Jeff Woodbury - VP, IR and Secretary

Doug Terreson - Evercore ISI Doug Leggate - Bank of America Merrill Lynch Paul Sankey - Wolfe Research Phil Gresh - JPMorgan Neil Mehta - Goldman Sachs Ryan Todd - Deutsche Bank Brendan Warn - BMO Capital Markets Roger Read - Wells Fargo Blake Fernandez - Scotia Howard Weil Jason Gammel - Jefferies Biraj Borkhataria - RBC Capital Markets Paul Cheng - Barclays Alastair Syme - Citigroup Theepan Jothilingam - Exane BNP Pavel Molchanov - Raymond James Rob West - Redburn John Herrlin - Société Générale

Good day, everyone, and welcome to this Exxon Mobil Corporation Fourth Quarter 2017 Earnings Call. Today's call is being recorded. At this time, I would like to turn the conference over to Vice President of Investor Relations and Secretary, Mr. Jeff Woodbury. Please go ahead.

Thank you. Ladies and gentlemen, good morning, and welcome to Exxon Mobil's fourth quarter earnings call. My comments this morning will refer to the slides that are available through the Investors section of our Web site. Before we go further, I'd like to draw your attention to our cautionary statement shown on Slide 2. Turning now to Slide 3, let me begin by summarizing the key headlines of our 2017 performance. Exxon Mobil earned $8.4 billion in the quarter, bringing year-to-date earnings to $19.7 billion. Our cash flow from operations and asset sales exceeded our dividends and investments for the year by more than $1 billion. We continue advancing attractive opportunities across all our business segments. In the Upstream, we closed the Mozambique Area 4 acquisition and we made our sixth discovery offshore Guyana. I’ll share for more detail about these items and others later in the discussion. Included in our results is a non-cash earnings gain of $5.9 billion resulting from U.S. tax reform. This reflects the magnitude of Exxon Mobil’s historic investments in the United States. These investments have created large deferred income tax liabilities which when revalued at the new tax rate results in a one-time non-cash benefit to earnings. The deemed repatriation tax on foreign earnings is not significant to Exxon Mobil as we have paid taxes on non-U.S. earnings at tax rates above 35% on average. Partly offsetting this earnings benefit is $1.3 billion of fourth quarter asset impairments in the Upstream. These impairments are primarily related to non-producing assets in Canada and dry gas production operations notably in the U.S. Gulf of Mexico. Moving to Slide 4, we provide an overview of some of the external factors affecting our results. Overall, the global economy experienced moderate growth in the quarter. Estimated GDP growth for the U.S., Eurozone and Japan softened in comparison to the third quarter. Meanwhile, economic expansion remained steady in China. Crude oil prices strengthened over the quarter whereas natural gas prices were mixed, as North American prices declined but prices in Europe and Asia Pacific increased. Global rig count remains steady. Finally, refining margins decreased with lower seasonal gasoline demand and global chemical margins softened due to higher feed and energy costs. Turning now to the financial results on Slide 5. As indicated, Exxon Mobil's fourth quarter earnings were $8.4 billion or $1.97 per share. In the quarter, corporation distributed $3.3 billion in dividends to our shareholders. Our CapEx was $9 billion, reflecting the completion of our Mozambique Area 4 acquisition, bonus payments for our successful acreage bids in Brazil and increased activity in our unconventional portfolio. All of these are key elements of our future growth potential. Cash flow from operations and asset sales was $8.8 billion, including proceeds from asset sales of $1.4 billion, driven by divestment of some operated Upstream assets in Norway as well as our Norwegian retail network. Cash totaled $3.2 billion at the end of the quarter and debt was $42.3 billion, an increase of $1.7 billion from the prior quarter due to increased CapEx. The next slide provides additional detail on sources and uses of cash. Over the quarter, cash balances decreased from $4.3 billion to $3.2 billion. Earnings, adjusted for depreciation expense, changes in working capital and other items and our ongoing asset management program, yielded $8.8 billion of cash flow from operations and asset sales. A negative adjustment for working capital and other items mainly reflects changes in deferred tax balances from U.S. tax reform. Uses of cash included shareholder distributions of $3.3 billion and net investments in the business of $7.9 billion. An increase in debt and other financing items increased cash by $1.3 billion. In the first quarter of 2018, Exxon Mobil will limit share purchases to amounts needed to offset dilution related to our benefits plans and programs. Moving on to Slide 7 for a review of our segmented results. Exxon Mobil's fourth quarter earnings increased $6.7 billion from a year-ago quarter due to non-cash impacts of U.S. tax reform and impairments as well as improved Upstream results as tax reform added $5.9 billion to earnings while the fourth quarter asset impairments of nearly $1.3 billion were more than offset by the absence of impairments in the prior year quarter. The Upstream business increased earnings $1 billion primarily due to stronger prices. This was partly offset by higher expenses in the corporate and financing segment primarily due to the absence of favorable, one-time non-U.S. tax items in the fourth quarter of 2016. Turning now to the Upstream financial and operating results starting on Slide 8. Fourth quarter Upstream earnings were $8.4 billion, an increase of $9 billion from the prior-year quarter, driven by non-cash impacts and higher realizations. Largest of these was the result of U.S. tax reform. Also as I mentioned earlier, we took impairments of $1.3 billion. These were associated with non-producing assets, including Horn River and the Mackenzie Gas in Canada as well as dry gas producing assets, mostly in the Gulf of Mexico. There were more than offset by the absence of last year’s fourth quarter impairments. Realizations increased earnings by $1.2 billion. Crude prices rose nearly $11 per barrel versus the year-ago quarter, whereas gas realizations increased about $0.60 per 1,000 cubic feet. Volume and mix effects decreased earnings by $110 million due to lower entitlements and mix effects. All other items decreased earnings by $60 million. Upstream unit profitability for the quarter was $7.07 per barrel, excluding U.S. tax reform, impairments and the impact of non-controlling interest volumes. Moving now to Slide 9. Oil equivalent production in the quarter was 4 million barrels per day, a decrease of 3% compared to the fourth quarter of 2016. Liquids production decreased 133,000 barrels per day as field decline, lower entitlements and divestment of some Norwegian assets more than offset volumes from new projects and more programs. Natural gas production increased 17 million cubic feet per day. Growth from projects and work programs and higher entitlements were probably offset by decline, reduced demand and regulatory impacts in the Netherlands as the new gas year began in October. Moving now to the Downstream financial and operating results on Slide 10. Downstream earnings for the quarter were $1.6 billion, up $323 million compared to the fourth quarter of 2016. Stronger margins, mainly in the U.S., increased earnings by $250 million. Unfavorable volume and mix effects decreased earnings by 190 million mainly from increased maintenance activities. All other items reduced earnings by $350 million, mostly due to the absence of asset management gains of the prior year quarter, including over $500 million related to the sale of Canadian retail assets. This was partially offset by asset management gains in the current quarter. U.S. tax reform had a positive impact of over $600 million. Moving now to the Chemical financial and operating results on Slide 11. Fourth quarter Chemical earnings were $1.3 billion, up almost $400 million compared to the prior-year quarter. Weaker specialty margins due to increased feed and energy costs decreased earnings by $30 million. Favorable volume and mix effects reflecting our highest product sales in a decade improved earnings by $100 million. All other items decreased earnings by 10 million. And U.S. tax reform had a positive impact of $335 million. Turning now to the summary of our full year 2017 financial results on Slide 12. As I mentioned, 2017 earnings totaled $19.7 billion or $4.63 per share. Corporation distributed $13 billion in dividends to our shareholders. CapEx totaled $23.1 billion for the year reflecting our commitment to pursuing high-value opportunities. Our financial strength and flexibility enabled us to capitalize on opportunities that arose throughout the year such as the acquisition of Jurong Aromatics in Singapore and our success in the Brazil bid rounds while still remaining within 5% of our original 2017 guidance. Cash flow from operations and asset sales was $33.2 billion. And year-end debt was $42.3 billion, down $0.5 billion from the beginning of the year. Turning to Slide 13. Cash decreased from $3.7 billion to $3.2 billion in the year. Earnings, adjusted for depreciation expense, changes in working capital and other items and our ongoing asset management program, resulted in 33 billion of cash flow from operations in asset sales. And negative working capital and other impacts for the year were again largely driven by changes in deferred tax balances from U.S. tax reform. Uses of the cash include shareholder distributions of $13 billion and net investments of almost 19 billion. Debt and other financing items decreased cash by 1.8 billion. This includes anti-dilutive purchases of about $0.5 billion. Moving to Slide 14. This graph illustrates the corporation’s sources and uses of cash during the year and it highlights our ability to meet our financial objectives. The corporation generated solid cash flow from operations and asset sales which more than covered our dividend and net investments in the business. Our strong cash generation and balance sheet continued to provide the financial flexibility to invest in attractive opportunities. During the year, Exxon Mobil generated $14.3 billion of free cash flow, up nearly 50% from 2016, primarily due to the stronger price environment and our disciplined approach to investing. As indicated, shareholder distributions totaled $13 billion. Annual per share dividends were up 2.7% compared to 2016, marking the 35th consecutive year of per share dividend growth. Looking ahead, we anticipate our 2018 capital and exploration expenditures will be about $24 billion. While we continue to invest across all segments, this increase compared to 2017 is primarily driven by higher investment in short-cycle Upstream opportunities, notably U.S. unconventional activity and conventional work programs, both of which yield attractive returns at $40 per barrel. We’re also pursuing strategic investments in the Downstream and Chemical businesses. Now I know there is a lot of interest in our investment plans and we’ll share more details including clarity on the value proposition at our Analyst Meeting in early March. Moving now to Slide 15 and a full review of our full year segmented results. 2017 earnings increased almost $12 billion due to U.S. tax reform and impairments, higher realizations in the Upstream and higher margins in the Downstream. Probably offsetting these gains were higher expenses in our corporate and financing segment primarily due to the absence of favorable one-time non-U.S. tax items in 2016. In light of the new U.S. tax rate, we expect our corporate and financing expenses to range from $600 million to $800 million per quarter. In the first quarter of 2018, we expect this expense to be at the high end of this range. Further guidance will be shared later in the year as we continue to evaluate the full impact of tax reform. Our full year effective tax rate was 5%, which includes the impact of tax reform and impairments. Excluding these impacts, our full year 2017 tax rate was 35%. 