Exxon Mobil Corp (XOM) — Q1 2015 Earnings Call Transcript

Thank you. Ladies and gentlemen, good morning and welcome to ExxonMobil's first quarter earnings call. My comments this morning will refer to the slides that are available through the Investors section of our website. So 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 for first quarter performance. ExxonMobil delivered earnings of $4.9 billion. These solid financial results demonstrate the value of our integrated business in a lower commodity price environment. Regardless of our current market conditions, we remain focused on business fundamentals and competitive advantages that create long-term shareholder value. Upstream production volumes were more than 2% higher compared to the year ago quarter, benefiting from new developments in Papua New Guinea, Canada, Angola, Indonesia, and U.S. onshore liquids plays. ExxonMobil's downstream and chemical businesses had strong performance across all regions driven by lower feedstock costs and improved demand, coupled with our competitive product and asset mix. Moving to Slide 4, we provide an overview of some of the external factors affecting our results; global economic growth continued to moderate in the first quarter of 2015. U.S. growth slowed relative to the fourth quarter, whereas China's economy decelerated further and growth in Europe and Japan remains weak. However, there are recent indications that growth may be improving, particularly in Europe. As you know, energy prices continued to decline in the quarter, leading to lower costs to supply in the downstream and stronger global refinery margins on hard demand. Meanwhile, chemical gas cracking margins softened on lower product realizations but remain advantageous relative to liquids cracking. Turning now to the financial results as shown on Slide 5. As indicated, ExxonMobil's first quarter earnings were $4.9 billion, which represents $1.17 per share. The corporation distributed $3.9 billion to shareholders in the quarter to dividends and share purchases to reduce shares outstanding, and of that total, $1 billion was used to purchase shares. CapEx was $7.7 billion which is in line with our plan. Cash flow from operations and asset sales was $8.5 billion, and at the end of the quarter, cash totaled $5.2 billion and debt was $32.8 billion. The next slide provides additional detail on sources and uses of funds. Over the quarter, cash increased from $4.7 to $5.2 billion. Earnings adjusted for depreciation expense, changes in working capital, and other items in our ongoing asset management program yielded $8.5 billion of cash flow from operations and asset sales. Users included net investments in the business of $6.8 billion and shareholder distributions of $3.9 billion; debt and other financing increased cash by $2.7 billion. Yesterday, the Board of Directors declared a cash dividend of $0.73 per share, a 5.8% increase from the last quarter. Share purchases to reduce shares outstanding are expected to remain at $1 billion in the second quarter of 2015. Moving on to Slide 7 for a review of our segmented results, ExxonMobil's first quarter earnings of $4.9 billion were $4.2 billion lower than the year ago quarter. Lower upstream earnings were partially offset by stronger downstream results. In the sequential quarter comparison, shown on Slide 8, earnings decreased by $1.6 billion as lower upstream and chemical earnings were partly offset by stronger downstream results. Guidance on corporate and financing expenses remains at $500 million to $700 million per quarter. Turning now to upstream financial and operating results starting on Slide 9. Upstream earnings in the first quarter were $2.9 billion, down $4.9 billion from the first quarter of 2014. As you can see, slightly lower realizations decreased earnings by $5.5 billion where crude declined by almost $54 per barrel and gas was down more than $2.60 per thousand cubic feet. Favorable volume and mix effects increased earnings by $340 million, driven by growth from new developments. All other items added another $250 million primarily due to favorable tax effects. Moving now to Slide 10, oil equivalent production increased 97,000 barrels per day or 2.3% compared to the first quarter of last year. Liquids production increased to 129,000 barrels per day or 6%, benefiting from new projects, work programs, and favorable entitlement impacts, partly offset by maintenance activities. Natural gas production decreased to 188 million cubic feet per day or 1.6%. Field decline and divestment impacts were partly offset by volume adds for Papua New Guinea and LNG in higher entitlements. Turning now to the sequential comparison starting on Slide 11, upstream earnings were $2.6 billion lower than the fourth quarter. Realizations decreased earnings by $2.4 billion as crude declined almost $22 per barrel and gas decreased more than $1.20 per thousand cubic feet. Favorable volume and mix effects improved earnings by $260 million driven by a higher LNG facility utilization, entitlement impacts, and growth from new developments. All other items reduced earnings by $500 million reflecting lower benefits from tax items in absence of the Venezuela ICC award, partly offset by lower operating costs. Now moving to Slide 12, sequentially volumes were up 194,000 oil equivalent barrels per day or 4.8%. Liquids production increased 95,000 barrels per day, on new project growth and entitlement effects partly offset by fuel decline. Natural gas production was up 594 million cubic feet per day driven by stronger seasonal demand in Europe and higher LNG facility utilization, partly offset by fuel decline. Moving now to the downstream financial and operating results starting on Slide 13. Downstream earnings for the quarter were $1.7 billion, an increase of $854 million compared to the first quarter of 2014. Higher refining and marketing margins increased earnings by $1 billion, positive volume and mix effects added another $70 million, and all other items decreased earnings by $260 million including higher maintenance activities and unfavorable foreign exchange effects. Now turning to Slide 14, sequentially first quarter downstream earnings were up $1.2 billion, stronger global refining margins increased earnings by $900 million while unfavorable volume and mix effects reduced earnings by $70 million. All other items added $340 million primarily from lower expenses and maintenance activities. Moving now to the chemical financial operating results starting on