Earnings Call: Q3 2013

Oct 31, 2013

Summary

Q3 earnings were $7.9B as stronger upstream and chemical results partly offset a sharp downstream decline. Production remained on track for the 2013 outlook, while Kashagan was shut in pending pipeline investigations.

Good day, and welcome to this Exxon Mobil Corporation third quarter 2013 earnings conference call. Today's call is being recorded. At this time, for opening remarks, I would like to turn the call over to the Vice President of Investor Relations and Secretary, Mr. David Rosenthal. Please go ahead, sir. 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 investor section of our website. Before we go further, I would like to draw your attention to our cautionary statement shown on slide 2. Moving to slide 3, we provide an overview of some of the external factors impacting our results. Global economic growth remained constrained in the third quarter, with mixed performance across the regions. 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 Europe's economic conditions 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 4. Exxon Mobil's third quarter earnings were $7.9 billion, or $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 6 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 7, 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-$700 million per quarter. Turning now to the upstream financial and operating results and starting on slide 8. 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 thousand cubic feet respectively. Production 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 underlifts 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 9. 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, ramp 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 thousand cubic feet. Volume and mix effects decreased earnings by $150 million, as increased liquids production was more than offset by the impact of underlifts 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 $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 downtime, 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 downtime 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 uptime 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 $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 $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 costs in the U.S., increased earnings by $110 million. Strong U.S. commodity sales volumes further increased earnings by $60 million. Lower costs associated with Singapore's new steam cracker startup and lower planned maintenance favorably impacted earnings by $100 million. Moving next to the third quarter business highlights, beginning on slide 16. The next two slides provide an update on Upstream projects which recently started or will start production next year. Beginning with the 2013 project startups. At Kearl, we are currently producing at or above 100,000 barrels per day. Over the past few months, we have undertaken normal startup-related fine-tuning and synchronization activities of our facilities, which are not unusual for 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 performance 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 Mainline Pipeline, which will extend 385 kilometers south of Cheecham to the Edmonton terminal and connect with refineries and export pipelines. 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 to Nauru 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, and again 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 in a unique and challenging work environment. The Cold Lake Nabiye development in Canada is 60% complete and progressing per plan towards a 2014 startup. This is another long plateau development, which will access a resource of 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 with 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 wellhead platform topsides have been installed. Startup 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 gas 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 ExxonMobil'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. To date, 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. ExxonMobil's proprietary technology has minimized drilling vibration and improved overall economic efficiency while reducing the environmental footprint of the Sakhalin-1 project. The relentless 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 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 topsides was completed in Korea earlier this year, and commissioning of the drilling rig and topside facilities are 40% complete. Installation of the topsides onto the gravity-based structure next year will set a new world record for float-over installation offshore at 42,000 tons. Startup is planned for 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 new petrophysical log data and core samples. This information will help identify key producibility parameters for the Bazhenov and will 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 sea ice and iceberg tracking 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 at Sakhalin-1 position 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 wildcat in Block 2 offshore Tanzania. The Mronge-1 well targets reservoirs equivalent in age to those successfully tested by the Zafarani and Lavani wells, in addition to another reservoir interval previously untested in Block 2. Further wildcat drilling is planned for 2014. In Argentina, ExxonMobil spud the first operated well on the Bajo del Choique block targeting the Vaca Muerta formation. This is the first of three ExxonMobil operated wells that will be drilled in sequence on the block. In Canada, ExxonMobil, in partnership with Imperial Oil, acquired ConocoPhillips interest in the Clyden oil sands lease. The Clyden lease is near Imperial's Corner lease holdings 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, ExxonMobil was awarded the interest it successfully bid for in May. ExxonMobil acquired a 50% interest in the Potiguar 762 block and a 50% interest in the Ceará 603 block, totaling more than 750,000 gross acres offshore northeastern Brazil. ExxonMobil will be the operator for both blocks. In Gabon, ExxonMobil has reached agreement to acquire a 30% participating interest in the offshore Aruwé block. The operator Perenco, along with the third-party equity holder Tullow, is planning a wildcat well in 2014. Turning now to slide 20 and an update on our North American liquids activities. 