Exxon Mobil Corp (XOM) — Q1 2016 Earnings Call Transcript

Good day everyone, and welcome to this Exxon Mobil Corporation First Quarter 2016 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 & Secretary, Mr. Jeff Woodbury. Please go ahead. Thank you. Ladies and gentlemen, good morning and welcome to Exxon Mobil's first quarter earnings call. My comments this morning will refer to the slides that are available through the Investors section of our website. Before we go further, I would like to draw your attention to our cautionary statement shown on Slide 2. Now turning to Slide 3, let me begin by summarizing the key headlines for first quarter performance. Exxon Mobil earned $1.8 billion in a difficult business environment marked by low commodity prices. Cash flow from operations and asset sales totaled $5 billion in the quarter. These results demonstrate the durability of our integrated business enhanced by our relentless focus on managing those factors that we can control, including the effect of cost management, reliable performance and operational integrity. The highlight this quarter is our strong chemical results, which underscored significant gas and liquids cracking advantages at our integrated sites and differentiated capabilities across the value chain. The Corporation also continues to make steady progress on its investment plans. During the quarter, we benefited from recent capacity additions while reducing CapEx 33% versus the prior year quarter. We continue to effectively manage our spending while selectively investing in the business to meet long-term energy demand and importantly grow shareholder value. Moving now to Slide 4, we will provide an overview of some of the external factors affecting our results. Global economic growth remained weak during the first quarter. In the U.S., estimates indicate growth has slowed further since late 2015. In China, growth continued to decelerate; however, economies in Japan and Europe showed some modest improvement compared to the fourth quarter. Crude oil prices were quite volatile and decreased relative to last year while natural gas prices continued to fall. Global refining margins weakened on lower distilled demand and continued surplus inventory. However, chemical commodity and specialty margins strengthened on lower feed and energy costs. Turning now to the financial results as shown on Slide 5, as indicated, Exxon Mobil’s first quarter earnings were $1.8 billion or $0.43 per share. The Corporation distributed $3.1 billion in dividends to our shareholders. CapEx was just over $5 billion, down $2.6 billion from the first quarter of 2015, reflecting continued steady progress on our investment plans. Cash flow from operations and asset sales was $5 billion and at the end of the quarter, cash totaled $4.8 billion and debt was $43.1 billion. The next slide provides additional detail on sources and uses of cash. So over the quarter, cash balances increased from $3.7 billion to $4.8 billion. Earnings adjusted for depreciation expense, changes in working capital and other items, and our ongoing asset management program yielded $5 billion of cash flow from operations and asset sales. Uses of cash included shareholder distributions of $3.1 billion and net investments in the business of $4.5 billion. Debt and other financing increased cash by $3.7 billion, which included the impact of anti-dilutive share purchases. Exxon Mobil will continue to limit your purchases to amounts needed to offset dilution related to our benefits plan and programs, but does not currently plan on making additional purchases to reduce shares outstanding. Earlier this week, the Board of Directors declared a second quarter cash dividend of $0.75 per share, a 2.7% increase from last quarter, marking our 34th consecutive year of per share dividend growth. Moving on to Slide 7 for a review of our segmented results, Exxon Mobil's first quarter earnings decreased $3.1 billion from a year ago quarter. Lower Upstream and Downstream earnings were partially offset by stronger chemical results, and lower corporate costs. The corporate effective tax rate was 19% during the quarter, down from 33% a year ago, reflecting changes in our segment earnings mix and one-time favorable tax effects reported in the corporate and financing segment. On average, corporate and financing expenses are anticipated to be $500 million to $700 million per quarter over the next few years. In a sequential quarter comparison shown on Slide 8, earnings decreased by $970 million as stronger chemical results partly offset lower upstream and downstream earnings. Turning now to the upstream financial and operating results starting on Slide 9, upstream earnings decreased $2.9 billion from a year ago quarter, resulting in a segment loss of $76 million. Sharply lower realizations decreased earnings by $2.6 billion. Crude prices declined by almost $18 per barrel and gas fell more than $2.25 per thousand cubic feet. Unfavorable sales mix effects reduced earnings by $100 million, while all other items decreased earnings by another $250 million where lower gains on asset sales and less favorable tax effects were partly offset by reduced operating expenses. Moving to Slide 10, oil equivalent production increased by 77,000 barrels per day or 1.8%, to more than 4.3 million barrels per day compared to the first quarter of last year. Our liquids production was up 260,000 barrels per day or 11.5%, driven by capacity additions from recent project startups and continued good facility reliability across the portfolio. However, natural gas production decreased 1.1 billion cubic feet per day or 9.3%. Growth from major projects was more than offset by regulatory restrictions in the Netherlands, field decline, divestment impacts and lower entitlement volumes. Turning now to the sequential comparison starting on Slide 11, upstream earnings were $933 million lower than the fourth quarter. Realizations decreased earnings by $1.2 billion where crude declined more than $8 per barrel and gas fell almost $0.75 per thousand cubic feet. Favorable volume and sales mix effects improved earnings by $170 million including contributions from new projects and higher natural gas demand. All other items added $140 million, reflecting lower operating expenses partly offset by lower favorable tax effects. Moving to