Earnings Call: Q3 2012

Nov 1, 2012

Summary

Q3 earnings fell 7% YoY to $9.6B as upstream declines and lower asset-sale gains offset stronger refining. Cash flow was $14B, with $7.6B distributed to shareholders and major project and acreage investments advancing.

Good day, ladies and gentlemen, and welcome to this ExxonMobil Corporation third quarter 2012 earnings conference call. Please note today's conference is being recorded. At this time, for opening remarks, I'd like to turn the conference over to the Vice President of Investor Relations and Secretary, Mr. David Rosenthal. Please go ahead, sir. Good morning, and welcome to ExxonMobil's third quarter earnings call and webcast. The focus of this call is ExxonMobil's financial and operating results for the third quarter of 2012. I will refer to the slides that are available through the investors section of our website. Before we begin today, I'd like to say a few words of support for those who have been impacted by Hurricane Sandy, which I know includes many people listening to today's call. Our thoughts are with you as you work to recover from the effects of the storm, which has touched so many lives along the East Coast. We are doing everything we can in our operations to help support the recovery effort. Now returning to ExxonMobil's results. Before we go further, I would like to draw your attention to our customary cautionary statement shown on slide 2. Moving to slide 3, we provide an overview of some of the external factors impacting our results. Global economic uncertainty continued in the third quarter, with further weakness in Europe and Japan. The European growth rate is estimated to remain negative in the third quarter following the contraction in the second quarter. Meanwhile, Japan is likely to decelerate further. The U.S. economy marginally improved versus the second quarter, and China's growth rate decline moderated versus prior quarters. Energy markets improved in the third quarter, with higher crude oil and U.S. natural gas prices and stronger industry refining margins versus the second quarter. Although U.S. commodity chemical margins remained strong, Europe and Asia margins showed continued weakness. Turning now to the third quarter financial results as shown on slide 4. ExxonMobil's third quarter 2012 earnings were $9.6 billion, a decrease of $760 million from the third quarter of 2011. Earnings per share for the quarter were $2.09, down $0.04 from a year ago. The corporation distributed $7.6 billion to shareholders in the third quarter through dividends and share purchases to reduce shares outstanding. Of that total, $5 billion was distributed to purchase shares. Share purchases to reduce shares outstanding are expected to be $5 billion in the fourth quarter of 2012. CapEx in the third quarter was $9.2 billion, up 7% from the third quarter of 2011. Our cash generation remains strong, with $14 billion in cash flow from operations and asset sales. At the end of the third quarter 2012, cash totaled $13.3 billion, and debt was $12.4 billion. The next slide provides additional detail on third quarter sources and uses of funds. Over the quarter, cash decreased from $18 billion to $13.3 billion. The combined impact of strong earnings, depreciation expense, and the benefit of our ongoing asset management program yielded $14 billion of cash flow from operations and asset sales. Uses included additions to plant, property, and equipment, or PP&E, of $8 billion, and shareholder distributions of $7.6 billion. Additional financing and investing activities decreased our cash by $3.1 billion, primarily due to the redemption of the SeaRiver deferred interest debentures. Moving on to slide 6 and a review of our segmented results. ExxonMobil's third quarter 2012 earnings of $9.6 billion decreased $760 million or 7% from the third quarter of 2011, primarily due to lower gains from asset sales and lower upstream volumes, partly offset by higher refining margins. Upstream earnings decreased to $2.4 billion, while downstream earnings improved by $1.6 billion. Chemical earnings were down $213 million, and corporate and financing expenses were favorable by $263 million, primarily due to tax items. Guidance for corporate and financing expenses remains at $500 million to $700 million per quarter. As shown on slide 7, ExxonMobil's third quarter 2012 earnings decreased by $6.3 billion compared with the second quarter of 2012, mainly due to lower gains on asset sales. Moving next to third quarter business highlights and beginning on slide 8. We continue to advance our global portfolio of high-quality upstream projects. In Nigeria, the Satellites Phase 1 project continues to progress towards first oil in the fourth quarter of 2012. Drilling has commenced on two of the three platforms. The project will have a peak capacity of 70,000 gross barrels per day. The Kearl initial development project is now 98% complete, and phase startup activities are underway. Mining operations have commenced, and ore is being stockpiled adjacent to the ore processing plant. Commissioning of the ore processing plant and utility systems are progressing, and the diluent and natural gas supply systems are operational. Construction is also progressing at the Papua New Guinea LNG project, which remains on schedule for a 2014 startup. In the third quarter, we completed both the hydrotesting of the 250-mile offshore pipeline and structural steel construction on the LNG plant trains. Drilling commenced at Hides with the first of two rigs, and the final site preparation is underway for the second drilling rig. Turning now to slide 9 and an update on our Gulf of Mexico opportunities. At Hadrian North, we drilled two appraisal wells in the quarter, and we are analyzing the results and will incorporate the findings into our development planning. Our current development basis is a 100,000 barrel per day capacity, new build, semi-submersible floating production system. ExxonMobil has also begun drilling our Hummer Shallow prospect, located in Walker Ridge Block 674, near the Jack St. Malo development. Also, during the quarter, ExxonMobil acquired a 20% working interest in the Phobos prospect, which is 5 miles south of ExxonMobil's Hadrian South discovery. Additionally, we acquired a 35% working interest in the Thorn prospect, located about 30 miles northeast of ExxonMobil's Julia discovery. Phobos is expected to spud by year-end 2012, and drilling will begin at Thorn in 2013. Turning now to our activities in the Black Sea on slide 10. ExxonMobil has established a material acreage position in the northern Black Sea across Ukraine, Romania, and Russia, totaling approximately 3.5 million net acres. In August, the Ukrainian government awarded the offshore Skifska block to a group of investors led by ExxonMobil. Our bid combined the extensive deepwater