Earnings Call: Q4 2014

Feb 2, 2015

Summary

2014 earnings were $32.5B, with $18B of free cash flow and production on plan at 4M boe/day. Q4 earnings faced sharp oil-price pressure, partly offset by higher chemical earnings and favorable non-cash tax and arbitration items.

Good day, everyone, and welcome to this Exxon Mobil Corporation fourth quarter 2014 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. Jeff Woodbury. Please go ahead, sir. Thank you. Ladies and gentlemen, good morning, and welcome to Exxon Mobil's fourth quarter earnings call. As you know, the focus of this call is Exxon Mobil's financial and operating results for the fourth quarter and the full year 2014. I 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 from our fourth quarter and full year performance. Exxon Mobil delivered earnings of $32.5 billion in 2014, and fourth quarter earnings of $6.6 billion. These results highlight the value of Exxon Mobil's integrated business model, which enables us to produce solid financial performance throughout the commodity price cycle. Corporation generated cash flow from operations and asset sales of over $49 billion in 2014, and free cash flow of $18 billion, an increase of over $7 billion from 2013. We completed a record of eight major upstream projects during the year, and achieved our full year plan to produce 4 million oil equivalent barrels per day. Moving to slide 4, we provide an overview of some of the external factors impacting our results. Global economic growth moderated in the fourth quarter. Expansion in the U.S. continued, but growth slowed relative to the third quarter. China's economy decelerated, while Europe and Japan showed continued signs of economic weakness. As you know, energy prices declined sharply in the fourth quarter, and U.S. refining margins decreased significantly, while chemical specialty product margins improved on lower feed and energy costs. Turning now to the fourth quarter financial results, as shown on slide 5. Exxon Mobil's fourth quarter earnings were $6.6 billion, or $1.56 per share. Corporation distributed $5.9 billion to shareholders in the quarter through dividends and share purchases to reduce shares outstanding. Of that total, $3 billion were used to purchase shares. CapEx was $10.5 billion in the fourth quarter, whereas cash flow from operations and asset sales was $7.7 billion. At the end of the quarter, cash totaled $4.7 billion, and debt was $29.1 billion. The next slide provides additional detail on fourth quarter sources and uses of funds. Over the quarter, cash decreased from $5 billion to $4.7 billion. Earnings, depreciation expense, changes in working capital and other items in our ongoing asset management program yielded $7.7 billion of cash flow from operations and asset sales. Uses included net investments in the business of $9.1 billion and shareholder distributions of $5.9 billion. Debt and other financing increased cash by $7 billion. Share purchases to reduce shares outstanding are expected to be $1 billion in the first quarter of 2015. Moving now to slide seven for a review of our segmented results. Exxon Mobil's fourth quarter earnings of $6.6 billion were $1.8 billion lower than the year-ago quarter. Lower earnings in the upstream and downstream and higher corporate expenses were partly offset by higher chemical earnings. Results were favorably impacted by approximately $1 billion of non-cash effects that included U.S. deferred income tax items and the recognition of the 2012 award by the International Chamber of Commerce for expropriated Venezuela assets. In the sequential quarter comparison, shown on slide eight, earnings decreased by $1.5 billion, primarily as a result of lower upstream and downstream earnings. Guidance for corporate and financing expenses remains at $500 million-$700 million per quarter. Turning now to the upstream financial and operating results, starting on slide nine. Upstream earnings in the fourth quarter were $5.5 billion, down $1.3 billion from the fourth quarter of 2013. Realizations decreased earnings by $2.4 billion, as worldwide crude oil prices declined almost $32 per barrel. Notably, favorable sales mix effects increased earnings $400 million, driven by higher margin production growth from the U.S. and major projects in Canada, Angola, and Papua New Guinea. All other items increased earnings by a net $640 million, including adjustments to deferred income tax balances in recognition of the gain from the Venezuela ICC award received in 2012. The ICC award was recognized given the favorable fourth quarter ruling of the International Centre for Settlement of Investment Disputes. Moving to slide 10. Excluding the impact of the Abu Dhabi onshore concession expiry, oil equivalent production decreased by 0.7% compared to the fourth quarter of last year. Liquids production was up 80,000 barrels per day, driven by major new projects and work programs. However, natural gas production was down over 650 million cubic feet per day as reduced entitlement volumes, lower weather-related demand, primarily in Europe, and field decline were partly offset by major projects in Papua New Guinea and Malaysia. In short, our volumes performance continues to demonstrate the progress being made to high grade the portfolio mix with higher margin production. Turning now to the sequential comparison starting on slide 11. Upstream earnings decreased $948 million versus the third quarter. Realizations decreased earnings by $2.2 billion, driven by sharply lower worldwide crude prices, which declined over $27 per barrel. Volume and mix effects improved earnings by $140 million, reflecting higher margin volume growth. All other items had a positive impact of $1.1 billion, including the previously mentioned deferred tax items and Venezuela ICC award. Upstream after-tax earnings per barrel for the fourth quarter were just over $15, excluding the impact of non-controlling interest volumes, and is down due to lower crude prices. Moving to slide 12. Volumes were up 223,000 oil equivalent barrels per day or 5.8% sequentially. Liquids production increased 117,000 barrels per day from higher entitlement volumes, improved facility uptime, and work programs. Natural gas production was also up 639 million cubic feet per day, driven by higher seasonal demand, primarily in Europe. Moving now to the downstream financial and operating results, starting on slide 13. Downstream earnings for the quarter were $497 million, down $419 million from a year ago. Earnings increased $40 million due to stronger marketing and non-U.S. refining margins, mostly offset by weaker U.S. refining margins. Volume and mix effects increased earnings by $20 million, and all other items decreased earnings by $480 million, primarily from higher maintenance activities and unfavorable tax effects. Turning to slide 14. Sequentially, fourth quarter downstream earnings decreased $527 million. Lower U.S. refining margins, partly offset by stronger marketing and non-U.S. refining margins, decreased earnings by $360 million. Volume and mix effects decreased earnings by a further $20 million. All other items reduced earnings by $150 million, reflecting higher maintenance activities, partly offset by favorable foreign exchange and other effects. Moving now to the chemical financial operating results, starting on slide 15. Fourth quarter chemical earnings were $1.2 billion, up $317 million versus the prior year quarter, primarily driven by higher non-U.S. product margins on lower feed costs. Volume and mix effects decreased earnings by $60 million, and all other items, primarily unfavorable foreign exchange effects, reduced earnings by $110 million. Moving to slide 16. Sequentially, chemical earnings were essentially flat as stronger specialty product margins were offset by volume and mix effects and increased maintenance activities. Now I'd like to provide a summary of our full year results shown on slide 17. 