Slide 12, sequentially volumes were also up 77,000 oil equivalent barrels per day or 1.8%. Liquids production increased almost 60,000 barrels per day, up 2.3% from the ramp-up of new project volumes. Natural gas production was up 120 million cubic feet per day reflecting stronger seasonal demand in Europe, partly offset by regulatory restrictions in the Netherlands and lower entitlements. Moving now to the downstream results starting on Slide 13, downstream earnings for the quarter were $906 million, a decrease of $760 million compared to the first quarter of 2015. Weaker refining margins reduced earnings by $860 million, partly offset by $100 million of all other items, primarily favorable foreign exchange effects. Turning to Slide 14, sequentially, downstream earnings decreased by $445 million as weaker margins reduced earnings by $470 million, unfavorable volume and mix effects mainly from increased European maintenance activities decreased earnings by another $150 million. All other items provided a partial offset adding $170 million mostly from lower expenses. Moving now to chemical results starting on Slide 15, first quarter earnings were $1.4 billion, up $370 million versus the prior year quarter. Stronger commodity margins from liquids cracking in Europe and Asia increased earnings by $250 million. Higher global sales volumes contributed $80 million while all other items added another $40 million again from lower expenses. Moving to Slide 16, sequentially chemical earnings increased by $390 million due to stronger commodity and specialty margins. Unfavorable volume and mix effects were more than offset by lower expenses. Turning now to Slide 17, as you may be aware, Standard & Poor’s reduced its credit rating on Exxon Mobil by one notch to AA positive with a stable outlook. Earlier this month, Moody's reaffirmed its AAA credit rating on the corporation with a negative outlook. We want to be clear that nothing has changed with respect to the Corporation’s conservative financial philosophy or prudent management of its balance sheet. Our ability to access financial markets on attractive terms remains strong. Exxon Mobil's financial strength remains a significant competitive advantage and enables us to create long-term shareholder value despite near-term market volatility. Exxon Mobil has a long history of prudently managing our capital structure and financial capacity through numerous commodity cycles and fully expects to manage through this one under those same prudent financial principles. Moving now to Slide 18 in an update on upstream projects in the exploration program, four major project startups year-to-date added 170,000 oil equivalent barrels per day of working interest production capacity. In January, the Heidelberg project in the Gulf of Mexico started up several months ahead of schedule and under budget. Heidelberg is a five well subsea development in 5,300 feet of water tied back to a central trust bar production facility with a peak capacity of 80,000 barrels of liquids and 80 million cubic feet of gas per day. In Australia, Train 1 or the Gorgon LNG project started out in March; as you know LNG production has been suspended due to mechanical issues which the operators are actively working to resolve. In April, Exxon Mobil started up two more projects ahead of schedule and under budget, Julia in the Gulf of Mexico and a Point Thomson initial production system on Alaska's North Slope. Julia is a capital efficient subsea tieback to an existing production facility, another example of Exxon Mobil's capability to cost-effectively develop new deepwater resources by leveraging existing infrastructure. Production will continue to ramp up in the coming months as two additional wells are completed. At the Point Thomson project, two injection wells will work in tandem with the production well cycling up to 200 million cubic feet of gas per day to an onsite central processing facility to extract about 10,000 barrels per day of condensate. Notably, the project provides a foundation for future gas development on the North Slope and further demonstrates Exxon Mobil's ability to safely and responsibly execute complex projects in challenging and remote environments. Two additional major projects are expected to come online later this year, namely Kashagan and Barzan, closing out to six major projects start-ups planned for 2016. Turning now to our exploration program where we continue to pursue and evaluate high-value resource opportunities. Offshore Guyana, we completed the largest proprietary 3D seismic survey in our company's history and we are currently drilling the Liza-2 appraisal well. Data from the appraisal well and the 3D seismic will be used to evaluate the block’s potential and development concepts. We do plan to drill additional exploration wells with the existing rig. Offshore Uruguay, we are participating in the Raya-1 exploration well in Block 14, where we have a 35% interest. And in the Gulf of Mexico, we were the apparent high bidder on five new exploration blocks and lease sale 241. Final award of these blocks is expected later this year and we will further strengthen our 1.1 million net acre position offshore. Branded utilized proprietary seismic imaging technology and continue to build the portfolio of attractive future drilling opportunities. So in conclusion, Exxon Mobil remains focused on creating value through the cycle. We are advancing self-help initiatives, driving down costs, increasing efficiency, proving reliability and capturing incremental value across the integrated portfolio. The first quarter Corporation earned 1.8 billion in a difficult business climate benefiting from structural advantages in our downstream and chemical operations. The integrated business generated $5 billion in cash flow from operations and asset sales. We continue to successfully progress our investment plans, increasing upstream production volumes to 4.3 million oil equivalent barrels per day, while reducing CapEx and upholding our reputation as a reliable operator. Exxon Mobil paid $3.1 billion in dividends during the quarter, sharing the Corporation's success directly with our shareholders, and we remain steadfast in our commitment to pay a reliable and growing dividend. That concludes my prepared remarks, and I would now be happy to take your questions.