experience, technological expertise, financial strength, and environmental protection capabilities of ExxonMobil, Shell, and OMV Petrom with the local expertise of the national oil company, Nadra Ukrainy. ExxonMobil will be the project operator, and we are currently negotiating the joint operating agreement and production sharing agreement. In Romania, where we had a discovery earlier in the year, we are preparing to commence additional 3D seismic acquisition in late 2012 and have begun preparations for additional exploration drilling in late 2013 or early 2014. In the Russian sector of the Black Sea, processing of the newly acquired 3D seismic is underway. We will utilize this information to develop our exploration drilling plans with drilling targeted to begin in late 2014 or early 2015. Turning to slide 11. During the quarter, we continued to progress our strategic cooperation agreement with Rosneft. We recently completed acquisition of 2D and 3D seismic surveys in the Kara Sea. In addition, geotechnical and oceanographic data were collected on potential drill well locations. Following completion of prospect definition and permitting, exploration drilling is expected to begin in the 2014-2015 timeframe. To advance Arctic drilling technology, we have signed an agreement in September to evaluate concepts for the development of a gravity-based shallow water rig that can withstand extreme ice, wind, wave, and temperature conditions. The structure would be designed to be installed on the seabed, refloated, and moved to multiple drilling sites. Studies have commenced on this state-of-the-art design, which could significantly increase the safety and efficiency of exploration in the Kara Sea. Onshore West Siberia, we are developing a work program for selected Rosneft license blocks, which will include geological studies and drilling, with drilling planned as early as next year. A pilot program will determine the technical feasibility of developing these tight oil reserves. In support of these exploration activities, ExxonMobil and Rosneft have been conducting technical studies on areas of interest, including visits to existing fields and facilities. Moving on to slide 12. We also continue to focus on high-potential, liquids-rich unconventional opportunities in North America, highlighted by activity in the Bakken, Woodford Ardmore, and Western Canada. In the U.S., approximately two-thirds of our operated rigs are drilling liquids-rich opportunities, up from about 20% at the beginning of 2011. On September 20th, ExxonMobil and its subsidiary, XTO Energy, announced the signing of an exchange agreement with Denbury to acquire 100% of their Bakken Shale assets, which consist of 196,000 net acres in North Dakota and Montana, and production expected to be more than 15,000 net oil equivalent barrels per day when the deal closes. The agreement will increase ExxonMobil's holdings in the Bakken region by about 50% to nearly 600,000 acres, resulting in a significant presence in one of the major U.S. growth areas for onshore oil production. Additionally, this acreage is located close to current XTO development areas, generating further efficiencies. The Woodford Shale in the Ardmore Basin of southern Oklahoma comprises our most active unconventional drilling program, with 10 operated rigs delineating and developing more than 260,000 net acres of leasehold. In addition, we are advancing infrastructure projects to optimize the liquids rich production from this area. For example, construction was recently completed on a 117-mile natural gas gathering pipeline from our operations in Southern Oklahoma to processing facilities in North Texas. In Western Canada, ExxonMobil announced an agreement on October 17 with Celtic Exploration, in which ExxonMobil Canada will acquire 545,000 net acres in the liquids-rich Montney Shale, 104,000 net acres in the Duvernay Shale, and additional acreage in other areas of Alberta. Current gross production on the acreage to be acquired is 72 million cubic feet per day of natural gas and 4,000 barrels per day of crude condensate and natural gas liquids. These new assets will complement our existing North American unconventional portfolio. Our financial and technical strength will enable us to maximize resource value by leveraging the experience of XTO Energy, which has expertise in developing tight gas, shale oil and gas, and coal bed methane. Turning now to the upstream financial and operating results and starting on slide 13. Upstream earnings in the third quarter were $6 billion, down $2.4 billion from the third quarter of 2011. Realizations decreased earnings by $130 million, due primarily to lower crude oil and U.S. natural gas realizations, which declined by $2.31 per barrel and $1.40 per thousand cubic feet, respectively. Production mix and volume effects negatively impacted earnings by $700 million due to the impact of lower entitlement volumes, base decline, and downtime, partly offset by the ramp-up of Angola and Nigeria projects. All other items, primarily lower gains from asset sales and unfavorable tax and foreign exchange effects, decreased earnings by $1.6 billion. Upstream after-tax earnings per barrel for the third quarter of 2012 were $16.39. Moving to slide 14. Oil equivalent volumes decreased by 7.5% from the third quarter of last year due to the impact of base decline, lower entitlement volumes, divestments, and downtime. Volumes were positively impacted by the ramp-up of projects in Angola and Nigeria. Excluding the impacts of entitlement volumes, OPEC quota effects, and divestments, production was down 2.9%. Turning now to the sequential comparison starting on slide 15. Upstream earnings decreased by $2.4 billion versus the second quarter of 2012. Higher crude oil and U.S. natural gas realizations positively impacted earnings by $340 million, as crude oil realizations increased by $0.77 per barrel and U.S. gas realizations increased $0.54 per thousand cubic feet. Production mix and volume effects decreased earnings by $540 million due to base decline, downtime, lower entitlement volumes, and seasonal demand in Europe. Other items, including lower gains from asset sales and higher expenses, decreased earnings by $2.2 billion. Moving to slide 16. Oil equivalent volumes were down 4.6% from the second quarter of 2012 due to downtime, base decline, seasonal demand in Europe, and lower entitlement volumes, partly offset by the ramp-up of projects in Angola. Excluding the impacts of entitlement volumes, OPEC quota effects, and divestments, production was down 3.6%. On slide 17, we show the year-to-date 2012 volumes associated with the expected 3% full-year decline provided at the analyst meeting in March. Operational performance through the third quarter was slightly below forecast, reflecting the timing of work program execution, duration