Good day everyone, welcome to this ExxonMobil Corporation second quarter 2015 earnings conference call. Today's call is being recorded. At this time, I'd like to turn the call over to the Vice President of Investor Relations and Secretary, Mr. Jeff Woodbury. Please go ahead, sir.
Thank you. Ladies and gentlemen, good morning, welcome to ExxonMobil's second quarter earnings call and webcast. My comments this morning will refer to the slides that are available through the Investors section of our website. Before we go further, I'd like to draw your attention to our cautionary statement shown on slide two. Turning to slide three. Let me begin by summarizing the key headlines of our performance. ExxonMobil generated earnings of $4.2 billion in the second quarter. We are delivering on our investment and operating commitments across our integrated portfolio. Corporation's results demonstrate sound operations, superior project execution capabilities, and continued discipline in both capital and expense management. Downstream and chemical earnings increased significantly from the second quarter of 2014, driven by higher margins, continued strong demand, and the quality of our product and asset mix.
Upstream production volumes of 4 million oil equivalent barrels per day were 3.6% higher compared to a year ago quarter, and liquids volumes were up nearly 12%. Growth was underpinned by an increased level of new development startups over the last 18 months, largely in Africa, Canada, Indonesia, Papua New Guinea, and the U.S. These results underscore the resilience of our integrated portfolio and the benefits of our disciplined capital allocation. In the first half of 2015, the corporation generated cash flow from operations and asset sales of $17.9 billion, with free cash flow remaining positive despite challenging market conditions. Moving to slide four, we provide an overview of some of the external factors affecting our results. Global economic growth improved in the second quarter of 2015. The U.S. rebounded after contracting slightly in the first quarter. Europe improved marginally amid concerns on Greece.
China's economy stabilized while Japan's growth tapered. Crude oil prices partly recovered during the quarter, while natural gas prices declined further. Refining margins continued to strengthen in both the U.S. and Europe. Chemical commodity margins also improved, while specialty margins weakened. Turning to the financial results as shown on slide five. As indicated, second quarter earnings were $4.2 billion, which represents $1 per share. Corporation distributed $4.1 billion to shareholders in the quarter through dividends and share purchases to reduce shares outstanding. Of that total, $1 billion was used to purchase shares. CapEx was $8.3 billion, which is in line with plans. We have remained focused on structural improvements through capital efficiency, as well as the capture of additional cost savings in a softer market.
Cash flow from operations and asset sales was $9.4 billion, and at the end of the quarter, cash totaled $4.4 billion and debt was $33.8 billion. Next slide provides additional detail on sources and uses of funds. Over the quarter, cash decreased from $5.2 billion to $4.4 billion. Earnings adjusted for depreciation expense, changes in working capital and other items, and our ongoing asset management program yielded $9.4 billion of cash flow from operations and asset sales. Uses included net investments in the business of $7.1 billion and shareholder distributions of $4.1 billion. Debt and other financing increased cash by $1 billion. Share purchases to reduce shares outstanding are expected to be $500 million in the third quarter of 2015. Moving on to slide seven for a review of our segmented results. ExxonMobil's second quarter earnings of $4.2 billion were down $4.6 billion from a year-ago quarter.
Lower upstream earnings were partially offset by stronger downstream and chemical results. Gains on asset sales were $1.2 billion lower than the second quarter of 2014, reflecting the absence of the Hong Kong power and Canadian asset divestments in the upstream segment. I'll also note that our corporate effective tax rate was 45%, up four percentage points compared to the year-ago quarter and up 12 percentage points sequentially. This higher tax rate reflects the relative mix of income across geographies and tax regimes, as well as a one-time increase in the corporate income tax rate in Alberta, Canada. In the sequential quarter comparison shown on Slide eight, earnings decreased by $750 million as lower upstream and downstream earnings were partly offset by higher chemical results. Guidance for corporate and financing expenses remains at $500 million-$700 million per quarter.
Turning to the upstream Financial and Operating results starting on Slide nine. Upstream earnings in the second quarter were $2 billion, down $5.9 billion from the second quarter of 2014. Sharply lower realizations decreased earnings by $4.5 billion, where crude declined by almost $46 per barrel, and gas was down almost $2.40 per thousand cubic feet. Note that favorable volume and mix effects increased earnings $330 million, driven by production growth on our new developments. All other items were negative $1.7 billion, and this was driven by the absence of divestment gains from Hong Kong power and Western Canadian assets, which represented $1.6 billion. The higher income tax rate in Alberta, Canada, resulted in a negative $260 million non-cash deferred tax adjustment. Lower operating costs provided a partial offset. Moving to Slide 10.
Oil equivalent production increased 139,000 barrels per day, or 3.6% compared to the second quarter of last year. Liquids production increased 243,000 barrels per day, or nearly 12%, benefiting from new projects, work programs, and favorable entitlement impacts. Natural gas production decreased 622 million cubic feet per day, or 5.8%, driven by regulatory restrictions in the Netherlands. Volume adds from the Papua New Guinea LNG and Hadrian South projects, along with entitlement effects, offset field decline. Turning to sequential comparison starting on Slide 11. Upstream earnings were $824 million lower than the first quarter. Realizations increased earnings by $600 million, crude was up almost $11 per barrel, while gas declined about $1 per thousand cubic feet. Unfavorable volume and mix effects decreased earnings by $420 million, driven by lower seasonal gas demand in Europe, regulatory constraints in the Netherlands, and maintenance in the U.S.
All other items reduced earnings by $1 billion, mainly driven by unfavorable tax and foreign exchange effects and lower gains from asset sales. Upstream unit profitability for the second quarter was $5.77 per barrel, excluding the impact of non-controlling interest volumes. Earnings per barrel for the first half of 2015 was $6.74. Moving to Slide 12. Sequentially, volumes were down 269,000 oil equivalent barrels per day, or 6.3%. Liquids production increased 14,000 barrels per day on new project growth and work programs, partly offset by maintenance, entitlement effects, and field decline. Natural gas production was down 1.7 billion cubic feet per day, driven by lower seasonal demand in Europe and regulatory constraints in the Netherlands. Moving now to the Downstream Financial and Operating results starting on Slide 13. Downstream earnings for the quarter were $1.5 billion, up $795 million compared to the second quarter of 2014.
