Earnings Call: Q3 2014

Oct 31, 2014

Summary

Q3 earnings rose YoY to $8.1 billion as stronger downstream and chemical results partly offset upstream price pressure. YTD free cash flow reached $19.4 billion, while production growth, project startups, and disciplined investment remained central to the outlook.

Good day, everyone, and welcome to this Exxon Mobil Corporation third quarter 2014 earnings conference call. Today's call is being recorded. At this time, I would like to turn the call over to Vice President of Investor Relations and Secretary, Mr. Jeff Woodbury. Please go ahead, sir. Thank you. Ladies and gentlemen, good morning, and welcome to Exxon Mobil's third quarter earnings call. The focus of this call is Exxon Mobil's financial and operating results for the quarter, and I'll refer to the slides that are available through the investors section of our website. Before we go further, I'd like to draw your attention to our cautionary statement shown on slide 2. Turning now to slide 3, let me begin by summarizing the key headlines from our third quarter and year-to-date performance. First, Exxon Mobil's financial results reflect the strength of the integrated business model, which creates unique competitive advantages and allows us to generate long-term shareholder value regardless of market fluctuations over the business cycle. Second, year-to-date cash flow from operations and asset sales fully covered our net investments in the business and robust shareholder distributions. Third, we continue to meet our operational and project development objectives. Upstream production volumes for 2014 remain on track to average 4 million oil equivalent barrels per day by year-end as the company delivers new production for project startups and work programs, all of which are enhancing our financial performance. Now moving to slide 4, we provide an overview of some of the external factors impacting our results. Global economy showed mixed results in the third quarter. In the U.S., the economy continued to expand at a moderate pace. However, China's economic growth tapered slightly, while the European economy showed further signs of weakness. As you know, crude oil prices decreased sharply and Henry Hub gas prices also weakened. The WTI spread to Brent narrowed, whereas global industry refining margins were essentially flat as stronger European margins were offset by weaker margins in the U.S. Finally, chemical commodity and specialty margins strengthened during the quarter. Turning now to the financial results shown on slide 5, Exxon Mobil's third-quarter earnings were $8.1 billion, or $1.89 per share. Corporation distributed $5.9 billion to shareholders in the quarter through dividends and our share repurchase program. Share purchases to reduce shares outstanding were $3 billion. CapEx was $9.8 billion in the quarter and just over $28 billion year to date, down 14% when compared to the first 9 months of 2013. Cash flow from operations and asset sales were $12.5 billion, and at the end of the quarter, cash totaled $5 billion and debt was just shy of $22 billion. The next slide provides additional detail on third-quarter sources and uses of funds. Over the quarter, cash decreased by $1.3 billion from $6.3 billion to $5 billion. Earnings, depreciation expense, changes in working capital and other items, and our ongoing asset management program yielded $12.5 billion of cash flow from operations and asset sales. Uses included net investments in the business of $7.9 billion and our shareholder distributions of $5.9 billion. Share purchases to reduce shares outstandings are expected to continue at $3 billion in the fourth quarter of 2014. Moving to slide seven and a review of our segmented results. Exxon Mobil's third-quarter earnings of $8.1 billion increased by $200 million from the third quarter of 2013. As you can see, higher downstream and chemical margins were partly offset by lower upstream liquids realizations and higher corporate and financing expenses. In the sequential quarter comparison shown on slide eight, earnings decreased by $710 million. Lower gains on upstream asset sales were partially offset by higher downstream and chemical earnings. Our guidance for corporate and financing expenses remains at $500 million-$700 million per quarter. Turning now to the upstream financial and operating results starting on slide nine. Upstream earnings in the third quarter were $6.4 billion, a decrease of $297 million versus the third quarter of 2013. Realizations decreased earnings by $670 million, driven by lower liquid prices. In this regard, on a worldwide basis, crude oil realizations decreased by $10.48 per barrel, and worldwide natural gas realizations decreased by $0.42 per thousand cubic feet, as lower European realizations were partly offset by higher U.S. gas prices. Notably, favorable sales mix effects increased earnings by $340 million. Higher margin production growth in Papua New Guinea, Angola, and North America, as well as a net overlift, were partly offset by higher planned maintenance activities, lower entitlements, and field decline. Moving to slide 10. Excluding the impact of the Abu Dhabi onshore concession expiry, our oil equivalent production decreased by 1% compared to the third quarter of last year. Importantly, liquids production was up 14,000 barrels per day. Increased production from onshore U.S. work programs, Canada, and Angola were partly offset by divestment impacts in Iraq and Canada, as well as scheduled maintenance in the U.S., Nigeria, and Russia. Natural gas production was down 319 million cubic feet per day as expected field decline in the U.S., and unfavorable entitlement impacts from pipeline gas in Qatar were partly offset by new high-margin production from Papua New Guinea LNG. In short, our volumes performance demonstrates the progress being made to high-grade our portfolio mix with higher margin liquids and liquids link gas production. As previously indicated, we remain on track to produce 4 million oil equivalent barrels per day in 2014. Turning now to the sequential comparison, starting on slide 11. Our upstream earnings decreased $1.5 billion versus the second quarter. Realizations reduced earnings by $850 million, with worldwide crude realizations down $7.29 per barrel and natural gas realizations down $0.56 per thousand cubic feet. Again, favorable sales mix effects increased earnings by $460 million, reflecting profitable growth in Papua New Guinea, Angola, and Canada, and a net overlift partly offset by lower seasonal demand in Europe. All other items reduced earnings by $1.1 billion, primarily driven by the absence of the prior quarter Hong Kong power divestment gain. Upstream after-tax earnings per barrel were $18.65, excluding the impact of non-controlling interest volumes. Moving on to slide 12. Volumes were essentially flat versus the second quarter. However, liquids production was up 17,000 barrels per day due to growth in Angola and the U.S., partly offset by higher planned maintenance in the U.S., Nigeria, and Russia. Natural gas volumes were down 155 million cubic feet per day, reflecting lower seasonal demand in Europe, partly offset by a full quarter of Papua New Guinea LNG volumes. Moving now to the downstream financial and operating results, starting on slide 13. Downstream earnings for the quarter were $1 billion, up $432 million from the third quarter of 2013. Higher refining margins increased earnings by $820 million, whereas volume and mix effects added another $100 million. All other items decreased earnings by $490 million, which mainly was due to unfavorable foreign exchange impacts. Turning to slide 14. Sequentially, third quarter downstream earnings increased by $313 million. Higher non-U.S. refining margins increased earnings by $310 million. Positive volume and mix effects due to lower maintenance were offset by unfavorable foreign exchange and other effects. Moving now to chemical financial and operating results shown on slide 15. Third quarter chemical earnings were $1.2 billion, up $175 million versus the prior year quarter, mainly due to higher commodity product margins. Positive volume and mix effects were more than offset by increased planned maintenance activities. Moving to slide 16. Sequentially, our chemical earnings increased by $359 million due to higher commodity and specialty product margins. Moving now to an update on our year-to-date cash flow growth shown on slide 17. Strong year-to-date cash flow from operations and asset sales of $41.5 billion more than covered the net $22 billion invested in the business and $17.6 billion distributed to our shareholders. Remaining cash was used for other financing activities, including debt reduction. Overall, free cash flow of $19.4 billion represented an increase of $12 billion compared to the same period in 2013. This year to date, free cash flow growth reflects our strong operational performance, ongoing asset management program, and disciplined capital allocation. Turning now to slide 18, I'd like to provide an update on project startups that will deliver profitable growth. Remain on track for a record startup year and plan to add 300,000 net oil equivalent barrels per day of production capacity. That is indicative of the diversity of our resource base. We continue to demonstrate our world-class project execution capabilities and have made significant progress during the year. Through June, three major projects were started up. As you know, Papua New Guinea LNG came online a few months ahead of schedule and reached full capacity in July. In Angola, CLOV reached full capacity in the third quarter, just a few months after first production. In Malaysia, Damar started up in the first quarter. Recently, we achieved several additional project milestones. In Indonesia, the second well pad at the Banyu Urip project started up, adding another 10,000 barrels per day of early production. Banyu Urip is now producing nearly 40,000 barrels per day. Construction of the central processing facilities, as shown in the picture, is near complete, and the floating offshore storage vessel was recently towed to its location for final hookup. The project will reach full field capacity of 165,000 barrels per day in 2015. In Malaysia, the Tapis Enhanced Oil Recovery project, which is the first large-scale EOR project in the country, was completed. The project is utilizing a water alternating gas injection process to sweep remaining oil reserves to the producing wells, increasing overall recovery. Also, the Qatargas 1 plateau maintenance project was completed, enabling the venture to maintain 10 million tons of annual LNG production for years to come. The project added well capacity and new onshore facilities for sulfur handling. In the fourth quarter, we also expect to start up several additional major projects, closing out our 2014 plans. In our offshore Sakhalin-1 project in Russia, the first production well at Arkutun-Dagi is currently being drilled. Offshore facility hookup and commissioning activities are nearing completion following the installation of the platform topsides this summer. Startup is anticipated around year-end, and the field is expected to add 90,000 barrels of oil per day at peak production. In the Gulf of Mexico, hookup and commissioning activities for both the Hadrian South and Lucius developments are underway. At Hadrian South, we finished drilling the two subsea wells earlier this year, and installation of the subsea facilities for the tieback to the Lucius spar is now complete. Startup of both projects is expected before year-end. In Canada, the Cold Lake Nabiye project is moving into the final stages of completion. Hydrotesting and commissioning activities are occurring in support of plant startup, and steam injection is expected around the end of the year. This project will add another 40,000 barrels per day to Cold Lake production. I would now like to turn to slide 19 for an update on our U.S. onshore liquids growth. We are generating significant cash flow by growing high-margin liquids production in the U.S., primarily in unconventional plays. In the Bakken, our resource base is now approaching 1 billion oil equivalent barrels, and gross operated production is up more than sixfold since we first entered the play in 2008. The Bakken remains our most active unconventional play and is the liquids growth engine in the U.S. Gross operated production has increased 38% year-on-year, reflecting higher activity levels. Currently running 13 rigs, up from 10 in the third quarter of 2013, and have increased new wells brought online by 25% year-on-year. We continue to achieve strong results and increased efficiencies through our development drilling in the core areas, optimizing completions and leveraging pad development. In this regard, drilling and completion costs have been reduced by 25% since 2011. We also have successfully employed our proprietary XFrac technology to reduce costs by eliminating the need for multiple plugs normally required for fracking. In the Woodford Shale, we're running 10 rigs. Gross operated oil equivalent production in the liquids-rich Ardmore, Marietta area has increased by 25% year-on-year, driven by more completions, strong well performance, and the move to pad development. Here too, well completion times have decreased significantly, reducing costs and increasing the number of wells drilled per rig year. Although rig counts have remained basically flat, we have increased the number of new wells by 33% year-on-year. In 2014, we also increased drilling activity in the Marietta basin, timed with the completion of infrastructure there. We are encouraged by the initial delineation work in Marietta, which has an even higher proportion of liquids than in the Ardmore area. Lastly, in the Permian Basin, we continue to develop both conventional and unconventional reservoirs across a leading position of over 1.5 million net acres, as shown on the map. Gross operated Permian production has increased 8% year-on-year on a large legacy production base, reflecting increased drilling activity. Currently, we have 16 rigs drilling liquids rich opportunities, almost tripling the number of rigs we had in the third quarter of 2013, along with approximately 65 workover rigs that are enhancing base conventional production. We continuously look for opportunities to add attractive acreage through bolt-on acquisitions. in 2014, transactions with Endeavor Energy Resources and LINN Energy added 64,000 net acres in the heart of the expanding Wolfcamp play, as shown on the map in blue, complementing the ramp-up of our horizontal drilling activities. Turning now to slide 20 for an update on our exploration activities. In Romania, drilling activities at Domino-2 are complete. The well was drilled to gather more information on the 2012 Domino discovery to assess the size of the resource and its commerciality. Domino-2 is being followed by the Pelican South-1 well, which is currently being drilled. Additional exploration