of downtime events, particularly in the North Sea, and the efficient use of capital in Iraq, which has lowered net volumes. Additionally, the continued focus on enhancing profitability through the shifting of North American drilling to liquids-rich opportunities has contributed to the variance. Per quarter were $3.2 billion, up $1.6 billion from the third quarter of 2011 as we continue to optimize our refineries by fully utilizing operational and feed flexibility and the integration with lubes and chemicals. Improved margins, mainly in North American and European refining, increased earnings by $850 million. Volume and mix effects decreased earnings by $20 million due to lower earnings associated with assets sold, largely offset by favorable refining optimization effects. Other items, including a gain on the sale of our downstream business in Switzerland, favorable Forex, and lower operating expenses increased earnings by $780 million. Turning to slide 19. Sequentially, third-quarter downstream earnings decreased by $3.5 billion. Improved margins, primarily in refining, increased earnings by $650 million. Volume and mix effects, mainly driven by lower planned maintenance and refining optimization activity, increased earnings by $300 million. Other items reduced earnings by $4.4 billion, primarily due to the absence of the gain associated with the Japan restructuring, partly offset by the gain from the sale of our downstream business, along with favorable Forex and lower operating expenses. Moving now to the chemical financial and operating results and starting on slide 20. Third quarter chemical earnings were $790 million, down $213 million versus the third quarter of 2011. Margins decreased earnings by $150 million, mainly due to lower olefin and polyolefin realizations. Other items decreased earnings by $60 million, mainly due to unfavorable foreign exchange impacts. Moving to slide 21. Sequentially, third quarter chemical earnings decreased by $659 million. Weaker margins, mainly in Europe, decreased earnings by $90 million. Other items, primarily the absence of the gain associated with the Japan restructuring, decreased earnings by $590 million. Moving to slide 22. ExxonMobil's third quarter financial and operating performance reflects the value of our integrated business model and other competitive advantages. We earned $9.6 billion, generated $14 billion in cash flow, invested $9.2 billion in the business, and distributed $7.6 billion to our shareholders. As we continue to focus on operational excellence, deploy high-impact technologies, and leverage our unparalleled global integration, ExxonMobil remains well-positioned to maximize long-term shareholder value. That concludes my prepared remarks. I would now be happy to take your questions. Thank you, Mr. Rosenthal. 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 1 on your touchtone telephone. We request that you limit your number of questions to 2 so that 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, ladies and gentlemen, it is star 1 to ask a question at this time. We will pause for a moment to assemble the queue. Our first question will come from Doug Leggate with Bank of America. Thank you. Good morning, David. Good morning, Doug. How are you? Not too bad, thank you. I hope you are well. I have got a couple, please. Well, one and one follow-up, I should say. I understand at the Analyst Day you gave us an indication that production would be down this year, but it seems that it is sliding a little harder than certainly we expected. At the same time, the capture rate, that is, as you know, the earnings against your weighted revenues has deteriorated somewhat this quarter. I am just wondering if you still feel confident in the medium-term outlook and if there was something unusual in this quarter that impacted the earnings capture? I have got a quick follow-up, please. Sure. Let me first address, Doug, the volume decline. As I mentioned in the chart in my prepared remarks we are only slightly below what the outlook would have generated if not for, as I mentioned, the price and entitlement effects of the higher crude prices earlier in the year and some divestments. I will say that when you look at the slight underperformance, if you will, on the operations side, a piece of that effect, a big piece of that bar is the fact that we have been able to generate the production volumes that we were looking to get in Iraq with less capital being expended. Because we expended less capital and were more efficient we did not get as many barrels back. We have also had some extended downtime, a little more than we thought particularly in the North Sea and some other areas. But other than that, just some timing of some work program and some of the other things I mentioned. But other than that, we are pretty much online with what we were looking at. If you are looking at the capture rate in particular in the upstream, I think the biggest driver there, of course, is going to be the mix of the volumes that we had and where we had some of that downtime across the quarter in Kazakhstan and some other areas that we had some downtime, North Sea, et cetera. Other than that, when you look at the other earnings effects, not a lot in there in terms of items other than the fact that we were about $1 billion less quarter-over-quarter this quarter on asset divestitures. So I think if you sort those things out, we are pretty much as we would have expected to be. Great. Thank you. My follow-up, David, is hopefully fairly quick. There is obviously a lot of other deltas this quarter, the other items that you talked about. But again, just like last quarter, they are not as big, but they are still fairly sizable, particularly in the downstream. So I guess there are two points to my question. The first one is, would you be able to quantify the absolute impact of the major parts from disposals and foreign exchange effects as opposed to the relative impact? And just as an observation, at what point or what is the philosophical reason for not providing the absolutes on a quarterly basis, because it would be extremely helpful if you were able to do that. Yeah, Doug, let me hit a couple of those. First of all, foreign exchange is one that is impossible to give an absolute because as you know, you have got both changes and impacts on your working capital balances. Those are specific. But when you are looking at the impacts on the earnings, it is really just the translation of margins and OpEx using exchange rates last quarter and this quarter. So you do not have an absolute amount on that. If we look across the corporation, though, I will tell you that quarter to quarter, the impact was very small, and I am happy to talk about the details. If we go specifically to the downstream earnings, I think, which is one you are interested