Exxon Mobil Corp (XOM) — Q2 2015 Earnings Call Transcript

Thank you. Ladies and gentlemen, good morning and welcome to ExxonMobil's second quarter earnings call and Webcast. My comments this morning will refer to the slides that are available through the Investors section of our website. Before we go further, I'd like to draw your attention to our cautionary statement shown on Slide 2. Now turning to Slide 3, let me begin by summarizing the key headlines of our performance. ExxonMobil generated earnings of $4.2 billion in the second quarter. We are delivering on our investment and operating commitments across our integrated portfolio. The Corporation's results demonstrate sound operations, superior project execution capabilities, and continued discipline in both capital and expense management. Downstream and Chemical earnings increased significantly from the second quarter of 2014 driven by higher margins, continued strong demand, and the quality of our product and asset mix. Upstream production volumes of 4 million oil equivalent barrels per day were 3.6% higher compared to the year-ago quarter, and liquids volumes were up nearly 12%. Growth was underpinned by an increased level of new development start-ups over the last 18 months, largely in Africa, Canada, Indonesia, Papua New Guinea, and the United States. These results underscore the resilience of our integrated portfolio and the benefits of our disciplined capital allocation. In the first half of 2015, the Corporation generated cash flow from operations and asset sales of $17.9 billion with free cash flow remaining positive despite challenging market conditions. Moving to Slide 4, we provide an overview of some of the external factors affecting our results. Global economic growth improved in the second quarter of 2015. The U.S. rebounded after contracting slightly in the first quarter. Europe improved marginally amid concerns on Greece, China's economy stabilized, while Japan's growth tapered. Crude oil prices partly recovered during the quarter while natural gas prices declined further. Refining margins continued to strengthen in both the U.S. and Europe. Chemical commodity margins also improved while specialty margins weakened. Turning now to the financial results as shown on Slide 5, as indicated, second quarter earnings were $4.2 billion, which represents $1 per share. The Corporation distributed $4.1 billion to shareholders in the quarter through dividends and share purchases to reduce shares outstanding. Of that total, $1 billion was used to purchase shares. CapEx was $8.3 billion, which is in line with plans. We have remained focused on structural improvements through capital efficiency as well as the capture of additional cost savings in a softer market. Cash flow from operations and asset sales was $9.4 billion, and at the end of the quarter, cash totaled $4.4 billion, and debt was $33.8 billion. The next slide provides additional detail on sources and uses of funds. For the quarter, cash decreased from $5.2 billion to $4.4 billion. Earnings, adjusted for depreciation expense, changes in working capital, and other items, and our ongoing asset management program yielded $9.4 billion of cash flow from operations and asset sales. Uses included net investments in the business of $7.1 billion and shareholder distributions of $4.1 billion. Debt and other financing increased cash by $1 billion. Share purchases to reduce shares outstanding are expected to be $500 million in the third quarter of 2015. Moving on to Slide 7 for a review of our segmented results, ExxonMobil second quarter earnings of $4.2 billion were down $4.6 billion from a year-ago quarter. Lower Upstream earnings were partially offset by stronger Downstream and Chemical results. Gains on asset sales were $1.2 billion lower than the second quarter of 2014, reflecting the absence of the Hong Kong power and Canadian asset divestments in the Upstream segment. I'll also note that our corporate effective tax rate was 45%, up 4 percentage points compared to the year-ago quarter and up 12 percentage points sequentially. This higher tax rate reflects the relative mix of income across geographies and tax regimes as well as a one-time increase in the corporate income tax rate in Alberta, Canada. In the sequential quarter comparison shown on Slide 8, earnings decreased by $750 million as lower Upstream and Downstream earnings were partly offset by higher Chemical results. Guidance for corporate and financing expenses remains at $500 million to $700 million per quarter. Now turning to the Upstream financial and operating results starting on Slide 9, Upstream earnings in the second quarter were $2 billion, down $5.9 billion from the second quarter of 2014. Sharply lower realizations decreased earnings by $1.5 billion where crude declined by almost $46 per barrel and gas was down almost $2.40 per thousand cubic feet. Note that favorable volume and mix effects increased earnings by $330 million driven by production growth on our new developments. All other items were negative $1.7 billion and this was driven by the absence of divestment gains from Hong Kong power and Western Canadian assets which represented $1.6 billion. Also, the higher income tax rate in Alberta, Canada resulted in a negative $260 million non-cash deferred tax adjustment. Lower operating costs provided a partial offset. Moving to Slide 10, oil equivalent production increased 139,000 barrels per day, or 3.6%, compared to the second quarter of last year. Liquids production increased 243,000 barrels per day, or nearly 12%, benefiting from new projects or programs and favorable entitlement impacts. Natural gas production decreased 622 million cubic feet per day, or 5.8%, driven by regulatory restrictions in the Netherlands. Volume adds from the Papua New Guinea LNG and Hadrian South projects along with entitlement effects offset built decline. Now turning to the sequential comparison starting on Slide 11, Upstream earnings were $824 million lower than the first quarter. Realizations increased earnings by $600 million as crude was up almost $11 per barrel while gas declined about $1 per 1,000 cubic feet. Unfavorable volume and mix effects decreased earnings by $420 million driven by lower seasonal gas demand in Europe, regulatory constraints in the Netherlands, and maintenance in the U.S. All other items reduced earnings by $1 billion, mainly driven by unfavorable tax and foreign exchange effects and lower gains from asset sales. Upstream unit profitability for the second quarter was $5.77 per barrel, excluding the impact of non-controlling interest volumes. Earnings per barrel for the first half of 2015 was $6.74. Moving to Slide 12, sequentially, volumes were down 269,000 oil