Earnings Call: Q4 2013

Jan 30, 2014

Summary

FY13 earnings were $32.6B as lower divestment gains weighed on results; production met target and cash generation supported $25.9B in shareholder distributions. Kashagan and Kearl remained key operating uncertainties.

Good day everyone, and welcome to this Exxon Mobil Corporation fourth quarter and full year 2013 earnings conference 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. David Rosenthal. Please go ahead, sir. Good morning, and welcome to Exxon Mobil's fourth quarter earnings call and webcast. The focus of this call is Exxon Mobil's financial and operations and full year 2013. I will refer to the slides that are available through the Investors section of our website. Before we go further, I would like to draw your attention to our cautionary statement shown on slide two. Moving to slide three, we provide an overview of some of the external factors impacting our results. Global economic growth continued at a modest pace in the fourth quarter, with mixed performance across the region. Moderate U.S. economic growth was sustained. China's growth rate stabilized while Europe's economic recovery remains sluggish. Energy markets delivered mixed results. WTI prices decreased more than $8 per barrel, widening the discount to Brent as the global marker was only slightly lower in the quarter. Henry Hub natural gas prices were essentially flat. Global industry refining margins strengthened as stronger U.S. margins were partially offset by continued margin weakness in Europe and Asia Pacific in the quarter. Turning now to the fourth quarter financial results as shown on slide four. Exxon Mobil's fourth quarter earnings were just under $8.4 billion, or $1.91 per share. The corporation distributed $5.8 billion to shareholders in the quarter through dividends and share purchases to reduce shares outstanding. Of that total, $3 billion was used to purchase shares. CapEx was $9.9 billion in the fourth quarter. Cash flow from operations and asset sales was $12 billion. At the end of the quarter, cash totaled $4.9 billion and debt was $22.7 billion. The next slide provides additional detail on fourth quarter sources and uses of funds. Over the quarter, cash decreased from $5.7 billion to $4.9 billion. Earnings, depreciation expense, changes in working capital and other items, and our ongoing asset management program yielded $12 billion of cash flow from operations and asset sales. Uses included additions to property, plant, and equipment of $8.4 billion and shareholder distributions of $5.8 billion. Additional financing and investing activities increased cash by $1.4 billion. Share purchases to reduce shares outstanding are expected to be $3 billion in the first quarter of 2014. Moving on to slide six and a review of our segmented results. Exxon Mobil's fourth quarter earnings of just under $8.4 billion decreased by $1.6 billion from the fourth quarter of 2012. Lower earnings across all business segments were partially offset by reduced corporate and financing expenses. In the sequential quarter comparison, shown on slide seven, earnings increased by $480 million as higher upstream and downstream earnings and lower corporate and financing expenses were partially offset by lower chemical earnings. Guidance for corporate and financing expenses remains at $500 million-$700 million per quarter. Turning now to the upstream financial and operating results and starting on slide eight. Upstream earnings in the fourth quarter were $6.8 billion, down $976 million from the fourth quarter of 2012. Realizations increased earnings by $60 million as worldwide natural gas realizations increased by $0.41 per Mcf and crude oil decreased by $2.38 a barrel. Unfavorable volume and mix effects, including the impact of crude under lifts in West Africa and the North Sea, along with lower natural gas production, decreased earnings by $550 million. All other items decreased earnings by $490 million, reflecting increased expenses driven by Kearl operating costs and higher planned exploration costs in Russia. Upstream after-tax earnings per barrel for the fourth quarter were $17.95, excluding the impact of non-controlling interest volumes. Moving now to slide nine. Production decreased by 77,000 oil equivalent barrels per day, or 1.8% from the fourth quarter of last year. Liquids production was up 32,000 barrels per day, or 1.5%. Ramp up at the Kearl and Nigeria Satellites projects, lower downtime, and continued increased production from unconventional plays in the U.S. were partly offset by field decline and price and spend impacts. Natural gas production was down 654 million cubic feet per day, primarily due to expected lower U.S. production and field decline in several areas. Turning now to the sequential comparison and starting on slide 10. Upstream earnings increased by $73 million versus the third quarter. Realizations decreased earnings by $430 million as worldwide crude prices decreased by $5.89 per barrel, and natural gas realizations increased by $0.57 per Mcf. Volume and mix effects improved earnings by $90 million, reflecting increased global liquids and natural gas production. All other items had a positive impact of $410 million. Higher gains from asset sales were partially offset by higher operating expenses. Moving to slide 11. Oil equivalent volumes were up 190,000 barrels per day or 4.9% sequentially. Liquids production increased 36,000 barrels per day, mainly due to additional production from work programs in the U.S. and the North Sea, Pearl ramp-up, and lower downtime, partly offset by scheduled maintenance in Nigeria and field decline. Natural gas production was up 973 million cubic feet per day, mainly due to seasonal demand in Europe. Moving now to the downstream financial and operating results, and starting on slide 12. Downstream earnings for the quarter were $916 million, down $852 million from the fourth quarter of 2012, mainly due to lower non-U.S. refining margins. Volume and mix effects increased earnings by $110 million, driven by refining optimization activities. All other items, including higher operating expenses and unfavorable foreign exchange impacts, decreased earnings by $280 million. Turning to slide 13. Sequentially, fourth quarter downstream earnings increased by $324 million. Improved refining margins, mainly in North America, increased earnings by $120 million. Volume and mix effects increased earnings by $330 million, reflecting favorable refining optimization activities. Other items reduced earnings by a net $120 million. Moving now to the chemical financial and operating results, and starting on slide 14. Fourth-quarter chemical earnings were $910 million, down $48 million versus the prior year quarter due to lower specialty product margins. Positive volume and mix effects were mostly offset by other items. Moving to slide 15. Sequentially, chemical earnings decreased by $115 million, primarily due to lower margins in Europe. Moving next to the fourth-quarter business highlights and beginning on slide 16. We continue to advance our global portfolio of high-quality upstream projects. Construction at the PNG LNG project is now nearing completion, with the focus shifting to commissioning key facilities and equipment in preparation for first LNG delivery, now targeted for the third quarter of this year. Gas has been introduced to both the gas conditioning plant at Hides and the LNG facility in order to progress commissioning activities. The Kearl expansion project is on budget, is now more than 70% complete, and remains on target for a 2015 startup. We continue to develop attractive logistics solutions to provide market access for our growing oil sands production from this future additional capacity. At Upper Zakum, we are progressing with our partners the field redevelopment to raise production capacity to 750,000 barrels a day over the coming years. The increase is enabled through the use of four artificial islands, of which two are now complete, and extended-reach drilling using proprietary ExxonMobil technology. Civil works and facility additions will continue through 2015. In 