own due to the sanctions and what not. I’m just kind of curious how that would unfold with regard to your relationship there. And participating in future interests?

Right, well Blake thanks for the interest. Clearly this is an important area for the industry in total. And we certainly appreciate the interest. Let me first start off by just recognizing the success of the well, I mean we’re extremely proud of what the organization has achieved in an extraordinarily remote arctic region, both from a logistics and a drilling perspective. The team successfully completed the well with the utmost concern for safety and the environment. And that really does speak to the strength and capability of the organization. As I said in my prepared comments, I can confirm that we encountered hydrocarbons, but this is a very large area. This acreage is over 31 million acres. We’ve got one penetration in that, so it is premature to make any assessment or really say anymore at this point. We are currently evaluating results to assess the Woodford plants, we’ll move forward on. I will remind you that ExxonMobil has a very longstanding and successful business in Russia, built on an affective and mutual beneficial relationship with the Russian partners.

Moving on we’ll hear from Jason Gammel, Jefferies. Jason Gammel – Jefferies: Thanks very much. Two questions for me Jeff. The first on the accelerated drilling onto North America, I know that Exxon is a company that will invest throughout the pricing cycle, but I was just wondering if the number of rigs that are being employed in this place is going to be affected by the change that we’ve seen in pricing conditions just over the last several weeks. Essentially what level of onshore price would you need to see before you can perhaps start laying down rigs? And then the second question, one of your primary competitors, just this week, successfully IPO’ed – MLP with pipeline assets. And there’s evidently a pretty big value gap between what the stock market is willing to pay for those assets through MLP and an integrated oil stock. Have you considered any form of MLP type of transaction with your pipeline assets?

Yeah, Jason thanks for those questions. Let me first start with the unconventional, as I said really good progress, I gave a lot of details about it, very proud of what the XTO organization is achieving up there. Let me say that, these near-term price fluctuations are not going to have an impact on our operational activities. We test all of our investments across a range of economic parameters including price. And I’ll just say at a high level that our current drilling programs and inventory are fairly robust in this price environment. So we’re very confident with the drilling activity as I indicated, we are picking up rigs, so that we can continue to progress our resource development activities. And it is a very significant part of our growth opportunity and importantly our improvement in overall profitability. More specifically on the master limited partnership question. I talked a little bit already about our asset management program that is a fundamental aspect of how we do our business. And it’s around making sure that we’re making the right choices there that are maximizing value for the shareholder. We have, through the course of that process; we have really divested or monetized all of our non-strategic assets. So we’ve been doing a lot of work you’re hearing some folks do today. The remaining assets that we’ve got in place are very strategic to the integrated model that we have between the upstream, downstream or on chemical business. The MLPs are generally used as a financing mechanism to raise cash and fund business growth, as you know with our financial flexibility we have very low cost to capital. While I will never say no, I would tell you that just the cost benefit tradeoffs for MLPs running attractive for us given our low cost to capital. Jason Gammel – Jefferies: Very helpful. Thanks Jeff.

Thank you, Jason.

Your next question comes from Roger Read. Wells Fargo. Roger Read – Wells Fargo: Hi good morning.

Good morning Roger. Roger Read – Wells Fargo: Just maybe going along with that sort of capital allocation and other questions that have come on here. So CapEx plus or minus 37 billion, or maybe I should say minus 37 billion here going forward. You just made the comment, a lot of the non-strategic assets have impaired. If we do find ourselves in a, let’s say $80 to $85 oil environment, between the share repurchase program at around 3 million a quarter, the CapEx at 37 billion. And maybe not as many assets left to sell, at least from a non-strategic or non-core standpoint. How do you balance all of that, what gives, is it CapEx that gets pulled back, is it the share repurchase or is the –?

