Jeffrey J. Woodbury - Vice President, Investor Relations and Secretary

Douglas Terreson - Evercore ISI Evan Calio - Morgan Stanley & Co. LLC Doug Leggate - Bank of America Merrill Lynch Sam Margolin - Cowen & Co.

LLC Paul Sankey - Wolfe Research LLC Brad Heffern - RBC Capital Markets LLC Edward George Westlake - Credit Suisse Securities (USA) LLC (Broker) Neil Mehta - Goldman Sachs & Co. Ryan Todd - Deutsche Bank Securities, Inc.

Asit Sen - CLSA Americas LLC Philip M. Gresh - JPMorgan Securities LLC Roger D.

Read - Wells Fargo Securities LLC Anish Kapadia - Tudor, Pickering, Holt & Co. International LLP John P.

Herrlin - SG Americas Securities LLC Paul Y. Cheng - Barclays Capital, Inc.

Pavel S. Molchanov - Raymond James & Associates, Inc.

Thank you. Ladies and gentlemen, good morning and welcome to ExxonMobil's second quarter earnings call.

My comments this morning will refer to the slides that are available through the Investors section of our website. Before we go further, I'd like to draw your attention to our cautionary statement, shown on slide two.

Turning now to slide three, let me begin by summarizing the key headlines of our second quarter performance. ExxonMobil earned $1.7 billion in the second quarter.

Our cash flow reflects the durability of the integrated portfolio amid industry volatility. In particular, strong Chemical results highlight sustainable competitive advantages, including gas and liquids cracking capabilities, along with our differentiated product portfolio.

Our financial flexibility enables us to selectively advance new investment opportunities across the value chain, and I'll provide an update on several of these new investments later in the presentation. Moving to slide four, we provide an overview of some of the external factors affecting our results.

Global economic conditions were mixed in the second quarter. U.S.

growth recovered modestly relative to the weak first quarter, and China showed signs of stabilization. However, Europe and Japan experienced slower growth.

Crude oil prices increased, whereas average global natural gas prices decreased sequentially. Global refining margins benefited from improvement in the U.S.

Gulf Coast and Midwest. However, Chemical product margins weakened due to higher feed and energy costs.

Turning now to the financial results as shown on slide five, as indicated, ExxonMobil's second-quarter earnings were $1.7 billion or $0.41 per share. The corporation distributed $3.1 billion in dividends to our shareholders.

CapEx was $5.2 billion, down 38% from the second quarter of last year, reflecting both prudent capital management and strong project execution. Cash flow from operations and asset sales was $5.5 billion.

And at the end of the quarter, cash totaled $4.4 billion and debt was $44.5 billion. The next slide provides additional details on sources and uses of cash.

So over the quarter, cash balances decreased from $4.8 billion to $4.4 billion. Earnings adjusted for depreciation expense, changes in working capital and other items, and our ongoing asset management program yielded $5.5 billion of cash flow from operations and asset sales.

Uses of cash included shareholder distributions of $3.1 billion and net investments in the business of $4.1 billion. Debt and other financing increased cash by $1.3 billion.

Moving now on to slide seven for a review of our segmented results, ExxonMobil's second quarter earnings decreased $2.5 billion from the year-ago quarter due to lower Upstream and Downstream results. Corporate and financing costs in the quarter were in line with our guidance, which remains at $500 million to $700 million on average over the next few years.

In the sequential quarter comparison, shown on slide eight, earnings decreased by $110 million, as stronger Upstream results partly offset lower Downstream and Chemical earnings and higher corporate charges. Turning now to the Upstream financial and operating results, starting on slide nine, second quarter Upstream earnings were $294 million, down $1.7 billion from the year-ago quarter.

Sharply lower realizations decreased earnings by $2.2 billion. Crude prices declined by over $16 per barrel, and gas realizations fell by $1.84 per thousand cubic feet.

Favorable sales mix effects increased earnings $50 million. And all other items added another $450 million, reflecting reduced operating expenses, the absence of an unfavorable one-time impact from the Alberta tax increase, and favorable foreign exchange effects.

Moving to slide 10, oil equivalent production was comparable to the second quarter of last year at about 4 million barrels per day. Liquids production was up 39,000 barrels per day, whereas growth from recent project startups was partly offset by the impact of field decline and downtime events, notably in Nigeria and in Canada with the wildfires in Alberta.

Natural gas production, however, decreased 366 million cubic feet per day, including field decline, downtime, and divestment impacts. Turning now to the sequential comparison, starting on slide 11, Upstream earnings were $370 million higher than the first quarter.

Realizations improved earnings by $960 million. Crude increased nearly $12.50 per barrel.

However, gas realizations decreased by over $0.50 per thousand cubic feet. Unfavorable volume and sales mix effects, including lower seasonal gas demand in Europe and higher downtime, reduced earnings by $280 million.

All other items further decreased earnings by $310 million, including higher exploration expenses, lower gains from asset sales, and less favorable tax items. Moving now to slide 12, sequentially, volumes decreased 368,000 oil equivalent barrels per day, or 8.5%.

Liquid production decreased 208,000 barrels per day, mostly from downtime events and entitlement impacts. Natural gas production decreased 962 million cubic feet per day on seasonally lower European demand.

So moving now to the Downstream results, starting on slide 13, Downstream earnings for the quarter were $825 million, a decrease of $681 million compared to the second quarter of 2015. Weaker refining margins reduced margins by $850 million.