2018 assuming current commodity prices and the existing portfolio mix, we anticipate that the effective tax rate will remain between 25% and 35%, excluding the impact of any large one-time items. This guidance also includes the expected impact of U.S. tax reform. Turning now to the full year comparison of Upstream results starting on Slide 16. Full year Upstream earnings were $13.4 billion, an increase of over $13 billion from the prior year. The largest contributing factors were U.S. tax reform, impairments and higher realizations. Crude prices rose more than $10 per barrel versus 2016 and gas realizations increased about $0.80 per 1,000 cubic feet. Volume and mix effects decreased earnings by $440 million primarily due to lower entitlements. All other items increased earnings $510 million driven by lower operating expenses which were partly offset by unfavorable foreign exchange impacts. Excluding the impact of U.S. tax reform, impairments and non-controlling interest volumes, Upstream unit profitability for 2017 was almost $5.50 per barrel. Moving to Slide 17. Full year oil equivalent production was 4 million barrels per day, a decrease of 2% compared to 2016. Liquids production decreased 82,000 barrels per day. Growth from new project volumes and work programs were more than offset by field decline, lower entitlements and asset sales. Natural gas production increased 84 million cubic feet per day. Volumes from projects and work programs were partly offset by a decline, regulatory impacts and reduced demand. Full year comparison for Downstream results is shown on Slide 18. Downstream earnings were $5.6 billion, an increase of 1.4 billion from 2016. Stronger margins across all regions increased earnings by about 1.5 billion. Volume and mix effects decreased earnings by $30 million due to lower throughput caused by Hurricane Harvey and higher maintenance activities in the U.S. These were mostly offset by improved operations in Europe and Asia. All other items decreased earnings $710 million. This is primarily driven by the absence of last year’s $900 million gain related to the sale of Canadian retail assets and expenses related to the hurricane. This was partly offset by asset management gains in the current year. U.S. tax reform and lower impairments increased earnings by $664 million. On Slide 19, we show the full year comparison with Chemical results. 2017 earnings were $4.5 billion, down almost 100 million from 2016. Weaker commodity and specialty margins, driven by increased feed and energy costs, decreased earnings by $260 million. Favorable volume and mix effects added 100 million driven by stronger demand, partly offset by impacts of Hurricane Harvey. All other items reduced earnings by $270 million reflecting higher expenses from turnarounds and new business growth. U.S. tax reform increased earnings by $335 million. Moving next to an update on some of our key business highlights. First, we’ve had continued success at offshore Guyana. As indicated, we announced our sixth offshore discovery with the successful Ranger well. And importantly, this well proves yet another new play in the Stabroek block. The well encountered 230 feet of oil-bearing carbonate reservoirs. We are encouraged by these results and have further work ahead to determine the full commercial potential of this resource. We’ll likely drill a delineation well later this year. To-date, we have discovered more than 3.2 billion oil equivalent barrels of recoverable resource on the Stabroek block and this excludes the recent Ranger discovery. Rig has now moved to the Pacora prospect where it has spud another well cap well near the Payara discovery. Our phase development of the Liza discovery is progressing with Phase 1 on track for first oil in March of 2020. Development drilling is planned to start this year. A second drilling rig is in route to Guyana and we envision a two-rig drilling program through the end of the year. We’ve also submitted an application for environmental permit to develop the second phase of Liza. Concept includes a larger FPSO and subsea systems. This facility concept we have production capacity of 220,000 barrels of oil per day with start-up expected by mid-2022. Payara is now planned as the third development offshore Guyana, mostly following Liza Phase 2. Payara has the potential to raise Guyana’s production to about 450,000 barrels of oil per day in total. Turning to Slide 21, we’ll provide an update on some activities that are positioning Exxon Mobil to provide low cost of supply natural gas to meet growing global demand. In December, we announced the completion of our transaction to acquire a 25% indirect interest in Mozambique’s gas-rich Area 4 block. Exxon Mobil will lead the onshore construction and operation of all future natural gas liquefaction facilities with scope of more than 40 million tons of LNG per year. Eni will continue to lead the Coral South floating LNG project in all Upstream operations in Area 4. Part of the deal closure, we have funded our share of participation in the Coral project. We’ve also secunded a number of employees into Eni’s project organization in key roles to leverage our extensive global LNG and project development experience. We are proud to bring our LNG leadership and experience to Mozambique to support development of this world-class resource. Now in Papua New Guinea, we encountered hydrocarbons in the P’nyang South appraisal well where we found high-quality sandstone reservoirs. This successful well confirms the Southeast extension of the field, a growing inventory of natural gas resources in Papua New Guinea and support a multi-train expansion of our PNG, LNG facilities. In offshore Cyprus, plans are progressing for Block 10. Acquisition of a 3D seismic survey was completed in 2017. The first well on the block in this promising gas-prone region is planned to spud later this year. Lastly, we signed production sharing contracts with the government of Mauritania for three deepwater offshore blocks. Together, these blocks cover nearly 8.4 million acres in water depths up to 11,500 feet. Exploration activity, including seismic acquisition, is planned to begin this year following government ratification of the contracts. Moving to Slide 22. Exxon Mobil continues to demonstrate its project execution expertise by starting up two projects in the fourth quarter of 2017, both of which were executed safely and on schedule in challenging operating environments. The Hebron project offshore Newfoundland and Labrador achieved first oil in November. The project consists of the gravity-based structure which will be able to produce up to 150,000 barrels of oil per day at its peak. Total recoverable resources are estimated to exceed 700 million barrels of oil. In eastern Russia, the Odoptu Stage 2 project, another arctic development, started in December. The project increases the Odoptu field production capacity to 65,000 barrels per day. And in Abu Dhabi, we are continuing our efforts to increase production at Upper Zakum. The Upper Zakum 750 project is making excellent progress, currently producing approximately 670,000 barrels of oil per day. We’ve been steadily increasing production on all four artificial islands. The joint venture partners recently signed an agreement to pursue further production growth with plans to increase production to 1 million barrels per day by 2024. Expansion will continue to use extended-reach drilling and completion technologies as well as state-of-the-art reservoir characterization and modeling techniques to effectively position wells. Infrastructure and facilities will be further expanded in a modular approach maximizing capital efficiency and lowering costs. Turning now to Slide 23. The graph on the right shows our progress to-date on development of our unconventional liquids volumes. Our total production from the Delaware, Midland, and Bakken basins is now about 200,000 oil equivalent barrels per day. We are progressing plans to ramp up to around 36 operated rigs in the Permian and Bakken by year end, of which 30 will be in the Delaware and Midland basins. With a continued focus on maximizing capital efficiency, we are drilling long lateral wells made possible by our contiguous acreage position. We’re incorporating learnings real time and continue to optimize both the lateral lengths and completion designs. In the Bakken, for example, we’ve made significant progress improving productivity through optimized completions. Recent wells had initial production rates in the top quintile of surrounding industry wells with the best 30-day average rate exceeding 2,500 barrels of oil per day. Looking forward, these longer laterals with optimized completions could potentially generate a 15% to 20% increase in our expected ultimate recovery from the Bakken wells, further supporting our growth plans in tight oil. We expect to drill another 15 to 20 three-mile lateral wells in the Bakken this year. Transferring our learnings from the Bakken into the Permian, we recently started producing our first 12,500-foot lateral well in the Delaware Basin. This well has successfully met our pre-drill expectations. Also, we recently finished drilling our first three-mile lateral in the Midland Basin and we’re currently drilling our second. We’ve continued to grow our service understanding in the Permian, integrating information from our own drilled wells and those on offsetting acreage. With multiple pay zones on our Delaware Basin acreage, we are working to evaluate the full prospectively of these stacked intervals. To support our production growth plans, Exxon Mobil will be investing more than $2 billion in Midstream infrastructure, including expansion of the Wink terminal. This will build additional takeaway flexibility to efficiently move production from the Permian to Exxon Mobil’s manufacturing facilities in the Gulf Coast region. We will share additional information about our plans for the Permian Basin at our upcoming Analyst Meeting. Moving now to the final slide, I’d like to conclude today’s prepared remarks with a summary of our 2017 performance which demonstrates our relentless focus on value, underpinned by the unique strengths of our company. Our integrated businesses have grown cash flow from operations and asset sales to over $33 billion and earnings to almost $20 billion. Excluding U.S. tax reform and impairments, our business segments have earned over $15 billion, an increase of more than 50% compared to 2016. Upstream production volumes were within our guidance range at 4 million oil equivalent barrels per day. Our investment in high-quality opportunities across all segments resulted in total 2017 capital expenditures of just over $23 billion. We continue to invest in our business through attractive opportunities, including strategic acquisitions across the value chain. These investments set the foundation to continue generating value for our shareholders for many years to come. Our free cash flow of over $14 billion more than covered our shareholder distributions of $13 billion. Finally, we remain committed to a reliable and growing dividend as evidenced by increasing our dividends per share for the 35th consecutive year. Entering 2018, we believe our integrated businesses positioned with a robust portfolio and a strong pipeline of high-quality projects will continue to deliver long-term value for our shareholders. We’ll discuss our forward plans in more detail at the upcoming Analyst Meeting which will take place at the New York Stock Exchange on Wednesday, March 7. We have an aggressive plan to drive value growth and we will look forward to the conversation with you. So that concludes my prepared remarks. I would now be happy to take your questions.