In the downstream, volume for both gasoline and diesel seemed to be weaker than the industry markers during the quarter and also over the past year, so my question is twofold: one, how much of the weakness can be attributed to items such as divestitures and unscheduled downtime, meaning what is the real apples-to-apples comparison for the company? And then two, with these results, I wanted to see if you had a little bit more color or maybe a more specific read-through into the key economies around the world. You touched on that at the outset, but I just want to see if you had a little bit more specifics in that area?

Yes, I think on the first item, just stepping back a little bit on the downstream, our fuel margins were weaker with distillate being at five year lows due to, as you are much aware, global surplus capacity and high commercial inventories. That was aggravated by warm winter in low heating oil demand and particularly in the U.S., and less demand in the energy sector, although gasoline margins remain strong and demand is growing above capacity growth. We saw, as I said in my prepared comments, that from a volume perspective, we had increased maintenance activity predominantly in Europe in the first quarter of this year if you compare it sequentially first quarter to fourth quarter; we had a much higher load on planned maintenance. I'll say broadly speaking, Doug, in 2016, our overall planned maintenance would be lower than in 2015, but we will have a fairly heavy first half.

And then maybe a read-through, a little bit more specific read-through into the global economy. I mean, the numbers were weak; I think you highlighted that, but do you have anything else to add to your comments earlier?

No, I mean, I think I would step back more so from a macro perspective on supply and demand. If you look at the last decade, overall demand has increased about 1 million barrels a day, maybe a little less than that. And if you look at demand growth here in the last two years, plus this year, we're seeing demand growth in excess of the 10-year demand growth. So, I think that’s a good indication of pretty healthy demand increase, very consistent with our outlook for energy, with oil growth growing about 0.6% per year and gas growing about 1.7% or 1.6% per year.

Okay and then second Jeff, the return on capital and valuation have declined versus the previous cycle for most energy companies, and I think you have prompted one of your competitors to indicate that returns, even at the expense of growth, would probably be their new path forward, and so I'll resonate pretty clearly that returns are still important for Exxon Mobil. But my question is whether there has been any specific movement towards changing the future balance between spending and shareholder distribution or do you guys think that as pre-productive capital normalizes, the situation will resolve by itself?

Well, from a macro perspective, as you know, we're constructive on oil and gas demand. We have maintained a very disciplined capital allocation approach for the longer term horizon. That hasn’t changed. We've been through these down cycles before, and we've built this business to be very durable in a low price environment. We've maintained financial flexibility throughout in order to continue to take advantage of opportunities, whether they're at the top of the cycle or at the bottom. The return on capital employed continues to be a very strong focus for us. You've heard us talk in the past about a strategic decision years back to go ahead and invest in a number of major upstream projects concurrently in order to capture unique value that probably no one else could capture, like Exxon Mobil. That had a burden on the return on capital employed for a period of time, but rest assured, all those investments are being tested across our average financial performance to ensure that we are adding accretive value, and we still view the return on capital employed as a key metric regarding how effective our value choices are.

My first question is about unconventionals; you have reduced the number of rigs from a peak of 96 to just 16 today, with four in the Bakken and the Permian given the current environment. While I understand you have outlined significant potential growth for Exxon, I would like to clarify how you view increasing activity during a recovery. You have many options available, but what factors will influence your decisions, such as oil prices, cash flow targets, or fundamental supply and demand outlooks, in this shorter-cycle resource during a recovery?

Yes. Well, let me ask you to think about it this way. And for Exxon Mobil it really starts at the micro level with our view of supply and demand, as I explained to Doug a moment ago, we have been very constructive of long-term energy demand. For our long cycle investments it's really a function of project maturity that maximizes value best, keeping in mind our prudent financial management to ensure that we are meeting our commitments and maintaining financial flexibility. Now for shorter cycle investments, that you're really asking about, by and large, it is the same but with a much narrower focus on the near-term business climate. So, it's not really a price trigger for us, it's really a combination of all the relevant factors to ensure that we are maintaining our very prudent financial management while also ensuring that we have financial flexibility to continue investing when opportunities come along. As you know, we're spending $23 billion this year, which represents a lot of investment activity.

I know there is great consistency to your approach through the cycles and through time. Do you see the allocation changing in any way that favors a shorter-cycle resource versus more conventional allocation given some of the changes that could be evident through the cycle?

Yes, I think Evan. It’s a good question and probably worthy of a deeper discussion sometime, but I’d tell you that the mix of shorter cycle and longer cycle has changed over time, obviously as our inventory base grew in the lower 48 unconventional. But our fundamentals are how we manage the business haven’t changed at all and the choices that we are making are driven by how we maximize shareholder value. All these investments compete and as we have said previously, we are not opportunity constrained; we’ve got a very deep inventory across the portfolio not only in the upstream but also in our downstream and chemical business. Just making sure that when we progress a project and investment decision that we have identified the optimized value proposition for it and it's competing for that capital across the portfolio.

I was wondering if you could put a finer point on the chemical's performance during the quarter. It seemed like it's a little bit stronger than maybe the micro environment would have suggested; I think you cited cost savings or operating cost savings in your prepared remarks, but is there any more detail you can provide around it?

Yes, there has been strong demand growth in chemicals, growing about 1.5% of booked GDP, which creates a favorable investment outlook moving forward. Looking at the segments, commodity growth has been robust, especially in Europe and Asia. This rapid demand growth positions us well for future investments. Margin benefits are primarily due to the quicker decrease in feed and energy costs compared to product realizations. Additionally, our gas crackers continue to perform well, with a competitive advantage in feedstock in North America, allowing us to compete effectively in the global demand market, even with improved margins from liquid crackers.

And then looking at CapEx, I think the number for the quarter is pretty well below in terms of a run rate basis, the 2016 CapEx guidance. I am curious if you are expecting seasonality in that number or if there is a reason to expect that that’s going to increase meaningfully going forward, or if you are actually truly below the CapEx on a run rate basis?