targets are also planned. In Tanzania, Statoil and ExxonMobil made a seventh discovery in Block 2. Mronge-1 well discovered gas in the western part of Block 2. The well confirmed an additional 1 TCF of gas in place, bringing the total estimated resource in place up to 21 TCF. In Argentina, drilling and testing continue in the Vaca Muerta, where we have drilled and successfully tested two ExxonMobil operated horizontal wells. The Bajo del Choique X-2 well flowed at an average initial rate of 770 barrels of oil per day and is currently under long-term test. I will note that this is the highest unconventional oil production rate test in Argentina. The La Invernada X-3 well began testing in September with encouraging initial results, although still cleaning up. Our active program continues with additional drilling and testing later this year and into 2015. Finally, in Russia, we successfully drilled the University-1 well in the Kara Sea. I can confirm that the well did encounter hydrocarbons. However, the results are under evaluation, and it would be premature to comment any further at this time. The well was safely plugged and abandoned, and the rig has departed the location. In conclusion, today's presentation provides a summary of our year-to-date performance. ExxonMobil's strong financial operating results demonstrate the value of our integrated business model and unique competitive advantages. Total earnings were $26 billion, reflecting solid operating performance across all of our businesses and our ongoing asset management program. In the upstream production of 3.9 million oil equivalent barrels per day remain in line with our plan as we add new production from project startups and work programs. We continue to improve our production mix with unit profitability increasing from $18 per barrel in 2013 to just over $21 per barrel year to date. Our strong operating results, combined with our disciplined capital allocation approach, generate a robust free cash flow of $19.4 billion, an increase of $12 billion compared to the same period in 2013. This favorable performance enabled us to maintain industry-leading shareholder distributions of $17.6 billion. That concludes my prepared remarks, and now I would be happy to take your questions. Thank you, Mr. Woodbury. The question and answer session will be conducted electronically. If you would like to ask a question, please do so by pressing the star key followed by the digit one on your touchtone telephone. We request that you limit your questions to two so that as many people may have the opportunity to participate. If you are using a speakerphone, please make sure your mute function is turned off to allow your signal to reach our equipment. We will proceed in the order that you signal us, and we will take as many questions as time permits. Once again, please press star one on your touchtone telephone to ask a question. We will first go to Ed Westlake, Credit Suisse. Yeah, and may I say welcome on behalf of the sell side to the new role. Thank you, Ed. Obviously, your net income margins probably surprised most people. They seem to go up as the oil price pulled back. You have new projects obviously coming on stream, and I can see that your exploration expense was a little bit low, which is kind of non-cash. Can you give us some color as to why you think net income per barrel went up in the U.S. and international? All surprised. Yeah. Let me broadly say, Ed, that it starts with the integrated business model. You're all very aware that we've got a very cyclical nature of our business, and our business model is focused on creating shareholder value by participating through that whole value chain. It provides robust earnings performance despite the cyclical nature. If you think about just the overall upstream unit performance, as I said, we're up year to date versus 2013 by about $3 per barrel. Half of that is asset management impacts. The other half are improved profitability, primarily due to improved liquids mix as well as higher profitability around our gas projects. Really good progress by the organization in improving the higher margin production, as I said in the presentation. Okay, and then a second unrelated question just around Kearl. Obviously, that is a big project, and there's the Kearl expansion and potential debottlenecking. Maybe just give us an update of the latest status and a bit more detail there. Thank you. Sure. Thanks for that, Ed. Kearl, as we've said many times, is a long life asset. It's advantaged. Obviously, it's advantaged because of the proprietary technology that we've implemented where it forgoes the need for an upgrader. Overall, I'd say that we're making progress quarter on quarter at Kearl. Currently, we're consistently producing over 100,000 barrels of oil per day. As we ramp up production there, we are clearly identifying opportunities where we can further enhance the facility reliability. I will say that we did take a turnaround in September for planned maintenance, and all of these learnings are being fully integrated into the expansion project. As you know, we've talked about the importance of capturing the learnings from the initial development, and that was a key element of our investment decision to progress right into the expansion. Likewise, as we get more and more comfort with the operability of the initial development, those learnings are being integrated into the expansion project as well. Overall really pleased with the asset. As I said, it's a long life asset that's going to provide very stable productions. And quite frankly, Ed, we're in our sweet spot right now. This is what we do very well in terms of our project execution and then optimizing our operations to make sure that we maximize the value from the resource. Thank you. We'll now go to Phil Gresh, JP Morgan. Hey, good morning. Good morning, Phil. Just kind of following up on the question about the margin lift in the quarter and past couple of quarters. Just kind of wondering how you would think about how we should think about the next year or so and what potential benefit you could see in particular from cost levers as we've seen the oil price come down. What levers do you think you can pull around cost and/or CapEx? Yeah, Phil, that's a great question. Clearly the market has seen some changes with prices. I don't think any of us should be surprised given the oversupply and continued economic weakness. I'll go right back, Phil, to the value of our integrated business model, which really does position us well to capture shareholder value through the cyclical nature of the business. Quite frankly, the market controls the price, and what we need to focus on are the variables that we do control. To your question, those include things like effectively managing our development and operating costs, maximizing our reliability, and then optimizing the value of the molecules through the integrated business model. All along, that has been a fundamental mainstay of our corporation. As a key element of how we manage that, it's always around optimizing the cost structure within our assets so that we are maximizing the value from the resources. As a clarification, could you tell us how much of the 2015 CapEx is locked in at this point and what kind of flexibility you have? Yeah. Just a little bit more about the CapEx, if I could step back a moment. As you all know, our CapEx has grown through the years, and it peaked in 2013 at about $42.5 billion. That was largely driven by a