Favorable volume and mix effects, mainly from improved U.S. reliability and lower maintenance activities, improved earnings by $130 million.

All other items increased earnings by $40 million. Turning to slide 14, sequentially, Downstream earnings decreased $81 million.

Stronger refining and marketing margins increased earnings by $80 million, while favorable marketing volumes added $20 million. Other items reduced earnings $180 million, reflecting unfavorable foreign exchange effects and higher maintenance costs.

Moving now to Chemical results, starting on slide 15, second quarter Chemical earnings of $1.2 billion were comparable to the prior-year quarter. Stronger commodity margins from both gas and liquids cracking contributed $150 million.

Favorable volume and mix effects added $70 million, while all other items reduced earnings $250 million, reflecting the absence of asset management gains. Moving to slide 16, sequentially, Chemical earnings decreased $138 million due to weaker margins and an increase of maintenance activity.

The next several charts will provide an update on how the corporation is advancing selective new investments across the value chain to extend our competitive advantage. Chart 17 showcases a good opportunity to add quality resources to our successful LNG operation in Papua New Guinea.

ExxonMobil has a long and successful history in the global LNG business and is proud to have started up the Papua New Guinea LNG project ahead of schedule given its many complexities. In 2015, PNG LNG produced 7.4 million tons per annum, exceeding the original design capacity of 6.9 million tons by 7%.

We continue to safely increase plant throughput and improve reliability at low cost. And in this regard, in June we achieved an annualized rate of 8.2 million tons per annum, the highest monthly rate since startup.

To build on this success, ExxonMobil recently announced plans to acquire InterOil Corporation in a transaction worth more than $2.5 billion, which includes consideration of $45 per share to be paid in ExxonMobil stock. The agreement also includes a contingent payment, which is based on the resource certification of the discovered undeveloped Elk-Antelope field and is payable above 6.2 trillion cubic feet, up to a maximum of 10 trillion cubic feet.

Finally, the agreement is subject to InterOil shareholder approval and the other customary closing conditions and regulatory reviews. This acquisition provides ExxonMobil access to six additional licenses in Papua New Guinea, totaling about 4 million acres.

Elk-Antelope complements our existing discovered undeveloped resources, such as P'nyang, better positioning the co-ventures to expand the existing operation with additional LNG trains. The transaction will allow ExxonMobil to create unique value for shareholders of both companies and the people of Papua New Guinea.

And we look forward to working closely with co-ventures, the government, customers, and importantly, local communities to grow this successful business. Moving now to slide 18 for an update on Upstream projects and exploration activities, where we are advancing several attractive new investment opportunities, ExxonMobil is on track to achieve 10 major projects startups in 2016 and 2017, of which four have already initiated production.

As shown in the photo, excellent progress continues at Hebron, located offshore Eastern Canada. The utilities and process module fabrication is now complete, and it was successfully loaded out in June from the fabrication yard in Korea for transport to Newfoundland and Labrador, where it will then be installed on the gravity-based structure.

Hebron remains on track for a late 2017 startup. In Abu Dhabi, production is steadily increasing in the Upper Zakum field.

Eight drilling rigs are operating on the artificial islands, where gross production has reached 100,000 barrels per day. Aggregate Upper Zakum gross production is currently about 670,000 barrels per day, and production is anticipated to reach 750,000 barrels per day by 2018.

ExxonMobil also recently sanctioned the Tengiz Expansion Project, which is expected to increase crude oil production capacity by up to 300,000 barrels per day, with startup in 2022. ExxonMobil is a 25% shareholder in Tengizchevroil, the operator of the field.

Now in offshore Guyana, we completed drilling operations on the Liza-2 appraisal well. The well test confirmed a world-class discovery, with a recoverable resource estimate of 800 million to 1.4 billion oil equivalent barrels.

The test also confirmed high-quality oil from the same high-porosity sandstone reservoirs we saw in the Liza-1 discovery well. ExxonMobil along with its partners is progressing development planning activities on an early production concept involving a floating production, storage, and offloading facility, along with related subsea production systems.

A final investment decision [FID] will be based on a variety of factors, including further Liza appraisal drilling, regulatory approvals, and market conditions. On July 17, we began drilling the Skipjack prospect, which is located approximately 25 miles northwest of the Liza-1 discovery well.

This is the third well on the Stabroek Block. In addition to these activities, ExxonMobil recently entered into an agreement with The Ratio Companies to acquire a 50% interest in the Kaieteur Block offshore Guyana and will become the operator.

Kaieteur is approximately 250 kilometers offshore Guyana in ultra-deepwater north and adjacent to the Stabroek and Canje blocks. Pending government approval, this deal will bring our total acreage position in Guyana to 11.4 million acres over the three blocks.

Chart 19 showcases improvements in our U.S. unconventional operated portfolio.

ExxonMobil is a leading operator in U.S. unconventional production.

Since 2013, we have more than tripled our gross operated production from the liquids-rich Permian and Bakken plays. Approximately 85% of this is liquids.

We have maintained a relentless focus on reducing costs and improving efficiency while maintaining high operational integrity. We have continued to reduce drilling cost per foot, implement efficiencies, and capture market savings to achieve substantial cost reductions.

With longer lateral lengths and improved completion designs, per well hydrocarbon recovery has dramatically improved. Coupled with lower drilling and completion costs, this high recovery has resulted in a nearly 70% reduction in Permian unit development costs over the past two years.