Yes, Brad. Just to set the stage, as you all remember our CapEx for 2016 is down 25% set at about $23 billion. The organization has not taken their foot off the pedal; they continue to work towards identifying capital efficiency opportunities we’re still capturing market savings and importantly, and I want to emphasize that we're delivering our major projects on schedule and on budget in many cases ahead of schedule and below budget. All of that is translating into capital savings that you are seeing in the first quarter of this year. We are not going to change our capital guidance at this point, but I'll tell you that we're making good progress. I'll just say for a moment that the organization has really responded to the low price environment in a very effective way; they keep very focused throughout the cycle but particularly at the bottom of the cycle and have really risen to the occasion and continue to identify substantial opportunities for the Corporation to save both cash and OpEx.

I also have a couple of questions if I may. My first one is really about some more specific on the oil sands business. It's been a fairly large part of your project growth and the shift towards liquids and so on, but obviously in this environment, I have to imagine it is a substantial drag on your cash margins. So, I'm just wondering if you could to the extent you can just give us some idea what the economics of Carol in your oil sands business generate Cold Lake and so on it looks like in this environment and what I'm really thinking about is the kind of free cash torque that could generate in a recovery scenario, and I've got a follow up please?

Yes. Well, I mean generally speaking, the oil sands certainly no doubt profitability is compressed in this price environment, but the organization once again keeps very focused on the fundamentals, particularly our cost and reliability, and they are making really good progress refining structural enhancements that create margin at the bottom line. If you think about the resource base that we've got in oil sands, we've been working in the oil sands now for over three decades including technology development and on the mining side, I think Carol is a great example where we applied proprietary technology that was able to reduce our capital investment, our operating cost and improve our environmental footprint that will increase long-term value. The same is true for the in-situ operations; I mean we've been optimizing our cyclic stream operations at Cold Lake for a long time, and we are identifying additional technology benefits like solvent-assisted steam-assisted gravity drainage technology that will improve, once again, the recovery and lower our cost and improve our environmental footprint. I think it's a testament to how Exxon Mobil manages its portfolio; we work the project management and execution very, very well and then when it starts up, they just keep on working on that cost structure and create margin because we know we can't count on price, what we have to count on is the things that we control, that being cost and reliability and our integrity of the operations. But the last point I’d make is remember we also get value across the full value chain because our upstream is fully integrated with our downstream and chemical business.

Jeff. My follow-up, I'm going to have a stab at this one and it might be a very short answer, but on Guyana can I frame my question like this: my understanding is that the appraisal well is something of a two-stage effort. Stage one being a treat before the drill sand test, and I'm just curious to the extent you can share with us whether that well has achieved its objectives and the additional plans perhaps to bring a second rig in and any comments around the additional prospects that have been identified? I realize it's early, but just looking for any update you can share on whether that well achieved its objective?

Sure, Doug. And I understand the interest that you and others have about Guyana. I mean we were certainly very encouraged by the discovery well; the organization moved quickly to get a dealership contracted and get it onsite to appraise the Liza discovery well. The well spud in February; we do plan to drill multiple wells this year. Liza-2 is progressing according to expectations; we will plan to test the well and we should complete that activity mid-year. As I said in my prepared comments, we did complete the 3D seismic survey on the Stabroek Block and we began a survey on the Canje block, which we picked up to the east of the Stabroek Block. The well and seismic data is being assessed real-time in order to provide insights into the discovery and the ultimate block potential. We do plan on moving the rig from the Liza appraisal well over to a new prospect to the Northwest after it is done at Liza.

There is actually quite a bit of enthusiasm developing for NGLs in the U.S. right now among the investor community. I was wondering if you could offer sort of a how that might impact an outlook on how that might impact Exxon going forward in the context of your overall gas outlook, and you could even get more esoteric if you want regarding heat content and all the benefits that you might see in your unconventional gas business, given the fact that U.S. earnings, U.S. upstream earnings have been dragging a little bit here for the past few quarters?

Yes. Well, it's a good question because it really highlights once again the benefits of the integrated business that we've got from the very large resource inventory and unconventionals in the U.S. all the way through to our chemical business. What's important is that we have built the chemical business to have a very wide flexible range of feedstock capability, including ethane, propane, butane, all the way to gasoil. So, we've got significant flexibility within the chemical business to modify the feedstock in order to maximize margins. I'd say the same is true for Europe and Asia, particularly in Asia Pacific, in our Singapore refinery; cracker that we have an unprecedented range of feedstocks including the ability to crack crude oil which is an industry first.

And then secondly on M&A, I think Mr. Tillerson was pretty clear at the Analyst Day that the organization is not interested in kind of taking on encumbered assets but Exxon Mobil has pretty good currency here, and I was wondering just in the context of whatever S&P's reasoning was in the revision if there is an opportunity to maybe equitize through M&A or asset additions or if that's even a factor, considering Moody's still has the stable rating?

Yes, Sam, I'd tell you that nothing has really changed on how we manage our portfolio and asset management includes the potential for accretive assets through acquisitions. As we talked previously and as you heard from Rex, we keep very alert to where there are potential value propositions a high grade or existing portfolio, we're only going to pursue those acquisitions that we think have strategic value and are going to be accretive to our long-term returns, and it's got to compete with the existing inventory investment opportunities that we've got. We've got to be patient. We want to make sure that we keep a very wide aperture on what the opportunities look like; I think we've got a good handle on where there are opportunities, but we need to make sure that it is value accretive to the business and once we are able to lock in on an opportunity like that, you will hear about it.