in, if I am looking at downstream earnings, third quarter of 2012 versus third quarter of 2011. Again, you saw the nice margin bump there of $850 million. That is really clean. There is no lag effects or other things in there. We were just able to have all of our operations running strong and take advantage of the strong market that we saw there. On the $780 million, if I move over to the other column, I am happy to give you some additional color there. The biggest part in there was about just under $400 million for our divestments in the quarter. Favorable Forex quarter versus quarter was another $300 million, and the balance was favorable OpEx. And that pretty much takes that out. Volume, pretty minimal. Where we lost volumes in some of the divested assets, we were able to make up those earnings by higher volumes and throughput in some of our other operations. Okay. I will take the rest offline. Thanks, David, for answering the question. Okay. Thank you. Our next question will come from Evan Calio with Morgan Stanley. Morning to you. Or afternoon, I guess. I just have a question, relates to the Celtic acquisition in the quarter, and does this deal reflect any change or evolution in Exxon's view of potential Canadian or British Columbian specific LNG export potential with your bigger Montney position now? I don't think it changes any of our views or thoughts we have going forward. The Celtic acquisition gives us an opportunity to pick up, as I said, about 545,000 net acres in the Montney. Most of that acreage is near acreage we already have, so it's very helpful to us. It's just a continuation of what you've seen for the last couple of years where we have taken advantage of opportunities to go out and acquire large tracts of promising acreage with high upside potential and bolt those on to the XTO acquisition. In particular, I think what you've noticed over the last year or so is these acquisitions have tended to be more on liquids rich properties than the gas things that we added early on. So no change. I will say, though, that of course, this gives us tremendous opportunities across North America, all of which we are looking at, as you mentioned. I think we've mentioned before that we are in the early stages of assessing potential export options from Alaska, from Western Canada, and from the U.S. Gulf Coast. So we're fortunate to have large resources in each of those areas. Again, as we develop our plans and go forward, we'll have more to say about that. But I'd say it's really a continuation of the strategy that we've had in place now for the last couple of years. That's great. Maybe just one other follow-up, if I may, to Doug's question. Relating to upstream volumes, can you quantify or discuss the turnaround activity? I guess that contributed to what you're defining lower operational performance. I guess specifically, and I guess your comments, it may not, but just confirm that you don't see that extending into the fourth quarter. I'll leave it at that. Thanks. Sure. I think the best place to look at really where we're seeing the impact of this downtime, if you look quarter on quarter, third quarter 2012 versus third quarter 2011 over in the net growth where we had the minus 125, about 40 of that is downtime across a number of areas. Most of it's scheduled that you're well aware of. We had some downtime in Qatar, Tengiz, Alaska, and the North Sea. So that impact showed up there. You also see it particularly if you're looking sequentially, because as you know, a lot of this downtime is seasonal, but the downtime effect between the third quarter of this year and the second quarter of this year was about 90 KBD OEB, so significant effects. Most of that production is pretty much back up. We do have some continued downtime in operated by others' properties in the North Sea. But other than that, the rest of the production is coming up as we would have expected heading into the fourth quarter. Great. Thanks for taking my question. Thank you. Thank you. Our next question will come from Robert Kessler with Tudor, Pickering, Holt. Good morning. A couple quick ones from me. Sure. One, your U.S. natural gas volumes declining quite considerably sequentially. I am wondering if there is any anomalous items in there. Of course, we had hurricanes. I would not have thought you would have been proportionally exposed to that. What can we assume for a, say, normal decline rate in your U.S. natural gas volumes going forward? Yeah. If you look sequentially at our U.S. gas, we had a little bit of an impact from weather-related activity, but it was not large. You did see a decline sequentially of about 5%. Some of that was downtime, but the majority of it was base decline, and really the impact you are seeing as we are shifting rigs from drilling primarily gas plays to drilling liquid-focused plays. The total rig count is down across the year, and the proportion that is drilling liquids rich plays versus gas has gone up. I think between that and some downtime, that really accounts for the bulk of the reason we are down. Now, as you look forward, I really do not have an outlook for you. It will be dependent on how we bring things along and the market and that sort of thing, but clearly you are seeing the impact of our changing focus from dry gas to liquids rich opportunities. Okay, thanks for that. Then a conceptual one for me on M&A. Your recent North American-focused transactions have, of course, further increased your upstream weighting of capital employed to North America. Your U.S. weighting alone was, I think, 46% in the upstream capital employed at the end of last year. Looking at future acquisition possibilities conceptually, does ExxonMobil apply any limit to the capital you plan to deploy to North America, or would you continue to look at potential North American M&A the same way you would look at opportunities globally? Yeah, let me step back. That's a good question. As we step back and look at our total capital budget and where we put our CapEx, we really don't have any limits in terms of type of resource or geographic focus. We pursue all of the attractive opportunities that are out there. As you look across the last several years, you've tended to see us sometime putting more CapEx into oil sands or unconventional plays or LNG. But all of that is really reflective of the opportunities as they're presented and our ability with our strong financial strength to basically take advantage of anything that's out there that's on offer that we think will provide shareholder value. As you've seen over the last couple of years, the bulk of that has been through internally generated CapEx, but there's also been some selective acquisitions. I would say going forward, you'll see us continuing to do what we've been doing, which is to look at all the opportunities that are