Earnings Call: Q2 2013

Aug 1, 2013

Summary

Q2 earnings fell to $6.9B as prior-year restructuring and divestment gains did not recur, while refinery maintenance and weaker margins weighed on downstream results. Volume and CapEx outlooks were unchanged, with major projects and unconventional liquids advancing.

Good day everyone, and welcome to this Exxon Mobil Corporation second quarter 2013 earnings conference call. Today's call is being recorded, and at this time for opening remarks, I would like to turn the call over to the Vice President of Investor Relations and Secretary, Mr. David Rosenthal. Please go ahead, sir. Good morning, and welcome to Exxon Mobil's second quarter earnings call and webcast. The focus of this call is Exxon Mobil's financial and operating results for the second 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 second quarter. The U.S. economy continues to be sluggish after first quarter GDP growth was revised downward. China's economic growth continues to lag expectations while European economies remain weak. Energy markets delivered mixed results in the second quarter. The quarterly average Brent crude oil price declined more than $10 per barrel from the first quarter, narrowing the spread with WTI, while U.S. natural gas prices increased. Global industry refining margins were essentially flat, with increases in the U.S. margins offset by weakness in Europe and Asia Pacific. Chemical commodity product margins declined across the quarter. Turning now to the second quarter financial results as shown on slide 4. Exxon Mobil's second quarter 2013 earnings were $6.9 billion, a decrease of $9.1 billion from the second quarter of 2012, mainly reflecting the absence of prior year gains associated with the Japan restructuring and divestments. Earnings per share were $1.55. The corporation distributed $6.8 billion to shareholders in the second quarter through dividends and share purchases to reduce shares outstanding. Of that total, $4 billion was used to purchase shares. CapEx in the second quarter was $10.2 billion and $22 billion for the first six months of 2013, in line with anticipated spending plans. Cash flow from operations and asset sales was $8 billion. At the end of the second quarter, cash totaled $5 billion and debt was $19.4 billion. The next slide provides additional detail on second quarter sources and uses of funds. Over the quarter, cash decreased from $6.6 billion to $5 billion. Earnings, depreciation expense, changes in working capital and other items, including equity company dividends, and our ongoing asset management program yielded $8 billion of cash flow from operations and asset sales. Uses included additions to plant property and equipment of $8.7 billion and shareholder distributions of $6.8 billion. Additional financing and investing activities increased cash by $5.9 billion. Share purchases to reduce shares outstanding are expected to be $3 billion in the third quarter. Moving on to slide six and a review of our segmented results. Exxon Mobil's second quarter 2013 earnings of $6.9 billion decreased $9.1 billion from the second quarter of 2012, reflecting the absence of prior year's gains associated with the Japan restructuring and divestments. In the sequential quarter comparison shown on slide seven, earnings decreased by about $2.6 billion across all segments. Guidance for corporate and financing expenses remains at $500 million to $700 million per quarter. Turning now to the upstream financial and operating results, and starting on slide eight. Upstream earnings in the second quarter were $6.3 billion, down $2.1 billion from the second quarter of 2012. Higher natural gas realizations, mainly in the U.S., partly offset by lower crude oil realizations increased earnings by $90 million. Worldwide natural gas realizations increased $1 per thousand cubic feet, while crude oil realizations declined $4 per barrel. Production volume and mix effects had a small negative impact of $70 million. All other items, mainly the absence of gains on prior year asset sales and the reimbursement of past exploratory costs to Rosneft for the Black Sea and Kara Sea joint ventures decreased earnings by about $2.1 billion. Upstream after-tax earnings per barrel for the second quarter of 2013 were $17. Moving to slide nine. Volumes declined by 78,000 oil equivalent barrels per day or 1.9% from the second quarter of last year. Liquids production was down 26,000 barrels per day as field decline and divestments were mostly offset by increased production from liquids-rich plays in the U.S., project ramp-ups, and lower downtime. Natural gas production was down 307 million cubic feet per day as field decline, mainly in the U.S., and lower entitlement volumes were partly offset by higher European demand, lower downtime in several countries, including Qatar, and project ramp-ups. Note that entitlement impacts were all price and spend related. Turning now to the sequential comparison and starting on slide 10. Upstream earnings decreased by $732 million versus the first quarter of 2013. Realizations reduced earnings by about $360 million as worldwide crude oil and natural gas realizations decreased by $5.84 per barrel and $0.56 per thousand cubic feet, respectively. Volume and mix effects decreased earnings by about $300 million, mainly due to lower European seasonal gas demand. Other items had a small net negative impact of about $70 million, as the higher costs in Russia mentioned in the quarter-on-quarter comparison were mostly offset by several small positive items. Moving on to slide 11. Oil equivalent volumes were down about 7% sequentially. Liquids production was essentially flat compared to the first quarter. Higher planned downtime and field decline were mostly offset by improved reliability and project ramp-ups. Natural gas production was down 1.8 million cubic feet per day versus the last quarter, mainly due to lower seasonal demand in Europe. Our year-to-date volume performance is in line with the projection presented at the analyst meeting in March, with strong uptime performance, increased North America unconventional liquids production, and higher European gas demand 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 and starting on slide 12. Downstream earnings for the quarter were $396 million, down $6.3 billion from the second quarter of 2012, due primarily to the absence of the $5.3 billion gain associated with the Japan restructuring. In addition, lower refining margins reduced earnings by $510 million. Volume and mix effects decreased earnings by $370 million, reflecting significant planned refinery maintenance activity across all regions. Turning to slide 13. Sequentially, second quarter downstream earnings declined by almost $1.2 billion. Lower overall refining margins, including unfavorable price timing effects in the U.S., decreased earnings by $170 million. Volume and mix effects decreased earnings by $540 million, reflecting significant planned refinery maintenance activity at Joliet and Torrance in the U.S. and Strathcona, Saudi Arabia, Augusta, and Singapore outside the U.S. This was the highest quarterly planned maintenance activity over the past five years. Other items reduced earnings by $440 million, primarily due to the absence of first-quarter asset sale gains and costs associated with the Dartmouth refinery conversion. Moving now to the chemical, financial, and operating results, starting on slide 14. Second quarter chemical earnings