First question on the quarter; you mentioned some color on the tax rate. It sounds like you separated it into two pieces; one was mix and the other was some one-time effects in the corporate and financing segment. It sounds like the corporate and financing piece you expect to kind of revert to the 500 million to 700 million a quarter; I was just curious maybe on the mix side, kind of what drove that and if you think about the full year tax rate, would you expect that to still be similar to last year at current oil price levels?

Yes, on the mix side, I'd tell you it always has to do with the relative contribution between U.S. international between upstream, downstream and our chemical businesses. You can just sense from my comments that there was a lot of complexity in that. In terms of what I expect going forward, our guidance would stay at an effective tax rate of between 35% to 40%. Now if we're in a lower commodity price environment like we saw in the first quarter, we're probably looking at something less than 30%.

Second question is just maybe a follow-up on the balance sheet. Looking at it slightly differently, your absolute debt levels are now around $43 billion, and I'm just kind of wondering how you feel about that comfort-wise, as you look through the cycle? And in a better environment with more cash flow, is that pay down on an absolute basis in any way a priority or would you be thinking about other uses of cash?

Well, I mean, obviously one of the considerations when we think about our capital allocation is retirement of debt, so we'll keep mindful. But remember we've got a very strong balance sheet; we'll look at the relative decisions around investments in the business, the pace of investments, our commitment to our reliable and growing dividend and then appropriately consider long-term debt levels. It's all about maintaining prudent cash management, maintaining our financial flexibility. We will continue to be disciplined in our investment approach; we are not going to forego attractive opportunities. But we will continue to assess our cash and our funding options around a range of options and take a very balanced approach on how we go forward in our capital deployment.

If I were to just clarify, would that pay down be a priority over buybacks?

That’s a decision that would be taken by the Board; that will be a function of a lot of factors, Phil. I wouldn’t leave you with any impression that there is any prioritization that I am conveying.

Jeff, I have two questions; the first one may be a little bit more detailed and earlier just let me know. If we're looking at the economics, have you talked to your downstream people whether right now economic to bring Naphtha into the U.S. gasoline pool or that you're better off to ship Naphtha into your cracker for the petrochemical in Europe or Asia?

Paul, you are asking what about bringing Naphtha?

Importing it into the U.S.?

No, exporting is not an option at the moment since we still have Naphtha available in the country. My question is whether you have discussed with your refining and chemical teams if it is more cost-effective for them to incorporate the new Naphtha into the gasoline pool in the U.S. or to export it to overseas markets, such as Europe or Asia, for use in petrochemical processes. Yes, we maintain tremendous flexibility on our feedstock options and that’s a real-time optimization that we are managing, and we will optimize those feeds based on the best available returns. That’s including moving feeds between continents.

Yes, but just curious that I mean, do you have any prior insight that you can share at this point that, how is the economics that have shifted, is it more in favor of branding it into the gasoline pool in this country or that is exporting?

Yes, Paul I really don’t have anything else to share on it other than to say that it's a dynamic issue that we continue to optimize, and I would say that we are very well positioned to ensure that we are making the best value towards it with respect to our feedstock swing.

The second question is that for the Point Thomson, you had mentioned in your prepared remark that it is also gives you a platform or a demonstration for potentially in the future Alaska LNG project. Let's assume that if the Alaska LNG project won't go ahead and would be not economic at all. Is the Point Thomson still a good investment in here by itself with all that purpose?

Yes, I would tell Paul that we look at these decisions on a long-term basis and given the constructive view of what we think gas is going to do over time, we are confident that the Alaska gas will be commercialized; as to how that actually happens may vary from what we are currently considering. But we have been very active with our partners in the state to identify the highest value opportunity in order to commercialize that gas, and it's going to compete on a global perspective. What's going to be really critical is getting a transparent, predictable and stable fiscal structure in place in order to make sure that it underpins such a significant investment.

I was hoping you could share a little bit about the rationale of the dividend increase. I know during your Analyst Day you kind of provided a cash flow breakeven, potentially in 2017, it sounded like then your remarks today you alluded to some capital efficiency and maybe potential for capital to be moving down. So I didn’t know if it would be fair to think that that cash breakeven number has potentially moved down, and maybe if that played into your thoughts around the dividend increase?

Yes, I think you are referring to the cash flow neutrality slide that we shared with you during the Analyst presentation, and if you recall, it's just a perspective of how we are managing our cash and how we manage the business. The organization is always trying to reduce that cost structure and improve the ultimate margins. And you are correct; we feel fairly confident that we can achieve cash flow neutrality into the future. I mean what we shared with you during the Analyst Meeting was a very wide range on prices but one that’s reasonable with the low end being $40 flat real, and you can see that we have good potential to reach that cash flow neutrality particularly in 2017 and forward. As I said earlier, we continue to reduce our cash expenditures and making good gains. I would tell you that when we make the decisions around capital allocation, it's a consideration of a lot of factors; we are going to balance our long-term investment with our shareholder distributions. Nothing has changed but I will tell you that we remain very committed to that reliable and growing dividend.

