David Rosenthal – VP, IR

Evan Calio – Morgan Stanley Douglas Terreson – ISI Group Inc. Doug Leggate – Bank of America Merrill Lynch Edward Kelly – Credit Suisse Paul Sankey – Deutsche Bank Blake Fernandez – Howard Weil Jason Gammel – Macquarie Asit Sen – Cowen & Company Faisal Khan – Citi Roger Read – Wells Fargo John Hurling – Societe Generale Allen Good – Morningstar Pablo Mockonoff – Raymond James Katherine Minyard – JPMorgan Paul Cheng – Barclays Good day, and welcome to this Exxon Mobil Corporation Third Quarter 2013 Earnings Conference Call. Today’s call is being recorded. And at this time for opening remarks, I would like to turn the call over to the Vice President of Investor Relations and Secretary, Mr. David Rosenthal. Please go ahead, sir.

Good morning, and welcome to Exxon Mobil’s third quarter earnings call and webcast. The focus of this call is Exxon Mobil’s financial and operating results for the third quarter of 2013. I will refer to the slides that are available through the Investors section of our website. Before we go further I would like to draw your attention to our cautionary statement shown on slide two. Moving to slide three, we provide an overview of some of the external factors impacting our results. Global economic growth remained constrained in the third quarter with mixed performance across the region. The U.S. economy continues to grow at a moderate pace, following an upward revision of second quarter growth. China’s growth improved modestly while European economies remain uncertain. Energy markets delivered mixed results compared to the second quarter with higher crude oil and lower natural gas prices Global industry refining margins deteriorated significantly reflecting moderate demand and improved capacity availability. Chemical commodity product margins strengthened during the quarter on lower feedstock costs and increased U.S. demand. Turning now to the third quarter financial results as shown on slide four. Exxon Mobil’s third quarter earnings were $7.9 billion or a $1.79 per share. The corporation distributed $5.8 billion to shareholders in the third quarter through dividends and share purchases to reduce shares outstanding. Of that total $3 billion was used to purchase shares. CapEx in the third quarter was $10.5 billion and $32.6 billion for the first nine months of 2013 in-line with anticipated spending plans. Cash flow from operations and asset sales was $13.6 billion. At the end of the third quarter cash totaled $5.7 billion and debt was $21.3 billion. The next slide provides additional detail on third quarter sources and uses of funds. Over the quarter cash increased from $5 billion to $5.7 billion. Earnings, depreciation expense, changes in working capital and other items and our ongoing asset management program yielded $13.6 billion of cash flow from operations and asset sales. Uses included additions to plant, property and equipment of $9.1 billion and shareholder distributions of $5.8 billion. Additional financing and investing activities increased cash by $2 billion. Share purchases to reduce shares outstanding are expected to be $3 billion in the fourth quarter. Moving on to slide six and a review of our segmented results. Exxon Mobil’s third quarter earnings of $7.9 billion decreased $1.7 billion from the third quarter of 2012. Lower downstream earnings were partly offset by higher upstream and chemical earnings. In the sequential quarter comparison shown on slide seven earnings increased by about $1 billion across all segments, reflecting higher upstream realizations, lower refining maintenance, improved chemical commodity margins and lower corporate and financing expenses. Guidance for corporate and financing expenses remains at $500 million to $700 million per quarter. Turning now to the upstream financial and operating results and starting on slide eight. Upstream earnings in the third quarter were $6.7 billion, up $740 million from the third quarter of 2012. Stronger prices increased earnings by $440 million as worldwide crude oil and natural gas realizations increased by $2.85 per barrel and $0.56 per 1,000 cubic feet respectively. Reduction volume and mix effects increased earnings by a net $20 million, as the benefit from higher liquid volumes was mostly offset by the impact of crude under lifts and lower natural gas production. All other items, mainly favorable tax and foreign exchange impacts increased earnings by $280 million. Upstream after tax earnings per barrel for the third quarter were $18.16. Moving to slide nine, production increased by 58,000 oil equivalent barrels per day or 1.5% from the third quarter of last year. Liquids production was up $83,000 barrels per day or 3.9%. Lower downtime, mainly in Nigeria, the U.S. Kazakhstan and Canada ramped up at the Kearl and Nigeria Satellite projects and continued increased production from liquids rich unconventional plays in the U.S. were partly offset by field decline. Natural gas production was down 147 million cubic feet per day. As expected lower U.S. production and field decline in several areas were partially offset by lower downtime, mainly in Qatar and project ramp-ups. Turning now to the sequential comparison starting on slide 10, upstream earnings increased by $408 million versus the second quarter. Realizations increased earnings by $410 million as worldwide crude prices increased $7.67 per barrel and natural gas realizations decreased $0.53 per 1,000 cubic feet. Volume and mix effects decreased earnings by $150 million as increased liquids production was more than offset by the impact of under lift in a number of regions including the North Sea and West Africa and by lower natural gas production in Europe. Other items had a positive impact of a $150 million, primarily reflecting the absence of exploration cost reimbursement to Rosneft in the second quarter. Moving to slide 11, oil equivalent volumes were down 1.4% sequentially. Liquids production increased 17,000 barrels per day, mainly due to project ramp-ups in Canada and Nigeria and lower overall down time partly, offset by field decline. Natural gas production was down 440 million cubic feet per day sequentially. Lower seasonal demand in Europe and field decline were partially offset by lower down time in Qatar. Our year-to-date production volume performance continues to be in line with the projection presented at the analyst meeting in March with strong up time performance increased North American unconventional liquids production and higher European gas demand for the year offsetting the slower than anticipated ramp up of Kearl. We remain on target to meet the 2013 volume outlook presented at the analyst meeting. Moving now to the downstream financial and operating results starting on slide 12. Downstream earnings for the quarter were $592 million, down $2.6 billion from the third quarter of 2012 due to lower global refining margins of almost $2.4 billion. Volume and mix effects increased earnings by a $150 million, driven by lower refining maintenance. Other items reduced earnings by $380 million including the absence of gains from the Switzerland investment. Turning to slide 13 sequentially third quarter downstream earnings increased by $196 million. Lower global refining margins decreased earnings by $870 million while volume and mix effects increased earnings by $500 million, reflecting reduced maintenance activity. Other items increased earnings by $570 million primarily due to the absence of the Dartmouth Refinery conversion costs, lower maintenance expenses and favorable foreign exchange impacts. Moving now to the chemical, financial and operating results and starting on slide 14. Third quarter chemical earnings were just over a $1 billion, up $235 million versus the prior year quarter due mainly to stronger margins from higher commodity realizations in all regions. Moving to slide 15 sequentially chemical earnings increased by $269 million. Improved commodity margins helped by favorable feed cost in the U.S. increased earnings by a $110 million. Strong U.S. commodity sales volumes further increased earnings by $60 million. Lower cost associated with Singapore’s new steam cracker start up and lower plant maintenance favorably impacted earnings by a $100 million. Moving next to the third quarter business highlights, beginning on slide 16th. The next two slides provide an update on upstream projects which recently started or will start production next year. Beginning with the 2013 project start-ups; at Kearl we are currently producing at or above 100,000 barrels per day. Over the past few months we have undertaken normal start-up related fine tuning and synchronization activities of our facilities, which are not unusual for our new operations of this scale and magnitude. Kearl incorporates a number of technology innovations such as our proprietary froth treatment process which significantly enhance environmental and reduce capital investment. Successful application of this new technology was confirmed as Kearl bitumen is now being processed at a number of Exxon Mobil and third party refineries. The Kearl expansion project is on budget, on schedule and now nearly 60% complete. Fabrication and assembly of pipe rack and equipment modules for the bitumen processing plant are progressing in Edmonton and are 80% complete. Learnings from the initial development are being applied to the construction and commissioning of the expansion project. On the logistics side Enbridge initiated construction of the Woodland mainland pipeline which will extend 385 kilometers South of Cheecham to the Edmonton terminal and connect with refineries and export pipeline. This new pipeline will have an initial capacity of 400,000 barrels per day with the ability to expand to approximately 800,000 barrels per day depending on crude viscosity. The Kipper-Tuna Turrum project in Australia has started with gas production from the Tuna Field via two new gas pipelines and first oil production from the Turrum Field through the new Marlin B platform. This project represents the largest new domestic oil and gas development on the