Higher margins increased earnings by $1.1 billion. Volume and mix effects decreased earnings by $80 million. All other items reduced earnings by $230 million, driven by higher maintenance activities. Turning to Slide 14. Sequentially, downstream earnings decreased $161 million. Stronger refining margins, mainly in the U.S., increased earnings by $140 million, whereas higher maintenance activities reduced volumes and increased expenses by $160 million and $140 million, respectively. Moving now to the Chemical, Financial, and Operating results starting on Slide 15. Second quarter chemical earnings were more than $1.2 billion, up $405 million versus the prior year quarter. Higher margins increased earnings by $340 million. Favorable volume and mix effects added $20 million. All other items increased earnings by $50 million, mainly due to asset management gains, partly offset by unfavorable foreign exchange effects. Moving to Slide 16. Sequentially, chemical earnings increased by $264 million.
Lower margins decreased earnings by $10 million. Positive volume and mix effects increased earnings by $40 million. All other items added $230 million as asset management gains were partly offset by higher maintenance. Moving next to an update on our exploration and project activities on Slide 17. We continue to focus on pursuing a diverse set of high-quality resource opportunities. In Guyana, ExxonMobil made a significant oil discovery on the 6.6-million-acre Stabroek Block well, which was drilled approximately 120 miles offshore, encountered more than 295 feet of high-quality oil-bearing sandstone reservoirs. We are encouraged by these results and we're assessing commercial viability of the resource, as well as evaluating additional potential on the block. In Romania, drilling continues in the deepwater Neptune block with five wells drilled to date. The potential for commercial development will be assessed after completion of the drilling program.
In the Kurdistan region of Iraq, drilling activities on the Al-Qush block are underway and anticipated to finish later this year. Turning now to a status update on our new development projects. In Canada, the Kearl expansion project started up ahead of schedule in June and is currently producing more than 100,000 barrels of bitumen per day. Phased development of the Kearl resource enabled us to draw significant learnings from the initial development project and capture lower capital costs and operating efficiencies. Total Kearl production averaged 130,000 barrels per day in the second quarter and is ultimately expected to reach 220,000 barrels per day. Erha North Phase Two in Nigeria is another example of a capital-efficient development. This subsea project utilizes existing processing facilities and avoids the need for an additional FPSO vessel. Deepwater drilling and subsea equipment installation are progressing, with startup expected later this year.
At the Banyu Urip development in Indonesia, we continue to experience favorable well performance, and production is now more than 80,000 barrels per day. The central processing facility is expected to start up in the next few months, which will enable the project to reach peak production of more than 200,000 barrels per day by year-end. In the U.S., Lower 48 onshore, we have maintained a measured investment program to unlock the value of more than 15 billion oil equivalent barrels. ExxonMobil is a leading producer onshore and the largest producer in the United States. Through our XTO affiliate, we operate in all major U.S. unconventional oil and gas plays.
On the term, gas investment is paced with anticipated demand growth, whereas near-term emphasis is on the development of 2.4 million net acres in the liquids-rich Bakken, Permian, and Woodford, Ardmore, Marietta, where investment opportunities remain attractive in today's price environment. Net production in these three areas was about 240,000 oil equivalent barrels per day in the second quarter, up more than 20% from the second quarter of last year. Throughout the commodity price cycle, ExxonMobil has a relentless focus on reducing costs and improving efficiency in our operations while maintaining high operational integrity. We regularly assess our performance relative to competitors and strive to be best in class. As this chart illustrates, our efforts deliver results. XTO is a leader in exploration and development costs per barrel of proved reserves added, just one metric of many that are considered.
This position is enabled by our disciplined and measured approach to resource development, deployment of proprietary technologies, and our intense focus on efficiency and productivity. We also have demonstrated the capability to respond quickly in a rapidly changing environment, and to date have captured incremental savings of about 30% in drilling and completion costs from the peak in 2014. These savings include market benefits as well as ongoing structural cost efficiencies and productivity improvements across our operations. I'd like to conclude this morning's comments with a summary of our year-to-date performance. In short, the corporation is delivering on its investment and operating commitments. Through mid-year, ExxonMobil earned $9.1 billion, benefiting from our integrated business, which captures value throughout the commodity price cycle, as demonstrated by our downstream and chemical results.
In the upstream, production increased to 4.1 million oil equivalent barrels per day, up almost 3% year-on-year, and it remains in line with our plans. Volume contributions from successful new developments underscore our superior project execution capabilities and reputation as a reliable operator. Our operational results, combined with continued capital discipline, generated cash flow from operations and asset sales of $17.9 billion and free cash flow of $3.9 billion. Our commitment to our shareholders remains strong as the corporation distributed $8 billion to shareholders through mid-year. Regardless of industry conditions, we remain focused on what we control and are driven to create shareholder value through the cycle. That concludes my prepared remarks, and I would now be happy to take your questions.
Thank you, Mr. Woodbury. The question and answer session will be conducted electronically. If you would like to ask a question, please do so by pressing the star key followed by the digit one on your touchtone telephone. We request that you limit your questions to one initial with one follow-up so that we may take as many questions as possible. If you are using a speakerphone, please make sure your mute function is turned off to allow your signal to reach our equipment. Additionally, please lift your handset before asking your question. We will proceed in the order that you signal us, and we will take as many questions as time permits. Once again, please press star one on your touchtone telephone to ask a question. We'll go to Phil Gresh with J.P. Morgan.
Hi. Good morning, Jeff.
Good morning, Phil.
First question, I just wanted to ask on the CapEx, what your latest thoughts are for the budget for this year? As we look ahead, post 2015, at the Analyst Day, you said sub $34 billion. It was a bit vague. A lot of your peers have been talking about reducing their sustaining capital costs as we look ahead. Just want to get any thoughts from you about perhaps where CapEx could go over the next few years, if you have any updates.
