Earnings Call: Q4 2016

Jan 31, 2017

Good day, everyone, and welcome to this ExxonMobil Corporation fourth quarter and full year 2016 earnings call. Today's call is being recorded. At this time, I would like to turn the call over to the Vice President of Investor Relations and Secretary, Mr. Jeff Woodbury. Please go ahead, sir. Thank you. Ladies and gentlemen, good morning, and welcome to ExxonMobil's fourth quarter and full year 2016 earnings call. My comments this morning will 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 of our performance. ExxonMobil generated full-year earnings of $7.8 billion and fourth-quarter earnings of $1.7 billion. The corporation continues to generate cash flow through the business cycle to meet our commitment to shareholders and support investments across the value chain. In the fourth quarter, cash flow from operations and asset sales exceeded dividends and net investments by a healthy margin. We're realizing the benefit of strengthening prices in the fourth quarter in our upstream financial results. However, these results included a $2 billion impairment charge in the US segment, largely related to dry gas operations with undeveloped acreage in the Rocky Mountain region. The impairment charge was the result of an asset recoverability study completed during the quarter and is consistent with the approach we took in 2015. Continued solid performance in our downstream and chemical segments underscores the resilience of our integrated business throughout the commodity price cycle. The corporation continued to progress strategic investments across the upstream, downstream, and chemical segments during the year, including execution of major projects, value-accretive acquisitions, and pursuit of high-potential exploration opportunities. Moving to slide 4, we provide an overview of some of the external factors affecting our results. Global economic growth remained modest during the fourth quarter. In the U.S., the pace of economic expansion slowed relative to a stronger third quarter, while it stabilized in China and remained tepid in Europe and Japan despite some improvement in the quarter. Crude oil and natural gas prices strengthened during the quarter on anticipation of an improved supply balance as well as colder weather. Refining margins improved in Europe and Asia, while seasonal margins in the U.S. weakened. Finally, chemical margins decreased due to higher feed and energy costs, driven largely by commodity products. Turning now to the financial results shown on slide 5. As indicated, fourth quarter earnings were $1.7 billion or $0.41 per share. In the quarter, the corporation distributed dividends of $3.1 billion to our shareholders. CapEx was $4.8 billion, down 35% from the fourth quarter of 2015, reflecting ongoing capital discipline and strong project execution. Cash flow from operations and asset sales was nine and a half billion dollars, and at the end of the quarter, cash totaled $3.7 billion, and debt was $42.8 billion. The next slide provides more detail on sources and uses of cash. Over the quarter, cash decreased from $5.1 to $3.7 billion. Earnings adjusted for depreciation expense, changes in working capital and other items, and our ongoing asset management program yielded nine and a half billion dollars of cash flow from operations and asset sales. The negative adjustment for working capital and other items reflects changes in deferred tax balances. Uses of cash included shareholder distributions of $3.1 billion and net investments in the business of $3.8 billion. Debt and other financing items decreased cash by $4 billion, primarily due to a reduction in short-term debt. Cash flow from operations and asset sales covered dividends and net investments in the quarter by more than $2 billion. Moving now to slide 7 for a review of our segmented results. ExxonMobil's fourth-quarter earnings decreased $1.1 billion from a year ago quarter as a result of the impairment charge taken in the U.S. Upstream segment. This was partly offset by stronger Upstream results and an earnings benefit in the Corporate and Financing segment as a result of favorable non-U.S. one-time tax items. On average, we expect that near-term corporate and financing expenses will be in the range of $400 million-$600 million per quarter, which does represent a reduction relative to our previous guidance. Similarly, in the sequential comparison shown on slide 8, earnings decreased $970 million. Turning now to the Upstream financial and operating results starting on slide 9. Fourth quarter Upstream earnings decreased $1.5 billion from a year ago quarter, resulting in a loss of $642 million. Higher realizations improved earnings by $510 million, driven by our liquids prices. Crude realizations increased more than $8 per barrel, whereas natural gas realizations decreased $0.32 per thousand cubic feet. Volume and mix effects decreased earnings by $50 million. Other items added $70 million, driven by lower operating expenses, partly offset by the absence of favorable tax items. Excluding the impairment charge, fourth quarter 2016 Upstream earnings totaled $1.4 billion, up $528 million from the prior year quarter. Moving to slide 10. Oil equivalent production decreased 3% compared to the fourth quarter of last year to 4.1 million barrels per day. Liquids production decreased 97,000 barrels per day as new project growth and work program volumes were more than offset by field decline, entitlement impacts, and downtime in Nigeria. Natural gas production decreased to 179 million cubic feet per day as higher demand and project growth were more than offset by decline, regulatory impacts in the Netherlands, entitlement effects, and divestments. Turning now to the sequential comparison starting on slide 11. Upstream earnings decreased $1.3 billion for the third quarter of 2016, from the third quarter of 2016. Improved realizations increased earnings by $450 million. Crude prices were $4 per barrel higher, and natural gas prices were up $0.41 per thousand cubic feet. Favorable volume and mix effects contributed $230 million, driven by higher seasonal demand, lower downtime, and project growth. Other items increased earnings by $90 million, driven by favorable foreign exchange effects. Moving to slide 12. Sequentially, volumes increased more than 8% or 310,000 oil equivalent barrels per day. Liquids production was up 173,000 barrels per day, mainly the result of lower downtime and growth from new projects and work programs. Natural gas production was 823 million cubic feet per day higher than the previous quarter. Stronger seasonal demand in Europe and entitlement effects were partly offset by regulatory impacts in the Netherlands and field decline. Moving now to the Downstream financial and operating results starting on slide 13. Downstream earnings for the quarter were $1.2 billion, a decrease of $110 million compared to the fourth quarter of 2015. Weaker margins reduced earnings by $570 million. Favorable volume mix effects, mainly from increased operational efficiency and production optimization, improved earnings by $200 million. All other items added $260 million, mostly from asset management activities, partly offset by increased maintenance costs and unfavorable foreign exchange effects. In the quarter, Imperial Oil completed the sale of its retail network. The sites have been converted to the branded wholesale distributor model, resulting in an earnings benefit of $522 million. Turning to slide 14. Downstream earnings were flat sequentially. Stronger refining margins outside the United States and improved volume mix increased earnings by $160 million and $100 million respectively. All other items reduced earnings by $250 million driven by increased maintenance costs and unfavorable inventory and foreign exchange effects, partially offset by asset management gains. Moving now to the chemical financial and operating results starting on slide 15. Fourth quarter chemical earnings were $872 million, down $91 million compared to the prior year quarter. Weaker margins, primarily