were $756 million, down $693 million versus the second quarter of 2012. Lower specialty product margins reduced earnings by $100 million. Higher commodity product volumes driven by strong polyethylene demand increased earnings by $120 million. The absence of the gain associated with the Japan restructuring decreased earnings by $630 million, while all other items decreased earnings an additional $80 million. Moving to slide 15. Sequentially, second quarter chemical earnings decreased by $381 million. Lower margins, mainly due to weaker aromatics prices, reduced earnings by $200 million, while an improved sales mix provided a $30 million offset. Higher planned maintenance, expenses associated with Singapore's new steam cracker startup, and the absence of gains from prior quarter asset sales decreased earnings by $210 million. Moving next to the second quarter business highlights beginning on slide 16. We continue to advance our portfolio of high-quality upstream projects, which we expect will deliver the liquids growth presented at the analyst meeting in March. The Kearl oil sands development continues to produce pipeline-quality crude. We continue to ramp up production, having now run two of the three froth treatment trains individually as well as concurrently and achieved rates of 35,000 barrels per day through each. The third train is ready for initial operation, and its startup will enable production to increase to 110,000 barrels per day in the coming months. The Kearl expansion project is on budget, ahead of plan, and now over 40% complete. We are using existing Kearl initial development contractors for efficiency and continuity and achieving higher productivity as a result. The expansion project is scheduled for startup in 2015. The Julia initial development project was sanctioned during the second quarter and is expected to develop more than 190 million gross barrels of oil with startup in 2016. The initial development phase is being designed for daily production of 34,000 gross barrels of oil and includes six wells with sub-sea tiebacks to the Jack and St. Malo production facility. Front-end engineering design has been completed, and the engineering, procurement, and construction contracts have been awarded. The field is estimated to have nearly six billion barrels of resource in place. Hebron construction activities continue with commencement of concrete pours for the gravity-based structure, as well as fabrication of the living quarters and drilling support module. Oil recovery from the project is estimated at 700 million gross barrels with upside potential. The platform is designed for production of 150,000 barrels of oil per day. First oil is anticipated around the end of 2017. Turning now to slide 17 and an update on our efforts to progress global LNG projects and opportunities. The map to the left of the chart provides an overview of our LNG business, displaying gross existing production capacity of 64 MTA, sites currently under construction, and a number of future opportunities being evaluated. The PNG LNG project construction is currently 88% complete and is achieving project milestones towards a 2014 startup. Commissioning activities for the first train at the LNG plant are ongoing, while construction activities for the second train continue. Progress also continues at the Hides gas conditioning plant, where equipment, including gas turbine generators and utility systems, is being received and installed. We are also advancing expansion opportunities, including negotiations with InterOil Corporation and Pacific LNG on the future development of the Elk/Antelope resource. Major terms have already been agreed, and should negotiations successfully conclude, ExxonMobil is proposing that 4.6 TCF of the gas resource from the Elk/Antelope field be used to underpin the construction of an additional train at the PNG LNG project site, subject to partner and government agreement. Construction at Gorgon is now 65% complete. Installation of the first subsea trees at Jansz has commenced, and offshore pipeline installation is ongoing. Moving now to North America. Golden Pass Products, our venture with Qatar Petroleum International, recently initiated the FERC pre-filing process, setting the stage for essential permitting activity associated with the design, environment, and construction of a proposed project to produce and export up to 15.6 MTA of LNG. Golden Pass Products already has an export license for free trade agreement countries and awaits approval of its non-free trade agreement license from the Department of Energy. ExxonMobil and Qatar Petroleum International also signed a commercial framework agreement in the second quarter, which demonstrates the project's readiness to succeed based on its technical, financial, and marketing capabilities. In Western Canada, ExxonMobil and Imperial Oil recently filed an application with the National Energy Board for an LNG export license to support the further assessment of the potential development of a natural gas liquefaction terminal on the northwest coast of British Columbia. The export license requested is for up to 30 MTA for a period of 25 years. If developed, the natural gas liquefaction plant, LNG storage, and marine loading facilities are anticipated to be in the vicinity of either the Kitimat or Prince Rupert areas. We also continue to assess other LNG opportunities in Alaska, Australia, Russia, and Tanzania. A range of factors will be considered before any final investment decision is made, in particular, the fiscal and regulatory regime, market conditions, and capital costs. Turning now to slide 18 and an update on our exploration activities. In June, Rosneft and ExxonMobil announced the completion of several milestones under the 2011 strategic cooperation agreement, including joint venture formation for the Kara Sea and Black Sea projects. Collection of seismic data within both regions is underway, and drilling operations are set to begin in 2014. As we announced previously, ExxonMobil and Rosneft agreed to increase the scope of their strategic cooperation by adding seven new blocks in the Russian Arctic, spanning approximately 150 million acres. We have now entered into more definitive foundation agreements for joint ventures to explore within these areas. Foundation agreements are also now in place for a joint venture tight oil project in West Siberia, where data gathering is underway in preparation for drilling. Rosneft holds a 51% interest, and ExxonMobil has a 49% interest in this project. Turning to Romania, ExxonMobil and OMV Petrom have successfully completed acquisition of the largest ever Black Sea 3D seismic survey on the Neptune deep block, covering more than 2,300 square miles. This survey will be used to continue the evaluation of the Domino discovery, as well as to evaluate additional exploration potential on the block. In the Gulf of Mexico, we recently spud the Maui deepwater prospect on Walker Ridge Block 282 after acquiring a 33% interest in the prospect during the first quarter. Turning now to slide 19 and an update on our unconventional liquids activities. In the Bakken play, our gross operated production recently hit its highest level ever, surpassing 60,000 oil equivalent barrels per day. For the quarter, equivalent production increased by 74% over the prior year quarter. This strong growth reflects higher per well production rates due to optimized drilling and completion practices and the shift to more