2014 earnings were $32.5 billion or $7.60 per share. Corporation distributed $23.6 billion to our shareholders through dividends and share purchases to reduce shares outstanding. Of that total, $12 billion were used to purchase shares. CapEx in 2014 was $38.5 billion, which is down $4 billion from 2013 and is also down $1.3 billion from our 2014 guidance. Cash flow from operations and asset sales remained strong at over $49 billion, which included $4 billion from asset sales. Moving now to the full year cash flow statement as shown on slide 18. During the year, cash decreased from $4.9 billion to $4.7 billion. Earnings, depreciation expense, changes in working capital and other items in our ongoing asset management program yielded $49.2 billion of cash flow from operations and asset sales. Uses included net investments in business of $31.2 billion and shareholder distributions of $23.6 billion. Debt and other financing increased cash by $5.4 billion to fund our commitments, including working capital requirements. Moving on to slide 19 and a review of our full year segmented results. 2014 earnings were essentially flat with 2013 results. Higher upstream and chemical earnings were offset by lower downstream earnings and higher corporate expenses. Turning now to the full year comparison of upstream results starting on slide 20. Upstream earnings of $27.5 billion were up $707 million from 2013. Realizations reduced earnings by $2 billion as crude oil prices declined almost $11 per barrel. Importantly, favorable sales mix effects increased earnings by over $500 million, reflecting investments in higher margin assets and our continued focus on profitability. Volume contributions from major project startups and U.S. onshore liquid plays were partly offset by lower weather-related downtime and unfavorable entitlement impacts. All other items, primarily asset sales and deferred tax effects, increased earnings by $2.2 billion. Upstream after-tax earnings per barrel for the year was $19.47, up $1.44 from 2013 despite declining crude prices. Moving to slide 21. As indicated, volumes ended the year on plan at 4 million oil equivalent barrels per day. Excluding the impact of the Abu Dhabi onshore concession expiry, volumes were down by 1.7% or 71,000 oil equivalent barrels per day from 2013, reflecting lower gas demand in Europe and asset sales. Of note, liquids production was up 44,000 barrels per day or 2%. Volume growth from work programs and major projects in Canada, Angola and Papua New Guinea were partly offset by field decline and divestment impacts. Our natural gas production was down 691 million cubic feet per day, driven by lower weather-related demand, entitlement and divestment impacts, and field decline, partly offset by major project volumes in Papua New Guinea and Malaysia. The full year comparison for downstream is shown on slide 22. 2014 earnings were over $3 billion, down $404 million from 2013. Lower refining margins reduced earnings by $230 million. Volume and mix effects, mainly driven by refinery optimization activities, increased earnings by $480 million. All other items, primarily unfavorable Forex and tax impacts, decreased earnings by $650 million. On slide 23, we show the full year comparison for chemical results. 2014 earnings of $4.3 billion increased $487 million from last year. Higher commodity product margins, partly offset by lower specialty margins, increased earnings by $520 million. Positive volume and mix effects on higher demand were offset by all other items driven by increased maintenance activities. Moving now to an update on our cash flow growth shown on slide 24. As mentioned, annual cash flow from operations and asset sales was $49.2 billion, while net investments in the business totaled $31.2 billion. Resulting free cash flow of $18 billion increased $7.3 billion compared to last year and supported total shareholder distributions of $23.6 billion. Debt and other financing, along with a reduction in our cash balance, provided additional funds to meet our commitments. Moving next to the fourth quarter business highlights beginning on slide 25. Over the past year, ExxonMobil completed a record eight major projects demonstrating a world-class project execution capabilities. We added more than 250,000 barrels per day of net capacity across a broad range of resource types and geographies. The higher margin production from these projects underscores our focus on delivering profitable growth. We completed several projects over the last quarter. In Russia, at offshore Sakhalin, the first well at our Arkutun-Dagi field reached target depth in December with first production in early January. Daily gross production from the field is expected to reach 90,000 barrels and will bring total gross production at Sakhalin-1 to more than 200,000 barrels per day. Arkutun-Dagi is the last of three fields to be developed by the Sakhalin Project. The other two fields, Chayvo and Odoptu, began production in 2005 and 2010 respectively. In Canada, initial steam generation at the Cold Lake Nabiye development started late December, followed by injection into the reservoir in early January. After steam soaking, the first bitumen production is expected later this quarter. Production will increase over the balance of the year, with gross rates expected to reach 40,000 barrels per day. Nabiye is an expansion of the existing Cold Lake field, which started up in 1985 and produced almost 150,000 barrels per day in 2014. In the greater Hadrian area of the Gulf of Mexico, the Lucius project was essentially completed in December, with first production in January. Gross production from Lucius is expected to be around 80,000 barrels of oil and 150 million cubic feet of natural gas per day once the wells have fully ramped up. The Hadrian South sub-sea production system and flow lines were installed and connected to the Lucius spar host in late 2014 and will be brought online once Lucius production has stabilized. Hadrian South is ExxonMobil's deepest sub-sea tieback at more than 7,600 feet. Daily gross production from Hadrian South is expected to reach approximately 300 million cubic feet of gas from two wells. In offshore Abu Dhabi, Upper Zakum is one of the world's largest oil fields, with a resource estimate of 50 billion barrels. Together with our joint venture partners, we are progressing the field redevelopment to raise gross production capacity to 750,000 barrels per day. The joint venture is utilizing extended reach drilling from four new artificial islands and deploying proprietary ExxonMobil technology. Civil works are now essentially complete on all islands. Drilling is ongoing from two of the islands, and first production started in November of last year. Facility additions and drilling will continue over the next three years to reach the targeted production plateau. Finally, the Kearl expansion project in Canada continues to track ahead of schedule. Site construction activities are now largely complete, and commissioning activities are ramping up. The project incorporates the learnings from the initial development phase and will double Kearl's production capacity to 220,000 barrels per day for the next several decades. Turning now to