Australian eastern seaboard. With reserves of 1.6 trillion cubic feet of gas and 140 million barrels of recoverable oil and gas liquids. Kipper-Tuna Turrum will help secure East Australia’s energy future. First production from Kashagan was achieved in September and production ramped up to near 80,000 barrels per day. In late September again and earlier this month traces of gas were detected along the onshore gas pipeline route from one of the production and drilling islands to the onshore processing facility. The operator is currently investigating the root cause of the events and it is now anticipated that inspection and investigation will take some weeks to conclude. Production will remain shut-in until this work is complete. Turning now to slide 17 and an update on some of our projects scheduled to start-up in 2014. The PNG LNG project is now more than 90% complete. We achieved several important milestones during the quarter including completion of drilling at the first well pad and starting the commissioning phase at the LNG plant in preparation of production startup in the second half of 2014. The plant has now been pressured up with gas to initiate power generation and enable testing of key facilities and equipment. The estimated cost of the project remains at $19 billion, reflecting disciplined project management and a unique and challenging work environment. The Cold Lake Nabiye development Canada is 60% complete and progressing per plan towards a 2014 startup. This is another long plateau development which will access or resource 280 million barrels of oil and produce an additional 40,000 barrels of bitumen per day. The Nabiye project includes a new steam plant, field production pads and associated facilities. Equipment installation is well underway and six of the seven initially planned drilling pads for 24 wells each have been completed to-date. Moving next to Qatar, the Barzan project is another major step in our long and successful relationship with Qatar Petroleum. All of the 30 production wells are now complete and the well head platform top sides have been installed. Start-up is planned for late next year. When completed, the project will provide gas to the State of Qatar to meet the country’s growing need for clean burning natural gas. The first phase of the project is to supply about 1.4 billion cubic feet of gas per day together with the sale of associated condensate LPGs and ethane. Also in Qatar the Helium 2 plant project operated by RasGas started up during the quarter. The plant is expected to produce approximately 1.3 billion cubic feet per year when fully operational. The Helium 2 plant is the world’s largest helium refining facility and makes Qatar the largest exporter and second largest producer of helium in the world. As Qatar continues to reliably supply international markets with LNG, extracting helium from the produced gases is a profitable, value added activity which helps meet the world’s ever growing demand for liquid helium. Turning now to slide 18 and an update on our progress in Russia, I will start by highlighting another milestone in the successful Sakhalin-1 development. The consortium marked 10 years of drilling success pioneering the industry’s extended reach drilling technologies while leveraging Exxon Mobil’s 90-year history of Arctic expertise. Since 2007 a number of world records in extended reach drilling have been set by the Sakhalin Yastreb rig at the Chayvo and Odoptu fields. Today 23 of the 30 world’s longest extended reach wells are Sakhalin 1 wells. The current world record is held by a Sakhalin 1 well which was drilled at the Chayvo field earlier this summer to a length of 12,700 meters. Exxon Mobil’s proprietary technology has minimized drilling vibration and improve overall economic efficiency while reducing the environmental footprint of the Sakhalin-1 project. Drilling with emphasis on safety, flawless execution and implementation of unique drilling technologies have made Sakhalin 1 a premier project in the global oil and gas industry. Now turning to our Arkutun Dagi, this will be the largest offshore oil and gas production platform in Russia making the Sakhalin shelf a model for Arctic and sub-Arctic project developments. Construction of the top sides was completed in Korea earlier this year and commissioning of the drilling rig and top side facilities are 40% complete. Installation of the top sides onto the gravity based structure next year will set a new world record for float over installation offshore at 42,000 tons. Start-up is planned by the end of next year and production will peak at around 90,000 barrels per day. In West Siberia, operations for the pilot program are underway. Instead of drilling new wells we entered and deepened existing well bores which has sped up the process to acquire the new petro-physical log data and for samples. This information will help identify key produce ability parameters for the [Baginov] and help optimize new horizontal drilling locations planned for 2014. In preparation for exploration drilling in the Kara Sea the Rosneft ExxonMobil joint venture recently completed a month long ice defense field trial to test CIs and Iceberg tracking in systems that will be used to protect the drilling rig. All operations were successful and completed safely. ExxonMobil’s Arctic leadership and continued successful execution of Sakhalin 1 positions us well as we prepare to ramp up the exploration program in the Kara Sea in 2014. Also in the Black Sea, site surveys were completed in preparation for drilling to begin in late 2014 or early 2015. Turning now to slide 19, and an update on our global and broad exploration program. In September, drilling started on the Mronge 1 Wild Cat in Block 2 Offshore Tanzania. The Mronge 1 well targets reservoirs equivalent in age to those successfully tested by the Zafrani and [Lavani] wells. In addition to another reservoir interval previously untested in Block 2. Further wildcat drilling is planned for 2014. In Argentina, Exxon Mobil spud the first operated well on the Bajo del Choique block targeting the Vaca Muerta formation. This is the first of three Exxon Mobil operated wells that will be drilled in sequence on the block. In Canada, Exxon Mobil in partnership with Imperial Oil acquired ConocoPhillips’ Interest in Clyden oil sands lease. The Clyden Lease is near Imperial’s corner lease holding and contains 226,000 gross acres of high quality oil sands amenable to the steam assisted gravity drainage or SAGD in-situ recovery technique. Turning to Brazil. Exxon Mobil was awarded the interest it successfully in bid for in May. Exxon Mobil required a 50% interest in the Potiguar Block and a 50% interest in the CR603 block totaling more than 750,000 gross acres offshore North Eastern Brazil. Exxon Mobil will be the operator for both blocks. In Gabon, Exxon Mobil has reached agreement to acquire a 30% participating interest in the offshore Arouwe Block, the operator Perenco along with the third party equity holder Tolo is planning a wildcat well in 2014. Turning now to slide 20 and an update on our North American liquids activity. In the Permian Basin, we are ramping up activities to develop both conventional and unconventional reservoirs across our leading position of 1.5 million net acres. We currently have eight operated rigs and have turned almost 100 wells to sales this year across the entire basin. Current net production is more than 90,000 barrels per day. More than 65 work over rigs are also active on our Permian properties increasing production by opening additional zones and performing fracture stimulation treatments. We are also optimizing development and expanding infrastructure in our CO2 projects in the Central Basin platform area in order to enhance oil recovery. We also continue to actively evaluate unconventional potential across our Permian acreage highlighted by the Wolfcamp, Wolfbone, Wolfberry and Bone Springs reservoirs. In the Bakken play our gross operated production recently hit a record 65,000 oil equivalent barrels per day. For the quarter oil equivalent production increased by 81% over the prior year quarter driven by a record 85 wells turned to sales year-to-date and the 2012 Danbury transaction. This volume increase reflects the benefits of well pad development drilling and optimized well completions across our core Bakken acreage. In the Woodford well reserves continue to be strong with peak 30 day equivalent production rates up 17% year-to-date. For example a recent five well pad competition had a peak seven day production rate just below 4,000 barrels of oil and 13 million cubic feet of gas per day. We also continue to develop infrastructure for our growing liquids production, recently putting in service a 65 mile oil gathering pipeline in the Ardmore area. In conclusion, in the third quarter we earned $7.9 billion, generated $13.6 billion in cash flow, invested $10.5 billion in cash flow, invested $10.5 billion in the business and distributed $5.8 billion to our shareholders. Business performance remains strong across our portfolio. In the upstream we increased liquids production from project ramp ups and lower downtime. Total production volumes are on target to meet the full year outlook provided at the analyst meeting. In the downstream refinery throughput increased upon successful completion of the significant plant maintenance activities in the second quarter. Chemical business results remain strong on increased commodity product demand and lower feedstock cost. Across the corporation CapEx is in-line with anticipated spending plans. Our cash flow remains strong and enables robust shareholder distribution. We maintain a long-term perspective on our business with a relentless focus on operational excellence and disciplined investing through the business cycle. As discussed in the business highlights we continue to progress a unique and diversified set of profitable growth opportunities which position us well to deliver long-term shareholder value. That concludes my prepared remarks and I would now be happy to take your questions.

