Jeff Woodbury - VP, IR and Secretary

Douglas Terreson - Evercore ISI Phil Gresh - JPMorgan Jason Smith - Bank of America Merrill Lynch Evan Calio - Morgan Stanley Paul Sankey - Wolfe Research Ed Westlake - Credit Suisse Blake Fernandez - Howard Weil Brad Heffern - RBC Capital Markets Jason Gammel - Jefferies Asit Sen - Cowen and Company Paul Cheng - Barclays Allen Good - Morningstar Ian Reid - BMO Alastair Syme - Citi Pavel Molchanov - Raymond James Guy Baber - Simmons & Company

Good day, everyone and welcome to this ExxonMobil 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 ExxonMobil’s fourth quarter earnings call. As you know the focus of this call is ExxonMobil’s financial and operating results for the fourth quarter and the full year of 2014. I will refer to the slides that are available through the Investors section of our Web site. 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. ExxonMobil delivered earnings of $32.5 billion in 2014 and fourth quarter earnings of $6.6 billion. These results highlight the value of ExxonMobil’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, ExxonMobil’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 purchase 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 were 7.7 billion and 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 in 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 7 for a review of our segmented results, ExxonMobil'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. And the sequential quarter comparison, shown on Slide 8, 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 to $700 million per quarter. Turning now to the upstream financial and operating results, starting on Slide 9, 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 a 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 and 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 probably 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 a 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 and all other items reduced earnings by $150 million, reflecting higher maintenance activities, partly offset by foreign exchange, favorable foreign exchange and other effects. Moving now to the chemical financial and 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 repurchases to reduce share 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 remain 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, and our ongoing assets management program yielded $49.2 billion of cash flow from operations and asset sales. Uses included net investments in the 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. Turing 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 and higher margin assets and our continued focus on profitability. Volume contributions from major project startups in U.S. onshore liquid plays 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 a $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 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, foreign exchange 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 Arkutun-Dagi field reached target depth in December with first production in early January. The early 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 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 subsea production system of flow lines were installed and connected to the Lucius far host in late 2014 and will be brought online once Lucius production is stabilized. Hadrian South is ExxonMobil’s deepest subsea tieback at more than 7,600 feet. The early 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're 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. And 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 X-3 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-equivalent 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 for Iberia to Angola. In Côte d'Ivoire, we added 2.3 million gross acres, by successfully completing negotiations of production sharing contracts on two Deepwater Frontier blocks. These captures marked a return of ExxonMobil to Côte d'Ivoire, where we produced the country's first oil 30 years ago. In Equatorial Guinea, we've completed PSC negotiations to acquire an interest in another offshore block encompassing 160,000 gross acres. The PSC is subject to final government ratification. This additional acreage builds on almost 20 years of ExxonMobil operations in Equatorial Guinea. And in the UK North Sea, we were awarded a 50% working interest and two licenses. They are part of a proven hydrocarbon province in our producing fields. ExxonMobil and Shell, bid jointly for these licenses which cover more than 250,000 gross acres. So 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 reserve replacement data. And 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 webcast beginning at 9:00 AM 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. [Operator Instructions] We'll take our first question from Doug Terreson with Evercore ISI.

Jeff because the Company is so diverse and functioning geographically your commentary on global economic activity has always been pretty helpful and 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 so, 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 are seeing in the non-OECD as well?

I would say broadly speaking, I'll pull back on our overall assessment of what demand will be doing across the globe, particularly in Asia Pacific. We are forecasting that demand and of course as I've said previously, that demand assessment that we do on an annual basis, really underpins our business strategies and our investment plans. So, 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. Now overall demand growth is largely underpinned by the non-OECD growth so 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.

And then also specific to the Company how much of the $1 billion non-cash effect was related to the arbitration ruling with Venezuela and also was this entire amount accounted for in the upstream?

So Doug on the nearly $1 billion about 70% of that was associated with the adjustments to our deferred tax accounting and then about 30% of that is associated with the Venezuela award and that was in the non-U.S. component of the upstream.

We’ll take our next question from Phil Gresh with JPMorgan.

So 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. So I know you’ve given 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 and obviously you pulled a buyback lever there so just kind of wondering more broadly how you’re thinking about that?