equivalent barrels per day, or 6.3%. Liquids production increased 14,000 barrels per day on new project growth and work programs, partly offset by maintenance, entitlement effects, and field decline. Natural gas production was down 1.7 billion cubic feet per day driven by lower seasonal demand in Europe and regulatory constraints in the Netherlands. Moving now to the Downstream financial and operating results starting on Slide 13, Downstream earnings for the quarter were $1.5 billion, up $795 million compared to the second quarter of 2014. Our margins increased earnings by $1.1 billion. Volume and mix effects decreased earnings by $80 million. All other items reduced earnings by $230 million, driven by higher maintenance activities. Turning to Slide 14, sequentially, Downstream earnings decreased $161 million. Stronger refining margins, mainly in the U.S., increased earnings by $140 million whereas higher maintenance activities reduced volumes and increased expenses by $160 million and $140 million respectively. Moving now to the Chemical financial and operating results starting on Slide 15, second quarter Chemical earnings were more than $1.2 billion, up $405 million versus the prior year quarter. Our margins increased earnings by $340 million. Favorable volume and mix effects added $20 million. All other items increased earnings by $50 million, mainly due to asset management gains, partly offset by unfavorable foreign exchange effects. Moving to Slide 16, sequentially, Chemical earnings increased by $264 million. Lower margins decreased earnings by $10 million. Positive volume and mix effects increased earnings by $40 million. All other items added $230 million as asset management gains were partly offset by higher maintenance. Moving next to an update on our exploration and project activities on Slide 17, we continue to focus on pursuing a diverse set of high-quality resource opportunities. In Guyana, ExxonMobil made a significant oil discovery on the 6.6 million acres Stabroek Block well which was drilled approximately 120 miles offshore and encountered more than 295 feet of high-quality oil-bearing sandstone reservoirs. We are encouraged by these results and we're assessing the commercial viability of the resource as well as evaluating additional potential on the block. In Romania, drilling continues in the deepwater Neptun Block with five wells drilled to date. The potential for commercial development will be assessed after the completion of the drilling program. In the Kurdistan region of Iraq, drilling activities on the Al-Kush Block are underway and anticipated to finish later this year. Turning now to the status update on our new development projects, in Canada, the Kearl expansion project started up ahead of schedule in June and is currently producing more than 100,000 barrels of bitumen per day. This development of the Kearl resource has enabled us to draw significant learnings from the initial development project and capture lower capital costs and operating efficiencies. From Kearl, production averaged 130,000 barrels per day in the second quarter and is ultimately expected to reach 220,000 barrels per day. Erha North Phase 2 in Nigeria is another example of a capital efficient development. This subsea project utilizes existing processing facilities and avoids the need for an additional FPSO vessel. Deepwater drilling and subsea equipment installation are progressing, with start-up expected later this year. At the Banyu Urip development in Indonesia, we continue to experience favorable well performance and production is now more than 80,000 barrels per day. The central processing facility is expected to start up in the next few months which will enable the project to reach peak production of more than 200,000 barrels per day by year-end. In the U.S., Lower 48 onshore, we have maintained a measured investment program to unlock the value of more than 15 billion oil equivalent barrels. ExxonMobil is a leading producer onshore and the largest producer in the United States. Through our XTO affiliate, we operate in all major U.S. unconventional oil and gas plays. Longer-term, gas investment is paced with anticipated demand growth whereas near-term emphasis is on the development of 2.4 million net acres in the liquids-rich Bakken, Permian, and Woodford, Ardmore, and Marietta where investment opportunities remain attractive in a phased price environment. Net production in these three areas was about 240,000 oil equivalent barrels per day in the second quarter, up more than 20% from the second quarter of last year. Throughout the commodity price cycle, ExxonMobil has a relentless focus on reducing costs and improving efficiency in our operations while maintaining high operational integrity. We regularly assess our performance relative to the competitors and strive to be best in class. As this chart illustrates, our efforts deliver results. XTO is a leader in exploration and development costs per barrel of crude reserves added, just one metric of many that are considered. This position is enabled by our disciplined and measured approach to resource development, deployment of proprietary technologies, and our intense focus on efficiency and productivity. We also demonstrated the capability to respond quickly to a rapidly changing environment and to date have captured incremental savings of about 30% in drilling and completion costs from the peak in 2014. These savings include market benefits as well as ongoing structural cost efficiencies and productivity improvements across our operations. I'd like to conclude this morning's comments with a summary of our year-to-date performance. In short, the Corporation is delivering on its investment and operating commitments. Through midyear, ExxonMobil earned $9.1 billion benefiting from our integrated business which captures value throughout the commodity price cycle as demonstrated by our Downstream and Chemical results. In the Upstream, production increased to 4.1 million oil equivalent barrels per day, up almost 3% year on year and remains in line with our plans. Volume contributions from successful new developments underscore our superb project execution capabilities and reputation as a reliable operator. Our operational results combined with continued capital discipline generated cash flow from operations and asset sales of $17.9 billion and free cash flow of $3.9 billion. Our commitment to our shareholders remains strong as the Corporation distributed $8 billion to shareholders through midyear. Regardless of industry conditions, we remain focused on what we control and are driven to create shareholder value through the cycle. That concludes my prepared remarks and I would now be happy to take your questions.