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 workover 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 Denbury 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 results continue to be strong, with peak 30-day equivalent production rates up 17% year to date. For example, a recent five-well pad completion 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 into 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 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 significant planned maintenance activities in the second quarter. Chemical business results remain strong on increased commodity product demand and lower feedstock costs. Across the corporation, CapEx is in line with anticipated spending plans. Our cash flow remains strong and enables robust shareholder distributions. 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. David Rosenthal. The question and answer session will be conducted electronically. If you would like to ask a question, please do so by pressing the star key followed by the digit one on your touchtone telephone. We request that you limit your number of questions to two, so that as many may have the opportunity to participate as possible. If you are using a speakerphone, please make sure your mute function is turned off to allow your signal to reach our equipment. We will proceed in the order that you signal us, and we will take as many questions as time permits. Once again, please press star one on your touchtone telephone to ask a question. Our first question comes from Evan Calio with Morgan Stanley. Oh, good morning, guys. How are you? Good morning, Evan. How are you? I'm good. Maybe I missed it in your opening comments on the discussion on the cash balance, but the additional financing investing item, will that show up in 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. Okay. While it may be premature, I know you guys addressed this at the Analyst Day, but what are your thoughts with regard to potentially reducing CapEx on a forward basis, which has been a theme 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, I think particularly in the upstream with a little higher investment in downstream and chemical. We will update that in the next analyst meeting. But right now, I don't have any new number to give you, 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 our approach. You have seen us over the course of this year increase leverage just a bit. But that's really to get us back to where we were if you go back to about 2010. If you look across the 2011 and 2012 timeframe where we had significant cash flow including from asset divestitures over those two years, we returned a lot of that cash to the shareholder. We also paid down a lot of debt. This increase you've seen this year really just gets us back to about where we were. But no real change in approach to the balance sheet or distributions to shareholders. Great. I'll leave it there. Thank you. Okay. Thank you. Our next question comes from Doug Terreson with ISI Group. Good morning, David. Hey, good morning, Doug. 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 the international arena. But in your E&P earnings charts that you highlighted, they did not indicate that volume mix effects played much of a role in this improvement. I wanted to see if you could 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 of the drivers of E&P profitability that you are able to provide color on. Sure. I would be happy to provide a little more color on that. If you are looking at quarter-over-quarter you see on the chart, and I mentioned in my primary remarks, a net increase of about $20 million. Right. We did have an underlift this quarter of about 25,000 barrels a day in a number of areas, including West Africa and the North Sea. If we had not been underlifted, earnings would have been notionally $100 million or so higher. Okay. That might have been more closer to what you expected. Okay. We did see quite a nice contribution on the liquid side, and that was offset a bit by declining as we expected and had talked about on the gas side of the business. 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. As we talked about at the analyst meeting, we are taking steps, and we will 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. I would not want to take any one quarter and say we have set a trend. Sure. But we are 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. Okay. Thanks a lot, David. All right. Thank you. Our next question comes from Doug Leggate with Bank of America Merrill Lynch. Thanks. Good morning, David. Good morning, Doug. How are you? Not too bad, thank you. I wonder if I could ask you about production volumes. I realize you've got a lot of projects that are in the ramp-up phase, and I guess slide 9 shows us the year-over-year impact. But can you help us understand what stage of their evolution the new projects are now? What I'm really trying to get to is, I know it's not an easy question to answer, but are we at the point now where the ramp-up in the stuff that's started up already is now enough to offset the underlying decline so that we can hit that inflection point in growth? I've got a follow-up, please. Sure. Doug, if you look particularly on the liquid side, which is I know where the focus has been, you are certainly starting to see an inflection point off of where we have been as the new projects have come online. I mentioned it is really a mix of some things are doing a little better than we were expecting this year, and that has more than offset a little slower ramp-up in Kearl. 