Sure, Phil. I'd tell you that we have no new guidance. Our CapEx guidance for 2015 remains at $34 billion. Having said that, given our ongoing focus on capital efficiency and the very successful capture of market savings in the current business climate, I think it is fair to say that there is a downward vector on that number. That type of focus and efficiency will be carried on into the subsequent years. Having said that, I also note that we continue to invest in the business, and we have a very attractive inventory of high-quality opportunities. Given the financial flexibility we've got, we can garner some real benefits during the down cycle in a softer market environment.
Sure. Okay. Second question is on the acquisition environment. Seems like others have been talking about the bid-ask spread maybe starting to improve a bit here. Maybe you could just talk about what you're seeing or any attractive opportunities starting to pop up on your radar screen. Just more broadly, as you think about the portfolio, are there places where you think inorganically you'd like to shift the mix over time? I'm specifically thinking about short cycle.
Yeah. Well, just broadly speaking on acquisition or what we'd like to say is asset management, I'd characterize it for us as business as normal. We always keep alert to value opportunities, not only to pick up what we believe is strategic and high-value opportunities, but looking for means to create greater value from our existing portfolio. We keep alert in terms of what we would target. If you step back and think about the diversity of our resource base, we're very well covered across all of the resource types. We're always interested in expanding those positions or further high-grading them. I wouldn't suggest that as we consider opportunities for picking up additional assets, that we're focused in one area or the other. We're always looking for high grading the portfolio. Phil, that also includes our exploration program.
It is designed to identify higher value opportunities to be added to the resource base or maybe to displace what we see as not as relatively significant as the exploration program can add to.
Okay. Thanks, Jeff.
You bet.
Next, we'll go to Doug Leggate with Bank of America Merrill Lynch.
Thanks. Good morning, everybody. Good morning, Jeff.
Good morning, Doug.
Sorry, my line cut out there for a minute, I hope this question hasn't been asked already. There's two things I wanted to hit this morning, Jeff, if I may. The first one is on tax. I'm trying to understand the extent of the mess on the international E&P, that you were looking at anyway. We're noting what Imperial did with their tax charge related to the change in the Canadian tax regime. I wonder if you could address that issue first, and I have a follow-up, please.
If you look at our tax in the second quarter of 2015 relative to 2014, we're up just over 3%. I'd say that about 5% of that were associated with one-time tax items. The largest piece being the Alberta tax that I mentioned in my prepared comments. The rest of the closure on that, down about 1%, is really due to the portfolio mix of income across our various business segments and geographies. If you look sequentially, Doug, we're up almost 12%. Again, the mix effect adds about a 6% increase, and the one-time items add about 6%. 4% due to the Alberta tax increase, and then just under 2% associated with the absence of the first quarter U.K. tax rate change.
Look, in absolute terms, Jeff, order of magnitude, it looks to us like that was somewhere around $0.10 or $0.12 on the quarter of non-recurring non-cash. Does that sound about right?
Say a little bit more, Doug, on how you're coming up with that.
I think the $320 million was what Imperial took. That alone is $0.08 a share, right?
The Alberta, as I said in my prepared comments, Doug, was about $260 million Exxon Mobil share.
Okay.
Which I-
All right, fair enough. I'll go back and look at that. My follow-up is really on the downstream. Obviously, I realize for commercial reasons you don't want to talk about Torrance explicitly, but when we look at the kind of results that other West Coast operators have had and the relatively weak U.S. downstream that you have, it strikes me that there's probably some merit in giving us some idea what the likelihood of Torrance coming back online is without all the additional costs of importing gasoline and so on. To the best that you can at this point, Jeff, can you give us an order of magnitude in terms of timing as to when you expect Torrance to get back to where it ought to be?
I think first, if I could, Doug, just to comment on your statement about a relatively weak downstream in the second quarter. I'd first say that we've seen significant margin improvement relative to last year. Second, as I commented on, we did have a very heavy maintenance period in the second quarter of 2015, and that had the downward impacts that I referenced in my prepared comments. In terms of Torrance, I think you probably know, Doug, that some of the units at the refinery are operational at reduced rates. We are producing gasoline by importing components and blending with refinery production, and I'll also say we're also producing distillates. We are progressing repair of the electrostatic precipitator as well as pursuing interim options.
It is difficult to provide you a time at this point given the definition work that's underway as well as the regulatory review that's underway. As we get closer to defining that timeline, we'll look for an opportunity to share that broadly.
I appreciate you at least taking a stab at the answer. Thanks, Jeff.
We'll go next to Blake Fernandez with Howard Weil.
Good morning, Jeff. Question for you on the gas volumes, which were fairly weak. I think you pointed out in the press release 622 million cubic feet down year-over-year. Can you highlight the Netherlands component of that and maybe give us an update of, for one, what contribution the Netherlands had in that decline, and then maybe some timing or outlook on when that may come back?
Yeah. The Netherlands was, as you could appreciate, a large component of it. It was about 600 million in the second quarter relative to the prior year, prior quarter.
Okay. Any thoughts on when that may return to market?
Well, the Netherlands on a quarter-to-quarter basis was all associated with the regulatory restrictions that the government has placed on the asset. That will return over time, but it's going to be a constrained cap on what we can produce from the resource.
Okay, fair enough. The second question for you, on slide 11, you highlight some of the sequential decline. I know the benchmarks were up. I know you've got some issues with tax and whatnot, but that billion-dollar waterfall other category, can you highlight what is in there besides tax? Then also, if you could maybe highlight some of the LNG impacts. I know pricing got fairly weak this quarter.
Yeah. Blake, on the billion-dollar other component, this is the sequential comparison. About 60% of that had to do with tax. 15% or so was Forex, the rest is a number of other puts and takes. On your comment about LNG, let me just broadly say that our natural gas realizations had a negative effect of about $300 million. To square that with the $600 million increase in realizations, we had About $900 million positive due to liquids and $300 million due to negative gas realizations.
