Earnings Call: Q2 2014

Jul 31, 2014

Summary

Q2 earnings rose to $8.8B, supported by asset-sale gains and stronger segment results, while H1 free cash flow reached $14.8B. Production remained on plan overall, with project ramp-ups offsetting seasonal demand and maintenance pressures.

Good day, and welcome to the ExxonMobil Corporation second quarter 2014 earnings conference call. Today's conference is being recorded. At this time, for opening remarks, I would 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 second quarter earnings call and webcast. The focus of this call is ExxonMobil's financial and operating results for the second quarter. I will refer to the slides that are available through the investors section of our website. Before we go further, I would like to draw your attention to our cautionary statement shown on slide 2. Moving to slide 3, we provide an overview of some of the external factors impacting our results. Global economic growth improved modestly in the second quarter. U.S. economic activity recovered after contracting in the first quarter. China's growth rate strengthened due to increased exports and government stimulus, while Europe's economic recovery remained moderate. Energy markets delivered mixed results. WTI prices increased by more than $4 a barrel, narrowing the discount to Brent, while Western Canadian Select prices also strengthened. U.S. natural gas prices decreased compared to the first quarter. Global industry refining margins strengthened, while strong chemical commodity margins were offset by weaker specialty margins. Turning now to the financial results as shown on Slide 4. ExxonMobil's second quarter earnings were $8.8 billion, or $2.05 per share. The corporation distributed $6 billion to shareholders in the quarter through dividends and our share repurchase program. Share purchases to reduce shares outstanding were $3 billion. Cap Ex was $9.8 billion in the quarter and $18.2 billion year to date, down 17% from the first half of 2013. Cash flow from operations and asset sales was $12.8 billion, including proceeds associated with asset sales of $2.6 billion. At the end of the quarter, cash totaled $6.3 billion and debt was $21.8 billion. The next slide provides additional detail on second quarter sources and uses of funds. Over the quarter, cash increased by about $500 million, from $5.8 billion to $6.3 billion. Earnings, depreciation expense, changes in working capital and other items, and our ongoing asset management program yielded $12.8 billion of cash flow from operations and asset sales. Uses included net investments in the business of $6.7 billion and shareholder distributions of $6 billion. Other financing activities increased cash by $400 million. Share purchases to reduce shares outstanding are expected to be $3 billion in the third quarter of 2014. Moving on to slide 6 and a review of our segmented results. ExxonMobil's second quarter earnings of $8.8 billion increased by $1.9 billion from the second quarter of 2013, primarily reflecting gains on asset sales and higher earnings across all business segments. In the sequential quarter comparison shown on slide 7, earnings decreased by $320 million, as lower downstream and chemical earnings and higher corporate and financing expenses were partly offset by higher upstream earnings. Guidance for corporate and financing expenses remains at $500 million-$700 million a quarter. Turning now to the upstream financial and operating results and starting on Slide 8. Upstream earnings in the second quarter were $7.9 billion, an increase of $1.6 billion versus the second quarter of 2013. Realizations increased earnings by $580 million, primarily driven by higher liquids realizations. On a worldwide basis, crude oil realizations increased by $4.48 per barrel. Worldwide natural gas realizations decreased $0.39 per thousand cubic feet, as higher U.S. gas prices were offset by lower international realizations. Volume and mix effects decreased earnings by $200 million due to a net underlift, primarily in West Africa, and lower gas volumes. Excluding the underlift impact, volume mix was a positive factor of about $50 million, reflecting higher margin production growth, primarily from North America and PNG. All other items increased earnings by $1.2 billion, mainly due to gains on asset sales in Hong Kong. Moving to slide 9. Excluding the impact of the Abu Dhabi onshore concession expiry, oil equivalent production decreased by 2.3% compared to the second quarter of last year. Liquids production was up 8,000 barrels per day. Increased U.S. liquids production and Kearl volumes were mostly offset by scheduled maintenance in Canada and Kazakhstan, base decline and unfavorable entitlement and divestment impacts. Natural gas production was down 604 million cubic feet per day as lower weather-related demand in Europe and expected field decline were partly offset by new production from PNG LNG. Turning now to the sequential comparison, starting on slide 10. Upstream earnings increased $98 million versus the first quarter. Realizations reduced earnings by $200 million. Volume and mix effects decreased earnings by $620 million, reflecting expected lower seasonal demand in Europe, scheduled maintenance, and underlift impacts primarily in West Africa. All other items had a positive impact of $920 million, primarily driven by net gains on asset sales. Upstream after-tax earnings per barrel were $23.07, excluding the impact of non-controlling interest volumes. Moving to slide 11. Excluding the impact of the Abu Dhabi onshore concession expiry, volumes were down 288,000 oil equivalent barrels per day or about 6.9% sequentially. Liquids production was down 77,000 barrels per day, mainly due to scheduled maintenance in Canada, Kazakhstan, and the North Sea, along with unfavorable entitlement impacts. Increased U.S. liquids production provided a partial offset. Natural gas volumes were down 1.3 billion cubic feet per day, reflecting lower seasonal demand in Europe and cutter downtime, partly offset by the addition of PNG LNG volumes. Moving now to the Downstream financial and operating results, starting on slide 12. Downstream earnings for the first quarter were $711 million, up $315 million from the second quarter of 2013. Margins decreased earnings by $330 million, driven by lower non-U.S. refining margins. Volume and mix effects increased earnings by $280 million, reflecting reduced planned maintenance activities. Other items increased earnings by $370 million, primarily due to the absence of Dartmouth refinery conversion costs and lower maintenance expenses. Turning to slide 13. Sequentially, second quarter downstream earnings decreased by $102 million, primarily due to unfavorable volume mix effects and higher maintenance activities, partially offset by higher margins. Moving now to the Chemical financial and operating results and starting on slide 14. Second quarter chemical earnings were $841 million, up $85 million versus the prior year quarter, mainly due to favorable volume mix and Forex