for specialty products, decreased earnings by $10 million, while unfavorable volumes and mix effects further reduced earnings by $30 million. All other items decreased earnings by $50 million, largely due to unfavorable inventory and foreign exchange effects. Moving to slide 16. Chemical earnings were down almost $300 million sequentially. Weaker margins driven by higher feed and energy costs reduced earnings by $200 million. Higher volumes added $50 million. All other items decreased earnings $150 million, including seasonally higher operating expenses and unfavorable inventory and foreign exchange effects. Turning now to the full year financial results starting on slide 17. As I mentioned, 2016 earnings totaled $7.8 billion and represents $1.88 per share. Corporation distributed $12.5 billion in dividends to our shareholders. CapEx totaled $19.3 billion for the year, a reduction of $11.7 billion versus 2015. Throughout the year, we maintained a relentless focus on costs, capturing both structural efficiencies and market savings while maintaining operational integrity. These efforts resulted in further reduction in total CapEx and OpEx of $16 billion in the year versus 2015 when excluding the effect of the upstream impairment charge. Cash flow from operations and asset sales was $26.4 billion. Turning to slide 18. Cash balances were flat to year-end 2015 at $3.7 billion. Earnings, adjusted for depreciation expense, changes in working capital and other items, and our ongoing asset management program resulted in the $26.4 billion of cash flow from operations and asset sales. The negative working capital and other impacts for the year were driven by lower upstream payables, deferred tax impacts, and cash contributions to the U.S. pension plan. Uses included shareholder distributions of $12.5 billion and net investments of $16.7 billion. Debt and other financing items provided $2.8 billion in the year. Moving to slide 19. This graphic illustrates the Corporation's sources and uses of cash during the year and highlights our ability to meet our financial objectives. In a difficult business environment, the Corporation continued to generate strong cash flow from operations and asset sales to support the dividend and most of our net investments in the business, supplemented by a moderate increase in debt financing. We maintain financial flexibility to continue to invest through the cycle in attractive opportunities. As indicated, shareholder distributions totaled $12.5 billion. Annual per-share dividends were up 3.5% compared to 2015, and this marks the 34th consecutive year of per-share dividend growth. In the 4th quarter of 2017, ExxonMobil will limit share purchases to amounts needed to offset dilution related to our benefits plans and programs. During the year, ExxonMobil generated $9.7 billion of free cash flow, up $3.2 billion from 2015, reflecting the resilience of our integrated businesses and our focus on the fundamentals. Looking ahead, we anticipate our 2017 capital and exploration expenditures to be about $22 billion. We know there will be a lot of interest in our investment plans, and we will share additional details in a few weeks at our analyst meeting. Moving now to slide 20 and a review of our full-year segmented results. 2016 earnings fell $8.3 billion as the impact of lower realizations and margins on our upstream and downstream segments was partially offset by stronger chemical results and lower corporate costs associated with several one-time tax items. As a result, the full-year effective tax rate was 13%. Assuming current commodity prices and the existing portfolio mix, we do anticipate that the effective tax rate will be between 25% and 35%, excluding the impact of any large one-time items. On this basis, our full-year 2016 effective tax rate was within the new guidance range. Turning now to the full-year comparison of upstream results starting on slide 21. Upstream earnings of $196 million were $6.9 billion lower than 2015. Realizations reduced earnings by $5.3 billion as crude oil prices decreased over $7 per barrel and natural gas prices declined by $1.40 per thousand cubic feet. Favorable volume and mix effects increased earnings by $130 million, driven by new project growth. All other items added $310 million due to lower operating expenses, partly offset by the absence of favorable tax items. Excluding the impairment charge, 2016 upstream earnings totaled $2.2 billion. Moving to slide 22. As indicated, volumes ended the year at 4.1 million oil equivalent barrels per day, down about 1% compared to last year, but within our full-year guidance of 4 million-4.2 million oil equivalent barrels per day. Liquids production increased 20,000 barrels per day as project and work program growth was partly offset by field decline and higher unplanned downtime, most notably from third-party impacts in Nigeria and wildfires in Canada. Natural gas production, however, decreased 388 million cubic feet per day. Growth from projects and work programs was more than offset by field decline, regulatory restrictions in the Netherlands and divestments. The full-year comparison for Downstream results is shown on slide 23. Earnings were $4.2 billion, a decrease of $2.4 billion from 2015. Weaker margins decreased earnings by $3.8 billion. Favorable volumes, mix effects increased earnings by $560 million, and all other items, primarily asset management gains, increased earnings by $920 million. On slide 24, we show the full year comparison for Chemical results. 2016 earnings were $4.6 billion, up $197 million from 2015. Stronger commodity margins driven by advantage liquids cracking increased earnings $440 million, while higher volumes added $100 million. Other items reduced earnings by $340 million, reflecting the absence of asset management gains. Moving next to an update on our Upstream project activities. We continue to deliver on our investment plans with an unwavering focus on long-term value. Five major projects started up in 2016, adding 250,000 oil equivalent barrels per day of working interest production capacity. In the fourth quarter, Kashagan and Gorgon Train 2 started up, and like other 2016 projects, continue to ramp up to plateau production levels. Looking forward, construction activities continue to progress on another 5 major projects that will come online over the next 2 years. These projects will together contribute another 340,000 oil equivalent barrels per day of working interest production capacity. Moving now to slide 26. Our focused exploration program continues to enhance our resource portfolio as demonstrated in the fourth quarter. In Guyana, ExxonMobil submitted a development plan for the initial phase of the Liza field. We continue to progress broader development planning activities based on a phased development approach. As part of these activities, contracts were awarded to perform Front-End Engineering and Design. We expect to reach the final investment decision for the project later this year. Additionally, as I mentioned in the third quarter earnings call, the Liza-3 appraisal well successfully encountered an additional deeper reservoir which was being evaluated at the time. This reservoir is now estimated to contain 100 million to 150 million oil equivalent barrels beneath the Liza field. Also, offshore Guyana, the Payara exploration well discovered hydrocarbons, marking the second discovery on the Stabroek Block. The well encountered more than 95 feet of high-quality oil-bearing sandstone reservoirs. Two sidetracks have been drilled to rapidly evaluate the discovery, and a well test is about to get underway. The data will be analyzed in the coming months to better understand the full resource potential and development options. Now, after the Payara well test, the Stena Carron drillship will next move to the Snoek prospect just south of the Liza discovery. ExxonMobil also made two additional discoveries in the fourth quarter, including the Nigeria Owoh-3 oil discovery announced in the third quarter earnings call and the Muruk discovery in