First question is one asking about CapEx, what your latest thoughts are for the budget for this year, and then as we look ahead post-2015, at the Analyst Day you said sub-$34 billion. It was a bit vague; a lot of your peers have been talking about reducing their sustaining capital costs as you look ahead. So just wanted to get any thoughts from you about perhaps where CapEx could go over the next few years, if you have any updates.

I'll tell you that we have no new guidance on our – so our CapEx guidance for 2015 remains at $34 billion, but having said that, given our ongoing focus on capital efficiency and the very successful capture of market savings in the current business climate, I think it is fair to say that there is a downward vector on that number. And that type of focus and efficiency will be carried on into the subsequent years. I haven't said that; also note that we continue to invest in the business, and we have a very attractive inventory of high-quality opportunities, and given the financial flexibility we've got, we can garner some real benefits during the down cycle in a softer market environment.

Sure, okay. Second question is on the acquisition environment; seems like others have been talking about the bid-ask spread, maybe starting to improve a bit here. Maybe you could just talk about what you're seeing, are any attractive opportunities starting to pop up on your radar screen, and just more broadly, as you think about the portfolio, are there places where you think inorganically you'd like to shift the mix every time, and I'm specifically thinking about short cycle?

Let me just broadly speak on acquisition or what we like to say as asset management. I characterize it for us as business as normal. We always keep alert to value opportunities not only to pick up what we believe are strategic and high-value opportunities but looking for means to create greater value from our existing portfolio. We keep alert in terms of what we would target. If you step back and think about the diversity of our resource base, we're very well covered across all of the resource types. We're always interested in expanding those positions or further high-grading them. So I wouldn't suggest that as we consider opportunities for picking up additional assets that we're more focused in one area or the other; we're always looking to high-grade in the portfolio. And Phil, that also includes our exploration program. It is designed to identify higher value opportunities to be added to the resource base or maybe to displace what we see is not as relatively significant as the exploration program can add to.

Sorry, my line cut out there for a minute, so I hope this question hasn't been asked already, but there are two things I wanted to hit this morning, Jeff, if I may. First one is on tax. I'm trying to understand the extent of, I guess the mess on the internationally Imperial we're all looking at anyway, and we're noting what Imperial did with their tax charge related to the change in the Canadian tax regime. So I wonder if you could address that issue first, and then I have a follow-up please.

If you look at our tax in the second quarter of 2015 relative to 2014, we're up just over 3%. I'd say that about 5% of that were associated with one-time tax items, the largest piece being in the Alberta tax that I mentioned in my prepared comments. The rest of the closure on that, down about 1%, is really due to the portfolio mix of income across our various business segments and geographies. If you look sequentially, Doug, we're up almost 12%. And again, the mix effect adds about a 6% increase and the one-time items add about 6%, 4% due to the Alberta tax increase and then just under 2% associated with the absence of the first quarter U.K.'s tax rate change.

In absolute terms, Jeff, order of magnitude it looks to us like that was somewhere around $0.10 or $0.12 in the quarter of non-recurring non-cash. Is that sum about right?

Say a little bit more, Doug, on how you're coming up with that.

So I think the $320 million was what Imperial took, that alone is $0.08, right?

The Alberta, as I said in my prepared comments, Doug, was about $260 million ExxonMobil share.

Okay, alright. I'll go back and look at that. My follow-up is really on the Downstream. I mean, obviously, I realize for commercial reasons you don't want to talk about Torrance explicitly, but when we look at the can of results that other West Coast operators have had and the relatively weak year at Downstream that you had, it kind of strikes me that you probably have some – there's probably some merit in giving us some idea of what the likelihood of Torrance coming back online is without all the additional cost of importing gasoline and so on. So to the best that you can at this point, Jeff, can you give us an order of magnitude in terms of timing as to when you expect Torrance to get back to where it ought to be?

I think first if I could, Doug, just to comment on your statement about a relatively weak Downstream in the second quarter, now I'd first say that we've seen significant margin improvement relative to last year. Second, as I commented on, we did have a very heavy maintenance period in the second quarter of 2015 and that had the downward impacts I referenced in my prepared comments. In terms of Torrance, I think you probably know, Doug, that some of the units in the refinery are operational at reduced rates. We are producing gasoline by importing components and blending with refinery production, and I'd also say we're also producing distillates. We are progressing repair of the electrostatic precipitator as well as pursuing interim options. It is difficult to provide you a time at this point, given the definition work that's underway as well as the regulatory review that's underway. As we get closer to defining that timeline, we'll look for an opportunity to share that broadly.

I appreciate you there. You've at least taken a stab at the answer. Thanks, Jeff.

Question for you on the gas volumes which were fairly weak. I think you pointed out in the press release 622 million cubic feet down year-over-year. Could you highlight the Netherlands component of that, maybe give us an update on, for one, what contribution the Netherlands had in that decline, and then maybe some timing or outlook on when that may come back?

The Netherlands was, as you could appreciate, a large component. It was about 600 million in the second quarter relative to the prior year, prior quarter.

Okay, and any thoughts on when that may return to market?

The Netherlands on a quarter-to-quarter basis was also say with the regulatory restrictions that the government has placed on the asset, and that will return over time, but it's going to be a constrained cap on what we can produce from the resource.

Okay, fair enough. The second question for you, on Slide 11 you highlighted some of the sequential decline. I guess I know the benchmarks were up; I know you've got some issues with tax and whatnot, but that $1 billion waterfall on the other category, can you kind of highlight what is in there besides tax? And then also if you could maybe highlight some of the LNG impacts? I know pricing got clearly weak this quarter.

So on the $1 billion other component, this is the indiscernible, and about 60% of that had to do with tax, 15% or so was Forex and the rest is a number of other puts and takes. On your comment about LNG, let me just broadly say that our natural gas realizations had a negative effect of about $300 million. So to square that with the $600 million increase in realizations, we had about $900 million positive due to liquids and $300 million due to negative gas realizations.