Thank you, Mr. Woodbury. The question-and-answer session will be conducted electronically. [Operator Instructions]. We will take our first question from Doug Terreson from Evercore ISI.

Good morning, everybody.

Good morning, Doug.

Jeff, returns in Exxon Mobil’s Downstream business were sustained at really high levels in decades past and you guys still lead almost every global peer from what I can tell. Simultaneously in the Upstream, while the company is rightfully enthusiastic about its Permian business as indicated by your recent guidance in that area and some of your slides today, returns elsewhere in the Upstream declined fairly meaningfully in recent years and they appear to be in need of remediation. So while your peers have the same problem, several of them have provided plans for improvement and time periods of which they expect to improve their performance. So, my first is that with the Analyst Meeting coming up, why wouldn’t a company specify an improvement plan for Upstream since it’s around 80% of corporate capital employed and it’s probably the driver of Exxon Mobil stock which is obviously really important to you guys? And then second, do you think that Exxon Mobil’s emphasis on the industry-leading financial performance rather than an absolute return target better serve shareholders when considering that a lot of your peers had declining returns over kind of the last decade or so? So it’s two questions but it’s really on the same topic.

Doug, on the first topic, the real objective for the corporation as you know is to very clearly make the investment case that of our growth prospects and the fundamental mission of creating long-term shareholder value. We are going to detail out in the Analyst Meeting the value proposition that we see. As I said, we have an aggressive growth plan across all three business segments. We’ve got three world-class businesses that have very robust portfolios that we are going to fully leverage to go ahead and lay out that value proposition over the long term. So I certainly acknowledge the drop that we’ve seen in the Upstream business and the return on capital employed and I think we’re going to lay out a growth plan that’s going to demonstrate where we’re heading in not only to enhance the Upstream return but furthermore continue to build in the Downstream and Chemical businesses which I think you recognize are very important to the corporation as a whole given our independent business model.