2013, the Upper Zakum joint venture was granted a 15-year license extension through 2041. The extension includes enhanced fiscal terms, allowing the expansion project to meet our investment criteria and contribute towards Abu Dhabi's plans to boost production. In Iraq, we reached a production capacity of 500,000 barrels per day at the West Qurna-1 development in 2013. We continue to progress additional capacity expansion through facility debottlenecking, workovers, new drill wells, and well tie-ins. We have also completed 3D seismic acquisition over the West Qurna-1 field. In the fourth quarter, we executed agreements to sell a combined 35% interest to PetroChina and Pertamina, reducing our participation interest from 60% to 25%. We will remain as the lead operator for the project and are committed to continue to maximize value for all parties involved in redeveloping this world-class resource. Turning now to slide 17 for an update on our exploration activities. In Tanzania, the Mronge-1 well discovered an additional 2 TCF-3 TCF of natural gas in place from two separate intervals. The main accumulation is at the same stratigraphic level as the proven Zafarani-1 well. Secondary accumulation was encountered in a separate gas-bearing reservoir in a play previously untested in Block 2. Mronge-1 is the fifth discovery on Block 2 and brings the total of the gas in place up to 17 TCF-20 TCF. Further exploration drilling is planned for 2014. In Russia, ExxonMobil and Rosneft completed joint venture agreements to implement a pilot project for tight oil development in Western Siberia. Operations for the pilot program are underway. We are evaluating data from the 2013 activity, which included a mix of workovers and new well drilling. The year 2014 will focus on drilling and testing new horizontal wells, with operations to commence by the third quarter. We are currently finalizing locations to test this high-potential resource. In Argentina, we drilled our first operated well and are currently drilling a second operated well in the Vaca Muerta shale formation. Previously, we have drilled a total of six Vaca Muerta wells with our co-venturers to progress the evaluation of our approximately 900,000 net acres. We have ongoing well operations to gather the production testing data required to validate expected recovery and to support potential development planning. Turning now to slide 18 and an update on our downstream investments, which continue to strengthen our global portfolio. During the quarter, we achieved several investment milestones. We commissioned a new diesel hydrotreater at our Singapore refinery, increasing ultra-low sulfur diesel production capacity by 62,000 barrels per day. The new unit, along with the recently completed petrochemical expansion project at our Singapore complex, positions ExxonMobil to competitively deliver high-value products to the growing Asia-Pacific region. We continue to extend our operating cost advantage by improving energy efficiency at our facilities. Worldwide cash operating costs for our portfolio of refineries are well below the industry average and consistently outperform the competition. in November, we commissioned our latest cogeneration facility at our Augusta refinery in Italy, increasing energy efficiency by 6%. To support market access for our growing Canadian oil sands production, we announced plans to build a crude oil rail loading facility next to the Strathcona refinery in Edmonton. The terminal will have a capacity of up to 250,000 barrels per day, of which we plan to use 100,000 barrels a day to supply our refining network. Connections to both Canadian National and Canadian Pacific mainlines will enable efficient, cost-effective transportation of heavy crude. Construction is underway, and startup is expected in early 2015. Now I would like to provide a summary of our full-year results, shown on slide 19. 2013 earnings were $32.6 billion, or $7.37 per share. The corporation distributed $25.9 billion to shareholders in 2013 through dividends and share purchases to reduce shares outstanding. Of that total, $15 billion was utilized to purchase shares. CapEx in 2013 was $42.5 billion and includes $4.3 billion for acquisitions. Base full-year CapEx of $38.2 billion was in line with our spending plans. Cash flow from operations and asset sales remains robust at $47.6 billion, which included $2.7 billion from asset sales. Moving now to the full-year cash flow statement, as shown on slide 20. During the year, cash decreased from $9.9 billion to $4.9 billion. The combined impact of earnings, depreciation expense, changes in working capital and other items, and our ongoing asset management program yielded $47.6 billion of cash flow from operations and asset sales. Uses included additions to property, plant, and equipment of $33.7 billion and shareholder distributions of $25.9 billion. Additional financing and investing activities increased cash by $7 billion. Moving on to slide 21 and a review of our full-year segmented results. 2013 earnings decreased by $12.3 billion. Lower net gains from divestments account for 70%, or $8.6 billion, of the reduced earnings. Lower earnings across all business segments were partially offset by reduced corporate and financing expenses. Turning now to the full-year comparison of upstream results and starting on slide 22. Upstream earnings were $26.8 billion, down $3.1 billion for 2012. Improved natural gas realizations, partially offset by lower crude oil realizations, increased earnings by $390 million. Unfavorable volume and mix effects, including the impact of crude underlifts in West Africa and lower natural gas production, decreased earnings by $910 million. All other items, including lower gains from asset sales, higher expenses driven by Kearl startup and operating costs, and higher planned exploration costs in Russia reduced earnings by $2.5 billion. Upstream after-tax earnings per barrel for the year were $18.03, excluding the impact of non-controlling interest volumes. Moving to slide 23. Volumes decreased by 1.5% or 64,000 oil equivalent barrels per day compared to 2012. Excluding the impacts of lower entitlement volumes, quotas, and divestments, production was essentially flat. Liquids production was up 17,000 barrels per day. Ramp up at the Kearl and Nigeria projects, lower downtime, and increased U.S. production were partly offset by field decline and divestment impacts. Natural gas production was down 486 million cubic feet per day. As expected, lower U.S. production, field decline in several areas, and full-year AKG entitlement impacts in Qatar were partly offset by increased weather-related demand in Europe and project ramp-ups. On slide 24, we show actual 2013 production volumes compared to the outlook we provided at the analyst meeting last March. Overall, total production volumes were in line with our target of 4.2 million oil equivalent barrels per day, with liquids production slightly below target and gas production slightly higher. Several positive factors contributed to this result, including strong uptime performance, increased North America unconventional liquids production, and higher European gas demand for the year. These factors mostly offset a lower-than-expected volume contribution from Kearl and the loss of Kashagan volumes due to the pipeline issue currently being investigated. During the fourth quarter, we continued to ramp up Kearl production, including making several upgrades to the steam system and filtration units to improve overall reliability. Average Kearl production for the fourth quarter and full year was 47,000 and 21,000 barrels per day respectively, and production rates of 100,000 barrels per day were reached by the end of the year. Full-year comparison for the downstream is shown on slide 25. 2013 earnings were $3.4 billion, down $9.7 billion from 2012. Lower refining margins across all regions reduced earnings by $2.9 billion. Volume and mix effects decreased earnings by $310 million, as higher planned maintenance activities in the U.S. and Europe was partly offset by refining optimization activities. Other items, including the absence of gains from the Japan restructuring and other divestments, reduced earnings a total of $6.6 billion. On slide 26, we show the full-year comparison for chemical results. 