pad development. For example, after rising 20% in 2012, peak 30-day flow rates have increased another 15% in 2013. We have also commenced evaluation of multiple benches in the Three Forks reservoir as part of a larger Bakken project involving XTO and our upstream research company. This initiative has a goal of increasing recovery, identifying further drilling and completion efficiencies, and better defining resource size and distribution across our 580,000 net acres of leasehold. In June of 2013, we started operations at a new cryogenic gas processing plant in southwestern Pennsylvania. Located in Butler County, this 340-acre facility will recover marketable liquids from Marcellus gas production. Two gas compressor stations feed the facility, which is designed to treat approximately 125 million cubic feet per day of natural gas. More than 45 wells are expected to be contributing to production processed at the plant by year-end. In our Appalachian operations, we hold nearly 700,000 prospective net acres across the Marcellus and the Utica shale plays. The liquids-rich Woodford Ardmore shale play in South Central Oklahoma remains our most attractive and active unconventional play with 12 operated rigs. During the quarter, we closed on a small bolt-on acquisition, adding to our core Ardmore area and increasing our total acreage position to more than 280,000 acres. In the quarter, gross operated production reached 31,000 oil equivalent barrels per day, up 73% over the prior year quarter. As noted at our March analyst meeting, we are expanding the play into the overlying Caney Shale. In the second quarter, three Caney wells were completed and brought online as we continue to delineate the reservoir across our acreage. Additionally, our first Caney well is being completed in the Marietta area, southwest of the Ardmore Basin, where the initial Woodford well in April 2012 had a 30-day peak flow rate of just over 700 barrels per day of oil and 1.4 million cubic feet per day of natural gas. Turning now to the downstream and chemical highlights and starting on slide 20. We recently announced expansions to increase Group II premium lube base stock production capacity at our Baytown and Singapore refineries. These expansion projects build on ExxonMobil's strong manufacturing base at these two world-scale facilities. ExxonMobil is the largest producer of base stocks for use in lubricant manufacturing in the world, and these projects will help us strengthen our position as one of the industry's leading global suppliers of high-quality lube base stocks. These expansions will employ ExxonMobil proprietary technologies and increase production capacity of high-value premium lube base stocks by 30%. Both projects are expected to start up by early 2015. Turning now to slide 21 on the Singapore chemical plant expansion project. During the quarter, ExxonMobil Chemical began producing ethylene from the facility's second world-scale steam cracker, more than doubling steam cracking capacity at the site and significantly increasing specialties capacity. We are now able to produce ExxonMobil's proprietary specialty elastomers and metallocene-based polyethylene in the Asia-Pacific region. Integrated with the existing petrochemical plant and powered by a 375-megawatt cogeneration plant, the new steam cracker is among the most energy efficient in our portfolio. The Singapore petrochemical plant is well-positioned to serve growth markets in Asia-Pacific while leveraging our feedstock flexibility and dozens of new technologies. In conclusion, in the second quarter, we earned $6.9 billion, generated $8 billion in cash flow, invested $10.2 billion in the business, and distributed $6.8 billion to our shareholders. 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 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. To ask a question, please press the star key followed by the digit one on your touchtone telephone, and please make sure your mute function is turned off to allow your signal to reach our equipment. Initially, please limit yourself to one question and one follow-up, and we'll take the first question from Faisal Khan with Citi. Please go ahead. If you could elaborate a little bit more on the refining downtime. I know you said this was the most downtime you've had in the last five years, but it looks like the last two quarters in a row, throughput has been relatively lower versus 4Q last year and 3Q last year. Can you discuss how these plants are coming back online, and how is this going to trend for the rest of the year? Yeah. If you look across the year, the first quarter also had a high turnaround workload. As you look at how we're doing this year, the first quarter was high, but the second quarter was even higher. Certainly, if you look prior to this year, over the last five years, it was considerably higher than normal. In fact, about 9% of our capacity was offline for planned maintenance in the quarter. We typically average about 4%-5%. Okay. Going forward, are all these plants back up and running? Are you still have a significant amount of downtime? No, this activity is now behind us, and by and large, all those units are back online and up and running. The other thing I'll mention, Faisal, is we have a long-standing practice of implementing improvement projects, minor projects, anytime we have these large facilities down for an extended time. We have certainly taken advantage of that opportunity, and done a few things at each of the sites to further improve the advantages that they have. Joliet would be an example in the MidCon, where we've done a few things to help improve our distillate production there. Big downtime, all of it planned, all of it coming back up, and we're looking forward to the third quarter and getting these things again back up and running and producing product. Okay, then last question from me. On U.S. upstream CapEx, it looked like it picked up fairly significantly from the first quarter of this year to about $2.6 billion. Can you tell us what's going on in the U.S. CapEx and how that's going to trend going forward? Are you ramping up your rig program in different areas, or how is that progressing? Yeah, we did see a little. If you're looking at quarter-over-quarter in the U.S. upstream, CapEx was up just a little bit. It wasn't anything in particular I can point to. We have added some rigs. Drilling activity is a little higher, and just a number of other spend across the business. Okay, fair enough. Because I was looking from the first quarter to the second quarter, it looked like a big ramp up. Okay. Is that increased rig activity or is that because I thought you guys were cutting back on CapEx in North America on the rig count. I thought that was one of the things that came out of the Analyst Day, but maybe I'm wrong. Yeah. I'm sorry, Faisal. If you are looking sequentially, we are up. We had a couple of minor XTO-based acquisitions. We added some more acreage in the Woodford that I mentioned, and we had a couple of other items. Additionally, drilling was up quarter-on-quarter sequentially by about $100 million. We did have also a net increase in rig activity by a couple of rigs. So it is continuing the program of ramping up the production capability of the liquids and also taking advantage occasionally when we have an opportunity to bolt on a nice piece of acreage that fits in one of our big areas. It makes sense. Thanks for the time. Appreciate it. All right. Thank you. Our