Sure Phil and I can certainly appreciate a lot of interest given this climate that we are in right now. I’d tell you that right now we have no CapEx guidance but 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 our -- 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 disciplined investment planning given the economic parameters. I guess Phil I’d like to emphasize a couple of points recognizing that I am 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 cost 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 and 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, liability 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 the growing dividend and where necessary we’ll leverage our balance sheet to meet our commitments as appropriate.

And then a question on the buyback I mean obviously it could have been any number between 0 billion and 3 billion. But just wondering kind of why you specifically picked what you did? Are you trying to kind of target a certain leverage level assuming the strip or just how you’re generally thinking about it and more specifically just kind of wondering what would make you change it up or down from here again?

Sure Phil. Obviously, it’s a number of factors our share of 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 and we’ll continue to manage our business in a prudent manner throughout the cycle as we have said many times and that buyback decision will be really an outcome of our cash flow management. So, I’d just again emphasize that we remain committed to our investment program and of course paying our growing dividend.

We’ll go next to Doug Leggate with Bank of America.

Jeff it’s actually Jason Smith on for Doug. Good morning. Just coming back to the one-time items in U.S. refining your earnings looked 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, could you maybe give some color around those and maybe quantify the absolute impact for the U.S. and 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 hard 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 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 feed stocks 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 and most important capturing the most value from our integrated business model.

And maybe just on PSC impacts, you’ve gave some color on the sequential improvement I think it was 78,000 barrels a day positive and with oil down significantly from 4Q can you maybe just give any color around the incremental impact that that price is down?

Yes, you can appreciate that each of our contracts are unique and associated with the commercial arrangement. It’d be really tough to give you a rule of thumb because we do have in that category price impacts, you’ve got spend impacts, we have temporary volume impacts that are associated with the fiscal agreements. Broadly speaking you’re 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.

We’ll go next to Evan Calio with Morgan Stanley.

My first question maybe CapEx from another angle, net debt is up $7 billion in the quarter I know you reduced the buyback guidance yet, I mean 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 to the buyback lower reduced CapEx? And maybe just lastly on CapEx, I presume you already have a 2015 CapEx number and it’s more of a guidance question or just function how does that work? Thanks.

Evan, so I’d get you to think about it from a, it’s fundamental in how manage our cash in the consideration and balance of all the variables that we need to address the inflows, our commitment to fund investment plans as well as our dividend -- I don’t have any specific guidance for you and debt capacity or 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 have 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 will assess the cash and our funding options under arrange at outcomes and take a balanced approach to meet those obligations as I indicated. So in short I’ll come back to this message throughout our discussion that we remain committed to investment program that delivers on attractive return but also to pay a reliable and growing dividend.

And maybe second is part of the smaller issue just a question on the quarter, is there an asset sale loss and I missed that which would affect the lower tax rate for the quarter if you can talk me through that please?

So the lower tax rate that you’re 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 that Evan that our guidance of our effective tax rate is still consistent or about the mid 40%.

We’ll take our next question from Paul Sankey will Wolfe Research.

Just could you update us on what’s going on in Russia from your point of view, if anything and further to that which I know is a JV that was very important to your longer term result and production plan, can you talk about how you would define the attractive opportunities that you’ve mentioned, I assume you’re referring to M&A and whether you’d be more attractive to oil I would assume as opposed to gas reserves more attractive maybe in the new world order to U.S. reserves and maybe within the U.S., if you could set us in a toll about what you would consider and how you would define an attractive opportunity? That would be great, thanks.

Let me starting at Russia, broadly speaking, I mean there is really nothing new to report on that as you all know that sanctions are still in place and we will continue to fully comply. As we said previously that it does not apply to Sakhalin-1 which I’ll just take this opportunity to say that we’ve had extraordinary success really thanks to a very talented organization and a highly effected joint venture. We are very pleased with the successful start-up of our Kutendagi, 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’d say is built on an effectively mutually beneficial relationship with our partners. On the second item around attractive opportunities in M&A. Broadly speaking and we've talked previously about our asset management program and you would really think about it on for the full scope of how we have high-grade our portfolios through asset management and that maybe obviously have a ongoing component of divestments of non-strategic or lower value assets but also bringing in through acquisitions some new opportunities. And those maybe bolt on acquisitions, than may be new entries that are synergistic to our business. But Paul we stay very alert to value propositions, we're 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.

Yes I guess within that you are primarily interested in long-term reserves, right? I mean obviously you don't want to buy someone's decline curve, so it becomes a question of 2P and 3P I assume?