Slide 15. First quarter chemical earnings were $982 million, down $65 million versus the prior year quarter. Higher margins on lower feedstock and energy costs increased earnings by $240 million. Favorable volume and mix effects added another $30 million and all other items reduced earnings by $340 million mainly due to unfavorable foreign exchange effects. Moving now to Slide 16, sequentially chemical earnings decreased by $245 million on lower commodity product margins. Positive volume and mix effects were more than offset by other impacts. Moving next to the first quarter business highlights beginning on Slide 17. In our upstream business, we continue to pursue attractive investments to commercialize our unparalleled resource base. As discussed during our recent analyst meeting, 2015 will be yet another active year for new developments including seven major project startups which will add another 300,000 barrels of oil per day to working interest capacity. We reached several milestones over the last few months starting in Canada; first production was achieved from the Cold Lake, Nabiye expansion which was completed on schedule and on budget. Nabiye produced 12,000 barrels per day in March with volumes expected to increase to a peak of more than 40,000 barrels per day by year-end. Over its expected 30-year lifespan, Nabiye will develop 280 million barrels of recoverable reserves. In the Gulf of Mexico, we initiated production from the Hadrian South subsea development in late March. I highlight that one of the Hadrian wells recently tested at 200 million cubic feet of gas per day, representing one of the highest production rates on record in the Gulf of Mexico. Daily gross production from Hadrian South is expected to reach approximately 300 million cubic feet of gas and 3,000 barrels of liquids from two wells. In Angola, Block 15 we successfully started up Kizomba Satellites Phase 2 project notably ahead of schedule and below budget. This capital-efficient project is a subsea development tied back to the existing Kizomba B and Mondo FPSOs and leverages available infrastructure for processing, storage, and offloading. Project development yielded 190 million barrels from three fields and gross production is expected to reach 70,000 barrels of oil per day helping to boost total Block 15 production to 350,000 barrels per day. In Asia, the Banyu Europe development is more than 96% complete and commissioning activities are well underway. The project's crude transport system, which includes onshore and offshore pipelines connected to a floating storage and offloading vessel, has been installed and first lifting is expected in April. The implementation of early production concepts has led to Banyu Europe now producing 75,000 barrels of oil per day. Early strong well performance enables continued use of existing early production facilities along with the ramp-up of the central processing plant. We expect to reach peak field production of more than 200,000 barrels per day by year-end. The Kearl expansion projects in Canada continue to progress ahead of schedule. All major construction activities are now complete, and our focus has shifted to commissioning and pre-startup activities. Facilities startup is now expected by mid-year. With respect to our exploration program we continue to pursue a diverse set of opportunities. In Romania, additional drilling is ongoing in the deepwater Neptune block and data collected from these wells are being integrated into development planning for the area. Drilling operations in the Kurdistan region of Iraq are continuing and we drilled and tested the Pirmam well and are evaluating those results. Additional drilling is planned in the next several months. Then offshore Guyana, we are drilling the Liza wildcat which is the country's first deepwater well. Lastly, in the Gulf of Mexico, we were the apparent high bidder on 11 new exploration blocks in lease sale 235, further strengthening our acreage position. We plan to utilize our advanced seismic imaging capability to enhance opportunity evaluation on these blocks. Turning now to Slide 18 and an update on our downstream investments which further strengthen our advantage portfolio. Here again during the quarter we achieved several milestones. We completed the lube basestock facility expansions at our refineries in Singapore and in Baytown, Texas, building on ExxonMobil's leading technology and our worldwide manufacturing footprint. These investments will help supply high-performance lube basestocks to meet global demand growth. In Canada, commissioning is underway at the Edmonton Rail Terminal, a joint venture between Imperial Oil and Kinder Morgan. The terminal will have a capacity of 210,000 barrels per day and will provide logistics flexibility to support efficient, cost-effective market access for our growing Canadian oil sands production. This facility will also enable us to deliver additional advantaged crude to our refinery system. Ramp-up of loading activities is expected over the next few months. Finally, we also continue to extend our operating cost advantage by improving the energy efficiency of our facilities. We have recently funded and started construction of a new 84-megawatt cogeneration plant at our Singapore refinery, which will enable the shutdown of less efficient power generation facilities and reduce carbon dioxide emissions. Upon startup, the unit will add to our total 5.5 gigawatts of gross cogeneration capacity around the world. This is another example of ExxonMobil's commitment to optimize manufacturing operations, improve energy efficiency, and to reduce both environmental impacts and operating costs. In conclusion, ExxonMobil's results underscore our continued focus on business fundamentals and our competitive advantages regardless of market conditions. In the first quarter, the corporation earned $4.9 billion, demonstrating the value of our integrated businesses in a lower commodity price environment. In the upstream, we increased production from new developments while in the downstream and chemical segments delivered strong results across all regions. Resulting cash flow from operations and asset sales were $8.5 billion generating positive free cash flow which highlights our disciplined capital allocation approach. The corporation distributed $3.9 billion to shareholders, and we remain dedicated to creating shareholder value through the cycle. Now that concludes my prepared remarks and I would now be happy to take your questions.