next question will come from Ed Westlake with Credit Suisse. Please go ahead. Actually, a follow-on from Faisal Khan's questions. Good morning. Just on the Good morning, Ed. Yeah. Back in refining and chemicals, do you think third quarter will be fully clear, or will you be fully back up in the fourth quarter? We always have a little planned maintenance across the quarters, and there'll be some. But if you're looking across our major plants and the bulk of our maintenance and turnaround activity is behind us. But we'll always have a little bit. But particularly if you're really looking at the second quarter heading into the third quarter and the fourth quarter this year, yeah, there'll be a much lower rate of maintenance activity. And you flagged Singapore startup costs, obviously a big plant. Any number that we could think about in terms of the sort of scale of that in the second quarter so that we can model it for the third quarter? No. Total OpEx in there was up a little bit. Singapore was an item, but it's not real significant in terms of order of magnitude. So as we continue to ramp up a little bit, you'll see a little more there, but nothing I would really single out as being material. Okay. Then a general question on LNG. Obviously, Canada is a big opportunity, Tanzania, and Golden Pass exports. Do you think we'll be talking about that at the Analyst Day next year with some granularity, or do you think it's further off in the future? Oh, I think as we typically do at the analyst meeting, we'll provide an update on all of those opportunities as they progress. Hopefully by then we can give you a little more granularity in terms of expectations. But a number of things to look at and work on in the meantime. I think the good news for us is we have a number of potentially attractive large-scale opportunities out there, and we're assessing all of them. We'll look forward to talking about it more in March. Of course, in particular here in the U.S., we're dependent on getting the permit for non-free trade agreement countries to progress that project. But in the meantime, as I mentioned in my remarks, we are working on other permits. And by the time we get to March, we hope to be able to give you a good update on that. Thanks so much, David. We will now go to Blake Fernandez with Howard Weil. Please go ahead. Hi, good morning, David. Good morning. Actually, I wanted to stick on the Canadian LNG. It sounds like obviously we will get some more detail down the road, but I had a general question for you with regard to the resource potential that you have to feed the facility. Do you feel that you have adequate resources to feed it, or would you rely somewhat on third-party gas? Just any color there? Yeah, I think, in general, we have the resources available to feed that. That doesn't mean that we wouldn't bring in some other, but if you look across our resource base in Canada, in particular, the acreage that we got with the Celtic acquisition, you look at the Horn River, a number of other properties we have up there, we are pretty well positioned just internally to support a major LNG facility, and that's why we're looking at it so hard. But again, it's one of many projects. But yeah, I think we're in pretty good shape. Okay, that's great. Thanks. My second question is really on U.S. natural gas. It seems like the decline has slowed a little bit from what we witnessed in previous quarters, and I'm just curious if that's a stabilization in activity levels or if some of the ramp-up you talked about with regard to Faisal's question, if maybe any of that was in the gas windows. Well, we do have, obviously, when we are drilling in these liquids-rich plays, there is some gas obviously that comes out for that, and that gets produced. And what you are generally seeing there is the base decline rate that you have, particularly if you are looking sequentially across the quarters in the U.S., being offset by a little higher production. It is really just the continuation of the program that we have had in place. It does tend to stabilize. One of the things that is interesting with all these unconventional wells, particularly on the gas side, is you get all these tails that stack up, and by and large, that is a mitigating impact by itself. But we are also seeing very strong performance. I mentioned the Marcellus in particular but also in the Haynesville. We are tracking right along in general some of the things we talked about at the analyst meeting in terms of well productivity, some of the benefits we are getting from advanced completion technologies. You are really starting to see that come into effect, and in particular, also on the liquids side. Whereas we talked about before, we spent a lot of time after the XTO acquisition getting the Denbury trade, doing a lot of delineation, a lot of appraisal, working with the research folks on trying to improve our technologies. And now you are starting to see the fruit of those efforts as we ramp things up, more pad drilling, et cetera. We talked about it before, and I know you have been waiting to see the results of marrying up that XTO capability with ExxonMobil's technology and research, and I think we are starting to see that come up, and we look forward to continued production increases in those areas. I appreciate the color, David. Thank you. Thank you. We will now go to Robert Kessler with TPH. Hi, David. Hello, Robert. A couple of questions if you don't mind, just to quantify some of the variance figures. One being the Rosneft, the amount of that reimbursement amount paid to Rosneft for past exploratory costs. The other one, just the quantification of the unfavorable price timing effects on the downstream. I think you said that was part of the $170 million sequential margin variance. If you could just specify each of those in absolute terms, I'd appreciate it. Sure. I'd be happy to. The Rosneft reimbursement of past costs was $220 million on an after-tax basis. If you look at the total price timing effects for the second quarter of 2013, they were about $166 million in total, about $150 million of that in the U.S. If you compare that to the first quarter, we actually had a $32 million positive. So if you're looking quarter-to-quarter sequentially in the U.S., that was about $183 million negative impact on a sequential basis. Got you. Very helpful. Thank you. All right. Thank you. Next is Doug Leggate with Bank of America, Merrill Lynch. Thank you. Good morning, David. Morning, Doug. David, when we traveled earlier this year, you talked about Rex having a laser focus on efficiency gains, cost improvements, and so on. If we look at the capture rate on your upstream margin this quarter, there doesn't really seem to be a lot of movement. So I'm wondering if you could share some of those initiatives and what our expectations should be coming out of that. I've got a follow-up, please. Sure. I think what I said was a little more broadly, we had a laser focus on unit profitability. As we talked about at the Analyst Day where we acknowledged the fallback we had had in upstream unit profitability given the mix of our production since the XTO acquisition and just reinforcing that we are very aware of this. We are working on it. Some of the portfolio projects that are coming online, and particularly the liquids projects are coming to fruition. We have talked about the mix impact we are going to have over the next 2 or 3 years as all those liquids and liquids-linked