out there on offer and taking advantage of any opportunity we have to really enhance the portfolio of our assets with the focus continuing on the long term. If you look at all the things we've been doing over the last couple of years, they're all focused on bringing really long-term legacy projects up and get them running, and then continuing to add to our resource base and our opportunities for the future. So I wouldn't see anything different going forward than what we've been doing. But we'll continue to look for attractive opportunities wherever they present themselves. Understood. Thanks, David. Thank you. Next, we will hear from Doug Terreson with ISI. Good morning, David. Morning, Doug. Some of the global competitors are indicating that global oil demand may be gravitating lower again. On this point, given your global perspective, I wanted to see if you could provide insight into some of the demand trends that ExxonMobil is seeing around the world, and specifically whether you guys are witnessing any deterioration in this area. Second, for Exxon specifically, R&M was clearly strong in the quarter, but the company did not seem to benefit to the degree that some of the competitors did. While you talked about some of the cost factors a minute ago, was there anything unusual on downtime, either planned or unplanned, that affected results? If so, do you have any quantification in that area? Yeah. Let me start at the first one there with the global oil demand. I don't think we're seeing anything different than what others are seeing and what you're reading in the press in terms of demand, particularly, say, in Europe and Japan and some other areas. We'll be putting out our own update here in December on our view of global oil demand. Again, I think from our perspective, I wouldn't have anything to offer any different than what you're seeing out there. Okay that they're talking about. Okay. The R&M results, as you mentioned, were really strong. Again, I have to say, we were able to have very good operations uptime, able to take advantage, in particular in the U.S., of the discounted feeds, both heavy Canadian feeds as well as WTI-linked crudes, and so we're optimizing those across our Mid-Continent refineries, and you're seeing some of those impacts showing up in the bottom line. If you're looking at downtime, I think was the rest of your Yeah comment in the downstream? Yeah. Was it unusual in the period? You saw a little bit more in the second quarter and less in the third quarter as we came out. I will just give you a little more color. If you were looking sequentially from third quarter of 2012 onto, again, I am sorry, the third quarter versus the second quarter, we did see some lower OpEx, somewhere between $100 million and $200 million you would have seen there to the quarters, and that would have helped that. But again, the bulk of the earnings driven by good operations and favorable margin impacts. Okay, thanks a lot. Thank you. Thank you. Next, we will hear from Allen Good with Morningstar Investment. Good morning, David. Hi, Allen. How are you? Good. How are you? Just a quick question on the M&A. Obviously, you mentioned some of the activity you have had relatively, probably a little bit more than some of your competitors of late. Can you talk a little bit about the characteristics that Exxon Mobil looks at when you go out there and survey those market opportunities that are out there and some of the things that maybe you have learned from XTO Energy since acquisition as far as what may be the better plays or any sort of knowledge you have gained from XTO Energy that helps you to better delineate those market opportunities as far as acquisitions go? I'll actually start with your second question and back up into the first. Clearly, one of the synergies that we anticipated getting with the XTO acquisition that have been realized in the last couple of years is the ability to utilize the expertise and knowledge that they had, combined with some of our technology advances, to better analyze and evaluate properties that are out there. You've seen that if you look at some of the acquisitions we've made in the U.S. of properties, and some of the deals we've done elsewhere and up in Canada. A lot of the ability to properly evaluate the resource potential of those properties and assign value to them stems directly from the organization that came with the XTO acquisition, and that is working just as we had planned. As you look at M&A or any other resource opportunity capture, we look for the same thing in all of them. Do we have a high-quality large resource with upside potential? That has to be number one. Do we think we can bring some synergistic value to those reserves and perhaps get a better return than someone else could? That comes from either technology that we bring to the table, R&D work, or operational expertise that allows us to then again, get a better value for that than might otherwise would have. Then we look for other more obvious synergies around contiguous properties to what we have or other ways of filling in a portfolio to perhaps be able to pursue a larger strategy. M&A versus outright capture of these resources, the criteria for us remains the same, and we really don't differentiate between the two. Okay, thanks for that. Then just a second question. Can you update us on the North American rig count? I believe you were close to around 50 in the last quarter, and you mentioned that I think over half those were in liquids rich plays. Are you continuing to move drilling away from dry gas at this stage? Yeah, I think as we looked across the quarter, we ended at about 50 rigs. We're probably close to that today, maybe a rig or two less as we speak. Two-thirds of those rigs are drilling the liquids-rich opportunities. In particular, I mentioned the Woodford Ardmore is an area of high activity for us. The Bakken, of course, an area of high activity, and the Permian is another area of high activity for us. So you do see this shift going into the areas that are more liquids rich. I think as you go forward, without giving any specific counts, I think you could expect to see us continuing to pursue those liquid-rich opportunities, particularly in the areas that I mentioned. But I don't have a specific outlook for you in terms of total rig count going forward. Thank you for that. Thank you. Next, we'll hear from Blake Fernandez with Howard Weil. David, good morning. Hey, Blake. You briefly mentioned LNG, and I was hoping you could maybe give us an update on where you stand in the application process out of the U.S. Gulf Coast, and then maybe more broadly. You kind of mentioned potential from Western Canada, Alaska. Could you maybe rank order where you see the best opportunities, if possible? I know it is early days yet. Sure. Let us start with the Golden