Thank you, Mr. Rosenthal. (Operator Instructions) And our first question comes from Evan Calio with Morgan Stanley. Evan Calio – Morgan Stanley: Good morning guys, how are you?

Good morning Evan, how are you? Evan Calio – Morgan Stanley: I am good. May be I missed it in your opening comments on discussion on the cash balance but the additional financing investing item that’s should open the balance sheet meaning what was the change to debt in the quarter?

Yeah that was the $2 billion that was an increase in our debt. Evan Calio – Morgan Stanley: Okay. Well it may be premature I know you guys address this at the analyst day I mean but what are your thoughts with regard to potentially reducing CapEx on a go forward basis which has been seen primarily in Europe or using as you did in this past quarter some of your significant and potential leverage to continue to fund the buyback?

Evan if we step back to the analyst meeting in March we did show somewhat of a rollover in CapEx going forward particularly in the upstream with a little higher investment in downstream in chemical. And we will update that in the next analyst meeting but right now I don’t have any new number to give you and so that’s still a good outlook for us as we go forward. In terms of leverage on the balance sheet, no real change in kind of our approach. You have seen us over the course of this year increase leverage just a bit but that’s really get us back to where we were if you go back to about 2010. So if you look across the 2011 and ‘12 timeframe where we had significant cash flow, including from asset divestitures over those two years we’ve returned a lot of that cash to the shareholders. We also paid down a lot of debt and so this increase you are seeing this year really just kind of gets us back to about where we were. But no real change in approach to the balance sheet or distributions to shareholders. Evan Calio – Morgan Stanley: Great. I’ll leave it there. Thank you.

Okay, thank you.

Our next question comes from Doug Terreson with ISI Group. Douglas Terreson – ISI Group Inc.: Good morning David.

Good morning Doug. Douglas Terreson – ISI Group Inc.: I have a question about E&P and specifically after-tax profitability appears to have increased versus the year ago period in both the U.S. and international arena. But in your E&P earnings chart that you highlighted that didn’t indicated volume mix effects played much of a role in its improvement. So I wanted to see if you can provide some color on unit profitability, excluding tax and foreign exchange benefits? And specifically whether or not the trend is improving and really just any other drivers of E&P profitability that you are able to provide color on?

Sure I’ll be happy to provide a little more color on that. So if you are looking at quarter-over-quarter you see on the chart and I mentioned in my prepared remarks a net increase of about $20 million. We did have an under-lift this quarter of about 25,000 barrels a day in a number of areas including West Africa and the North Sea. And if we had not been under-lifted earnings would have been notionally $100 million or so higher. Douglas Terreson – ISI Group Inc.: Okay.

So that might have been more closer to what you expected. And we did see quite a nice contribution on the liquids side and that was offset a bit by declining as we expected and I talked about on the gas side of the business so if I look at the third quarter things came out really just about the way we expected, higher liquids particularly in some of our more profitable areas and then a decline in gas volumes, particularly in the U.S. And so as we talked about at the Analyst Meeting we are taking steps and we’ll continue to take steps to strengthen profitability. I think if you look at our third quarter results and the flow through of higher realizations to the bottom line I think our unit profitability actually went up a little more than our realizations did. So I wouldn’t want to take any one quarter and say we set a trend but we’re certainly starting to see the impact of the higher liquids volumes and a little lower gas volumes in the U.S. as we had expected. Douglas Terreson – ISI Group Inc.: Okay, thanks a lot David.