Our development cost per barrel is now $8 in the Permian and less than $10 in the Bakken. Additionally, we have successfully reduced cash operating costs to approximately $8 per barrel.

As a result of these cost improvements, a large part of the Permian drill-well inventory is economic at prices around $40 per barrel. Over 2,000 drill-well locations in the Permian and Bakken yield a 10% rate of return at $40 per barrel.

This drill-well inventory equates to nine years of continuous drilling at 2015 rig levels, providing ExxonMobil the flexibility to progress profitable short-cycle opportunities and adjust activity in response to market conditions. And, as you can see on the chart, our economic drill-well inventory increases significantly as energy demand and prices improve.

Turning to slide 20 and an update on our Downstream and Chemical businesses where we are selectively investing to grow higher-value product sales. First, we recently completed the expansion of our Taicang lubricants plant.

This facility employs innovative blending technologies that increase operating efficiency and enables us to support growing demand for premium lubricants in China. In the Chemical business, we launched Exceed XP performance polymers, which expands our comprehensive slate of polyethylene products.

This new product provides leading performance in a variety of film applications, including consumer, construction, and agricultural use. Exceed XP was developed using advanced metallocene catalyst technology, process research, and applications expertise.

ExxonMobil recently announced a facility expansion of our Santoprene plant in the United Kingdom to meet growing demand for specialty elastomers for the automotive, consumer, and industrial segments. Additionally, we announced a project at the Beaumont refinery to expand ultra-low-sulfur diesel and gasoline production by more than 40,000 barrels per day.

The upgraded facilities will employ proprietary scan-finding technology to remove sulfur and maximize octane. The corporation also continues to advance new opportunities to meet growing demand for ethylene and related products.

We are evaluating a new project with SABIC to build a world-scale ethylene cracker and derivative units along the U.S. Gulf Coast.

SABIC and ExxonMobil enjoy a long history of successful partnership. Most recently, we completed a joint specialty elastomers project at our Kemya facility in Saudi Arabia.

The facility builds on existing world-scale commodity assets to help meet growing demand for premium synthetic rubbers. Chart 21 illustrates the corporation's year-to-date sources and uses of cash and highlights our ability to meet our financial objectives.

As shown, cash flow from operations and asset sales of $10.5 billion funded shareholder distributions and, together with a moderate increase in debt financing, supported net investments in the business. The scale and integrated nature of our cash flow provide competitive advantage and the flexibility to selectively invest through the cycle.

And we remain resolute in our commitment to pay a reliable and growing dividend. Quarterly dividends per share of $0.75 were up 2.7% versus the second quarter of 2015.

Finally, ExxonMobil generated $1.8 billion of free cash flow during the first half of 2016, reflecting capital discipline and the strength of our business. Moving to slide 22.

So in conclusion, ExxonMobil is delivering on its commitments and continues to create long-term shareholder value through the cycle. At midyear, the corporation has earned $3.5 billion and generated $10.5 billion of cash flow from operations and asset sales amid volatile industry conditions, underscoring the resilience of our integrated business.

Upstream volumes were 4.1 million oil crude barrels per day, and capital spending has been reduced 36% to $10.3 billion. As you just heard, we continue to advance our investment plans to extend competitive advantage and unlock value across the Upstream, Downstream, and Chemical businesses.

And we remain committed to sharing the corporation's success directly with shareholders through the dividend. Year-to-date shareholder distributions totaled $6.2 billion.

That concludes my prepared remarks, and now I'd be happy to take your questions.

Good morning, Jeff.

Good morning, Doug.

A few of your competitors have publicly committed to new capital management plans and performance metrics by which they plan to be held accountable in the future. And on this point, ExxonMobil is typically focused on industry-leading returns across the business mix, I think is the way that Rex [Tillerson] phrases it.

And the company has clearly been successful in that area. But my question is whether that objective may require revision when you consider that none of your peers were able to earn their cost of capital, even with Brent near $100 in 2014.

So we're in a little bit of a different scenario these days, and I wanted to see if there was an update on how the company may be thinking about capital management plans, performance metrics, et cetera, in light of these circumstances?

Yeah, I think nothing has changed in our strategy, Doug. I mean, we fundamentally keep focused on maximizing shareholder value and have always been and will continue to be measuring that based on a return on capital employed.

As we have talked previously, Doug, I mean, the focus is on value. Our decisions are based on the value choices that we make.

Now if we get additional volumes growth or we get additional market share in those choices, well, that makes it even better. But there's no change, we continue to lead on return on capital employed, and we maintain focus on the business fundamentals.

Okay. And I also wanted to ask a question about refined products demand.

Specifically, your refinery throughput and your sales declined about 6% year-over-year, but there were changes to the portfolio along the way. So my question is whether or not there was anything unusual about that data point just because it is minus 6% besides the portfolio factors?

And also what you guys are seeing in refined products demand around the world?

Let me start with the second part of the question. And as you know, demand has been generally strong from gasoline products, and distillate demand is growing, but the issue that we're all faced with right now are very large inventories of products at this point.

The way we'll manage that is like we always manage it. We've got to be the most competitive refiner in the Chemical business out there, and we'll continue to focus on the key elements to achieve that objective.

In terms of the quarter-on-quarter performance, in terms of volumes, it's primarily due to plant maintenance activity.