Let me follow up on CapEx and the down-cycle approach. Your peers appear or at least are more vocal in cost-cutting and laying off employees, increasing asset sales, and reducing the forward CapEx guidance to close their funding gaps by almost extensional upstream struggle. So I mean your releasing call has been different. Is that just stylistic, or does it mean a different approach by Exxon through the down-cycle? Any comments there?

I would back up and just talk fundamentally. Culturally, the organization is designed to constantly focus on capital efficiency and cost management, okay. What we are looking for always, Evan, is to drive the cost structure down in the business, okay, and when we have a down-cycle like we're seeing right now, we further are well-positioned to quickly lead that cost curve in capturing market savings. Now on top of that, we've got that financial flexibility to invest through the cycle, and that does very much position us to capture those market savings in the down cycle. So in short, I'd say it is a focus regardless of where we are in the cycle. Likewise on staffing, I mean you mentioned common staffing. I mean first and foremost, I want to highlight that our people are our greatest asset, and they really drive the success of this Company. Therefore, we take a very measured approach to managing our headcount given the cyclical nature of the business and the need for us to be ever more productive, and in doing so we keep an unrelenting focus on capturing organizational efficiencies to keep the organization right-sized, again, given the likelihood of business volatility. So if you look at our employee headcount, it has been coming down consistently since the merger of Exxon and Mobil where we were at about 125,000 employees, today we're at just over 80,000 employees. You may recall during the Analyst Meeting that the Chairman talked about some of this and he gave some examples by way of steps that we've taken well in advance of the down-cycle in order to do exactly what the numbers are depicting.

Right, and your CapEx appears to be trending at least below guidance so far this year. My follow-up on the Downstream, and maybe as it relates to the U.S. Upstream, I mean can you discuss crude transfer pricing assumptions between North American Upstream and refining? I mean it would appear that refining with offset may not be entirely market-based, kind of understating refining and transferring some of that to your Upstream. Any color there would be helpful.

I mean it is very much market-based. I mean as you know, our integrated sites have the capability to run at a very, very wide range of feedstocks. I can't get into the specific pricing at all but we have very competitive capacity within the U.S.; we're the largest in the Gulf Coast and mid-continent. As you know, our capacity increase is greater than our overall U.S. production. So we're also out there picking up supplies that meet our system's needs. Our mid-continent and Gulf Coast refineries have increased processing of advantaged North American crudes. Currently about 45% of the slate was North America in 2011, and currently we're at about 70% in 2014. The key point I want to emphasize here is that we get intrinsic value given the integration of our operations between Upstream, Downstream, and the Chemical business, allowing us to really focus on optimizing the value of the molecule.

This is just a philosophical question. I mean, Jeff, you've got a great balance sheet and you've just reduced the buyback. Are you worried about future deterioration in cash flows due to the macro? Is this just a decision that's just made quarter-to-quarter without thinking about the implications? I know people are chattering in the market this morning that you're trying to conserve cash for M&A, so maybe just a comment there, and then I've got a detailed comment on the results.

Ed, just go back, fundamentally our business plans and our investment strategy come from our perspective on the long-term that we share with you all in our energy outlook. That's what really sets our business strategy and our investment outlook. Now stepping back from that, we maintain a very robust balance sheet, as you say, and we have the significant inventory investment opportunities, over 90 billion barrels of high-quality resources, a very strong inventory of Downstream and Chemical opportunities. But we manage the cash flow looking at the current business climate as well as the future outlook and we have a high degree of confidence in what we expect supply/demand to do in the future. Fundamentally, we're committed to our shareholders to continue to provide a reliable and growing dividend, and I think the continued buyback is evidence of the confidence that we have in the integrated business model.

You mentioned the LNG impact which was helpful. Obviously, Asia LNG prices might come in the spot market, particularly not contract, come under where the pressure is. All of these Australian projects try and fight their way into the market and they all have commission cargoes and some spot with them. Can you sort of give us a sense of how much flexibility in the overall contract structure your customers have to sort of say, we're going to take minimum amounts of volumes to maximize our advantage to take some perhaps the cheapest bulk cargoes that are available? I'm just trying to get a sense of is there a little bit of the margin or price risk and volume risk even to your sort of existing LNG business, and it's fine for you to say, no, there's not a big risk, I mean that could just be the answer.

Sure. I'd just remind you that a majority of our LNG is under long-term contract. So we have very little spot risk and we've got diversion capability in the existing contracts to allow us to capture a greater value there.

So it's pretty clear that there is a path to grow production through 2017 with some of these large capital projects that you talked about and seeing indications of production growth here in 2015. One of the questions investors frequently ask is, how does Exxon grow production post-2017, which we'll probably get some line of sight on at the next Analyst Day when you roll forward past 2017, but any initial color about how you think about growth especially if the forward curve proves correct post-2017 would be valuable?