Well, I think that would be great. Sorry, Jeff, go ahead.

Go ahead, Doug.

I was just going to say, well, I think that would be welcomed and rewarded in the market. More specifics, the better obviously but I didn’t mean to interrupt you.

Yes, and just following up on the last part about the return on capital employed, I think we’ve talked in the past that that remains a key objective for the corporation. I know there’s a lot of interest about our capital investment program. I think we’re going to demonstrate the quality of the portfolio and that our shareholders are best served for us to continue to invest to capture that value.

Okay. Thanks a lot, Jeff. We look forward to it.

All right. Thanks, Doug.

We will take our next question from Doug Leggate from Bank of America Merrill Lynch.

Thanks. Good morning, everybody. Jeff, I wonder if I could start by taking you back to the cash flow. I understand you tried to walk us through some of the moving parts, but oil up quite nicely in the quarter and your cash flow is flat it looks like on an underlying basis. Can you walk us through whether there’s any unusual situations going on in there whether it’d be hurricane related or cost or anything like that? It just is kind of hard to explain why the cash flow is as light as it was and maybe explain a little better on the working capital move?

On the cash flow, as I explained in the prepared comments, Doug, the big impact is obviously in the working capital and other and that was primarily driven by the U.S. tax reform. There were other less significant changes to the deferred tax balances that impacted cash flow. As I said, in that cash flow we had assets sales of about 1.5 billion largely associated with some of our Norwegian divestments in our operated Upstream and our retail sector.

Sure. So I’m thinking more of the ex-asset sales number, I don’t want to belabor the point, but just to be clear. So if it’s largely nonrecurring, you’re underlying cash flow then would have been closer to 13 billion, is that right or am I missing something?

Yes, I’m not sure how you’re coming up with that calculation, Doug, to be able to comment on it.

7.4 plus the 6.5 basically. Working capital draw 6 and change and your underlying was you reported 7.5 ex the asset sales. Am I wrong?

Yes, remember the earnings include the upwards associated with the U.S. tax reform. You got to back that – that’s what’s happening in the cash flow analyses. You’ve got $5.9 billion in U.S. tax reform benefits in the earnings and then in the working capital and other you’re backing that out to come out with the cash.

Okay. So that’s really the roots of my question and so if I look at ex all that out, you’re underlying cash flow was flat sequentially on a significant increase in oil price. What’s going on?

When you look at overall unit profitability, it remains strong on the assets. We had a number of one-time effects in our portfolio that I talked about in my prepared comments that lowered the overall – in fact in several of the segments that lowered the overall earnings in that quarter.

Okay. I’ll take it offline and maybe go in more detail. Let me try one final one if I may and it’s on the increase in the rig count. So the chart you’ve shown I think is the same chart you’ve shown multiple times before. But you have, if I’m not mistaken, taken the rig count up. So why are we not seeing any increase in the production guide?

Doug, you’re talking about the Permian and Bakken now?

Yes. So I think you talked about 30 rigs by the end of '18 previously and now you’re talking 36.

Yes. So as you can see from the display, you can see that we are tracking in the guidance that we provided. We did have a bit of downtime in the fourth quarter associated with weather notably in the Bakken and you can see that in the variation on the red line that’s tracking. We’re doing well in terms of working off the ducts [ph] that have built up. And I think we’re right on our plans in terms of ramping up.

All right. I’ll wait for the Analyst Day. Thanks.

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

Hi, Jeff. Jeff, can I just follow up on Doug’s question about working capital? Can we just have the working capital number alone?

Working capital number alone --

For the shift in the quarters. Sorry.

Yes, the working capital alone in the quarter is just $200 million.

And that’s the amount of working capital or the change – what we’re trying to get to is the sequential --

I’m sorry.

So basically – so to further what Doug Leggate said, the sequential cash flow is essentially flat.

That’s right.

Okay. Thanks. If we could go on just to your volumes, I can imagine that the 40s impact was significant on oil in Europe. I would assume that the African problem in terms of declining volumes was PSC effects in Nigeria maybe. We’re also seeing some weakness in Asia. These are all liquids questions, Jeff. Could you just run around the world and kind of give us the reasons for the issues in the liquids volumes? Thank you.

Yes, if you look at the quarter-on-quarter volumes, you’ll see that it’s really broken up into three key components, which is taken by thirds – about a third of it is associated with PSC effects driven by the higher prices. The second third is associated with asset sales. And on the liquids side that is all associated with our sale of our operated assets in Norway on Upstream. And then the last third is primarily associated with a base decline in our portfolio offset by project and work program build up.

That’s great. Thank you. My final question is, Jeff, there’s a lot of press around $50 billion of spending which you’re going to make in the U.S. It wasn’t quite what was written in downwards press release. I think it was a blog post that you guys put out. I wasn’t sure – and it was kind of not by Darren but by everyone else was kind of tied to the tax reform that we’ve seen here in the U.S. Can you just talk a little bit about how much incremental capital in the U.S. you’re going to spend as a result of the tax changes and sort of if you could annualize the number, it would be helpful just to get a small clarity on your spending over the coming years? Thank you.

There’s a couple of elements to what you’re talking about. One is the 50 billion that we had projected in the U.S. over the next five years, let me give you a little bit color on the 50 billion. About two-thirds of that is in the Upstream portfolio. As you would anticipate, a lot of that is in our unconventional activity. The rest is split fairly evenly between our Downstream and our Chemical portfolios. If you look at the quality of those investments, as you would expect they’re very robust in the Upstream unconventional business and the rest of the conventional work program generated greater than 10% return on investment at a $40 flat rail. The Downstream and Chemical investments are 15% to 20% plus. So that’s kind of the forward definition of the anticipated spend in the U.S. over the next five years. Think about the overall U.S. tax reform and the way I’d characterize is the following that we clearly believe that the reform will make the investment climate more attractive. It will lead to things like capital inflow, group profitability, new jobs, ultimately higher returns for savings plans. The same is true for Exxon Mobil and we believe the changes will help strengthen our investment plans. The 50 billion that we’ve talked about is a projection. We haven’t made a decision to move forward with those investments at this point, but certainly the U.S. tax reform is going to strengthen and build that investment confidence. So really what the message was just one of we’re encouraged by an improved competitive positioning within the U.S. for an investment climate. We’ve got 50 billion that we’ve got projected going forward. We’ve got some other projects that are on the table that are not in the 50 billion that we’re – in light of the current tax basis, we are going to step back and take a look at. So other than that, I don’t have any other specifics to break out specific dollars associated with incremental expenditures on the U.S. tax reform.

No, but that was helpful. Thank you, Jeff.

Thank you, Paul.

We will take our next question from Phil Gresh with JPMorgan.

Hi. Good morning, Jeff. My question is a follow up to Paul’s just around the production. I appreciate the color around the thirds breakout. If you look at the base plus projects piece, it’s about a third that looks like that would be about down 1% year-over-year. I’m wondering how you feel about that performance in 2017 and how we should think about 2018 specifically? Obviously there were projects coming out in '17 but there are also maybe some one-time factors in 2017. So is that something that you’d expect to grow in 2018, given that the other two pieces could be a little bit more nonrecurring?