I will try two if I may. The first one is on the upstream capture rate specifically I'm looking at the very strong international gas prices this quarter, which seem to hold up a lot better relative to the oil benchmarks and I guess the mix significant of there are a lot of moving parts obviously but the mix also saw your gas production decline. So I'm wondering if you can just help those two specific issues on what’s going on with the margin and whether you expect that strength to continue. And I've got a follow-up, please.

Doug, we generally don't provide forward guidance on commodity prices. In the first quarter, our total gas realizations were about $6.11 and as you know, that’s a combination of our flowing gas as well as our LNG sales, and those LNG contracts have mixed fiscal terms that will, in many cases, be benchmarked to liquid prices, obviously with some type of lag effect associated with the market conditions.

So the strong European gases or international gas driver is really more of a lag effect; how should we think about it?

Well, I think from an LNG perspective, if you remember from our prior discussions, it is a very significant part of our portfolio, and we've been adding significant liquids-linked volumes over the years, and certainly is a factor for how our realization will change over time.

I will try to follow up offline to get into details. However, my follow-up may be a bit hopeful regarding whether you will answer or not. At our conference in November, you mentioned that Exxon is positioned well for this type of environment, especially concerning mergers and acquisitions. We've already witnessed one major transaction. I am curious if you could elaborate on how you perceive the market in light of that comment, specifically regarding Mozambique LNG, since you've had advisory involvement there with the government in recent years. I'll leave it at that.

We view our business from a broader perspective as asset management, which is essential to our operations. We continuously evaluate our portfolio for opportunities that can deliver higher value throughout the market cycle. As reflected in our financial outcomes, this includes actively managing assets that we believe will have greater value to others. Additionally, we remain vigilant for potential acquisition opportunities, whether they involve smaller bolt-on acquisitions that can create natural synergies with our current operations or larger acquisitions that would provide long-term strategic advantages. While we won't disclose specific plans, we are always looking for ways to enhance shareholder value. I would like to emphasize our financial strength allows us to invest consistently throughout the cycle, including in resource development, our manufacturing business, and potential acquisition opportunities.

On the quarter itself it looks like production was a little higher than what we were expecting; some of that was the PSEs, but I think some of that was the underlying projects here. And as I think about Angola, Gulf of Mexico starting up, you've got some ramp towards the backend of the year as well. So I'm just curious as we think about the balance for the year, could there be some upside to the base case production guidance or are we not thinking about turnarounds? Anything you can do to provide some color on shape of production over the course of the year would be very helpful.

Yes, so just from a production standpoint, I'd tell you that our guidance that we provided in the analyst meeting last month remains the same about 4.1 million barrels per day. We started the year very strongly as you highlighted, we added significant volumes with a quarter-over-quarter or sequentially associated with the new projects that we've brought on, which, as you appropriately pointed out, continue to ramp up. As I said in my prepared comments, we've got seven new major projects starting up throughout the year and this is part of our significant investment program that we had implemented several years ago; that's where our CapEx peaked a few years ago, as we wanted to progress these mature assets to capture long-term value and we're seeing the benefits of it today. Important in all that, Neil, is not only new projects but our continued focus on the base making sure that we've stronger liability and we're continue to integrate our learnings into productivity improvements.

And then if you could comment on two kind of topical subjects here. The first would be any comments around Exxon Torrance and how we should be thinking about the ESP and timing there? And the second as it relates to Russia, which I know you've spent a lot of time on, how we should be thinking about the impact assumptions on long-term growth from those operations?

