Please stand by. We are about to begin. Good day, everyone, and welcome to this ExxonMobil Corporation second quarter 2017 earnings call. Today's call is being recorded. At this time, I'd like to turn the call over to Vice President of Investor Relations and Secretary, Mr. Jeff Woodbury. Please go ahead, sir.
Thank you. Ladies and gentlemen, good morning, and welcome to ExxonMobil second quarter earnings call. My comments this morning will refer to the slides that are available through the Investors section of our website. Before we go further, I'd like to draw your attention to our cautionary statement shown on slide two. Turning now to slide three. Let me begin by summarizing the key headlines of our second quarter performance. ExxonMobil earned $3.4 billion in the quarter, bringing year-to-date cumulative earnings to $7.4 billion. First and foremost, we remain focused on business fundamentals. That is operational integrity, costs, reliability, and disciplined investment with the objective of growing value regardless of the commodity price environment. Cash flow from operations and asset sales exceeded dividends and net investments in the business for the third consecutive quarter.
We continue to advance key projects across the value chain for strategic growth, some of which I'll highlight later. In the downstream and chemical segments, we're investing to meet growing demand for higher value specialty and differentiated commodity products across the globe. Moving to slide four, we provide an overview of some of the external factors affecting our results. Global economy maintained modest growth in the second quarter. In the U.S. and China, economic expansion accelerated compared to the previous quarter, while Japan and the Eurozone experienced steady growth rates. As you know, the commodity price environment weakened in the quarter as both crude oil and natural gas prices decreased. Nonetheless, the global rig count increased, driven primarily by higher North American activity, compounding uncertainty in future supply-demand balances. Refining margins improved with heavy industry maintenance and the change to summer gasoline specifications.
Global chemical commodity margins showed signs of softening with new industry capacity coming online as anticipated. Turning now to the financial results as shown on slide five. As indicated, ExxonMobil second-quarter earnings were $3.4 billion, or $0.78 per share. In the quarter, the corporation distributed $3.3 billion in dividends to our shareholders. CapEx was $3.9 billion, down 24% from the prior year period as the corporation remains disciplined in its investment plans while delivering best-in-class execution. Cash flow from operations and asset sales was $7.1 billion, and at the end of the quarter, cash totaled $4 billion, and debt was $41.9 billion, down $1.7 billion from the prior quarter. The next slide provides additional detail on sources and uses of cash. Over the quarter, cash balances decreased from $4.9 billion to $4 billion.
Earnings adjusted for depreciation expense, changes in working capital and other items in our ongoing asset management program yielded $7.1 billion of cash flow from operations and asset sales. Uses of cash included shareholder distributions of $3.3 billion and net investments in the business of $3 billion. Debt reduction in other financing items decreased cash by $1.7 billion. Cash flow from operations and asset sales more than covered dividends and net investments with an excess of nearly $800 million. In the second quarter, ExxonMobil did not make any share repurchases to offset dilution related to our benefit plans and programs, and we don't currently plan on making additional purchases to reduce shares outstanding in the third quarter. Moving on to slide seven for a review of our segmented results.
ExxonMobil second-quarter earnings increased $1.7 billion from a year ago quarter, driven by stronger upstream and downstream results and lower corporate charges due to one-time favorable tax items. In the sequential quarter comparison shown on slide eight, earnings decreased $660 million due to weaker results from the upstream and chemical segments. This was partly offset by lower corporate charges due to one-time favorable tax items and stronger downstream performance. On average, we expect corporate and financing expenses will continue to be between $400 million-$600 million per quarter in the near term. I'll note that our corporate effective tax rate for the quarter was 31%, down from 40% a year ago, reflecting changes in our segment earnings mix and other one-time items. Turning now to the upstream financial and operating results, starting on slide nine.
Second quarter upstream earnings were $1.2 billion, an increase of nearly $900 million from the prior year quarter due to higher realizations. Crude prices rose about $3.50 per barrel versus a year ago quarter, and gas realizations increased more than $1 per thousand cubic feet. Volume and mix effects decreased earnings by $140 million, largely because of sales timing and lower entitlements. Compared to the second quarter of 2016, we had a net underlift of more than 150,000 barrels per day. All other items increased earnings, $140 million, driven by lower operating expenses. Upstream unit profitability for the quarter was $3.41 per barrel, excluding the impact of non-controlling interest volumes. Moving to slide 10. Oil-equivalent production in the quarter was 3.9 million barrels per day, a decrease of nearly 1% compared to the second quarter of 2016.
Liquids production was down 61,000 barrels per day as new project volumes and buildup from work programs were more than offset by field decline and lower entitlements. Natural gas production increased to 158 million cubic feet per day as volumes from new projects and work program more than offset field decline, lower seasonal demand, and regulatory impacts in the Netherlands. Turning now to the sequential comparison starting on slide 11. Upstream earnings were $1.1 billion less than in the first quarter of the year, as lower realizations for both liquids and gas reduced earnings by $390 million. Crude prices decreased more than $3 per barrel, and natural gas fell $0.29 per thousand cubic feet. Volume and mix effects decreased earnings another $250 million. Negative sales timing effects, reduced demand, and increased downtime were partly offset by new project volumes. All other items further decreased earnings by $430 million.
This is largely the result of asset management activity and higher operating expenses. Asset management impacts included our relinquishment of East Natuna, located offshore Indonesia, as we continue to high-grade our portfolio. Moving to slide 12. Sequentially, volumes decreased 5.5% or 229,000 oil equivalent barrels per day. Liquids production decreased 64,000 barrels per day, driven by higher downtime. Natural gas production decreased 988 million cubic feet per day as seasonal demand dropped significantly but were partly offset by new project volumes and work program. Moving now to downstream financial and operating results starting on slide 13. Downstream earnings for the quarter were $1.4 billion, up $560 million compared to the second quarter of 2016. Stronger margins increased earnings by $220 million. Favorable volume and mix effects improved earnings by $90 million, mainly from lower planned maintenance, which resulted in higher throughput.
All other items added $250 million, mostly from ongoing asset management activities, favorable foreign exchange effects, and lower turnaround costs. Turning to slide 14. Downstream earnings increased sequentially by $269 million. Stronger margins increased earnings by $200 million. Volume and mix effects improved earnings by $40 million, primarily driven by increased fuel sales. All other items further increased earnings by $30 million. Moving now to chemical financial and operating results starting on slide 15. Second quarter chemical earnings were $985 million, down $232 million compared to the prior year quarter. Weaker commodity margins decreased earnings by $40 million. Lower commodity volumes reduced earnings by $50 million. All other items decreased earnings by $140 million, largely due to increased turnaround expenses and unfavorable foreign exchange effects. Moving to slide 16. Chemical earnings decreased sequentially by $186 million.