2013 earnings were $3.8 billion. Higher commodity margins, partly offset by lower specialty margins, increased earnings by $480 million. Volume and mix effects also increased earnings by $80 million, mainly due to strong U.S. commodity demand. Other effects reduced earnings by $630 million, mainly due to the absence of gains from the Japan restructuring. Moving to slide 27. In conclusion, in 2013, we earned $32.6 billion, generated $47.6 billion in cash flow from operations and asset sales, invested $42.5 billion in the business, and distributed $25.9 billion to our shareholders. ExxonMobil's strong financial and operating performance reflects the benefit of our integrated business model and other sustainable competitive advantages that create long-term shareholder value. We achieved total production in line with our target and continued to progress attractive opportunities across our unique and balanced portfolio. Base full-year CapEx spending was also in line with our plans. Our cash flow remains strong and enables robust shareholder distributions. Finally, I would like to mention two upcoming events. First, in mid-February, we will be releasing our 2013 reserves replacement data. Second, as many of you will already have seen, our upcoming analyst meeting will take place at the New York Stock Exchange on Wednesday, March 5. We will include a live webcast beginning at 9:00 A.M. Eastern, 8:00 A.M. Central Time. Presentation will be led by ExxonMobil's Chairman and CEO, Rex Tillerson. That concludes my prepared remarks. I would now be happy to take your questions. Thank you, Mr. Rosenthal. The question and answer session will be conducted electronically. If you would like to ask a question, please do so by pressing the star key followed by the digit one on your touch-tone telephone. We request that you limit your number of questions to two so that as many may have the opportunity to participate as possible. If you're using a speakerphone, please make sure your mute function is turned off to allow your signal to reach our equipment. We will proceed in the order that you signal us, and we'll take as many questions as time permits. Once again, please press star one on your touch-tone telephone to ask a question. Our first question comes from Doug Terreson with ISI Group. Good morning, David. Good morning. How are you? I'm doing fine. My question is about your European E&P, and specifically whether or not we could get clarification on the supply restriction at Groningen, meaning it seems like a 20% reduction in output is going to be required from the partners during the next three years, which I think equates to about 60,000 BOE per D, or BOE net to ExxonMobil. Is this the correct way to think about the supply effect and the duration of the restriction? Any color on that situation would be appreciated. Yeah, Doug, I'd be happy to give you a little perspective on the Groningen situation. Let me start by saying that the government's draft decision does include a production decrease for the next three years of about 7% compared to average production over the average of the last few years. Okay. If this offtake limit is final, it would have an impact of approximately on ExxonMobil, 100 Mcf a day net production in 2014 versus the average of the last several years. Compared to 2013, which as I mentioned, was a year of very high production due to weather-related demand, there would be a decrease of about 20%, and that's consistent with what was communicated by the Dutch government. The proposed curtailment is not final. It'll take a little bit of time to finalize it. But if implemented again, the impact on us relative to a normal year is about 100 Mcf a day. Oh, okay. And I think the- Yep, sorry, go ahead. I am sorry. Let me just make one other comment- Yep to keep it in perspective and add a little color. In terms of the financial impact on the company, while Groningen is of course a very attractive asset in our upstream, the unit profitability is in the bottom half of our portfolio. So the earnings impact is not as great as I think some people might have expected. Okay, good point. Then just second, in the U.S. downstream, obviously, you guys have a leading position in the Mid-Continent, and it's really benefited from wide differentials over the last couple of years. But I wanted to see if we could get an update on the program to secure advantage feedstock via rail cars or what have you for the refineries outside the MidCon. Any elaboration on this is appreciated. I think you guys talked about it a little bit for the Gulf Coast at the analyst meeting. Just an update there would be appreciated. Yeah, sure. In general, if you look at our MidCon footprint, which as we talked about before, is one of the largest in the industry, and our Gulf Coast refining footprint is also one of the largest. We've got a lot going on in terms of making sure that we can get the Western Canadian crudes down into the circuit, and also take advantage of the light sweet crudes. We are pipeline, rail, barge. We're using all of the logistics opportunities available to us to optimize those barrels getting the refineries. That's a big piece of what you see in these positive volume mix effects on our earnings both quarter-to-quarter sequentially, and that sort of thing. Particularly if you look at that sequential comparison where we've really been able to optimize the feed slate we're running and of course, take advantage of butane pricing as we switch over to winter-grade fuels. That's been helpful to us as well. But we are actively and the fourth quarter was a good one for us. I might just mention one of the things that makes that important in the earnings comparison, we did have in the fourth quarter alone about $250 million of negative price timing effects. So that hurt on the margin side gets somewhat offset by some of these refining optimization efforts that we talked about. We continue to work on that. One of the things that helps is being fully integrated across the downstream, upstream, and chemical, and having a worldwide supply department to help us on this. But you can rest assured from Canada all the way down to the Gulf Coast, we are fully optimizing and taking advantage of our integration opportunities. Great. Thanks a lot. Our next question comes from Evan Calio with Morgan Stanley. Hey. Good morning, David. Morning, Evan. Yeah. First question on the production volumes. I guess from your comments, I can disaggregate the impact from Kearl and Kashagan in the fourth quarter. Can you provide any outlook into 2014 on Kearl? What is the ramp, and more color there? On Kashagan, which you mentioned, is there any prognosis for the production return and the state of the gas leak repairs? I have a follow-up. Thanks. Sure. Let me start with Kearl. I cannot give you an exact time of when we would expect to reach our full production capabilities. I will say although the Kearl volumes did come in over the course of the year, as I mentioned, less than our expectation going in, and certainly a part of the volume outlook we shared with you last March. We did achieve a number of milestones in cranking that project up. We have been able to run each of the three froth treatment trains at their max capacity. On a combined basis, we have been able to reach rates at 100,000 barrels per day. What we are working on now is how do we improve the reliability so that we can run at those rates on a consistent basis, and we continue to make progress there. Again, I think as I have mentioned in prior calls, the good news for us is all the technology is working, the trains work, the equipment works. It is simply been just a matter of startup and this complex kit we got on the ground and working some of these reliability issues that I mentioned. But they are all fixable. We are working on it. We are making progress. But I would not want to give you an exact date in terms of full capacity, but we will give you an update at