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 the kind of turnaround that we talked about at the analyst meeting, and we have been discussing since then. One of the other things that we have seen this year, particularly year-over-year, is much lower downtime. Our operations are running very well this year. We are very pleased with the progress we have made, particularly on the liquid side in some of our higher margin areas, but also on the LNG side of the business. When you have the combination of lower downtime on some of your better profitable barrel equivalents and the turnaround and uplift that you are 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. I would say, again, I wouldn'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. As I mentioned in my prepared remarks, as we look forward into 2014, our major projects are on schedule, on budget, and we continue to be very pleased with that progress. As you know, that continues on into the 2015 and 2016 timeframe. We are on track to deliver that big wedge of volume we talked about between year-end 2012 and year-end 2017, and things are progressing well. Thank you. My follow-up, David, is really I know you have been on the road a fair amount these last several months, and I am really looking for you to clarify or at least put the debate to rest. There seems to be some debate over whether or not you are going to stick with your multi-year capital budget as laid out at last year's Analyst Day. In light of where the share price is, I guess it goes back to Evan's question. The share price has frankly been pretty awful this year on a relative and absolute basis. How is management thinking about the kind of reward that some of your overseas competitors have had by cutting back capital? How are you thinking about maybe being a bit more aggressive on the buyback to take advantage of, or at least address the weakness that we've seen so far this year? I'll leave it at that. Thank you. Sure. Thanks, Doug. Let me hit those three things. On the CapEx side, there is no new outlook relative to what we said at the analyst meeting. We're certainly updating our plan now, and we'll give an update in March. When we look at our investment plan that we showed you, we don't have any information to date that would suggest a major change from what we said. As 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 as good as you've seen in the chemical business this quarter, where our uptime rates were extremely high, and we're capturing that value added there on the margin, particularly in the U.S. I mentioned the operations that we're having in the upstream. If we're looking at the things that really generate shareholder value short term and long term, running the business well, we're seeing that and bringing those big projects online and benefiting from the CapEx profile that we've had the last few years, and you've seen that. In terms of the buyback, no change in the buyback. It continues to be a quarter-to-quarter decision. I updated you on the third quarter, and it's another $3 billion, or the fourth quarter, I'm sorry, another $3 billion. We'll have another update on that in the next earnings call. Thanks, David. All right. Thanks. We will move now to Edward Westlake with Credit Suisse. Early this year. Just on the CapEx comment you made about CapEx rolling over, that is presumably mainly the Celtic acquisition that you flagged in the analyst day? Yes. If you look at where we are on CapEx, I said we were in line with expectations. If you step back to the analyst meeting, we had said we would spend about $41 billion in total. We had about $3 billion in there for the Celtic acquisition. So if you were to look at what we showed you ex acquisitions, that would have been about 38. As we sit here through the third quarter and we take Celtic and add in the Clyden acquisition, that is about $4 billion round numbers. If you take the $4 billion away from the $32.6 billion you are seeing year to date, that is 28 and change. 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 have been able to manage such a large project load this year and keep that CapEx discipline to bring these projects in on budget. Again, it is a large number, too close to call for the year-end, but we feel pretty good about where we are at. Just to switch to the downstream and chemicals. Obviously, in the second quarter, you were still burdened with Singapore costs, 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 that is a more normal kind of level of operations that most of the 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, as we talked about on the last call, significant downtime, a lot of planned maintenance. Again, I am happy to say that we came out of all that very successful on the turnarounds and maintenance, concluded in a safe manner, and that has come out very well. As we came through the third quarter, all of that equipment came back up fine, running well. Capacity utilization is doing well. The third quarter is more of a kind of normal quarter, I guess, if you were looking from that perspective. We have some minor turnarounds as we always do coming up, but nothing specific. As we look in 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 were able to take that to the bottom line. Maybe one final one. Just on the restructuring in the downstream. Obviously, you have already taken some moves to improve the competitiveness of the refining assets relative to the market environment. Any thoughts about perhaps being more aggressive here given some of the trends in terms of capacity adds and gasoline margins globally that we are seeing? Well, I would not want to give any guidance specifically on that program. We did, as you point out, have a very successful multi-year program on some asset restructurings and some asset divestitures in the downstream, particularly during an upcycle in the business. We certainly brought a lot of value home to the shareholder. Going forward, no big change in approach. We are always looking at all of our assets, so we are always talking to people. People are approaching us. We will see how that goes. No change, more aggressive, less aggressive, just optimizing