Weaker commodity margins reduced earnings by $100 million. All other items decreased earnings $90 million, primarily from increased turnaround and project-related expenses. Turning to slide 17 and a review of our upstream business highlights. We continued to capture new high-quality acreage with recent portfolio additions offshore Australia Equatorial Guinea and Suriname. ExxonMobil will be the operator of each of these new blocks, with total over 3.5 million gross acres. While appraising the Muruk discovery in Papua New Guinea, we confirmed the presence of a second gas-bearing fault block. Production testing confirmed good quality reservoir with high deliverability. Further appraisal is needed to delineate this resource, but this discovery has helped to de-risk several other leads on trend with the fields in this area. In June, we successfully completed the tow out and installation of the Hebron platform located offshore eastern Canada.
The 750,000 ton platform was towed over 350 kilometers from the Bull Arm construction site to the Hebron field in the Jeanne d'Arc Basin. Facility is capable of producing 150,000 barrels per day, with a total estimated recovery of more than 700 million barrels of oil. Commissioning work is progressing and drilling began this month. The field is expected to start up before year-end. The Odoptu Stage 2 project also remains on track for first oil by year-end. A major milestone was achieved in June when the final facility modules arrived on Sakhalin Island. Turning now to slide 18, we continue to make strong progress in the greater Guyana-Suriname region. We recently announced the signing of a production sharing contract for Block 59 offshore Suriname. The 2.8 million acre block will be operated by ExxonMobil with co-ventures Hess and Statoil.
Block 59 is in deep water, located approximately 190 miles in the Guyana-Suriname Basin. We look forward to leveraging our regional knowledge to help evaluate the block's potential. In Guyana, we're currently acquiring a large 3D seismic survey over the Kaieteur Block to assess resource potential. Also, the rig is currently on the Payara-2 delineation well, and initial results are encouraging. We've encountered nearly 60 feet of high-quality oil-bearing sandstone, deeper than the previous lowest known oil in the first Payara well. This brings the total Payara discovery to about 500 million oil equivalent barrels. As a result, total gross recoverable resources on Stabroek Block are now estimated at 2.3 billion-2.8 billion oil equivalent barrels. This higher estimate is driven by the results of Payara-2 and the previous Liza-4 well, which encountered more than 197 feet of high-quality oil-bearing sandstone reservoir.
Rig will next move to drill the Turbot and then Ranger prospects. These two prospects represent new play tests on the Stabroek Block. Moving to slide 19 and still in Guyana, we reached final investment decision on phase 1 of the Liza development. First oil is expected by 2020, less than five years after the initial discovery. Phase 1 will develop 450 million barrels of oil from a floating production, storage, and offloading vessel with production capacity of 120,000 barrels per day. This development is expected to cost $4.4 billion, resulting in a unit development cost of less than $10 per barrel and a projected double-digit return even in a flat $40 per barrel price environment. Combination of high resource quality and proven execution capabilities applied in today's lower cost environment positions Liza for success.
Development planning for a second phase has also progressed following the recent success at Liza-4, which confirms significant additional resources to underpin future phases. Successful well test of Liza-4 confirmed the anticipated superior well deliverability expected from this high-quality reservoir. We are certainly excited about the tremendous potential at Liza, Payara, and the greater Guyana Basin, and we look forward to working with the government and, of course, the people of Guyana in the years to come to develop this world-class asset. Moving to slide 20 for an update on our Permian development. ExxonMobil's Permian assets rank among the top tier investment returns in our global portfolio. Strong drilling and completion execution in the middle of basin has to date yielded unit development costs of about $7 per oil equivalent barrel.
We've been steadily increasing our Permian drilling activity through 2017, and our current net production is more than 165,000 oil equivalent barrels per day, an increase of 20% from the prior year quarter. Despite growing industry activity in the Permian, we have successfully offset inflationary pressure through increased efficiencies and higher recoveries per well, and this includes, amongst other factors, a continuing reduction in drilling days and cost per foot, as well as further improvement in completion designs. We currently have 16 operated rigs in the Delaware and Midland basins combined and expect to reach 19 total rigs by the end of August. Specifically in the Delaware Basin, we just finished drilling our first operated well on the recently acquired acreage. This well has a lateral section of 12,500 feet, well above the industry average.
As we further progress development and gain additional learning curve benefits, we anticipate extending lateral lengths, including leveraging our learnings from our recent completion of Bakken horizontal wells of over three miles. Our superior, highly contiguous acreage position in the Delaware Basin uniquely positions us to exploit longer laterals and drive down unit development costs. We also continue to optimize our logistics and infrastructure plans, including export capacity, gas gathering, and water handling. For example, ExxonMobil recently executed an agreement for Summit Midstream Partners to develop, own, and operate a new associated gas gathering and processing system servicing the northern Delaware Basin. We're pleased with our progress to date and anticipate that as activity continues to ramp up, we will continue capturing efficiencies. Our estimated unit development cost for the full northern Delaware acreage is $5 to $7 per oil equivalent barrel.
Turning to slide 21 in our downstream and chemical business highlights. We continue to strengthen our portfolio by increasing feedstock and logistics flexibility, upgrading the value of hydrocarbon molecules, and expanding volumes of premium products. In May, we reached mechanical completion of two new 650,000 ton per year polyethylene lines at our plant in Mont Belvieu, Texas. The company expects production to begin during the third quarter of this year. Building on the success of our Gulf Coast initiatives, the corporation also continues to advance new opportunities to meet growing demand for ethylene and related products. We recently selected a site in South Texas for our proposed joint venture with SABIC to construct a world-scale petrochemical complex, including an ethane steam cracker and a monoethylene glycol unit and two polyethylene units.
In May, the venture partners signed an agreement for the next phase of the project, which enables planning for front-end engineering and design work. Recognizing that Asia Pacific continues to be the largest and fastest growing lubes market globally, we recently completed the expansion of our grease and synthetic lubricants operations in Singapore. The new synthetic lubricants plant is the only facility in the region that can manufacture Mobil 1. We're also increasing our basestock capacity in Asia with a further expansion of our Group II production in Singapore. This value-driven investment underpins our continued leadership in basestock production. In the quarter, ExxonMobil also announced its plans to enter the Mexican fuel market with Mobil branded stations and its advanced Synergy gasoline and diesel fuels.
Local partnerships, we plan to open our first Mobil service station in central Mexico during the second half of 2017, with additional stations to follow by year-end. We plan to invest about $300 million in fuels logistics, product inventories, and marketing over the next 10 years to provide a reliable supply of quality products to retail, wholesale, industrial, and commercial sectors. Finally, we continue to invest in research and development to position our long-term success. ExxonMobil and Synthetic Genomics have jointly researched biofuels for over eight years and recently announced a breakthrough involving the modification of an algae strain that more than doubled its oil production. We are pleased to have achieved this important milestone and will continue to progress the potential commercial application over the longer term. Turning to slide 22. We're also progressing a strategic acquisition in Singapore to grow our chemical capacity to meet increasing Asian product demand.