effects. Stronger commodity margins were offset by weaker specialties margins. Moving to slide 15. Sequentially, chemical earnings decreased by $206 million, primarily due to lower specialty margins and higher planned maintenance activities. Moving now to an update on year-to-date cash flow growth, as shown on slide 16. Strong free cash flow of $14.8 billion represented an increase of $12.1 billion compared to the first half of 2013. Cash flow from operations and asset sales of $29 billion more than covered the $14.2 billion invested in the business and $11.7 billion distributed to shareholders, with remaining cash used for other financing activities in addition to our cash balance. This year-to-date free cash flow growth reflects our strong operational performance, ongoing asset management program, and a disciplined capital allocation approach. As highlighted in our March analyst meeting, we are starting up a number of major projects that will add significant profitable volume growth. Our world-class project execution capabilities are enabling us to make significant progress and achieve key milestones. One of these milestones was the PNG LNG project startup in April, which was months ahead of schedule. We have now ramped up to full production through both LNG trains and are currently producing close to 1 billion cubic feet of gas per day. Through July, we have already loaded 15 cargoes for delivery to customers in Asia. The project was completed below the $19 billion budget announced in 2012 and produces LNG at a unit cost that is one of the lowest in the region. This achievement is a good example of how ExxonMobil creates value through technology applications and leading project execution capabilities. Learnings will be applied to other LNG projects that we plan to progress. In Angola, the CLOV project, of which ExxonMobil owns a 20% interest, started operations in June. Production is now ramping up and expected to reach 160,000 barrels per day. Offshore Sakhalin Island, the topside of the Berkut platform has been installed onto the gravity base structure at the Arkutun-Dagi field. The operation set a world record for installation of the heaviest integrated topside structure, weighing over 42,000 tons and using the world's largest ocean-going barge to carry and then set the structure. Berkut is now the largest offshore oil and gas production platform in Russia. The facility will start up later this year and will add up to 90,000 barrels per day to Sakhalin-1 oil production. Let me now provide a quick update on Kashagan. The project partners have agreed to work towards a progressive transition from the current venture model to a consolidated joint venture company operating under a single corporate management system, integrating existing processes and tools from the venture entities. An experienced ExxonMobil executive has been appointed as the managing director of the operating company. Regarding the pipeline issues, the current assessment is that both oil and gas pipelines need to be replaced. The North Caspian Operating Company is now developing a full replacement plan. Turning now to slide 18 for an update on our exploration activities. In Argentina, we drilled and successfully completed two ExxonMobil-operated horizontal wells in the Vaca Muerta formation. The Bajo del Choique-X2 well flowed at an average rate of 770 barrels of oil per day, while the La Invernada-X3 well will be flow tested during the third quarter. Our active program continues with additional wells planned to be drilled in the second half of the year. In Tanzania, Statoil and ExxonMobil made an additional discovery in Block 2. The Piri-1 well discovered gas in a high-quality reservoir, confirming an additional 2 TCF to 3 TCF of gas in place. Six gas discoveries in Block 2 have been made to date, with total resource in place estimated at 20 TCF. ExxonMobil, Statoil, BG, and Ophir completed an evaluation of potential sites for a common onshore LNG plant and made a location recommendation to the government of Tanzania. Drilling operations are also currently underway on two blocks in the Kurdistan region of Iraq. At Pirmam, we have successfully drilled to target depth and are preparing to test the well in the third quarter. At Al Qush, we are drilling ahead and anticipate reaching target depth in the third quarter. In Romania, we have spud the Domino-2 well in the Neptune Block in the Black Sea. Data collected from the well will aid in the development planning for the gas field discovered in 2012 by the Domino-1 well. We will then move on to additional exploration drilling in the block. Turning now to slide 19 and an update on our downstream business. During the quarter, we achieved notable investment milestones to increase high-value product sales. We commissioned the Clean Fuels project at the Saudi Aramco Mobil Refinery in Saudi Arabia. The project reduces sulfur levels in gasoline and diesel by more than 98% to meet more stringent fuel standards in the kingdom. The project included new hydrotreating and sulfur recovery facilities and started up successfully and on budget. In China, we completed the expansion of the Taicang lubricants plant to increase the supply of high-value Mobil-branded lubricants. Work is also underway to significantly increase the blending capacity at the Taicang lubricant plant, with expected completion by the end of 2015. Together, these two projects will increase our local capacity by 75% and help meet the growing demand for high-quality lubricants in China. We also recently approved a project to install a new 50,000 barrels per day delayed coker unit at our Antwerp refinery in Belgium. The unit will convert low-value residual oil from our Northwest Europe refineries into higher-value transportation fuel products, such as diesel. This is another example of selective investments we are making at our competitively advantaged sites, further strengthening our industry-leading portfolio. Startup is planned for 2017. Turning now to slide 20 and an update on our chemical business, where we are also progressing several projects to grow high-value product sales. We received all final regulatory approvals and started construction of a multibillion-dollar ethane cracker at our existing, fully integrated Baytown, Texas complex and associated premium product facilities in nearby Mont Belvieu. The steam cracker will have a capacity of up to 1.5 million tons per year and provide ethylene feedstock for further chemical processing at two new 650,000 tons per year high-performance polyethylene lines. This project is made possible in large part by abundant, affordable supplies of U.S. natural gas for energy and chemical feedstock. The expansion will enable us to economically supply rapidly growing demand for high-value polyethylene products used in a variety of consumer and industrial applications. Startup is planned in 2017. We also recently approved expansions of our specialty hydrocarbon fluid facilities in Antwerp and Singapore. These projects will upgrade refinery streams into higher-value specialty