Pass opportunity that we are assessing. Early in October, we received authorization from the US Department of Energy to export domestically produced natural gas as LNG from Golden Pass to nations that have existing free trade agreements. So we do have that approval in hand. I can also tell you that we have recently filed an application with the US Department of Energy to export LNG to non-FTA countries. We will see how that application process proceeds. I have to say, though, when we look at all of these activities, they really are all in the early days, and no decisions have been made. Again, we are very fortunate to have a material high-quality gas resource in both the U.S. Gulf Coast and in Western Canada and Alaska. It would be way premature to try to rank order those other than to say they are all high-quality resources for us, and we are looking at all of the options available to monetize those resources. Including, again, early days on assessing the viability of LNG exports from any one of those three regions. Yep, fair enough. The second question was on the Gulf of Mexico shelf. As I understand it, you had formed maybe a JV with a smaller E&P player to target, I guess, a deep oil play, similar to what some of your peers are doing on the gas side for deep gas. I am just curious if you had any updates on that. If I am not mistaken, there was going to be a well spud toward the end of the year. I do not have a specific update with regard to that joint venture. We do have that transaction as was publicly discussed, but I really would not have any update, particularly near term, on what our activities are going to be on that. Okay. Thanks a lot, David. I will just mention, though, if you look across the broader Gulf of Mexico, you do see a nice increase in activity as we continue to develop some of these properties that we have captured over the last couple of years. I mentioned some of those in our prepared remarks, and we are very excited about getting some of these wells down and continuing the broader exploration phase, which as you mentioned, has a number of partners and a number of structures. But all in, a very good opportunity for us and one we are pursuing pretty quickly. That is great. Thanks a lot, David. All right. Thank you. Our next question will come from Arjun Murti with Goldman Sachs. Thanks. Dave, just a few follow-ups on some of the North America type questions. Sure. You have been pretty clear you have pulled back on some of the gas drilling in the U.S., and we saw a little bit of that decline show up. I guess, when you slow down the drilling in unconventionals, the declines can be pretty precipitous. Just wondering, maybe as a follow-up to the earlier question, is 5% just the beginning of what could be a more rapid decline in your gas production? Or is there something that is not fully apples to apples about this decline, and it will not be as bad or worse going forward? Yeah. I do not have a specific outlook for you, Arjun, but I will note there are a number of factors, in addition to just some of the shifting of these rigs. We did have some downtime in the quarter. If you look this year versus last year, you will recall we did have some asset sales last year, and we are seeing a little bit of that. Again, if you look just over the last quarter in particular, downtime and then just normal decline associated with this. But I do not have a decline rate for you or a go-forward outlook. We will see how things go. I will tell you, in some areas, we have actually been able to keep the volumes flat while reducing the rigs due to efficiencies we have gained, rates of drill wells, and that sort of thing. We have been able to offset some of this decline in rigs with some improved operations and productivity. In terms of the shift, Dave, to liquids rich, would you say you have made the shift now, or is there still more gas rigs to come out of the rig count? Well, I think, what you will see is we will continue to have this focus on the liquids-rich plays. Exactly how many more rigs might move, I do not have a specific number for you. We do have contractual obligations that we have to meet and other commitments which will keep us drilling some dry gas wells. But we evaluate this thing on an ongoing basis, literally, day to day and month to month in terms of how we optimize the rigs we have available to us, what the market is generating, how the wells are performing. So I really would not have a forward look for you. Dave, maybe just lastly on the same topic. Clearly, you are increasing the emphasis on liquids rich. You mentioned the Permian, Bakken, some of these places. In terms of having that show up visibly in your U.S. liquids oil volumes, I assume there's some lag for that to happen. I do not know if you can comment on that at all. Yeah. You are seeing that show up in the liquids volumes as some of this ramp up. Most of what we've been doing in these areas for the last several months has been delineating what we have, appraising what we've been doing, looking at what the optimum parameters are for developing these fields. Now you're starting to see us ramp up on the production side, particularly in the Bakken, where we're up, I think, just under 50% year-on-year, if you look at the third quarter. So you're starting to see some of that. You'll start to see some of that in the other areas as well, the Woodford Ardmore, for example, and the Permian as we continue to move into more of a development mode. I do not have a number for you other than to say yes, if you look at those fairly small decline rates on U.S. liquids, you are seeing the impact of normal decline on our conventional fields being offset somewhat by ramp-ups in some of those other areas. I will say, if you take out Alaska and just look at the lower 48, our liquids volumes are actually up quarter versus quarter and sequentially. So some of that downtime is masking some of that performance. That's helpful. Thank you so much. Thank you. Our next question will come from Faisal Khan with Citigroup. Yeah, good morning. It is Faisal Khan from Citigroup. Good morning, Faisal. Good morning. I want to go back to the production outlook for a second. At your analyst meeting, you guys discussed how production capacity would grow at some rate through 2015. Given your comments around decreased drilling of natural gas in the U.S., also, for that matter, decreased investment in Iraq and potentially an exit from Southern Iraq, I am just trying to figure out how this impacts your future production capacity growth targets, and for that matter, reserve replacement, too? Sure. First of all, I don't have a new outlook on the outer years. We're just in the process of pulling our plan together and looking at what the future looks like, so I don't have any updates. Of course, we will provide an update