All right thank you.

Our next question comes from Doug Leggate with Bank of America Merrill Lynch. Doug Leggate – Bank of America Merrill Lynch: Thanks. Good morning David.

Good morning, Doug. How are you? Doug Leggate – Bank of America Merrill Lynch: Not too bad, thank you. I wonder if I can ask you about production volumes. I realize you got lot of projects on the ramp up phase and I guess slide nine shows that the year-over-year impact but can you help us understand what stage of their evolution the new projects are in? what I’m really trying to get to is most of the my questions are answered but are we at the point where the ramp up in the new, that stuff has started up already, is now enough to offset the underlying decline so that they can hit that inflation point of goal and then I’ve got a follow up too.

Sure Doug if you look particularly on the liquids side which is I know where the focus has been you’re certainly starting to see an inflection point of where we’ve been as the new projects have come online. I mentioned it’s really a mix. some things were doing a little better than we were expecting this year and that has more than offset little slower ramp up in Kearl. So if I were to step back and look at overall as the projects are coming online, the satellite projects in West Africa, the Kearl project et cetera we are starting to see a kind of turnaround that we talked about at the Analyst Meeting and we’ve been discussing since then. One of the other things that we’ve seen this year, particularly year-over-year is much lower downtime. Our operations are running very well this year we’re very pleased with the progress we have made. Particularly on the liquids side and some of our higher margin areas but also on the LNG side of the business. So when you have the combination of lower downtime on selling your better profitable barrel equivalents and the turnaround and uplift that you’re starting to see from the liquids production volumes including here in the U.S. you saw we had a nice increase just in the U.S. so I would say again, we don’t want to grab any one quarter. But if you are looking directionally and look at trends we are starting to deliver on the commitments that we have made and the projects that we have talked about, and then as I mentioned in my prepared remarks, as I look in 2014, our major projects are on schedule, on budget and we continue to be very pleased with our progress and as that continues on into the 2015 and 2016 timeframe. So we are on track to deliver that big wedge volume between year-end 2012 and year-end 2017 and things are addressing well. Doug Leggate – Bank of America Merrill Lynch: Thank you. My follow up David is really, I know you have been on the road a fair amount, since last several months and there seems to be I am really looking for you to qualify or at least put the debate to rest, there seems to be some debate over whether or not you are going to stick to your capital budget, as with your multi-year capital budget as laid out at last year’s Analyst Day, and in light of where the share prices is, I guess it goes back to Evan’s question, the share has been very awful this year on a relative and absolute basis, how is management thinking about the kind of reward, some of your overseas competitors apart by cutting back capital and how are you thinking about maybe even bit more aggressive on the buyback, taking advantage of or at least address the weakness that we’ve seen so far this year, and I will leave it at that. Thank you.

Thanks Doug, Let me kind of hit those three things. On the CapEx side there is no new outlook relative to what we said at the analyst meeting. We are certainly updating our plan now. We will update in March, but what we look at our investment plan that we showed you, we don’t have any information today that would suggest a major change from what we said. As oppose to regards the stock price the market determines that, we are executing on the things that we can control, flawless execution of the base business, making sure our assets are up and running when the margins is good as you seen in the chemical business this quarter, where up time rates were extremely high were capturing that value added there on the margin particularly in the U.S and then I mentioned the operations that we are having in the upstream. So if you are looking at the things really, generate shareholder value, short-term and long-term, running the business well, we are seeing that and bringing those big projects online and benefiting from the CapEx profile that we have in the last few years and you’ve seen that. In terms of the buyback, no change in the buyback. T continues to be a quarter decision, and I updated you on the fourth quarter, another $3 billion and we’ll have another update on that in the next earnings call. Doug Leggate – Bank of America Merrill Lynch: Thanks David.

Thanks.

We move now to Edward Westlake with Credit Suisse. Edward Kelly – Credit Suisse: Kelly is here. Just on the CapEx comment you made about CapEx rolling over. That’s presumably mainly the Celtic acquisition that you flagged in the Analyst Day.

If you look at where we are on CapEx, say we are in line with expectations, if you kind of step back to the analyst meeting, we have said we’d spend about $41 billion in total, we had about $3 billion in there for the Celtic so if you were to look at what we showed you, ex-acquisition that would have been about 38. As we sit here through the third year, and we take Celtic and add in the [Clyden] acquisition that’s about $4 billion around numbers. If you take the 4 billion away from the 32.6 you have seen year-to-date that’s 28 and change. So I don’t have another number for the end of the year. But from what we can see, we are going to be pretty close as we head through the fourth quarter and we are generally pleased with how we’ve been able to manage such a large project low this year and keep that CapEx discipline to bring this project in on budget. So again that’s a large number to close to call, for the year end but we feel pretty good about where we are at. Edward Kelly – Credit Suisse: And just to switch to the downstream in chemicals. Obviously in the second quarter you were still burdened with Singapore cost and you had as you flagged a lot of downtime. When you think about the third quarter operations as you look across the world, do you feel that’s a more normal kind level of operations that most of that are turnaround, and downtime activity was not in that quarter so it was clean.

Yeah when you look at we step back to the second quarter, we talked about on the last call, significant downtime a lot of plant maintenance. Again I am happy to say that we came out well that very successful on the turnarounds and the maintenance concluded in a safe manner, and that’s come out very well. As we come into the – as we came through the third quarter all of that equipment came back up fine, running well capacity utilizations doing well. So the third quarter is more of a kind of normal quarter, I guess if you are looking from that perspective. We have some minor turnarounds as we always do coming up but nothing specific. So as we look into the third quarter and as you saw from our earnings charts the margin hit was big, but the volume mix effects reflecting the turnarounds coming off and excellent operations boosted back we took what the market had on offer in terms of margins and we are able to take that to the bottom line. Edward Kelly – Credit Suisse: And may be one final one just on the sort of restructuring in the downstream of CV we’ve already taken some moves to improve the competitiveness of the refining assets relative to the market environment but any thoughts about being more aggressive here given some of the trends and some capacity adds and gasoline margins globally that we are seeing?

Yeah I wouldn’t want to give any guidance on specifically on that program. We did as you point out have a very successful multi-year program on some asset restructuring and some asset divestitures in the downstream, particularly during an up cycle in the business. So we certainly brought lot of value home to the shareholders. Going forward no big change in approach. We are always looking at all of our assets. We are always talking to people, people are approaching us and so we’ll see how that goes. So no change more aggressive, less aggressive just optimizing the business and bringing the value home whenever we have the opportunity to do so. Edward Kelly – Credit Suisse: Thanks David.

All right thank you.