And I don’t want you to walk away from this thinking that there won’t be any other divestment opportunities, because it is a continual process. Think of it as an ongoing upgrade of our overall portfolio whereby we continue organic exploration, identify higher up value assets, we continue to high-grade our down streaming chemical facilities. So it’s an ongoing process that will likely continue to yield periodically divestment opportunities, Roger Read – Wells Fargo: Okay thanks, and taking another look at your lower 48 unconventional opportunities and ranking those in terms of returns or growth plus returns to some of your other opportunities, how do they scale up, or maybe as you just said, what is your best return opportunity today and where they fit in relative to that?

Yeah, I would tell you Roger that they all are very strong. There’s a lot of variability even within a given resource area depending on where you are in the trend. And I would tell you that ExxonMobil has prime acreage in all three of the areas that I talked about, as well as some others. So we are very well positioned, and as you saw with the Permian basin, we continue to look for opportunities to high-grade the overall portfolio on those basins, so very strong inventory that we continue to high-grade and look for opportunities for progressing the investment opportunities in each one of those fields. So we would not expect any change in our operational plans, thank you Roger.

Moving on, we’ll hear from Allen Good, Morningstar Investment Research. Allen Good – Morningstar Investment Research: Good morning, just another follow-up question on the lower 48 unconventional, as you mentioned you’ve been pretty active in Permian acquisitions. I just wonder what’s Exxon’s thought, as far as what’s the right size Permian position that you eventually want to get to, to get that to scale. And is there a preference for Permian acquisitions to relative to Woodford and Bakken or is it just been a case of value?

Yeah Allen, it’s always a case of value for us. I wouldn’t say that we are excluding any opportunity in the US or internationally. Now we have found a number of opportunities to high-grade the portfolio in the Permian recently, but we continue to keep very well alert to other opportunities that may come up. And maybe even with the current decrease in prices, we may have additional opportunities that we’ll find they are complementary to our business and can increase our overall underlying value. And I would take that – I’d extend that beyond the U.S., we’ve leveraged the expertise within the U.S. unconventionals to position ourselves strategically for other unconventional opportunities globally. Allen Good – Morningstar Investment Research: Great, thanks. And just one on the downstream, Exxon obviously has a very large downstream global footprint, can you give us any color on what you’re seeing as far as the demand side, given the slide we’ve seen in oil prices. And a lot of concern out there is, I’m not saying on the supply side, but weak demand. I was just wondering if you’ve seen any changes in the demand patterns of late, given the lower prices.

Yeah, well I mean as I said in the presentation, we did some margin improvement, but generally demand has been fairly strong within the U.S., particularly in our chemical’s business. But in Europe, Asia Pacific, demand has been down and that’s really a function of building capacity faster than demand, as well as economic weakness. But you’ve got to step back from a chemical’s perspective, for instance, we’re expecting demand to grow at 1.5% above GDP. And we’re a long-term business where we invest for the long-term and it’s all fundamental to energy outlook, and demand projections.

Our next question comes from Paul Cheng, Barclays. Paul Cheng – Barclays: Hey Jeff, good morning.

Good morning Paul. Paul Cheng – Barclays: Well first, just want to add my welcome to the Investor Relations.

Thank you Paul. Paul Cheng – Barclays: Several quick questions, on the page 11 of your presentation, the other is a negative $1.1 billion comparing to the second quarter. In the second quarter there’s about $1.6 billion of the other sales gain related to the Hong Kong power. And your exploration expanse is lower, so then maybe adding another 100 million, 150 million in earning. So that’s about $300 million to $400 million of other benefits. Can you help us with that in terms of what that benefit may be, the nature?

Yes, so you’re looking at, Paul, the sequential earnings reconciliation? Paul Cheng – Barclays: That’s correct.

Yeah, so as I said in the presentation, that was down about $1.1 billion and I would, at a high level, say that its asset management is down about 1.3. It’s a net effect of the absence of Hong Kong power as well as other acquisition activities that occurred during that period, as well as, I think you appropriately pointed out, that other operational items were positive by about $160 million, due to lower OpEx primarily in exploration as well as some minor for ex-benefits. Paul Cheng – Barclays: So you’re saying that there was a swing is 1.3, so that means we have about 300 million or so, sales gained in this quarter?

Yes, that’s correct.