the analyst meeting in March and probably be in a better position to help you with some outlook on that. With regard to Kashagan, as you know, oil and gas production does remain shut in. We are investigating. We have got the best experts in the world looking at this. We are investigating the root cause of the pipeline leaks, and the seeps. That is going to take a little more time. We do know that the immediate cause of the leaks has been sulfide stress cracking. But we're still investigating to establish what's the cause of the sulfide stress cracking, and that is ongoing. There's a lot of work going on, a lot of analysis underway. But I just couldn't give you an outlook. I know there's some speculation out there at various times, but I'd be hesitant to try to give you an outlook until we know more about both the cause and extent of the leaks and therefore, what it's going to take to repair them and get that equipment back in service. Okay. That's helpful. Then my second question also relates to production and 2014 production. Thank you for the color on Groningen. I guess there, is there any ability to offset volumes from other European fields as it's largely a demand-driven market? Then secondly, in another area which has been very profitable, and a marquee investment for Exxon and Qatar LNG, any color there on the relative contribution as you move through various contract thresholds in those contracts would be helpful. Thanks. Yeah. Let me start off with Groningen. As you know, it is the swing field in Europe. and tends to take the balance of what's needed, depending on weather, typically, unless there's some supply disruption. So that's really what drives the production there year to year, more so than capacity. In terms of ability to offset, we're already working everything we got. As you know, Continental Europe conventional gas is on decline. North Sea gas is on decline. We do feed LNG into that circuit out of the Middle East. It has to compete with prices that you can get in Asia Pacific. We will be looking to optimize that. But again, under normal circumstances, loss of about 100 Mcf. We will be looking to optimize around that to the best we can. If you are talking about Qatar, I think the one thing to keep in mind is other than the AKG project, all the rest of the trains are joint ventures. They are not PSCs, so they do not react the same way that PSCs do. They do all have unique fiscal terms associated with them. But I can tell you as time goes on, we do not see any significant impact on the earnings contribution, anything that would be material. So, we continue to remain focused on keeping that equipment up and running. We had a terrific year on uptime and reliability. That enabled us to take advantage of some very strong margins that are available prices, particularly in the Asia Pac. So it continues to be a terrific investment for us. Great, David. Thanks for my questions. Our next question comes from Doug Leggate with Bank of America Merrill Lynch. Thanks. Good morning, David. Good morning, Doug. Hi, I have a couple questions also, if I may. The first one is on the long life nature of some of your assets. It just occurs to me that when we talk, obviously, you haven't given a reserve replacement number for the year yet, but as your portfolio shifts towards the likes of Qatar and the likes of Kashagan and so on, Kearl, all these very long life assets, what is the determination internally about the need for reserve replacement to be at or above 100% when you have such a huge piece of your portfolio that doesn't decline on a multi-decade basis? And I've got a follow-up, please. I'm thinking really about capital intensity of the overall portfolio. Yeah. Let me hit the capital intensity first, and I'll use that to back end to your original question. We have been in a very capital-intensive mode in the upstream over the last few years as we recapitalize and invest in a number of these big projects. Some you mentioned coming out of Qatar LNG, and into Kearl, Papua New Guinea LNG, Gorgon LNG, the Kashagan, of course. You have seen a wrap-up in CapEx on these long life projects. As we talked about in the March analyst meeting last year, we do have an expectation of rolling that upstream CapEx over a little bit as we go forward, and we'll give you an update on that in March, but we continue to progress that. In terms of having a target of 100% reserve replacement, we don't really have a target. In other words, we're not going to go out and do things that are not optimal just to achieve 100% replacement target. You know the company and the organization well. We span the world looking for good opportunities, good resources to get access to, and if they're commercial, we'll put the investment capital and human capital in there to develop them. We have been fortunate over the last many years that the summation of all this effort has achieved 100% or greater than 100% reserves replacement. But I am glad you asked the question because I do want everyone to know that we do not go and spend the shareholders' money to reach any kind of target, like a reserves replacement. It's the outcome of our very disciplined analytical process, and again, making sure that the CapEx is being spent in those areas that have the best opportunity to generate long-term value for the shareholder. I think the last thing I'll mention, Doug, as we look around the world and you look at our exploration portfolio, one of the things that's really nice today is our ability to be selective amongst that portfolio and pick and choose those opportunities that we want to go after and do the most attractive ones, and the reserve adds will be the fallout of that. But thanks for asking the question. Sure. My follow-up, David, very quickly is on the Middle East again. It's specific to the ADCO concession. I know it's fixed margin and relatively low in the grand scheme of things, but can you just frame for us what the situation is with that contract? I believe it expired on January 1. Whether or not you have any chance of recouping that at some point, and I'll leave it there. Thanks. Yeah. The Abu Dhabi onshore concession expired on January 10th of this year. We did have a 9.5% interest in that. That worked out to about 140,000 barrels a day of production. We are no longer in that concession. I will tell you mentioned fixed margin contracts. While it was 140,000 barrels of production, the unit profitability of that was down at the lower end of our spectrum of profitable barrels. So that's the status on the onshore. I really couldn't comment on any discussions, opportunities, forward-looking thoughts other than to give you a status of where we are today. All right. Thanks, David. Thank you. Our next question comes from Ed Westlake with Credit Suisse. Hey, good morning, David. Morning, Ed. Seems we're all fishing for your slides in March on the production volumes, so why not fish again? Just very quickly, the reduction in the West Qurna stake, how much did you include longer term in the slide that you put up each year in terms of the new projects for West Qurna? Do you know? Yeah. What I can tell you is when we put up that slide in March of every year, and it's important to know this, we do it on an apples to apples basis. So we assume the status quo and the same as prior year prices. So it allows you folks to get a look at what we would be status quo. No assessments every March in terms of acquisitions, divestments, contract expiries, and all those sort of things. Last year, we would've had an assumption of the status quo in the outlook. I can tell you that the way the contracts work, we don't book a lot of barrels in that area, and so the reduction will not be significant. I don't have a specific number for you other than to tell you it won't be significant in the overall context of our production. Okay, and then just trying to shift the conversation on, can you talk a little bit about where you are in terms of oily rig count again in North America, some of your plans? Obviously, the industry's announced some success in the Duvernay. You've got some good acreage in the Woodford and