slide 26 for an update on our broad exploration program. Drilling operations are ongoing at the Pelican South wildcat well in the Neptune block offshore Romania. Following this well, additional exploration targets in the area will be considered. In Argentina, we successfully drilled and tested two ExxonMobil-operated horizontal wells in the Vaca Muerta. The La Invernada X3 well flowed at an average rate of over 600 oil equivalent barrels per day and is currently on a long-term test. It is among the best producing wells in the Vaca Muerta. Our active program continues with additional drilling and testing in 2015. Recently, we have also added high potential acreage to our diverse exploration portfolio. ExxonMobil expanded its presence in the Canadian North Atlantic by 1.6 million gross acres, capturing three blocks offshore Newfoundland and Labrador. These blocks are in a proven oil-prone hydrocarbon basin with recent industry discoveries. This new opportunity will build on our 17 years of success with Hibernia, Terra Nova, and the ongoing development at Hebron. ExxonMobil also recently added significant acreage in West Africa, building upon a strong position that stretches from Liberia to Angola. In Côte d'Ivoire, we added 2.3 million gross acres by successfully completing negotiations for production sharing contracts on two deepwater frontier blocks. These captures mark the return of ExxonMobil to Côte d'Ivoire, where we produced the country's first oil 30 years ago. In Equatorial Guinea, we completed PSC negotiations to acquire an interest in another offshore block encompassing 160,000 gross acres to PSC, subject to final government ratification. This additional acreage builds on almost 20 years of ExxonMobil operations in Equatorial Guinea. In the U.K. North Sea, we were awarded a 50% working interest in two licenses that are part of a proven hydrocarbon province near producing fields. ExxonMobil and Shell bid jointly for these licenses, which cover more than 250,000 gross acres. In conclusion, our full-year results underscore the value of our integrated business model. In 2014, ExxonMobil earned $32.5 billion, and we achieved our full-year plan to produce 4 million oil equivalent barrels per day. We maintained our disciplined capital allocation approach by selectively investing in attractive opportunities, thereby improving our production mix. Unit profitability increased from just over $18 per barrel in 2013 to about $19.50 per barrel in 2014, despite lower prices last year. Corporation generated free cash flow of $18 billion, an increase of over $7 billion when compared to 2013, and we maintained strong shareholder distributions totaling $23.6 billion. In summary, we delivered on our commitments, and we remain resilient through the cycle. Finally, I'd like to mention two upcoming events. First, in mid-February, we'll be releasing our 2014 reserves replacement data. Second, as many of you may know, our upcoming analyst meeting will take place at the New York Stock Exchange on Wednesday, March 4th, with a live broadcast webcast beginning at 9:00 A.M. Eastern Time. We will provide an update to our business strategies and our investment plans during the meeting. Presentation will be led by ExxonMobil's Chairman and Chief Executive Officer, Rex Tillerson. That concludes my prepared remarks, and I would now be happy to take your questions. Thank you. The question and answer session will be conducted electronically. If you would like to ask a question, please do so by pressing the star key followed by the digit one on your touchtone telephone. We request that you limit your number of questions to two so that many have the opportunity to participate as possible. If you are using a speakerphone, please make sure your mute function is turned off to allow your signal to reach our equipment. We will proceed in the order that you signal us, and we'll take as many questions as time permits. Once again, please press *1 on your touchtone telephone to ask a question. We'll take our first question from Doug Terreson with Evercore ISI. Good morning, everybody. Morning, Doug. Jeff, because the company is so diverse, both functioning geographically, your commentary on global economic activity has always been pretty helpful. Based on your remarks at the beginning, it seems like economic trends in the OECD and China weakened materially during the second half and specifically in the fourth quarter. My question is whether or not you have additional color or updates in those areas, and also any commentary and/or color on economic activity trends that you're seeing in the non-OECD as well? Yeah, Doug, thanks for that question. I'd say broadly speaking, I'll fall back on our overall assessment of what demand will be doing across the globe, particularly in Asia-Pacific. We are forecasting that demand. As I've said previously, that demand assessment that we do on an annual basis really underpins our business strategies and our investment plans. Sure. As we look forward, we see oil demand growing at about 0.8% per year. That's underpinned by transportation and chemical needs. In the gas sector, we see gas demand growing by about 1.5%, 1.6% per year, and that's primarily underpinned by power generation and industrial demands. Overall demand growth is largely underpinned by the non-OECD growth. When you think about our business, the scope of our business, and how we lay out our business strategies and our investment plans, they really are focused on the long-term expectation around energy demand. Okay. How much of the $1 billion non-cash effect was related to the arbitration ruling with Venezuela? Is this entire amount accounted for in the upstream? Doug, on the nearly $1 billion, about 70% of that was associated with the adjustments to our deferred tax accounting. Okay. About 30% of that is associated with the Venezuela award, and that was in the non-U.S. component of the upstream. Okay, great. Thanks a lot. You bet, Doug. We'll take our next question from Phil Gresh with J.P. Morgan. Hey, good morning, Jeff. Just to start off on the CapEx side. Last quarter, Exxon indicated that it did not plan to cut its CapEx in 2015 versus its initial target. I know you'll give a more broad update at the Analyst Day, but just generally speaking, has your view changed at all, or are you still deciding at this stage? You pulled the buyback lever there. Just wondering more broadly how you're thinking about that. Sure, Phil. I can certainly appreciate a lot of interest given this climate that we're in right now. I tell you that right now, we have no CapEx guidance. As you may recall, we had signaled a further reduction in CapEx to under $37 billion in 2015. As we normally do, we'll provide an update on both our business strategy and our investment plans next month, as I indicated. As you are aware, we have been reducing our capital spend since 2013 due to several reasons, including the completion of several major projects, our ongoing intense focus on capital efficiency and of course our discipline in investment planning, given the economic parameters. I guess, Phil, I'd like to emphasize a couple of points, recognizing that I'm asking you to hold off until next month. First, regardless of where we are in our business cycle, this organization has a very strong culture of driving down our cost structure, whether it be self-help in our operating costs or capital efficiency in our project execution. We expect to lead the cost curve in capturing savings, especially in downturns like we're experiencing today. Second, we challenge all of