I'd say first and foremost, just step back a moment and remind everybody that based on that very sizable high-quality resource base we've been talking about, we've had a very significant Upstream investment program in place now for some period of time whereby from 2012 to 2017 we had committed to our shareholders to bring on 32 high-quality long-life assets. We're about halfway through that in terms of starting them up. We had a very substantial tranche of them starting up in 2014 with eight. This year we have another seven starting up. As you go into 2016-2017, we've got the rest of them coming on. The information that we had shared back at Analyst Meeting, we would grow capacity by about 1.1 million oil equivalent barrels per day, and recognizing that those projects are starting up in 2017, we're just at the early stages; they would ramp up into 2018 and thereafter. We also shared, Neil, in our F&O review the list of projects that we've got on the table right now for 2018 forward. These are all in different stages of progress; some are in development planning, some are in Beats, but that is the list that we are working on to bring to an FID decision. Some of these that we're working to further optimize in the current price environment, some may have some opportunities to enhance the commercial terms, but as we get closer to FID's decisions, we'll signal where we are. As you indicated, we'll provide another update in March of next year which will take us beyond the 2017 horizon. But all that said, I want to reinforce that we've got this very robust inventory of investment opportunities, and I don't want to focus just on the Upstream, the Downstream and Chemical business as well, and that positions us well to be very selective on what we want to progress and when we want to progress, and it gives us the capability on those other assets or investment opportunities to keep working on them to make sure that we're capturing the greatest value from it.

Thanks, Jeff. And then the follow-up is on that point about Chemicals; it was one of the few places in the quarter where we saw a real upside to our numbers. Just wanted to talk about what you're seeing from the macro in the Chemical space, clearly margins having compressed as much as some would've thought given the move down in Brent and then just how you're thinking about growing that business going forward.

So just broadly speaking, as you can appreciate, there are structural differences in the Chemical business. U.S. natural gas and natural gas liquids provide for very strong margins and advantage polyethylene. In Europe and Asia-Pacific, the liquids fees, energy prices have been hard, and we were at the bottom cycle in Asia-Pacific but we saw in the first half material improvement due to lower fees and energy costs. Specialty margins have declined over the past few years with capacity additions exceeding demand growth, but demand growth remains robust. So as we've said before, our long-term business has a positive outlook for global demand expecting to exceed GDP by about 1.5%, or said in another way, growing by more than 50% over the next 10 years, of which about two-thirds of that will be in Asia. So very well-positioned to participate, as you see that we're making some important investments like the expansion of Baytown that allows us to continue to participate in the high value polyethylene market given the very low feed costs we have here in North America.

I appreciate the comments on the whole savings in the U.S. Lower 48. I wonder if you could offer what Exxon is seeing as far as cost savings internationally, free the projects under construction, maybe some currently in the development phase and maybe even offshore as well. Do you expect to capture some of the cost savings there and what would be some of the timing on that relative to what you've seen so far in the U.S.?

I would tell you Allen that let me break it up between capital and expense, and to answer your question right now, yes, we are capturing cost savings across our global portfolio. On the cost side, I just want to keep on emphasizing, cost management is a fundamental driver in the success of our business, no doubt about it. Throughout that business cycle, our organization has a strong culture of driving down the cost structure, and then when we're in these down cycles, we expect to lead the cost curve and capture additional market savings, so ongoing structural improvements and additional market savings in the down cycle. So we're very well positioned, and one of the things that allows us to react very quickly, as I mentioned last quarter, is that we've got a global procurement organization that is always focused on capturing the lowest lifecycle cost, and they are absolutely critical in managing our overall cost structure. As you can appreciate, Allen, savings vary significantly by region and type of service. By way of example, our base metals are down as much as 40%. Engineering services and construction labor is down 10% plus. Rig rates are down across the board, both land and floater. On floater, the day rates of mobilization costs are down anywhere from 25% to 40%. So we're well positioned to capture that both on the cost as well as the capital side.

Great, thanks. One more question, maybe a bit premature but certainly made headlines of late, along with the Iran deal, it seems that some of your peers have become interested, I know there's been some headlines suggesting Exxon as well. What would you need to see in Iran as far as milestones for you potentially to become interesting and doing business there?

Allen, I'd just say that we'll continue to monitor the circumstance and I want to be really clear that we'll remain in full compliance with existing sanctions. As you know, there are multiple sanctions that apply to U.S. companies. That's all I can really say about that right now, Allen.

Two questions. Thanks for the additional color on Lower 48. I'm wondering if you could give us the breakdown in the production and rig activity by the three main unconventional plays, and talk about how you expect things tracking in the back half of the year.

So really good growth there, I mean from a net production basis, as I said we're producing about 240,000 barrels a day, over 20% increase quarter-on-quarter versus the prior year. Permian is about 120,000 barrels of that, Bakken just over 80,000 barrels, and Woodford is about 40,000 barrels.

And rig activity, please?

So our rig counts have come down just a little bit. From the first quarter, we're down about 10 rigs, so we're currently running 34 rigs in those three plays. We've been able to continue to high-grade the activity. I think as we showed in the Analyst Meeting, we continue to capture both cost efficiencies and productivity improvements. A lot of what we learned in these plays is being quickly shared to make sure that we're integrating all those learnings into our forward execution plans, but very pleased with the positions that we've got in those assets, and we've got a very sizable inventory of drillable prospects.

So would you think that there would be upside to the incremental 2017 target? I think it was 150,000 barrels a day. Would you, given efficiencies?

I mean we are keeping a measured pace as we said previously. If you think back over the ups and downs, when everybody was really picking up a lot of rigs, we took a measured pace and made sure that we were going at a pace that we can fully capture the benefits of the learnings that we were realizing. Likewise, in the down-cycle, our rig counts haven't come down as significantly as you've seen in the industry because we've been able to capture those learnings, and the economics of these investments are still robust. So I would give you a response of a measured pace; with a very attractive inventory of opportunities, we'll keep moving forward and anticipate, as we showed in the Analyst Meeting, a growth in our unconventional liquids volumes.