the core of the Bakken and the Permian. Just a quick update on where you are in the oily drilling in North America. Thanks. Sure. As you can tell by the sequential quarter-to-quarter-to-quarter sustained increase in U.S. liquids volumes, we have been really orienting our rigs towards the more liquid areas. Biggest places for us, the Bakken, the Permian, and the Woodford Ardmore. Most all of our rigs are running in those areas. We continue to ramp up. We're adding rigs in the Permian, for example, both for conventional liquids as well as testing some of the unconventional. We are drilling in the Montney and the Duvernay, as you suggested, and increasing activity there, as well as in the Bakken. If you look at the rigs we're running today, it's not 100%, but it's probably 85% or so of all of our rigs are working in liquids-focused plays. Thus, you've seen that significant increase in production. We're bringing a lot of wells onto sales every quarter and continue to ramp that up. We're testing new areas, new zones in these plays. The Marietta and the Ardmore, for example, looks very promising to us. We'll be getting more wells down there. The Wolfcamp out in the Permian and a number of those plays. So we're very pleased with the acreage we've been able to acquire and get into and ramping up pretty dramatically. If you look at a number of these things that are occurring over the years, over this year, a lot of it gets back to the commentary we made at the analyst meeting about working on improving unit profitability, and you do that by limiting or reducing your exposure to low profit barrels, working on fiscal terms where you can, and putting your human and financial capabilities in those areas that generate above average incremental profitability. We've been executing those efforts this year, and we'll give you a better update at the March analyst meeting on the extent of that program. Thank you. Our next question comes from Paul Cheng with Barclays. Hey, David. Good morning. Good morning, Paul. How are you? Very good. Sorry to beat that horse too much. If I look at your last year presentation in the analyst meeting on the production profile, can you tell us that for 2014, 2015, roughly, how much is building into that particular profile you share from the field Kashagan from the Abu Dhabi onshore contract and also Groningen? Yeah, I do not have a specific number for Kashagan. Abu Dhabi would have been something in the neighborhood of the 140,000 barrels a day I mentioned, and Groningen would have been whatever the equivalent would have been, again, for an average year. I think the important thing to think about is the difference would be what we have mentioned today for both Groningen and the onshore. Again we will be giving you a full update on our outlook that will incorporate those changes and many others that we have heading into 2014 when we get together in March. Okay. Second question. When I am looking at Imperial in the fourth quarter, they report downstream earning of CAD 625 million. So if you adjust for your working interest and the foreign currency, it would suggest that your share of their downstream earning is about CAD 417 million. Meanwhile your lone U.S. downstream only report $319 million. Does that mean that outside Canada, the rest of your global downstream operation actually lost about $100 million, or that is some different other accounting adjustment that we were not aware of? Yeah, let me give you a little perspective on that. First of all as I mentioned a few minutes ago, one of the issues we did see in the quarter was price timing effects about $250 million negative in the U.S., and that impacted those earnings. We do see weakness in our European and Asia Pacific businesses out there. Margins are weak. The economy is a bit sluggish. So both on the refining and the chemical side you are not seeing an earnings contribution there that you would see in an up cycle because as I have said before, we are at bottom of cycle margins. We also had in the fourth quarter a higher turnaround and maintenance load in Europe. Our Antwerp refinery, for example, had a major turnaround. So you are looking at some volume impacts there. Clearly we're optimizing the European and Asia Pacific footprint as best we can with the integration between refining chemicals and lubes. Those are weak markets compared to the U.S. and Canada without question. Can I just sneak in a one real quick one? Sure. For the quarter, you have a cash proceed from asset sales of $1.8 billion. Can you tell us what is the asset sales gain in the quarter and breakdown by segment? Sure. If you look at the first of all, the proceeds from asset sales, we had a number of asset sales in the quarter. I mentioned our partial sell down in Iraq. We had a number of sales in the U.S. and in Canada. Additional service stations as we continue to progress that effort. We booked the films divestment on the chemical side. A number of things contributed to that $1.8 billion. In terms of an earnings contribution in the fourth quarter that total was about $1 billion all in in the quarter across all the businesses, and that compared to about $400 million in the fourth quarter of last year. Dave, do you have a breakdown by segment on that $1 billion? Sure. If you look in the upstream, right about $775 million, in the downstream about $225 million order magnitude. Thank you. Those are absolute numbers. Our next question comes from Blake Fernandez with Howard Weil. Hi, David. Good morning. Thanks for taking the question. I could not help but ask a question on natural gas here, given the recent spike that we have seen. I know the volumes for Exxon have been progressively in decline due to the activity, but I am just curious, is there a certain pricing level where you may get interested in re-engaging in activity? I guess tied in with that, I know historically the company does not hedge, but with the recent move we have seen, is that an opportunity to maybe lock in some economics and get more active? Well, I will hit the last one first and then back up. No, we do not hedge oil and gas prices, and I would not expect that to change here. In terms of natural gas pricing, you have seen some firming here in the last several weeks. We have had a very cold winter in the U.S., and the demand for gas in the power gen and heating has been very strong. We have seen a fluctuation on the upside for that. But we do not change our activity levels and investment plans to any significant extent on short-term price movements in the commodities. We do have tremendous flexibility in our operations. I think our drill well inventory here in the U.S. is about 50,000 wells, so we certainly have the capability to move our activity around. But again, we do not typically move dramatically one way or another on a short-term price spike or decline. But do acknowledge that we have seen some price uptick here recently. Okay, fair enough. The second question is on Tanzania. Obviously, you've had some really good success there, and from what I gather, it looks like sufficient resources to probably move forward with the development. I am curious, can you give us an idea of maybe timing on potential FID and maybe what additional resources you may need to move forward? Sure. First of all, it all starts with that resource, and we have found a very high-quality gas resource out there with the wells that we've drilled so far. I think I mentioned earlier, 17 TCF to 20 TCF gas in place. I think one of the things that's encouraging is we still have several more prospects on that block that haven't been drilled yet, and so we are continuing to drill. We will drill some more this year. We will be doing some appraisal drilling and some more wildcat exploration activity. That continues to go very well. In terms of forward planning, we are in the early stages of planning for the development of that block, working on things like site selection. You're probably aware that us and our partner, Statoil, have worked with BG and Ophir to complete an evaluation of potential sites for a common onshore LNG plant. We have made a recommendation to the