Okay, great. The second one is just kind of project specific. I know you mentioned Kashagan coming online later this year. I think there have been some press reports suggesting that could get pushed out to ’17. Can you remind me, I believe Exxon was ready to take over operatorship? Are you formally controlling the new flow on that or are you relying on peers at this point?

No. The Kashagan is managed by the North Caspian operating company. And which you may recall hearing is that, that was restructured in a more conventional manner and Exxon Mobil seconded the Director for NCOC. In terms of timing what we're doing there is we're replacing the onshore or offshore gas nova pipelines where NCOC is making good progress; they are progressing as per plan with the intention to complete that by the end of this year and start the facility.

So two upstream questions one on Upper Zakum and one on West Africa. On Upper Zakum in Abu Dhabi, Jeff, there were talks to expand capacity to over 1 million barrels a day. Could you update us on the current thought process on expansion and where production is currently? And secondly, in West Africa, Exxon had decent success last year in starting up the new projects Kizomba in Angola and Erha in Nigeria. How would you characterize the current operating environment in some of the key countries given all the reported fiscal stress? I know it's probably a generic comment but any color would be helpful?

Okay, Asit. On Upper Zakum, current production is around 650,000 barrels a day. The project itself is progressing well to increase capacity ultimately to 750,000 a day. We are continuing to evaluate the opportunity to expand to a 1 million a day development. Nothing more to share on that, and what is that?

And Jeff on the timeframe for 750, is what timeframe?

Getting up to that full 750? I don’t recall, but probably around by 2018. On West Africa, let’s just say we've made some really good progress. Just a broad comment about globally there, with country budgets feeling the strain of lower energy prices, it is slowing down investment globally, and that is a challenge to make sure that we progress those investments at a pace that is consistent with the resource owner. I'll say that we have a very strong inventory of opportunities in West Africa, but we've got to do it consistent with confidence in the fiscal basis in which we are making those investments.

I guess if we could talk maybe a little bit about cost deflation, kind of where are you progressing both on the CapEx and the OpEx side and whether that’s consistent with one of the questions asked earlier, if there was any seasonal component to that, that we should be thinking about?

So just a recap for the results that we had last year, we were able to reduce our total CapEx and cash OpEx by about $16 billion year-on-year, representing about a 16% decrease. In terms of going forward into 2016, nothing has really changed. We continue to manage the cost side as we always have, focusing on structural efficiencies, market savings while maintaining operational integrity. I will tell you, Roger, we still believe there is significant opportunity in streamlining the business and reducing the cost structure, and I would say it's early in the year; we’re seeing a similar trend line as to last year, but we will maintain that relentless focus on cost regardless of whether we are in a low price environment or in a high price environment. Just to give you a bit of a perspective again being very early in the year, our upstream unit costs for OpEx are down about 9%.

And along those same lines, at this point oil prices are rebounded, the market is starting to think about an ultimate recovery in drilling activity. Do you take advantage, consistent with your view that there is a lot more cost to get out? Is this a point at which you'd want to sign contracts, kind of lock in service capacity, service pricing, kind of anywhere around the world really?

I'd say Roger that, in the downturn, we've been high-grading our service providers and we’ve been locking in more favorable, more efficient service contracts. So it's not something that we had stopped doing. One of the advantages of Exxon Mobil is that we're able to invest through the cycle. That means that in a down cycle, we're continuing to spend a significant amount of money to capture value opportunities associated with that down cycle. So, of course, the organization, and you have heard me talk previously Roger about the global procurement business, but it’s all focused around finding the lowest life cycle cost, and you are correct to say that in a low price environment, there are some unique opportunities that we want to walk into.

So, clearly $48 Brent is not a great price but a heck of a lot better than $30 a barrel Brent, and so it feels like this market is moving in the right direction, demand is growing and we're seeing signs on OPEC supplies coming offline. I just want to reconcile that with your view, or does Exxon believe that we're starting to see the signs of a sustained recovery in energy prices, particularly in crude? And then because you get to see the world through your portfolio, one of the big debates is a non-OPEC supply outside the U.S. really rolling over because of the decline rates. Are you seeing evidence that that supply outside the U.S. is actually falling off?

Yes, the first thing I'd say, Neil, and it's really a good guard around how the macro is looking and how the sector will respond to it, I'd say first and foremost is that remember, we are price takers. We are not counting on price growth; what we are focused on is really maintaining a focus on the things that we control in order to create margin. So regardless of what it's going to do, it is going to do it, and we'll keep focused on the things that we control. The second thing I would say in just a little bit more expansion of what I was sharing with Doug earlier is that underlying demand growth has been generally strong and we expect this year would be in excess of the 10-year average. I would say that in the first half of 2016, we’re still oversupplied by about 1.5 million barrels per day. We do expect to see conversions in the second half with seasonal demand growth, but that's going to widen again in the first half of 2017. Remember during this period of oversupply, we've been building up commercial inventories since about the year in 2013, so taking forward, we're seeing conversions over supply and demand into the future but we have got this overhead of supply that’s going to also have to work off over time. So, we're heading in the right direction in terms of how and when that will happen will be anybody's guess. Remember there is still a bit of uncertainty in terms of the supply trend and the economic growth near-term, but clearly we're seeing, as you are all aware, we're seeing North America supply dropping off pretty significantly now.

I appreciate that Jeff. And then I have two questions, related questions here. First is, any update on Torrance? And then second, what's the latest on Groningen?