deliberate decision to progress several high-value upstream resource projects that were ready and mature to move forward. Now we're trailing down to what I'd consider a more of a normal spend pattern of just shy of $37 billion. The upstream is dropping off a little bit more than that as the downstream and chemical are increasing their spend pattern. You can appreciate a lot of these projects that are in current progress, that CapEx profile will continue into the future. Our guidance is no different, Phil, in terms of about just shy of $37 billion a year for the next couple. We continue to invest through the cyclical nature of our business. Okay. My second question would be, you obviously have a very strong balance sheet and strong free cash flow generation, arguably stronger than most of your peers. You are in a pretty unique position to be potentially more aggressive in this period of weaker oil prices. Maybe if you could comment about how you would think about that bigger picture, whether it is the buyback program or opportunities with the portfolio. Phil, I would tell you, I think you assessed it up pretty good. Clearly, the financial flexibility we have with our current debt levels and our AAA credit rating position us very well to respond to potential investment opportunities, whether they be additional resource developments, investment in our downstream or chemical business that provide us advantaged benefits to the industry. It really requires us to maintain a very disciplined approach to capital allocation through the business cycle while at the same time providing industry-leading shareholder distributions. If you think about our capital allocation approach, it is first and foremost to invest in all of our attractive business opportunities that are accretive to average unit profitability and returns. Second is to continue to pay our reliable and growing dividends. I will remind everybody that our dividends have grown about 10% a year over the last 10 years. Lastly is to return cash to our shareholders through our share buyback program. As we have said in the past, our operating cash flows remain the primary source of funding for both our capital requirements and our shareholder distributions. We will access the financial markets when and if needed to meet commitments or capture opportunities. Thank you. Thanks, Phil. Thank you. We will now hear from Doug Terreson, ISI. Good morning, Jeff. Good morning, Doug. My question regards to margin and profitability improvement as well. You covered the mix effects on new projects and removal of Abu Dhabi, but you also mentioned asset management. My question is whether these benefits that you guys are getting from asset management are of the strategic or operational variety, just some clarification on what you meant by that. As you know, asset management has been a core component of how we manage our business. We're constantly looking across the portfolio to assess how we could maximize the value of our assets, either through development or finding alternative means to monetize those assets. As a result, as you know, we have had a very healthy program in terms of our divestment activities. In terms of our unit profitability, as I said year-on-year 2014 to 2013, part of that increase in unit profitability was associated with our asset management efforts. Okay. By way of example, Doug, let me just remind you, over the last 10 years, for instance, in our downstream, we have reduced our refining capacity by more than 1 million barrels a day. Yeah. Associated with divestment of about 20 plus refineries. We've divested over 200 fuel terminals, 38 blending plants and 6,000 miles of pipeline. It's a very active program to make sure that we're maximizing the value of the shareholder, but also positioning us strategically to continue to perform at an industry leading pace in the future. Let me ask you one other question about this. The company's always done really well optimizing cost. There's always been pressure on your cost for that reason. But is there maybe a step up in the effort to deliver sustained cost improvements that also may be affecting the results over the last few quarters? We always focus on cost management and our cost structure. Doug, I tell you that regardless of where we are in the business cycle, that is a fundamental part of our DNA is how do we become even more efficient than we've had historically? That's not only through the highly qualified people we have working here at ExxonMobil, but also the application, the technologies that we have in order to position ourselves in even a more effective manner to increase the value of those molecules. Okay, thanks a lot. You bet. We'll now go to Evan Calio, Morgan Stanley. Hey, good morning, Jeff. Good morning, Evan. Yeah. Hey, look, so somewhat related to the cash flow question and discipline. What drives you to forward the 4Q buyback guidance at $3 billion given the sequential commodity price drop or seasonality of refining, and that you do cash in 3Q? Maybe in general what commodity price do you need to slow the flywheel or buyback? Or will the balance sheet just underwrite that through any potential downturn? Evan, I would pull back on what I indicated previously on our capital allocation approach. It's a decision that we manage internally around what are our cash requirements in order to invest in the opportunities that we have in our portfolio. It's making sure that we continue to return cash to our shareholders through the dividend, and then we make a unique decision internally around how much additional cash are we to go ahead and distribute to our shareholders via our stock buyback program. Is this more of a quarterly by quarterly assessment? Because I know it's an up and down over time. Is that how it's approached? Yeah, Evan, I'd say it's probably much more continual than that, but generally speaking, there's a decisive point on each quarter to decide what we're going to do in the next near future. And moving on, we'll hear from Asit Sen, Cowen and Company. Thanks, and good morning. Good morning, Asit. Two unrelated questions. First, thanks for the color on U.S. onshore liquids, but wondering if you could quantify your production during the quarter, if you could, from U.S. unconventional. Yeah, you bet, Asit. Let me just share with you. The largest part of our unconventional U.S. liquids growth is in the Permian, Bakken, and the Woodford. In total, those are producing in excess of 210,000 barrels a day now. As I said in my prepared comments, it has really been significant progress over the last several quarters. I'd give you a little bit more color to that by saying that about 40% of that is in the Bakken, 35% in the Permian, and the rest is in the Woodford. Great progress. Couldn't be more proud of the folks there at XTO and the success they've had here in the recent past. Thanks, very helpful. Second, on LNG, could you comment on how global LNG pricing adjusts to lower oil prices? It appears that there's a 4-6 month lag, but wondering if you could comment on that. Yeah. Broadly speaking, the specifics of our LNG commercial agreements are confidential. Let me use Papua New Guinea as an example. A majority of the Papua New Guinea volumes are contracted in excess of 95%. They are linked to a crude price, and as crude price varies, so does that LNG. Thank you. We'll now hear from Blake Fernandez, Howard Weil. Good morning, Jeff. Thanks for taking the question. Over the past six months or so, you've announced