Perfect. Thanks, Jeff.
Very good.
We'll go next to Evan Calio with Morgan Stanley.
Hey. Good morning, Jeff.
Good morning, Evan.
Let me just a follow-up on CapEx and the down cycle approach. Your peers appear or at least are more vocal in cost-cutting and laying off employees, increasing asset sales, and reducing the forward CapEx guidance to close their funding gaps. While almost existential upstream struggle. Your release and call has been different. Is that just stylistic or does it mean a different approach by Exxon through the down cycle? Any comments there?
I would back up and just talk fundamentally culturally, the organization is designed to constantly focus on capital efficiency and cost management. Okay?
What we are looking for always, Evan, is to drive the cost structure down in the business. Okay? When we have a down cycle like we're seeing right now, we further are well-positioned to quickly lead that cost curve in capturing market savings. On top of that, we've got that financial flexibility to invest through the cycle, and that does very well position us to capture those market savings in the down cycle. In short, I'd say it's a focus regardless of where we are in the cycle. Likewise, on staffing. You mentioned comments about staffing. First and foremost, I want to highlight that our people are our greatest asset.
They really drive the success of this company. Therefore, we take a very measured approach to managing our headcount, given the cyclical nature of the business and the need for us to be ever more productive. In doing so, we keep an unrelenting focus on capturing organizational efficiencies to keep the organization right-sized, again, given the likelihood of business volatility. If you look at our employee headcount, it has been coming down consistently since the merger of Exxon and Mobil, where we were at about 125,000 employees. Today, we're at just over 80,000 employees. You may recall during the analyst meeting that the chairman talked about some of this, and he gave some examples by way of steps that we have taken well in advance of the down cycle in order to do exactly what the numbers are depicting.
Right. Your CapEx appears to be trending at least below guidance so far this year. My follow-up on the downstream and maybe as it relates to the U.S. upstream, can you discuss like crude transfer pricing assumptions between North American upstream and refining? It would appear that refining results that may not be entirely market-based, kind of understanding refining and transferring some of that to your upstream. Any color there would be helpful. Thank you.
Yeah. It is very much market-based. As you know that our integrated sites have the capability to run a very wide range of feedstocks. I can't get into specific pricing at all, but we have a very competitive capacity within the U.S. We're the largest in the Gulf Coast and Midcontinent. As you know our capacity is greater than our overall U.S. production. We're also out there picking up supplies that meet our system's needs. Our Midcontinent Gulf Coast refineries have increased processing of advantage North American crudes. Currently about 45% of the slate was North American in 2011, and currently we're at about 70% in 2014. The key point I want to emphasize with you is that we get intrinsic value given the integration of our operations between upstream, downstream, and the chemical business, allowing us to really focus on optimizing the molecule, the value of the molecule.
Understood. Thanks for your comment.
Ed Westlake with Credit Suisse has our next question.
Yeah, this is just a philosophical question. Jeff, you've got a great balance sheet, and you've just reduced the buyback. Are you worried about future deterioration in cash flows due to the macro? Is this just a decision that's just made quarter to quarter without thinking about the implications? I know people are chattering in the market this morning that you're trying to conserve cash for M&A. Maybe just a comment there, and then I've got a detailed comment on the results.
Ed, just go back to fundamentally our business plans and our investment strategy comes from our perspective on the long term that we share with you all in our energy outlook. That's what really sets our business strategy and our investment outlook. Stepping back from that, we maintain a very robust balance sheet, as you say. We have the significant inventory investment opportunities, over 90 billion barrels of high-quality resource, a very strong inventory of downstream and chemical opportunities. We manage the cash flow looking at the current business climate as well as the future outlook. We have a high degree of confidence in what we expect supply and demand to do in the future. Fundamentally, we're committed to our shareholders and to continue to provide a reliable and growing dividend.
I think the continued buyback is evidence of the confidence that we have in an integrated business model.
You mentioned the LNG impact, which was helpful. Obviously, Asia LNG prices might come in the spot market, particularly not contract, come under a bit of pressure as all of these Australian projects try and fight their way into market, and they all have commissioning cargoes and some spot with them. Can you give us a sense of how much flexibility in the overall contract structure your customers have to say, "We're going to take minimum amount of volumes to maximize our advantage to take some of the perhaps the cheaper spot cargoes that are available"? I'm just trying to get a sense of, is there a little bit at the margin of price risk and volume risk even to your existing LNG business? It's fine for you to say, "No, there's not a big risk." I mean, that could just be the answer.
Yeah, sure. I'll just remind you that a majority of our LNG is under long-term contract.
Yep.
We have very little spot risk, and we've got diversion capability in the existing contracts to allow us to capture a greater value if it's there.
If Asia says no, you can put it into Europe or do something else from the Middle East. Yeah.
Okay.
Thanks.
Thanks, Ed.
We'll go next to Neil Mehta with Goldman Sachs.
Hey, good morning.
Good morning, Neil.
It's pretty clear that there's a path to grow production through 2017 with some of these large capital projects that you talked about and seeing indications of production growth here in 2015. One of the questions investors frequently ask is how does Exxon grow production post-2017, which we'll probably get some line of sight on at the next Analyst Day when you roll forward past 2017. Any initial color about how you think about growth, especially if the forward curve proves correct post-2017 would be valuable.
Thanks, Neil. I'd say first and foremost just step back a moment and remind everybody that based on that very sizable high-quality resource base I've been talking about, we've had a very significant upstream investment program in place now for extended period of time, whereby from 2012 to 2017, we had committed to our shareholders to bring on 32 high-quality, long-life assets. We're about halfway through that in terms of starting them up. We had a very substantial tranche of them starting up in 2014 with 8. This year we have another 7 starting up. You go into 2016, 2017, we've got the rest of them coming on. The information that we had shared back in the analyst meeting, we were to grow capacity by about 1.1 million oil equivalent barrels per day, recognizing that those projects starting up in 2017 were just at the early stages.