chemical products to serve rapidly growing demand in extended reach drilling, hydraulic fracturing, and other industrial applications. These investments underscore the benefits of our business integration and technology advantage to capture advantaged feedstocks and increase high-value product sales. Startups are planned in 2015 and 2016. I would like to conclude today's presentation with a summary of our year-to-date performance. ExxonMobil's strong financial and operating results reflect our ability to grow cash flow and provide robust shareholder returns, as we presented during the analyst meeting in March. Total earnings year-to-date, $17.9 billion, reflecting solid operating performance across all of our businesses and our ongoing asset management program. In the upstream, production of 4 million oil equivalent barrels per day is right in line with our plans. Actions we took to improve upstream profitability and grow higher margin production increased unit earnings to $22.19 per barrel, up from $18.03 a barrel in 2013. In the downstream and chemical businesses, we progressed attractive investments to strengthen the portfolio and continue to leverage integration benefits. Our strong operating results, combined with our disciplined capital allocation approach, generated robust free cash flow of $14.8 billion, an increase of $12.1 billion compared to the first half of 2013. This strong performance enabled us to maintain industry-leading shareholder distributions. That concludes my prepared remarks, and 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 touch-tone telephone. We request that you limit your number of questions to 2, so that as many may have the opportunity to participate as possible. If you are using a speakerphone, please make sure your mute function is turned off to allow your signal to reach our equipment. We will proceed in the order that you signal us, and we'll take as many questions as time permits. Once again, press star 1 on your touch-tone telephone to ask a question. We'll pause for a moment to assemble the queue. We'll go first to Paul Sankey with Wolfe Research. Hello, David. Can you hear me? Hey, good morning. I hear you fine, Paul. How are you? Very good, David. Thank you. David, what have the impacts of sanctions been on your operations in Russia? Yeah. Look, Paul, I know our activities in Russia are a matter of great interest to you and everybody else on the call, and rightfully so. But what I can tell you as of this morning is that we are waiting for further details on the sanctions in order to better understand how we need to comply. But I have to tell you, given that we simply don't have sufficient information, I'm just not in a position this morning to comment any further on the impact of the sanctions. Okay, the CapEx in Russia, is that financed from within Russia? I was thinking, given the scale of your operations in Sakhalin, maybe it's an internal Russian financing operation. Yeah. I really don't have the details of that. We finance our operations in a number of different ways. I don't really have a specific comment on Sakhalin or the rest of our activities. So essentially the status is that you're waiting for more clarification on any limits that may be placed on, I guess, investment and operations. Yeah. As you know, what's been in the press has been people's thoughts and expectations, but we really just haven't seen the detailed written sanctions. Until we have those and have a chance to assess them and evaluate them, again, it just puts me in a position this morning where I really can't make any specific comments. Understood. My follow-up is totally separate. The construction started at Baytown, you highlighted. That, I think, is advanced against schedule, isn't it? Is that fully permitted and obviously final investment decision and everything else? What is the expected completion date? Thank you. Yeah, that project is right on our plan. We do have all of our permits in place. Construction has started. We put that picture in the slides this morning to show we're digging dirt. The project's underway. Even throughout the permitting process, we were well underway getting all the engineering lined up, all the contractors, all the supply chain, so that once we had the permits, we were ready to go. So no change to what we told you at the analyst meeting. We're on schedule so far, and we do expect to have that project up and running sometime in 2017. Thank you, David. All right. Thanks, Paul. We'll go next to Doug Leggate with Bank of America Merrill Lynch. Hi, David. Good morning. How are you? Hi, Doug. A couple of questions, please. The promise of improving operating cash flow is obviously a big theme from your Analyst Day. We do not really see any substantial margin change this quarter with the start off of PNG LNG and I guess Kearl ramping up. I am just wondering if you can frame for us what the drivers of that change in cash flow are in terms perhaps of how the margin could change for your new portfolio of assets, which I guess will be about a quarter of the company in 2017. Any color you can give qualitatively if necessary, but just to give some comfort that turn is coming, and I have got a follow-up, please. Yeah, sure, Doug. Let us talk about that a little bit as we look at how things have really evolved over the last say 12 months. We have seen some pretty significant increase in our unit profitability and our ability to capture changes in the realizations as they come along. If I look at where we are so far in the first half of 2014 on upstream profitability relative to 2013, we are up over $4 a barrel on unit profitability. If I go back and I take out all of the asset management, asset sales, related gains in all the periods, unit profitability is up right at $2. I think you are starting to see the impact of the trend that we talked about in the analyst meeting of reducing our exposure to lower margin barrels and barrels where we do not have quite the upside potential. You are just now starting to see some of the projects that we have talked extensively about coming online. PNG LNG is an example. It has just started up, but it is one of several projects to come on in the next couple of years. As we talked about at the analyst meeting, all of which are accretive to average unit profitability and average unit cash flow. I think in our production volumes, we are starting to see the benefit of that. Again, it is early. We have just started up the project. We have a number of projects yet to come over the course of the year. Of course, PNG will be ramping up. We will have the Lucius project coming up later in the year. I might give you an update on that. As you know, at the time of the analyst meeting and when we put out our F&O review, we had a 15% interest in the Lucius project. That interest is now up to a little over 23% through a normal redetermination exercise as well as our exercising our preemptive rights on the Apache sales. That project will be starting up later this year. Again, we will have about 23% of those