the business and bringing the value home whenever we have the opportunity to do so. Thanks, David. All right. Thank you. We'll move now to Paul Sankey with Deutsche Bank. Hi, David. Hey, good morning, Paul. David, reading between the lines, are we saying that 2013 is a peak year for CapEx? If you look at the chart that we showed in March, it would indicate that this was a peak year. Again, really don't have a change to that. Our expectation is what we've seen, which is the upstream CapEx would trend down as 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. In particular, in chemical, we've talked about a major expansion opportunity potentially in the Gulf Coast with a new steam cracker and some polyethylene lines. We're 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. I really don't have any different signal or any different fundamental change in the opportunity set than what we've talked about this year. Of course, we'll update that in March, but as of now, I don't see any change to what we've talked about before. Which would imply that it would be a peak year for CapEx. Then I guess the risk there, as you've highlighted, is actually non-operated, which is obviously the Gorgon project. Well, we do not have an update on the Gorgon project. Obviously, it'd 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. Speaking of non-operated, I think you may have done this, but could you just remind us what the contribution of Kashagan was in Q3 and what you anticipate it will be in Q4? Yeah. It was fairly small across the quarter. I do not have that exact number. It came online. It got up to 80,000 barrels a day and went down. Looking into the fourth quarter, Paul, I really do not 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. Until we know that, it is hard to give an outlook. We just have to wait and see and find out what remediation, if anything, is necessary and how long that might take. As you would expect, that investigation and evaluation is ongoing as we speak. We will stay shut in until it is complete. I just do not have any better outlook than that. Understood, David. Then finally, could you just remind us, I think what you said here is that your debt levels in the quarter rose, net debt rose, but you maintained your buyback. In other words, you are now increasing debt in order to buy in shares. Is that a fair statement? No, 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 are up, as I mentioned, the levels that we were a couple of years ago, but still fairly conservative. A lot of flexibility as we like to keep on the balance sheet. I think our debt-to-equity ratios and some of the other metrics that people look at on the balance sheet are all pretty much within where we have been historically coming out of the low period we had, as I mentioned, in 2011 and 2012. So, no real change in either approach or any other outlooks to offer in that regard. Okay. Thanks, David. Sure. Thank you, Paul. Our next question comes from Blake Fernandez with Howard Weil. Hey, David. Good morning. Thanks for taking the question. Blake. We've covered CapEx pretty well. I was just going to see if we could maybe shift it over to divestitures. This may be a better question for the Analyst today, but some of your peers in Europe especially have definitely gone into a mode of more aggressively divesting assets, and it seems like Exxon in particular would certainly have quite a host of opportunities there. Are there any thoughts to maybe take advantage of that in the marketplace? Well, I think the first thought I'd have is we don't ever announce in advance what our divestiture plans are. Over time, we 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. 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 viewed them as having more value than we value them in our portfolio. When you have that type of a situation, it's very beneficial to make a transaction, and we're always looking at that, and 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, 2011 and 2012, 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 a program. It's just, again, always optimizing the portfolio and taking advantage of the opportunities that the market presents us. 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's 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're hopeful we'll get that permit approved soon. In the meantime, we continue to look at the project and again, develop what we can pending the permit. 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. Good deal. Thanks a lot. Thank you. We'll move now to Jason Gammel with Macquarie. Hi, David. Hey. Hi, Jason. How are you? Good, thank you. I just wanted to ask a few questions. Thank you for the detail, first of all, on the project schedule. We always want more than you give us, so I guess we just 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're going through there. Then also just within the gas business, if you could talk about the potential for Train 3 at PNG and what the process will be leading up to that decision. Then finally, there has been a little more discussion on the monetization of Alaskan natural gas. Can you talk about maybe what your intents would be on the Point Thomson lease? Sure, Jason. You've hit a big piece of our opportunity 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. We're 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 would continue to make what's already a very attractive project even more 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 are very pleased with the progress, heading towards a startup next year. We are and continue to look at the potential for adding a third train. We have space to do that there. A 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 are still discussing. We still have negotiations ongoing, and we will 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. That is still a possibility. Of course, adding a train to an existing site is usually a pretty robust investment opportunity, so we will 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, and particularly environmental conditions, among other items. 