They would ramp up into 2018 and thereafter. We also shared, Neil, in our F&O review the list of projects that we've got on the table right now for 2018 forward. These are all in different stages of progress. Some are in development planning, some are in feed. That is the list that we are working on to bring to an FID decision. Some of these that we're working to further optimize in the current price environment. Some may have some opportunities to enhance the commercial terms. As we get closer to FID decisions, we'll signal where we are. As you indicated, we'll provide another update in March of next year which will take us beyond the 2017 horizon.
All that said, I want to reinforce that we've got this very robust inventory of investment opportunities. I don't want to focus just on the upstream, the downstream and chemical business as well. That positions us well to be very selective on what we want to progress and when we want to progress it. It gives us the capability on those other assets or investment opportunities to keep working on to make sure that we're capturing the greatest value from it.
Thanks, Jeff. The follow-up is on that point about chemicals. It was one of the few places in the quarter where we saw a real upside to our numbers. Just wanted you to talk about what you're seeing from the macro in the chemical space. Clearly, margins haven't compressed as much as some would've thought given the move down in Brent, just how you're thinking about growing that business on a go forward.
Just broadly speaking. As you can appreciate, there are structural differences in the chemical business. The U.S. natural gas, natural gas liquids provide for very strong margins and advantage polyethylene. In Europe, Asia Pacific, the liquids feeds, energy prices have been higher, and we were at the bottom of the cycle in Asia Pacific. We saw in the first half material improvement due to lower feed and energy costs. Specialty margins have declined over the past few years with capacity additions exceeding demand growth, but demand growth remains robust. As we've said before, our long-term business, we have a positive outlook for global demand expecting to exceed GDP by about 1.5%, or said another way, growing by more than 50% over the next 10 years, of which about two-thirds of that will be in Asia. Very well positioned to participate.
As you see that we're making some important investments like the expansion of Baytown. That allows us to continue to participate in the high-value polyethylene market given the very low feed cost we have here in North America.
Thank you, Jeff.
We'll go next to Allen Good with Morningstar.
Good morning, Jeff. I appreciate the comments on the cost savings in the U.S. Lower 48. I wonder if you could offer up what Exxon's seen as far as cost savings internationally for the projects under construction or maybe some currently in the development phase and maybe even offshore as well. Do you expect to capture similar cost savings there? What would be some of the timing on that relative to what you've seen so far in the U.S.?
Yeah. I would tell you, Allen, let me break it up between capital and expense. To answer your question right now, yes, we are capturing cost savings across our global portfolio. On the cost side, I just want to keep on emphasizing cost management is a fundamental driver in the success of our business. No doubt about it. Throughout that business cycle, our organization has a strong culture of driving down the cost structure. When we're in these down cycles, we expect to lead the cost curve in capturing additional market savings. Ongoing structure improvements and additional market savings in a down cycle. We're very well positioned.
One of the things that allows us to react very quick, as I mentioned last quarter, is we've got a global procurement organization that is always focused on capturing the lowest life cycle cost, and they are absolutely critical in managing our overall cost structure. As you can appreciate, Allen, savings vary significantly by region and type of service. By way of example, base metals are down as much as 40%. Engineering services and construction labor is down 10+%. Rig rates are down across the board both land and floater. On floater, the day rates and mobilization costs are down anywhere from 25%-40%. We're well positioned to capture that both on the cost as well as the capital side.
Okay, great. Thanks. One more question. Maybe a bit premature, but it certainly made headlines of late. Along with the Iran deal, it seems that some of your peers are becoming interested. I know there's been some headlines suggesting Exxon is as well. What would you need to see in Iran as far as milestones before you'd potentially become interested in doing business there?
Allen, I'll just say that we'll continue to monitor the circumstance, and I want to be really clear that we'll remain in full compliance with existing sanctions. As you know, there are multiple sanctions that apply to U.S. companies. That's all I can really say about that right now, Allen.
All right. Thanks.
We'll go next to Asit Sen with Cowen and Company.
Thanks. Good morning, Jeff.
Good morning.
Two questions. Thanks for the additional color on Lower 48. I wonder if you could give us the breakdown in production and rig activity by the three main unconventional plays, and talk about how you expect things tracking in the back half of the year.
Yeah. Really good growth there. From a net production basis, as I said, we're producing about 240,000 barrels a day over 20% increase quarter-on-quarter versus the prior year. Permian is about 120,000 barrels of that, Bakken just over 80,000 barrels, and Woodford is about 40,000 barrels.
Rig activity, please.
Our rig counts have come down just a little bit. From the first quarter, we're down about 10 rigs. We're currently running 34 rigs in those three plays. We've been able to continue to high-grade the activity. I think as we showed in the analyst meeting, we continue to capture both cost efficiencies and productivity improvements. A lot of what we learned in these plays are being quickly shared to make sure that we're integrating all those learnings into our forward execution plans. Very pleased with the positions that we've got in those assets, and we've got a very sizable inventory of drillable prospects.
Would you think that there would be upside to the incremental 2017 target? I think it was 150,000 barrels a day. Would you give an efficiency?
Well, we're going to keep a measured pace, as we said previously. If you think back over the ups and downs, when everybody was really picking up a lot of rigs, we took a measured pace and made sure that we were going at a pace that we can fully capture the benefits of the learnings that we were realizing. Likewise, in the down cycle, our rig counts haven't come down as significant as you've seen in the industry because we've been able to capture those learnings. The economics of these investments are still robust. I would give you a response of a measured pace that with a very attractive inventory of opportunities, we'll keep moving forward and anticipate, as we showed in the analyst meeting, a growth in our unconventional liquids volumes.
Great. My second question is on LNG. Spot LNG market has been surprisingly strong, over $8 near term, would be 15% oil equivalent. Just wanted to get your thoughts on that. Is it seasonality or something else? Could you update on the demand pattern that you're seeing in Asia?