Sure, Neil. On Torrance just for the benefit of the group, the Torrance refinery in February experienced an incident which resulted in damage to the electrostatic precipitator, and I'll say up front that we certainly do regret the incident and — obviously going to be very diligent and understanding what the issues were, what learnings we can take from it, and how do we incorporate that into our global business? But this precipitator is a mission control device that removes fine particles from exhaust gas. There are several investigations underway at both state and federal levels. Neil, at this time, we really can't estimate when the investigations will be completed and when the site may return to full operations. As I indicated, we have our own investigation that's in progress. I'll say that we are diligently working to ensure a continued supply to our customers; some of the units at the refinery are operational and we're producing both gasoline and distillates, but we continue to evaluate in parallel with the investigations ongoing to evaluate options to reinstate our capacity there. With respect to Russia, broadly speaking there is really nothing new to report at this point. As you know, the sanctions remain in place, and we will continue to fully comply — I don't want to speculate when those sanctions will conclude, but I'll remind you that they do not include or soften one operation which recently we're very pleased with, the successful start of the third field, Arkutun-Dagi. I would also say that we have had a longstanding and successful business in Russia that's really built on our effective and I think mutually beneficial relationship with our Russian partner. I guess the other point I'd leave you with is that we have a very diversified portfolio with Russia just being part of that and it provides great opportunities for us to continue to grow shareholder value over the years.

I was hoping you could discuss Kearl performance a bit this quarter. It looks like some significant improvement relative to where it ran last year, and if you could actually approach max rate there for the quarter. So could you talk about what you're seeing there, and then could you also address confidence levels in a quick sustainable ramp up for the Kearl expansion? I mean what that timeline looks like and some of the benefits of applying learning from some of the struggles with ramping up Kearl 1.

I appreciate the question. As we've said in the past, Kearl is an advantaged long-life asset, one that has significant future potential as you look at how we further optimize the base. As you highlight, we have continued to improve on our reliability towards our operating targets and we’re fairly consistently producing at the 110,000 barrels a day growth. We were a bit short of that in the first quarter given some plant maintenance that we took, but nonetheless it's important to say that we’re achieving higher rates, we've implemented some facility enhancement opportunities, and we expect to see better reliability going forward. As I said in my prepared comments, the expansion is progressing ahead of schedule, and when that expansion comes online, we will get further economies of scale with the full operation. As I've said previously, we’re fully integrating the learnings from the initial development into the expansion real-time such that we will expect to see a better ramp-up on the expansion versus the initial development. I would also highlight a couple of other things; first that we’re making additional investments to maximize logistics flexibility, and as I mentioned in my prepared comments, the Edmonton Rail Terminal is going to provide additional flexibility. That takes me to my second point; it is really fully integrated with our manufacturing business and we’re capturing integration value throughout the full value chain from upstream, downstream, and our chemicals business.

Also, I was hoping to get a general comment on what you all are seeing on the capital spending front when it comes to securing cost reductions and managing the CapEx according to the internal plan. It looks like it's tracking well to start the year from an advantage point, and more specifically, the upstream non-U.S. spending was the lowest this quarter; it's been since 2009, I believe. So could you just talk about that a little bit, and is that just reflective of major project phasing or has there been perhaps some significant cuts to the international CapEx in areas that are a little bit less visible perhaps to the base or elsewhere that you can talk about?

So let me take your first question in the broadest concept. As we've talked previously, regardless of where we are in the business cycle, the organization stays very focused on driving down that cost structure, whether it be in operating cost or a focus on capital efficiency in our major projects. Across our spend, we’re actively engaged with the various service providers and we’re making some really good progress in capturing those savings from raw materials to services to our rig rates to our fundamental construction costs. I will highlight, just make a point that we have a very effective global procurement organization that is focused on capturing the lowest lifecycle cost, and I think it really does advantage us from managing that from a global perspective. I think it's also worth noting that our efforts go well beyond reducing costs from our service providers; as we do think, we're continuing to integrate our learning curve benefits into our designs and execution plans. I've shared with you in my response to a prior question that we have been able to integrate our learnings from the Kearl initial development into the expansion project in real-time. We continue to enhance our set of opportunities, including through commercial terms, as well optimizing our development plans, and we continue to leverage what I'd say as the collective ingenuity between our service providers and our own people in identifying and pursuing more cost-effective solutions. I'd note that given our financial capability we’re able to accelerate equipment and commodity purchases in the softer market, which provides a real cost advantage to our project portfolio. Since the price decline, I would say that the drilling and related services have been most responsive to the current market, and we've captured about an incremental 20% reduction in our well cost from the lower 48 to unconventional plays in terms of our spend level. I would tell you that there is no new guidance. We've signaled a $34 billion target for 2015; we are making good progress in capturing the savings as I said that was incorporated into that spend level. But this organization tends to overperform, and I expect that we'll see further savings beyond what we had envisioned.

So over the macro, maybe another aspirational question. Exxon touches more barrels than any U.S. producer, any refiner for that matter. Any color on demand trends you are seeing, or is there broadly any change or shift in the longer commodity down cycle view that was espoused at the Spring Analyst Day?