Great. And my second question is on LNG. Spot LNG market has been surprisingly strong, over $8 near-term, would be 15% oil equivalent. Just wanted to get your thoughts on that; is it seasonality or something else, and could you update on the demand pattern that you're seeing in Asia?

Broadly speaking, I mean as you can appreciate, there's a lot that goes into this. As we've said, gas demand has grown at about 1.6% per year. LNG capacity will probably triple from 2010 to 2040. So you're seeing a general demand growth that's underpinning, obviously underpinning realizations. There are a lot of other country-level dynamics like alternatives, nuclear power, fuel switching from coal to gas, all those variables really play into this 1.6% per year that I mentioned.

Two questions if I could. If we're looking at your very sizable total resource which is over indiscernible, do you have a rough estimate that what's the percentage of that resource base already passed all the regulatory hurdles and with today's technology will be able to produce and earn a 10% after-tax indiscernible way of return at a $60 to $70 barrel price? Any kind of color you can provide?

I would tell you, I'd actually think about it differently, Paul, and that the resource base is in various stages of development planning. Some assets clearly, as I indicated previously to Neil, some of those assets are currently on the table right now in development planning and pre-feed, some of the assets are probable reserves in our possible or static resources or under various stages of development planning in order to ensure that we are defining the most attractive returns for those resources. And some, we make it to the point, Paul, that we have a better alternative to monetize; this may include divestment. But it's a dynamic resource base that is constantly being upgraded with new additions, pulling things out that we don't see as creating a value for the Corporation. And I'll give you one example by way of illustration. You think about the sizable Julia resource and how we've optimized that to a much smaller initial development in order to de-risk the overall resource size; that's the type of optimization that I'm talking about and based on that de-risking it will there position us on future investment opportunities.

Great. Second question, just some quick numbers; I think in a number of segments that you have some asset sales gain. Can you just give us what is the asset sales gain in the second quarter by segment and breakdown between U.S. and international and also tell us what is the Kearl current production in Phase 1 and Phase 2 separately?

So in terms of the earnings impact from our asset sales in the second quarter, it was about $490 million. A majority of that, Paul, was in the Chemical business. In terms of Kearl, it's in total as I said is producing about 130 – or in the second quarter it was producing about 230,000 barrels per day. The Phase 1 or the initial development was around 100,000 barrels, and Phase 2 was around 30,000 barrels.

Jeff, do you have the latest number in July in the last couple, maybe a week or so, on Kearl?

On Kearl, no, I don't have anything to share at this point.

Guess one question hasn't really been asked I'd like to get out there. Oil prices this low, last time we had a sustained lower for longer situation, a lot of mergers in the space. I know you don't want to talk about anything specific, but as a general sort of commentary, on maybe the bid-ask spread that's out there, the type of assets that might be interesting to axe on, if you could give us any clarity on that?

Roger, that was similar to an earlier question. As I said earlier, I would just say that we keep alert to where we've got value propositions, and the way I clarify that is, you know, bolt-on acquisitions that have natural synergies with our business, long-life assets that we think that our expertise in operating experience will bring intrinsic value associated with it. It's not focused on a specific resource type but it's really focused on where we think that our unique experiences can add value that others can't see.

And on the bid-ask spread, maybe how that's – if it's changed at all, if there's anything you can add there?

Roger, I really don't have much to add on there. I mean that's really a function of the transactions. I mean that certainly staying in a lower price environment is going to encourage both buyers and sellers to find closure.

Okay. And then as kind of the unrelated follow-up, in Guyana the big discovery, is there any sort of timeline at all we can be thinking about at this point for the next appraisal well and then if that goes, how you think about some of the other things including the border dispute with Venezuela, et cetera?

As I said, we're certainly very encouraged by the first well. It is one well in a 6.6 million acre block. We are currently evaluating that well and we're laying out, if you will, the plans moving forward. You can expect the intent for us to not only further appraise the discovery but pursue other opportunities on the block. I want to be clear though that we follow all the laws within the host countries and international law, and that we're operating on this block on a license from the government of Guyana, and the border matters are really a function or should stay with the governments to address through appropriate channels.

Maybe if I could one follow-up on costs. I know you've talked about cost control efforts a couple of times already, but maybe not on the CapEx side but if we look on the OpEx side or the expense side of the Company, a lot of your competitors have talked about percentages in terms of year-over-year decreases and OpEx or targets in terms of absolute numbers that they think they can pull out of the business. I mean, any guidance you can give us in terms of maybe where your cost structure might be year on year or how much you think you might be able to pull out on relative to the 2014 basis?

Obviously, our objective is to make sure that we're capturing all those opportunities, both structural and market out there, and at the same time ensuring that we maintain the high integrity of our operations. I think, Ryan, the ultimate measure here is our industry-leading unit cost performance that we've seen over the last several years, and while it's still early, I don't want to go too far with this. We are seeing the unit cost on a downward trend year-to-date, almost 9% down from where we were last year, but that's about as far as I'll quantify at this point. Obviously, this is a key element to ensuring that we remain a leader in unit profitability as well.

Good, thank you. And maybe one question on LNG and thoughts over on the business, we've had a number of questions on spot pricing and trends, but if you look at – you've got a decent queue of potential development projects that could happen at some point over time. Can you talk about maybe what would be the threshold that you would need to move forward on some of these projects? Is it local permitting? Is it an effort on reducing costs in the industry and getting costs down to a place that's competitive? Is it a wide bid-ask spread between buyers and sellers right now? Any thoughts in general, I guess on your asset portfolio on LNG on the development side and what you're seeing in the market?