projects come on. There is not a specific OpEx program or something like that. It is top to bottom. It is production, it is margin capture. It is bringing the projects online, seeing the improvement in the earnings. Also, I will say, as we always have, continued focus on operational excellence and cost management. That is ongoing, but it is not any one particular program. I will say, if you take out the Rosneft seismic reimbursement and look at some of our unconventional liquids increases sequentially across the quarter and how things are trending, I think you are going to see that upturn on a price constant basis here as we go forward. Thank you for that. My follow-up, I am afraid, is the buybacks. I really just wanted to kind of frame this. Oil prices are obviously a lot stronger, both domestically and internationally. You are targeting production growth with 90% weighted towards liquids, and you have had obviously a big one-off working capital shift in the second quarter. With that backdrop, I know you do not like to talk about the longer term outlook for buybacks, but conceptually, why would you be pulling back on your buyback program given that backdrop? What is your tolerance for net debt on the balance sheet? I will leave it there. Sure. Let me add a little bit to your backdrop comments because they are all quite valid. Let me add just a little bit of perspective on the buyback. If you look back over the past 2 years, so you look at 2011 and 2012, we bought back $20 billion in each of those 2 years in share buybacks. So $40 billion, let us call it, for the 2 years combined. Over that same time period, we had about $20 billion in net proceeds from asset sales, so about 10 a year. So if you put those 2 together and you think about it, we bought back $20 billion a year, 10 of it sourced from our operating activities and 10 sourced from proceeds from asset sales. Then if you come into 2013 and look at the first half, we bought about $9 billion of shares back, have less than $1 billion in proceeds from asset sales. So on an equivalent basis, we've already bought back a little over $8 billion in share buybacks, excluding the proceeds from asset sales. So if you look at it from that perspective, the buyback actually remains quite strong. There's nothing magical about the $3 billion number for the third quarter other than we've just taken a look at, like we always do, expected cash flows for the quarter, our needs, cash requirements, and that sort of thing, and just came up with a $3 billion number. We're also managing our capital structure this year and keeping that in line with our longer-term objectives, but not any more complicated than that. Again, I think sometimes people overlook the fact that that asset management program that we had the last couple of years generated a significant amount of cash for us, and we returned all of that to the shareholder, which I thought was very positive. I hope that answers your question. If not, I'd be happy to talk about it in a little more detail. No, that's great, David. I'll take the rest offline. Thank you. Okay. Thank you. We'll now go to Evan Calio with Morgan Stanley. Good afternoon, David. I look forward to the Pointer Sisters next time before the call begins as well. Oh. I'll look into that. My first question's on PNG. It's clearly a differentiated position for Exxon. I know you discussed your negotiations to acquire additional supply, and you picked up some exploration acreage in the quarter. Could you discuss how additional expansion train economics compare within your portfolio or versus other projects that I know you have reviewed globally? Additionally, with train 1 and 2, I think they were five years from FID to expected first gas. I would presume expansion trains could be much faster than that. Based upon the availability of gas, does Exxon envision replicating a Qatari style development here of two train per year type of concept? I have a follow-up. Yeah, let me kind of start at the back of your question first. Clearly as would be true of any project, once you've got all the facilities in place, the pipelines, the capacity, the trains, the utilities, all the common facilities, any addition is typically going to be quicker and have quite attractive incremental economics. I wouldn't want to give a specific timeframe on an additional train at Papua New Guinea other than to say we have plenty of land space there. We've got plenty of infrastructure. We certainly have the ability to, as rapidly as possible, expand that facility over the course of the next few years. We do have a number of opportunities for gas. We mentioned the InterOil discussions that are going on. We've had some success in exploration recently in PNG South, and we've got some other exploration opportunities in the area. We're optimistic on that. In terms of relative economics of Papua New Guinea versus other projects, I wouldn't want to give any specific comparisons or numbers other than to say we do view that project as quite attractive for us. We certainly look forward to bringing forward some expansion opportunities and continuing to improve even further on those economics. Great. That's helpful. My second question, if I could follow up on the buyback. That's gone from 5 to 4 to 3 on a guidance basis. With limited free cash flow in 3Q, even if we see CapEx flat to down in 2014, we see some continued pressure on that buyback. Really, the question, just to kind of reiterate Doug's question is, would you consider using the balance sheet or larger than normal asset sales to support the buyback going forward, which has also historically supported your very high returns? Yeah. Well, one of the things to keep in mind as we go forward, particularly as you look into 2014, and you get kind of the ramp-up in production, and particularly liquids production that we showed you in the analyst meeting. At current prices, you could certainly expect increased cash flow right from operations. I think as that goes up, and remember, most of these assets, these projects that we're bringing online in the next few years, have two things. One, they're either oil based or oil-linked gas, and they're no decline kind of projects. The CapEx requirements on a maintenance basis will be much lower than your typical oil projects. Then the free cash flow generation out of that and the earnings impact, well, basically 90% of that increment tied to liquids. You have to keep that in mind. When you think about, I guess, the other one was using the balance sheet to buy shares. We manage the balance sheet really around the whole capital structure that we want to manage, and you've seen some increase in our debt levels here over the year. You might recall back three years ago, after the XTO merger, we had about $19 billion of debt on the books. We paid most of that off over the ensuing years. Got rid of that high cost debt. We've replaced that with low cost commercial paper. We do continue to manage the balance sheet, manage the capital structure of the firm, but also always maintaining that balance sheet flexibility that we've talked about. I wouldn't make any specific guidance on use of leverage or the buyback going forward, other than to say we continue to focus on cash flow generation and returning as much of that cash flow back to the shareholders as possible in the form of both increasing dividends, which we did again this year, and the buybacks. Great. That's helpful. I just have one last one, if I