our investments to ensure that we are creating long-term shareholder value through the cycle. Remember, we are price takers. We don't assume price growth into the future, but we really focus on those things that we can control, like cost, reliability, and of course, our project execution. So Phil, we'll keep a close eye on our cash flow, maintain our investment discipline, and of course, our commitment to our growing dividend. Where necessary, we'll leverage our balance sheet to meet our commitments as appropriate. Sure. Okay. Then just a question on the buyback. Obviously, it could have been any number between $0 billion and $3 billion, but just wondering, why you specifically picked what you did. Are you trying to target a certain leverage level, assuming the strip? Or just, how you're generally thinking about it, and more specifically, just wondering what would make you change it up or down from here again? Sure, Phil. Obviously, it's a number of factors. Our share buybacks have always been the flexible part of our capital allocation program. The buyback pace has been determined each quarter considering the company's current financial position, our CapEx requirements, our dividend requirements, as well as our longer-term business outlook. We'll continue to manage our business in a prudent manner throughout the cycle, as we've said many times. That buyback decision will be really an outcome of our cash flow management. So I just, again, emphasize that we remain committed to our investment program and of course, paying our growing dividend. Okay, thanks. Thank you, Phil. We'll go next to Doug Leggate with Bank of America. Jeff, it's actually Jason Smith on for Doug. Good morning. Good morning, Jason. Just coming back to the one-time items. In U.S. refining, your earnings look a little bit weaker than your peers that have reported so far. You called out some year-over-year tax and maintenance impacts, but it seems like that was not part of your $1 billion. Can you maybe just give some color around those and maybe quantify the absolute impact for the U.S.? I am just curious if there is anything else going on in U.S. refining beyond that. Sure. Let me just give you a broad summary on the U.S. refining. Fourth quarter, our downstream earnings were impacted by lower realized refining margins and a negative crude lag impact, as well as higher maintenance activities at some of our largest refineries in the Gulf Coast. While earnings were marginally negative over the quarter, our full-year results were solid at about just over $1.5 billion, despite the pressure on refining margins and a heavier maintenance year than normal. Overall, our U.S. refining footprint is just very well positioned to benefit from advantage feedstocks and from the investments that we have made that focus across a number of areas to further advance our profitability in those assets, such as feedstock flexibility, logistics capability, increasing the higher value product yields, and reducing our fundamental cost structure. Most important, capturing the most value from our integrated business model. Got it. Thanks. Maybe just on PSC impacts. You gave some color on the sequential improvement. I think it was 78,000 barrel a day positive. Oil down significantly from 4Q. Can you maybe just give any color around the incremental impact at prices down here? Yeah, you can appreciate that each of our contracts are unique and associated with the commercial arrangement. It would be really tough to give you a rule of thumb because we do have in that category price impacts. You have got spend impacts. We have temporary volume impacts that are associated with the fiscal agreements. Broadly speaking, you are correct to assume that lower crude prices will provide an uplift, as you saw in the sequential comparison. But that impact is largely complicated by the multiple contracts, cost recovery, and other effects that we have in our operations. Thanks, Jeff. You bet. We will go next to Evan Calio with Morgan Stanley. Hey, good morning. How are you? Good morning, Evan. My first question, maybe CapEx from another angle. Net debt is up $7 billion in the quarter. I know you reduced the buyback guidance. How willing are you to flex the balance sheet through a down cycle? Maybe discuss limitations on that side, which would either take that lower or the buyback lower, reduce CapEx. Maybe just lastly on CapEx, I presume you already have a 2015 CapEx number, and it's more of a guidance question, or just functionally, how does that work? Yeah, Evan, so I'd get you to think about it from a fundamental in how we manage our cash and the consideration and balance of all the variables that we need to address, the inflows, our commitments to fund investment plans as well as our dividends. I don't have any specific guidance for you on debt capacity or our plans. As you know, our operating cash flows remain the primary source of funding. As evidenced by the reductions that we have taken in CapEx, and as you've heard, the reduction planned in the first quarter on share buybacks. We'll continue to be disciplined in our investment approach throughout the cycle, but we won't forego any attractive opportunities. We have a significant debt capacity, but we will maintain our financial flexibility, and we'll assess the cash and our funding options under a range of outcomes and take a balanced approach to meet those obligations, as I indicated. In short, I'll come back to this message throughout our discussion, that we remain committed to an investment program that delivers on an attractive return, but also to pay a reliable and growing dividend. Great. That is helpful. Maybe second is a smaller issue, just a question on the quarter. Is there an asset sale loss, or did I miss that, which would affect the lower tax rate for the quarter? If you can talk me through that, please. Yeah. The lower tax rate that you are focusing on really have three components. One would be the gains on deferred tax items that I mentioned already. The second would be changes to the portfolio mix, given the income streams that we get from our U.S. and non-U.S. And then third would be ongoing asset management activities. But I will tell you, Evan, that our guidance of our effective tax rate is still consistent at about the mid 40%. Yep. Got it. Okay. Thank you. You bet, Evan. I'll take our next question from Paul Sankey with Wolfe Research. Good morning, Jeff. Good morning, Paul. Jeff, could you update us on what is going on in Russia from your point of view, if anything? Further to that, which I know is a JV that was very important to your longer term reserves and production plans, could you talk about how you would define the attractive opportunities that you have mentioned? I assume you are referring to M&A and whether you would be more attracted to oil, I would assume, as opposed to gas reserves. More attracted maybe in the new world order to U.S. reserves, maybe within the U.S. If you could fill us in at all about what you would consider and how you would define an attractive opportunity, that would be great. Thanks. You bet, Paul. Starting at Russia. Broadly speaking, there is really nothing new to report on that. As you all know, the sanctions are still in place, and we will continue to fully comply. As we have said previously, that does not apply to Sakhalin-1, which I will just take this opportunity to say that we have had extraordinary success, really thanks to a very talented organization and a highly effective joint venture. We are very pleased with the successful startup of