Papua New Guinea. Both Owoh and Muruk are near currently producing fields which will enable capital-efficient development. We also continue to capture new prospective exploration acreage. In Mexico's Offshore Bid Round One, ExxonMobil and Total jointly submitted the apparent high bid for Block Two located in the Perdido area near the U.S. border. In Cyprus, ExxonMobil and our partner, Qatar Petroleum, have been selected as the winners of Offshore Block Ten in the recent tender round. We look forward to negotiating the production sharing contract for this high potential block. ExxonMobil has also been awarded an offshore prospecting license for exploration activities in the Gulf of Papua in Papua New Guinea. The initial scope of work on this block is expected to include seismic acquisition. Turning now to slide 27 and an update on ExxonMobil's U.S. unconventional portfolio. As a leading oil and gas producer in the United States, we have a strong acreage position and proven operational expertise in unconventional plays. XTO's daily production is currently more than 700,000 oil equivalent barrels per day, of which 38% is liquids. Our ownership and operating position enable flexible development and allow us to maximize learning curve benefits through the cycle. For instance, in the Permian Basin, where we operate two-thirds of our production, our average drilling footage per day has increased about 85% since 2014 because of continuous learning and application of ExxonMobil's proprietary FastDrill process. We continue to focus on liquids growth through development activities and strategic farm-ins and acquisitions. Since 2010, XTO has grown liquids production at a compounded annual growth rate of about 11%, which currently represents about 12% of the corporation's global liquids production. Moving now to slide 28. Our most recent acquisition in the Permian further strengthens our unconventional portfolio, adding high-quality acreage in the Delaware Basin and more than doubling our resources in the Permian to greater than 6 billion oil equivalent barrels. ExxonMobil agreed to acquire privately-owned companies whose holdings include 250,000 net acres of leasehold in the Permian. The acquisition includes an upfront payment of $5.6 billion in ExxonMobil shares, plus additional contingent cash payments totaling up to $1 billion based on development of the resource over a specified timeframe. Map on the left shows our heritage acreage in yellow, acreage acquired in transactions in 2014 and 2015 in blue, and the acreage associated with the most recent transactions in red. As you can see, the new leasehold represents a significant position in the heart of the Delaware Basin. Less than 5% of the acquired resource has been developed to date, providing substantial opportunity for future growth. As a result of our proven capabilities, we are well-positioned to maximize the value of this resource. This acquisition will add an estimated 3.4 billion oil equivalent barrels in multiple stacked plays, 75% of which is liquids. The highly contiguous nature of the acreage will also provide significant cost advantages by combining XTO's low-cost execution capabilities with proprietary technology from our upstream research company. We plan to drill the longest laterals within the play, which will maximize per-well recoveries and help generate market-leading development costs. More than 85% of the wells are expected to have lateral lengths 2 miles or longer because the acreage is not constrained by traditional land lease issues. This transaction increases ExxonMobil's inventory of Permian drill wells that yield at least a 10% rate of return at $40 per barrel to more than 4,500 wells. We currently produce more than 140,000 net oil equivalent barrels per day in the Permian and are operating 10 rigs. This is expected to move higher in 2017 as we begin activity on the newly acquired acreage. Moving now to slide 29. We continue to strengthen our downstream and chemical business through selected integrated investments in our facilities and operations. We recently completed investments in lubricants and chemical facilities in Louisiana that support our aviation lubricants business, commissioning a new state-of-the-art jet oil manufacturing facility in October of last year. The new plant will use Group V synthetic base stocks sourced from facilities that started up last year at our adjacent Baton Rouge chemical plant. Across the fuels, lubricants, and chemical value chains, we continue to high-grade our portfolio and reduce complexity to efficiently capture market value while reducing operational risk and capital expenditures. In the quarter, we reached agreements to divest several downstream affiliates in Africa and South America. Additionally, as I mentioned earlier, Imperial Oil completed the conversion of its retail business to a branded wholesaler model. This model benefits from significantly lower capital requirements while continuing to grow retail sales. We also continue to enhance our logistics capabilities by focusing on strategic midstream assets. We recently announced the formation of a joint venture with Sunoco Logistics that will expand access to domestic crude oils by improving transportation options from the Permian and Ardmore Basins to the U.S. Gulf Coast refineries. In Baytown and Mont Belvieu, Texas the construction of our new 1.5 million tons per annum ethane steam cracker and associated metallocene polyethylene facilities is progressing well with phased start-up commencing in the second half of this year. Finally, ExxonMobil recently announced a new project at our Beaumont, Texas facility to expand polyethylene capacity by 650,000 tons per year. This expansion amounts to a 65% increase in polyethylene capacity at the site. Together, the projects at Beaumont and Mont Belvieu represent multibillion dollar investments that will increase ExxonMobil's U.S. polyethylene production by nearly 2 million tons per year or 40%, making Texas our largest polyethylene supply point. The new facilities will process advantaged ethane feedstock to meet growing global chemical demand. Moving to the final chart on slide 30, I'd like to conclude today's comments with a brief summary of our 2016 performance, which is really underpinned by our sustained focus on value. ExxonMobil earned $7.8 billion in the year while managing through a challenging business environment. Corporation delivered on its plan to produce 4.1 million oil equivalent barrels per day and maintain focus on business fundamentals. Volume contributions from our portfolio of new developments underscore our project execution excellence and reputation as a reliable operator. Total CapEx was $19.3 billion, down 38% from 2015 as we exercised capital discipline and investment selectivity and continued to pursue market and execution efficiencies. Solid operating performance combined with continued investment and cost discipline generated cash flow from operations and asset sales of $26.4 billion and positive free cash flow of $9.7 billion. As I mentioned in the fourth quarter, cash flow from operations and asset sales more than covered the dividend and net investments in the business. Our commitment to shareholders remains strong, as demonstrated by our reliable and growing dividend. We are confident in ExxonMobil's integrated business model and our ability to continue to grow long-term value in any business environment. Now we'll discuss our forward plans in more detail at the upcoming analyst meeting, which will take place at the New York Stock Exchange on Wednesday, March first. That concludes my prepared remarks on a very busy year. 