Yes, good question, Phil. Let me take the prior discussion from a quarter-on-quarter dialogue to a year-on-year. And if you look at the year-on-year volumes, down 2% overall. Liquids is primarily driven by entitlement effects, price effects and divestments. Liquids is actually up in everything in the rest of the variables. So as we think going forward, a key driver for our volumes and we’ve detailed for you is the unconventional growth program. We’ve got some projects that we still expect to start up in 2018. But more specifically as we sit down in the Analyst Meeting next month, we’re going to lay out what that looks like in terms of volume growth.

Okay. The essence of the question was, you generally have expected 4.0 to 4.4 have long-term range and you came in below that. So I was trying to think through 2018 specifically realizing you’ll give more longer term color later.

Yes. Let me just clarify your comment. When we gave that range, it was ex asset sales and entitlements. So my point being is, is that if you look at 2017 to 2016 reconciliation, the deviation is primarily or is all in those areas.

Sure. Okay.

Simply put, higher prices drove the volumes down and we went ahead and monetized some assets that we thought we can get greater value from on the market as opposed to continuing operations. Again, as we go forward we’re going to go ahead and detail that out as to what our current views are in terms of our investment program and how that will impact our volumes.

Okay. My second question was just on the capital allocation. I think some investors were hoping that perhaps you would announce a buyback for 2018 given the strength of the balance sheet and the higher oil price environment? And I know Exxon generally views it as a flywheel. But given your capital spending number for 2018, it would seem like you would have some potential room to do that if oil prices hold where they are. So just if you can update us conceptually and how you think about that?

Yes. So, Phil not – we haven’t changed our view on how we manage our capital allocation. First and foremost is that we’re going to continue to invest in attractive opportunities that are accretive to our overall financial performance. As we’ve said many times and as I said today, we’re going to maintain our commitment to a reliable and growing dividend. And then with excess cash, we’ll decide whether there are more opportunities that we can invest in or do we go ahead and return that to the shareholder via buyback program. And we think about that on a quarterly basis. We look at a number of factors to assess whether we want to go ahead and buy shares or we want to pursue some additional opportunities. But I think the underlying message in what I’m trying to convey is that we have a very attractive investment opportunity and we really do believe that we can generate a better shareholder return by pursuing these investments if they’re ready to go ahead and be funded. But like I’ve said before in the past that we’re not going to hold large cash reserves and if we don’t have immediate use to put that to work, we will go ahead and purchase some shares back as a means for shareholder distributions.

Okay. Thanks, Jeff.

Thanks, Phil.

We will take our next question from Neil Mehta from Goldman Sachs.

Hi. Good morning, Jeff.

Good morning, Neil.

Jeff, can we talk about the $24 billion 2018 capital spending? The previous number was around 25, so it shaved lower. Is that just a function of deflation? And historically there’s been a couple billion dollars of M&A-related capital spending in there. So any color in terms of how we should think about what that organic CapEx level is? And then if you could just juxtapose that against whatever 2017 organic CapEx was ex-acquisition just to help us frame the bridge from '17 to '18 spending?

Yes, sure. So as you know there was a fair bit of inorganic CapEx in 2017. And if you look at the build from 2017 to 2018 just ballpark numbers, you’re talking about a $5 billion to $6 billion increase in organic – total CapEx in organic activity. Now I will highlight that there is some inorganic funds in that 2018 which is associated with the payments for the farm-in in Brazil for the North Carcara field. So what does that increase represent? It really represents – the lion share of it is in the Upstream business. Again, mostly it’s associated with the unconventional work program and some conventional work program across our global portfolio. As I indicated before when we were talking about the five-year projection of $50 billion, that is a very attractive investment. We’ve got – at a low price forecast we’ve got returns in excess of 10% with a $40 per barrel flat rail. I would tell you the investment plan is optimize to achieve attractive returns even in a low price environment. And the plan includes – it does include some investments to maintain our license to operate as well as investments that have attractive future potential. But the lion share of that increase year-on-year is associated with more short-cycle investment that is highly attractive even in a low price environment.

Got it, Jeff. And the follow up and you and I talked about this last month, but how you’re thinking about M&A in this environment, whether it is – when you think about where you see value as a company? Is it still in the private market or how do you think about the public market as well? Historically, the message has been that the value has been more on the private market.

Yes, really no fundamental change. We’re not going to filter out potential opportunities. We’re going to keep a wide brief and make sure that aperture is wide open. And if there is something that we can identify that could effectively compete with our existing inventory investment opportunities, well then obviously it makes a lot of sense for the corporation to go ahead and pursue it. But to-date, as you’ve seen, they’re probably much more focused on assets that we see synergistic benefits with our existing operations as well as where we bring a capability where we can get additional value for the assets and what the market maybe valuing it at. And I would highlight for the group that if you look at what we did over 2017, we did a nice job in taking full advantage of the market conditions and picked up some high quality, very competitive opportunities that has really positioned our portfolio even in a stronger state than it was historically. And that’s part of what we’re going to be talking about in the upcoming Analyst Meeting.

All right, Jeff. Thank you.

You’re welcome.

We will take our next question from Ryan Todd with Deutsche Bank.

Great. Thanks. Maybe a couple questions on LNG. You have a little bit in there in the presentation on Mozambique. The deal is closed. You suggest that it could be upwards of 40 megatons a year which is a big capacity. Can you talk a little bit about how you think about long-term development of the assets there, the timing of the development path there in Mozambique and maybe what – is the assumption that you would supply all of the relevant gas from Area 4 or would you look to bridge that with Area 1 as well in the region there?

Ryan, as I said, a very high quality. We believe it’s well on the left side of the cost of supply curve. So it’s going to compete very well in the market. A very substantial resource, over 85 trillion cubic feet in place. And there’s clearly synergies to be had between Area 1 and Area 4. We just closed the deal. We’ve got an engagement with all the partners to lay out the forward development schedule. So it’s really too early for us to convey specifics in terms of what program in the timeline, but I can tell you that this is going to take a central focus on our development planning efforts to make sure that we’re getting at it just like you’ve seen us do in other places like Guyana and Papua New Guinea. And then on top of that you’re probably aware that we have exploration acreage in the area that we’re also progressing concurrently that has some really high prospectively. So I’ll leave it there.

And maybe as a follow up on LNG, with – I don’t know if we’ve talked about this in the past, but with Mozambique not closed, you have additional appraisal success there in PNG. Golden Pass LNG was always kind of in the hopper at some point as well. How do you think about – and it feels like the environment is improving from a gas, sales and contracting point of view. I guess first is, is that true? And then how do you think about the timing of the relative priority of these LNG projects? And is it necessary to stagger them or would you actually see benefits in proceeding with multiple LNG projects simultaneously?

Let’s start with the fundamentals. If you look at the supply/demand projection, we’ve got gas growing at about 1.5% per year between now and 2040 and we’ve got LNG growing over two times over this time period. So that is the prize that we’re working towards. Now of course in order to compete for that, we have got to have the lowest cost of supply. And you’ve highlighted two key areas, Papua New Guinea and Mozambique, we think will compete very strongly for that. Now obviously there’s a – with any LNG project, there is a very large upfront capital investment. We typically have walked in these funding decisions on long-term LNG contracts. We’ve got very strong marketing connections and a very strong reputation in the market. So we’re out there going ahead and putting in place the commercial structure. But fundamentally, Ryan, it really needs to be robust enough to underpin such a substantial investment. But we’re very positive about where we’re heading with it. We think we’re going to be very competitive with offerings that we have in both those assets as well as some others that we’re pursuing. And you’ll hear more about the details as we go into the Analyst Meeting.