Sure. Broadly speaking, as you know, LNG is a key component of our portfolio and it's an important part of our margin generation. As I said earlier, we've got a very good inventory, and including in that inventory is a number of LNG projects and it's all based on our assessment. As I indicated, that gas will grow by about 1.6% per year between now and 2040 and more specifically, LNG demand will triple from 2010 to 2040. So that is the value proposition we're pursuing. We've got a number of projects moving forward concurrently. We're going to be very selective in what we invest in. To your question about what does it take to make it go forward, it's all the things you mentioned; it's making sure that we get a competitive cost structure, that we've got stable, transparent fiscal terms to underpin a very capital intensive investment, and that's why we're progressing settlement at the same time. I would tell you that kind of the brownfield type expansions are probably going to be the lowest cost LNG add. By way of example, our Papua New Guinea project started up ahead of schedule, very, very good reliability, very well-positioned to compete in expansion should we identify sufficient resource, having the assets that we have in the U.S. positions us very well, Alaska, West Coast of Canada continue to progress. Those opportunities will require more of what we were talking about in terms of cost, in terms of fiscal terms, regulatory environment. So in short, what I'd say, Ryan, is that the demand projection is there; obviously we've got the capability to participate in that, and we're very well-positioned with a very good inventory of high-quality opportunities to meet that demand growth.

Just looking at the Downstream business, there have been a lot of press reports and/or regulatory filings about a potential substantial expansion of Beaumont. I was wondering if you could comment on that, provide any color around the thinking there?

So just again, taking a portfolio look, Brad, we regularly evaluate our assets, our various business lines for where we can grow earnings or optimize the long-term value of it, and in the Downstream business, it's focused in the following areas; expanding our logistics, expanding our feedstock, reducing our overall cost structure, and importantly increasing high-value product yields. You'll see that one of those areas or one or more of those areas will underpin the investment projects that we have communicated have been through FID, such as the indiscernible investment. As it pertains to Beaumont, we typically assess those activities. I understand that that may include some discussions with the regulators. It doesn't indicate that we have made a decision, and when we get close to an FID and we've made that decision, we'll communicate that accordingly.

Okay, I understood. And then looking in California on the Upstream side, I was curious what the impact during the quarter was given the planned pipeline downtime and what the outlook is there?

Good question, Ryan. I mean as you all know, the planned All American Pipeline was down due to a failure of the line in the second quarter. We've looked for options to go ahead and keep our facility on without that pipeline running or until we are able to find an alternative export route as while it will be shut down. Before it was shut down, it was producing somewhere around 30,000 barrels a day. In fact that was a 2014 number. So we'll keep focused on it, we'll keep working with the regulator as well as the All American Pipeline to identify the earliest restart.

First question is, just looking at some of the great projects again that surpass 2018, it seems to me like you focused on three key areas or things if you like which is getting more challenged over the next few years. So when you look at international LNG, seems to be a little more competition coming in from domestic U.S. LNG. When you look at your oilsands projects, they are relatively high cost and impacted by potential carbon pricing and higher taxes coming through. In Nigeria, clearly a difficult political environment there and tax uncertainty. Just wondering, given those as kind of your key areas, how comfortable are you with those areas and the potential growth there?

Anish, we're in the risk management business. Everything that we do has a level of risk that we've got to judge, whether it would be geopolitical risk, economic risk, technical uncertainty, and that is the world we live in, and I think the organization has demonstrated over the years that it's got the expertise and the capabilities to take on these more challenging resources and convert them into value propositions for our shareholders. So the areas you talked about, I mean take a look at Papua New Guinea LNG. I mean no infrastructure; we were able to build that into a very successful project that's going to supply an important part of LNG demand in the future. We have a good track record in all these areas; we're very good at capturing the learnings and transporting those learnings into our future resource development activities to make sure that we maximize return, and as I said to Paul earlier, if we don't see the value proposition there, we will find other ways to monetize that asset.

Okay, great. And just a follow-on, in terms of your future projects, I'm just thinking, how you think about delaying projects in an attempt to, in this kind of falling kind of service price environment to capture lower prices. Is that something that you're actively kind of looking to do or would you just go ahead with the projects as it kind of makes sense in terms of the economics at the moment?

I mean remember these projects that you referenced earlier are multi-year projects; they happen over a period of time, and we are looking for not only the market savings but I'll stress again the structural savings. Let me use an example of what I'm talking about. We went forward with both the Arkutun-Dagi and the Hebron developments concurrently because we saw a very consistent development option and the tremendous benefit that we'd get by learning curve advantages. So both GBS, we used a comparable design shop for both of them, we used the same GBS contractor, we used the same topside contractor, and we captured that immediate learning curve benefit. On top of that, in a lower price cycle, as I said earlier, we're very well positioned with the global procurement organization to be first in line in capturing those market savings, and given our long-term investment and our expectation of what demand is going to do, we're very confident that over the timeframe – the things we're investing in today, some of them we won't see production on for five or ten years. We're very confident in our demand projections, in our ability to turn that into accretive financial performance.

When I hear what you're saying about costs and potential M&A, and knowing what you said in the past about the Permian, it feels like that's the best opportunity for you to combine the overlap that you have with the potential to drive out costs. I think you've highlighted that it's a very fragmented zone. And I would also think that the Bakken is similar. But you really don't have a lot in the Eagle Ford. So my assumption is that essentially the Permian would be the most attractive place for you, and then the Bakken to take advantage of this low price environment.

Paul, just broadly speaking, we keep focused globally and we've got those type of opportunities in other countries that will naturally maintain a line of sight on should the right value proposition come forward. If you want to focus in them, conventional, certainly the ownership structure in the Permian by way of example is very, very diverse, and where we can find natural synergies. I mean over the last several years, we've made a number of bolt-on acquisitions that have increased our position there, and you get a value uplift when we're able to do that, where it's within our operational structure.