barrels. Hadrian South will also start up at the same time. Again, the projects we talked about are on schedule, and they are coming online, and they will be accretive to the unit profitability we talked about. There are a number of other things that you see as we progress through in looking at the year-to-date cash flow, including an active asset management program, and you saw the impact of that. As I look back really at the first half and staying away from the first quarter versus the second quarter and looking at the six months, we are spud on. The outlook we gave you on production in the analyst meeting. As you have seen in our supplement, U.S. liquids production is up fairly significantly, and we continue to grow that production as we said we would. That will also add to the improving margins. Cash flow is good. Free cash flow is dramatically better than last year. We are continuing to provide the shareholder with strong returns. We raised the dividend again, as you know, almost 10% in the second quarter. As we sit back and we look at the first half results and compare to what our plans were and compare to last year, we are very encouraged and very confident that we will continue to deliver the growth that we had talked about and continue to trend up on unit profitability and the cash flow. From our perspective, everything is right on track, and we look forward to continuing to deliver the commitments we have made to the shareholder. Thanks for the full answer, David. I'll make my follow-up a very quick one, hopefully. Assuming the spending level does hold around the $37 billion number, all things equal, the age-old question for you guys, you're going to have a lot of free cash flow. How are you thinking about the dividend nowadays as opposed to stepping up the buyback? When we traveled recently, I think your message was, well, that cash will go back to shareholders. If you could help frame the importance of one over the other as you stabilize the underlying production base, that would be helpful, and I'll leave it there. Thanks. Sure. Thanks, Doug. As you mentioned, at constant prices, yes, as we deliver the plan that we outlined at the analyst meeting, we do expect to see a continued increase in our cash flow generation. Keeping the CapEx at the levels we discussed would, by definition, improve free cash flow again, just as we've seen dramatically here in the first half. In terms of the capital allocation, no change to our prior approach. We're going to stay disciplined on the capital. We're going to fund our best projects. I think as we've talked about in the analyst meeting and folks are beginning to recognize, our opportunity portfolio is quite extensive at this point, and that's going to allow us to be selective. So we'll continue to be disciplined on the capital side. We will continue to pay a very consistent and increasing dividend over time, and I think you've certainly seen evidence of that over the last few years. After you accomplish those two things, the rest of the cash will flow back to the shareholder through the share buyback program. So no change in approach, no change in how we're doing our capital allocation. But again, we are certainly looking forward to continued success in our project ramp-up, continued success in upgrading the value of our molecules in the downstream and chemicals, and delivering that profitable growth that we talked about a lot in the analyst meeting. So thank you. Thanks, David. We will go next to Ed Westlake with Credit Suisse. Good morning, David. Very small question first, just asset sale gains in the quarter, if you shout out the actual number in this quarter, if you have that. Sure. In total, the gains from asset sales on an absolute basis were about $1.7 billion, 1.6 of that in the upstream and the other $100 million in the downstream and chemical. Okay, thanks. That's helpful always. Let's talk a bigger picture about the Permian. Obviously, at the Analyst Day, you spoke about 1.5 million acres. Do you have a breakdown of how much of that is CBP, how much is Midland, and how much might be in the Delaware Basin for more the application of horizontal drilling? Sure. I'll start out by saying, if you look at that whole 1.5 million acres, it is spread throughout the Midland Basin and the Delaware Basin. We are in a number of different areas, and that really gives us the opportunity to do a number of things to grow our production there, including a lot of things in the conventional fields, water floods, CO2 floods. We have 65 workover rigs still running in the Permian, in addition to the other rigs that we have drilling exploration wells. We have a lot of exposure to both conventional and unconventional, again, broadly across the basin, in Texas and in New Mexico. As we look at the various areas that I know people are interested in, we certainly have some very good acreage in the prime areas for the Wolfcamp, and we are just getting started in there. Bone Springs is another one that we are working on. When you look at this ramp-up in growth that we have seen to date, and you have seen the numbers of the significant growth in liquids in the U.S. year-over-year, we are just now beginning to scratch the unconventional plays and getting some of those wells down and see what we have going on. We have about five rigs drilling horizontal wells today. Again, the Wolfcamp, the Bone Springs, and a number of areas. We have brought 93 wells online this year. That is up almost 70% from last year about this time. A lot of activity, a lot of growth, but just scratching the surface of the potential in that area. We are excited to have the opportunities that we have across the basin, across the platform, and in particular, the wide variety of things we have to work on in that place. It is not just unconventional, it is a number of resource opportunities. You will continue to see us ramp up activity there and see that production. Again, as we talked about at the analyst meeting, that is a big time focus area for us, as is the Bakken, where we are having tremendous success as well, and the Woodford Ardmore area. I can tell you, sitting here mid-year, the opportunity is there. We are developing it, and we are seeing that production increase right in line with our expectations. If I can be very sneaky, is it fee acreage, or is it more recently sold in the Permian? I am thinking about the royalty position. Some are starting to disclose where they are on that. No, we've got most of our acreage is fee acreage. As you know, that's a big help on the royalties. Thank you. We'll go next to Blake Fernandez with Howard Weil. Good morning, David. Thanks for taking the question. Morning, Blake. I had a question for you on the production profile. I know you kind of confirmed that you're on track to meet your full-year target. 