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 is going to be very important to have a good, 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 is 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 opportunity set we have around the world for potential monetization of our gas resources, particularly via LNG. Mentioned the Sakhalin project. We have had great exploration success so far in Tanzania. We have the Gulf Coast project that we are anxious to progress. We continue to evaluate the potential for LNG exports out of British Columbia, and then we mention Alaska, and we have other opportunities. So it is nice to have a real rich opportunity set that is geographically diverse. 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 is 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. Thanks for that very thorough answer, David. Maybe just a very quick follow-up. Is P'nyang field still a possibility for underpinning a 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've 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. Great. Thanks, David. We'll move now to Asad Sind with Cowen and Company. Good morning, David. Hey, good morning. How are you doing? Good. Two quick questions. First on, just falling back on the PNG LNG project, it looks like the timeline has improved just slightly. Could you talk about the critical steps ahead before the first LNG sales take place next year? You mentioned that you started commissioning the LNG plant. How long does that take, and what's the drilling program look like? Sure. It's a little early to talk about a different startup timeline other than to say we're still looking at the second half of next year. A lot to do. We're very far along. I did mention we started some commissioning, feeding 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 site, but up in the Highlands. So there's still a lot of kit to put together and test. But again, all of that is ongoing. We are finishing up the pipeline. Drilling is continuing. We've had success and things are going well as we did the initial drill pad and move over to the second one. So I think as the months go 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. Thanks. A quick unrelated follow-up is on U.S. Chemicals. Looks like some very nice numbers. What percent of your U.S. business is specialty versus commodity? Could you provide any guidance on that? Yeah. If we're looking at the split in the U.S. on commodities versus specialties, we're a little higher, obviously, on the commodity side because of our big steam cracking operations. But the specialty business again as well. But without giving a specific number in the U.S. alone, we're more heavily weighted to the commodity side of the business than the specialty. Thanks. We'll move now to Pavol Kahn with Citi. Good morning, David. Good morning, Faisal. How are you? All right. How are you doing? I'm great, thank you. Okay, thank you. I appreciate the detail on the unconventional resources in the U.S. and production. 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 and CO2 flooding. So it's not really at that level where you're producing anything from shale oil or tight oil. Faisal, I don't have a specific breakdown just in the U.S. on conventional versus unconventional. Certainly, as you said, in the Permian, the big uptick we've seen recently has been on the conventional side with a lot of work going on in the unconventional. Whereas, if you look at the absolute production levels, more of it's coming from conventional than unconventional. But certainly as we go forward, the conventional will continue to decline, and even though I mentioned some of the steps we're taking to stem that, we do see decline in Alaska, et cetera. But the real key for the U.S. is we are just really getting started on the unconventional side. 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. That's why I pointed out now you're really starting to see wells coming on, not for evaluation and delineation, but to sell so we can start bringing the cash register from these investments, and you're starting to see that uptick. Although the absolute split, you haven't really seen a huge change there. The growth is coming along as we expected, and we're very pleased with the progress. But I have to say, it's not just the unconventional. We're happy with what we got going on in the Permian and some other areas to stem decline, base decline, and do some things that grow those very profitable barrels for us. Okay. David, along those same lines, if you're starting to scratch the surface now and finally monetize all those acres that you've accumulated over the last few years or several years, I should say. In terms of your total rig count in the U.S., what is it and how much of it is dedicated to 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 of where those rigs are drilling, just about all of them are drilling liquids areas. We have very few gas rigs running, only where we have an opportunity for a nice return on them. If you think about our three core areas, the Bakken and the Ardmore and the Permian, those are where the wells are drilling. That is where 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. All of that, as you know, helps on unit profitability in the portfolio as well as cash flow generation. If you think about those three core areas, you are really starting to see the benefit 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. Business is doing well and certainly a potential growth area for us that we are exploiting in due course. Okay, last question from me, David. On the Bakken, if you could just give us what your average well costs have been over the last quarter, just so that we can compare these efficiency gains you are talking about versus what we are seeing some of your other peers and competitors in the basin. Yeah, I understand the question. I really do not want to give out per well costs, and for a number of reasons. One, for competitive purposes. Also, any particular point in time, what a well cost is is not near as important as 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, these productivity gains both from technology and approach, and some of the improvements we have seen there. 