I think, broadly speaking, as you can appreciate, there's a lot that goes into this. As we've said, gas demand has grown at about 1.6% per year. LNG capacity will probably triple from 2010 to 2040. You're seeing a general demand growth that's obviously underpinning realizations. There are a lot of other country-level dynamics like alternatives, nuclear power, fuel switching from coal to gas. All those variables really play into this 1.6% per year that I mentioned.
Thank you very much.
Paul Cheng with Barclays has our next question.
Thank you. Jeff, good morning.
Good morning, Paul.
Two questions, if I could. If we're looking at your very sizable total resource, which is over 90 billion barrel, do you have a rough estimate that what's the percentage of that resource base already passed through all the regulatory hurdle and with today's technology, will be able to produce and earn a 10% after-tax internal rate of return at $60-$70 Brent price? Any kind of color you can provide?
Yeah, I would tell you, I'd ask you to think about it differently, Paul, in that the resource base is in various stages of development planning. Some assets clearly, as I indicated previously to Neil, some of those assets are currently on the table right now in development planning and pre-feed. Some of the assets, our probable reserves and our possible or static resources are under various stages of development planning in order to ensure that we are defining the most attractive returns for those resources. Some, we make it to the point, Paul, that we have a better alternative to monetize that. That may include divestment. It's a dynamic resource base that is constantly being upgraded with new additions, pulling things out that we don't see as creating value for the corporation. I'll give you one example by way of illustration.
You think about the sizable Julia resource and how we've optimized that to a much smaller initial development in order to de-risk the overall resource size. That's the type of optimization that I'm talking about. Based on that de-risking, it will better position us on future investment opportunities.
Great. Second question, just some quick number. I think in a number of your segment that you have some asset sales gain. Can you just give us what is the asset sales gain in the second quarter by segment and breakdown between U.S. and international? Also tell us what is the current production in phase 1 and phase 2 separately. Thank you.
Yeah. In terms of the earnings impact from our asset sales in the second quarter, it was about $490 million. A majority of that, Paul, was in the chemical business. In terms of Kearl, in total, as I said, in the second quarter, it was producing about 130,000 barrels per day. The phase 1 or the initial development was around 100,000 barrels, and phase 2 is around 30,000 barrels.
Jeff, do you have a latest number in July, in the last couple, maybe a week or so on Kearl?
On Kearl? No, I don't have anything to share at this point.
Okay. Thank you.
We'll go next to Roger Read with Wells Fargo.
Yes, good morning.
Morning, Roger.
I guess one question hasn't really been asked, I'd like to get out there. Oil prices this low, last time we had a sustained lower for longer situation, a lot of mergers in this space. I know you don't want to talk about anything specific, but as a general sort of commentary on maybe the bid-ask spread that's out there, or the type of assets that might be interesting to Exxon, if you could give us any clarity on that.
Yeah, Roger, that was similar to an earlier question. As I said earlier, I would just say that we keep alert to where we've got value propositions. The way I'd clarify that is, bolt-on acquisitions that have natural synergies with our business, long life assets that we think that our expertise and operating experience will bring intrinsic value associated with it. It's not focused on a specific resource type, but it's really focused on where we think that our unique experiences can add value that others can't see.
On the bid-ask spread, maybe how that's, if it's changed at all, if there's anything you can add there?
Yeah. Roger, I really don't have much to add on there. That's really a function of the transactions. Certainly, staying in a lower price environment is going to encourage both buyers and sellers to find closure.
As a kind of the unrelated follow-up. In Guyana, the big discovery, is there any sort of timeline at all we can be thinking about at this point for the next appraisal well, and then if that goes, how we should think about some of the other things, including the, I guess, border dispute with Venezuela, et cetera?
Yeah. Well, as I said, we're certainly very encouraged by the first well. It is one well in a very large block. We are currently evaluating that well and we're laying out the, if you will, the plans moving forward. You can expect the intent for us to not only further appraise the discovery, but to pursue other opportunities on the block. I want to be clear though, that we follow all the laws within the host countries and international law that we're operating on this block under license from the government of Guyana. The border matters are really a function or should stay with the governments to address through appropriate channels.
Thank you.
Okay.
We'll go next to Ryan Todd with Deutsche Bank.
Great. Thanks. Jeff, maybe if I could, one follow-up on cost. I know you've talked about cost control efforts a couple of times already, but maybe not on the CapEx side, but if we look on the OpEx side or the expense side within the company. A lot of your competitors have talked about percentages in terms of year-on-year decreases in OpEx or targets in terms of absolute numbers that they think they can pull out of the business. Any guidance you can give us in terms of maybe where your cost structure might be year-on-year, or how much you think you might be able to pull out on a relative to 2014 basis?
Obviously our objective is to make sure that we're capturing all those opportunities, both structural and market out there, and at the same time ensuring that we maintain the high integrity of our operations. I think, Ryan, the ultimate measure here is our industry leading unit cost performance that we've seen over the last several years. While it's still early, I don't want to go too far with this. We are seeing the unit cost on a downward trend year to date almost 9% down from where we were last year. That's about as far as I'll quantify at this point. Obviously, this is a key element to ensuring that we remain a leader in unit profitability as well.
Great. Thank you. Maybe one question on LNG and thoughts around the business. We've had a number of questions on spot pricing and trends, if you look at, you've got a decent queue of potential development projects that could happen at some point over time. Can you talk about maybe what would be the threshold that you would need to move forward on some of these projects? Is it local permitting? Is it an effort on reducing costs in the industry and getting costs down to a place that's competitive? Is it a wide bid-ask spread between buyers and sellers right now? Any thoughts in general, I guess, on your asset portfolio on LNG on the development side and what you're seeing in the market?
Sure. Broadly speaking, as you know LNG is a key component of our portfolio, it's an important part of our margin generation. As I said earlier, we've got a very good inventory and including in that inventory is a number of LNG projects. It's all based on our assessment, as I indicated, that gas will grow by about 1.6% per year between now and 2040. More specifically, LNG demand will triple from 2010 to 2040. That is the value proposition we're pursuing. We've got a number of projects moving forward concurrently. We're going to be very selective in what we invest in. To your question about what does it take to make it go forward? It's all the things you mentioned. It's making sure that we get a competitive cost structure, that we've got stable, transparent fiscal terms to underpin a very capital-intensive investment.