ExxonMobil signed an agreement with Jurong Aromatics Corporation to acquire its plant located on Jurong Island in Singapore. This aromatics plant is one of the largest in the world with an annual production capacity of 1.4 million tons and also produces 65,000 barrels per day of fuels. Integration of this plant with ExxonMobil's existing manufacturing facility will provide product, operational, and logistical synergies that will enable cost-competitive growth of the aromatics business. As you may know, Singapore is home to ExxonMobil's largest integrated refining and petrochemical complex and has a crude oil processing capacity of almost 600,000 barrels per day and includes two world-scale steam crackers with a capacity of 1.9 million tons per annum. Acquisition of the Jurong Aromatics plant will increase ExxonMobil's Singapore aromatics production to over three and a half million tons per year, of which 1.8 million tons is paraxylene used in polyester production.
We're looking forward to closing this acquisition in the second half of this year. Turning now to slide 23. A summary of the corporation's year-to-date sources and uses of cash highlights our ability to meet our financial objectives and commitment to our shareholders. As shown, year-to-date 2017 cash flow from operations and asset sales of $16 billion funded shareholder distributions, net investments in the business, and a reduction in debt. Following the most recent drop in commercial prices, this is the third consecutive quarter where our free cash flow has exceeded our dividends to shareholders, reflecting capital discipline and the strength of the integrated businesses. I'll note that the cash operating surplus in the second quarter is after covering a seasonal working capital build. Moving now to the final slide. I'll conclude today's presentation with a summary of our year-to-date performance.
Simply put, we remain focused on value growth through self-help and attractive investments. Our integrated businesses continue to generate solid cash flow and earnings. Our business segments collectively earned $7.4 billion, an increase of nearly $4 billion compared to the first half of 2016. Upstream production volumes were consistent with plans at four million oil equivalent barrels per day. We remain disciplined in our investment program, selectively advancing strategic opportunities across the value chain while maintaining focus on capital efficiencies. Year-to-date CapEx was $8.1 billion, a decrease of 21% from the prior year. Our capital guidance for 2017 remains at $22 billion, as we previously shared. Cash flow from operations and asset sales totaled $16 billion, and free cash flow was $8.5 billion, more than covering $6.4 billion in shareholder distributions.
Of the strength of our integrated businesses, we remain confident in ExxonMobil's ability to continue delivering long-term value to our shareholders in ever-changing industry conditions. That concludes my prepared remarks. I would now be very 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 1 on your touch tone 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're 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 telephone keypad to ask a question. We'll go first to Neil Mehta of Goldman Sachs.
Hi, Jeff. How are you?
Good morning, Neil. I'm doing fine, thank you.
Jeff, I asked you this question last quarter, but I always value your opinion on the oil macro. Just wanted to get ExxonMobil's perspective as a buyer of 5 million barrels a day of crude, of where you think we are in the rebalancing process, and how you see the macro playing out going forward.
Thanks, Neil. Let me just give you some observations. On the positive side, clearly demand continues to be relatively strong when you compare it against the 10-year average. Likely to see demand growth of about 1.5 million barrels this year. We are seeing some inventories, commercial inventories draw, both on crude as well as products. Still quite a bit of inventory to go ahead and draw down. Of course, on the opposite side, working against the balance is that we are seeing a significant build in production in several places, notably in North America. Right now, pretty much on trend to reach about an additional million barrels a day capacity growth over the last, say, 12-18 months by year-end. That's going to work against us in some regards. Of course, how other non-OPEC producers perform over the near term will have an effect.
When you put all that together, you are seeing convergence of supply and demand in the second half of 2017. That will probably spread out again as demand drops in the first half of 2018. I think I'd summarize by saying that we are seeing some progress towards a healthier balance. As I indicated, there are a lot of variables in play.
I appreciate those comments. The follow-up is on gas. You have a lot of optionality on global gas. You have PNG with the InterOil acquisition, Mozambique, and there's talk about the potential for expansion in Qatar. Can you just comment on each of the three opportunities, and then how Exxon's thinking about prioritizing the different options you might have here?
Well, as you said, Neal, we do have a lot of optionality here. As part of our diverse resource base, we've got a very large presence in gas. We see gas, as you may recall from our energy outlook, growing about 1.5% per year between now and 2040. That really sets up the investment basis. We're progressing all of these opportunities forward. As you can appreciate, there are a lot of variables that will determine the pace. Some of these will likely move quicker than others. When you think about the full spectrum of the portfolio, those that are what I would characterize as brownfield expansions of existing operations are probably going to have some of the lowest cost of supply. I'd note specifically Papua New Guinea, where we have built up a very substantial resource base.
Starting with the foundation project that has exceeded the original scope in terms of offtake and total resource to the success of our exploration program and the, as you know, the acquisition of the InterOil assets. That positions us very well to expand that facility. I'd suggest that that's going to be on the left side of the cost of supply curve. To some other very large resources, like the acquisition we're pursuing in Mozambique, that are also going to be very competitive on a cost of supply, as well as our continued interest in supporting the objective of our partners in Qatar, which we take a lot of pride in supporting their ultimate plans for the North Field.
Thanks, Jeff.
We'll now take our next question from Doug Leggate of Bank of America.
Hi. Good morning, Jeff. Can you hear me okay?
Yeah, I can, Doug. Good morning.
Thanks. A couple of things, maybe two questions if I may. The first one is on volumes in the second quarter. Is there anything unusual going on in Europe? I know that production is typically seasonally weak anyway, but it just looks down about 20% year-over-year, looks unusually low. Related, I guess, Canada volumes, oil volumes, were down also, and I'm guessing that's maintenance. Can you just speak to some of the moving parts in the quarter? Because obviously internationally in production seemed weak, and we're just trying to get a handle on whether there's something changing here which has some leaks or if it's really just one-offs and seasonality. I've got a follow-up, please.
Yeah. Well, thanks for the question, Doug. You're right, we are pretty low in the second quarter, and there are a couple drivers for that. As I said in my prepared comments, we saw a pretty significant downtime in a couple of regions. One being Canada, as you highlighted. We had a turnaround in Kearl. We also, as has been pretty well-publicized, Syncrude has been down. We expect Syncrude to ramp up to full capacity by August. Staying on the liquids side, we had some downtime in Nigeria and West Africa as well. Second quarter tends to have a lot more of our planned maintenance activities in the upstream. On the gas side, one of the biggest drops was the reduction in the European gas demand. Of course, that is seasonal in nature.
On top of that, as I said in my prepared comments, there are still some impacts associated with the regulatory restrictions at Groningen. On the positive side, I think it's important to highlight that we've had some really significant builds in some of these projects that have come on. Really good progress in places like Upper Zakum, Kashagan. We continue to ramp up some of our additional projects that started up over the last one or two years. The last negative I'd highlight, which is real clear on the chart, is that there was a significant liquids decrease associated with entitlement volumes, which, as you know, is really a price-driven impact.
Okay. I appreciate the lengthy answer. Thanks. I guess my follow-up, I realize you just reiterated the spending guidance for the year, Jeff, but realistically, you're running very light at the half-year level. Even with back-end loaded spending, the number still looks a little bit aggressive in the back end. Can you just speak to that in terms of are you just really being conservative here, or do you really expect that significant ramp-up in the run rate spending in the second half of the year? I'll leave it there. Thanks.