in March at the analyst meeting. I will say, if you look at all the big projects that we have going on out there that we've been building for some time those are all in the process of starting up as planned. The projects we had this year in Angola and Nigeria. As we look out a little further, of course, the startup of the Pearl project. Then as we move into the following years, the Banyu Urip project in Indonesia and all the other large projects, Papua New Guinea LNG, Kashagan, Gorgon, all of those projects that we got still going in the ground, all of those are still in the plan, and that portfolio remains very strong. I don't have an update around on that. The second part of your question, Faisal? Yeah. David, on Southern Iraq, what are your plans in the country? Yeah. If we look at Iraq, the comment I made was we're now producing right at about 430,000 barrels a day of oil, right on plan. The good news is strictly that we've been able to do that a little more efficiently than we had expected. But I don't have any other update on Iraq other than that we continue to work and continue to meet our contractual commitments. Okay. Thanks, David. Just one last question. On your chemicals business, on the expansion of your Singapore facility, can you give us a status update on that and how that facility is operating, if it is up and running and if you are moving product into the markets? Sure. The simple answer would be yes to all three of those questions. The project is nearing mechanical completion. As we have talked about before, several of the various pieces of that project have been progressively starting up. We were able to produce, for example, metallocene-based polymers here earlier in the year. We do have product qualification activities underway for those products. The overall project is coming right along. The very last project to reach mechanical completion is the steam cracker. We do expect completion of that by year-end. We would certainly expect to be mechanically complete and on track for starting that large investment up and moving that product into the market. The project is doing well. The Asia-Pacific area, as you well know is looking at bottom of cycle margins right now. Not surprisingly, that remains a cyclical business. One of our strengths has been for a long time investing through these cycles. It was very strong a year or two ago. It is weak now. This project as you can well imagine, is really designed for the long term where we remain very bullish on growth in that part of the area. The long-term view remains the same. The project is on schedule to start up and be mechanically complete by the end of the year, then we will progress the ramp-up of that as we go through the first part of next year. Thank you, David. Thank you. Thank you. Our next question will come from Pavel Molchanov with Raymond James. Thanks, guys. Two quick ones on Celtic, if I may. As I'm sure you saw, the Canadian government recently vetoed a purchase by another operator of a domestic oil and gas company. Any concerns about getting approval for the Celtic purchase? Our approval process is the same as everyone else's, and we're progressing through that. We have a long history of operating in Canada. We've been there a long time. We're looking forward to getting through the approval process and closing on that deal and moving forward with our plans for those resources. Okay. Assuming the deal goes through and given what you said about curtailing dry gas drilling across North America, is it safe to say that you would pull back on relative to the current level of drilling activity across Celtic's acreage? I don't have any outlook today on exactly what specifics we'll be doing with that once the deal closes. The deal hasn't closed yet, so it'd be premature for me to make any comments about our plans going forward. All right. Appreciate it. Thank you. Next, we'll hear from Edward Westlake with Credit Suisse. Hey, David. Thanks for taking my questions. Just two quick earnings questions. If I turn to slide 15, this is the upstream sequential 3Q to 2Q. Obviously, there is that $2.2 billion negative other and $1.1 billion of it is asset sales. But can you give us some color onto what the other $1 billion is in terms of the changes? Yeah. You did that for the downstream. That was helpful. Yeah. This is the sequential that you are looking at. Yeah, 2Q versus 3Q. Yeah, on that, a couple other factors in there. OpEx is a negative $200 million. Forex is a negative $100 million. Then the combination of asset sales and tax items is about $1.8 billion. Right. Okay. The main driver of the OpEx and tax related, we did have the change in the U.K. tax. But if you roll it all up, just think about OpEx, a couple of hundred million, Forex, 100 million, taxes, 100 million, and the balance in the asset sales and tax items. Yep. Those tax items, were any of those deferred or were those ongoing? No, some of those were deferred. Right. Okay. On the chemical business in the U.S., obviously Baytown had some disruption in the first half. I guess Q3 was a good result. Is that a fair kind of run rate for the macro conditions that were in Q3, or were there any disruptions in the U.S. portfolio for chemicals? No, we didn't really have any disruptions of any consequence, kind of normal operations and nothing really to speak of. Like the downstream, our chemical operations ran well in the third quarter, and no major items. Coming to a question on cash and buybacks, et cetera. Obviously, your ending cash at the end of the quarter was lower than the beginning of the quarter because $14 billion of cash flow doesn't cover the dividend plus buybacks plus the spend on these large mega projects. Are you comfortable to let cash balances fall, or is this some kind of statement about the future cash earnings power of Exxon as these big projects come on, which means that ultimately, this level of buybacks is appropriate? Yeah, I think the first thing I'll note, Ed, is that we did spend $3 billion of our cash when the SeaRiver debentures matured in the quarter. That was a $3 billion hit there. In terms of overall strategy around cash, no change in our approach there. We maintain sufficient cash to run the operations and keep our flexibility for doing other things in the business. But really don't have any particular change or outlook in terms of cash or debt. We'll optimize that as we go forward, depending on business conditions. Okay, thanks very much. Thank you. Next, we will hear from Paul Cheng with Barclays. Hey, guys. Good morning. Good morning, Paul. I have three, hopefully, really short questions. First, versus the second quarter, you indicate that production dropped 39,000 barrels per day due to entitlement. I presume that that is all primarily related to changing payout ratio in some of your projects. The