could. Sure. No problem. Maybe I missed it. On chemicals in the quarter, were there any impacts of outages there, particularly in the U.S.? I think volumes were a little bit lower. Yeah, we did have some planned maintenance, but it was kind of minimum in terms of the impact in the U.S. One of the things we did see in the U.S. that was helpful was some increased polyethylene demand, and that kind of helped our mix. But we did have some downtime in a couple of areas. But nothing real significant. Got it. Appreciate it. Thank you. John Herrlin with Societe Generale is next. Yeah. Hi. Two quick ones, Dave. Hi, John. With respect. How are you doing? With respect to the Bakken, you said you were going to combine your exploitationists, the XTO folks, with your technical people. Should we expect to see more of an activity ramp given the potential of Three Forks in the Williston? Yeah. I think it would be logical to assume over time, as we continue to develop that resource, particularly taking this kind of full field development approach that you would see as a ramp-up activity over time. I have to say, and I kind of alluded to it in my opening comments, we are really pleased with the progress we are making in the Bakken. Again, it is pad drilling, it is optimized completions. It is changing the way some things are done, incorporating the learnings as we go along. One of the things we have talked a little bit about is not getting in a hurry. You do not want to drill a bunch of wells and then look back over your shoulder and wish you had not done that quite yet because you have learned a bunch. So I think we have a pretty deliberate, disciplined pace of growth in both activity and production. But the gains that we are seeing year-over-year, we would like to continue and do more and not get too far out in front of that curve. Okay, thanks. Next one from me is on the tight oil pilot project with Rosneft. How long will you be in the science phase, next year or so? I think with unconventional resources in general, we are going to be in the science phase for a while. I think if you look at the West Siberia area, tremendous opportunity for that joint venture with us and Rosneft. We are in the process right now of gathering data. But testing will begin this year. So that activity will start up before the end of the year, and depending on how that goes, that will determine the pace heading into next year. But as we have done in all the other unconventionals, we will be prudent. Making sure we know what we have, testing the resource itself, the quality of what we find underground, and then looking for that commerciality determination. But the area has plenty of infrastructure. Plenty of support. So if we can make it work, we will get after it pretty quick. Okay. Last one for me is on Maui. Can you give us any more information on that? Yeah. Maui is drilling ahead. We've not reached target depth yet. Because of that, I really wouldn't want to say much more. Obviously, in the next quarter, we'll have more to say on that. But the drilling's going fine as expected, and we'll look forward to providing a little more update next time. All right. Thank you. Hey, thank you, John. Next is Paul Sankey with Deutsche Bank. Hi, good morning, David. Morning, Paul. David, we're as focused as you are on this net income per barrel or marginal barrel profitability. Sorry to do this, but can we go back to this Rosneft deal first? If I look at the earnings year-over-year, the variance in the other category was $2.07 billion. I think that you said it was $220 million of that was Rosneft. Is that correct? Yes, that's correct. What's the rest? All of the rest. Because it's just a very large number. Yeah. It's very simple. All the rest is the absence of asset sales from last year. We sold our Block 31 in Angola. We booked some of the Japan in there. We had some other minor sales. But that $2.1 billion, it's $1.9 billion asset sales and $200 million for the reimbursement of past costs. Got you. I think generally speaking, because we are as focused as Rex is on this issue, the more detail we can get on this sort of noise, the better. Sure. That would explain why the sequential earnings were down only $70 million in other, but would include the $220 million. Yes Of Rosneft, right? Yes, that's correct. Then there's obviously, whatever it is, 100 and something offset. Positive. Yeah. Paul, it's a number of small items. Nothing really big to point out. But yeah, I think the important thing there is just what you've noticed. It's pretty clean on the other when you've got all the factors in, particularly given that we had a negative $200 million in there for the Rosneft cost. Yeah, understood. The proceeds from the asset sales, you also mentioned that you'd made a couple of acquisitions. Can we get some more detail on the scale of You've got $300 million of proceeds. I guess the acquisitions are in CapEx, right? Yeah, the acquisitions are in CapEx. I think all in, less than $100 million. It wasn't significant in the quarter. They were some small bolt-ons. That was the acquisitions. What were the sales? Were the sales upstream? Sorry, I missed that. Excuse me. The sales that we had, we had some minor ones in the upstream, just some minor ones there. I think that was upstream. Yeah, it was just a little bit of stuff there. Again, in that net there wasn't a big deal. I think you'd quite deliberately reiterated your guidance as given at the Analyst Day for, I think it was for full year 2013. Is that what you referred to or was there another term? Yeah. Yeah. No, I just wanted to reinforce two things for you. The volume outlook is unchanged and the CapEx outlook also is unchanged. Okay, great. I've got kind of a detailed one, which is unfortunate. If you could extend it into the overall North America picture, can you update us on the status and future for the Pegasus pipeline? Can you also talk about how you're going to move crude out of Canada down into your major refining center on the Gulf Coast? Thanks. Yeah. Let me hit the second one first. We have the ability, if you're really referring to Kearl, we've got the pipeline capacity in place for the first 110,000 barrels a day to move that either into the U.S., some of that into Joliet or also into our other Canadian refineries. If you're looking in general, Western Canada crudes down into the Gulf Coast, we have made some other arrangements to offset what was coming down Pegasus, and that really hasn't had a big impact on us on a net basis. If you look at the Pegasus pipeline incident broadly, I'll tell you that the cleanup of that is going very well. We've removed all visible freestanding oil from the environment. Many of the folks that were evacuated from their homes have completed the re-entry process, so that's going well. In terms of starting up that pipeline, I really couldn't give you an estimate on that or an outlook. We've still got some more work to do to determine the details of the investigation around that incident and what caused it and that sort of thing. Until we've got that completely nailed down and can think about that over the rest of the line, I couldn't give you any update of when that'll be back in service. Okay. Obviously it's out now. I think the interesting thing, if I could say, is that I believe it was built in 1940, that pipeline, right? It's obviously- Yes. David, I look forward to seeing you in September. Thanks for your help. All right. Thank you. Next is Paul Cheng