Arkutun-Dagi. But in terms of the rest of the business, we just need to wait to see how the sanctions play out. I will remind you that ExxonMobil does have a very long-standing and successful business in Russia, that I would say that is built on an effective and mutually beneficial relationship with our partners. On the second item around attractive opportunities in M&A. Broadly speaking, we have talked previously about our asset management program, and we really think about it for the full scope of how we high-grade our portfolios through asset management. That may obviously have an ongoing component of divestments of non-strategic or lower value assets, but also bringing in through acquisitions, some new opportunities. Those may be bolt-on acquisitions. They may be new entries that are synergistic to our business. Paul, we stay very alert to value propositions. We are watchful where we can capture opportunities to high grade our portfolio, whether it be oil, whether it be gas, onshore, offshore. But I will be clear that the real focus here is creating value, and we will pursue only those acquisitions that we think that have ultimate strategic value and are accretive to our longer term returns. Yeah, and I guess within that, you're primarily interested in long term reserves, right? Obviously, you don't want to buy someone's decline curve, so it becomes a question of 2P and 3P. Yeah I assume. Paul, it'd be a focus on, again, if we can get synergistic benefits like some of the bolt-ons that we've brought into XTO over the last couple of years have been very beneficial, but they do have a very significant component of development potential where we can apply our resource capability expertise and how to develop that, our proprietary technology and our strong balance sheet. But yeah, we don't want something that's already on decline that doesn't have potential. We're really looking for something that really can upgrade our overall portfolio and add future potential. Great. Thank you. Thank you, Paul. We will go next to Ed Westlake with Credit Suisse. Hey, good morning, Jeff. An interesting time to step up to the role. So good luck this year. Thanks, Ed. Just trying to get a sense of, again, this CapEx question again, how much of your, say, upstream spend is kind of locked in for 2015, and how much wiggle room do you have in 2016? Appreciate this may be something for the analyst day, but just trying to get a sense of the levers that you could pull if your revenues are much lower this year. Yeah, sure. Well, I would tell you that as we look at our overall investment program, we focus on every asset that we've got, regardless of whether it's, as you've indicated, a longer-term investment, which is, quite frankly, a core component of our investment program, as well as the shorter cycle investments and study work. Nothing is really sacred in there. As I indicated, we have a very strong culture of driving those cost structures down. We've been very actively engaged with our service providers, and we fully expect to capture savings across the spectrum of our business, from rig rates to labor and services, as well as commodities. But I'd be clear, Ed, that we're probably in the very early innings of this effort. There's a lot of strong reaction to the current price business climate, and we think that what that is presents a number of really good opportunities to capture incremental savings, lower the overall cost structure of the business, as well as position us with some other opportunities as we go forward. The thing that I would really point out that distinguishes us is that, as we've said many times, is that we can invest through the business cycle, and it presents some opportunities that we're able to lower that cost structure and improve our overall longer-term returns given the financial capability that we have. A quick quarter question. Asia natural gas production and Australasia as well downticked in the fourth quarter versus the third quarter, and I appreciate there's lots of different demand drivers across a big business. But is there anything specific you'd call out for that step down? Yeah. I would say that a component of that had to do with demand in Australia. But remember that there was a very healthy increase associated with Papua New Guinea over the year. Sequentially, you do not see as much of an increase. There was a slight increase in Papua New Guinea, though. But in Asia, obviously a much larger business, but that was also down generally? Yeah, it was generally some facility performance downtime. Okay, great. Thanks. We'll take our next question from Blake Fernandez with Howard Weil. Good morning. Thanks for taking the question. The first question's on Venezuela. I know you mentioned the arbitration ruling. Can you just kind of confirm that that finalizes this process, or are there any additional legs to kind of move forward on there? Yeah, Blake, on Venezuela, there's actually two separate arbitration proceedings. One was the International Chamber of Commerce that I mentioned that we recognized the award on. The second was the World Bank's International Centre for Settlement of Investment Disputes. What we recognized was the first one. I'll note that both of those decisions did confirm that the Venezuela government failed to provide fair compensation for the assets that were expropriated. We will recognize the second ruling at the time that we receive payment and when all legal proceedings have concluded. Okay, great. I hope this doesn't get too in the weeds, but the second question's on the impact of the strong U.S. dollar. I'm just curious if you could talk around how that's impacting your business with the rapid moves we've seen and maybe what's been embedded in the quarter as a result of FX. Yeah, in terms of Forex, obviously, as you're probably very aware that it has opposite impacts across our business. In the upstream, it primarily ends up being a margin benefit due to local denominated OpEx, whereas in the chemical and downstream, it tends to have a negative impact due to our dollar-denominated crude payables. So in quarter-on-quarter, it was a slight hurt to earnings of under $50 million. Although sequentially, it actually was a positive of over $200 million. Great. Thank you so much, Jeff. Thank you. We'll go next to Brad Heffern with RBC Capital Markets. Good morning, Jeff. Good morning, Brad. I was wondering if you could just go through maybe Exxon's current thoughts on the global LNG market. You have several potential projects that haven't FID'd yet. Do you think maybe the global market needs to take a pause at this point? Well, Brad, again, as we talked a little earlier our investment plans are really founded on our outlook for supply and demand. We show, as I said, projected gas demand to grow about 1.6% per year between now and 2040, and that really provides the business case for our LNG projects. Broadly speaking, our existing LNG facilities are a key component of our portfolio, very important part of our margin generation. As we see demand grow in the future, we expect supply will grow in line with that demand. Obviously, these are capital-intensive projects, so we'll need to ensure there's a sufficient price structure in place to underpin those investments. We have gotten a number of projects across the globe that are in place that are positioned to go ahead and compete for that demand profile. Okay, understood. Thanks. Just thinking about gas in a different way, certainly in the U.S., you've been somewhat minimizing gas drilling over the past couple of years, and the