Evan, let me see if I just give you some thoughts on the broader picture. Currently, we range in anywhere from the 1.5 to 2 million barrels a day oversupply. General feeling is that as you get into the second half we’ll see more conversions towards a balanced supply demand. But as we all know, there was a significant inventory build in 2014 due to the oversupply, and that has continued year-to-date. And that storage overhang will need to be addressed over time. While we may converge in the second half of the year, I’d tell you that there are still a lot of unknowns, and one of them being how the unconventional production levels in the U.S. will trend over time despite the fact that we’ve seen significant reductions in rig counts.

My second question, if I could, on PNG, as Total finalizes development plan for its proposed second facility, I think it's this quarter. Is there a potential for Exxon to recover more costs or improve your overall PNG LNG economics with a bigger integration of the two projects or infrastructure?

Just broadly speaking and it's for a reason PNG, Evan, because it really does spotlight the successful organization we have for our project execution in commercializing our resources. What a great success story with a location that had limited infrastructure. The project was a significant feat for the organization in terms of being delivered on time and on budget, ramped up very quickly and it's been held at design rates; we’re just very pleased with the outcome. As you think beyond that, ExxonMobil and its partners continue to assess additional resource opportunities. As you reflect on whether you can pull together enough resource in which to underpin a subsequent train, that’s part of what’s being considered amongst the joint venture. I would tell you that it would be the most cost-effective option compared to another Greenfield development. Of course, we are very well positioned there and we are open to options to try to reduce the overall cost structure for resource development in Papua New Guinea.

Given the economics, superior economics you had on the Greenfield facility, I presume a Brownfield expansion would be relatively high in your rankings at your relative upstream projects.

Yes, most definitely.

I think you pretty adequately addressed Guy's question on the capital cost trend. But I was hoping you may elaborate a little bit more towards the operating cost side. Many of your peers have enacted hiring freezes and headcount reductions, etc. And while I know we're not going to get a specific absolute dollar figure from you, I was just wondering if you could talk maybe about some trends we could expect to see on the operating cost side from just capital trends.

Sure, Blake. I would tell you that comments I made earlier were really reflective of both our operating costs and our capital costs. The point I would emphasize for you is that really regardless of whether we’re in the high price cycle or in a lower price cycle that we're in right now. The organization has remained focused on the fundamentals. And you've heard us say before that we're price takers, and we really focus on those things that we control. And those things that we control are things such as cost, our reliability, and our productivity, and it's how we structure the organization in the most efficient way. I'd tell you that we are very well positioned, we never lose sight of those fundamentals, but we're also very well poised when we get into a down cycle like this that we can capture additional savings. As I alluded to previously, given our financial capability, we're also able to invest during the cycle and capture a lower cost structure on resources that we had planned to commercialize in the future. So, I think we're very well positioned; we've got a very capable organization that keeps their eye on the fundamentals through the cycle, and as I've said in the past, we got to lead that cost curve.

The second question is for you, Jeff. The recent decision to increase the dividend, obviously an interesting time to enact that, obviously demonstrates confidence. But noticing that the debt balance has increased about $11 billion from year-ago levels. I'm just curious if you could talk a little bit about how you're thinking about shareholder returns and using the balance sheet to continue leveraging up depending on how long this down cycle remains.

I think it's a good question, Blake. When you think about from a perspective of our capital allocation, nothing has changed, and we have maintained a very disciplined capital allocation approach throughout history in the highs and the lows with the focus on a long-term horizon. We remain committed to our shareholders to invest in attractive business opportunities that are accretive to financial performance and to continue paying a reliable and growing dividend. Across that business cycle, I'd say that we manage the cash by, as we've said before, returning the excess to our shareholders through share repurchases or borrowing to fund our investments. What you've seen with the increase in the dividend — and continuing the stock purchases underscore our commitment to shareholder distributions. I think it also demonstrates the confidence that we have in our integrated business model.

So two quick questions. First on LNG utilization, I think in your prepared remarks you mentioned utilization improving a little bit, could you elaborate, is it primarily related to PNG ramp-up or is there anything else going on?

So, LNG utilization is broadly defined by several operational and commercial factors, including maintenance, reliability of our facilities and then market and commercial considerations.

And then shifting gears to the Permian; Jeff, last year Exxon added about 65,000 net acres in the core Wolfcamp. How do you see opportunities evolving in this current macro-environment and on that, could you update us on activity and volume relative to last quarter, please, on the Shell plays?