a couple of investments in the downstream in Europe, which seems a little bit counter to what we've seen from peers who are basically trying to reduce their capital employed in the area. I'm just curious if Exxon is maybe taking a different view on the macro longer term, or if it's a scenario where you feel you have superior assets where over time, maybe just capacity rationalization occurs, and you're left standing with an attractive asset. Yeah. Blake, thanks for the question and the interest in that area. Clearly we are stepping out and distinguishing ourselves. Let me step back just a little bit and talk about the European portfolio and then the downstream investments. Clearly, Europe is disadvantaged by overcapacity, and some of which is driven by the lower cost feedstock in the U.S. and the Middle East. The sector will continue to rationalize existing capacity. ExxonMobil's European assets, though, are advantaged versus our peers due to the more efficient operations and the integration that we have with our chemicals and lubricants manufacturing businesses. So you'll see us continue to invest through the business cycle in order to enhance our advantaged position. Now, specific to those investments, they're always focused around key areas like lowering our raw material costs, increasing our higher value product yields, expanding logistics capability and flexibility, and then our mainstay of reducing the operating cost structure ultimately to high-grade the products to capture market demand. So if I focus specifically by way of example on the investment in the Antwerp delayed coker, that's around investing in conversion capacity to take lower yield products such as the fuel oil, convert it to distillate volumes where have higher volume and more margins. Thanks. I'll take one more if I could. You may not be able to answer this, but you mentioned the discovery in the Kara Sea with University-1. If I'm not mistaken, I've read some press articles suggesting that Rosneft may decide to pursue the additional drilling on their own due to the sanctions and whatnot. I'm just kind of curious how that would unfold with regard to your relationship there and participating in future interests. Right. Well, Blake, thanks for the interest. Clearly this is an important area for the industry in total, and we certainly appreciate the interest. Let me first start off by just recognizing the success of the well. We are extremely proud of what the organization has achieved in an extraordinarily remote Arctic region, both from a logistics and a drilling perspective. The team successfully completed the well with the utmost concern for safety and the environment, and it really does speak to the strength and capability of the organization. As I said in my prepared comments, I can confirm that we encountered hydrocarbons, but this is a very large area. This acreage is over 31 million acres. We've got one well penetration in that, so it is premature to make any assessment or really say any more at this point. We are currently evaluating the results to assess what forward plans we'll move forward on. I will remind you that ExxonMobil has a very long-standing and successful business in Russia, built on an effective and mutually beneficial relationship with our Russian partners. Moving on, we'll hear from Jason Gammel, Jefferies. Thanks very much. Two questions from me, Jeff. First, on the accelerated drilling onshore North America. I know that Exxon is a company that will invest throughout the pricing cycle, but just wondering if the number of rigs that are being employed in these plays is going to be affected by the change that we've seen in pricing conditions just over the last several weeks. Essentially, what level of onshore price would you need to see before you would perhaps start laying down rigs? Then the second question, one of your primary competitors just this week successfully IPO'd an MLP with pipeline assets, and there's evidently a pretty big value gap between what the stock market is willing to pay for those assets through an MLP and an integrated oil stock. Have you considered any form of MLP type of transaction with your pipeline assets? Yeah. Jason, thanks for those questions. Let me first start with the unconventionals. As I said, really good progress. I gave you a lot of details about it. Very proud of what the XTO organization is achieving up there. Let me say that these near-term price fluctuations are not going to have an impact on our operational activities. We test all of our investments across a range of economic parameters, including price. I will just say at a high level that our current drilling programs and inventory are fairly robust in this price environment. So we are very confident with the drilling activity. As I indicated, we are picking up rigs so that we can continue to progress our resource development activities, and it is a very significant part of our growth opportunity and importantly, our improvement in overall profitability. More specifically on the master limited partnership question, I talked a little bit already about our asset management program, that that is a fundamental aspect of how we do our business. It is around making sure that we are making the right choices that are going to maximize value for the shareholder. Through the course of that process, we have really divested or monetized all of our non-strategic assets. So we have been doing a lot of what you are hearing some folks do today. The remaining assets that we have got in place are very strategic to the integrated model that we have between the upstream, downstream or our chemical business. The MLPs are generally used as a financing mechanism to raise cash and fund business growth. As you know, with our financial flexibility, we have very low cost of capital. While I will never say no, I would tell you that just the cost benefit trade-offs for MLPs are unattractive for us given our low cost of capital. Very helpful. Thanks, Jeff. Thank you, Jason. Our next question comes from Roger Read, Wells Fargo. Hi. Good morning. Good morning, Roger. Just maybe going along with that sort of capital allocation and other questions that have come on here. CapEx plus or minus $37 billion, or maybe I should say minus $37 billion here going forward. You just made the comment a lot of the non-strategic assets have been paired. If we do find ourselves in a, let's say, $80-$85 oil environment, between the share repurchase program at around $3 billion a quarter, the CapEx at $37 billion, and maybe not as many assets left to sell, at least from a non-strategic or non-core standpoint, how do you balance all of that? What gives? Is it CapEx that gets pulled back? Is it the share repurchase? Is it something else? I'm just sort of curious there. Yeah, Roger. Generally speaking, operating cash flows remain our primary source of funding for both our capital requirements as well as our shareholder distributions. We will access the financial markets when and if needed to fund other commitments. I don't want you to walk away from this thinking that there won't be any other divestment opportunities because it is a continual process. Think of it as an ongoing upgrade of our overall portfolio, whereby we continue organic exploration, identify higher value assets. We continue to high grade our downstream and chemical facilities. It's an ongoing process that will likely continue to yield periodically divestment opportunities. Okay, thanks. Then taking another look at