Yes. So Paul if we focus on -- again if we can get synergistic benefits like some of the bolts ons that we have 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 yes 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.

We will go next to Ed Westlake with Credit Suisse.

Just on I am trying to get a sense of again this CapEx question again. How much of your say upstream spends is kind of locked in for 2015 and how much wiggle room do you have in 2016 I appreciate this maybe 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?

Yes, sure. I would tell you that as we look at our overall investment program, we've been -- we focus on every asset that we have got regardless of whether it's as you have 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. But as I indicated we have very strong culture of driving those cost structures down, we have been very actively engaged with our service providers and we fully expect to capture savings in across the spectrum of our business from rig rates to labor and services as well as commodities. But I would be clear Ed that we're probably in the very early innings of this effort. There is a lot of strong reaction to the current price business climate and we think that with that it 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 will able to lower that cost structure and prove our overall longer-term returns given the financial capability that we have.

And then a quick quarter question. Asia natural gas production and Australasia as well down ticked in the fourth quarter versus the third quarter I appreciate there is lots of different demand drivers across a big business, but is there anything specific you would call out for that step down?

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 don't see as much of an increase there was a slight increase in Papua New Guinea though.

But in Asia there was well say a much larger business but that was also down generally?

Yes, it was generally at some facility performance downtime.

.:

The first question in terms of Venezuela I know you mentioned the arbitration ruling, can you just kind of confirm that that finalizes this process or is there any additional legs to kind of move forward on there?

Yes. Blake on Venezuela, there is actually two separate arbitration proceedings one was International Chamber of Commerce that I mentioned that we recognized the award on. The second was the World Bank's International Center for Settlement of Investment Disputes. What we recognized was the first one I will 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.

I hope this doesn't get too in the weeds but the second question is on the impact of the strong U.S. dollar. I am just curious if you could talk around how that's impacting your business with the rapid moves we've seen and may be what's then embedded in the quarter, as a result of FX?

Yes, in terms of ForEx, as you are probably very aware that it has offset 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.

We will go next to Brad Heffern with RBC Capital Markets.

I was wondering, if you could just go through Exxon's current thoughts on the global LNG market, you have several potential projects that haven’t FID’d yet, you think may be 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 still, as I said projected gas demand to grow about 1.6% per year to now in 2014 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 is a sufficient price structure in place to underpin those investments. We have gotten a number of projects across the globe that are in place. They are positioned to go ahead and compete for that demand profile.

And 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 but has the downturn in oil caused you to think any different way about, what's specifically your drilling for in the U.S.?

Not really, I would 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 this, generally a short cycle type investment. We can get on capacity pretty quick. So, we are very well positioned to do that, should the demand grow and the prices support it. I would also say that from a chemical perspective, our chemical business is very well positioned to take advantage of the lower commodity prices. Particularly in U.S. our manufacturing sites are highly flexible and can run across a wide range of feedstocks, from ethane all the way to gas oil.

We'll take our next question from Jason Gammel with Jefferies.

Thank you. I actually got a follow-on to both the questions that were just asked, just in terms of how you are managing the lower 48 business in the pricing downturn Jeff, are you keeping a relatively steady rig count or have you being laying down rigs the way that the rest of the industry has as well.

Yes, well that'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 wanted to makes sure that we had a good understanding of the resource performance and importantly, we wanted to make sure that we are fully integrating all the earnings 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, we've got, I just want to reinforce that we do have a very robust inventory of opportunities even in this price environment.

And 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. And then on the spot market, are you seeing significant demand weakness that potentially would even lead to reducing sold utilization?

So on the LNG business, I'd say that a majority of our LNG or 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. And also note that in our LNG contracts we have potential to divert cargos as well, which gives a lot of flexibility.

We’ll take our next question from Asit Sen with Cowen and Company.

Two unrelated questions. First on the issue of supply chain cost and your prior success with that. I was wondering if you could quantify annual third partly cause globally for the organization. Some of your peers have highlighted multibillion dollar opportunities for this reduction. And also any high level thoughts on recently announced oil service industry consolidation? Has anything changed on the ground for Exxon?

Broadly speaking -- I don’t have specific numbers. As I said previously we are as a mainstay in how we manage our business. We’re constantly working on that cost structure. We are very active with our service providers. As I indicated we’re probably in the early innings of that. We’ve seen -- 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? I said, was there…

And on the oil service industry consolidation, any thoughts on that or things have changed?