government in Tanzania regarding that. The next step as you progress would be moving into early FEED to see what you have there. It is a little too early to be talking about any potential FID date at this time. Clearly, as we always do, if you have what looks to be an excellent resource, you put the human capital on it and get to thinking about development and optimization, and I can assure you that process is well underway. We will probably be able to give a little better update in March as well on that opportunity. For now, I would just say we're moving right along and very pleased with this world-class discovery that we've made. Thanks, David. Our next question comes from Arjun Murti with Goldman Sachs. Thanks. David, just a couple follow-ups. Just first on the natural gas point, fully appreciate Exxon classically does not adjust to the short-term price swings. Is it reasonable to think the mid-single-digit declines you've had will continue for the next several years? Or as you've assessed the XTO and your own resource base between the Marcellus and Woodford and some of these other areas, do you see greater confidence in the cost and the resources that the decline rates might be lower or different than what you've done, say, over the last year and a half? Yeah, that's a multi-part question, and both of those can be independent or work together. Certainly, we have continued to make good progress in terms of productivity, well rates, down spacing, optimizing our completions and drilling. We've been able to make the progress we always thought we would when we acquired XTO and combined their folks with our folks and looking at some of these things. That continues to improve. It's hard to give an overall decline curve because as you know, a lot of time that depends on well work activity and workovers and various other things, and a lot of that'll be driven by the activity levels, which of course are dependent on longer term price outlooks. I think from our perspective with the resources there, the opportunities are there. We know all these plays. We know how to produce more gas. When the market needs the gas, we'll provide it. It's a market-driven activity, and the outcome in terms of production and reserves and decline will be based on the outcome of those activities as opposed to any target that we might set. But we can adjust quickly. We do have the capability to adjust quickly if the market needs the gas. That's great. An unrelated follow-up. You mentioned the partial sell-down in West Qurna in Iraq to 25%. I think a few years ago, you'd also bought some acreage in Kurdistan. Can you provide any update on your activities there? I think there'd been some question, at least at the time, as to whether you could pursue activities in Southern Iraq and Kurdistan. Any thoughts on what you're doing in Kurdistan would be helpful. Sure. If you look at the Kurdistan region in northern Iraq, I can tell you that we continue to progress all six of the PSC contracts we have there and meet our commitments. Specifically, we do have drilling operations underway in one of our blocks, and that drilling is ongoing. I don't have any report out for you yet, but those operations are underway. We continue to do seismic and other operations on our other blocks in preparation for drilling there. I think in summary, across Iraq, of all of our contracts in the north and the south, we continue to meet our commitments, and we continue to progress our operations in all of the areas. I'm pleased to say that all of them are progressing per the plan and doing quite well. That's great. Thank you so much. Our next question comes from Asit Sen with Cowen and Company. Thank you. Good morning, David. Morning, Asit. How are you? Good. Two quick questions. First, on asset sales. Looks like the $1.8 billion in the fourth quarter did not include a portion of Hong Kong Power. Could you update us on the Hong Kong Power sale? Yeah, sure. You're right, that 1.8 did not include any proceeds from the Hong Kong Power sale. As you are aware, we have reached agreements to divest our interest in those facilities. Those approval efforts are ongoing, but it's not closed, and it won't close for a little while. But the process is moving along, and we would expect to close that deal sometime later this year. Okay. The second one is on PNG LNG. It is very unusual to see a big LNG project coming on ahead of schedule. My question is, what sort of volumetric contribution do we expect in Q4 in the ramp-up phase? Yeah, I might just add to your comment about how unusual it is to see one of these mega projects stay on schedule. I will also note that we are still on budget, and we have not increased the cost outlook on that project since the outlook we gave over a year ago. So we are on or ahead of schedule and on budget. I do not have a specific volume outlook for you for the fourth quarter. It is all going to depend on how we get this thing ramped up. As I mentioned earlier, I think we have been saying we would have first deliveries in the second half, and now we have moved that up a little more concrete to the third quarter. As we progress commissioning, we will be in a better position here in March to maybe give you a little better update in terms of what to expect. Everything is working well, the drilling, all the commissioning, feeding the gas, the equipment, and that is why we were able to give a more specific target of the third quarter. We will look forward to giving you a better update here in a month or so. Thanks. Our next question comes from Faisal Khan with Citi. Thank you, and good morning, David. Morning, Faisal. Just I wanted to clarify the gain on the asset sale, the billion dollars you said, was that for the year or for the quarter? Yeah, thanks for that follow-up, so that we can be clear. The absolute gain in the fourth quarter was $1 billion, and that compares with a gain of about $600 million in the fourth quarter of last year. So we've had a change of a positive $400 million. Okay. Understood. Thank you. Just on exploration expense, it's sort of been elevated for the last three quarters. I understand some of that is coming out of Russia. Can you give us an idea of how this number is supposed to trend? Because you've gone from roughly $450 million to over $700 million a quarter, so it's tending to have an outsized effect on some of your expenses. Any sort of clarification or sort of guidance in terms of where that should be would be helpful. Well, the biggest driver of the exploration expense, as you noted, has been our pickup in activity in Russia, and it's in all areas. We're talking about all the work that we did this summer in the Kara Sea, the seismic we've been running, the efforts we have in West Siberia, as well as across the Black Sea, northern Black Sea, and then over in Russia. So we have had a lot of exploration activity in support of what is going to be a very robust drilling program this year and next year in a number of these areas. So that is ongoing. It's nothing that we hadn't planned or expected as we came into this year and looked forward to this year. But I don't have an outlook in terms of a forward look. Again, that is one of those areas we will talk a little bit more about in March. Dry hole expense has been low this past year, so it had not been a big contributor to that. It has been just a lot of work identifying those drillable prospects and preparing for, again, an active drilling campaign. Thank you, David. Appreciate the time. Our next question comes from Allen Good with Morningstar. Good morning, David. Hello, Allen. I wonder if I could just press you maybe for a bit more details on the Western Siberia and tight oil campaign, whether it be maybe rig counts or planned wells for 2014, and maybe even what you anticipate a production exit rate in 2014 might be. Sure, I would be happy to give you an update. We have got a lot of activity going on, a lot of geotechnical work, seismic work. As I mentioned in the last quarter call, we did have a lot of effort in terms of entering some old well bores and doing some other activity in the fourth quarter of last