your lower 48 unconventional opportunities and ranking those in terms of returns or growth plus returns to some of your other opportunities, how do they scale up? Or maybe if you just said what is your best return opportunity today and where they fit in relative to that? Yeah. I would tell you, Roger, that they all are very strong. There's a lot of variability even within a given resource area depending on where you are in the trend. I would tell you that ExxonMobil has prime acreage in all three of the areas that I talked about as well as some others. So we are very well positioned. As you saw with the Permian Basin, we continue to look for opportunities to high grade the overall portfolio in those basins. So very strong inventory that we continue to high grade and look for opportunities for progressing the investment opportunities in each one of those fields. We would not expect any change in our operational plans. Thank you. Thank you, Roger. Moving on, we'll hear from Allen Good, Morningstar Investment Research. Good morning. Just another follow-up question on the Lower 48 unconventional. As you mentioned, you've been pretty active in Permian acquisitions. I just wondered what's Exxon's thought as far as what's the right size Permian position that you eventually want to get to get that to scale? And is there a preference for Permian acquisitions relative to Woodford and Bakken, or has it just been a case of value? Yep. Allen, it's always a case of value for us. I wouldn't say that we are excluding any opportunity in the U.S. or internationally. We have found a number of opportunities to high grade the portfolio in the Permian recently, but we continue to keep very well alert to other opportunities that may come up. Maybe even with the current decrease in prices, we may have additional opportunities that we'll find that are complementary to our business and can increase our overall underlying value. I'd extend that beyond the U.S. As you know, we've leveraged the expertise within the U.S. unconventionals to position ourselves strategically for other unconventional opportunities globally. Okay, great. Thanks. Just one on the downstream. Exxon obviously has a very large downstream global footprint. Can you give us any color on what you're seeing as far as the demand side, given the slide we've seen in oil prices? I know a lot of concern out there is not necessarily on the supply side, but weak demand. I was just wondering if you've seen any changes in the demand patterns of late given the lower prices. Well, as I said in the presentation, we did see some margin improvement, but generally demand has been fairly strong within the U.S., particularly in our chemicals business. But in Europe, Asia Pacific, demand has been down, and that's really a function of building capacity faster than demand as well as economic weakness. You got to step back and from a chemicals perspective, for instance, we're expecting demand to grow at 1.5% above GDP. We're a long-term business where we invest for the long term, and it's all fundamental to our energy outlook and our demand projections. Our next question comes from Paul Cheng, Barclays. Hey, Jeff. Good morning. Good morning, Paul. Well, first, just want to add my welcome to the investor relation. Thank you, Paul. Several quick questions. On page 11 of your presentation, the other is a negative $1.1 billion compared to the second quarter. In the second quarter, there is about a $1.6 billion of the asset sales gain related to the Hong Kong power, and your exploration expense is lower, so that may be adding another $100 million-$150 million in earning. So that is about a $300 million-$400 million of other benefit. Can you help us in terms of what that benefit may be, the nature? Yeah. So you are looking at, Paul, the quarter or sequential earnings reconciliation? That is correct. Yeah. So, as I said in the presentation, that was down about $1.1 billion. I would at a high level say that its asset management is down about 1.3. It is a net effect of the absence of Hong Kong power as well as some other acquisition activities that occurred during that period. As well as I think you appropriately pointed out that other operational items were positive by about $160 million due to lower OpEx primarily in exploration, as well as some minor Forex benefits. So you are saying that the asset sales swing is 1.3, so that means that we have about $300 million or so in asset sales gain in this quarter? Yes, that is correct. We will now hear from Ian Reid, BMO. Hi, Jeff. Good morning, Ian. How are you? Yeah, very good. Can I ask a quick question about Papua New Guinea? Now you've got the first part of the project or at least phase one fully on stream. What is your thinking about adding the third train, utilizing the additional gas which the joint venture has discovered in the region? Also potentially processing third-party gas or building another train to process third-party gas. Can you just kind of outline Exxon's thinking about that? Sure, Ian. Thanks for bringing up Papua New Guinea because it's another very successful accomplishment for the organization. I would tell you that everything is on the table in terms of what we do there. Obviously, first and foremost in terms of our priorities is to make sure that we are very comfortable with the operating structure. As I said, started up early, we got up to peak production. It is operating very well. The project team and the operations organization has done a remarkable job there. You're aware that we maintain an active exploration program in Papua New Guinea. We have picked up some additional resource. There are some other exploration opportunities that we're considering. I would tell you that the next step would be to consider, and has been under review, the economic viability for incremental trains there at the LNG plant. It was designed in order to easily tie in additional trains. We are very well positioned, and as you can appreciate, the incremental cost to expand the PNG facility is going to be much, much more competitive than another greenfield site. In summary, I'd say that we're very pleased with the resource, the overall potential and performance of Papua New Guinea. We've got some additional resource out there with the successful PNG discovery, and we're looking for opportunities to add to it, and that can come either through additional resource development or, as you indicated, processing third-party gas. Okay, thanks. Just one further thing. On the Russian sanctions, how is that affecting your Sakhalin development and also the LNG project, which you are progressing with Rosneft? Yeah, very good. I failed to mention that when we were talking about Russia earlier, and just to clarify for everyone, that the sanctions do not apply to Sakhalin-1 or our Far East LNG facility. The current program is moving forward. I talked about our Arkutun-Dagi. Sakhalin has been producing phenomenally, and I think it is representative of a very effective joint venture relationship with our Russian partners and the other partners in the JV. Moving on, we will hear from Doug Leggate, Bank of America Merrill Lynch. Hi, Jeff. It is actually Jason Smith on for Doug. How are you? Good morning, Jason. Most of my question's been answered. I just have one quick one, maybe to look at lower oil prices from a different perspective. One of the key issues, I think, in your production trajectory in the last few years has been the loss of PSC volume as a result of rising oil