Okay. Jeff, the year-over-year, first half versus first half, is it the same answer that it was really related to the changes in portfolio and turnarounds?

Is that the way to think about it?

Exactly.

Okay, okay, thanks a lot

Thank you, Doug.

You're welcome.

Good morning, Jeff.

Good morning, Evan.

My first question is on Guyana. It's clearly a large discovery.

Can you share any preliminary thinking on development concepts, when volumes might be realized, whether there would be an earlier full production system? Is Kizomba B a good template here, and thoughts on adding a second rig?

I certainly appreciate and understand all the interest in Guyana. We're very excited by it, as we talked in the past.

We're integrating the data that we're picking up from the drill wells and the seismic analysis real time. You can appreciate there's a good effort around development planning.

And as I said in the prepared comments, the current plan right now is an early production concept as an initial start. It's probably too early to discuss too much of those details.

Clearly, there has been some initial work that we've done for regulatory purposes. But as I said, we have a lot of work to do, and we'll continue to manage it.

When you think about things like bringing in a second rig, that will be a function of a lot of issues. And when you do something like that, Evan, you want to make sure that you've got a really good understanding of what your prospects look like, and you understand the dependencies on them.

You don't want to outrun your headlights on it. Good success so far, we're encouraged about the growth in Guyana and the development capability, but we want to manage this in the most effective way to make sure we maximize the value.

Okay, that's fair. And my second question is another Tier 1 asset here.

The InterOil transaction really has unique value to Exxon due to the PNG LNG brownfield expansion and the economics. Maybe more on the macro, what is your outlook on the LNG markets, and does the potential for multi-train expansions in PNG reduce your appetite for LNG development elsewhere over the next several years?

Thank you.

Evan, I'd say let's start with our energy outlook. And it starts with our forecast that gas is going to grow about 1.6% per year from 2014 to 2040.

And LNG will triple over that time period from today's capacity. So that really sets up the business case for us.

Now, like any type of commodity, there are going to be periods of oversupply and periods of shortness, and we do expect that into the early part of the next decade that there will be some oversupply. But we keep focused on the long-term value proposition.

And I've always said, the energy outlook is one of providing us the insights and informing us for our investment choices. Papua New Guinea, as I said in my prepared comments, has been just a remarkable outcome.

The organization is really proud of the results, and we think we've got a really strong business there. And frankly, I think a brownfield expansion of the existing facility is going to compete very strongly for additional LNG demand in the future.

I think we're very well positioned with the experience that we've got in country, the relationship that we have with the communities and with the government, our marketing capability. So I think the organization sees that as a very significant opportunity moving forward.

Broadly speaking, as you've heard, we've got a number of LNG projects that are in our development planning stages that we think are going to compete for that long-term LNG demand growth.

Great, thank you.

Thanks, Evan.

Thanks. Good morning, Jeff.

How are you today?

Good morning, Doug. How are you?

Good, thanks. I guess can I start with a follow-up please on Evan's question?

I guess I'd like to switch to the additional exploration activity. I'm just wondering.

I realize exploration is what it is. But to the extent you can share any thoughts on risk profile, how you've chosen the next exploration targets because previously that's (30:17), and that seems to have been pushed back in favor of Skipjack.

So what is the read-through? What is your go-forward plan, and is there anything on risk profile you can share from the read-through from Liza (30:30)?

Doug, just to clarify, you are talking about just Guyana right now, right?

Yes, sir, yes.

As I said in my prepared comments, we're drilling the Skipjack prospect. It is testing a similar play to Liza, with comparable resource potential.

Clearly, Liza helped to derisk a new play in a new basin. But as you know, all exploration wells do carry inherent risk.

We do have a lineup of other prospects in the block. As I said, we've added two additional blocks, one that's got a seismic survey in progress and the next one in which we anticipate once the deal is concluded that we will do the same there.

And that will continue to be fed into our list of options, and we'll decide what the next best opportunity is to pursue after Skipjack. But right now, the plan is that the rig will move from Skipjack back to Liza for another appraisal well.

That's terrific. Jeff, if I may just add on this a bit, I think Mark [Albers] had suggested that you did [indiscernible] (31:45) indicators across the whole block.

Would Skipjack qualify under that category?

I'd tell you that the seismic images are similar to Liza, and probably that's where I'll end.

Okay, thanks. My follow-up, a quick one, is M&A.

Last down cycle, you guys obviously were very active. This down cycle is more asset focused with InterOil, it would seem.

What are your thoughts on where the other basins (32:15), things that you could see opportunity? Of course, top of mind is Rex's recent visit to (32:21) and Mozambique.

Really nothing. I'd say from an acquisition standpoint that it's business as normal.

We continue to stay very alert to the value propositions across our portfolio. We're not really focusing on a specific geography or resource type.

But it's got to meet the fundamental quality expectations we shared previously, and that is it's got to compete with the resources we've got in our existing inventory. And we've got to have confidence that we can bring value to it and that it's got long-term strategic value that's going to be accretive to our returns.

As you know, we've got the financial flexibility to do a number of things, and acquisitions is one of those things.

Would you care to address the press speculation in Mozambique?

Doug, I really can't comment on any market speculation.

I'll leave it there, Jeff. I look forward to seeing you in a few weeks.

Thanks.

Thank you, Doug.

Good morning, Jeff. How are you?

Good morning, Sam. How are you?