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 star key followed by the digit 1 on your touchtone telephone. We request that you limit your questions to one initial and one follow-up so that we may take as many questions as possible. If you're using a speakerphone, please make sure that your mute function is turned off to allow your signal to reach our equipment. Additionally, please lift your handset before asking your question. We will proceed in the order that you signal us, and we'll take as many questions as time permits. Once again, please press star one on your touchtone telephone to ask a question. We'll take our first question from Neil Mehta with Goldman Sachs. Morning, Jeff. Morning, Neil. Jeff, I appreciate the incremental disclosure here on the Delaware transaction. That's where I wanna start. As you think about that deal, is it indicative of the view that Exxon has that you see more value in, let's say, the private market than the public market? Can you just talk a bit more about the opportunity you see in U.S. unconventional to do deals? Yeah, Neil, that's a good question. I would tell you that I would not view it as being exclusive to one type of transaction. As we have talked in the past, we keep a full view on what may be out there that could be competitive with our existing resource base and accretive to overall long-term financial performance. You know, these things don't happen overnight. You know, several of these, you know, take many, many months to go ahead and put in place, and not all of them, you know, transpire into an executed deal. What's important is that it is a key aspect of our overall asset management program in order to high grade our portfolio with the view of our underlying mission of growing shareholder value. Appreciate that. My follow-up, Jeff, is on CapEx. I imagine we're going to get a little bit more color on this at the Analyst Day in a couple of weeks, but the $22 billion that you outlined is in line with what you talked about earlier this year, but up from 2016. Can you at least speak high level to what's driving the growth in 2017 versus 2016 in terms of CapEx? Then bigger picture, can you talk about what you're seeing in terms of cost inflation across your portfolio? Well, Neil, as you indicated, we do plan on giving a lot more detail around our investment plans in the analyst presentation that will be just a little bit more a month from now. You know, as you indicated, the $22 billion that I mentioned is fairly consistent with our forward-looking plan that we provided a year ago. I would tell you that it does not reflect a year-on-year increase associated with the cost inflation. In fact, the inverse is true, is that the organization continues to look for high impact capital efficiencies to drive the cost down, and it is by and large a function of activity level. you know, certainly as activity continues to build, we will all experience some market pressures, but that doesn't relieve us of our fundamental objective of maximizing the value proposition. Rest assured that the organization will continue to keep focused on what new solutions are there for us to get to a lower cost outcome. The organization is very committed to make sure that we're capturing those and really leading the cost curve. Our next question comes from Phil Gresh with JPMorgan. hey, Jeff. Good morning. Good morning, Phil. I wanted to start on the working capital and other headwind, $2.4 billion in the quarter, $8 billion for the year. A pretty big number. I guess I was just wondering if you could maybe, you know, elaborate or break that down a little more between deferred taxes and some of the other items, and moving forward, how you think about the ability to lessen that headwind in 2017. Well, I mean, obviously there's really 2 large components that are driving it. Obviously the changes in the working capital. You know, by and large, you know, adjustments in, you know, receivables and payables due to activity and changes in commodity prices. The second part are other balance sheet items, some of that associated with deferred taxes. As I said, it also includes, you know, cash contributions that we made to the pension plan. You know, a lot of moving part, pieces is understandable, and I understand the interest. You know, that's about all the color I have for you at this point. Okay. In terms of kind of priorities for with cash from here, I mean, to the extent you have excess free cash flow above the dividend in 17 is the first priority, with your ending debt balances where they are, would it be debt pay down, or do you feel like you have flexibility to do other things? I think it's a function of, you know, the business climate and the opportunities that we have before ourselves. As you've heard us say before, if you think about our capital allocation approach, it's a commitment to provide a reliable and growing dividend to our shareholders and at the same time, continue to selectively invest in our business with opportunities we believe are going to enhance the long-term return of the corporation. The excess cash, by and large, you know, we don't wanna hold large cash balances if we don't have an immediate need for it. We will think about either paying down debt or buying back shares, and that is done primarily on a quarterly basis. You know, the corporation will step back and look at a number of factors like our current financial position, our potential opportunities to put capital to work, as well as what we see in the near term in terms of the business outlook. Okay, thanks. We'll take our next question from Doug Leggate with Bank of America. Thanks. Good morning, everybody. Good morning, Jeff. Morning, Doug. Jeff, I wonder if I could kick off with your capital guidance. I guess as kind of a follow-up, but ask you if you could move it on to talk a little bit about the production capacity that you see that goes along with that capital, 'cause I'm assuming the Permian is part of it. What I'm really driving at is you've got a number of projects still ramping up, so could you give us some idea as to what the remaining capacity is for those ramp-ups? In other words, what would the delta be if those projects were running full out in 2017? I've got a follow-up, please. Yeah, Doug, I mean, first observation would be is that you're correct that we have projects that started up all the way back to, you know, early 2015 that are still well within their development drilling programs or are ramping up to plateau production rates. Some of these things could take 12 to 24 months to fully reach the plateau production rate. I don't have a specific number for you as to what is that incremental capacity that's left to ramp up. I'll also highlight that a number of those projects also are exceeding design expectations due to really strong management by the organization around reliability and reservoir performance. We talked about Papua New Guinea in the past, you know, design at about 6.9. It's now, you know, produced above 8 million tons per annum. You've heard in the news about Banyu Urip, which the development basis was about 165,000 barrels a day. We've been producing about 185, and it is now under review to take it all the way up to 200,000 barrels a day. Again, very strong operational reliability and very good reservoir performance. The point I'm making is above the additional ramp-up that's anticipated from the major project startups, there's also another layer of capacity that we're building on based on the organization's focus on the operational capabilities of our assets. Okay. Just to be clear, Jeff, on the Permian piece of that, I think at the time of the acquisition you talked about moving to a 15 rig program. Is that what's the starting point for that? Yeah. What are they running right now? You're talking about the recent acquisition, I believe. Right. Yeah. Let me back up and first say that if you know, if you look at the overall development of the new acreage, we see that over the long term, it would support a multi-decade production plateau of about 350,000 oil equivalent barrels per day. A very substantial addition to liquids production as well. In fact, if I can put it in scale for you, if you remember the, you know, my prepared comments, I said that our current liquids production from XTO represents about 12% of the corporation's global liquids production. If you were just to add on the expectation from the Delaware acreage, that would take us up somewhere between 