And we’ve now to Paul Sankey with Deutsche Bank. Paul Sankey – Deutsche Bank: Hi David.

Hey good morning Paul. Paul Sankey – Deutsche Bank: David reading between the lines, are we saying that 2013 is it peak year for CapEx?

If you look at the chart that we showed in March it would indicate that this was a peak year and again I really don’t have a change to that. Our expectation is what we’ve seen which is the upstream CapEx would trend down, some of these projects come on and other ones continue to spend. As we mentioned we still believe we have some nice investment opportunities in both the downstream and chemical, and particular in chemical we’ve talked about our major expansion opportunity, potentially in the Gulf Coast with the new steam cracker and some polyethylene lines. We are expanding the specialties business elsewhere around the world. So those investments still look good. We do have some nice investment opportunities in the downstream that still look attractive. So I really don’t have any different signal or any different fundamental change in the opportunity set then what we’ve talked about this year. Off-course we’ll update that in March but as of now I don’t see any change to what we’ve talked about before. Paul Sankey – Deutsche Bank: Which would imply that it would be a peak year CapEx. And then the, I guess the risk there as you’ve highlighted is actually non-operated which is obviously the Gorgon Project.

Well I mean you know we do not have an update on the Gorgon Project and obviously be appropriate to defer to the operator for that kind of update but we don’t have an update on that project as of today. Paul Sankey – Deutsche Bank: And speaking of non-operated, could you, I think you mapped on this but could you just remind us what the contribution of cash again was in Q3 and what you anticipate it will be in Q4?

Yeah, it was fairly small and across the quarter. I don’t have that exact number I mean we came on line. It got up to 80,000 barrels a day and went down. Looking into the fourth quarter Paul I really don’t have any kind of an outlook or estimate for you. The operator is currently evaluating and inspecting the gas line and trying to get to the root cause of what happened there. And until we know that it’s hard to give an outlook. We just have to wait and see and find out what remediation if anything if necessary and how long that might take. But as you would expect that investigation and evaluation is ongoing as we speak. But we will stay shut in until it’s complete and I just don’t have any better outlook than that. Paul Sankey – Deutsche Bank: Understood David and then finally, could you just remind us something what you said here is your debt levels in the quarter rose, net debt rose but you maintained your buybacks. So in other words you are now increasing debt in order to buy shares is that a fair statement?

I would separate those two things, the share buyback is reflective of how things are going in the quarter and looking ahead at the business and our cash needs and cash avails. The debt is simply managing the capital structure on the balance sheet. We’re kind of up as I mentioned the levels that we work couple of years ago but still fairly conservative, lot of flexibility as we like to keep on the balance sheet. I think our debt-to-equity ratio and some of the other metrics that people look at on the balance sheet are all pretty much within where we’ve been kind of historically coming out of the low period we had as I mentioned in ‘11 and ‘12. So no really change in either approach or any other outlooks to offer in that regard. Paul Sankey – Deutsche Bank: Okay, thanks David.

Sure, thank you Paul.

Our next question comes from Blake Fernandez with Howard Weil. Blake Fernandez – Howard Weil: Hi, David good morning and thanks for taking the question. We’ve covered CapEx pretty well so I was just going to see if we could may be shift it over to divestitures. This may be a better question for the Analyst Day but some of your peers in Europe especially have definitely gone into a mode of more aggressively divesting assets and then it seems like Exxon in particular would certainly have quite a host of opportunities there. Are there any thought to may be take advantage of that in the marketplace?

Well I think the first thought I have is we don’t ever announce in advance what our divestiture plans are. Over time we kind of think we get a little better value in the market if we don’t announce in advance what it is we’re planning to do. And I really can’t again forecast any particular outlook in terms of the divestiture program. As we talked about in the past some of the divestitures you’ve seen in the last few years have been strategic or initiated from our standpoint. But several of our divestitures have actually been buyers, seeking our assets out because in their portfolio they view them as having more value than we value them in our portfolio and so when you have that type of a situation it’s very beneficial to make a transaction. We’re always looking at that. We’re always talking to people. But again no change in our approach in any of our businesses or across the asset management program in general. You did see us with about as I recall $20 billion over the last two years ‘11 and ‘12 in cash flow from asset sales; several billion dollars in earnings so that program was very successful. This has been a down year so far in that but again it’s not because we made any strategic decision or decided to change the program. It’s just again always optimizing the portfolio and taking advantage of the opportunities that the market presents. Blake Fernandez – Howard Weil: Okay. Fair enough the second question David is on LNG I didn’t see any comments in the slides on where you stand with regard to the LNG export facility in the U.S. could you just give us an update there please?

Yeah, there has been no major change. We continue to look at that project and do what we can while we’re waiting for approval of our non-free trade agreement permit that is pending with the government and we are hopeful we’ll get that permit approved soon. In the mean time we continue to look at the project and again develop what we can pending the permit. So still looks like a very good opportunity for the company and certainly a good opportunity for the economy and trade and we’re anxious to get after that project as soon as possible. Blake Fernandez – Howard Weil: Good day, thanks a lot.

Thank you.

We’ll move now to Jason Gammel with Macquarie. Jason Gammel – Macquarie: Hi, David.

Hey, hi Jason how are you? Jason Gammel – Macquarie: Good, thank you. I just wanted to ask a few questions, thank you for the details first of all on the project schedule, but we always want more than you give us. I guess we do have a healthy appetite. I was hoping that you might be able to first of all discuss any commercial arrangements for the natural gas at Sakhalin given the expansions that you are going through there? And then just also within the gas business if you could talk about the potential for train three at PNG and what the process will be leading up to that decision? And then finally there has been a little more discussion on the monetization of Alaska Natural Gas, can you talk about may be what your intents would be on deployed comps and lease?