Good, thanks. I just wanted to actually follow up on the LNG outlook question.

I'm not going to ask you to front-run your 2017 long-term market outlook, but one of the things that other operators are saying is that one of the big challenges in sanctioning LNG projects is that it's difficult to find buyers right now. But it seems like if LNG prices are structurally lower into the long term, maybe demand could accelerate perhaps faster than what the view was one or two years ago.

And I was just wondering if you're seeing anything, if you have spot market exposure, if there seems to be increased penetration of LNG in some markets that you hadn't seen before, and if it was a function of price?

I'd say that certainly there are a lot of players in the LNG market now. But I would also say we have built a very credible reputation with the buyers.

We delivered our projects on time, on schedule. We have an exceptional operations center that has been very effective in managing the contracts that are in place.

So we've got a really good relationship out there with the buyers. We've got a good feeling on where there are market developments.

And you understand that the approach that we take, these are multibillion-dollar developments, and we by and large are going to fund those based on long-term firm commitments. And that's how we manage these investments to ensure that we get an attractive return on such a large commitment.

Okay, thanks for the color, and then just a quick bookkeeping question, if I can. As you know, there's a lot of focus from investors on quarter-to-quarter sources and uses of cash.

I was just looking at this working capital draw, and if we could get a little color on that, if it's going to reverse or maybe what was behind that.

So the working capital had a $2 billion impact, and it really is a function of many different variables in it. But I'll pull out that one is a pension contribution that we had detailed in our 10-K this year, and then the second being just normal account – changes in account balances between receivables and payables.

Okay, thanks so much.

Okay, thank you.

Hi, Jeff.

Good morning, Paul.

Just a quick one on Guyana. You were very successful in Angola with the early production.

Could you be producing within a couple of years, do you think, as soon as 2018?

What we were laying out in our permitting activity is probably early into the next decade at this point. There's a lot to consider to make sure that we are maximizing the value for the resource owner and for the co-ventures.

Understood, Jeff. Thank you.

Secondly, the PNG, would that be for your own – would the InterOil deal be for your own facility, or are you intending to continue with the second development?

Yeah, that's a good question, Paul. Clearly, that's a topic for discussion amongst the co-ventures when we bring it together.

You remember, as I said in my prepared comments, that we've got our already established discovered undeveloped resources that we've been working on in order to underpin an expansion to the existing PNG facility. The Elk-Antelope assets obviously are an attractive add.

When the deal is closed, it's a matter of discussion amongst the co-ventures and the government parties to agree what the best value proposition is for how we develop that. And I think there's a strong case to say that it's going to go through our existing facilities.

Thank you, that's very helpful. Jeff, finally the cash flows of the quarter.

Was there any major distortions in terms of the operating cash flows that we should think about? And can you remind me, do you have a sensitivity of cash flow to a dollar change in the oil price?

Obviously, the concern here is that for the quarter, cash flows are falling short of your combined CapEx and dividend. I know your guidance is for flat volumes.

I assume you're spending at a level to achieve flat volumes. My worry is that maybe we need to see a much higher oil price, I'm thinking more like $60 a barrel to balance this cash flow versus CapEx versus dividend.

Can you give us a sense of how the cash flows would move? And if there was any particular distortion in the quarter?

Thank you.

Yeah, sure, Paul. I mean, there was no specific distortion in the quarter.

I will say that, if you recall in the Analyst Presentation, we did provide you a perspective of cash flow neutrality. In there, if you recall, we used a range of $40 to $80 per barrel, and felt like we were very well positioned to achieve cash flow neutrality by next year.

I think the organization is making some really good progress in reducing our costs and making sure that they're all focused on creating incremental margin. Your comment about price impacts on cash flow, we do provide in the 10-K some pricing sensitivities on earnings that you may want to go ahead and look at.

I will indeed. And, Jeff, sorry, I've had a follow-up request from a client to ask you why is CapEx trending well below the full-year guidance.

Right.

So our CapEx guidance, as you all know, just over $23 billion. Year-to-date, we are trending below, and it's driven by a number of factors.

One is the organization remains focused on capital efficiency. We're still capturing market savings.

Importantly, we continue to execute our projects very well. We're not seeing major budget overruns or extension to the schedules, and that's an important deliverable.

And then there are still opportunities to go ahead and delay some of our resource investments that in this down market we can restructure them to capture additional value. So those factors are what I would summarize as the shortfall year-to-date.

Thank you, Jeff. Have a good weekend.

You too, Paul.

Morning, Jeff.

Good morning, Brad.

I was curious if you could go into the impact from the Canadian wildfires and also the impacts in Nigeria, what kind of volume loss you had during the quarter? And also, I assume the Canadian wildfires are no longer having a substantial impact, but maybe the outlook in Nigeria?

Yeah, sure, Brad. Well, I mean, for the quarter, it was about 100,000 barrel a day impact combined.

The Canadian wildfires, I mean as you know, they're not impacting our assets directly, but we went ahead and shut down out of safety for our organization. This time of year we watch it very closely, but for the most part, we think it is behind us.

Nigeria, you may recall that we did declare a force majeure in May for a period of time, and that resulted from a third-party operator that had an operational instance while they were towing a drill rig that, unfortunately, sat down on one of our pipelines. So we had to shut in the facility to help them remove that rig and then investigate the impact.