prices. Can you maybe provide some sensitivity or an update on how much production you get back if oil stays around $85? Well, Jason, I don't have the specific numbers at the price that you stated, but I will tell you that sequentially, in our sequential earnings, there were some positive effects associated with PSC volumes. It was under 10,000 barrels a day, second quarter to the third quarter. Got it. Okay. Thanks. That's all for me. We'll now hear from Ryan Todd, Deutsche Bank. Great. Thanks. Good morning, gentlemen. I guess a question, you've already touched on CapEx and CapEx outlook a few times during the call, but if we take a step back and look, a number of your European peers, there's been kind of a clear trend and maybe for a variety of reasons, a clear message and strong effort towards capital constraint, deferral of certain projects, and trying to kind of inflate free cash flow going forward from that point of view. It's been a bit more muted here in the U.S. Can you think about maybe if there's been a shift in your approach to project economics and relative returns and profitability as you look to your go-forward portfolio and the potential to constrain more CapEx and whether lower oil prices impacts that whatsoever? Yeah. We always are mindful of what's happening in the near future, but I keep on falling back that we are a long-term investor. Our plans are set well in advance. As I said earlier, our investment portfolio is tested across the full range of economic parameters, including price, so that we have the comfort that we're going to end up generating a favorable return regardless of the type of price fluctuations that we would test on. We always do stress tests. We feel like the program is robust. That is one of the real strengths of ExxonMobil with our integrated business model, is that we invest through these business cycles, and we've got the financial flexibility in order to fund those projects if we need some additional capital. Okay, thanks. Maybe one more specific one. In Tanzania, you guys have discovered an awful lot of gas to date. Can you give us any thoughts in terms of timing, in terms of your expectations and go-forward plans there? Yeah. On Tanzania, very good progress between Statoil and ExxonMobil. As I said, seven gas discoveries, now over 21 TCF in place. There is a consortium that has come together that have evaluated potential sites for a common onshore LNG facility, and we have made a recommendation to the government of Tanzania regarding the plant site location. Studies are progressing to determine the optimal development plan for Tanzania Block 2 resource as an LNG development. It really is at very early stages, and it is really too early to determine a specific startup date or overall design capacity or even the capital investment. But fundamental for us to move forward is a competitive, predictable, and durable fiscal environment to ensure that an investment of this scale and complexity is going to generate an acceptable return for our shareholders. Our next question will come from Paul Sankey, Wolfe Research. Hi, good morning, Mr. Woodbury. Welcome from me, too. On this CapEx question that we keep going back to, it was an interesting number that you gave us. You talked again, to be clear about a peak of CapEx in 2013, and then you said next year around $37 billion, in line with this year. Could you talk a little bit about the components of that? Because we have some interesting variation in your spending, for example, even in the latest quarter, where we are seeing lower upstream spending, somewhat higher downstream in chemicals. Beyond that, beyond the $37 billion next year, would we potentially have even lower CapEx in the longer-term future, given that you have highlighted the extent to which you reached a peak in 2013 as a function of recapitalizing the upstream? Right, Paul. As I said, we grew up to $42.5 billion in 2013. Again, I want to make the point that that was a deliberate decision given the resource opportunities that we had before us and the maturity of those, and the confidence that we had that we would generate very favorable returns for our shareholders. Likewise, it is a conscious decision to bring our upstream spending down to a normal spend pattern. As we communicated early this year in our analyst meeting, we are projecting that to fall down to just south of $37 billion over the 2015 to 2017 period. And yes, there is this larger increase in the downstream and chemical business, and that is focused on, like I talked about Antwerp, focused on making strategic investments that are going to better advantage our downstream facilities relative to industry, such as the North America ethane cracker at Baytown. I wanted to pick you up on the more normal that you are describing at level of CapEx. What do you mean by that? How do you define that normal level? If you look at your overall portfolio and the maturity of the resources going forward, Paul, it is based on our judgment as to when those resources are going to be ready, whether they be the definition of the resource, the definition of the development concept, the regulatory or a fiscal regime. It is a matter of when we believe they are ready to move forward and we have an optimal development plan in place. That is really what I mean by normal, is looking at our portfolio, as opposed to several years back when we saw these really large projects that came to fruition together that provided a huge opportunity for the corporation that we capitalized on. Yeah, I am with you. Just going back to the PSC question, obviously, if prices were to stay here, you have spoke about the 2Q to Q3, but obviously, it was a relatively minor oil price shift. At the moment, you are guiding to 4.1 million barrels a day next year. I assume that you are continuing with the guidance laid out at the analyst meeting. But the obvious expectation would be that number would come in higher as a result of lower oil prices, even though I know there is a different whole issue around economics. But broadly speaking, that would be what we should work towards, right? I think, Paul, I'd suggest our guidance is no different from March at the analyst meeting. Again, we look at a range over a period of time. The market's going to drive what the prices do, and we make our best judgment as to where we're going to fit in that in order to give you that guidance. If you think about what we said back in the analyst meeting, we said that we would grow from about 4 million barrels a day up to 4.3 million oil equivalent barrels a day by 2017. In doing so, we were adding about 1 million oil equivalent barrels a day of capacity. I'll remind you that a large part of that, 95% plus of that was liquids and liquids linked gas production. It will change our production mix from about 64% liquids and liquids linked today to just south of 70% in 2017. In summary, I'd say our guidance on volumes is still consistent with what we shared with you in March. Thank you, Paul. Moving on, we'll hear from Alastair Syme, Citi. Hi, Jeff. A couple of very quick questions. Can you highlight a wee bit how much you're spending on the U.S. shale piece? Is that something you'd be willing to or part disclose? Yeah. Sorry. Go ahead. All right. Secondly, I was just picking up on the comment you made about Qatargas volumes and the way they moved year-on-year. Just wanted to get a wee bit of an explanation for why that was. Sure. Thank you. On the first part on the U.S. shale, as you can