So broadly speaking, as I said earlier when we are talking about M&A, that we keep alert to where we’ve got opportunities to build the portfolio with accretive assets, so those opportunities come along — we'll go ahead and consider them. We're making great progress as you heard in our analyst meeting in terms of cost efficiency improvements, and productivity improvements not only from our drilling and completions but also from initial well rates. So we really good progress; we have great opportunities in the Permian and in the Bakken. Just broadly speaking, in the three key plays that are liquid plays that we’ve in unconventional, we're running just south of 40 rigs right now; that's been trending downward in part commensurate with the efficiency and productivity improvements that we've been able to capture.

And do you see — how do you see this evolving in the balance of the year trending down through the year-end?

We have been trending downward, like I said, because we've been able to maintain real-time capture of additional benefits. So, I wouldn't translate that into a linear relationship with activity levels.

Obviously just moving to Holland, Groningen's been in the news again. I'm just trying to understand what sort of decline did you assume that the Groningen field was going to have say over the next two years in your planning numbers. And how do you assess the risk that it might actually be lower? And then I have a follow-up.

Ed, when you referred to decline, I think you're referring to the production constraints that have been imposed.

You outlined a corporate production target for the firm, and Groningen is included in that. I am trying to understand what assumptions you have already incorporated regarding Groningen, so if conditions worsen, we can quickly evaluate the impact.

So first let me start with the impacts in our operating performance here both quarter-over-quarter and sequentially; Netherlands was up due to higher demand but that was offset by some constraints. I'll be clear upfront, Ed, that we did incorporate the advertised restrictions into the volume projections that we shared with you last month.

So if they get worse then that would be a negative delta?

It really is a function of what happens due to changes in demand throughout the year, but certainly, there are more extreme restrictions that will have an impact.

And then a broader question which is more demand-related; obviously Exxon has refining, chemicals, upstream businesses around the world. You've started to see some demand estimates from the main agencies being revised upwards, but apart from the sort of chink of light that you saw in Europe, your opening comments were a little bit down based on the global economy. So just trying to gauge I guess whether you think that the recent increases in some of the demand estimates are real or not, and if not, what might be the reasons such as tertiary rebuilding?

So from a downstream perspective, we did see margin improvements but due to several different reasons; if you think about in Europe, there was some capacity that was brought offline within both Europe and Asia as well as due to lower crude prices, as well as some planned and unplanned maintenance that was taking capacity off the system. Lastly, there was some fundamental demand improvement in a number of products like gas, distillate, and fuel oil. We saw similar benefits in the U.S. as well. Going into the future, I would be a bit reluctant to extrapolate that beyond this quarter.

The earnings performance; what about demands for both?

You are talking about?

Global demand for products.

Let me start with the chemicals business. Our projection on global demand for the chemicals business is that it's going to continue to grow greater than the GDP by about 1.5%. Refining demand will, I think, depend on what happens in the economies.

I just wanted to ask specifically about the international upstream earnings; most of your peers have quantified the effect of the change in the UK tax laws within their releases. I appreciate that you have addressed the variance that has occurred in the other section, but I was hoping to get the absolute amount from you.

Let me give you a little bit more color on just the tax rate. As you see in our supplemental information, we had an effective tax rate of a little over 33%, and that’s about a 12% drop quarter-on-quarter. As you would appreciate, the effective tax rate is an outcome of our business results across the geographies in which we operate within. Most of that drop was really due to the portfolio mix of income across our business segments and our geographies; about 3% of that was associated with one-time tax items, primarily the UK tax rate change, which amounted to about a $200 million positive impact on earnings.

Another question; that’s a completely separate topic. Just in the current oil price environment, I haven't seen a lot of deflation yet. Are you expecting to make any FIDs this year? And if you could address Hadrian North specifically?

So, Jason, I would encourage you to look at our recent financial operating review. You will see that we have a list of projects that we anticipate will start up post-2017, and that will give you a sense for the next tranche of development opportunities that are currently in play. Many of these are in development planning stages or even some in pre-FID. That will give you a sense of what’s on the horizon. We don't broadcast planned FIDs in the future, but we do give you a pretty detailed list of what’s out there that we are working on.

Maybe if I could just put it another way, have you seen enough cost deflation in the deepwater yet to maybe accelerate your investment potential in that area, or have you seen very little in terms of cost deflation?

Frankly, I will tell you, Jason, that we are never really satisfied with the cost structure, and we will always continue to work on it. But as you can appreciate, there are a lot of factors. As I indicated earlier, we have seen what I consider early innings of reductions in services like rig rates. We expect that we would be able to do a lot more. As I alluded to previously, that also includes an expectation within our organization that we will be able to further optimize these development plans to maximize shareholder returns. But I'll tell you that we have a very, very large and diverse resource base to work on; it allows us to be very selective in what we decide to pursue. When we decide when we get to an FID stage, it's been tested across a range of economic considerations since that will be confident it's going to be accretive to overall financial performance.