Okay. Thank you.

You’re welcome.

Our next question comes from Brendan Warn with BMO Capital Markets.

Hi, Jeff. Just two questions, I guess first question on Chemicals. Can you just give us an update on the timing of your new capacity and I’d appreciate it if you can make some comments on your outlook for heading into some any other supply and just your view on margins over the next 12 months? And then my second question was just related to the 2 billion you announced in terms of additional infrastructure spend related to the Permian, is that included within the 24 billion or is it over the next few years? Can you just clarify that number for me please?

Yes. Well, on the first one in terms of our Chemical business and our investments, obviously – let me go back to the fundamentals again here. We’ve got from an ethylene demand perspective, we see ethylene growing about 5 million tons per year that will require about three to four world-class crackers per year to be started up. That is – the objective that we’ve is to compete in that space. And we’re very close to bringing our Baytown crackers online later this year. And then we’re still working the potential greenfield steam cracker development in South Texas which we add another 1.8 million tons per annum of potential capacity. But one of the advantages that we bring to that is, is not only do we have a good source of low cost advantage feed stock but we also have proprietary technologies that offer a premium product. And what I’m speaking to is metallocene polyethylene. So with that demand projection and our ability through our integration and our technology to compete, that is a significant growth area and one that we’re going to talk about next month as well. When you talk about – I think your other question was around the $2 billion that we discussed in investing in the Permian business, those are really so commensurate with the build-up of the volumes that we showed out to 2025. And there are really two components to it. One is expanding the Wink terminal. We currently have permitted capacity about 100,000 barrels a day at Wink and we’ll expand and commensurate with the growth projection than you see in the prepared remarks I gave. And then the second one is to add additional takeaway capacity and those expenditures would occur over this timeframe of about five years or so.

Okay. Thanks for the update.

You’re welcome.

Our next question comes from Roger Read with Wells Fargo.

Good morning, Jeff.

Good morning, Roger.

I guess we can – since the focus of this call the CapEx increase and I know more will come at the Analyst Day, but as you think about the 50 billion from both an Upstream and a Downstream and Chemical side, what is your – or what is baked in there in terms of a cost inflation? I just think about when we’ve seen major projects kickoff in a particular area, we always seem to get some of that. And then obviously in the Upstream side we are seeing some cost inflation on the well completion side. So maybe just kind of give us an idea of how you combat that within this big program?

Well, it’s an important aspect to make sure that we deliver on the financial performance of these investments. And when we lay out the projects and specifically individual execution plans for the investments, we’re very mindful about what can we bring to bear in order to really reduce the structural cost of these investments. And if you look over the last couple of years, I think over the last two years, we were able to reduce kind of near-term project inventory cost by about 30% down. And there’s a number of synergies that we’re picking up. We’re applying certain technologies, execution strategies and then we have built all that into our forward projection of investment notably within the long-cycle capital-intensive projects but also as you’ve seen us explain in our short-cycle business how we continue to build that learning curve going forward. So while we always got to be mindful about how these investments can create inflationary pressures, we also detail out these plans to make sure that we’ve put the right mitigators in place and we have strategies that will ensure that we can deliver on the investment expectations. So our view is that we’re going to continue to combat any type of inflationary pressures by these type of cost reduction initiatives that we’ve demonstrated over the last several years.

Okay. Thanks for that. And then kind of a follow up of some of the cash flow questions and then obviously the portfolio expansion you’ve done through the various acquisitions and investments here recently. Asset sales relatively light in '17 and I know you don’t guide a specific number for asset sales, but I’m just curious if you’re upgrading the portfolio in terms of future development, should we anticipate over the next couple of years maybe a slightly more aggressive hiving off of some of the more mature assets that are out there, especially thinking with this higher oil price potential buyers are a little more liquid?

Yes. Well, Roger, as you know, we have an ongoing asset management program that’s really designed to identify what assets we should be considering and testing the market with that in order to get greater value for monetizing them from continuing our operations. And if you look over the last five years, we’ve had – in fact from way back, we’ve had a very active divestment program, very successful divestment program. And if you look at the last five years, we’ve sold over I think it’s like $21 billion, $22 billion of assets in terms of proceeds from those sales which is about $4 billion a year. So in total, 4 billion a year has been about an average for us over an extended period of time. This year it is a little bit light compared to what we have done in the recent past. But we will continue to identify where we can get greater value and upgrade the portfolio. When you think about what we’re actually doing and why we view this asset management program as fundamental of how we manage the business is that on the upside we have a very focused exploration program and we have a targeted inorganic program and acquisition program that’s looking for opportunities that can be accretive to our investment inventory, our portfolio that upgrades the overall portfolio. And you think about things like Guyana and Papua New Guinea and the Jurong Aromatics and Mozambique assets. We’ve bought a lot of stuff at the very top of the portfolio. And concurrent with that, we’re looking at the bottom of the portfolio of things that don’t compete, assets that are late in life and we don’t see material upside and that’s what really sources our ongoing divestment program.

No, it’s helpful. I’m just interested if maybe with the churn in terms of new opportunities if that would increase sort of the churn or whatever on the mature scale of things. But it’s helpful and we’ll see you next month.

Thanks, Roger.

We will take our next question from Blake Fernandez with Scotia Howard Weil.

Hi, Jeff. Good morning. I’ll just use both my questions fairly straightforward on CapEx. For one, I just wanted to go back to 2017. I think the $23 billion number was about $1 billion above your original guidance. And I’m just trying to understand the delta there. Was that kind of activity-based or more inflation than you were expecting or maybe more M&A dollars?

Yes, Blake, it was really the last. So if you think about the 23 billion, we had a number of break-ins, but I want to make sure everybody understands that those break-ins were highly accretive to overall financial performance. And as a result, it pushed us up. But if you think just like in the Brazil acquisitions that we picked up, the bid prices in Jurong Aromatics, they both increased the CapEx well above what our plans were and the organization was able to absorb a majority of that through our ongoing blocking and tackling with capital efficiency improvements. There was some reprioritization of some capital plans. But I think the message I want to keep on emphasizing is, is that we have a robust opportunity in inventory of high-quality investments that we think will continue to grow materially long-term value for our shareholders. And as long as we’ve got such a strong inventory investment opportunity, we’re going to continue pursuing. And we’ve taken a full advantage of the down cycle in the market to capture some very attractive assets that are going to upgrade our portfolio.

Understood. I guess tying in with that, and this maybe goes back to Neil’s question, but just to understand. It seems like there’s a little bit of a shift in that. I guess your original guidance of 22 billion for '17 contemplated some form of M&A obviously, but now it sounds like going into '18, the 24 billion basically does not. So aside from the Brazil piece of it, I guess should we be thinking that any kind of M&A activity would be additive to that 24 billion? Just looking to confirm that.