market certainly has its own challenges right now. Has the downturn in oil caused you to think any differently about what specifically you're drilling for in the U.S.? Not really. I tell you that it's still based on our demand projections. We've got significant drillable gas potential within the U.S., and as you know, that's generally a short cycle type investment. We can get on capacity pretty quick. So we're very well positioned to do that should the demand grow and the prices support it. I'd also say that from a chemical perspective, our chemical business is very well positioned to take advantage of the lower commodity prices, particularly in the U.S., where manufacturing sites are highly flexible and can run across a wide range of feedstocks from ethane all the way to gas oil. Okay, understood. Thanks for taking the question. You bet, Brad. We'll take our next question from Jason Gammel with Jefferies. Thank you. I've actually got follow-ons to both the questions that were just asked. Just in terms of how you're managing the Lower 48 business in the pricing downturn, Jeff, are you keeping a relatively steady rig count, or have you been laying down rigs the way that the rest of the industry has as well? Well, it's a good question, Jason. I'd cast it from a, if you will, a historical perspective that we've taken a very measured pace in how we've developed our Lower 48 unconventional resources. You did see over 2014 a number of operators really ramp up their rig counts significantly. We did grow our rig count, and in fact, we are up in the fourth quarter versus the third quarter but at a very measured pace to make sure that we didn't outrun our headlights. We want to make sure that we had a good understanding of the resource performance, and importantly, we wanted to make sure that we're fully integrating all the learnings back into our advanced program. So we've been very measured how we've moved forward. Going forward, we'll consider all the factors including the business condition, infrastructure capability, as well as our demand projections. But going forward, I just want to reinforce that we do have a very robust inventory of opportunities, even in this price environment. Got it. Thank you. My second question is on the LNG business. Can you remind us how much, just as a percentage of your overall LNG output, is committed under long-term contracts, and how much is actually put into the spot market? On the spot market, are you seeing significant demand weakness that potentially would even lead to reducing facility utilization? Yeah. On the LNG business, I would say that a majority of our current LNG is under long-term contracts. Very few that have spot sales. Of course, we did take some spot sales with Papua New Guinea, given the early startup. Also note that in our LNG contracts, we have potential to divert cargoes as well, which gives a lot of flexibility. Okay. Thanks, Jeff. You bet, Brad or Jason. We'll take our next question from Asit Sen with Cowen and Company. Thanks, and good morning, Jeff. Good morning, Asit. Two unrelated questions. First, on the issue of supply chain costs and your prior success with that, I was wondering if you could quantify annual third-party costs globally for the organization. Some of your peers have highlighted multi-billion dollar opportunities for this reduction. Also any high-level thoughts on recently announced oil service industry consolidation. Has anything changed on the ground for Exxon? Well, broadly speaking, I don't have specific numbers. As I said previously, as a mainstay in how we manage our business, we are constantly working on that cost structure. We're very active with our service providers. As I indicated, we're probably in the early innings of that. We are seeing decreases in rig rates and labor and service costs, as well as starting to see some commodity changes as well. But watch that space. More is to come in that area. On the second question, remind me, Asit, was there- On the oil service industry consolidation, any thoughts on that, how things have changed? No, there's really nothing I have to say on that. We access all of the service providers, and competition is good, and we have a very strict standard on what we expect from them in terms of quality, performance, and service costs. Okay. My follow-up is on U.S. onshore. Last quarter, you had highlighted that Bakken was Exxon's most active unconventional play with, I think, 13 rigs running. Could you update us on activity levels currently? I think, and perhaps provide update on Woodford and Permian as well. Yeah. Across the three main liquid plays that we've got, we're producing in excess of 220,000 barrels a day gross. And we're running currently about 44 rigs. I'd say we're active in all three of them. That rig count has, if you compare back to what I said last quarter, has increased. But very encouraging list of opportunities, and we're making great success in integrating our learnings and driving down the cost curve. Thank you. We'll take our next question from Paul Cheng with Barclays. Hi, Jeff. Good morning. Good morning, Paul. Two quick questions. Do not know whether you have any number you can share. In your supply costs, when we are looking at the contract, is there a number you can share in terms of the percent maybe for the contract is over two years still remaining? In other words, I am trying to understand what is the percent of your supply cost that, if we do see a substantial deflation in the industry cost structure, it is going to see a relatively quick pass through into you? Yeah, Paul, I do not think I have any guidance on that. Okay. Secondly, did you say that in the downstream you have a crude lag purchase effect that is negative? That's correct. Can you quantify how big is that? Well, broadly speaking from a crude lag, I want to be clear, Paul, when we see a decrease in prices like we're seeing right now, we have a negative crude lag effect. In fourth quarter, absolute, it was just over $600 million. Got it. In an environment where price is increasing, you would have the opposite effect. You are using the LIFO accounting, so why we have such a big negative crude effect? Also, I thought the price finalization related to your Saudi contract in a declining oil price environment should actually be a favorable positive impact. I guess I am just totally wrong on that then. Yeah. The crude lag effect is primarily associated with pipeline supply contracts, standard terms to how the pricing is done. Okay. This 600 is primarily in U.S. then, I presume? That's correct. I see. Is there any other tax impact in the quarter other than, say, the $700 million U.S. deferred tax in the upstream? Paul, is your question relating to our overall performance or specific to a segment? If you can say, looking at all the other segment that we know that you have $700 million of the U.S. tax benefit in the upstream. Is there any other tax negative impact or positive impact in the other segments? That is, in essence, most of it. Okay. Will do. Thank you. You bet, Paul. We will take our next question from Allen Good with Morningstar. Good morning. I wonder if I could tackle the cost improvement question from a different angle. Is there any area that Exxon has identified based off of trends the past few years where you think you may have more opportunity to cut cost relative to other areas? I guess I'm thinking more along the lines of project type and then specific regions relative to other ones. Allen, I think broadly speaking, we always feel like we've got opportunity to become more