Yeah. Thank you, Doug. I can certainly appreciate that view. We are spending lower on a, if you will, on a seasonalized basis. I bucket them in really two categories. One being timing related, and the second one being that the organization has continued to make significant efforts to capture new efficiencies. We are seeing those capital efficiencies in that performance. On the timing side, we got a couple of things that I'll share with you. One, obviously, is we've got two acquisitions that we are working to close by the end of the year, the two being Mozambique and the Jurong Aromatics Corporation acquisition. We also, as I indicated in my prepared comments, we're ramping up our permitting activity as well. Those factors lead us to the view that we want to keep the guidance flat.
In some regards, you can say there's some upward pressure to that, but we've got full confidence in the organization that we'll continue to capture additional savings as we go forward.
Thanks, Jeff.
Thank you.
Our next question will come from Doug Terreson of Evercore ISI.
Good morning, Jeff.
Morning, Doug.
You made a point a few minutes ago about growing value, and several of your peers have become much more focused on return on capital employed during the past year. Besides more disciplined spending, they've increased divestitures, too, to try and realize greater value from their portfolios. Because returns for all companies have declined over the past couple of years, and because you pulled this lever slightly less than your peers over time, not a ton less, but slightly less. My question is, how do you guys think about the opportunity for value creation from this mechanism? Meaning it's not new, but are there reasons to step up or not step up your program at this time, given the current environment where assets are starting to pretty freely trade hands?
Yeah. Doug, just a couple thoughts to share with you on that regard. First, I'd also say that we have had a continual asset management program, and we've shared the total value benefit from that in the past.
Yeah.
When you look at that point, for us, it's not a defined, we're going to sell X amount of assets over a defined time frame.
Yeah.
It's an ongoing focus around how do you high-grade the overall portfolio? I can share three key components of doing that. One is clearly identifying new, highly accretive assets that can compete in your portfolio through exploration activity or acquisitions. Then the second one, the last one being that this ongoing program to monetize what we see as assets that may be of greater value to others. If you look at our annual performance on that, we're selling anywhere between $2 billion-$4 billion of assets per year. If you look at, say, over the last five years, that equates to about over $20 billion from those asset sales. We maintain a very active program.
Right.
This is not a fire ship sale. This is all about the fundamental objective of this corporation is to grow value, and the decisions are value-based. If we see that we can get that value through monetizing it through a sale, we'll go ahead and proceed with it. We like the portfolio. We've been very successful in ensuring that there's a constant high grading of that portfolio. I want to talk about the broader comment about return on capital employed.
Yeah.
The fundamental objective of our investment program is to be very selective on how we can grow our value proposition, ultimately that will evidence itself in the return on capital employed. If you think about from the upstream through the downstream and chemicals, it's all about that value chain investment to provide accretive financial performance. Very strong discipline, and we've never lost our view on that.
Okay. Also, Jeff, the downstream has historically been an area of industry leadership for ExxonMobil, needless to say, it still is. In this area, your results seem to have lagged your peers during the past 6-12 months. Again, not a ton, but there seems to be a little leakage. My question is whether or not you had any insight into this outcome, not so much from a return on capital perspective, which is probably explained by changes in pre-productive capital with your new projects. Is there anything from a margin or earnings perspective or anything else that might be worth mentioning about the downstream performance?
The only thing I would share with you on that, Doug, that again, I'm not sure what your reference point is.
Yeah
We did have a fairly heavy maintenance period in the first half of the year.
Okay.
I think we completed about 85% of our overall planned maintenance in the first six months of the year. I will focus also on the very strategic investments that we're making throughout the downstream that is a good example of how we're not necessarily growing volume, but we're growing value. Where we're going ahead and upgrading lower value products like marine fuel oil to higher value products like ultra-low sulfur diesel or lube basestocks. Specific projects, Antwerp is doing that. Rotterdam is doing that using proprietary technology. Should take us to the largest Group II basestock producer in Europe. It really demonstrates how the investment is very focused, very strategic, and all underpins that value proposition.
Okay. Thanks a lot, Jeff.
Thank you, Doug.
We will now move next to Sam Margolin of Cowen and Company.
Hey, Jeff. How are you?
Morning.
I guess we'll start with Liza, just because it sounds like there's been some developments there. As the Recoverable resource reserve gets bigger and bigger. Are there any other factors in place with the development that might be changing? Is this project getting more complicated or less complicated as you're building economies of scale? Just curious about your thoughts around development impacts of the resource increasing and ongoing discoveries.
Well, the short answer is we really like what we've got, Sam, and we've got significant scope to continue to increase the resource. You can see, we've grown the acreage substantially to, I think, about 14 million gross acres now with the additional pickup of Suriname. Yes, clearly, you can see the model that we've employed here is that we're trying to get production or a revenue stream on pretty quick through this leased FPSO approach. Five years from discovery to startup is industry leading. At the same time, we're continuing to maintain the ongoing exploration and appraisal program. That is, as you've seen in our recent communication, has continued to build the resource base, positioning us for subsequent phases of development.
You can see the analog we've got here with what we did in Angola, Block 15, where we got out there early with a leased FPSO to get a revenue stream on. We maintained our exploration program. We built mass. It allows us to get into a much more of a manufacturing process. We design one template, then we go ahead and build that template throughout the development of the resource. That allows us ultimately to make this value proposition that I talked about with Doug previously, drive that unit development cost down, and maximize the results. As I indicated in my prepared comments, very excited about where we are. A lot of activity going on and a lot of scope. This is exactly what we want to be doing right now.
Okay. That's really helpful. Thanks. I guess moving on to Permian, since you're accelerating there currently right now too. You did mention some inflation, but you have offsets with efficiencies and application of some development techniques that you've developed in other areas. Is there any critical mass? Is there any tipping point there? Do you think that you'll continue to be able to beat out these inflationary trends with production technique? Just because it does sound like you're adding rigs and laterals are getting longer. Service intensity does seem to be increasing.
Yeah. Well, clearly, as I indicated previously, we are really trying to keep the organization focused on progressing various structural efficiency savings going forward. It's through, as I said in the prepared comments, it's through some of the execution, it's also driving our unit development costs down. Leveraging the global scale of our organization through our procurement business. We've got that unique structure. We've got the procurement organization that's really focused on driving the cost down over the life cycle of the asset, and have made across the business significant gains. If I back up and talk corporate wide, we are seeing some inflationary pressures. They're very localized on specific services, the organization is fully offsetting those costs as we go forward. Taking it down to Permian, we're being very strategic in terms of our forward development planning and execution.
I mentioned by way of example, we're thinking about the logistical and the supply chain requirements. We're planning out all that, all that effort is driving that unit development cost down and offsetting those inflationary pressures.
Yeah. Thanks so much.
Now we'll go to Paul Sankey of Wolfe Research.
Hi. Good morning, Jeff. Just a quick one. On the buyback, will you continue with the anti-dilutionary buybacks, or is it all suspended?