We’ll now hear from Ian Reid, BMO. Ian Reid – BMO: Hi Jeff.

Good morning Ian, how are you? Ian Reid – BMO: Yeah, very good. Can I ask you a quick question about Papua New Guinea? Now you’ve got the first part of the project, or at least phase 1, fully on-stream, what is your thinking about adding the third train, utilizing the additional gas which a joint venture has discovered in the region. And also, potentially processing third party gas or building another train to process third party gas. Can you just kind of outline Exxon’s thinking about that?

Sure Ian, thanks for bringing up Papua New Guinea because it’s another very successful accomplishment for the organization. I would tell you that everything is on the table, in terms of what we do there. Obviously, first and foremost, is that in terms of our priorities is to make sure that we are very comfortable, the operating structure, as I said, started up early. We got up to peak production, is operating very, very well, the project team and operations organization has done a remarkable job there. You’re aware that there’s some – we maintain an active exploration program in Papua New Guinea. We have picked up some additional resource; there are some other exploration opportunities that we’re considering. And I would tell you that the next step would be to consider – and has been under review, the economic viability for incremental trends, here at the LNG plant. It was designed in order to easily tie in additional trends, so we’re very well positioned. And as you can appreciate, the incremental cost expand the PNG facilities is going to be much, much more competitive than other Greenfield site. So in summary I’d say that we’re very pleased with the resource, the overall potential and performance of Papua New Guinea. We’ve got some additional resource out there with the successful P’nyang discovery. And we’re looking for opportunities to add to it, and that can come, either through additional resource development or, as you indicated, processing third party gas. Ian Reid – BMO: Okay, thanks. And just one further thing, on the Russian sanctions, how is that affecting your Sakhalin developments, and also the LNG project which you’re progressing with –?

Yeah, very good. I feel to mention that when we were talking – Ian Reid – BMO: [indiscernible] loss of PSE volume as result of rising oil prices can you provide some sensitivity on earned up there and how much production you get back if oil stays around $85?

Well Jason, I don’t have the specific numbers at the price that you stated but I would tell you that sequentially in our sequential earnings that there were some positive effects to, associated with PSE volumes. It was under 10,000 barrels per day, second quarter to third quarter. Ian Reid – BMO: Got it ok that’s all for me.

And we’ll now hear from Ryan Todd, Deutsche Bank. Ryan Todd – Deutsche Bank: A question you already touched on CapEx and CapEx outlook a few times during the call but if we take step back and look a number of your European peers, there’s been kind of a clear trend and may be for a variety of reasons, clear message and strong efforts towards capital constraint deferral of certain projects and free cash flow going forward from that point of view? It’s been a bit more muted here in the U.S. may be how, if there’s been a shift in your approach to project economics and relative returns and profitability as you, like your go forward portfolio and the potential of the constrain more CapEx or prices impacts there whatsoever?

We always are our ends are set well in advance as I said earlier our investment, full range of economic parameters including price so that we have the comfort, that we’re going to end up regardless of the type of price fluctuations that we feel like the program is robust. Or any great business model is that we invest into these business cycles and we’ve got the financial projects if we need some additional capital. Ryan Todd – Deutsche Bank: Specifically on Tanzania you guys have discovered enough lot of gas to date can you give us any thoughts in terms of timing, in terms of your expectations and go forward plans there?

Yeah. So on Tanzania a very good progress between Statoil and ExxonMobil as I said certain gas discoveries, now over 21 TCF in place. There is a consortium that has come together they have evaluated potential sites for common onshore LNG facility and we have made plans on site location. Studies are progressing to determine the development it really is in really early stages and it’s really too early to determine a specific startup date. Overall design capacity or even the capital investment, but fundamental for us environment is to ensure that an investment of this scale and complexity is to generate an acceptable return for our shareholders.

And our next question will come from Paul Sankey – Wolfe Research Paul Sankey – Wolfe Research: Good Morning, just to confirm me to – on this CapEx question we keep coming back to is an interesting number again to be clear about peak of CapEx in 2013. And then you said next year’s interesting variation in your spending for example even in the latest quarter we had downstream in chemicals. And beyond that, beyond the 37 net CapEx in the longer term future given that you’ve highlighted to the extent to which you reached to peak in 2013 as a function of recapitalizing the upstream?