More recently here in July, we had another force majeure. We picked up a system anomaly on the offshore export pipeline and have had some initial investigation.

And we believe it was damaged due to a third-party impact. And we're working with the joint venture partner and our government authorities to investigate how to rectify that at this point.

Okay, thanks for that. And then I was curious if you could also talk a little bit about the new petrochemicals plant that you're investigating on the Gulf Coast.

Just thinking about there are a lot of plants in queue ahead of you presumably before that would come online. So how do you think about the supply and demand dynamics of that?

Yeah, really good question, Brad. Let me start again with our energy outlook.

We see chemicals demand growing about 1% above GDP between now and 2040. Over the next decade, we see that ethylene demand will grow about 4% per year, and that translates into capacity additions of about 6 million to 7 million tons per annum, per year, of additional capacity.

So you can think of that as maybe four to five world-scale crackers per year. So once again, our outlook will inform our business strategy and our investment choices, and we see this as a really good opportunity.

Remember that we've currently got a project underway in Baytown to add another 1.5 million tons per annum of ethylene capacity and a corresponding project in Mont Belvieu to add derivative units to take it to polyethylene, in fact, metallocene polyethylene. This project would look at another world-scale cracker of about 1.8 million tons per year of ethylene.

And that would feed, at this stage still early, would feed a monoethylene glycol plant and two polyethylene plants.

Okay, thanks for that color.

Hi there. Just coming back to the gas theme, obviously you had Paris on the CO2 side.

You've got a very bullish forecast on LNG demand. I mean, is this a general shift towards gas?

I noticed you're sort of 60% oil, and it would have been even higher in the quarter with Nigeria and Canada. Or is this just knowing the assets just an opportunity to just get hydrocarbon at the low end of the gas cost chain?

No, Ed. It's not a shift in our strategy in any way.

We've been very consistent in it. It's a recognition of opportunities that we see across the globe in both the crude as well as gas.

And again, I'll go back to my value theme. It's where we think we can maximize shareholder value.

Okay. And then on U.S.

gas price, I mean obviously there's a lot of noise about spot LNG prices and contract renegotiation, but obviously, there are time lags in the contracts as well, so you would have expected the gas price to probably go down a little bit. But anything funny that you're seeing in terms of the gas prices across your non-U.S.

portfolio?

No, not really. As you recall, crude prices got to a low level in the first quarter of this year.

There is a lag effect on the contracts. We've got many different contracts.

It's hard to imply that there's a standard that you can use to calculate the impact. But generally, you can see a crude lag impact of anywhere from three to six months.

Okay, cool. Thanks so much.

Thank you, Ed.

Hey. Good morning, guys.

Good morning, Neil.

So, Jeff, just wanted to follow up on the first question in terms of refining margins. And you guys have a unique perspective on this given the amount of capacity that you touch.

Do you think the weakness that we've seen year over year in refining margins and versus the five-year average is a function of global demand? Or of refining capacity and utilization?

And then how do you see it playing out over the longer-term?

No, I think it's probably the latter. It's probably refining capacity and then, as you know, inventory build.

So I mean, with very strong demand in 2015, good demand in 2016, I think the sector was ready for the demand moving into 2016. And you've seen that in the inventory builds.

And going forward, just like any supply/demand fundamental, either the demand's got to grow or the supply's got to shrink, and you'll see the same type of fundamentals going forward. Our focus will be one of – again, as I said earlier, it will be making sure that we're the most competitive refiner out there.

As you think about it geographically, which regions do you think will have to rationalize runs as you think about your competitor portfolios, to the extent margins do continue to weaken?

I'm not going to speculate on capacity utilization. Rationalization, we've said for some time, we expect to see across the globe, particularly in places like Europe and Asia.

Okay, great, Jeff. And the follow-up question on M&A here is I think in Rex's remarks at the Analyst Day, he had pointed to valuations from Exxon's perspective of U.S.

E&Ps were challenging and the bid/ask spreads aren't there. If you could talk about the opportunities set as you think about M&A in the Lower 48, that would be helpful.

As you can appreciate, Neil, the bid/ask is really a function of many factors, including the business climate and for us the unique ability for us to add value to it. There has been a pickup, a slight pickup.

The longer that prices stay in this area code, probably the more ability to come to a win-win agreement. As I said earlier, Neil, really it's keeping focused on the full breadth of opportunities and trying to identify where we can come to a win-win solution that adds value for the long term.

I appreciate the comments. Thank you.

Thank you, Neil.

Great, thanks. Good morning.

Maybe if I could just ask the first one on capital priority, do you have any rough priorities in terms of the use of cash as the commodity recovers in terms of balance sheet versus capital acceleration versus shareholder return? Is there a point that you look to get back to before thinking about restarting the share buyback program?

No. If you go back to our capital allocation approach, it's all about making sure that we provide a reliable and growing dividend to our shareholders and at the same time continue to invest in accretive assets.

The buyback program has been the flexible part of the program. As we've talked previously, the buyback program is considered on a quarterly basis.

And it also considers things like the company's current financial position, our investment requirements, as well as the near-term business outlook. We'll make those determinations on buyback on a quarterly basis.

And in terms of debt reduction on that as well, are you at a place where you'd like to reduce absolute levels of debt, or are you fairly comfortable with where you are right now for this point in the cycle?

I think given where we are in the cycle, we've got significant debt capacity that we can leverage. Paying down debt is obviously one of those things that we will consider as we move forward.