Yeah. Good morning, Paul. Yes, we will.
Morning, Jeff.
to the extent that we are buying or need to maintain the anti-dilution. Right now, in the quarter, we didn't have any.
Okay. It might continue in Q3?
It's usually a couple I don't remember which months it is, Paul, but it's really tied to our overall benefits plans. It's typically we see it in the first quarter.
Okay. That's good enough, Jeff. Go ahead.
Go ahead. Go ahead, Paul.
I was going to totally change the subject. Could you talk through Mozambique? There's been, obviously, you've made significant moves there, and could you just outline what's going on there? Thank you.
Sure. Mozambique, as I indicated when Neil asked the question, is clearly another big opportunity for us to leverage our capabilities to really go ahead and bring this, what we think is going to be a very competitive cost of supply to market. As we announced earlier this year, we went ahead and executed an agreement with Eni to pick up indirect interest of about 25%. That's a cash transaction that was valued at about $2.8 billion. It is subject to government approvals, and that's what we're working through right now. In that arrangement, ExxonMobil will take responsibility for operating the midstream, which will involve leading the construction and operation onshore facilities.
I will tell you that when we get to that point, once we've gotten the necessary approvals and we are able to close the transaction, we'll get involved, certainly, with all the co-ventures, the government, and even Area 4, to look at or Area 1 to look at how further synergies could be captured, recognizing the potential growth and development in that specific area. I'd say a very large resource. Area 4 contains more than 85 trillion cubic feet in place. We think it's going to compete very well on the left side of that cost of supply curve.
Understood. Just forgive me for asking three, but the situation in Qatar and the announcement from Qatar on expansion. Firstly, how have the sanctions, if in any way, impacted you? Secondly, how would that fit going forward, in terms of the massive expansion that they've announced?
There are no sanctions with Qatar. I think what you're referring to is the diplomatic issues amongst the Middle Eastern countries.
Right. Yeah. Obviously not the U.S. sanctions. Yeah.
Yeah. Simply put, we've not experienced any impacts to LNG production or exports. With respect to the aspirations of Qatar to further expand their LNG capacity, I put it this way, Paul, that as you know, Qatar is a very important partnership for us. We are very proud of the contributions that we made in supporting Qatar's evolution as the, what we believe is the world's largest LNG supplier of LNG. As you look forward, we'll continue to support Qatar. Very interested in future investments, and we're very interested in supporting their stated objectives. Very strong relationship, and I think we're very well-positioned.
Thank you, Jeff.
Thank you, Paul.
We'll now move to Evan Calio of Morgan Stanley.
Hey. Good morning, Jeff.
Morning, Evan.
Yeah. Question on Guyana, where you've had great success. Given the returns, better returns, I presume, at the top of your gating process, how do you think about accelerating subsequent developments to maximize the value of this resource base? Meaning with several phases underpinned Payara, is there a scope for a faster pace of development, than Kizomba, faster than an FPSO every two to three years? What are the thoughts there?
It's a great question, and I think it really talks to the development planning process that we go through. We're doing a lot of this activity in parallel. We took our largest 3D seismic acquisition. We're analyzing that. We're integrating real-time, the drill well data that we're collecting, and we're building that into the process. One of the ways to get that faster pace is being able to put in place a standard template as we go forward and develop these assets. As I indicated in my prepared comments, we're already looking at the subsequent phases in Guyana. To the extent that we can standardize that template, I think it's going to allow us to move quicker. It goes right back to the fundamental objective that we're looking for, and that is, how do we maximize the value for this investment?
We'll certainly keep a very close watch on where we can capture through learning curve benefits, additional capital efficiencies.
It sounds like Kizomba is a good model for now. Is that fair?
Yeah. It was a very successful outcome for the corporation. It certainly demonstrated its value proposition, and it's a good model going forward. Of course, our desire is to continue to see additional success in our exploration program.
Great. The second, in the Permian, there's a chart on slide 20, the chart at the bottom right seems to indicate the potential for up to a 20,000-foot lateral. That's clearly a function of your contiguous position. I also know you guys hold the record in lateral drilling in Sakhalin conventional. Can you talk about plans to test at that length or discuss, is it too early, or could you discuss any technical challenges you see from either completion or equipment perspective? That's a pretty long lateral.
Thanks for the question, Evan. This is in our wheelhouse. It's all about leveraging our technology to achieve these type of aspirational objectives. A couple of data points I give you. One is, as you indicated, we've got very strong success with our drilling execution. We've got a number of execution processes that allows us to fully analyze the physics associated with drilling. That allows us to overcome some of the impediments to be able to achieve those type of outcomes. The second point I make, as I said in my comments, we just finished drilling over three-mile-long Bakken wells. That's allowed us to really inform ourself, and that's all being integrated real time into our ongoing unconventional drilling program, but notably in the Permian. It's a very strong focus on thinking about, what are those limiting factors and how do we push it out even further?
I look forward to hear.
Okay.
We will now go to Phil Gresh of JPMorgan.
Hey, good morning, Jeff. Sorry about that. First question is around the capital spending and the two acquisitions you were talking about. Could you quantify those for me? I know generally what Mozambique is, but if you put the two together, how much of an impact is that on the full year guidance?
Yeah, good morning, Phil. The Mozambique acquisition, as I said, was $2.8 billion. The Jurong Aromatics acquisition, the actual acquisition price has been confidential. It's not been disclosed.
I guess I'm asking a similar question again here, but as I think about your comments about including those numbers in the full year guidance of $22 billion, and you talk about some upward pressure from inflation, I mean, is there also a significant increase in activity level that you're expecting in the second half of the year? I'm just trying to tie out why we'd have such a big increase in the back half.
Yeah, sure. A couple of points that I'll just reiterate. One is we are seeing some very good progress beyond what we had in our business plan in terms of some additional efficiency benefits that we're capturing. There is a lot of timing implications associated with not only the acquisitions in the second half, but we got, as I said, the ramp-up in our Permian activity, but also there's a number of big projects that just the spend profile ends up being a little bit more skewed to the second half of the year, particularly in our development company and our chemical business.
Okay. I guess as we think about the longer-term guidance that you gave at the Analyst Day of $25 billion annualized 2018 through 2020, I guess, is what you're implying here that the second half ramp is the reason we get to the run rate of that 25 for the next couple of years up from 22 this year?
Yeah. It's a good question, Phil. I understand where you're going with it. I wouldn't try to anchor the second half 2017 spend on the projection that we provided in the analyst meeting for 2018 forward. Ballpark, we're going to see anywhere between $20 billion-$25 billion going forward. We're pretty comfortable with the range that we had provided earlier this year as an outlook out to 2020. It's going to moderate based on progress in certain projects and some new opportunities that have been brought into the portfolio. As a rule going forward, if you think that we stick with around $22 billion in 2017, slowly ramping up through the end of the decade is the way I think about it.
Sure. Okay. That makes sense. Thanks a lot.
Okay. Thank you, Phil.