That's why we're progressing several of them at the same time. I would tell you that the brownfield type expansions are probably going to be the lowest cost LNG add. By way of example, our Papua New Guinea project, just a phenomenal outcome. Started up ahead of schedule. Very good reliability. Very well positioned to compete in expansion should we identify sufficient resource. Having the assets that we have in the U.S. positions us very well. Alaska, West Coast of Canada continue to progress. Those opportunities will require more of what we were talking about in terms of cost, in terms of fiscal terms, regulatory environment. In short, what I'd say, Ryan, is that the demand projection's there. Obviously we've got the capability to participate in that, and we're very well positioned with a very good inventory of high quality opportunities to meet that demand growth.
Okay. Thanks, Jeff.
We'll go next to Brad Heffern with RBC Capital Markets.
Morning, Jeff.
Good morning, Brad.
Looking at the downstream business, there have been a lot of press reports and/or regulatory filings about a potential substantial expansion of Beaumont. I was wondering if you could comment on that, provide any color around the thinking there.
Just again, taking a portfolio look, Brad, we regularly evaluate our assets, our various business lines for where we can grow earnings or optimize the long-term value of it. In the downstream business, it's focused in the following areas: expanding our logistics, expanding our feedstock, reducing our overall cost structure, and importantly, increasing high-value product yields. You'll see that one of those areas or one or more of those areas will underpin the investment projects that we have communicated have been through FID, such as the Antwerp investment. As it pertains to Beaumont, we typically assess those activities. I understand that may include some discussions with regulators. It doesn't indicate that we've made a decision. When we get close to an FID and we've made that decision, we'll communicate that accordingly.
Understood. Looking in California on the upstream side, I was curious what the impact during the quarter was given the Plains pipeline downtime and what the outlook is there.
Yeah. Good question, Ryan. As you all know the Plains All American Pipeline was down due to a failure of the line in the second quarter. We've looked for options to go ahead and keep our facility on without that pipeline running or until we're able to find an alternative export route. SYU will be shut down. Before it was shut down, it was producing somewhere around 30,000 barrels a day. In fact, that was a 2014 number. We'll keep focused on it. We'll keep working with the regulator as well as the All American Pipeline to identify the earliest restart.
Okay. Thank you.
We'll go next to Anish Kapadia with Tudor, Pickering, Holt & Co.
Hi. First question is just looking at some of the growth projects again for post 2018. It seems to me like you're focused on three key areas or themes, if you like, which are getting a bit more challenged over the next few years. When you look at international LNG, seems to be a lot more competition coming in from domestic U.S. LNG. When you look at your Oil Sands projects, they're relatively high cost, impacted by potential carbon pricing and higher taxes coming through. Nigeria, clearly a difficult political environment there and tax uncertainty. Just wondering, given those are your key areas, how comfortable are you with those areas and the potential growth there?
Anish, we're in the risk management business. Everything that we do has a level of risk that we've got to judge, whether it be geopolitical risk, economic risk, technical uncertainty, and that is the world we live in. I think the organization has demonstrated over the years that it's got the expertise and the capability to take on these more challenging resources and convert them into value propositions for our shareholders. The areas you talked about, take a look at Papua New Guinea LNG. No infrastructure. We were able to build that into a very successful project that's going to supply an important part of LNG demand in the future. We have a good track record in all these areas. We're very good at capturing the learnings and transporting those learnings into our future resource development activities to make sure that we maximize return.
As I said to Paul earlier, if we don't see the value proposition there, we will find other ways to monetize that asset.
Okay, great. Just to follow on, in terms of your future projects, I'm just thinking, how do you think about delaying projects in an attempt to, in this kind of falling kind of service price environment, to capture lower prices? Is that something that you're actively kind of looking to do, or will you just go ahead with the project if it kind of makes sense in terms of the economics at the moment?
Well, remember, these projects that you referenced earlier are multi-year projects. They happen over a period of time, we are looking for not only the market savings, but I'll stress again, the structural savings. Let me use an example of what I'm talking about. We went forward with both the Arkutun-Dagi and the Hebron developments concurrently because we saw a very consistent development option and the tremendous benefit that we'd get by learning curve advantages. Both GBS, we used a comparable design shop for both of them. We used the same GBS contractor. We used the same topside contractor, and we captured that immediate learning curve benefit. On top of that, in a lower price cycle, as I said earlier, we're very well-positioned with the global procurement organization to be first in line in capturing those market savings.
Given our long-term investment and our expectation of what demand's going to do, we're very confident that the things we're investing in today, some of them we won't see production on for five or 10 years. We're very confident in our demand projections and our ability to turn that into accretive financial performance.
Understood. Thank you.
Our next question comes from Paul Sankey with Wolfe Research.
Hi, Jeff.
Morning, Paul.
Jeff, when I hear what you're saying about costs and potential M&A, and knowing what you've said in the past about the Permian, it feels like that's the best opportunity for you to combine the overlap that you have with the potential to drive out costs. I think you've highlighted that it's a very fragmented zone. I would also think that the Bakken is similar, but you really don't have a lot in the Eagle Ford. My assumption is that essentially the Permian would be the most attractive place for you and then the Bakken to take advantage of this low price environment. Thanks.
Yeah, Paul. Just broadly speaking, we keep focused globally, and we've got those type of opportunities in other countries that we'll naturally maintain a line of sight on should the right value proposition come forward. If you want to focus in the unconventionals, certainly, the ownership structure in the Permian, by way of example, is very diverse. Where we can find natural synergies, over the last several years, we've made a number of bolt-on acquisitions that have increased our position there, and you get value uplift when we're able to do that where it's within our operational structure.
Yeah, I guess the operational structure is well-suited because of the XTO separate division you have gives you the flexibility.