But we've got a very strong balance sheet. We're going to maintain our prudent cash management and we're going to invest wisely.

But at the same time, we're not going to forgo attractive opportunities. And I think you've seen that here, as we talked this morning in the prepared comments.

Great. And maybe if I could shift one to the U.S.

onshore, we appreciated the slide that you had in there with some details on the Permian and the Bakken. Could you say how many rigs you're running right now in the U.S.

onshore currently? And how should we expect to see you manage that heading into 2017?

Are you at the point where you're thinking about moderately accelerating?

So right now we're running – for the second quarter we were running 11 rigs in total. Now we're down to about 10.

In terms of going forward, we want to be mindful of a number of factors. We generally manage this with a very measured pace considering a number of factors that would drive how aggressive we want to be in the near-term.

You heard me say in the prepared comments that one of those things are the market conditions, but also resource maturity, learning curve benefits you saw in the prepared comments, the significant benefits we continue to realize in our Permian and Bakken drilling activities. We don't want to outrun the headlights and we don't want to miss some value opportunities.

You need to have the right infrastructures in place. And then there's obviously considering the current supply/demand balance.

So we'll manage it as we go forward, depending on those factors.

Great. Thanks, Jeff.

Okay.

Good morning, Jeff.

Good morning, Asit.

So thanks for the color on PNG, LNG. I just want to get a little deeper, please.

If you were to add a train, a new train to the existing facility, how much resource gas do you really need to underpin a train? Is it still sort of a 5 Tcf number?

And remind us of your resource footprint there. I think in your opening remark you said 4.1 million net acres.

What is Exxon's resource footprint in the region?

Yeah, I guess on the first one is, the resource required for a train is really a function of how big we build that train, and that's part of the development planning that we're going through at this stage. As you heard me say earlier, the two existing trains have a combined capacity of 6.9 million tons per annum.

In terms of our total acreage, I don't have a number to share with you at this point. I mean, the IOC deal, as I said in my prepared comments, adds 4 million acres.

And then shifting gears to International Downstream, Jeff, I'm wondering if you have any thoughts on the current trends in Asia given emergence of Chinese teapot refineries? Did you see anything incrementally new in the first half of 2016?

Are you seeing anything different? Or is it business as usual?

I'd say the latter, business as usual.

Okay, thanks.

Thanks, Asit.

Hey, Jeff. Good morning.

Good morning.

I just wanted to ask a clarification on Paul's CapEx question. You're talking about costs trending well.

Is there any specific reason that you wouldn't have lowered the full-year guidance for CapEx? Are there specific projects or things you're thinking about for the back half that would have it trending upward from a pretty consistent rate in the first half?

Well, I mean, Phil, we really provide guidance at the beginning of the year. Unless there's something materially different in our plans, we really don't change that guidance.

Now the organization will obviously continue to manage it in the most effective way. If there are opportunities that come up on the horizon, we'll judge it against the value proposition and not be constrained if we think it's the right decision for the company.

As I said, having said that, we do expect a downward vector.

Yeah, okay, fair enough. You did lower it last year, I think midyear, so that's why I was asking.

I guess I'll ask one final question on the second quarter. Just given the magnitude of the miss, you usually don't miss by this much, looking back over the past five or 10 years.

So if I take maybe the LNG lag effects or gas pricing, the effect of the production, up 1,000 barrels a day, do you have any rough sense of maybe what one-time factors from an earnings standpoint hit you in the quarter?

Yeah, well, I mean, I would summarize it on the Upstream side, it's primarily driven by three components: one were gas realizations; two were the non-reoccurring events; and then three would be the downtime that we talked about previously, particularly in Nigeria and Canada.

And any way to quantify it?

Nothing more than what we've shared in the prepared information.

Okay, thanks.

Thanks, Phil.

Yeah, good morning.

Good morning, Roger.

Getting kind of late in the call, but I guess the question I'd ask, kind of getting to the, call it M&A or investment options as you look internationally. So you've announced the InterOil transaction.

There's been – and I know you won't comment on rumors, but there have been rumors out there about moving more aggressively into Iraq, potentially Mozambique. Does any of this reflect an improvement in sort of I don't know if you call it a bid/ask spread on some of these big global projects, but maybe a view internally that things are at least looking a little more stable or that sellers are starting to be more reasonable about what they're requesting?

I mean, I guess nothing's really changed in how we consider acquisitions, as I said earlier. We'll continue to scan the opportunities, and some of these things come and go and they come back again, so they take a while to transact.

And if it competes with our existing inventory investments, it's something that we're interested in. It's something that we want to try to progress and make a deal on.

By and large, I do think, Roger, that resource owners do recognize ExxonMobil's capabilities. And I think that, particularly in a down cycle where the resource owner is trying to attract investors, I think that plays well for us.

Yeah, yeah, okay. I can certainly understand that.

And then just a last question that hasn't come up in a while, but Argentina and the shale opportunity down there, any updates worth mentioning?

Yeah, so you may have seen that we had announced a pilot for the Vaca Muerta in the Bajo del Choique and La Invernada block. It's a five-well pilot that we're progressing.

It's underpinned by the December approval of a 35-year unconventional exploitation concession that we were able to secure. And the pilot will then allow us to better assess the full acreage potential.

So good progress; it looks very promising. And you may have also picked up that we've got our XTO organization stirring (1:00:07) that asset as well to bring the U.S.

knowledge and expertise into Argentina.