Our next question will come from Brendan Warn of BMO Capital Markets.
Yes, thanks, Jeff. Thanks for the opportunity to ask a question. Just back on Liza or Guyana, can I just ask a question about, let's see, Turbot and Ranger? You talked about them as being, call it new play tests. Are they different, call it horizons, different prospect types? Can you just probably expand on that comment in terms of what are the additional risks related to those step-outs on that block?
Yeah. Well, thanks for raising that, Brendan, because it is an important point to make, because any type of rank well cap exploration has got a fairly material risk to it. Turbot is still in the Upper Cretaceous. It's still a stratigraphic trap, but it is in a different sediment fairway or depositional environment than Liza, Snoek, and Payara. The Ranger prospect, the analysis that we've done really suggests a large carbonate buildup. Higher risk and uncertainty, but obviously we see the potential as being material to justify that risk profile.
Actually, the follow-up to that then, if it's carbonate, are we talking the same source from the Cenomanian-Turonian?
I'm sorry, Brendan, can you say that once again?
For Ranger, is it still the same source rock from the C-T?
Yeah. Maybe. It's probably early to fully conclude that, but potentially. As I indicated earlier, we got a lot of things going on in parallel right now in our analytical work.
Okay. Thanks, Jeff.
You're welcome.
Brian Todd of Deutsche Bank has our next question.
Great. Thanks, Jeff. Maybe one high-level question on your thoughts around the Gulf Coast Initiative that you have down there. Can you talk a little bit about the potential expansions that you see there? I know some of them you talked about potential petchem expansions. Are there likely to be refining expansions? How do you see the Gulf Coast region? Do you see it as a strategically advantaged location for exports of everything from refined product to pet chems. How does that figure into your long-term strategic plans there?
Yeah. In fact, you answered where I was going to start. Strategically, it's very well-positioned in terms of the feed advantage, the unconventional resource base, the infrastructure and the linkage in that infrastructure, the integration that we have throughout our facilities, the full integration of fuels, lubricants, and petrochemicals, the logistics capability. All those factors really position it very well. As part of our Gulf Coast Initiatives Program, we've had a number of very successful projects that we've implemented. The ones that are in progress right now is obviously the big Baytown expansion that adds another 1.5 million tons per annum of ethylene capacity. I referenced in my prepared comments the corresponding polyethylene trains that are starting up in the third quarter. We've got an expansion going on at Beaumont for additional polyethylene trains.
We've got the big greenfield development down in South Texas, potentially with our partner, SABIC, that will add that additional 1.8 million tons of additional ethylene capacity, and then associated derivative units. On the upstream side, we are still moving forward with an assessment of the Golden Pass LNG export facility. You may be aware that in April this year that the Department of Energy finally authorized Golden Pass to export LNG to countries that do not have free trade agreements with the U.S. That was really one of the last big significant authorizations we were looking for. Now we're focused more on bringing together all the remaining elements to really position the project for a potential final investment decision, specifically looking at and updating the technical and commercial details at this point.
That's a high-level summary of the benefits of what we see the Gulf Coast brings, as well as the investments that we're progressing.
Great, thanks. It's mostly, I guess, pet chem and LNG. Are we likely to see any type of refining expansion down there?
Well, as part of this whole Gulf Coast initiatives, we have made some investments to expand. Like for instance, in Beaumont, we added something like 20,000 barrels a day of additional feedstock capacity allow us to have the capability to bringing in more of the unconventional feedstock or production for feedstock. We've made a lot of investments to really focus in the following areas, either building logistics flexibility, building feedstock flexibility, but importantly, focused on the integrated benefits of the facilities and really increasing the value of the products that we make at those manufacturing sites.
Great. Thanks. Maybe just a quick follow-up on that. I saw the announcement of the expansion there in Mexico. How big of an opportunity could this be?
Well, we're certainly pleased with the business climate where it has moved to. It's an attractive market for, as we just were talking about, our Gulf Coast refining. We have a reliable facility, and this is a good outlet. We've had a very long history in Mexico, and I think it positions us well.
Great. Thank you.
Thank you.
We will move next to Roger Read of Wells Fargo.
Hey, good morning, Jeff.
Good morning, Roger.
Maybe just come back to CapEx real quick so I can understand some of the moving parts here. The two acquisitions, are those going to be cash only or cash and shares? I'm just trying to think its impact on cash flow in the second half.
Yeah, those will be cash transactions.
Okay. As we think about the guidance that CapEx slowly trends higher through the end of the decade, presumably you don't build acquisitions into that CapEx assumption. Should we think about that as field development, exploration, et cetera, the kind of CapEx spending, or should we build in an acquisition expectation in that?
Well, by and large, you're exactly right. Unless there's something that's in the works that we feel fairly confident with, we will not include it in that projection. Be clear, Mozambique was in that outlook we shared in March during the analyst meeting. We just didn't highlight it because it wasn't ready for prime time. We'll go ahead and depending on where we are, we'll represent it accordingly. Important to highlight is that, and you know this, Roger, we've got a very strong balance sheet. It allows us to capitalize on the moments regardless of where we are in the commodity price cycle.
I think you just look back over the last 6-9 months, we've been able to pick up four very accretive, very high-quality assets that really meet the objective that we're trying to achieve with high grading the portfolio.
No, absolutely appreciate the longer-term view that you're able to take. My follow-up question, I think it was slide 20, estimated project development costs in the Delaware Basin of $5-$7 per BOE. Multiple benches out there. Is the $5-$7 looking at the development over the course of 10 or 15 or longer years? Or is this sort of a way to think about phase one?
Well, if you remember when we communicated the acquisition, we laid out a long-term development expectation. Certain level of rig activity, total buildup, I think it was about 350-plus thousand BOE per day. It was a long-term view of the development of this northern acreage in the Delaware. That's what that represents. It's kind of the overall assessed scope that we had built in to develop it based on, if you will, our technical assessment that underpinned our decision to go ahead and assess the or acquire the asset.
Okay, appreciate it. Thank you.
Thank you, Roger.
Now we'll move next to Blake Fernandez of Scotia Howard Weil.
Hey, Jeff. Good morning. I was hoping to go back to the volume question, the production question. I know you already tackled the European rollover. I'm trying to get a sense of how much is associated with just pure seasonality and how much is more regulatory Groningen effects. Is there a way you can quantify the quarter-to-quarter change that's down about 159,000 barrels a day in gas? Can you quantify how much of that is actually Groningen?
Yeah. If you look on quarter to the prior quarter, my recollection is about 90 million cubic feet per day was associated with the cap impact. That was the second quarter 2017 to second quarter 2016.
Okay. That's helpful. Thank you. The second question is on your slide showing the free cash flow above dividends. You had mentioned your debt has definitely been working down over the past year, I guess I'm just trying to understand the appetite for re-implementing the buyback program, over and above offsetting dilution versus reinvestment into the business. Obviously, you've got a whole host of acquisitions that are underway, it seems to me like your appetite is more geared toward acquisition opportunities rather than buying back stock, I just didn't know if you had any commentary you could offer there.