20%-25% of our global liquids production. The point being is it's a very material part of the portfolio. As I indicated, we've got 10 rigs running right now. We are planning on ramping up that activity over the near future. We're to do it commensurate with the leasehold development requirements. You know, we're very, very positive about this, obviously, given the acquisition, and we wanna get to it right away. Jeff, I appreciate that answer. My follow-up is very hopefully a quick one. Payara, I think, in Guyana, the limited disclosure you've given so far, I guess, has raised some questions about potential scale. Is there anything you can tell us about relative scale or absolute scale of both the Liza and Payara, reserve expectations ultimately, but also a likely development plan both beyond the early production system? I'll leave it there. Thanks. Yeah, Doug. As we indicated in the 3rd quarter, given the Liza-3 appraisal well, that really built confidence in a view that we've got at least 1 billion barrels of recoverable reserve. Since then, we've drilled the deeper zone that added additional volume, as I indicated in the prepared comments. Payara, we're very pleased with the outcome. We moved very quickly to drill 2 additional sidetracks in order to better define the reservoir. As I said, I think the next critical piece of information will be this well test that we're starting right now, and that will allow us to size Payara. Obviously, as we move along in each operational activity, that data is feeding our real-time development planning effort to assess the full development scope of the block. Remember, we've got two other blocks to that we'll have to integrate as well. Right now, we're moving forward with the initial phase development. As we've said previously, it's a 100,000 barrel a day FPSO. We do feel like that's a prudent step, very good, strong returns. You know, right now, we view that as just, you know, the initial phase. Okay. I'll wait till the analyst day. Thanks, Jeff. Thank you, Doug. We'll go next to Jon Herrlin with Societe Generale. Yeah. Hi. Two quick ones for me, Jeff. Regarding your CapEx, is that just strictly E&D, or are you including the acquisition cost for Bass? Well, Jon, on the Permian acquisition, remember we're purchasing that via shares. Right. It excludes that share purchase. Okay. Well, it'll still be part of costs incurred at the end of the day, but that's fine. Next one on Payara. Is that age correlative with the upper Liza pay or the lower Liza pay, or can you not say anything on that? Yeah. I really don't have anything to share on that at this point. Okay, that's it. Thank you. Thank you. We'll go next to Doug Terreson with Evercore ISI. Good morning, Jeff. Good morning, Doug. Just for clarification, is it correct that the $2.1 billion in asset sale gains were after tax and included in the $1.7 billion earnings figure? Either way, could you provide some guidance as to which operating segments that these gains came from? Yeah. The proceeds of $2.1 billion are you're asking about the proceeds that we had in the press release? Correct. Yeah, those are before tax proceeds. Okay. Those proceeds are primarily within our downstream portfolio. You know, I'd say about, you know, over 85% of it is in the downstream. Okay. The largest part of that is in the Canada retail sales. Jeff, can you give guidance on after tax? On the proceeds? Yes. No, I don't have any numbers. Okay to share with you on that. Okay. Then also, three of your competitors have taken steps to enhance their pay for performance linkage by changing the metrics that they're using for their business units to ones which tie to intrinsic value on the stock market and probably CEO pay too. While your stock has outperformed some of these companies in the equity market over the years, my question is how is the company thinking about P4P this year, and specifically, whether there's need for change given its rising profile as a corporate governance issue with investors? Well, if you remember, you know, You're talking about our executive compensation program? I am. Yeah. As you and I have talked in the past, you know, remember that a large part of our compensation program is based on a long-term payment schedule. It is intended in order to make sure that our executives are being held to the decisions that we're making over the long term. You know, our long-term incentive is paid over a 10-year period, 50% about 5 years, the remaining 50% after 10 years. Really, it's the later of the 10 years or retirement. You know, some of us go even beyond 10 years. It's really designed to ensure that our executives feel the same performance that our investors feel because when it does pay out, it's paid out at the current stock price. Now I'll tell you that the compensation committee does step back and look at the program periodically to make sure that it's ensuring, it's encouraging the right type of behaviors, and it's recognizing the success of the corporation. You know, for those that are listening about it, we've got a what we call an executive compensation overview disclosure that we send out annually. Yeah that provide a lot of good detail about the structure of the program. Okay. Okay, thanks a lot, Jeff. Hey, Doug- Yeah Just a follow-up on your question regarding the Canadian retail. As I said in my prepared comments, it was $522 million after tax. Great. Thanks a lot. We'll go next to Sam Margolin with Cowen and Company. Morning, Jeff. How are you? Morning, Sam. Late in the quarter, you finally got FERC approval for Golden Pass. I guess I'd add that to the, to the bucket in one of the later slides about kinda de-lengthening your U.S., you know, nat gas position maybe. I'm sure you've made comments on this before, but, you know, how do you think now in the new environment or how things are played out currently, how U.S. LNG competes with some of your other world-scale LNG potential assets around the world? How do you think about that sort of moving forward as you, as you wanna develop additional U.S. gas assets in the context of that? You know, it's a good question, Sam. If you, if you could, well, the best place to start is really thinking about it from our overall energy outlook and our supply-demand balances. You know, over the long term, you know, we expect that LNG capacity or demand will continue to grow. In fact, almost, you know, something like 250% of today's LNG capacity. You know, a large part of that growth is primarily driven by Asia. Now, like most commodities, you're gonna have periods in which there's oversupply and periods where there's insufficient supply. You know, we do expect that with the number of projects coming on, that there are some projects that where there is a period in which we'll see LNG oversupply. Now, if I step back from that's the, if you will, the value proposition. I step back, we've got a very extensive portfolio. I would tell you that brownfield developments, you know, that is incremental investments to existing operations like Papua New Guinea or even Golden Pass, provide us a economic advantage by lowering the cost, by leveraging the installed investment. At Golden Pass, as you noted, we did get FERC approval. You know, the one key step that we're still waiting for after many years is final Department of Energy approval of non-FTA export authorization, and we're hoping that that will come shortly. You know, each one of these projects will be evaluated on their own merit. As you've heard us say previously, as it relates to LNG projects, we wanna, you know, lock in a large part of that capacity on long-term contracts. You know, Golden Pass within the whole portfolio of investment opportunities that we have, we're pursuing long-term sales contracts. They'll all be evaluated on their own merits. Okay. I guess my follow-up then is sort of on the same topic. It might be a similar answer on sort of an individual project analysis basis. You know, as you look within your 30-year outlook and a lot of energy demand globally is driven by gas and, you know, against