Right Paul, so as I said we grew up $42.5 million in 2013 and again I want to make the point that the resource opportunities that we had before us and the maturity of those and the confidence that we had that we would generate very favorable returns for our shareholders likewise it is a conscious decision to bring our upstream spending down to a normal spend pattern. And as we communicated in early this year in our Analyst meeting we were projecting not to pull down to just south of $37 billion over the 2015 to 2017 period. And yes there is this larger increase in the downstream and chemical business and that is focused on like I talked upon Antwerp focused on making strategic investments that are going to better advantage our downstream facilities, relative to industry such as the North America ethane cracker at Baytown. Paul Sankey – Wolfe Research: Level of CapEx, what do you mean by that? How do you define that normal level?

Well if look at the resources going forward Paul it’s based on our judgment when those resources are going to be ready whether it be the definition of the resource, the definition of the development concept the regulatory or when we believe they are ready to move forward and we have an optimal development, that’s really what I mean by normal looking at our portfolio as opposed to when we saw these really large projects that came to provision together that – Paul Sankey – Wolfe Research: And just coming back to the PSE question obviously if prices were to stay here you spoke about two Q3 obviously it is relatively minor oil price shift, at the moment you are guiding to $4.1 million barrels a day next year. I assume that you’re continuing with the guidance like that in the Analyst meeting but the obvious expectation be that, that number would come in higher as a result of lower oil prices even though I know, there’s a different coalition around economics but broadly speaking that would be what we should work towards, right?

I think Paul I would – in March at the Analyst meeting. Again we look at the range over a period of time it’s going to drive what the prices do and we make our best judgment as to where we’re going to fit in that in order to give you that guidance. So if you think about what we said back in Analyst meeting we said that we would grow from about $4 million barrels a day up to $4.3 million barrels a day. 1 million oil-equivalent barrels a day by 2017. And doing so we are adding up the and I’ll mind you that a large part of that 95% plus was liquids and liquids linked gas production. So it will change our production mix by about 64% liquids and liquids linked to just south of 70% in 2017. So in summary I’d say our guidance on volumes is still consistent with what we shared with you in March. Thank You Paul.

Moving on we will hear from Alastair Syme, Citi. Alastair Syme – Citi: Hi Jeff couple of very good questions, can you maybe highlight little bit about how much you’re spending on the U.S. shale piece is that something you’d be willing to – and secondly just picking up on the comment you made about Qatar

[indiscernible].

Our next question comes from John Herrlin, Societe Generale. John Herrlin – Societe Generale: Yeah, thank you. Most of the things been asked Jeff, but regarding the shale economic thresholds in North America with the Bakken, it sounded like you have a different kind of completion, it’s not plug and perf, its somewhat different. Can you elaborate a little bit more, and also with that completion are you also doing similar thing in Argentina?

Yeah, good question John. I would tell you that, as I said in my comments, the XTO expertise that we built up in the unconventionals is being leveraged globally. And we are continuing to grow our capability there. As I shared in my prepared comments the improvements that we’ve seen, not only in reducing overall cost, but improving the productivity of, if you will, the manufacturing process of drilling these wells. But a key element of that has been the application of technology. And as I said in my prepared comments, one of the benefits that we’ve used in Bakken has been this completion technology, which is proprietary ExxonMobil technology called the XFrac. And that allows us to avoid putting a whole bunch of plugs in the well and makes it a much more efficient and safer operation for completion installation. And to close on your question about Argentina, I’d broaden that and say that, that all of these learning’s and they’re conventional to apply elsewhere within our portfolio. And once again its, it’s just another leading performance in our capability, and that positions us very well to compete for resources. John Herrlin – Societe Generale: Great. Thank you very much.

Thank you John.