Yeah. Blake, I'd put it this way, that if an opportunity comes along from an acquisition perspective that we think would be very competitive to our existing investment portfolio, we're certainly going to go ahead and pursue it. As I said earlier, we have the financial capability to do that regardless of where we are in the commodity price cycle. The buyback decision really steps back, I think I've mentioned this before, if you think about our cap allocation approach, it really is bounded on being committed to a reliable and growing dividend, at the same time, continuing to invest in accretive investment opportunities. With the remaining cash, the decision is around how do you put that to additional work? How do you distribute to your shareholders if you feel that's appropriate?
That's really viewed on a quarterly basis where we step in and we consider, is there some debt that's maturing that we'll go ahead and close out? Does it make sense to go ahead and purchase some shares with it? Think about it as a separate, it's part of the overall cash management, that we'll consider that on. We like the trend we're on, and regardless of what commodity prices do, if you pick up anything from me, it's one of through our self-help and through our investment program, we are building value.
Understood. Thank you.
You're welcome.
We will now move to Paul Cheng of Barclays.
Hey, guys. Good morning.
Good morning, Paul.
Jeff, on the warning, can I go back, in Africa, year-over-year, there's a big decline in your liquid production. I think you mentioned that you have heavier than maybe heavier turnaround activities there. You also have a sale of, I think some Nigerian operation. Trying to understand that, how big is the drop year-over-year, in the first half of the year is related to sale or that is more structure and how much is really just more activity? Also you mentioned in your prepared remark, you have underlift, this quarter, 150,000 barrel per day. Do you have an earning impact related to that?
Yeah. A couple points. On the first one, you were talking about the decline that we've seen in our Africa volumes, there are several things that are driving that. One has to do with natural decline in Africa. The second one has to do with, there's been a reasonable amount of downtime that we've experienced. Then the third one that I mentioned earlier was the entitlement impacts due to the commodity crisis. I would summarize that those are probably the three key areas that are driving the volumes in Africa right now. The second question about the underlift and the earnings impact. It's a large part of that component. I think it's in excess of $100 million plus earnings impact associated with it on a quarter-on-quarter basis.
Mm-hmm. That final one on Liza. In phase 1, you are reinjecting the gas. I think the estimated gas resources may be about 20% of the total BOE, or maybe a little bit more, little bit less. In the future phases, will you be able to still just reinject, or you actually have to fund the infrastructure to develop it? If that's the case, given that the lack of infrastructure over there, what kind of cost component that we may be talking about?
Yeah. Well, Paul, as you said, in the phase 1, the plan is that we will reinject the gas into the reservoir. Going forward in subsequent phases, obviously, that's a key aspect of our development planning efforts. I think it's probably too early to signal where we end up on that. That will certainly be an area of dialogue with the resource owner and making sure that we're meeting their objectives as well.
Mm-hmm. I see. All right. Will do. Thank you.
Thank you, Paul.
We will now move to Anish Kapadia of Tudor, Pickering, Holt.
Hi, Jeff. Just a first question on the overall LNG market. You're obviously seeing Qatar make that announcement, yourselves adding quite a lot of potential capacity over the next decade from Mozambique. I was just wondering, how have your conversations been with LNG buyers? Have you signed any deals this year in terms of your future projects? Obviously we've seen kind of on the other side of the equation, companies canceling projects, which is a large project in Canada that was announced in the last week or so. I just wanted to get an idea of how those conversations with the LNG buyers are going.
Well, I guess a couple points to share with you, Anish. First, again, our forward-looking perspective around the LNG development opportunity is really underpinned by our energy outlook, which with gas growing at 1.5% per year throughout the period out to 2040, that translates into LNG capacity growing two and a half times. As it relates to our interaction with potential buyers, obviously, I can't share the specifics. That's part of those confidential discussions. I will note that there've been a number of announcements that we've released regarding heads of agreements. One of them having to be, I think it was in Indonesia for an extended period sale. There were others that were announced that I just don't have them all in front of me, Anish. I think the message you should understand is that we have a very large program right now.
We've got a very strong marketing organization, and we have continued to underpin our LNG investment decisions or final investment decisions with long-term contract structure that helps ensure the return expectations on those investments. Rest assured, we've got active marketing programs in place.
Great. Just a quick follow-up is, you mentioned, I think, some asset sale gains in the quarter that helped the results. Could you quantify what those were on an earnings basis?
Yeah. On an earnings basis, Anish, in the second quarter, it was $68 million, and all of that was in the downstream.
No, thanks.
We will now go to Theepan Jothilingam from Exane BNP Paribas.
Yeah. Hi. Good morning, Jeff Woodbury. Thanks for taking my questions. I've got just two, actually, please. I think you discussed the broadening of the fuels marketing business in Mexico. Is there a broader strategy there for ExxonMobil to invest more aggressively in fuels marketing? Where are those opportunities as you see them today? Secondly, we've talked about the deep water and Liza and Guyana. I was just wondering whether you saw opportunities for ExxonMobil in the bidding rounds coming up in Brazil. Thank you.
Well, Theepan Jothilingam, thanks for the questions. On our fuels marketing, you may be aware that we had transitioned to a branded wholesale model, really with a focus of expanding our market share and brand, and at the same time reducing our capital and operational risk. That's worked very well. We're seeing some really good pickup out there with these branded wholesale opportunities. We see that as an important element of our value proposition going forward. Of course, in conjunction with that is that we're rolling out at the same time and expanding our signature line on Synergy gasoline and diesel fuels. It's the whole package that's important in terms of our overall expansion of this branded wholesale model. On the second question about our interest in participating in Brazil, in short, no doubt about it, Theepan Jothilingam, Brazil has a very nice resource endowment, high quality, great geology.
We need to see what's being offered in terms of the potential blocks as well as the participation structure. That will guide us in terms to the level of interest that we will progress. You think about it from a kind of benchmark perspective, we're looking for things like Guyana with really high quality, really good, if you will, risk-reward structure on how we manage this portfolio going forward. We do have a bias towards wanting to operate these assets because we think through our long-established project management capabilities and our ability to continue to grow the value proposition once we make the investment and all the way through the life cycle of the asset, that we tend to get more out of it. I'll leave it there, but you can get the sense that certainly very interested.
It's just got to compete with the rest of the portfolio.
Thanks, Jeff.
You're welcome.
We will now move to a question from Biraj Borkhataria of Royal Bank of Canada.
Hi, Jeff. Thanks for taking my questions. I had a couple. The first one was on Guyana and back on Liza. Based on what you see now, would you be able to give us your kind of blue sky scenario for the resource base and how you think that can go over the next year or two? The second question on LNG, relating to Mozambique. You acquired 25% of the project. One of your peers has talked about the willingness to take on more than their equity interest as an offtake volume in order to enhance the portfolio. Is that something you would be interested in for that project? Thanks.