Yes. So 2017 – to your point just to be clear, 2017 included although we didn’t advertise at the time, it included the Mozambique acquisition. On top of that, we picked up a number of additional opportunities as I said, Brazil and Jurong Aromatics. As you think about 2018, we always leave a little flexibility in our budget in order to pursue those type of opportunities. You want to make sure that you give yourself some room to go ahead and try to capture those opportunities when they come about. Fundamentally, we’ll go leverage our strong financial capability and balance sheet if something really big comes along and we think it’s going to be accretive for the shareholder. But going forward in the 2018 program, the only thing that is specific, that’s public is the Brazil payment for the farm-in into North Carcara which is round numbers, about $1.3 billion.

Understood. Thank you.

All right.

Our next question comes from Jason Gammel with Jefferies.

Thanks. Hi, Jeff. Jeff, you’ve been absent from Brazilian Upstream for a number of years and now a pretty massive shift all at one time into exploration development potential and strategic lines with Petrobras. Can you talk about anything that may have changed in your thoughts around Brazil or is this purely a lot of opportunities just coming up at the same time? And I’ll just ask my second question at the same time. You’ve also picked up a lot of other deepwater exploration acreage just over the last six months or so in Guyana and Mauritania and Ghana. Can you talk about how you’re looking in general at deepwater now competing on the global cost curve?

Sure. On the first one, Jason, in Brazil and I’ll certainly acknowledge that we’ve been absent – largely absent from Brazil where – I think we would all recognize has a very strong and rich resource endowment. One of the issues for us over the time, Jason, was that we’re going to invest where we believe the investment dollars are globally competitive. And as Brazil continued to evolve the fiscal reforms, it got to a point where the opportunity coupled with the changes in their reforms made it more attractive for us. And particularly if you think about some of the pre-salt acreage that we picked up, unlike some of the earlier bids, the acreage that we’ve got is covered by a concession contract and not a production sharing contract which just provides a better risk reward balance. So very pleased about the way Brazil has developed and progressed and we think we’ve got a very strong position there now. And as I alluded to previously, we’re going to be very focused to getting after it. The second question is the acreage that we had picked up around the world. It’s fairly obvious to everyone. We’re picking up additional exploration potential. Think about it this way. In terms of how we focus our exploration pursuits, it’s primarily in two key areas. One is where we can get into new play opening opportunities that we see a very high quality potential resource that would compete with global investment opportunities that we believe has a very – assuming we achieve the objectives of the exploration program, we’ll have a clear path to profitability relative to our other investment opportunities in the portfolio. The second area is where we have existing infrastructure and we see significant high quality potential that we can bring on and start generating revenue pretty quick. When you think about some of the deepwater areas that we’re in, Guyana is a great example. While we’ve had that acreage for a while, some of our technology that we’ve applied to sub-surface imaging has really positioned us well to see things that others historically had not seen there. And you’ve seen the result. We’ve got six very substantial discoveries there and the economics are very robust. At a $40 flat rail, we’re talking about double digit returns. The cost of supply for Guyana is very low. And I think we are – as with our partners are very well positioned to capitalize on it and we’re leveraging our global deepwater capabilities in doing so. But the same is true in some of these other areas in West Africa, in Cyprus, we’re looking at resources that could be very much on the low side of the cost of supply curve and can compete in a global view that maybe long on supply for a period of time.

Thanks, Jeff. I appreciate the thoughts.

All right, Jason.

Our next question comes from Biraj Borkhataria from Royal Bank of Canada.

Hi, Jeff. Good morning. Thanks for taking my question. Just had one question. On CapEx, obviously you’re increasing investment in the U.S. Could you talk a little bit about the projects which are effectively or the regions are losing competitiveness internally or moving down the priority list? I see the impairments you’ve taken are partly – it looks like Canadian gas is one of the losers within your portfolio and the impairment shows that. But any color around projects that aren’t going to have less capital going forward will be helpful.

Biraj, I wouldn’t call any area losers. You can think – rewind back over a decade and we were – the industry generally view that the U.S. was going to be declining in terms of energy supplies. And you look at – fast forward to today and look at the abundance that we’ve got. And it’s very relevant to the example that you just highlighted what’s really happened with these non-producing assets within Canada. Well, they’ve become less and less competitive as technology and learning curve benefits have continued to increase substantially the quality and quantity of unconventional resources in the U.S. So as a result we find ourselves in a circumstance where once again technology is going to continue to open up opportunities. So while there may be over certain periods of time maybe areas where you see resource potential or investment dollars declining, I just never short the full potential of technology and what it can bring to additional investment opportunities. As we were just talking per Jason’s question, you see that we’ve got a lot of exploration focus in some of these deepwater areas. Again, we’re trying to fully leverage the full capability of Exxon Mobil’s unique strengths in doing so. But we keep a brief across the whole global portfolio to see if there is anything new that’s coming up. And you’ve seen us going to some places after many years of absence and being very successful there.

Thank you. That’s helpful.

Our next question comes from Paul Cheng with Barclays.

Hi, guys. Good morning.

Good morning, Paul.

Jeff, a number of real quick questions. Do you have any – what’s the asset sales gain in the quarter and in what segment or regions?

So let me start with – per the press release, the total proceeds in the quarter was $1.4 billion. And most of that, Paul, I’d say about two-thirds of that was in the Upstream, the rest in the Downstream. And I really highlighted what that was in my previous comments. The Upstream is driven by our divestment of our operated assets in Norway, Downstream being driven by the divestment of our retail assets in Norway. If you look at earnings, in the quarter itself, it was just shy of – it’s about $540 million. Again, primarily split between the Upstream and the Downstream.

Is it also two-thirds, one-third in terms of earnings?

Well balanced. It’s probably 60/40 Upstream/Downstream.

Okay, 60/40. And just want to clarify. The Mozambique acquisition, the $2.8 billion, is that in 2017? Does that mean that it closed before the year or it closed after the year-end?

It closed before the year-end.

Before the year-end, okay.

It’s in the 2017 results.

Okay. And just curious that for Bakken, you drilled the three-mile – not exactly three-mile, I think 12,000-feet lateral well. Have you completed or brought that on stream that have any production data?

For the three-mile laterals?

Yes.

Yes, we don’t have anything sure at this point. We have brought it on stream. They’re working through facility constraints for the facility – for that region. And I think we’ve got two of the four wells now that are on production but – like I said, it’s still very early days right now. But I will tell you that they’ve met our pre-drill expectations.

Jeff, can you tell us that when did they come on stream or how long you already have the data?

It’s not very long, Paul. We’re talking about months. And as I said earlier, we also had this weather downtime notably up in the Bakken.

Okay. And for the $24 billion on the 2018 CapEx, can you tell us how much is associated with the equity of Eni?

Sorry, the equity of what now?

The equity of Eni, the non-consulting subsidiaries, because the 24 billion is your total rate including the consulting operation --

You’re talking for Mozambique?

No. I’m saying that in 2018, you’re CapEx of $24 billion, how much --

How much is equity companies?

Yes, equity companies.

Yes, Paul, we don’t break that out.

All right, will do. Thank you.

Thanks, Paul.

Our next question comes from Alistair Syme from Citi.

Thanks very much. Just a very quick one, Jeff. Can you just explain on the impairments, taking both U.S. and international, I think you said in 3Q that you were revising the oil and gas prices. So I just wanted to clarify what that change was.