We’ll now hear from Guy Baber, Simmons & Company. Guy Baber – Simmons & Company: Thanks very much for squeezing me in here. Two quick ones for me, first question around exploration, but generally speaking, can you just remind me what percentage of the total capital budget this year is allocated to exploration appraisal activity. And then optimally, where would you like to see that percentage longer-term, just to sustain the long-term opportunities that reserve maturation, but also how comfortable you maybe in flexing that down at any point in the cycle for any given year. So that’s number one, just thoughts on the exploration budget. And then secondly, just if you could quickly talk about the balance sheet, but you mentioned your excess financial markets if need be and your net debt to total cap obviously low compared to most peers. But actually high, relative to where it’s been at the last 10 year period. But could you just remind us of your target leverage ratios and framework also. And just where you’re comfortable in taking the leverage?

Yeah. Guy let me first with the second, after your first question about whether we would flex down our exploration. I would tell you that we are opportunity driven, we got – in the well, we’ve got a very robust inventory. It’s a – we’re very well positioned to compete, as I said earlier, it’s all around how do you upgrade the value of overall resource base. So from an expert, we have really got to be focused on the horizon around high grading our portfolio, specific to our budget, we don’t break that type of information out in terms of risk. Components within the exploration budget, but I’d like you to think about our exploration activity as a means to further high grade our overall portfolio. On the second point on our leverage ratio, there is no target. We’ve been fairly consistent over the last couple of years. We’ve maintained the triple A credit rating. I want you all to think about it, our focus is around value. It’s not always – or not a focus around market share or volume, it’s around value, how can we create greater value? And we’ll use that balance sheet to achieve that objective when we think it’s appropriate.

Our next question comes from Pavel Molchanov, Raymond James. Pavel Molchanov – Raymond James: Hey thanks very much. Just one more for me on Russia if I may, you touched on the policy sanctions related uncertainty on relation to the Archadeck. Are there any other uppered or reduced because of the sanction rules?

Yeah, so you may recall a number of joint ventures throughout Russia, we talked about the Kara Sea. We also have a venture in the Black Sea and West Siberia, and then lastly, a number of ventures within the Russian arctic ship. And if you think about the sanctions, they deal with specifically deepwater, unconventional resources and arctic activity. So , the joint ventures I just summarized for you, are included within the scope of the sanctions. Pavel Molchanov – Raymond James: So have all the activities in those JV’s been suspended as a result?

Well we have – we are fully complying with the sanctions and regulatory requirements.

And we do have one follow-up question from Paul Cheng, Barclays. Paul Cheng – Barclays: Hey Jeff – we need to know your investment in Europe refining. Do you have any plan to do a safe system? Second question, I think in your comments you were saying that you have a spec in the quarter, and also at the end of the third quarter from the inventory underneath or overneath. Thank you.

Thank you Paul. On your first question around investments, I would just say broadly that we regularly evaluate our global portfolio where we have offered investment. As I’ve already discussed, with areas targeting on things like expanding our feed logistics or reducing our cost structure. We have a lot of – and generally speaking Paul as a matter of practice we just don’t want to comment or speculate on any particular opportunities or investments, maybe not be considering. When they’re ready we will and we’ve made a decision. We’ll go ahead and ensure that more broadly. The second question was around over lift. And I’ll just, if I can, I’ll refer back to our quarter-on-quarter upstream earnings reconciliation. And if you remember there was a volume mix component about the positive $340 million. And first and foremost there was a fairly sizeable component associated with project, high margin project and program activity of over $500 million. And as I said during my prepared comments, it really highlights the progress that we’re making on our unit profitability in the higher value volumes. Not for the sake of growing volumes, but for the sake of capturing value. There was an over lift component that was positive. And then there was an offsetting decrease in a number of various, such as entitlements, decline, downtime and some asset management.

That does conclude today’s question and answer session. Mr., Woodbury at this time, I would like to turn the conference back to you for any additional or closing remarks.

Well to conclude, thank you all for your time and your interest this morning. Certainly, very good questions and I do look forward to further dialogue with you all in the near future, thank you.

And that does conclude today’s conference, thank you all for your participation.