with Barclays. Hey guys. Good morning. Good morning, Paul. Two questions, Dave. In the second quarter, is there any kind of one-off, somewhat more unusual tax adjustment or inventory gain or loss in any of your divisions that we should be aware? No, Paul, this is actually a pretty clean quarter along those lines. All right. Secondly, Dave, I think you have talked about the success story that you guys have in the Woodford and also in some other unconventional play like Bakken. Can you give us a rough idea how much is the total unconventional liquid production to date that you're running at net to the company, and also that within that, what is the rough percentage between the split of oil, condensate, and NGL? Paul, I don't have the breakdown of unconventional liquids relative to conventional. Certainly what we're seeing, if you look at how we're doing, particularly sequentially in the U.S. where I think our liquids production are basically quarter-over-quarter liquids production flat. What you're seeing is unconventional increase in liquids production is offsetting declines. So you've got your normal decline on the conventional side being offset by the unconventional. But I don't have those two numbers broken down like that. Is that something that you guys may be willing to share? We can take it off now if that is the case, or you could have someone just shoot me an email. Yeah, I think those kind of details will probably hold for a broader update at our Analyst Day in March. I think the important thing for us is this ramp up that we are seeing and the year-over-year increase that I mentioned in my prepared remarks. Again, in particular, the ability to grow these volumes at a lower capital cost as time goes on and a lower OpEx. I do understand your question and we will look for an opportunity down the road to be a little more specific on that. On the unconventional liquid at this point, Dave, are you guys the operating cost per unit or per barrel? Are they higher or about the same or lower than your average portfolio in the U.S.? I do not know that I have that specific number in terms of coming up with a conventional average cost versus an unconventional. Again, Paul, I think the important thing for us is to continue to ramp down those OpEx costs, ramp up the well productivity as we depend on those unconventional liquids to offset the decline in the conventional. I do not have a split out in the cost for you along those lines. Again, as this portfolio goes forward, you will see an increasing amount in the unconventional liquids offsetting and then growing more than the decline on the unconventionals. We will also look for an opportunity at the next Analyst Day to talk about that a little more as these volumes come up. All right. Thank you. We'll now go to Allen Good with Morningstar. Good morning, David. Morning, Allen. Just a follow-up question on your commentary related to the asset sale supporting share repurchases in the past. First of all, is there any current marketing of assets now that would be significant enough to potentially support the repurchases later this year and next? Secondly, on that point, when you evaluate asset sales or the future potential of assets, do you stack up the returns on those assets in the future relative to what you could potentially get on returns of buying your own stock or the valuation of your own stock? So as the repurchase of, are there use of proceeds factors into whether you decide to sell an asset or not? Yeah, let me answer that second one first. Those are two completely separate decisions. The decision to sell assets is sometimes it's strategic, like our decision to get out of owned and operated retail stores in the U.S. which also ties into the other part of asset sales, which is they're worth more to somebody than they are to us. Oftentimes when we look at something that looks like a strategic benefit for us, it turns out that it marries up quite well with an economic advantage for someone else. When you look across our other assets either in upstream, downstream, or chemicals, it's a very simple analysis. What's this thing worth to us? Looking at both upside potential and downside potential, and then how does that compare to the value to a potential purchaser? When the latter's greater than the former, generally speaking we'll conclude an asset sale. A lot of those sales are opportunistic where people approach us asking to buy assets. So we don't have a program. We don't have a target or an objective. Where they come along and they're attractive we go ahead and do it. That kind of leads into I really can't comment on future sales because, as I said, so many of those come about because we get approached by people and don't have any way to look at that. But I will say we did see a very successful program over the last couple of years, and again, as I mentioned earlier, that cash flowed directly to our shareholders. But what we might do next quarter or the next quarter or next year I don't know and couldn't comment on. Okay, thanks. My second question relates to the factors that you outlined as far as evaluation of relative attractiveness of LNG projects with respect to Australia. I understand you're going to pursue FLNG down there in the development of Scarborough. Is there anything else besides that potential with respect to regulatory or capital costs in Australia that have maybe abated in the past, call it 6 months to a year, that make that project a bit more attractive than maybe it was a year or 2 ago relative to the rest of your portfolio? We haven't seen a big change in terms of the cost structure. We are evaluating the potential of FLNG at the Scarborough prospect, and those evaluations continue. But again, I wouldn't want to position that relative to any other project, either already in the portfolio or one that we're looking at. Again, it's nice to have the wide geographic flexibility we have and the opportunity set for LNG. So you got a lot of things at play. I mentioned fiscal terms and stability, capital costs in particular areas, infrastructure and that sort of thing, as well as the markets that those things would serve. So, as we bring along this portfolio and evaluate it, we'll be looking at different technologies. FLNG is an example of that. Also different sizes of facilities and different locations and that sort of thing. So, we'll continue to progress that, but don't have an outlook for FID and costs or on any of those, or certainly not relative competitiveness. Okay, thanks. Just one quick one. I'm sorry if I missed it, but on Asian gas volumes during the quarter, was there a reason, whether it be PSC or turnaround effects, for the decline sequentially there? If you're looking sequentially, we had some downtime, was a big piece of that, and then also some price and spend impacts on entitlements in the gas area there. But nothing outside of that ordinary. Thank you very much. All right. Thank you. We will go to Pavel Molchanov with Raymond James. Thanks for taking my question. First, just a quick one on PNG LNG. Any sense of when you are looking to make a decision, project sanction on train three? No, I really don't have an outlook on that. We're still in commercial discussions on the potential for that expansion. Until those are concluded, it would be difficult to give any forward guidance on timing after that. Other than we're working on it, and if those negotiations are successfully concluded, we'll be in a better position