Yes, and I guess the operational structure is well-suited because of the XTO separate division you have gives you the flexibility?

That's correct.

One thing I'm worried about, Jeff, is with the replacement, just in as far as I don't think you've had any FIDs this year, indiscernible just that your business bookings last year were heavily dominated by the U.S. Could you update us on where we stand as regards with those replacements?

Obviously, that's an annual process and we've fully replaced our production for 21 straight years. We've got a very good inventory that we're working on to convert to an FID decision and proved reserves as well as a very active exploration program. So we've been very successful as the history shows, and I'd say that the prognosis in the future will remain the same.

Jeff, do you know how many FIDs you had last year?

Not off the top of my head, Paul, no.

Thanks for your comment on operating costs earlier. Can you give us some sort of magnitude about how much of that 9% you might feel is natural deflation in the environment, like energy prices, and how much is your in cost management?

Alastair, I'd just tell you that the organization wants to keep focused on the structural improvements as well as net market capture. Everything is under focus constantly, even when we're at $100 per barrel, but I don't have any specific numbers to breakout on the benefit today.

And secondly, in the Chemicals business in this environment, you've seen that difference in the profitability between the base and derivative businesses?

Remember it's all premised under very strong demand growth, and our investments are strategically placed in order to make sure that we can compete competitively over that timeframe. I think we're very well-positioned in both the commodity and specialties markets.

Jeff, you highlighted on Slide 18, Lower 48 onshore F&D cost, best in class by a substantial margin. I believe those costs have been declining in recent years as well and likely continue to decline. So I was just wondering if you could discuss how that positive trend for U.S. Lower 48 F&D compares to the trends that you're seeing internationally and that you've seen in recent years, where it appears F&D for the industry has risen considerably in some cases. So can you just discuss your thoughts on that emergence, what you're seeing, and also how that might influence capital allocation and strategy long-term? Specifically does it lead you to believe you need to find a way to allocate more capital to the regions where you can most efficiently add reserves, which appears to be the U.S.?

I think it's an excellent question, Guy, because I think this is just one example of what we do across our whole global portfolio. I talked about by way of another example, we've shown you the XTO example. In my prepared comments, I talked about Erha North Phase 2. Last quarter I talked about the start-up of Kizomba Satellites Phase 2, but that's another really good example that instead of – that we sequenced the resource development in a manner that we can fully leverage the fixed investment over a period of time, and what that does is that lowers our overall cost structure or E&D costs globally. And in a deepwater environment where we've got to be very careful that we've got very good execution plans and that we execute flawlessly. So it's a very strong focus across the world whether it's in the deepwater with Kizomba Satellites Phase 2 and Erha North Phase 2 or we're talking about the Arctic or sub-Arctic like in Arkutun-Dagi and Hebron, there is an ongoing emphasis to try to get that cost structure down. And that's why I made the point earlier that this is something that we have to work 365 days a year, it's not something that's driven by the price environment, it's driven by the need to be ever more productive and to compete in a market that you know there's a lot of investment dollars going in. So we keep line of sight on where we've got cost opportunities.

Thanks, Jeff. And last one for me, liquids production up 12% on the year, so obviously very impressive growth; major projects ramping up, you get some PSC benefit obviously, but it also appears like you're showing growth in some areas where you don't have high-profile major projects, North Sea oil for example, but it appears that reliability uptime may be improving just across the portfolio. Is that an accurate observation and is there any detail you can provide of how the base level of production is performing perhaps relative to expectations coming into the year because it seems to be doing better?

It's another good question, and you may recall back in the Analyst presentation, we spent a little bit of time; the Chairman showed a chart that tries to quantify the volume add that we make with our focus on reliability. We are making very significant gains on improving overall operating reliability, and I'll emphasize, not only in the Upstream but also across our manufacturing business as well. As we focus intensely on cost structure, we do the same on uptime and reliability, and really try to transfer those learnings quickly across the Corporation to make sure that once again we're best in class.

Most things have been asked here, but you've seen a lot of your peers as well as some large cap E&Ps take significant impairments. You have a very robust resource base, as you've stated. Are there any issues for say intermediate-term projects coming off the books on a long-term basis for Exxon?

There are two parts to your question. One is if we've got resources that are in a resource base that ultimately we don't see the long-term value, as I indicated earlier, John, we will look for ways to monetize them which may include some level of divestment. In terms specifically of impairments, as you know, we live in a commodity price environment that has great volatility, but as I've said several times in our energy outlook, the long-term market fundamentals remain unchanged, and the lifespan of our assets is measured really in decades; therefore, our long-term price views are more stable and quite frankly more meaningful for future cash flows and market value. So we expect the business to more than recover the carrying value of the assets on the books. Obviously, in the course of our ongoing asset management efforts, we do confirm that asset values fully cover carrying costs.

Great, that's what I wanted to hear. One last one for me, which you probably won't answer, Guyana insignificant, you want to attach a volume sense to that?

John, I think it's just too early. I look forward to that done; I can have more discussion about it as well, but as I said, John, one well in a 6.6 million-acre block, it's a very good start and just watch that space. There's more to be said there, I think.

To conclude, again I want to thank you for your time and your very thoughtful and insightful questions this morning. We appreciate the opportunity to talk about the business and really share the successes of our people that work day in and day out to make sure that we're creating shareholder value. So thanks again, and we look forward to further discussion in the future.