So on Torrance, we have completed the repairs of the electrostatic precipitator and we have received the approval from the regulator to go ahead and start operations. There are a number of things that we need to do to get it up and capacity demonstrated, but we do expect the formal change of control to happen mid-2016. On Groningen, as you know, we continue to have a pretty significant impact on volumes in the quarter; it was close to 600 million cubic feet a day. NAM has made the submission for the new production forecast going forward, and my understanding is, is that the regulator will review that by September of this year. Right now the cap is 27 billion cubic meters, but it has the potential to grow up, depending on what demand requirements are.

I was looking back at the interview that Rex Tillerson gave after the Analyst Meeting when he was asked about the AAA rating. What he said quite specifically is that there have been periods where Exxon's financial metrics have been worse than they are today, but you still retained a triple A rating. Obviously, as you mentioned in your remarks, you have been downgraded by S&P. Naturally, I went to S&P and what I saw there was the comment that maintaining production and replacing reserves will require higher spending from Exxon. It seems that given the financial metrics are not the issues that it seems there's an upstream issue that S&P is concerned about. Can you talk about your ability to maintain production and reserves at the current level of spending and address whether or not they're correct in thinking that you are going to have to spend a lot more to maintain reserves and production?

Sure, Paul. Well, first, I’ll remind everybody that we've got a very large inventory of investment opportunities, over 90 billion barrels of resources in our portfolio. If you recall in the analyst presentation, we provided a little bit more insight as to the type of projects and their potential capacity they can bring on over the time horizon. What we need to do is we need to make sure that as we mature that inventory of projects, we are doing it with the greatest value proposition, and I think we have made great strides in finding opportunities in order to reduce the cost structure going forward. I would say though, Paul, that we've gone through these cycles for a long time. We have been able to maintain a very strong balance sheet; we have maintained our financial flexibility to the ups and downs. Our inventory looks very attractive going forward; so we think all the elements are set right to continue to invest into an attractive way to maintain our initiative leading return on capital employed. The other point I’ll remind you is that, as we showed in the analyst presentation, we have done very well in terms of efficiency deploying investment dollars. If you recall the upstream capital efficiency chart that we used in an analyst presentation chart, our capital employed over proved reserves, clearly we are distinguishing ourselves relative to others.

Okay Jeff, because of time constraint, you again mentioned return on capital employed. I really struggle with you losing money in the upstream on an earnings basis, particularly in the U.S., and how you reconcile that with the measure of the return of capital employed. Typically, we don't look at that; we look at the cash flow measure. Can you help us with the DD&A upstream particularly in the U.S. so we can get to the cash returns that you're making as opposed to?

We have got a very strong portfolio in the upstream and remember that we invest on it with a long-term view that’s informed by our long-term energy demand outlook. All of our assets are managed to maximize the returns to the lifecycle with the objective of maintaining positive cash flow in low price environments. We will continue to focus on those things that we control, cost reliability, operational integrity. Importantly, we will invest in attractive opportunities throughout the cycle that further enhance the asset profitability. We see significant value in our assets. Yes, there is a low price; we are in a low-price period like we have been in the past as I have said, we really design these assets to be durable during a low price environment; they continue to generate. Our producing assets continue to generate cash flow and over the long term, we will continue to demonstrate industry-leading returns on capital employed.

And I just had a question on your project execution. I think Exxon has clearly shown leadership amongst your peers on project execution over the last few years, but Exxon doesn't seem to have sanctioned any major upstream projects of note in the last couple of years. Do we see anything on the horizon to be sanctioned for this year, so I'm just wondering how you intend to benefit from the quality of your project execution if you're not progressing with projects of the moment?

I’ll tell you that we will announce our FIDs after the company has made that funding decision, so we really don’t project it. But as indicated just a moment ago, we gave you an insight through our analyst presentation and the F&O as to the type of projects that we are currently working on, and we're really taking this down cycle as an opportunity to retest the value proposition for each one of these investment opportunities. There are some incremental benefits that we are able to capture through anywhere from design changes to different ways to execute the project given the service market to fiscal basis. This is a good opportunity to step back and make sure that we are really capturing the most value from these investments. We gave you some line of insight on the upstream, and I’ll remind you that we've got 10 major projects still underway in the upstream that will start up between 2016 and 2017. Additionally, we maintain a very active high-value work program and we gave you some insight on that during the analyst presentation as well, with a very deep inventory of opportunities. In summary, I would tell you that we have a large inventory of investment opportunities that are in various stages of planning execution. When we get to the point where we've made an investment decision, we will share that publicly, but the pace would be consistent upon project maturity to maximize value and our prudent financial management, and of course remember, Anish, that we've got a number of very large investments underway in our downstream and chemical business.

And just one follow-up more specifically on Nigeria because you've got a number of projects that have been in your project queue for a number of years, the South Oil field projects that you gave also Oxy field. I see you've added yet another project, Aurora West, into that project queue. Just wondering what has prevented you from sanctioning some of those projects? They have been around for a long time, and what needs to change in Nigeria for you to be able to go ahead with projects?

I would tell you that some of these projects are a function of optimizing the design all the way through to getting alignment with partners and establishing the right fiscal basis to go ahead and make the investment.