That's correct.
One thing I'm worried about, Jeff, is reserves replacement, just insofar as I don't think you've had any FIDs this year. I also noticed that your reserves booking last year were heavily dominated by the U.S. Could you update us on where we stand as regards reserves replacement? Thanks.
Yeah. Well, obviously, that's an annual process, and we've fully replaced our production for 21 straight years. We've got a very good inventory that we're working on to convert to an FID decision in proved reserves, as well as a very active exploration program. We've been very successful as the history shows, and I'd say that the prognosis in the future will remain the same.
Jeff, do you know how many FIDs you had last year?
Not off the top of my head, Paul. No.
I'll leave it there. Thanks, Jeff. Thank you.
Thanks, Paul.
We'll go next to Alastair Syme with Citi.
Hi, Jeff. Thanks for your comments on operating costs earlier. Can you give some sort of magnitude about how much of that 9% you might feel is natural deflation in the environment, like energy prices? How much is your own cost management?
Alastair, I'd just tell you that the organization wants to keep focused on the structural improvements as well as that market capture. Everything is under focus constantly, even when we're at $100 per barrel. I don't have any specific numbers to break out on the benefit to date.
Okay. Secondly, in the chemicals business, in this environment, you see much difference in the profitability between the base and derivative businesses?
Remember, it's all premised under very strong demand growth. Our investments are strategically placed in order to make sure that we can compete competitively over that timeframe. I think we're very well positioned in both the commodity and specialties markets.
Okay. Thank you very much.
We'll go next to Guy Baber with Simmons & Company.
Good morning, Jeff, thanks for fitting me in here.
You bet, Guy.
Jeff, you highlighted on slide 18, Lower 48 onshore F&D costs, best in class by a substantial margin. I believe those costs have been declining in recent years as well and likely continue to decline. I was just wondering if you could discuss how that positive trend for U.S. Lower 48 F&D compares to the trends that you are seeing internationally and that you've seen in recent years, where it appears F&D for the industry has risen considerably in some cases. Can you just discuss your thoughts on that divergence, what you're seeing, and also how that might influence capital allocation and strategy long term? Specifically, does it lead you to believe you need to find a way to allocate more capital to the regions where you can most efficiently add reserves, which appears to be the U.S.?
I think that's an excellent question, Guy, because I think this is just one example of what we do across our whole global portfolio. I talked about, by way of another example, we've shown you the XTO example. In my prepared comments, I talked about Erha North, the phase 2. Last quarter, I talked about the start-up of Kizomba Satellites, phase 2. That's another really good example that we sequence the resource development in a manner that we can fully leverage the fixed investment over a period of time. What that does is that lowers our overall cost structure, our E&D costs globally. In a deepwater environment where we've got to be very careful that we've got very good execution plans and that we execute flawlessly.
It's a very strong focus across the world, whether it's in the deepwater with the Kizomba Satellites phase 2 and Erha North phase 2, or we're talking about the Arctic or sub-Arctic, like in Arkutun-Dagi and Hebron. There is an ongoing emphasis to try to get that cost structure down. That's why I made the point earlier that this is something that we have to work 365 days a year. It's not something that's driven by the price environment. It's driven by the need to be ever more productive and to compete in a market that there's a lot of investment dollars going in. We keep line of sight on where we've got cost opportunities.
Thanks, Jeff. Last one from me. Liquids production up 12% on the year, obviously very impressive growth. Major projects ramping up. You get some PSC benefit, obviously, but also appears like you're showing growth in some areas where you don't have high-profile major projects, North Sea Oil, for example. It appears that reliability uptime may be improving just across the portfolio. Is that an accurate observation? Is there any detail you can provide of how the base level of production is performing, perhaps relative to expectations coming into the year? Because it seems to be doing better.
Yeah, it's another good question. You may recall back in the analyst presentation, we spent a little bit of time. The chairman showed a chart that goes to quantify the volume add that we make with our focus on reliability. We are making very significant gains on improving overall operating reliability. I'll emphasize not only in the upstream, but also across our manufacturing business as well. As we focus intensely on cost structure, we do the same on uptime and reliability. Really try to transfer those learnings quickly across the corporation to make sure that, once again, we're best in class.
Thanks, Jeff.
You bet.
Our final question for today comes from John Herrlin with Société Générale.
Yeah, thank you. Most things have been asked, Jeff, but you've seen a lot of your IOC peers, as well as some large cap E&Ps, take significant impairments. You have a very robust resource base as you've stated. Are there any issues for, say, intermediate term projects coming off the books on a long-term basis for Exxon?
Well, there's two parts to your question. One is, if we've got resources that are in a resource base that ultimately we don't see the long-term value, as I indicated earlier, John, we will look for ways to monetize them, which may include some level of divestment. In terms specifically of impairments, as you know, we live in a commodity price environment that has great volatility. As I've said several times in our interview, outlook, the longer term market fundamentals remain unchanged. The lifespan of our assets are measured really in decades. Therefore, long-term price views are more stable and, quite frankly, more meaningful for future cash flows and market value. We expect the business to more than recover the carrying value of the assets on the books.
Obviously, in the course of our ongoing asset management efforts, we do confirm that asset values fully cover carrying costs.
Great. That's what I wanted to hear. One last one from me, which you probably won't answer. Guyana insignificant. You want to attach a volume size to that?
John, I think it's just too early. I look forward to that time that I can have more discussion about it as well. As I said, John, one well in a 6.6 million acre block, it's a very good start. Just watch that space. There's more to be said there, I think.
Thanks very much, Jeff.
You bet, John.
With no further questions in the queue, I'd like to turn the call back to our host for any additional or closing remarks.
To conclude, again, I want to thank you for your time and your very thoughtful and insightful questions this morning. We appreciate the opportunity to talk about the business and really share the successes of our people that work day in and day out to make sure that we're creating shareholder value. Thanks again, and we look forward to further discussion in the future.
Ladies and gentlemen, that does conclude today's call. Thank you all for joining.