2Q came in a bit light compared to what we were looking for. I know you referenced some maintenance and European nominations were weak. Is it fair as we move into second half to think that 2Q is a low point? I know you have CLOV ramping up and maybe some of that maintenance coming back online, or any color you can give us on how to think about the second half of the year? Yeah, sure. If we look at the first half in particular, if we look sequentially where the volumes came down quite a bit. Just on the liquid side, downtime was worth 66,000 barrels a day for us from first quarter to second quarter, so we had a very heavy maintenance load up in Canada, in Kazakhstan at Tengiz, and a number of other places in North Sea, for example. While we did see the benefit from projects at PNG and Kearl, they were masked by, again, this planned maintenance, seasonal maintenance, but it did have quite an impact on us. As we typically do going forward into the second half, that maintenance gets done and those things come back. The other impact we had sequentially, again, was a sharp reduction in gas sales. I think our demand in Europe was probably worth over 150,000 oil equivalent barrels a day on the gas side. Then we also had some downtime. So I'd characterize, if you're looking at the second quarter, characterized by an extremely heavy maintenance load, and your typical seasonal decline in Europe volume coming off a low base because of the low winter. The offset of that, of course, is PNG LNG starting up. The increase you've seen in the higher margin U.S. liquids volumes, they just weren't enough to offset these other factors. As we head into the second half of the year, you will see these maintenance items come back up as they typically do, and then the project startups that I talked about, full ramp-up of PNG LNG, and then the other projects that I mentioned, Buzios and some of the other ones. We would certainly expect to see the benefit of both of those factors coming out of the second quarter. That is why I really wanted to focus a little bit of time this morning on how we are doing year to date, because I think the real key measure of our performance and whether or not we are delivering on the targets that we established at the March analyst meeting is we are right on plan. In fact, we are a little ahead in some areas like U.S. liquids production, for example, PNG LNG, a little ahead. Some other things are a little behind European demand, for example, on the gas side. We continue to ramp up Kearl, and that progress is also looking good as we head into the second half of the year. Again, if we look past the quarter-to-quarter fluctuations and focus on where we are at year to date and what we are expecting in the second half, I can assure you that we are spud on to deliver the outlook that we gave you. That is great. That is helpful. Thank you. The second question. One of your European counterparts has just announced the initial steps to form an MLP, and it seems like ExxonMobil is flush with assets that would probably fit very nicely into one and really highlight the underlying value that is probably not reflected in the stock. I am just curious if that is even on the radar screen. Well, I would say kind of generically, everything is on the radar screen. We are just constantly looking at all of the things that are out there, all the options we have to realize full value from all of our assets, including our midstream assets. The one thing I would remind you, if you recall back in the 2011 and 2012 timeframe, we actually sold a number of our midstream assets and realized extensive value for those, and those were reflected in the very strong gains on asset sales and cash flow we generated. Now, if you step back and look at MLPs, most companies are using those as a means to raise cash and finance growth or reduce their ownership costs or exposure. Those aren't strategic drivers for us. In our case, when we look at our midstream portfolio, these are strategic assets to us. We think we are monetizing the value of those, whether or not you would assert that they are adequately reflected in our share price yet. We are certainly monetizing those and maximizing the value in the integration of our full value chain, and also as part of our logistics and integration between the upstream, downstream, and chemicals. You probably won't be surprised to know that we've taken a hard look at this and look at the assets and the opportunities. But we like what we have. We like the integration benefit. In fact, if you've seen some of our recent announcements, we're actually investing more dollars in that part of the business. We mentioned the Edmonton rail project and a few other ones. Midstream assets are strategic to us. We think we're getting full value for them as part of the integrated business model that we have. But I wouldn't want you to ever think that we're not aware of and looking at everything that's out there that others are doing and some things others may not have thought about yet. Great. Thank you, David. Our next question comes from Roger Read with Wells Fargo. Hi, good morning. Morning, Roger. Just maybe come back a little bit on the Permian question, just because we did see, I believe it was an asset swap that you did during the quarter. Since in general, we're seeing a lot more activity heading that direction, maybe could you give us an idea, a little bit of sort of relative size? I know you don't like to get into a lot of details, but kind of relative size, and if we think about growth opportunities, maybe of the Permian relative to the identified projects in the Gulf of Mexico, if there's any sort of additional detail, clarity, something there you could offer us. Yeah. We did sign an agreement in the second quarter to do a swap that basically added about additional 26,000 net acres in the Permian. Virtually all of it was in the Midland Basin, which of course, as you know, is prospective for the horizontal drilling that we've talked about. If you add that to the acreage we talked about that we picked up earlier this year, we've now added 50,000, 60,000 prime acres right in the sweet spot of where we want to be. So that's good. That's one of the reasons why we've increased rigs in that area. I mentioned the 65 work over rigs that we're running. I think we've got 11 rigs running on the exploration and delineation evaluation side. So certainly ramping up activity there and very encouraged by the results we're seeing. It's a very active area for us. Now, in terms of activity relative to other areas, I have to also say the Bakken is an area where we're also ramping up production quite significantly, and you see that in our results. We've got a lot of activity there. We've got 12 rigs running. That's up from where we've been in the past. Operated production was up 26% in the second quarter. Again, we're continuing to ramp up. The other play we've talked about is the Ardmore, and we've got higher rigs running there as well. One of the things, if I just think about adding all that up and looking at our liquids plays, production across the Permian, Bakken, and Woodford Ardmore in the second quarter was over 200,000 barrels a day. That was up about over 25% from a year ago and up quarter-to-quarter. We're continuing to work