year. As we head into this year, now is the time to move on to a drilling program where we would drill some horizontal wells and see how we can get various areas to produce. One of the things that is really important for us with the size of our acreage position is to make sure we understand where we are in the play, what are the most prospective areas. That takes a lot of analysis, so you do not waste a lot of money drilling wells. We got a lot of expertise in this area that we acquired from XTO. We are bringing that to full bear, along with some of our own technology that we have. We are looking forward to getting some more wells down this year, testing the production capability of some of these areas. It would certainly be premature to give any indication of thinking about exit rates or production rates because we are early on in this analysis. Again, it is a very huge resource opportunity in front of us, and it certainly behooves us to take our time and go about this in a disciplined manner so that we do not waste a lot of money while at the same time finding out what this very exciting play is capable of doing. This will be a big year for us. Okay, thanks for that. Then I know you do not give guidance on asset sales or what you may be marketing, but earlier this week, I guess one of your peers came out and indicated that he is willing to sell a pipeline asset they own here in the U.S. I was just wondering, presumably you are sitting on a lot of midstream assets that may not necessarily receive the value that they would in a market being incorporated within Exxon, given the level of disclosure and the size of your business. Is there any interest, and I know MLP may be able to question, but any interest in potentially trying to monetize some of these midstream assets you have? Or do you think you just have more value ultimately through operating them and then maybe integrating your operations as opposed to selling them? Yeah. It is interesting, if you look back over the last couple of years, so 2011 and 2012, we actually did divest a fairly significant chunk of those midstream assets that we had, not only in the U.S. but elsewhere. That was a portion of those large asset sale gains that we had and cash flows in those two years. I cannot give any specific outlook or asset, but as you would expect, we are continuously looking at all of our assets, including our midstream assets, what those values are to us internally and what they might be on the market. We test the market occasionally with some of these. Again, they are not sitting there not getting looked at and evaluated. But it is all part of a program to look at the entire logistics footprint that we have. I mentioned the Edmonton rail facility we are building. Where it is optimal for us, we will add midstream facilities. Where some midstream assets that we have are worth more to somebody else than they are to us, then we will divest them. Again, no specific outlook or assets, but we are continuously looking at that entire portfolio. Okay, great. Thanks. Our next question comes from Roger Read with Wells Fargo. Yeah, good morning. Morning. I guess just to follow up a little bit on the chemicals business, I know there have been a few questions on it already, but I just wanted to understand the changes you saw in the fourth quarter. Exxon wasn't particularly unique. We definitely saw a greater competition out there. As we look forward into 2014, what's going on in terms of new competition, pricing, and all that? Let us know how you fall into that or how you would expect 2014 to unfold on the chemical side. Yeah. As I have on a number of other questions, I can't give an outlook today on any kind of financial parameters for the business. One of the things we've seen recently, first of all, we'll start here in the U.S. We continue to take advantage of a very good market there. Demand has picked up a little bit, and of course, gas cracking is also a very attractive business for us. We have been fortunate in that we've been able to run our facilities along the Gulf Coast flat out here over the last quarter and therefore make the production we need to meet the market demand. So those margins in the U.S. remain healthy. Demand pick up a little bit. Export opportunities also very attractive, and we're maximizing all that. On the other side of the planet, margins continue to be quite weak in the Asia Pacific area. We did have some capacity come on last year, and as typical in our business, there's never a perfect match between capacity additions and demand growth. Demand growth tends to be out there for a while, and people put on the facilities, and they tend to come in chunks. For a while you'll have supply outstripping demand, and we've seen that in a number of areas, a number of products, particularly in the Asia Pac area. Those have a tendency to balance themselves out over time. We are also seeing some demand pickup in China and the rest of the Asia Pac area, and that is helpful. I mentioned the specialties business. We have seen some weakness there, particularly in Europe, again both from the economic situation there as well as additional industry capacity that's come on. So I'd characterize it as normal cyclical business for the chemical industry across many years. You've got the U.S. at top of cycle business conditions today, and Europe and Asia Pac at bottom of cycle. That's why we have over time invested in each of these places where we can bring some technology or get a feed slate advantage or a logistics advantage in order to be able to supply all of those reasons through the business cycle. But most importantly, be able to take advantage when you get an upside, and we're certainly well positioned to do that with our facilities. Combine that with the level of integration we have, and if you look overall, it is a tough market, but we did make almost $4 billion this year in that business, and that's pretty strong performance. Fully agreed. Thanks. The unrelated question, you mentioned in the press release the LNG for Alaska. I was just curious, is there anything you can do to help us understand more conventional business on North Slope crude in Alaska? You had the tax change that the government put through up there. We've seen some indications that the other participants in Alaska are getting a little more active. I just wondered how does Exxon participate in that? Is it basically along with the others? So maybe there is a little bit of growth coming from Alaska in the near future, or if you're waiting for something larger like the more offshore drilling that looks like it continues to slip out to the future. Well, what we have seen across the business up there is pretty much what you would expect. Lower taxes have led folks to take another look at their investment opportunities, and investments that were not viable under the old regime could very well be viable under the new regime. You have seen some activity up there. As you know, we are a large participant owner in Prudhoe Bay. We are not the operator. But any of the growth that you see there and some of the projects and activity increase that you have seen announced and underway in Prudhoe Bay up on the North Slope, we would participate in. Everybody up there is looking at that, and it is still a very key resource for us. As opportunities become attractive, of course with our partners we would be willing to invest in that. I think that is pretty straightforward on the North Slope. If you look at the Alaska LNG opportunity for us, as you know it is one of many opportunities we are looking at across the globe for LNG. We did, as you read in the press, have a heads of agreement here recently, another very positive milestone. It sets guiding principles, terms, and conditions to progress the work on the project. We are continuing to progress that. After a long evaluation process looking at locations, we have identified an industrial site near Nikiski as a lead site for the potential plant and terminal. We are looking at other sites, but I think the message is that is potentially a very large, very complex project. All of the stakeholders