Yes, so I talked about it a bit earlier when – first of all when we go through the process, it really starts through our business planning process, which includes a look at long-term supply and demand and in our planning process, if there’s anything that we see that is a fundamental change that will cause us to do a deeper dive. But one of the things that we have continued to see as a trend has been the substantial growth in commercial resources within the unconventional or within North America and the significant commensurate with that, a significant reduction in the cost of supply. And as a result, when you think about that and the impact it’s going to have longer term, it’s likely to depress longer term gas prices. Now kind of the flipside of all that is, one, that reduces the cost of energy. Also, that technology has, as I said, driven down the cost side of it. So it’s a matter of making sure that you’re pursuing the most competitive assets. And then when you think about some of these Canadian assets I referenced, they just don’t compete like they used to at this point. And as a result, we took the decision not to progress any more development planning activity and write them off.

Okay. Thank you for clarifying.

You bet.

Our next question comes from Theepan Jothilingam with Exane BNP.

Hi. Good morning, Jeff. Two quick questions. Firstly, just in terms of coming back to the cash flow number for the quarter, just objectively, are there any particular sort of one-offs or seasonal factors? I know it’s difficult just to extrapolate one quarter into sort of annual performance but I just want to know if there was any sort of cash taxes that were higher than a typical quarter or not. Second question, you’re growing that retail business in Mexico. I just want to understand where you think the position can get to or what are the ambitions for Exxon in Mexico in the Downstream? Thank you.

Theepan, there’s really nothing that is mentionable with respect to our cash flow in the quarter itself other than these kind of one-offs that were – and it’s an accumulation of a bunch of one-off, other earnings events that had a negative impact on earnings and therefore cash flow as well. But I will be the first to admit. Those happen throughout the year as well. So there’s nothing that I would point to, other than the impact from the tax reform that had the effects that we’ve already talked about on the other balance sheet items that I would be able to talk to.

Okay.

On Mexico, we went ahead and, I believe in the fourth quarter, we opened eight Mobil branded stations. We’ve got plans to go ahead and open up another 50 sites by the end of the first quarter. I think it’s important that Exxon Mobil is participating in Mexico on an integrated basis using our global refining capacity to supply the Mexican fuel demand. I believe we did announce that we’ve got plans to invest about $300 million in logistics, product inventories, and marketing over the next decade. But I think it provides another good opportunity and outlet for our refined products.

Okay. Thanks very much, Jeff. See you next month.

You’re welcome.

Our next question comes from Pavel Molchanov with Raymond James.

Hi, guys. Just one from me. I don’t think it’s been touched on yet. A lot of headlines over the last 10 days or so regarding the Groningen field. And I wanted to get your understanding of what the JV will be able to produce at Groningen in the course of 2018 beyond the output cap that went into effect this past October.

Yes. Well, right now, as you know, NAM, which is the operator, is continuing to operate under the current cap at 21.6 cubic meters. We clearly understand the concerns of the people that are experiencing these tremors and the related damage. We respect the government’s efforts to go in and address valid concerns. In terms of how NAM will respond to that, it’s really – they’re probably best to go ahead and address the matter. We continue to provide technical support to them. But I think if the cap, the current 21.6 stays in effect through the full year, Pavel, it would impact our 2018 volumes by about 40 million cubic feet a day lower than 2017. But, of course, as you probably saw on the recent announcement, the government is thinking about modifying that.

Okay, clear enough. Appreciate it.

You’re welcome.

Our next question comes from Rob West with Redburn.

Hi. Thanks, Jeff. There’s two shorter term questions I wanted to ask you. The first one is thank you for the breakdown of the production effects between divestments and PSCs and decline. I was wondering on the decline component, can you touch on whether the assets, particularly Africa and Asia, the weaker areas, are seeing any decline that’s above the level you’d expected or in line? And that is in the context of I think some of your peers are seeing lower declines generally because of digitization and reliability drives, because I was wondering where you were on that. That’s my first one.

Yes, Rob, it’s a great question because we monitor that very closely. And I’d say, by and large, over the last year we’ve been able to mitigate some of the natural field decline in a number of fields through very solid reservoir management, artificial lift improvement, changes to how we manage the assets, reliability. But, by and large, we’ve managed that very well and been able to offset those declines. So nothing in excess of what we would expect at this point.

Okay. That sounds like good news. On the second question, back to what Brendan was asking about on the Chemical side, the long-term view is clear. I was wondering more on the short term. I guess what we’ve got, particularly in the U.S., is quite a large number of start-ups really bunched together quite quickly. And I hear you on the long term of the market but particularly this quarter, you had big growth in volumes and with that, a slight weakening of margins. Do you see any short-term margin impacts as those big volumes ramp up? I’m just trying to get a sense of that prior comment you made, whether it’s a long-term comment or whether we should brace for some short-term margin impacts as the ramp-ups come?

Well, Rob, there’s always the possibility of short-term volatility. No doubt about it. I mean, if you think about – break it down to some elements, the olefins, polyolefins, demand growth has been very robust. But there are going to be some capacity start-ups here over the next two years or so that could have some implications. But what you’ve got to do is you’ve got to have the lowest cost of operation and you have to have a very high-value and appreciated product to sell. And if you look at our metallocene product sales, we’ve been growing at a much greater escalation than the demand growth for chemicals. But each one of these products, we pay very close attention to it. And our investment premise has primarily been based on our long-term expectation in terms of growth. And then you build the portfolio to be robust by lowering your feedstock flexibility, taking full advantage – for Exxon Mobil, taking full advantage of the lower cost structure from the integration between our chemical and our refining operations. And then, as I said, fully leverage our technology in order to provide a high-value product that the market appreciates and has a pull on.

Okay, great. Thank you. Look forward to asking some long-term ones at the strategy update.

Okay, great. Thank you.

Our next question comes from John Herrlin from Société Générale.

Yes, just two quick ones. With Liza Phase 2, are you going to own the FPSO or lease?

Yes, John, that’s to be determined.

Okay, that’s fine. And then with respect to the horizontal wells in the Midland, three-mile wells take a while to clean up. Can you give us a sense of how long it does take to clean up a well that long?

Yes, I really don’t have anything to share at this point. It’s still pretty early days on the start-up for these wells. I know there’s a lot of interest as a result of us pushing further and further out. But I will tell you that all of the technical work that we have done, the modeling, et cetera, in order to justify the incremental value proposition that we’re to get from these longer laterals that these wells so far are performing as expected, in terms of execution and initial rates. But when we get to the point where we’ve got some good data that we feel like is appropriate, we’ll go ahead and share it at that point.

Okay. Thank you.

You’re welcome, John.

This concludes today’s question-and-answer session. I’d like to turn the call back over to Mr. Woodbury for any additional or closing remarks.

Well, as always, I really do appreciate your interest, your engagement, and your very thoughtful questions. And as I noted earlier that we’re looking forward to having a good conversation next month at our Analyst Meeting. And we do have in sights a very aggressive plan to drive our value growth and intend to give more clarity around what that looks like, in terms of what it is, how we’re going to do it, and why it is important to the corporation and to our shareholders. So, again, I appreciate your interest and we look forward to seeing you next month.

This concludes today’s conference. Thank you for your participation and you may now disconnect.