question is that do you have any major projects about to change their payout ratio over the next 1-2 years? Yeah, let me talk about the first one. I'll give you a little more color on that 39,000 barrels a day, Paul. It was about half was permanent, the net interest impacts, and the other half was on price and spend, so kind of a mixture there, neither one of them having a significant impact. Going forward, when we look at near-term production, of course, the biggest factor for us is the price, because that drives how many barrels you get to recover your cost as well as how quickly you go through the tranches. Looking forward here, particularly near term, I don't have an outlook number to provide you specific to what the sequential price and spend impacts might be, but again, the biggest factor there is crude price. Do you have any major project that is about or that potentially could be they move to the next payout ratio within the next one or two years if the current oil price stay? Paul, I really don't have any specifics along those lines in terms of project by project. We'll really talk again about the makeup of our volumes going forward when we visit with you in March, and so I'll probably just hold any comments about future volume outlooks to that time when we can kind of wrap in the whole story for you. Okay. Can you tell us that what is your total shale oil production as of this, in the third quarter or as of this point, and break out between the oil and gas? If you are looking at our unconventional volumes, I do not have a total for you on that, Paul, or a split between oil and gas. I think the important thing is as you are looking at the progress that we are making, again, some of these improvements we are making year-over-year, in the Bakken in particular, for example, and some of the other areas. I think that the progress we are making in those fields, particularly as we transition from delineation and appraisal into more development, is probably more important than the absolute production that we are seeing on that. And the progress that we are making, but I really do not have a specific number to provide for you. Just a real quick one, last one. Do you have the absolute value of the asset sales gain in the quarter? Do you have any meaningful inventory gain or price finalization impact for your long-haul barrel on the water in this quarter? Yeah, let me hit that second question, and then I will back up to the first one. If you look at the absolute number in the third quarter, it is almost zero in terms of all the price timing, price finalization, long-haul crudes. We did have a negative effect in the second quarter, but if you look at our absolute results in the third quarter, there really was not anything there. If you were looking at the absolute value of the divestments in the third quarter, that was about $400 million, and the biggest item there was the downstream divestment of our business in Switzerland. Thank you. All right. Thank you very much. Thank you. Next, we'll hear from Iain Reid with Jefferies. Hi, David. Hello, Iain. How are you? I am doing very well. Very well, indeed. I just got a couple of quick questions about your international assets. On Kurdistan, do you want to give us your thinking about the drilling program there, and when we should be looking for results, et cetera? Yeah, Iain, I have to say, I really do not have any comment on Kurdistan at all to offer today. Really? But you do have a program going on, though. Yeah. As I said, I really just do not have any comment on Kurdistan today. All right. Okay. I'll try another one then. Papua New Guinea. What's the status of the planning for train 3? You obviously made some pretty good progress on the first two trains. I believe train 3 is in the works now. When should we look for FID on that? Yeah, let me first back up just a second and let you know that our primary focus, of course, is on our existing project. That project is coming along very well, and we are on schedule for startup in 2014, and that's our primary focus. If you look at how we're doing on the exploration side, we do have a number of opportunities in the area, and we have a very active, broad exploration program going on. We have had some success this year in the P'nyang well, so that's looking good. Obviously, as we continue to evolve and mature our resource base in the area, we'll be looking at options for monetizing those resources, and I can't give you any outlook in terms of when we'll make final decisions on any opportunities. We are in the early stages of looking at what we have, thinking about what we might want to do, and that would, of course, include a potential additional train in Papua New Guinea. All of that will be depending on the exploration success that we have and how we look going forward. In the meantime, I think the really positive news for the shareholders is the project is progressing and progressing well, and the area's looking very promising for us. Yeah, just another comment on PNG. I notice you didn't take up the farm out, which Oil Search was offering in the exploration areas there. Does that indicate that you've got enough of PNG, or what was your thinking there? I wouldn't want to make any comment on any thoughts or rumors or speculation on deals that we've done or not done. We look at a lot of things, but again, I wouldn't make any specific comment on any particular potential transaction. Okay. I thought so. Now, last one, I think you can help me with. West Siberia tight oil. What's the structure of the contract or the agreement there with Rosneft? Are you carrying them through this, and any idea of outline costs and volumes, et cetera? If you're looking at West Siberia, we are, as I mentioned, looking at, we're already actively studying what we're going to do in that pilot program. Hope to get a well down in the first quarter. In terms of specific details of the commercial arrangements there, probably premature to be talking about that given where we are in the stage. So I won't be able to help you on that question after all. But you do have a 30% interest, is that the way it works? Yes. Okay. It's a two-thirds, one-third Rosneft and Exxon Mobil. Okay, David. Thank you very much. All right. Thank you. At this time, we have no further questions in the queue. Mr. Rosenberg, I'll turn the conference back over to you for any additional closing remarks. I would just like to thank everybody for your participation today. I know many of you are probably participating under some probably fairly difficult personal situations. I wish you all the best in that regard. Thanks for the good questions, and I look forward to seeing you in about 3 months. Thank you very much. Thank you. Again, that does conclude our conference for today. We thank you for your participation. You may now disconnect.