are progressing the analysis and looking at that project in due course, and we are of course a big part of that. Thank you. Our next question comes from Robert Kessler with Tudor, Pickering, Holt & Company. Hi, good morning. I see you've finalized the Canadian rail terminal project plans. Can you tell us what the total CapEx will be for that 250,000 barrel a day facility? How do you think about it more strategically? I know, at least to me, Exxon seems more like a vertical integration player where you see an opportunity in your downstream and you set up a midstream opportunity here to really integrate. Others seem to be using rail as more of an optionality. If the spreads get to a certain distance and other transport routes are not available, you use them opportunistically. Can you tell me how you're thinking about the expected utilization rates at that facility? Is it more of a base run near 100% or are you leaving it out there as an option? Let me hit the first part of your question first. We would expect the all-in capital cost for that JV to be somewhere in the neighborhood of $200 million-$250 million, and that's a 50/50 joint venture. So we've got about half of that. The terminal will have the max capacity could be upwards of 250,000 barrels a day. Out of that, we're looking at utilizing initially about 100,000 barrels a day to move our expanded production into the market. With the growing production of Western Canadian crudes, both heavy crudes and oil sands, it's prudent to be working on all of the logistics opportunities so that you do get a lot of optionality as you mentioned, but also the flexibility to be able to better pinpoint the destination of some of your crudes as various regional opportunities present themselves. We're taking full advantage of all the pipeline opportunities that are out there and working on that. Other modes of transportation by water are also being utilized. Then again, as is prudent, we're looking at the rail car option. It's all about optionality, flexibility, and being able to take advantage of spreads and opportunities to maximize the overall value. We've been working on that for quite a while. The other thing, having the flexibility on the transportation piece is it really helps us on both the integration with our own refining circuit, as well as having the opportunity and viability to make third-party sales. The more options you have and the more flexibility you have, the better off you are to divert production to areas different than what you might have originally planned. We're taking all of that into consideration. Makes sense. Thanks for the clarification. Our next question comes from Pavel Molchanov with Raymond James. Hey, guys. Just one from me, and this is a high-level question. On the day that the Senate Energy Committee is debating crude oil export policy, I know that Exxon's perspective on this is going to be closely watched. So any thoughts on the issue and where the company stands? Sure. I'd be happy to talk about that. It's a topical subject. First of all, our response is principle based, as you would probably guess. As a company, we fully support free markets, free trade. We oppose any barriers or restrictions to free trade and open investment across the value chain in the energy sector. Over time, I think it's pretty clear that barriers to free trade can actually lead to higher prices, dampen economic growth and prosperity. In this case, could potentially harm energy security by limiting the diversity of supplies. Trade is good. Free trade is the best way to maximize the economic value of any enterprise, including the oil and gas enterprise. Generates the most jobs, generates the most revenue to the taxing authorities. Across the business that's what we support, and we would not advocate putting any restrictions at any point along a manufacturing value chain even if it might benefit some part of our business. In addition to crude oil, we strongly support unrestricted LNG exports even though we are a very large petrochemical company and consume a lot of petrochemical feedstock. The bottom line, big supporters of free markets and free trade, level playing field for all competitors, and then let the market do what it does best. All right. Appreciate it, guys. Our next question comes from Biraj Borkhataria with RBC. Hi, David. Thanks for taking my question. Yeah. I have two, if I may. Firstly on LNG, you touched on it a couple of times on the call. I wondered if you could talk through your options to expand in this growth area outside of Tanzania and PNG. Secondly, I wonder if you could talk a little bit about your thought process when setting dividends. You obviously have a very strong balance sheet and the highest returns in the industry and you could afford a significantly higher dividend. So I was wondering if you could talk a little bit about that. Sure. Let me start with LNG because we are very pleased to have a broad opportunity set in front of us. In addition to Papua New Guinea, Australia, and Tanzania, as you mentioned, we have a very attractive opportunity in the U.S. Gulf Coast where we already have a very large regas facility. A lot of that investment is already on the ground. And we have an opportunity to add liquefaction capacity there. One of the things that makes our project unique is we also have regas capacity available in Europe from some investments that we made in prior years. We have the opportunity to simply add liquefaction capacity on the front end and then export that LNG and take advantage of a number of opportunities, not the least of which is capacity we have to regasify in Europe. We have received a permit for free trade agreement countries, and we have had a permit application in for some time for non-free trade agreements, and that continues to be a nice opportunity. We also are looking at the possibility or viability of LNG exports out of British Columbia in Canada. We have a very large resource base in Western Canada of natural gas, and we do have efforts underway and are progressing. In fact, we just received a permit approval for a potential up to 30 MTA facility in Western Canada, and we are working on site selection and other things there. And then, of course, Alaska, which we just mentioned a minute ago. Huge resource, great opportunity, but again, like the other projects, very high capital cost, very complex. It will be extremely important to have attractive, stable fiscal terms, as it is in any area. But that is also an opportunity for us. Again, it is all about having a broad, balanced portfolio of opportunities so that you can select those that are the most attractive. But you do not find yourself in a position where you have to do something that is not attractive, and our LNG opportunity set certainly fits that case. In terms of dividends, we have been pretty briskly increasing the dividend over the last few years. We had a fairly significant dividend increase, I think it is about 20% or so in 2012. Another 11% increase this past year. And it extends a very long period of time that we have been increasing dividends. So I think we have been responsive in that area. In terms of going forward, I would not expect any change to our overall philosophy with regards to the dividend. We do expect to pay a consistent dividend that grows over time, and obviously, we are able to do that given the strong cash flows the business generates and our strong financial capacity. So, do not have any outlook or guidance or anything other than to say that I would expect our philosophy going forward to be the same as it has been historically. Perfect. Thank you. Thank you very much. It appears there are no further questions at this time. Mr. David Rosenthal, I would like to turn the conference back to you for any additional or closing remarks. Okay. I would simply like to thank everybody for their participation on the call. I appreciate your questions today. Very important to our business, and look forward to seeing everyone here in a few weeks at the analyst meeting in March. Thank you very much. This concludes today's conference. Thank you for your participation.