cost efficient. From a capital perspective, it's around upfront planning for execution to make sure that we're most effective in utilization of services as well as commodities. In terms of our day-to-day operations, our fuel costs are a big component. You have to manage that appropriately in terms of energy efficiency of your facilities. As I commented on the capital program, I'd say that nothing's really sacred. We continue to identify additional opportunities to make our cost structure more efficient. Great, thanks. On asset sales, I would assume that you guys are more opportunistic on that level. I think if I recall, you took the approach of if it's worth more to us or more to the buyer, we'll sell. Has activity around your assets or at least interest that you may have seen six months ago declined into today? Should we expect maybe the asset sales slow down over the next year to 18 months? Well, we've got such a diverse portfolio of assets I really couldn't characterize for you whether the interest has increased or decreased. Assets are so unique in their own right, and we recognize that these are years of planning to assess when the right time is to go ahead and monetize that asset in a different means. We've been very successful in capturing incremental value from our assets that we don't believe no longer has a strategic fit for our business. So I'd leave it at that. All right. Thank you. We will take our next question from Ryan Todd with Deutsche Bank. Great. Thanks. Good morning, gentlemen. Maybe one follow-up question on the U.S. liquids production. It was quite strong in the quarter, strong sequentially and strong year-on-year. Can you talk a little bit about what assets are primarily driving that growth? Is this kind of your big three onshore plays that you were talking about, or is it a little bit of everything? Yeah. This is a good opportunity to really talk more about it. In terms of our fourth quarter versus the third quarter performance, we are up quite significantly on our volumes, primarily driven by our projects. Quarter-on-quarter projects are up about 130,000 oil equivalent barrels per day. Those volumes are coming from Angola, primarily the CLOV project in Canada associated with the Kearl project in Papua New Guinea, associated with our LNG project. We had an increase in project volumes associated with Malaysia, Telok, and Damar. As well as we had a very nice build in our U.S. work program due to our active drilling program in the three main liquid plays. The other thing I would point out is that we have also made great progress. The team has done an outstanding job in reducing our downtime in our facilities. 2014 was a very successful year, and that brings very high value volume to the bottom line. Great. Thanks. Then maybe one more on LNG. I guess a couple parts on LNG, which is there any risk to the pricing terms of your existing LNG contracts in the current environment from periodic reopeners in the contracts? Would a longer duration of this moderate environment change the pace or effort at all around U.S. LNG exports? No, again, these are very large capital intensive projects. The investment is underpinned by our long-term gas demand projection, and that's really the business case. As I said earlier our existing LNG projects are a very significant part of our margin generation. All right. Good. Thanks. Thanks, Ryan. We'll take our next question from Roger Read with Wells Fargo. Hi. Good morning. Good morning, Roger. Just maybe follow up on a couple of things that have been hit here already. But as you look at the major projects that you outlined in the earlier presentation, just curious what the incremental 2015 impact is. I mean, a lot of these projects started up at the end of 2014 and roll into 2015. If you could give us an idea of maybe the volumes impact there. Yeah. So for our 2014 program, just to recap, we added about 250,000 oil equivalent barrels per day. As we look forward for 2015, we'll need to provide you an update at the March analyst meeting. Well, I guess I was just wondering for the ones that were highlighted in the presentation, or it's a March event, and we'll wait for that, I guess, is. Yeah, for 2015. I shared with you how those investments in the presentation will ramp up to their peak production. As I said Arkutun-Dagi ramping up to 90,000 barrels a day, Nabiye ramping up to 40,000 barrels a day, Hadrian South ramping up 300 million cubic feet per day. Beyond that we'll be more specific in next month's analyst presentation to have a discussion about it. Okay. Earlier in some of the Q&A, you mentioned specific to dealing with the cost structure of the company. It sounded like to me, both internally and your third parties. Any comparisons, contrasts you can do with previous downturns in terms of contracts that you have fixed here? I mean, another way of asking the question, any change in the flexibility Exxon has to address the cost structure today versus several years ago or in prior downturns we've had? No, I wouldn't highlight anything that's changed. As I've said a couple of times, it's a very intense focus on capital efficiency and lowering our cost structure in our business across the areas that I talked about previously. No particulars on rig contracts or anything like that are more onerous than prior times? No. I don't want to get into specifics on our commercial arrangements, but we've got a very large sizable operation and that positions us well to go ahead and work with our providers to put in place a very effective cost structure. Okay. Thank you. Thank you, Roger. We'll take our next question from Ian Reid with BMO. Hi there, Jeff. Hey, Ian. Just got a question on your pre-sanction, pre-FID projects. A couple of your partners have been talking about pushing these out due to current cost pressures and waiting for lower service costs, et cetera. I am specifically thinking about projects such as Tengiz and some of the Australasian and Canadian LNG projects. Is that something which you are also kind of factoring into both your longer term production and your CapEx outlook in terms of pushing these kind of more marginal projects down the road a little bit? Well, that would be a consideration. Broadly speaking, we have got a very large and diverse inventory of opportunities. We are very careful as we move these things forward. That one, not only have they reached technical maturity, but that we have tested the economic viability across a full range of economic parameters, including commodity price. While we do not forecast or expect a price growth in order to make these investments go forward, we want to make sure that we go into this eyes wide open and that we have a good handle on how robust these investments are. So when we do have these commodities volatility like we are seeing right now, we are comfortable about the investment plans that we have in place. Quite frankly, our investment program is really driven by a long-term projection, and we just do not overreact to volatility in the market. But we are mindful. We are mindful about implications on the business climate, implications on our cash flow management, and then the overall supply-demand projection. So all of those variables are considered in how we set up our investment plans. But given that it is based on a long-term projection of demand, and they have been tested across a range of economic parameters, there won't be a whole lot of change. I am not suggesting that there will be no change, but there won't be a whole lot of change to our investment plans. Okay. All right. That