One question on the quarter; you talked about the benefit from lower tax rates; I know you had proceeds from asset sales as well. So just wondering if there any one-time benefits from asset sale gains?

As you see in our materials that we sent out, there was about just under $500 million cash flow benefited associated with asset sales. That translates to about a 50% reduction in the number if you unwind the remaining un-depreciated investment that we have on our books. Those proceeds are really the result of sales across our upstream and downstream businesses.

And then you've talked about a fair number of investment you're making in Europe to high-grade your refining capacity to this lift. I guess maybe just give us an update or remind me when that’s supposed to be coming online. And then on the U.S. side, what opportunities might there be to debottleneck or add new capacity here over the next few years if you think that that’s a decent return project?

Phil, I guess you're referring to our Antwerp coker?

Yes, exactly.

So really good progress on that investment opportunity; I'd tell you that it's progressing towards a 2017 startup.

And then on the U.S., do you see any opportunities there to debottleneck capacity or add new capacity in any of your refineries in the next few years?

No, we regularly evaluate our portfolio book in the U.S. and internationally for where we can capture additional value for earnings growth. I'd tell you that while I'm not in a position to give you any indications specifically, we keep very mindful of where we can capture additional value, and primarily falls in four areas; one is trying to further improve our flexibility of our feedstock. Two, are opportunities that we can further reduce our cost structure. The third one would be in areas where we can increase our higher value product yields. Lastly, as you saw with the Edmonton Rail Terminal, improving our overall logistics flexibility.

So my question is also on Groningen; there has been a lot of commentary about the issue surrounding seismic conditions and property in the area. My question is whether or not we could get a little bit more color on the situation. Meaning, it sounds like when you answered Ed's questions a few minutes ago that the implication for production may be negligible, but I just want to make sure I heard that correctly. And then also, there have also been talks of some financial penalties too. So any commentary that you could provide that would help us sort this out would be appreciated.

Yes, so most of the information, as you know, has been digested in the media. Just broadly speaking, the original target was about 42 billion cubic meters in 2014; that’s been originally reduced down to about 36 billion cubic meters, and then in the first half of 2015, down to 16.5. It's still a very dynamic issue. Our understanding is there will be some further guidance from the government coming out in July. But broadly speaking, as I referred to it previously, our production guidance has been incorporating the reduction in production constraints that had been advertised externally. It is having an impact and I don’t want to mislead anybody.

Maybe a follow-up on earlier comments that you made on Canadian crude. How big is the rail terminal that you are working on up there and how much crude can you actually move out of there by rail once it’s up and running? And can you give us any differences; obviously it has been very tough out there in terms of heavy barrels, any thoughts on this in the crude terminal in terms of ways it might offer better pricing going forward?

So the capacity of that terminal is just over 200,000 barrels a day, 210,000 barrels to be exact. You emphasized a point I made earlier that it's part of our integrated businesses. It's a key element for us to connect our upstream business to our refining and chemicals business throughout the Gulf Coast and the Mid-Continent.

And then maybe a quick follow-up on gas decline as well. We saw a relatively steep decline in U.S. gas lines quarter-on-quarter, and really there is a lot of quarter-to-quarter volatility. But can you give us an idea of generally a good assumption for what you would assume for annual decline rate in U.S. gas?

I would say just to your point, our gas activity has been fairly limited in the U.S. We have really transitioned a lot of our drilling activity in the lower 48 to liquids plays, obviously because we see the value proposition is stronger. But I really want to highlight the point that there is a real opportunity in the U.S. to commercialize this gas if we were to remove some of the barriers that we've got before us, and we've got as you all are aware, we've got an investment pending in Golden Pass to convert that terminal to an LNG export facility. We think we’re well positioned with infrastructure; we think it is a great opportunity for the United States if we could increase the export options for U.S. producers. It's going to create additional investment, it's going to create additional jobs, and bottom-line, it's going to improve the economy. So I think the call to the government would be one of really taking advantage of the opportunity that the U.S. has to really build energy security not only in the U.S. but more globally by providing, if you will, free-trading.

I would like to follow up a little bit on some of the volume guidance and the entitlements in a fairly significant amount of barrels that came back in. As you think about the 4.1 million barrels for the full year, the outperformance in Q2, is there upside based on entitlements or would you say your projection is based on expectation in the future curve as oil pricing, etc. that we should think as 4.1 million really is the right number?

I would tell you, if you go back to the analyst presentation, we had assumed just for the sake of the presentation itself we assumed Brent price of $55 per barrel, and of course flowed that into our production sharing contracts to give you a sense of what we would expect in terms of volume. That is target of 4.1 million barrels per day; obviously, if prices go up or down, it's going to have an impact. I really don't have a rule of thumb for you when it comes to entitlement impacts, which as you know include many different factors including the commercial structure, as well as expenditure levels and obviously price. But we had assumed a price forecast comparable to where we are right now.