Sure Jason, that’s you kind of hit kind of our big piece of our opportunities set out there and it is pretty broad. We have a lot of opportunities in a number of places around the world. If I take them in order while I can’t ever discuss commercial arrangements or commercial negotiations that might be ongoing in the business, I will say as we look at Sakhalin gas and the gas resources that we have there, we are looking at a potential LNG facility with Rosneft on Sakhalin Island or looking at some locations under consideration and progressing the evaluation of that project and working on it pretty steadily here. So that’s one opportunity that’s certainly out there. We have a very nice gas resource in the area and finding a way to monetize that. We continue to make what’s already a very attractive project even more so. So we are looking forward to working on that. If we flip over to the Papua New Guinea plant, as I mentioned that project is coming along very well, we’re very pleased with the progress heading towards a start-up next year. We are and continue to look at the potential for adding a third train. We have space to do that there, lot of opportunities. One of course is the discussions that are ongoing with InterOil. I know it was in the press recently that our exclusivity period had ended and that was correct. But we’re still discussing. We still have negotiations ongoing and we’ll just have to see how that bears out. We also in the area have a pretty good opportunity set in terms of exploration and we have had some success there recently and we continue to evaluate that opportunity. So that’s still a possibility and of course adding a train to an existing site is usually a pretty robust investment opportunity. So we’ll continue to pursue that. When we look at the potential of LNG exports out of Alaska, we did complete in the third quarter our summer field surveys on the northern portion of the proposed pipeline route, which of course is the first field work required for permitting. So we did a lot of work during the summer to analyze particularly environmental conditions among other items. So we continue to progress that on the project side. That would be a very, very large project of literally unprecedented scale and complexity. So it’s going to be very important to have a good fiscal, sound fiscal and stable, fiscal regime there and that will be one of the items necessary of course to continue to progress that project. But it does move along. The Point Thomson project is also moving along. So that opportunity is still there. I think what’s really interesting if you take a step back and look at some of the questions we have had today on LNG, you really get a sense for the really rich opportunities that we have around the world for potential monetization of our gas resources, particularly by LNG, mentioned the Sakhalin project, we have had great exploration success so far in Tanzania. We have the Gulf Coast project that we’re anxious to progress. We continue to evaluate the potential for LNG exports out of British Columbia and then we mentioned Alaska and we have other opportunities. So it’s nice to have a real rich opportunity set that’s geographically diverse and we are spending as you would expect a lot of time working on all of those and looking at which ones are ready one order to bring forward for commercialization. But it’s great to have that portfolio and the ability to take a nice long term view of monetizing those natural gas resources we have around the world. Jason Gammel – Macquarie: Thanks for that very clear answer, David. Maybe just a very quick follow-up, in [Penang Field] still a possibility for under pinning train three at PNG?

That’s one nice discovery that we’ve had. I wouldn’t want to take it any further than that other than it is one of many opportunities that we have in the area and we’re still evaluating that to answer the question that you have asked, while we consider other exploration potential in the area. I think the good news is the base project’s doing well, opportunities for expansion exist and we have a couple of different opportunities we can pursue to affect that expansion in due course. So more to come on Papua New Guinea in the future. Jason Gammel – Macquarie: Great, thanks David.

We’ll move now to Asit Sen with Cowen & Company. Asit Sen – Cowen & Company: Good morning, David.

Hey, good morning. How are you doing? Asit Sen – Cowen & Company: Good, good. Two quick questions. First on just following back on the PNG LNG projects, looks like the time line have improved just slightly. Could you talk about the critical steps ahead before the first LNG sales take place next year. You mentioned that you’ve started commissioning the LNG plant, how long does that and what’s the drilling program look like?

Sure I would – it’s little early to talk about a different start up timeline other than to say we are still looking at the second half next year. A lot to do – we are very far along. I did mention we’ve started some commissioning, feeding in some gas into the plant for testing and making sure things are working. It’s a very complex project, not just down at the LNG plant side but up in the Highlands. So there is still a lot of kit to put together and test but again all of that is ongoing. We’re finishing up the pipeline, drilling is continuing. We’ve had success and the things are going well as we did the initial drill pad and move over to the second one. So I think as the months ago by we’ll be able to give a little better update on the exact timing but for now I would say everything is certainly on schedule and going per the plan. Asit Sen – Cowen & Company: Thanks and a quick unrelated follow up just on U.S. Chemicals looks like very nice numbers. What percent of your U.S. business is specialty versus commodity? Could you provide any guidance on that?

Yeah if we are looking at the split in the U.S. on commodities versus specialty we are little higher obviously on the commodity because of our big steam cracking operations but the specialty business again as well. But we are not given a specific number in the U.S. alone we are more heavily weighted to the commodity side of the business in the specialty. Asit Sen – Cowen & Company: Thanks.

We’ll move now to Faisal Khan with Citi. Faisal Khan – Citi: Good morning David.

Good morning, Faisal how are you? Faisal Khan – Citi: All right how are you doing?

I am great, thank you. Faisal Khan – Citi: Okay, thank you. Could you – I appreciate the KPI along the unconventional resources in the U.S. and production. But could you give me a little bit more color on if I look at the total liquids production in the U.S. of roughly 423,000 barrels a day. How much of that is really coming from shale oil and shale liquids it sounds like your Permian production is mostly geared towards conventional than CO2 floodings so is that primarily at that level where it’s producing anything from shale oil or tight oil.

Yeah that’s, Faisal I don’t have a specific breakdown just in the U.S. on conventional versus unconventional. Certainly as you’ve said in the Permian the big uptick we’ve seen recently has been on the conventional side with the lot of work going on in the unconventional and so whereas if you look at the absolute production levels more of its coming from conventional and unconventional. But certainly as we go forward the conventional continue to decline and even though I mentioned some of the steps we are taking to stem that we do see decline in Alaska and et cetera. But the real key for the U.S. is we are just really getting started on the unconventional side. And as I’ve mentioned before we spent a lot of time in the last couple of years evaluating what we’ve had, doing a lot of testing, a lot of technology work, a lot of research work and that’s why I pointed out now you are really starting to see wells coming on, not for evaluation and delineation but to sell. So we can start ringing the cash register from these investments and you are starting to see that uptick. So although the absolute split you haven’t really seen a huge change there the growth is coming along as we expected and we are very pleased with the progress. But I have to say it’s not just the unconventional. We are happy with what we got going on in the Permian and some other areas to stem decline, base decline and do some things and grow those profitable barrels for us. Faisal Khan – Citi: Okay and then along the same lines then if you’re starting to scratch the surface down and finally monetize all this acreage that you accumulated over the last few years or several years I should say, what’s your – in terms of your total rig count in the U.S. what is it and how much of it is dedicated to the oil and liquids?

Yeah I think our current rig count is just over 40 rigs. I think we averaged about 45 in the quarter and I think we are currently at about 41. In terms where those rigs are drilling just about all are drilling liquids areas, we have very, very few gas rigs running only where we have an opportunity for a nice return on that. But if you think about our three core areas, the Bakken, and the Ardmore and the Permian those are where the wells we are drilling, that’s what we are seeing not only the increase in production but very pleased with the progress we are making on operating expense reduction, productivity of the wells, CapEx, efficiency and all of that as you know helps on unit profitability in the portfolio as well as cash flow generation. So if you think about those three core three areas you are really starting to see benefits of the time we spent evaluating those areas, understanding what we had, quietly adding acreage to our positions which are now quite large in all of those areas. So business is doing well and certainly a potential growth area for us that we are exploiting in due course. Faisal Khan – Citi: And last question from me David. On the Bakken if you could just give us like what your average well cost have been over the last quarter just so we can compare these efficiency gains you are talking about versus what we are seeing from your other peers and competitors?