the backdrop of early this year, the debooking of some natural gas reserves domestically and, you know, an imperative to maybe get those rebooked over time, what do you think is more preferable between uses of that gas for you, investing in kind of shipping it to these Asian demand centers via LNG or keeping it onshore and consuming it within your chemical business? That's a good question. It really highlights and talks to the issue of optionality. We are the largest gas producer in the U.S. Where do we see that gas going in the future? Again, stepping back from the energy outlook, we expect gas is gonna grow about 1.5% per year. That's primarily driven by 2 things: 1, power generation, the 2nd thing, petrochemicals. As you know, we've got a very integrated value chain. The anticipation is that resource will not only meet domestic growth in power generation, but will also look at the utilization of that into our value chain in the chemicals business as well as where we started this discussion around LNG exports. Optionality gives us tremendous amount of flexibility to make sure that we're maximizing the value proposition. All right. Thanks, Jeff. You bet. We'll go next to Evan Calio with Morgan Stanley. Hey, good morning, Jeff. Morning. I have a question. Any outlook on future project returns, conventional versus your acquired Permian? I ask the question in the context that you make a significant acquisition in one of the tighter energy asset markets in the world, the Permian. You discuss a relatively healthy plateau, future plateau level of production, you know, while there's distress in asset markets globally and in regions in which Exxon operates. I guess given the assets and these laterals, these longer laterals you discussed, you know, can you talk about how you think the future returns compete within your portfolio or how advantaged they may be? Well, from a general perspective, Evan, I would tell you that, you know, clearly the recent acquisition predominantly in the Delaware Basin is very competitive. It really goes back to the fundamental objective that we're trying to achieve through acquisitions or through exploration or, you know, our investment program. That is to make sure that we're maintain a focus on value creative performance. We're looking for investments that are gonna continue to maintain our industry leading return on capital employed. You know, certainly very attractive. We've given you a sense for the economics where, you know, I think back in the second quarter we showed you some of the progress we've made in unit development cost, operating cost. We gave you a sense for the portfolio then which, you know, with the Bakken and Permian together, we had over 2,000 wells that achieved, you know, greater than a 10% return, money forward economics, full in, fully loaded on a $40 per barrel price. You know, you add this acquisition into this, it takes us up to about 4,500 wells, so a very robust inventory. The long-term objective, thinking about the short cycle versus long cycle is one in making sure that the pace maximizes the learnings that we're integrating and captures the technology application that we want to apply in order to achieve these outcomes like the length of the laterals. I'd say that these, this acquisition and the investments that we plan under it are gonna be very competitive to our existing, inventory of opportunities. I mean, can you dimension how much of your expected CapEx, $22 billion CapEx is in shorter cycle, however you define that, whether offshore or onshore? related, I mean, how do you consider the value of capital flexibility or cycle times in your gating process, either as a plus or a minus for a longer cycle project? Yeah. On the first question, I tell you that we are gonna provide some more color in about a month's time at the analyst meeting. If I ask you just to hold that thought, we'll give you a little bit more perspective at that time. On the second one, you know, the balance, the overall balance of short cycle versus long cycle, you know, obviously we've got a very large resource inventory, with over 90 billion barrels. We're trying to move that resource inventory at the same time, you know, maintaining a robust level of short cycle investments. Now of course, that short cycle inventory continues to grow with all these acquisitions that we've been picking up. That's done through our annual planning process. You know, we look at the execution capability of the organization, the service sector, and then we look at the fundamental, you know, cash management objectives to make sure that we've got that flexibility. A key element of when we share a CapEx objective, we've built in flexibility to the upside as well as flexibility to the downside. We know how to flex that program depending on what commodity prices do. Appreciate it. We'll go next to Jason Gammel with Jefferies. Thanks. Hi, Jeff. Jeff, I know that, in the third quarter press release you had talked about the potential for needing to take some negative revisions to prove reserves in the oil sands. Clearly, at least in the quarter, you haven't taken any financial impairments to those assets. Can you talk about whether you would still view those proved reserves as potentially needing to be written down or whether the price recovery into the end of the year was sufficient to allow those to remain on the books? Yeah. It's a good question. Again, I wanna make sure that everybody's very clear that there is a separation between proved reserves reporting under the SEC rules and then the whole issue of asset impairments. Really, what you're asking, Jason, is clearly the question about proved reserves. In the third quarter we indicated, because we thought it was prudent at the time given where crude prices were, that we indicated that we were likely gonna take as much as 4.6 billion barrels out of proved and put them in our resource base. And I'll remind you that I emphasized at that time that even though we make that transfer, there is no change to our operations or how we manage the business, those assets going forward. We'll be announcing our final year-end reserves here in the next 2 weeks as we typically do. In short, we do expect to reflect most of the SEC pricing impact that we discussed in the third quarter. I will also note that we anticipate that there will be some partial offsets to those numbers. Stay tuned. We'll be finalizing that shortly and be releasing that information here in the next 2 weeks. Appreciate that, Jeff. Then just as a follow-up, the other acquisition that you've announced this year, I'm afraid I'm a little bit lost on the process for actually completing the InterOil transaction. Can you talk about what is still outstanding there in order to get that deal done? Yeah. You know, we're going back through the process following a decision by Canadian courts. We put in place a new amended agreement between InterOil and ExxonMobil. I'll just remind everybody that in the first process through the InterOil board fully unanimously approved this transaction, and shareholders approved it by over 80%. We're going back through the process, and right now there is a shareholder vote anticipated in the middle of February. Then, as in the last cycle through this, we will need to go back to the Yukon courts to make a final ruling on the offer, and then hopefully close thereafter. Great. Thanks, Jeff. Appreciate that. Bet. We'll go next to Ryan Todd with Deutsche Bank. Great. Thanks. Maybe if I could have a couple quick follow-ups on capital budget. I realize you'll give more, more details next month. How should we think about capital allocation, to some extent for the lower 48 business, with the addition of the Permian acquisition? Does it highlight a growing relative share of the capital budget by the U.S. onshore? Is it additive to your existing activity, or should we expect to see the capital diverted away from areas like the Bakken and Oklahoma and be replaced by activity in the Permian? Well, I mean, Ryan, we'll certainly provide more color here in 1 