Just on gas, we've got oversupplied markets in the U.S., Europe and in Asia. Now clearly the best cure for gas prices being low is low gas prices; demand will probably pick up as a result of the time. Can you give us some sense of the magnitude of potential gas declines across the portfolio you exercise capital over the next four or five years?

Yes, you are talking with respect to our portfolio, Ed?

I'm really thinking about base business. Obviously, we know that you've got some new projects coming on stream operated by others like Gorgon, etcetera?

Yes, and you've seen our volumes, your gas volumes have dropped off in part largely due to a switch from gas growing to higher value liquids drilling during this down cycle. Gas, Ed, we continue to be very constructive, growing about 1.6% per year primarily driven by the power sector. The LNG we expect to triple from current capacity between now and 2040. So, I think we've got the long-term value proposition well within our sight and it's just pacing those investments consistent with that demand growth to make sure that we capture full value for it. But we've got a very deep inventory of gas, and if you look at our improved reserves, it's somewhere around 45% to 48% of our total improved reserves when compared to our resource base. And then of course importantly, it adds significant value to the value chain; it provides an advantage feedstock for us for our steam cracking here in North America. You may recall that we are in the process of progressing the expansion of a bay count for adding another 1.5 million tonnes per annum of cracking capacity, in conjunction with adding polyethylene lines over at Mont Belvieu. So, it's got a significant component of our future and a very deep inventory, but pace would be a function of demand.

Maybe a specific on Asia gas; you went I think from 4.1 down to 3.8 in the quarter. You mentioned PSE impacts in gas; maybe just run through what's happening there. Is it sort of customers exercising low GTQs on the LNG contracts or is there something else going on?

There were three major drivers there. One was planned maintenance, second one being asset managements and divestments investments, and the third one being price impacts.

So you're not seeing customers exercise low quantity crude oil ounces?

Well, I can't really talk about specific contracts, but it's primarily driven by the three items I shared with you.

A couple of questions for you. You talked about the North American U.S. lower 48 liquid productions falling, but ExxonMobil's price isn't falling; it's going up. Is this a kind of deliberate decision to invest counter-cyclically? You talked about your long-term vision, etcetera, or is it something specific to your acreage where you're getting more barrels out of your existing wells because you're contributing to the problem rather than the solution if you're growing your lower 48 volumes? And I have got a follow-up after that.

I tell you Ian that, as I said earlier, we're able to continue to invest in the down cycle, and that provides an opportunity for us to capture lower cost structure in the investments that we're making. Particularly in the lower 48 unconventionals, it's allowed us to hydrate the rig activity; we're down quite significantly in terms of now we're down to about 16. We have reduced our activity materially. So, we continue to pursue the attractive unconventional opportunities that we have, predominantly in the Permian and Bakken, and we're getting great value for it. It just shows the value proposition that ExxonMobil is able to provide because we have the capability to invest through the cycle.

Okay. And my follow-up question is on chemicals. Obviously, very strong numbers in this quarter; the environment is clearly pretty favorable out there in terms of natural gas prices and the fact there's a lot of maintenance activities out there, so lower production. But looking a little bit further forward, there is more volumes coming on stream, you're building capacity as well. Do you see this kind of chemical cycle at the peak now and then going into a bit of a trough toward the second half of this year and into next year, or does Exxon have a more positive view of the market?

Currently, olefin and polyolefin have been pretty tight and demand is continuing to grow; it's outpacing capacity additions, and I think that's an important investment opportunity. Remember, this is all our investment decisions, Ian, are really founded on our view of long-term demand and on the chemical side, as I mentioned earlier, we expect demand to grow about 1.5% above GDP. Now, I'll tell you that underlying demand growth across the olefin and polyolefin, the aromatics, and our specialties has been fairly robust. Now sometimes the supply capacity additions are outpacing that and that's what you're seeing for instance in paraxylene, but broadly speaking, the demand is robust and it's going to continue to grow, and we think it presents some investment opportunities.

Just a quick one for me Jeff, on Guyana, you have multiple structures in your lease area. In the event that you have multiple successes, should we consider Guyana to be kind of an analog to what you did in Kizomba a while back in terms of design one build many? And then my other question is, can you bring some of these longer-cycle projects forward to take advantage of excess E&C capacities that I mean you did discuss kind of how you're optimizing things, but can you bring longer cycle projects forward to take advantage of low-cost environments?

Yes. On Guyana, John, and good morning, John, I’d tell you that as I indicated earlier, it is really early days and we need to get a better handle on the full block potential. But kind of the question around design one build many, we’re doing that across all of our businesses, and I’d tell you that the real modifier in that is design one, and we continue to get more and more efficient in that design and reduce the cost structure. I’d tell you that the even expanded globally in terms of how you look at concurrent developments in different parts of the world to make sure that you're fully capturing the benefits of robust design and execution. To your point around the engineering and construction contractors, yes, I mean their backlogs are certainly light and we are very mindful about facing the investments to ensure that we maximize value, but we want to do it with a clear view on prudent financial management and maintaining our financial flexibility going forward, but I’d tell you that one of the best opportunities that we have out there is the collaboration that we've been able to have with many of our providers and really encouraging them to bring forward lower-cost solutions to see if we can make investments move quicker.

Well, thank you. To conclude, I just want to thank you all again for your time and very good questions. It was an insightful discussion, I think for all of us. So, we appreciate your time this morning, and we very much appreciate your interest in Exxon Mobil, and we look forward to talking with you in the future. Thank you.