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 on to all of these properties, consolidated our acreage position, and now, as I have said, really ramped up the activity there. Great. Thanks for the time. Appreciate it. All right. Thank you. We will move now to Roger Read with Wells Fargo. Hi, good morning. Morning, Roger. I guess, a lot of stuff's been already asked and answered, but I just was wanting to check on a couple of things. Number one is a follow-up to the last question on production in the U.S., and I guess specifically gas production. We've seen the expected slowing in the rate of decline. It doesn't sound like much of that would have been due at this point to ramped up associated gas from some of the shale plays. Is this just a function of the decline rates are finally slowing enough, and this will help that overall expectation of production growth in 2014 and 2015 because you no longer have this drag, or is there something else going on here? No, I'd say 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 in line with the full year outlook that we had in March. 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 it does offset some of the decline, but nothing going on any different than what we expected coming into the year. Again, consistent with that full-year outlook that we gave everyone in March. Again, liquids up, U.S. gas down. Have seen a benefit, as I mentioned over the year in some European gas on demand, but things going pretty much as we anticipated. Okay, thanks. The follow-up question, recently, the exploration expense had been moving higher, and I know you can't predict when you'll drill a dry hole and when you'll drill a successful well. I was wondering, does that indicate a generally higher exploration spend overall as we're 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 had talked about in March. What you do see is lumpiness in the actual booked exploration expense. We did have about $100 million higher exploration expense this quarter than we had the quarter before. As you mentioned, it's just the timing of expensing the dry holes, and that's what we saw in the third quarter. Okay, thanks. Thank you. All right. Thank you. Our next question comes from John Herrlin with Societe Generale. Yeah. Hi, Dave. Some quick unconventional questions. Sure. With the Bajo del Choique, you are going to drill four wells. Are you going to spud them more or less sequentially and then frack them to see what you have? Yes. We will do those sequentially. We have got a number of wells that we have 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 frack them, as you mentioned. Regarding your operator programs, you don't have the same type of expenditure commitments, correct, as one of your West Coast peers? When we look across our acreage, no. 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. Okay. Last one from me. On the Permian, you added 8 drilling rigs. How much would be for conventional activities? How much unconventional? That's it. Thank you. Oh, I don't have an exact split, but I would tell you, generally more are doing conventional than are doing unconventional. Yeah. Okay, great. Thank you. Thank you. Our next question comes from Allen Good with Morningstar. Morning, Allen. Good morning, David. Just a few quick ones. First of all, on the Kearl volumes, can you give a split between the amount or even the percentage that were run through Exxon refineries versus third party? Long term, is there a target as far as respect to integration with your downstream there where a certain amount of crude you would like to run through your own facilities? Sure. I will 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 Joliet refinery in the MidCon area. We did also get some down into the Gulf Coast to run at Baton Rouge, and we ran some in Sarnia in Canada. Pretty good dispersion there. As I mentioned in my prepared remarks, all of the refineries experienced exactly what we were expecting them to running that product. Again, a good demonstration of the technology. Going forward, we will continue to expand the disposition of this crude in our other refineries. We will probably run some more down to the Gulf Coast and into Baytown and then into our other Midwest refineries up in the Midwest, et cetera. In terms of third party, we expect to expand that a little bit. I would not mention the specific customers or give a target rate other than one of the things that is 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. Because of our integrated businesses and our unique supply opportunities and coordination, we can place those barrels in third party refineries where we actually get more value overall by doing that and substituting other crudes into our refineries. No target in any particular disposition, just optimizing the value upgrade of those molecules across our circuit. Okay, great. Thanks. We are going through your comments on the unconventional here in the U.S. and saying that we are in the beginning phases of it. That seems to imply that you will see increased capital moving into the U.S. or Lower 48 to exploit some of those opportunities. Is that assumption one correct? Two, 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 into the guidance that we have given you. We are seeing a little better volumes than we had expected coming in, which is good, but I would not have any specific guidance on Lower 48 versus non-U.S. or in 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 do not have an outlook any different than what we have talked about in the last analyst meeting. Okay, thanks. Just one more quick one, and this may be more of an Analyst Day question, but earlier this year regarding unit profitability, there is obviously a variety of concerns and things that contributed to maybe the lower earnings per barrel over the past couple years. I think one of those was unattractive