that. Comparing those opportunities to the Gulf of Mexico, we're fortunate that we've got opportunities in both of those areas. We do have major projects coming on and starting up. I mentioned Lucius, which is the oil development there starting up before the end of the year. The gas piece of that project for us, Hadrian South, will also start up and bring on additional volumes. We continue to work on Julia, and that's progressing well. Then there are a couple other projects that we also have an interest in. That's coming through. We've also picked up some additional very attractive exploration acreage. Recently, we were awarded the three blocks that we were the high bidder on right over there on the trans-boundary area bordering up against Mexico. We've got those three blocks awarded to us there in the Gulf, and we're hoping that'll lead to some opportunities down the road beyond that. Both of those areas are looking good. The Gulf of Mexico never delivers 100% success rate to anybody, and we've drilled a couple of dry holes ourself. But if we step back and look across the last several years and what we got on the plate going forward, we like what we have, and we're looking forward to getting these high-margin volumes up and running here later in the year. Okay. That's great. Thanks. That segues into what my other question was going to be. Mexico, clearly they've made progress on the legislative side. We still need to see what the actual rules are going to be and get a good feel for timing. Can you talk a little bit about what Exxon sees as the possibilities in Mexico over the next, I don't know, 3-5 years as this develops? Well, we're certainly encouraged by what we've seen to date, and we're certainly respectful of the process of deliberation that's going on, as they work through their legislative process. We're monitoring that closely. We have a long history in Mexico. We are certainly anxious to see how all this comes out and what opportunities might be available for us along those lines. Again, as I mentioned a minute ago, we do have those three blocks awarded to us right there on the boundary of the Mexican blocks in the deepwater Gulf. We'll see if that can help generate opportunities. But we're encouraged to date, anxiously awaiting how all of that finalizes and all the details come out over time. Then we'll pursue any opportunities that are attractive to us. But we certainly like our position. Okay. Thank you. Our next question comes from Doug Terreson with ISI. Good morning, David. Morning, Doug. So for clarification, how does the $1.6 billion of upstream asset sales that you mentioned a minute ago reconcile with the $1.2 billion other figure that you highlighted on slide 8? Do you have any geographical segmentation for either of those results? Sure. If you are looking at the 1.2 that we mentioned, that was the delta quarter-on-quarter. Sure. Okay? Because we had a number of asset gains last quarter and then last year. If you are looking at the total picture there, and again, there are other items in the earnings rec, but just to be clear, in the upstream, the total value of the asset sales in earnings was $1.6 billion in the quarter. Right. And then if you look quarter-over-quarter, that is about 1.5 with an offset of a couple of hundred million dollars and some other things like startup expenses and that sort of thing. If you are looking at the sequential comparison, we had about $400 million of gains on asset sales in the first quarter of this year. So the delta there is about $1.2 billion Okay in earnings. So I hope that sorts it out for you. Sure. Then we talked separately in the call about the impact on the cash flows. Okay. Then secondly, over the years, ExxonMobil and its peers have employed fairly substantial portfolio management programs to support returns on capital. With the decline in returns across the sector over the past four or five years, the pace has accelerated for some companies, and with positive effect on returns and their values in the market. So my question is, with ExxonMobil's returns falling with the industry's over the last several years, why would not the company be using portfolio management more rather than the same or less to enhance its returns profile? That is, if you think that it is not. So really any updated thinking on portfolio management strategy in light of the industry context is appreciated, David. Yeah. Thanks, Doug. I would say there's really two items to talk about in regard to the return performance here over the last couple of years. First, with regard to asset sales, they're not linear. We had a number of asset sales in 2011 and 2012, and I think the combination of those two years yielded about $20 billion in cash flow. Very strong. Last year was less of a year. This year, we're off to a pretty solid start between the first quarter and the second quarter, and in particular, what we generated here with our asset sales. The program is ongoing. We don't make an announcement in advance of what we're going to do. We find that gives us a little better negotiating strategy when we do actually sit down and talk about selling assets. We don't have any stated objective. We don't have any target that we feel we must make. But we're certainly able to take advantage of anything in the market that gives us a chance to realize value for our shareholders. Fortunately for us, we don't have to sell assets in order to make a dividend payment or another distribution because of the cash flow we generate. Again, reference back to that chart I showed you. I think one of the other things to keep in mind when you look at upstream ROCE over the last few years, particularly in our case, and I can't speak for others, but one of the aspects of these very large legacy plateau volume, non-declining volume projects, however you want to call them, is all the CapEx is up front. Sure. As you're building these projects, and particularly in our case, we talk about bringing on 1 million barrels oil equivalent a day of production between 2013 and 2017. By definition, you got a lot of steel in the ground to produce 1 million barrel oil equivalent a day. Until that capital starts up, that's non-productive capital. Okay. So that, I think, at least for us, has been a big driver in terms of ROCE. As you know, as those projects crank up, PNG LNG being a perfect example, you go from non-productive capital in the ground to productive capital, and in this case, highly productive capital. Again, part of bringing all these projects online, part of ramping up the production is the earnings, the cash flow, and the ROCE that comes along with that. Then on the downstream side, of course, we continue to have industry-leading returns and continue to make incremental investments there to at least maintain, if not increase that advantage. Okay. Thanks a lot, David. Thank you. Our next question comes from Paul Cheng with Barclays. Hey, good morning, guys. Morning, Paul. Dave, on Kearl phase one, the ramp up has been, I think, probably slower than what the investor has been