to talk about the going forward time frame. Okay. Second one from me. We've seen a number of large Western players getting into the Vaca Muerta in Argentina in a pretty big way. Can we just get an update on where things stand with your JV down there with, I guess it's Americas Petrogas? Yeah, sure. I think as you're probably aware, we've got a huge position in the Vaca Muerta. We were kind of an early mover into that area. We've got 11 blocks totaling over 800,000 net acres in the Neuquén Basin. Of course, we're targeting the potential of the Vaca Muerta. We did have a number of wells that we drilled last year and into this year. Some of those are on tests, and others are being completed and will be testing going forward. We do have a fairly active operated plan for the balance of this year, and we'll get a few more wells down there over the course of the year. The real key there is to kind of figure out where the windows are for the liquids versus the gas, figure out what you've got, how it looks, and not drill more wells than you need to to define that resource. We're pleased. The early results are encouraging, and we continue to progress, and like I mentioned a minute ago, we're looking forward to drilling our operated wells the rest of this year and give you a little better update as we progress. Great. Appreciate it very much. We'll now go to Iain Reid with Jefferies. Hey, David. How are you? I'm good, Iain. How are you? I am doing very well. I got quite a few things. Firstly, on just coming back to share buyback. I am just wondering, when you look at share buybacks and dividends, do you kind of look at those together? Because you are ramping down the share buyback at the same time you have increased dividend payments fairly significantly. Do you look at that as a kind of total shareholder return number, and are you moving, if you like, more towards dividends rather than share buybacks consciously? Or is it more about this disposal impact you were talking about earlier? Yeah. Let me talk about the dividends first. I think the most important thing to think about the dividends is we have a track record, and have certainly talked about on a go forward basis, the objective of always growing that dividend over time. The rate at which we have grown that dividend over the last several years has varied a little bit, although if you average it out over the last 5 or 10 years, it has been substantial. We did take a 20% hike in the dividend in 2012 and another 10%, almost 11% this year. I think as we talked about at the analyst meeting, that was in response to both desires of our shareholders and also wanting to remain competitive in the marketplace. So if you just hold that aside on the dividend, then you get to the buyback. The buyback is, of course, driven by cash flow that is available to give back to the shareholder. The buybacks give us great flexibility in terms of managing the cash and capital structure. I would not combine that with the dividend. They are separate and managed in that manner. I think as you look back over the last few years at the sheer level of total distributions to the shareholders, they have been quite impressive. Again, we have grown the dividend to meet those needs, and then the rest of the cash has gone back in the form of the buybacks. Okay. Second one is, I was a bit curious about this, what you were talking about in terms of refining capacity being significantly down in the quarter. Because if you look at it on a sequential basis, it is down, but not significantly compared to the first quarter. Is there anything else in these refining numbers which could explain the kind of really weak performance other than just the cost of what you are doing and also the downtime you are talking about? Sure. A big piece of the actual impact on earnings really comes from the fact that a lot of the refineries are down are some of our higher margin refineries. For example, our Joliet refinery in the Midwest was down for 2 full months, and without giving a specific number, I can tell you that's a big chunk of what you're seeing in that earnings number. It's not just the amount of throughput or the amount of volume that was lost, but the mix of those refineries as well. Okay. Yeah, the last one just on tax rates, if you don't mind. Your tax rate ticked up fairly substantially this quarter, certainly compared to the second quarter of last year. Is that a purely mix effect or some of your competitors have been talking about the impact of a stronger dollar on deferred tax balances. Is this something we might see kind of maintained at an elevated rate if the dollar remains strong, or is it something you'd expect to reverse with refining becoming a little more profitable? Yeah, let me hit that. If you're looking, for example, the last year, second quarter and this year, second quarter, the biggest impact there is the difference in the tax rates on earnings and some of the divestments and restructurings that we have. Aside from that, particularly if you're looking sequentially this year, it is purely the mix effect of where we're making our money upstream versus downstream, U.S., non-U.S., so a geography there. You saw the results much different in terms of the downstream quarter-on-quarter. I don't think foreign exchange rates are having an effect on us. Going forward, I don't have a specific number for you, but if you look back over the last several quarters and take out the impact of the big restructuring and divestments, we've been in that mid to upper 40s range. Again, I don't have a specific outlook for you, but if you take away a couple of those anomalies, that's kind of where we've been. All right, David. That's very kind. Thanks very much. Thank you. We'll take our last question today from Faisal Khan with Citi. Please go ahead. Thanks, David. Just have a follow-up. Sure, Faisal. Could you describe how you are dealing with this RIN issue in the U.S. for refining and downstream? Are you guys fairly balanced or do you have more blending capacity than you have gasoline production capacity? How retail and marketing sort of helps mitigate some of that? The answer to that is yes. We are a net purchaser of RINs, but I will tell you, we are pretty well-balanced. We do generate the majority of our credits by blending our biofuels directly. While it is an impact on us, it is not real significant. I think the more broader issue in that arena is really the RFS mandate and approaching hitting the blend wall next year from an industry perspective. It is not going to be a matter of RINs or RIN pricing, but just the fact that the RINs will become insufficient and compliance with the RFS mandate is just going to be infeasible. RINs are an issue. It is a topic. But the more broader issue going forward is going to be the RFS mandate heading into 2014. Okay. Just to confirm, if I am looking at your results for the quarter, I should not see any sort of material impact from RINs in the quarter. Oh, no. Not at all. Okay, great. Thanks. That does conclude our question and answer session for today. I'd like to turn it back to David Rosenthal for any additional or closing remarks. Yes. Thank you. I just want to thank everybody for your time and questions today. We appreciate you being with us on the call, and look forward to visiting with you next quarter. Thank you very much. Thank you very much. That does conclude our conference for today. Thank you for your participation, and you may now disconnect.