I did. Thank you.

Thank you, Roger.

Hi, good afternoon.

Good morning.

Good morning to you. I have a question going back to the InterOil deal again.

I just wanted to understand why you chose to use equity, use your shares rather than cash for the deal. Just wondering if it's to do with balance sheet constraints, and especially as I think you're likely to get a significant amount of cash in from Total from milestone payments.

Anish, don't read too much into it. We have flexibility to do either, stock or cash.

As you would expect, the final structure of a transaction is really a function of the dialogue between the seller and the buyer. And obviously, we keep focused on what the seller's needs are.

But again, I wouldn't read too much into it. There are no balance sheet constraints with ExxonMobil.

Okay. And my follow-up question is on your U.S.

gas production. We've seen some steep declines in U.S.

gas production previously, and it seems to have moderated some more recently. I'm just wondering if you can give some idea of how you see that trending over the next few years and in the current gas price environment.

If you recall, we are the largest gas producer in the U.S. We've got a substantial resource base that underpins that and a significant amount of development opportunities.

If you think about the recent period, there has been – to be very transparent, we've had a much stronger focus on development of liquids opportunities, less so on gas. Longer term, we think about that gas resource base in a number of ways.

One, as I said earlier, we expect gas to grow globally at 1.6% per year. So we expect in the U.S.

is that gas will underpin increases in domestic use, and you've seen how gas has continued to grow in power generation, as an example. Two, we see that gas helping to underpin some of these petrochemical investments that we've been talking about like the investment we've got in Baytown and even the one we're considering with SABIC.

And then three, that gas also underpins our ability to compete in the global LNG market and our anticipated increases in demand.

Thanks very much.

Hi. Most things have been asked.

But quickly with Skipjack, Jeff, do you have the same kind of seismic signature, not just the aerial extent of the image for Skipjack versus Liza? Do you have the same seismic signatures?

Yes, we do, John.

Okay, great. Next one, you said China stabilization.

Can you be a little bit more specific? And that's it for me, thanks.

Are you talking about in GDP?

Yes.

We're just looking at the quarter-on-quarter change in GDP, and by in large, it's been fairly stable. Fourth quarter of 2015 was about 6.8%.

It's been on a gradual decline. First quarter of 2016 is 6.7%, and then it's estimated to be about the same level in the second quarter.

Okay, thanks.

I'll just add on China, John. Remember, overall demand products have been pretty strong in China if you look at crude demand and products.

Thanks, Jeff.

All right. Thank you, John.

Hey, Jeff. Good morning.

Good morning, Paul.

Three quick questions. You mentioned that now you have 10 rigs in the U.S.

Can you tell us what is the number of rigs you need to maintain flat production in the Permian and Bakken?

Paul, we really don't think about it as how many rigs we need to keep production flat. We really think about it from a full global portfolio perspective.

And as I said earlier a couple times, we've been very focused on maximizing value. And on the short-cycle investments, one of the things we've got to think about is the supply/demand mechanics.

So we really don't think about it from keep volumes flat. We think about how do we maximize value.

I fully understand. I'm not saying that Exxon thinks about that, but it's for our own benefit that in terms from an industry standpoint.

So I'm wondering if there's a number that you can share.

No, there isn't because we don't work it that way.

Okay. Secondly, in page 11 of your presentation, hopefully you talk about asset sales gain and tax benefits different between first and second quarter.

We saw the difference in earnings. Can you tell us what is the actual sales gain and the actual tax benefit in the Upstream during first quarter, and also in the second quarter?

So you're asking for the quarter-on-quarter earnings?

No, I'm talking about the actual asset sales gain you report in the first quarter and in the second quarter for Upstream. And also what is the tax benefit you record in the first quarter and also the second quarter in Upstream?

From an earnings asset perspective, in the first quarter it was about $80 million total positive. And in the second quarter it was immaterial.

It was a negative $20 million in the second quarter.

Okay, tax benefit?

Paul, we just don't share specific tax information in our business segments.

Okay. And final one, in M&A you mentioned that in order for you to go into a major concession, you need to ask the question, what do you bring to the table.

Should we interpret that means that either once you applied whatever is the asset or what ownership, you will be the operator, or that you will be able to convince the consortium to move those assets into your own development site (1:07:23), like you may be able to do in Papua New Guinea? Should those be an important principle when you consider?

Those are certainly key considerations when we consider opportunities on the acquisition front.

Okay, thank you.

Thank you, Paul.

Thanks, guys, just one question for me. About a month ago Exxon was in the headlines stating its preference for carbon tax and then the selection fees, and I wanted to ask.

Within Exxon's project economic planning, do you incorporate a future carbon price? And if not, what would you need to see before you would include that factor in your planning?

Pavel, if you look in our energy outlook, which we've got posted on our company website, you'll see that we've included now for many years what we call a proxy cost of carbon. And over the outlook period out to 2040, that number grows as high as $80 per ton.

But you'll see it in our energy outlook if you go ahead and take a look at it.

Okay, I appreciate it.

To conclude, I want to thank you all once again for your time and questions, really good questions. I think you get the impression that we've got a lot going on.

The organization is very focused on the value choices that we've got before us. We're not being driven by specific objectives of volumes or market share, but one of value.

And I do appreciate the engagement this morning, and we certainly look forward to our discussions in the future. Thank you.