Yeah, I understand the question, I really don’t want to give out per well cost for a number of reasons. One for competitive purposes but also any particular point in time what a well cost isn’t near important as kind of what we are doing over the longer term period. We did share some of that with you at the Analyst Meeting last year. We will share some more at the upcoming Analyst Meeting as we talk about, again this productivity gains both from technology and approach and some of the improvements we have seen there. So without giving a specific number, I can tell you that we are meeting or exceeding the expectations we had in this area when we acquired XTO and have added all of these properties, consolidated our acreage position and now as I have said really ramped up the activity there. Faisal Khan – Citi: Great. Thanks for the time. Appreciate it.

Thank you.

We will move to Roger Read with Wells Fargo. Roger Read – Wells Fargo: Hi, good morning.

Morning Roger. Roger Read – Wells Fargo: I guess lot of stuff’s been already asked and answered. But I just wanted to check the couple of things. Number one is a follow-up to the last question on gas production, – production in the U.S. and I guess specifically gas production. We have seen expected slowing in the rate of decline. It doesn’t sound like much of that would have been due at this point to ramp up associated gas from some of the shale plays. So is this just a function of the decline rates are finally slowing enough and this will help that overall expectation of production growth in ‘14 and ‘15, because you no longer have this drag or is there something else going on here?

I’d say there are things are going exactly as we had anticipated. If you look at where we are just for example year-over-year in U.S. gas we’re down about 4% in the third quarter and that’s kind of in line with the full year look that we had in March. So if I look across the year things are going just as we had expected. You do see the impact of associated gases in there and that’s offset some of the decline but nothing going on any different than what we expected coming into the year and again consistent with that full year outlook that we gave everyone in March. So again liquids up, U.S. gas down, have seen a benefit as I mentioned earlier over the year in some European gas on demand but things are going pretty much as we had anticipated. Roger Read – Wells Fargo: Okay, thanks. And the follow up question, recently the exploration expense had been moving higher and I know you can’t predict when you will drill a dry hole, and when you will drill a successful well. But I was wondering does that indicate a generally higher exploration spend overall as we are looking out?

No, I think if you look at total exploration expense from a programmatic standpoint over the years, I wouldn’t give any indication that it’s any different than what we have talked about in March. What you do see is lumpiness in the actual booked exploration expense. We did have about a $100 million higher exploration expense this quarter than we had in the quarter before. And as you mentioned it’s just the timing of expensing the dry holes and that’s what we saw in the third quarter. Roger Read – Wells Fargo: Okay, thank you.

All right, thank you.

Our next question comes from John Hurling with Societe Generale Investment. John Hurling – Societe Generale: Yeah, hi Dave. Some quick unconventional questions.

Sure. John Hurling – Societe Generale: With the Vaca Muerta you are going to drill four wells, are you going to spud them more or less sequentially and then frac them to see what you have?

Yes we’ll do those sequentially. We’ve got a number of wells that we drilled in the past couple of years and they continue to be on test. We are starting our operated program and yes we will drill those sequentially and then frac them as you mentioned. John Hurling – Societe Generale: And then regarding your operator program you don’t have same type of expenditure commitments correct, as one of your West Coast peers?

When we look across our acreage no, we don’t – I wouldn’t comment on other folks but certainly when we look at our 800,000 acres that we have down there no, we do not have any significant committed expenditures. We are continuing on the program of evaluating in due course but we have a lot of flexibility in both the pace and size of that program. John Hurling – Societe Generale: Okay and then last one from me. On the Permian you added eight new drilling rigs. How much would be for conventional activities, how much unconventional? That’s it. Thank you.

I don’t have the exact split. But I would tell you generally more are doing conventional than are doing unconventional. Yeah. John Hurling – Societe Generale: Okay great. Thank you.

Thank you.

Our next question comes from Allen Good with Morningstar.

Good morning Allen. Allen Good – Morningstar: Good morning David. Just a few quick one, first of all on the Kearl volumes can you give a split between the amount or even a percentage that were run through Exxon refineries versus third party? And long-term is there a target as far as our with respect to integration with your downstream there, where certain amount of Kearl you’d like to run through your own facilities?

Sure I’ll start with the first part without an exact barrel split, the vast majority that we ran in the third quarter we ran in our own refineries. Most of that went to our Juliette refinery in the Mid-con area we did also get some down in the Gulf Coast to run at Baton Rouge and we ran some in Sarnia in Canada. So a pretty good dispersion there and as I mentioned in my prepared remarks all of the refineries experienced exactly what we were expecting them to running that product. So again a good demonstration of the technology. Going forward we will continue to expand the disposition of this crude in our other refineries. We’ll probably run some more down to the Gulf Coast into Baytown and then into other Midwest refineries up in the Midwest et cetera. In terms of third party we expect to expand that a little bit. I wouldn’t mention the specific customers or give a target rate other than one of the things that’s really nice is we have the capability to take all of the crude into our refining circuit. We have the pipelines in place to do so but because of our integrated businesses and our unique supply opportunities and coordination we can’t place those barrels in third party refineries where we actually get more value overall by doing that and substituting other crudes in to our refineries. And so no target in any particular disposition, just optimizing the value upgrade of those molecules across our circuit. Allen Good – Morningstar: Hey, great thanks. And then regarding some of your comments on the unconventional here in the U.S. and so which are in the beginning phases of it does this imply that you will see increased capital moving in to U.S. a little 48 exports and those opportunities is there is that assumption more incorrect and two so is that largely already built into some of the CapEx guidance that was given earlier this year?

I think if I take your second part of that question, all of that is built in to that guidance that we’ve given you. We are seeing a little better volumes than we had expected coming in which is good but I wouldn’t have any specific guidance on lower 48 versus non U.S. or one particular type of resource development or the other, other than to say we will direct CapEx to the areas where we get the most uplift. But don’t have an outlook any different than what we talked about in the last Analyst Meeting. Allen Good – Morningstar: Okay thanks. David. Just one more, quick one and this may be more of a Analyst Day question but earlier this year regarding unit profitability there was obviously variety of concerns in things that contributed to maybe the lower earnings per barrel over the past few years. I think one of those was unattractive commercial terms and fiscal terms in some areas has there been any progress and I am sure you can’t mention specifics but if you can I’ll take them. But is there any progress with respect to some commercial terms that may result in lower profitability per barrel with respect to Exxon renegotiating terms or even trying to progress some of the assets and divest them longer term or is that still sort of an issue that may be have to be worked out over the longer term?