No, there is really nothing I have to say on that. We access all the service providers and competition is good and we have a very strict standard on what we expect from in terms of quality, performance and service costs.

And just my follow up is on U.S. onshore. Last quarter you had highlighted that Bakken was Exxon’s most active and conventional play with I think 13 rigs running. Could you update us on activity levels currently, and perhaps provide update on Woodford and Permian as well?

Yes, so 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-very encouraging list of opportunities and we’re making great success in integrating our learnings and driving down the cost curve.

We’ll take our next question from Paul Cheng with Barclays.

Two quick questions. I don’t know whether you have any number you can share. In your prior calls when we’re looking at the contract, is there a number you can share in terms of the send, maybe for the contract is over two years, still remaining? In other words I'm trying to understand that what is the percent of your supply cost that if we do see a substantial deflation in the industry cost structure, it's going to see a rapidly quick pass flow into you?

Paul, I don’t think I have any guidance on that.

Okay. And secondly that -- you’re saying that in the downstream you have a crude lag purchase. In fact 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 the fourth quarter absolute it was just over $600 million. And likewise in an environment where price is increasing you’d have the opposite effect.

Do you think the -- nice [ph] oil economy, so why we have such a big negative crude effect? And also that I thought the price finalization were made to your Saudi contract in a declining oil price environment. So it’d actually be a favorable positive impact. So I get that. I'm just totally wrong on that then?

So the crude lag effect is primarily associated with pipeline supply contracts standard terms to how the pricing is done.

Okay. Can you speak also -- this 600 primarily in U.S. then, I presume?

That’s correct.

And that -- 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?

Yes, 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 segment?

That is an essence the most of it.

We’ll take our next question from Allen Good with Morningstar.

Maybe if I could tackle the cost improvement question from a different angle. Is there any area that Exxon has identified based off trends of the past two years, where you think you may have more opportunity to cut cost relative to other areas. And I guess I'm thinking more along the lines of project type and in specific regions relative to the other ones?

I think broadly speaking -- we always feel like we’ve got opportunity to become cost efficient. From a capital prospective, 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 big a 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 is really sacred. We continue to identify additional opportunities to make our cost structure more efficient.

And then on asset sales, I would assume that you guys are more opportunistic on that level and I think you probably recall -- you said the approach of the -- if it's worth more to us or more to the buyer, we'll sell. And could you give me around your asset release interest that you may have you may have seen six months ago declined into today and should we expect maybe the asset sale slowdown over the next year to 18 months?

We’ve got such diverse portfolio of assets, I really couldn’t characterize for you whether time -- the interest is increased or decreased. Assets are so unique in their own right, and recognize that we're -- 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 longer has a strategic fit for business. So I’d leave at that.

We’ll take our next from Ryan Todd with Deutsche Bank

Maybe one follow-up question on 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 are talking about or is it a little bit of everything?

So this is a good opportunity to really talk more about it. In terms of our fourth quarter versus the third quarter performance, we’re up quite significantly on our volumes primarily driven by our projects. Quarter-on-quarter projects are up about 130,000 oil equivalents barrels per day. Those volumes are coming from Angola, primarily the Coak [ph] project, in Canada associated with the Kearl project in Papua New Guinea, associated with our LNG project. We had an increase in project volume associated with Malaysia to Loakim [ph] 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'd point out is that we've 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.

And then maybe one more LNG. I guess a couple of quotes on LNG which is -- is there any risk to the pricing in terms of your exiting LNG contracts in the current environment from periodic reopeners in the contracts? And 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've said earlier our existing LNG projects are a very significant part of our margin generation.

We will take our next question from Roger Read with Wells Fargo.

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 sort of incremental '15 impact is? A lot of these projects started at the end of '14 and roll into '15. If you could give us an idea of maybe the volumes impact there?

Yes, 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 will 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 we just -- it's the March event, we'll wait for that I guess is?

Yes, 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 3,00 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. And then earlier in some of the Q&A, you had mentioned specific to dealing with the cost structure and it sounded like to me both internally and your third parties. Any comparisons contracts you can do with previous downturns in terms of contracts that you have fixed here? An 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.

So no particulars on rig contracts or anything like that that, that are more onerous than prior times?

No. And I don't want to get into the 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.