month or so, but I mean, directionally, it's a fairly sizable acquisition that we're making in the Permian. We feel good about our acreage position in the other unconventional basins. I showed you a map where, you know, we've got a meaningful presence in every one of them. You know, I would as an indicative guidance, I would tell you that it's likely gonna add additional CapEx to our short cycle investments in order to move forward on the acreage that we picked up in the acquisition. Okay. Thanks. That's helpful. Maybe just one on 2016 CapEx, which came in quite a bit lower than guidance early in the year. I mean, any comments on what were the primary drivers? Is that cost deflation, deferral of activity, you know, change any expected scope and spend? Yeah. Thanks for asking the question, Ryan, because I think it does reflect very well on how the Corporation responded, and particularly our people and their focus on recognizing that we're in a down cycle, and we got a great opportunity to take advantage during that down cycle. I'd say that it really is a function of a number of things. One is. It all is underpinned by our very strong focus around capital discipline. It comes down to capital efficiency opportunities that we're able to continue to capture regardless of where we're in the commodity price cycle. It includes market capture. You know, we all know that, you know, the service sector and the, and, you know, the related costs have dropped materially. It also, importantly, it has to do with the very strong project execution performance on our operated projects, most of which coming in on budget and on cost. There was an element of how we paced our projects for several reasons. One, recognizing the business climate, wanting to stay within our means. Two, in a low price environment, there's unique value that we're able to capture by going back and recycling through the development planning process on some of these projects to try to do things like reduce the cost structure, add additional resource to increase resource density. It really is an opportunity in the down cycle to go ahead and add incremental value to those future investment. All right. Thanks, Jeff. Okay. Thank you. We'll go next to Paul Sankey with Wolfe Research. Hi, Jeff. Morning, Paul. Jeff, with the changes in Washington, I just wondered what Exxon's stance is. Firstly, I assume you guys are pro lifting sanctions on Russia. Secondly, I assume that you would be anti the border-adjustment tax. Finally, can you make any comments about the impact on your operations in Iraq from the recent limitations on travel there? I assume that's gonna directly impact you. Thanks. I guess a couple comments. You know, we will continue to advocate for, you know, in many of the areas you talked about, advocate for free market principles. You know, when it comes down to the important discussion that's happening in Congress and the current administration around the tax code, you know, we believe the tax code should be globally competitive. It should be predictable, stable, providing investment certainty and not picking winners and losers. I mean, we will continue to stay principle-based in our view on those matters. You know, with respect to Russia, we will continue to fully comply with the existing sanctions, and I'm not gonna speculate when or if they are fully satisfied and removed in the future. On Iraq, you know, more broadly speaking, some of the issues associated with decisions taken in the U.S., you know, a key aspect wherever we are around the world, including Iraq, is the security of our people and our contractors. You know, we have a very dedicated effort within the organization to ensure that we're trying to stay in front of potential threats that the organization needs to respond to in order to ensure the safety and security of our assets and people. I'd rather not talk about specifics, but I will tell you that we're monitoring the situation very closely. Understood. Jeff, if I could completely change the subject. The president of Guyana was commenting earlier in the week that we could see production start up in 2019 from Liza. Is that, is that, you know, reasonable, do you think? We've also obviously heard from Hess about final investors investment decision mid this year. If we look back to what you did in Angola as an example of your speed with which you can get these things up and running with the idea of getting very early cash flow, I wondered if you could handicap the chances that we do see first production much, much sooner than I think you've been talking more 2021. Yeah. No, it's a good question. Listen, I think first and foremost is that we're gonna work with our co-venturers and the government to move this project along in the most efficient and expedient way. You know, all stakeholders have a role in deciding how this project moves it forward. We certainly understand the resource owner's interest, and I'll tell you, we are very attuned to it. As I indicated in my prepared comments, we think it is reasonable that the initial phase will move forward to an FID decision later this year. The guidance that we have been providing, as well as consistent with the regulatory filings, is that the initial phase would start up in 2020. Got it, Jeff. Thank you. You're welcome. We'll take our next question from Asit Sen with CLSA Americas. Good morning, Jeff. Morning, Asit Sen. Thanks for the color on the short cycle versus long cycle. I just wanted to make sure I got the Permian numbers right. The 140,000 barrels a day production now, you comment on the 350,000 barrels a day of plateau production from the recent delivery acquisition, what timeframe are we looking at? Well, you know, we have yet to share the specifics around the buildup of that. As I indicated, Asit, you know, we wanna get at it quickly. You know, the 350,000 potential, and that's oil equivalent barrels per day, we believe is a, is a reasonable investment program that can be maintained over multi-decades. Gotcha. Okay, my quick question on the new project startups. Barzan, is that a 2017 startup? Could you remind us on the working interest that you have there, 7%? That's what I have. Yeah. Our working interest is 7%. You know, you really need to talk to the operator RasGas on the specifics around the project. Great. Thanks, Jeff. Welcome. We'll go next to Paul Cheng with Barclays. Hi, this is Moses, on for Paul. Quick question on the impairment charges. Have you completed the review of the entire portfolio or are certain assets still under review in 2017? We've completed the review of the entire portfolio. Great. Thank you. That's it from us. You're welcome. We'll go next to Alistair Syme with Citi. Hi, Jeff. I also had a question on the impairment. If you look back at your most recent energy outlook, you know, it looks like you made some quite big changes around the expectation on North American tight oil and gas. Is it possible to relate those changes back to today's impairment decision? It feels like you expect there's gonna be a lot of growth in associated gas, for instance. Well, I mean, it's a good question, Alistair, I tell you, the first point I'd make is the reason why we do an annual update on our energy outlook is really to make sure that we are most informed about the fundamental building blocks that really underpin that demand projection. The changes that you're asking about is really a function of a number of factors. It's not just the energy outlook, it's our You know, we do this in conjunction with our annual budget and plans process. You know, it also is a function as part of the energy outlook is looking at the competitiveness of different resources that underpin that demand outlook. It's a number of factors that will drive our decisions and ultimately the choices that we make. Okay. Thank you. As a follow-up, can I ask, you know, can you explain what non-U.S. tax effects are on the corporate items? Are these upstream or downstream items? The non-U.S. tax items really across a number of the business segments. The largest in the fourth