commercial terms and physical terms in some areas. Has there been any progress? I am sure you cannot mention specifics, though if you can, I will take them. But has there been any progress with respect to some commercial terms that may result in lower profitability per barrel with respect to Exxon renegotiating terms or even maybe even trying to progress some of the assets and divest them longer term? Or is that still sort of an issue that maybe has not been worked out over the longer term? I would say if I wrap up each of those questions, one, it probably is a good question for the next Analyst Day, and we will 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 do not want to mention anything specifically. But we have undertaken initiatives in a number of areas to improve unit profitability. To the extent we can be more specific at the next analyst meeting, we will 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. Okay, great. Thanks. Thank you. We'll move now to Pavel Molchanov with Raymond James. Okay, 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 to purchase RINs? Yeah. If you step back and take a look at the RINs situation, it's not a huge impact on us. We do generate the majority of our RINs by doing our own blending directly. So there's 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 the 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're 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. Okay. Appreciate it. Then just quickly, a lot of news flow recently, mostly bad, frankly, from various shale gas opportunities in Europe, protests, political controversy, et cetera. You obviously have acreage in a lot of those countries. Any comments on where you stand in the places where you still have acreage? Well, I think if you look at Europe, probably our biggest opportunity is in Germany where we do have about 4 million acres of prospective 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 pilot some of that to see what we have. But it's all about working closely with the communities, with the regulators, with the policymakers so that we can all understand what the potential opportunities are and balance those against the concerns. Outside of Germany, I probably wouldn't comment on any of the other European countries. But it certainly is an opportunity for us and potentially an opportunity for the country and one that we will continue to have dialogue on. All right. Appreciate it. Thank you. We'll move now to Kate Minyard with J.P. Morgan. Hi, David. Thanks very much for taking my question. Hi, Kate. Hi. Just very quickly on going back to your answers on the Kearl 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, or are you moving any volumes by rail? No, all of the volumes coming out of the initial development are moving by pipeline. Okay, do you see the ability to accommodate? At what point do you need to start moving via a mechanism other than pipelines, or can you fully accommodate the expansion phases too? Also any potential development the further expansion at Cold Lake and then also any potential future development of Clyden? Well, first we'll talk about the Kearl expansion project, and as we look towards 2015 and bringing that online, we are looking at a number of logistical opportunities that we have including pipeline routes and certainly Keystone XL would be there for the industry in general. 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 48 by rail. We are in the process of evaluating that opportunity, and we'll have more to say on that in the future. Certainly as the Kearl expansion project comes on, I mentioned the Nabiye project in Cold Lake. A lot of volumes to find a disposition for. Again, as I think I mentioned earlier, we're very fortunate in that we have a very good logistics optimization opportunity and network and a lot of avenues for us. 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 sit near an in-situ opportunity Imperial already has, so we're 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. Okay, thank you. Just switching a little bit over to West Africa, can we get a status update on maybe on the deepwater satellites in Angola, timing and specifically whether you are actively drilling there right now? Do they have a rig engaged? If we look at the satellite projects both in Nigeria and Angola, I will start with Nigeria first. That project is on and ramping up. The Angola Satellites project also progressing per the plan. I cannot give you a specific answer in terms of a drill rig running or any of that sort of thing. I would say, as we look at these 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. All right. Thanks very much, David. Thank you, Kate. I will move to Paul Cheng with Barclays. Hey, guys. Hey, Paul. How are you today? 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 have the perspectives in there seems to suggest that the local tax holiday for the RasGas 6 and 7 will be expiring probably in 2014, 2015. Can you give us some idea that if indeed that's the case, what is the financial impact both in earning and cash flow may look like? Yeah, Paul. If we look at Qatar, all the various trains that we have on that have come on over the years, they have their own unique fiscal terms. I wouldn't comment specifically on any of the terms on any of the trains, other than to say, as we move out into the future, there's 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 them. Okay. A final one on Alaska. I think both your partner, Conoco, and BP in the North Slope indicate with the tax law change, they're going to increase their spending there. Are you guys also aligned with them that you're going to increase your spending in Alaska? I think there are a 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, any time 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. 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. David 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. Thank you very much. Once again, ladies and gentlemen, that does conclude today's conference. Thank you for your participation.