.:

Jeff, just got a question on your pre-sanctioned pre-FID projects. A couple of your partners have been talking about pushing these out due to carrying some cost pressures and waiting for lower service cost et cetera. Specifically thinking about projects such as Tangese and some of the Austrilasian and Canadian R&D projects, is that something which you're also kind of factoring into with 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, it'd be a consideration. Broadly speaking we've 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. So while we don't forecast a -- 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 -- volatilities like we're seeing right now, we're 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 don't overreact to volatility in the market. But we're mindful. We're 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's 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'm 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's understood. Can I just ask a quick question on chemicals? Your numbers there seem to be holding up pretty well. I'm just wondering what you are thinking about chemical demand, in particular outside of the U.S going forward, because you're going to be seeing very much lower in [indiscernible] prices now. So what do you feel about the kind of pricing and demand side of that business?

Very well positioned. It's a great business. We've got the chemical facilities positioned throughout in North America. We're benefiting from the lower feed costs. We've got advantaged assets there in the Europe and Asia Pacific, our steam crackers really benefit from the lower price environment we're 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 the -- really an industry first.

Yes, I am just wondering about how the industry dynamic you're seeing out there in terms of demand and pricing -- I know you're well positioned but what are you seeing in terms of Asian demand, European demand.

Yes, Ian, our global demand is expected -- based on our assessment it's expected to grow above GDP, driven by Asia.

We'll go next to Alastair Syme with Citi.

Can you just come back to the deferred tax benefits and just explain what's going on? A comment please?

Yes so, we periodically will review our deferred tax accounts to make sure that we've got the right reserves in place, and sometimes that results in an adjustments which you're seeing this quarter.

It's not related to commodity prices in anyway?

No, it's just a prudent review of our deferred tax accounts.

Okay. And my second question -- some people have eluded to that -- this is the lag effect on pricing. If could just discuss on LNG, what the typical lag effect is and how -- 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 going to discuss the specifics of those. So you will see some impacts going forward. It really does vary by contract.

Okay, but it's sometime the first and second quarter, will be reasonable even?

Well, it depends on what prices do.

We'll take our next question from Pavel Molchanov with Raymond James.

First on the balance sheet, is it still the case that you are targeting maintaining AAA credit rating? And if so, how much debt do you think you can take on and still keep the AAA?

Yes so as I said earlier Paul, we don't have any specific guidance on debt capacity or our plans. We will asses our cash and funding options around a range of outcomes and we'll take a balanced approach to meet our obligations. But 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 play, if 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 a rig activity. I'll leave it at that there.

We'll go next to Guy Baber with Simmons & Company.

You highlighted the improvement to your underlying upstream margins through 2014 despite a 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 do you think perhaps the biggest drivers and biggest opportunities may be. And I'm thinking evolution of maybe project mix and ramp ups, costs, or focused portfolio moves, just wondering if there is anything specific you could share there that we should be focusing on? And then I had a quick follow up.

Good question Guy. I'd say I appreciate the recognition of the progress that we've made over 2014. And I'd say that, that's a result of several factors. One is this intense focus on capital efficiency and lowering our cost structure too has been the higher margin production that we've been adding to the portfolio due to our major project activity and our U.S. onshore drilling activity, predominantly in the three main liquid plays that we've talked. Both have been a significant uptick to our overall unit profitability.

That’s very helpful. And then my follow up was with 2014 now on the books, I was just wondering if there is any update you could share on base portfolio decline, how that performed versus expectations? And then big picture, did Exxon expect an increase in global decline rates just for the industry, given some base spending that’s perhaps being cut? And then is that an important component of your oil price, kind of fundamental outlook?

So 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.

We’ll go next to Paul Cheung with Barclays.

Just two very quick follow up. Do you have underlip or overlip in the quarter for your upstream production versus the sales versus the production?

So the overlipped and underlipped we have a -- my recollection was that we did have an underlip in the fourth quarter relative to the third quarter.

How about that versus the actual production?

Well, that’s what it is. Underlip versus the production.

Do you have -- can you quantify what is that number?

Sequentially it was about 90,000 barrels.

Okay, and…

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.

And that do you have -- and 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.

And it appears we have no further questions at this time.

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, there's intense cost control. I talked about it a couple of times and obviously excellence in project execution. And we really do look forward to sharing more with you in March with an update on our business strategies and our investment plans. So 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.