quarter were primarily in the upstream business. Is it possible to give any color what they relate to? We don't have any additional information to share. Okay. Thanks very much, Jeff. You're welcome. We'll go next to Brendan Warn with BMO Capital Markets. Yes. Thank you, Jeff. Just first question, just on those five major project startups. You flagged 2017 to 2018, particular I guess with Hebron and Sakhalin that you do operate. Are they still in 2017 recognizing Hebron you most recently said it was on track for end 2017? I have a follow-up as well. Thanks. Yes, that's correct. They're currently on plan to achieve those objectives. Okay. They're both in before end 2017. Yes. My follow-up refers, and it's probably, you'll probably say defer this to the Capital Markets Day, if I refer back to slide 33 from the Capital Markets Day, you'd sort of given guidance of Cash flow from operations and asset sales for 2016 with a range of sort of at $40 a barrel to $80 a barrel. It looks like at $45 average for this year, you've just come in at where the $40 a barrel line should be. I'm trying to reconcile you had a weaker cash flow number for 2016 and whether that changes your view for 2017 in terms of Cash flow from operations. Yeah, Brendan, a good question and an important dialogue that we think is something that we should be talking to. We will update that chart you're referring to in the upcoming analyst day here within a month and be ready to talk more about it with our current views. Okay. Thanks, Jeff. Welcome. We'll go next to Ed Westlake with Credit Suisse. Yes, good morning. Toplyar here. Two questions, I guess. Firstly, decline rate. I mean, you guys have done very well on the production side to minimize base decline. You've got these long duration assets in a number of geographies. Maybe just a quick update as far out as you could go on expected decline rate on the base business. Yep. Ed, our, we assess our long-term decline rate over every year. In fact, it's in our, in our 10-K. What we've had in terms of a decline rate here in the last, you know, recent past, last couple years has been 3%. Let me just qualify that 3% as being, That does not include project activity. It'd be high, yeah. Okay. We haven't really had a conversation around OpEx and margins, maybe deferred tax, maybe to the prior question on cash flow as you go forward. Maybe just a word on how much more savings you can get on OpEx, the new projects, are they accretive to margins, and then what you expect to happen to deferred taxes as prices bump up a little here, hopefully? Yeah, really good question on, in terms of OpEx and how we're managing that. I would tell you that we are never satisfied. I mean, we clearly understand there's been a lot of progress here over the last two years, but I can tell you that the organization doesn't believe status quo is sufficient. As I alluded to previously, we'll continue to look for structural opportunities. We'll continue to be very focused on organizational effectiveness. Importantly, we'll continue to work with the service sector to come up with lower cost, higher quality opportunities. You know, sure, if activity continues to build, there's gonna be market pressures, but we're gonna continue to work against those market pressures to capture incremental value. On deferred income taxes in the future, there's really nothing more I can share with you. You can appreciate some of this has to do with the current low price environment that we've been through here the last 2 years. Margins should also improve with the new projects coming on, presumably. Well, that's the objective of the investment program. Thank you. Yes. Thanks, Ed. We'll go next to Theepan Jothilingam with Exane BNP Paribas. Hi, good morning, Jeff. Thanks for taking my questions. I had two actually. Firstly, could you just talk about, I know you're intending to issue equity for the recent Permian transaction. Is there any thoughts about buying back to offset that dilution? My second question, just in terms of exploration for 2017, I know the focus is on Guyana, could you talk about any other high impact plays for 2017 and the spend associated? Thank you. Theepan, on the fundamental question. To me, I interpret it as, whether we're gonna buy back any stock. I'll go back to our earlier discussion around it. It's really a quarterly decision that management makes based on a number of variables that I've already described. You know, as I said in the prepared comments, we don't anticipate doing any type of buybacks other than to address anti-dilutive impacts also with the benefits programs and plans. On other exploration focus, we expect, you know, for the near term, you know, flat spend out to the next several years. I've shared a number of key areas that we're focusing our attention. You know, Cyprus, you know, the high quality block we got there on Block 10 that we've got to enter into negotiations on the production sharing contract, but we're very encouraged by it. Mexico, the Block One that we picked up, which is right along the U.S. border, adjacent to some U.S. acreage that we've got. Again, very encouraged by it, you know, putting plans in place. I indicated that we continue to expand to our exploration acreage position in Papua New Guinea. You think about some of the big high potential areas for us, Papua New Guinea is, you know, very important to us. You know, Guyana, that area has been very important to us. As we've been talking about off and on today is the unconventional business with a very strong focus on the liquids potential. I think it really does make a very strong statement around the value proposition that we're trying to deliver to our shareholders. Okay. Thanks, Jeff. I was just wondering, I mean, when you think about potential acquisition add between equity and adding debt, I mean, could you just talk about how the market should think about that? Should we see if there are opportunities Exxon uses paper rather than debt? Yeah, well, it's going to be case specific. I mean, the important message for you to understand is that we have the flexibility to do either. The final structure of a given transaction is really a function of the dialogue between the parties with the focus of what the seller wants from the transaction. I wouldn't read any more into it relating to our capital structure. Great. Thank you. Our final question comes from Pavel Molchanov with Raymond James. Thanks for taking the question, guys. Just two quick ones. You mentioned that almost all of the increase towards the $22 billion CapEx budget reflects higher activity. Can you be a little more specific on what service cost inflation you are assuming, particularly in your North American CapEx? You know, Pavel, as I indicated earlier, you know, we're gonna provide more color around our investment plans in about a month's time in the analyst meeting. I just ask you to hold that until we get to that point. Okay. As far as the InterOil closing process, you're currently doing the rerun of the shareholder vote. Should the Yukon court block the second attempt as they blocked the first one, is there any other alternative in your mind to getting shareholder approval? Well, I mean, let me not speculate as to how this will progress. Very strong support from the shareholders of InterOil. This is a process that InterOil is running, and we think that we have addressed some of the comments that were made in the first process. Let's let that go through, and then we'll decide how we move forward from there. All right. Appreciate it. Thank you. We have no further questions in the queue at this time. Well, I want to thank everybody for their participation today, and I really do appreciate your time and the questions. You know, we appreciate your continued interest in ExxonMobil, and we really do look forward to visiting with you next month at the analyst meeting. Until then, we'll keep very focused on our fundamental mission of growing long-term shareholder value. Thank you. That concludes today's conference. We thank you for your participation.