expecting. From you guys' standpoint internally, when you think all the startup issue will be fixed and then you will be running at a sustainable rate towards the full capacity, is it going to take another year, six months, any kind of rough timeline internally that you guys are forecasting? Paul, let me give you a quick update on Kearl because we have seen a continued ramp up in the production. I mentioned that in the second quarter, although on the surface it looks like production was flat at about 66,000 barrels a day first quarter and second quarter. But recall, we did have some planned maintenance there in April that took us way below that number. I can tell you as we came out of that April downtime for maintenance, production picked up quite well. In fact, we achieved record production in the month of June of almost 80,000 barrels a day. We've not quite reached the lined out production and our expectations, but we are making progress. A number of the issues that you are aware of are being resolved, and we're working on that. Again, I have to stress that although we're certainly a little disappointed in the ramp up over the last year from what our original expectation was, the technology is working fine. We've actually been able to run each of the three froth treatment trains above their design capacity. That's very encouraging. The objective for us now is to get all three of them running simultaneously on a consistent basis at or above their design capacity. When we achieve that's when you'll really see that volume change. We're encouraged at the capability of the assets that we've put in place. We're encouraged with how the technology's working. We are working on the ramp up and look to improve that. I can't give you a specific date on which we'll achieve 110,000 barrels a day or some number greater than that. But we are making progress, and we are looking forward to continue that progress. I can also say on the other side of the Kearl initial development, the expansion project is going very well. I am pleased to say for another quarter that the project is on schedule and on budget, which on the backs of the PNG LNG project, very unusual in our industry for somebody in my position to sit here on an earnings call and tell you the projects are on budget and on schedule. So acknowledge that the ramp up in Kearl first phase has not been quite what we were expecting. But again, want to confirm that we are making progress and we are encouraged with the results we have seen so far this year. Dave, you guys have some very decent success on the shale oil. Do you have a number you can share what is your total shale oil production in the second quarter average and comparing to the full year 2013 and whether you can break it down between the black oil condensate, NGL, and gas? I cannot break down the split between oil, NGL and gas. But the numbers I gave just a minute ago on the call across the Permian, the Bakken, and the Ardmore are pretty indicative of what we are doing. Although, not all of it in the Permian, as I mentioned, is unconventional oil. But I think without a specific number, again, when you look at the numbers that we had in the supplement to the press release, you see the 38,000 barrels a day increase in U.S. liquids year over year. And we look at how things are going again in the big three, the Bakken, the Woodford Ardmore, and the Permian. We are ramping up to that level that we talked about in the analyst meeting, and we continue to move forward, and I will continue to give you an update on a quarterly basis. Can I just make a quick question, my final one? Sure. There's an article, I think out there talking about Exxon is evaluating to have a major expansion in one of your Texas refineries. That seems to be very uncharacteristic or quite different than what Exxon historically has been viewing or the refining strategy in the U.S. I want to see whether you can comment on that. Paul, the first thing I'd say is I'm not going to make a specific comment on any rumors or speculation that are out there in the press. We are regularly looking at our portfolio around the world. I mentioned the investment we're putting into the Antwerp plant, which you might say, why would you be putting money into Europe given its current weak spud on the margin side? But again, that's consistent with our strategy of upgrading molecules. Very nice project to take what is currently a low value resid stream and upgrade it into very high value diesel and other products. When we look at the U.S., when we look at Europe, when we look at Asia Pacific, we're always looking at opportunities and what we can do to either upgrade any molecule that's flowing through our system, how we can take advantage of already advantaged assets like our refining circuit, and improve that. For us to be looking at many different things should not come as a surprise. But rather than mention anything specifically and coming back to the strategy that we've articulated, I think I can really go back to what we said at the analyst meeting. When you look at our downstream strategy, it's all about expanding feedstock flexibility, increasing high value product yields, reducing operating costs, taking advantage of logistics like we're doing in Europe that I mentioned in my prepared remarks or pressing even more the value we get from integration. I would say there's no change in that strategy per se, but wouldn't comment on any specific item that you might have read in the press somewhere. Thank you. Our next question comes from Pavel Molchanov with Raymond James. Thanks for taking the question, guys. On Russia, I appreciate the point that the sanctions have not yet been fully clarified, but can you confirm whether the Arctic exploration prospect with Rosneft is still set to spud in August? Yeah, Pavel, again, I can understand the interest in the question, but I really have to come back to what I said at the opening. Until we have a chance to look at the sanctions, read them, assess them, evaluate them, it just wouldn't be appropriate for me at this point this morning really to make any comments specifically on any of our activities. Okay. Understood. Then you guys recently applied for approval for the Gulf Coast LNG export terminal with cutter. Any sense of when you are expecting that approval to be given? I do not have a specific expectation. I think one of the things that is helpful for us is we have been in a pre-FERC filing process for a while. We have been working on this. So this is not brand new for us. I do not know exactly what the expectation is in terms of approvals or a number you have to get from the FERC, of course, from the DOE, et cetera. But I think if we look across how this thing might progress through the approval process and if we can get to a position where we can FID this, you might be looking at some timeframe for production around 2019. Again, without breaking it into its components, but nice opportunity for us, and we are certainly looking forward to an efficient process in terms of getting everything