And then back to the OpEx cost reductions; is there any guidance you can provide us on or any help you can provide us in terms of how that works its way into the system or whether or not most of that has been captured during the first half of this year or so Q1 and Q2?

In fact, the guidance I gave you, Roger, is that we’re going to see further capture opportunities as we progress through the year.

So should we think the majority has come through or minority, or is that still?

We have been able to capture savings in the first quarter, but as I alluded to, not all parts of our cost structure have responded at the same level, and we will continue to progress those, and we expect increased savings over time.

Most of my questions have been answered, but I will try more on macro one. Obviously, Exxon is always prior to itself on investing with more long-term demand viewpoint. Do you think that with the current down cycle, we've taken enough CapEx out of the industry that we're going to face more of a supply-demand squeeze going forward, maybe later in the decade or early in the 2020s?

That’s a hard one to really answer. I would step back and just think about the overall energy outlook that we publish annually. We are fairly confident given the range of variables that we test that we’re looking at about a 35% growth in energy demand between 2010 and 2040. Fundamentally, that is how ExxonMobil sets its investment plans. We continue to periodically test that not only annually, but also inter-annually in terms of how the business—more broadly speaking—is investing whether that’s going to be sufficient to meet that energy growth over time. There are a lot of variables in it including you may recall that inner energy outlook it really does require a very healthy progress on energy conservation. Broadly speaking, it's hard for me to say whether the current level investment will cause any shortages in the future.

I have a couple of questions; first one was to get your thoughts on Tanzania LNG. I saw that you went non-concern on the last exploration well with Statoil and it didn’t think that featured in any of the four projects you highlighted on the slide in the Analyst Day. Just wondering if this is something that’s going to drop to the back of the queue that you've prioritized in this kind of environment and your CapEx cut back.

Not at all. Tanzania, for the benefit of the people on the phone, Block 2 today we have participated in seven gas discoveries; we think total resource in places in excess of 20 TCF now. There is a lot of work to do in a Greenfield development like this. Statoil and ExxonMobil have been progressing development plans for the initial discoveries. There is a broader consortium that has been looking at the potential for an onshore LNG facility. We would tell you that upfront planning is progressing. I will confirm that there was one well we do not participate in. But I wouldn’t use that as an indication of our lack of commitment. I think what's important here as we go forward is we get better definition of the project. Equally important, you all know that LNG projects are capital intensive; what we need to ensure is that we have a stable fiscal regime with appropriate terms and conditions to underpin that type of investment.

And one follow-up question; going back to the acquisition market, what we're seeing is it seems like a lot of the U.S. and E&P companies we integrated are pulling out of international investing, more in U.S., seeing similar trends with some of the NOCs. So just wondering, are you seeing more value internationally and less competition for actually for assets now relative to the U.S. market?

Well, I think broadly speaking it's a good observation. When capital becomes constrained, that by definition that provides additional opportunities. I would say that from our perspective it's the value proposition that we bring that we hope that resource owners will look to, and that is our strong balance sheet, our leading return on capital employed, our operational expertise, and the technology that we bring to resource development. I'll say that we have one of the best, if not the best, project execution organizations. We’ve got a leading downstream and chemical business that’s fully integrated with our upstream, and I'd say that as a package those characteristics provide a winning proposition for resource owners.

Can I go back to the balance sheet? You've always said maintaining triple-A is critical, given that you are not currently funding the dividend and the buyback from cash flow. What do you think is the cushion that you have in billions to lever up and still maintain the triple-A?

I'd say that triple-A is really an outcome of our financial strategies. As you've heard us say previously, operating cash flows are our primary sources of funding for both of our capital departments and shareholder distributions. We maintain a very strong focus and prudent approach to cash management throughout that cycle. We have, as you know, significant debt capacity. We'll maintain our financial flexibility, and we'll continue to be very disciplined in how we invest and what we choose to invest in; but we're not going to forgo attractive opportunities. I think that’s a key differentiating factor for ExxonMobil; we’ve got the capability to respond when we need to respond, and we're very mindful of our cash balances and how far we want to take our investment program.

Can I ask you just a little bit on that? Have you looked at what the credit agencies might say if you take on an additional $5 billion to $10 billion over the next year, 1.5 years?

We're very—obviously we look at all the variables when we talk about our cash management and our financing capability; we keep a very mindful look at what our commitments mature in the future, but I'll tell you that we're very comfortable, and we're very mindful about where we are in terms of our debt. But I’m just not going to quote any specific numbers.

First and foremost, I want to say thank you for your questions, very good, very insightful, and I think it really brings more color to our business. So to conclude, I just want to thank you for your time and we very much appreciate your interest in ExxonMobil. Thank you.