I would say if I kind of wrap up each of those questions, one it probably is a good question for the next analyst day and we look forward to talking about that a little more. Having said that I will say we have progressed a number of initiatives across the year. I don’t want to mention anything specifically. But we have undertaken initiatives in a number of areas to improve unit profitability. And to the extent we can be more specific at the next analyst meeting we’ll do so. But I do want to confirm that we are doing what we said we would do and we are making progress in that regard. Allen Good – Morningstar: Okay, great, thanks.

Thank you.

We’ll move now to Pablo Mockonoff with Raymond James. Pablo Mockonoff – Raymond James: Hi, thanks for taking the question. In your U.S. downstream segment can you talk about the impact, either in Q3 or year-to-date of having the purchase RINs?

Yeah if you step back and take a look at the RIN situation it’s not a huge impact on us and we do generate the majority of our RINs by doing our own blending directly. So there is some minor impact but not a lot financially and certainly nothing material in our results. I think the more important thing in the whole discussion of the RINs is the issue of blend wall and the industry hitting that blend wall next year and then some of the things that could be done to alleviate that we are certainly supportive of those. But if you are looking just in our third quarter results or year-to-date the net impact of the RINs is nothing that would show up as a material impact for us. Pablo Mockonoff – Raymond James: Okay, appreciated. And just quickly a lot of news flow recently, mostly bad frankly from various shale gas opportunities in Europe protest political controversy et cetera. You obviously have acreage in lot of those countries, any comments on where you stand in the places where you still have acreage?

I think if you look at Europe probably our biggest opportunity is in Germany where we do have about four million acres perspective unconventional resource opportunity. We continue to talk with the regulators and the authorities in Germany about that opportunity and the prospectivity of it. And looking for an opportunity to work on that and pile it some of that to see what we have. But it’s all about working closely with the communities, with the regulators, with the policy makers so that we can all understand what the potential opportunities are and balance those against the concern. So outside of Germany I probably wouldn’t comment on any of the other European countries. But it’s certainly is an opportunity for us, potentially an opportunity for the country and the one that we will continue to have dialogue on. Pablo Mockonoff – Raymond James: Right, appreciate it. Thank you.

We’ll move now to Kate Minyard with JPMorgan. Katherine Minyard – JPMorgan: Hi, David thanks very much for taking my question.

Hi, Kate. Katherine Minyard – JPMorgan: Just very quickly on going back to your answers on the coral project you talked about having the ability to take all the volumes within the Exxon and Imperial system and you mentioned pipelines. Are all the volumes moving via pipeline are you moving any volumes by rail?

All of the volumes coming out of the initial development are moving by pipeline. Katherine Minyard – JPMorgan: Okay. And do you see the ability to accommodate, I mean at what more point do you need to start moving via mechanism other than pipelines or can you fully accommodate the expansion basis to and also any potential development to further expansion at Cold Lake and then also any potential future development of [Clyden]

Well we first we talk about the Kearl expansion project and as we look towards 2015 and bring in that online we are looking at a number of logistical opportunities that we have including pipeline routes and certainly Keystone XL will be there for the industry in general. But as would be prudent we are looking at other options including evaluating a project to build a rail terminal in Edmonton and then move some of that crude out of there into the lower 58 by rail and we are in the process of evaluating that opportunity and we’ll have more to say on that in the future. But certainly as the Kearl expansion project comes on, I mentioned the Nabiye project in Cold Lake, lot of volumes to find disposition for and again as I think I mentioned earlier we are very fortunate in that we have a very good logistics optimization opportunity and network and a lot of avenues for us but we are actively working on all of the alternatives that are available to us to move that crude into market and get the maximum value for those molecules. In regards to Clyden as I mentioned in my prepared remarks a very nice resource opportunity for us. It does set near a in situ opportunity Imperial already we have so we are working together to take a look at all of that. I don’t have an update for you in terms of project timing or any of that just yet but we are evaluating that and looking at what we might want to do in terms of development plans and timing. So more to come on that later. Katherine Minyard – JPMorgan: Okay, thank you. And then just switching a little bit over to West Africa, can we get a status update on maybe on deepwater satellites in Angola, kind of timing and specifically whether you are kind of actively drilling there right now whether you have a rig engaged?

If we look at the satellite projects, both in Nigeria and Angola, I’ll start with Nigeria first that project is on ramping up the Angola satellites project also progressing per the plan. I can’t give you a specific answer in terms of drill rig running or any of that sort of thing but I would say as we look at the satellite opportunities, again to tie into existing facilities those investments and projects are quite attractive and they are coming along and ramping up as planned. Katherine Minyard – JPMorgan: All right, thanks very much David.

Thank you, Kate.

And we’ll now move to Paul Cheng with Barclays. Paul Cheng – Barclays: Hey guys.

Paul, how are you today? Paul Cheng – Barclays: I am very good. Just one very quick one, Qatar I think several years ago RasGas your joint-venture between you and Qatar Petroleum did have a bond offering and they had their prospectus and that seems to suggest that the local tax holiday for the RasGas 6 and 7 will be expiring probably in 2014-’15. Can you give us some idea that if indeed that’s the case what is the financial impact both in earnings and cash flow may look like?

You know Paul if we look at Kearl all the various streams that we have on that have come on over the years they have their own unique fiscal terms and I wouldn’t comment specifically on any of the terms on any of the trains, other than to say you know as we move out into the future there is nothing material in terms of our results, no significant impact that we would see but in terms of talking about the specific terms of those contracts it just wouldn’t be appropriate for me to comment on that. Paul Cheng – Barclays: Final one on Alaska, I think both your partner Chronicle and BP in the North Slope that indicate that with the tax law change they are going to increase their spending there. Are you guys also aligned with them that you are going to increase your spending in Alaska?

I think you know there are number of opportunities for us in Alaska but I wouldn’t comment specifically on any specific plan to ramp up CapEx or to progress anything any faster than what we already have in the plan but of course anytime you know the fiscals improve, projects on the margin by definition become attractive or more attractive and get reevaluated but other than that I really wouldn’t have a specific comment relative to Alaska. Paul Cheng – Barclays: All right, thank you.

Thank you very much.

We have no further questions in queue. So I would like to turn the call back over to Mr. Rosenthal for any additional or closing remarks.

I would just like to close by thanking everybody for your time and your questions today, excellent questions and I appreciate it and I look forward to visiting with you again after the year-end results are in. So thank you very much.

Once again, ladies and gentlemen that does conclude today’s conference. Thank you for your participation.