approved and getting our DOE approval for export to non-FTA countries, and moving on with that project. But it is just one of many LNG opportunities we have in the portfolio. We are fortunate to have a number of things we can be working on around the world in various points of development. This one is certainly one that we are working on real closely. All right. Appreciate it, Dave. Thank you. Our next question comes from John Herrlin with Société Générale. Yeah. Hi, thank you. Sure. Just a couple quick ones, Dave. Sure. With the PNG LNG, is that all contracted sales at this stage? Uh- Because you had some spot cargoes initially. Yeah, because the project has started up months early, the current cargoes that I talked about, they are basically, by definition, going in on a spot basis. We are pleased with our ability to place those cargoes at attractive prices. As we get down to later on and the contracts all kick in, about 95% of the production is contracted on long-term contracts tied to the price of oil. That is certainly part of, if you will recall back at the analyst meeting when we said we would take the percentage of our total upstream portfolio production from about 63 or 64% liquids or liquids linked up to about 69%. This is just an example of that. But yeah, the cargoes that we are placing now are basically spot, but into the market, but again, we have been able to place them and pleased with how that went, and then really looking forward to getting this project continuing on. Again, just very pleased with the startup, and very pleased that we were able to bring that project in under a budget that was two years old. The industry has gotten used to those annual updates of budgets on LNG projects and costs going up annually. Again, we are very pleased to bring this thing in early and under our budget. Thanks. Last one for me is on your tax rate. Your effective tax rate was low. Sure. Maybe you said something, but I missed it. Yeah, let me give you a little more color on that. You did see an effective tax rate around 41% or 42% or so. That is down from last year and also a little bit down from what we saw in the first quarter. The real impact you're seeing there is just a combination of the mix of our businesses: upstream, downstream, chemical, geographic, some of our portfolio management activities. The expiry of the Abu Dhabi onshore concession, of course, as is typical, asset sales tend to have a lower tax rate than earnings from your operations. All of that drove us a little low here in the second quarter. I can tell you without giving a specific guidance and a specific number, but a normalized tax rate going forward ought to be somewhere in the mid-40s, compared to upper 40s of prior history, somewhere in that order of magnitude, just to give you a feel for how that impact might roll through going forward. Great. Thanks very much, Dave. Thank you. Our next question comes from Guy Baber with Simmons Investment Bank. Thank you guys for squeezing me in. Just one quick one from me. Oh, sure. More of a point of clarification. I wanted to ask about the U.S. liquids performance relative to your internal expectations. That is an area that has outperformed our model. You have given us some great detail on the call, so thanks for that. I was not sure if you had said that the U.S. liquids production was tracking in line with the internal plan or it was outperforming. I just wanted to clarify there, as we try to think through the ultimate potential of your LRS portfolio in light of some of the longer term guidance you gave at the Analyst Day previously. Yeah, Guy, thanks for the opportunity to clarify that a little bit. We are slightly ahead of our internal expectations for the year in the U.S. on liquids. I mentioned in total, relative to what we talked about at the analyst meeting, we are kind of spud on. With the puts and takes, think about it as still maybe a little bit behind on the Kearl ramp-up, but I addressed that earlier. But slightly ahead, in the lower 48. We are very encouraged with the results we are seeing. We are very pleased with the additional opportunities. We are adding rigs. We are putting some additional resources into those areas. Bottom line, to answer your question, yeah, we are a little bit ahead of where we even thought we would be internally so far this year. Okay, great. I just wanted to confirm that. Thanks. Thank you. Our last question comes from Allen Good with Morningstar. Morning, Allen. Good morning, Dave. Thanks for getting me in here. No problem. Just a quick one, and I'm sorry if I missed it, but on the U.S. natural gas production, it looks like declines have been slowing over the past few quarters. This quarter, we actually saw sequential growth. Can you talk a little bit behind the moves there and what we may expect for the rest of the year and maybe into next year as well? Yeah. If we look at the gas business, yeah, we're sequentially up just a hair, but really about flat down year-on-year, which is also consistent with what we talked about at the analyst meeting. So you are seeing that kind of year-on-year decline as we move those resources more into the liquid side. If we're looking sequentially, I wouldn't read too much into that. We are about flat. It's probably just timing of fracking and completions and bringing wells on to sale. I would say as a follow-up to the prior question, everything we're doing on the gas side is per the plan. That's a broad statement as well as in the U.S. So yeah, the second quarter, we had some good performance. But again, I wouldn't want to give an indication that our full-year outlook on the gas side is any different than what we might have said at the analyst meeting. We are seeing the bump up, of course, from the early start-up of PNG LNG. Then on the other hand, we came out of a very warm winter in Europe and those volumes were down fairly significantly. I think what I would just say to wrap up your question, and the call, think about all the things we laid out for you at the analyst meeting, both strategically and the strategic choices we're making and upgrading our portfolio, high value, higher margin, higher unit profit products into the market, and that's across all of our businesses. Selective investments to continue to press those strategic advantages. And then zeroing in on upstream production volumes, right on what we had expected and maybe a little better in a couple areas. Again, if you look at that year-to-date free cash flow chart and you look at the progress we've made in a number of areas, again, we're very pleased with how our first half is turning out so far this year. Okay, great. Thanks. All right. Thank you. And that does conclude our question and answer session. Mr. Rosenthal, I'll turn the conference back to you for closing remarks. I would just like to thank everybody for participating on the call today and your questions, and look forward to talking with you all again in about 3 months. Thank you very much. This does conclude today's conference. Thank you for your participation.