is understood. Can I just ask a quick question on chemicals? Your numbers there seem to be holding up pretty well. I am just wondering what you are thinking about chemical demand, in particular outside of the U.S. going forward, because you are going to be seeing very much lower naphtha prices now. So what do you feel about the kind of pricing and demand side of that business? Very well positioned. It is a great business. We have got the chemical facilities positioned throughout in North America. We are benefiting from the lower feed costs. We have got advantaged assets there. In the Europe and Asia Pacific, our steam crackers really benefit from the lower price environment we are in right now. Particularly our newest cracker in Singapore, which can process an unprecedented range of feedstocks ranging from crude oil, including crude oil, which is really an industry first. Yeah, I am just wondering about the kind of the industry dynamics you are seeing out there in terms of demand and pricing. I know you are well positioned, but what are you seeing in terms of Asian demand, European demand? Yes. Our global demand. I am sorry. Ian, our global demand is expected, based on our assessments, expected to grow above GDP, driven by Asia. Okay. All right, Jeff. We'll see you at the analyst meeting. Great. Thank you, Ian. We'll go next to Alastair Syme with Citi. Hi, Jeff. Hi, Alastair. Can you just come back to the deferred tax benefit and just explain what is going on with that mechanic, please? Yeah. We periodically will review our deferred tax accounts to make sure that we have got the right reserves in place. And sometimes that results in an adjustment, which you are seeing this quarter. It is not related to commodity prices in any way? No, it's just a prudent review of our deferred tax accounts. Okay. My second question. Some people have alluded to the lag effect on pricing. Could you just discuss on LNG what the typical lag effect is and when do you think we'll see bottom prices given where oil prices are today? Well, there is a crude lag effect on our LNG contracts. We're not going to discuss the specifics of those. So you will see some impacts going forward. It really does vary by contract. Okay. But sometime in first and second quarter would be reasonable, do you think? Well, it depends on what prices do. Yeah. Okay. Thank you very much. You bet. We'll take our next question from Pavel Molchanov with Raymond James. Thanks for taking the question. First, on the balance sheet, is it still the case that you are targeting maintaining AAA credit rating? If so, how much debt do you think you can take on and still keep the AAA? Yes. As I said earlier, Pavel, we don't have any specific guidance on debt capacity or our plans. We will assess our cash and funding options around a range of outcomes, and we'll take a balanced approach to meet our obligations. As I indicated, we have significant debt capacity, but importantly, we'll maintain our financial flexibility. Okay. In relation to your top three U.S. liquids plays, you said that the rig count has actually increased from three months ago. Can you name any geographic areas, either North America or otherwise, where the rig count has dropped in the last three months? Well, I'd just say, broadly speaking, at the level that we'll share with you all, our overall rig count globally is running just under 100 rigs. About 60% of that is in the U.S., and we continue to assess the value proposition of maintaining our rig activity. I'll leave it at that there. Okay. Fair enough. Appreciate it. Okay. We'll go next to Guy Baber with Simmons & Company. Good morning, Jeff, and thanks for fitting me in at the end here. Good day, Guy. You highlighted the improvements to your underlying upstream margins through 2014, despite the lower year-on-year commodity pricing environment, which you all have been very focused on for some time and I think was a very important accomplishment for you guys. Setting aside the commodity as we look to 2015, I was just hoping you could comment on just bigger picture expectations for the trend in underlying upstream margins, and what you think perhaps the biggest drivers and biggest opportunities may be. I am thinking evolution of major project mix and ramp-ups, costs, or focus portfolio moves. Just wondering if there was anything specific you could share there that we should be focusing on. Then I had a quick follow-up. Yeah. Good question, Guy. I would say I appreciate the recognition of the progress that we have made over 2014, and I would say that that is a result of several factors. One is this intense focus on capital efficiency and lowering our cost structure. Two has been the higher margin production that we have been adding to the portfolio due to our major project activity and our U.S. onshore drilling activity in predominantly the three main liquid plays that we have talked about. Both have been a significant uptick to our overall unit profitability. That is very helpful. Then my follow-up was with 2014 now in the books, I was just wondering if there is any update you could share on base portfolio decline, how that performed versus expectations. Then big picture, does Exxon expect an increase in global decline rates just for the industry given some base spending is perhaps being cut, and is that an important component of your oil price kind of fundamental outlook? Our overall base decline in 2014 was about 3%. We have continued to offset that with our work program activity as well as the major project adds. Obviously in our unconventional, you see a higher decline rate earlier on and then it flattens out, and that will have an impact and we offset that with a very active work program. Thanks very much. We'll go next to Paul Cheng with Barclays. Hey, Jeff. Just two very quick follow-up. Do you have an underlift or overlift in the quarter for your upstream production, the sales versus the production? Yes. The overlift and underlift, my recollection was that we did have an underlift in the fourth quarter relative to the third quarter. How about versus the actual production? Well, that's what it is. Okay. Underlift versus the production. Okay. Can you quantify what is that number? Yeah. Sequentially, it was about 90,000 barrels. Okay. And that you have Hey, Paul, I'd just highlight though, while we see that variability on a quarter-to-quarter basis, I'll just note that it was essentially flat year-on-year. Okay. And that you have, I think that very little asset sales. Just wondering, is there any asset sales gain in the quarter? For the quarter on the asset sales, it was very small, Paul. It had some small upstream assets in the fourth quarter and very small downstream as well. Okay. All right. Will do. Thank you. Alrighty, Paul. Thank you. It appears we have no further questions at this time. Well, to conclude, I'd like to thank everybody for your time and your questions this morning. As you know, our business model is designed to be successful in a business climate known for commodity price volatility, and that's really why it always comes back to the fundamentals. Prudent cash management, operational reliability and efficiency, this intense cost control I've talked about a couple times, and obviously excellence in project execution. We really do look forward to sharing more with you in March with an update on our business strategies and our investment plans. Until then, everybody take care, and we'll see you in March. Thank you. That does conclude today's conference. We appreciate your participation. You may now disconnect.