appreciate, we are very focused in that area, but we really do not break it down beyond the country itself. You can see that in our financial and operating, the additional data in the investor relations information. With respect to Qatar, this is really associated with entitlement impacts associated with the Al Khaleej gas project. Is it a permanent ratchet down or is it temporal? No, it is associated with prices. Okay, great. Thank you very much. Our next question comes from John Herrlin, Societe Generale. Yeah, thank you. Most everything's been asked, Jeff, but regarding the shale economic thresholds in North America, with the Bakken, it sounded like you have a different kind of completion. It's not plug and perf, it's somewhat different. Can you elaborate a little bit more? Also with that completion, are you also doing a similar thing in Argentina? Yeah. Good question, John. I would tell you that, as I said in my comments, the XTO expertise that we've built up in the unconventionals is being leveraged globally. We are continuing to grow our capability there. As I shared in my prepared comments, the improvements that we've seen, not only in reducing overall cost, but improving the productivity of, if you will, the manufacturing process of drilling these wells. A key element of that has been the application of technology. As I said in my prepared comments, one of the benefits that we've used in Bakken has been this completion technology, which is proprietary ExxonMobil technology called XFrac, and that allows us to avoid putting a whole bunch of plugs in the well and makes it a much more efficient and safer operation for completion installation. To close out on your question about Argentina, I'd broaden that and say that all of these learnings in the unconventional are being positioned to apply elsewhere within our portfolio. Once again, it's just another really good example of our industry-leading performance and our capability, and that positions us very well to compete for resources. Great. Thanks very much. Thanks, John. We'll now hear from Guy Baber, Simmons & Company. Thanks very much for squeezing me in here. Two quick ones for me. First on, just a big picture question around exploration. Generally speaking, can you just remind me what percentage of the total capital budget this year is allocated to exploration appraisal activity? Then optimally, where would you like to see that percentage longer term, just to sustain the long-term opportunity set and reserve maturation? Also, how comfortable you may be in flexing that down at any point in the cycle for a given year? So that's number one, just thoughts on the exploration budget. Then secondly, just if you could quickly talk about the balance sheet. You mentioned you'd access financial markets if need be, and your net debt to total Cap, obviously low compared to most peers. Actually high relative to where it's been at the last 10-year period. Could you just remind us of your target leverage ratio and framework also, and just where you are comfortable in taking the leverage? Yeah. Guy, let me first start with the second half of your first question about whether we would flex down our exploration. I would tell you that we are opportunity-driven. We have tremendous opportunities around the world. We have a very robust inventory. We are very well positioned to compete. As I said earlier, it is all around how do you go ahead and upgrade the value of overall resource base. From an exploration perspective, given our financial flexibility, given the opportunities, we have really got to be focused on the horizon around high-grading our portfolio and positioning ourselves strategically around the globe. Specific to our budget, we do not break that type of information out in terms of the various components within the exploration budget. But I would like you to think about our exploration activity as a means to further high-grade our overall portfolio. On the second point, on our leverage ratio, there is no target. We have been fairly consistent over the last couple of years. We have maintained a AAA credit rating. I want you all to think about it, that our focus is around value. It is not a focus around market share or volume. It is around value. How can we create greater value? And we will use that balance sheet to achieve that objective when we think it is appropriate. Our next question comes from Pavel Molchanov, Raymond James. Hey, thanks very much. Just one more from me on Russia, if I may. You touched on the policy sanctions-related uncertainty in relation to the Arctic. Are there any other operations within Russia that have had to be postponed, deferred, or reduced because of the sanctions rules? Yeah. You may recall that we have a number of joint ventures throughout Russia. We talked about the Kara Sea. We also have a venture in the Black Sea and West Siberia, and then lastly, a number of ventures within the Russian Arctic shelf. If you think about the sanctions, they deal with specifically deepwater, unconventional resources, and Arctic activity. Yes, the joint ventures I just summarized for you are included within the scope of the sanctions. Have all the activities in those JVs been suspended as a result? Well, we are fully complying with the sanctions and regulatory requirements. We do have one follow-up question from Paul Cheng, Barclays. Hey, Jeff, two quick ones. First, related to your investment in Europe refining, do you have any plan to do a similar investment in your U.S. refining system? Second question, I think in your comment, you are saying that you have some overlift in the quarter. Can you quantify how big is that or how much is the impact in the quarter? Also, at the end of the third quarter, from an inventory standpoint, are you guys neutral or underneath or overlift? Thank you. Thank you, Paul. On your first question around additional investments, I would just say broadly that we regularly evaluate our global portfolio where we have opportunities for investment. As I have already discussed with the areas targeting on things like expanding our feedstock flexibility or our logistics or reducing our cost structure. We have a lot of conversion capacity in the U.S. already. Generally speaking, Paul, as a matter of practice, we just do not want to comment or speculate on any particular opportunities or investments that we may or may not be considering. When they are ready and we have made a decision, we will go ahead and share that more broadly. The second question was around overlift, and if I can, I will refer back to our quarter-on-quarter upstream earnings reconciliation. If you remember, there was a volume mix component, about positive $340 million. First and foremost, there was a fairly sizable component associated with the high-margin project and program activity of over $500 million. As I said during my prepared comments, it really highlights the progress that we are making on our unit profitability and the higher value volumes. Not for the sake of growing volumes, but for the sake of capturing value. There was an overlift component that was positive, and then there was an offsetting decrease in a number of areas such as entitlements decline, downtime, and some asset management. That does conclude today's question-and-answer session. Mr. Woodbury, at this time, I would like to turn the conference back to you for any additional or closing remarks. Well, to conclude, thank you all for your time and your interest this morning. Certainly very good