On the first one, what I just summarized, other than what we've already communicated at this point, Biraj, around what we anticipate as a recoverable resource. As you can see from the display that we shared with you, there's a lot of potential plays there. They've got very material potential. It's really too early for us to go ahead and share what we think the ultimate resource potential is. You may recall that it was stated back in the analyst meeting that we clearly see multiple billion barrel of potential for the blocks. In fact, we're there today. We're very encouraged and I think the additional seismic acquisition, the analysis that we're doing, and the drilling that we're doing is going to help us converge on a view longer term. Can you tell me again the second question you had about what you're hearing from a competitor?
One of your peers has talked about the willingness to take on more than their share of the equity interest. For example, you have 25% interest in Mozambique. Would you be willing to take on, say, 50% of the offtake volumes?
Well, again, early days. We need to get into the venture structure here, hopefully, within the end of the year. We're always open to potential opportunities as long as it competes with the portfolio that we've got right now. I'm not going to speculate on market rumors or whatnot because I'm really not familiar with the specifics that you shared.
Thanks. That's very helpful.
Thank you.
We will now take a question from Pavel Molchanov of Raymond James.
Thanks for taking the question, guys. First on PNG, many of your shareholders came into the stock based on their InterOil ownership, and for their benefit, I am wondering if you can give an update on the resource certification of the Antelope field and the contingent value rights.
Yeah. Well, thanks for asking the question, Pavel. Certainly, I know there are many that are interested in how that closes out. As you know, we completed the Antelope well that we were drilling, and the resource certification process is in progress. The plan is that that will be concluded in the third quarter, and then the final results will be shared as per the arrangement. Hopeful that that will come to closure soon.
Okay. Very helpful. One more on Europe. You talked about the year-over-year decline in Groningen, but there is an additional further cap that you guys are currently appealing. If that appeal at the Dutch court fails, do you have any other options before you have to reduce production further?
Well, I think what you're referring to is that the minister went ahead and decided to further curtail production from 24 to 21.6 billion cubic meters per year. That doesn't go into effect until the next gas year, which starts in September. I really don't want to get into the discussions that we're having with the government. We certainly understand the issue. There's been a lot of really good collaboration amongst the various parties to make sure that we've got a good understanding, and that will all be addressed in these discussions between the various parties. I'm not going to speculate how that turns out.
Okay, fair enough. Appreciate it.
Bye-bye.
We'll now go to Jon Rigby of Societe Generale.
Just two quick ones on Guyana, Jeff. Is Ranger a structural trap or a strat trap?
Good morning, Jon. Ranger, the carbonate buildup, it'd likely be structural.
Okay. I was just wondering if you had clastics off lapping on it. Next question. For Liza Phase One, Hess mentioned that you're only planning eight producers. Is that correct? Should we assume for comparable phases that it will be a low number of wells given relative productivity or expected productivity?
Yeah. Well, as you heard, we had a really nice test on Liza, that really sets us up for the development plan. We do have eight production wells planned from four drill centers, we'll see how that goes as the development progresses, that is the current basis going forward.
Great. Thank you.
Thank you, Jon.
We'll now go to Doug Leggate of Bank of America. Doug, if you could please check your mute function.
Sorry about that. Yes, indeed. Sorry for lining up again, Jeff. I just wanted to close the loop on one issue. The deeper Payara tail. Hess gave some color on it, but I guess we're going to get the official version from you. Can you just give what your prognosis was there? Whether there are plans rather to go to a Payara 3 and try that deeper section again, or are you done with that one and moving on? I'll leave it there. Thank you.
Yeah. In terms of the plans, Doug, that's yet to be determined. Yes, we did deepen approximately 300 meters to evaluate a deeper exploration objective. I'll just note before I share the results, that this was a good low-cost opportunity to evaluate what we saw as potentially material prospect. In terms of what we found, we found high-quality water-bearing sands with oil shows throughout. I think we would characterize the results as being encouraging, both from a reservoir quality and hydrocarbon system standpoint in the deeper section. That information will clearly be integrated into our forward assessment.
Jeff, are you planning to go back to that at a future date with another Payara appraisal and maybe another deepening? Because it sounds like you're not I'm trying to read the tea leaves here a little bit. Are you writing the deeper section off completely, or are you saying there's further testing you want to do in that Santonian part of the play?
I think the results would indicate that clearly we need to integrate that into our overall model of the depositional environment and the potential. That may lead up to some additional work in those sands of a comparable geologic age. It's just way too early to comment on specific plans at this point.
All right. I'll leave it there. Thanks again. Could you give my follow-up?
All right, Doug.
We have time for one final question, and that will come from Guy Baber of Simmons.
Hey, good morning, Jeff.
Good morning, Guy.
Thanks for fitting me in here. I apologize for revisiting this, but I think it's important, just trying to understand the messaging on the $25 billion or so medium-term capital spending framework and how sensitive that might be to the oil price environment should we find ourselves in a lower oil price world than you may have anticipated at the time you gave the guidance. Really just trying to understand that tension between investing sufficiently to sustain, replenish your portfolio against the willingness to tolerate some cash flow outspend. Really, I just ask because on an organic basis, your spending right now is obviously well below that $25 billion future potential run rate, even allowing for some pretty material activity increases over the back half of this year.
Yeah. Well, I think it's a very good question, and a couple of thoughts I would share with you is, one, remember our long-term investment program is really founded on our long-term constructive view of energy demand. For us to compete and win, simply put, is that we have got to be the lowest cost of supply producer out there. Okay? A large part of our investment program that we shared with you all in March, the announcement meeting, out through the end of the decade is really these long-cycle investments. Of course, we've got a short cycle component, and it represents, let's just say round numbers, about a third of our total upstream spend. We will look at that, particularly in a near-term price, a low price environment.
We'll look at that to make sure that it makes good sense, because one of the things you want to do in the short cycle program, particularly in things like Permian or the Bakken, is you want to maintain a certain level of activity to continue to grow that learning curve. You don't ever want to drop back on that learning curve. On the same hand, you don't want to over-invest. The last thing we want to do is over-capitalize an unconventional business. We'll keep a level commensurate with that learning curve benefit. You saw that over 2015, 2016, as we dropped rigs, we stayed pretty high in our activity level. Those are kind of some of the trade-offs we've got. I'd summarize by saying that we've got flexibility.
We have always built in flexibility, and we tried to share some of that at the analyst meeting with respect to our capital program. Again, I'll just emphasize that the long cycle program is really based on our constructive view of supply and demand.
Thanks, Jeff.
You're welcome.
This does conclude our question and answer session. I'd like to turn the conference back to Mr. Woodbury for any additional or closing comments.
Well, to conclude, I just thank everybody once again for your time. I mean, very thoughtful questions this morning. A really good exchange of some of the key fundamental elements that drives our value proposition. I do appreciate the preparation, and importantly, we really do appreciate the trust that our investors place in ExxonMobil. We'll close here, and we'll look forward to our future discussions. Thank you.
With that, ladies and gentlemen, that does conclude today's call. We'd like to thank you again for your participation. You may now disconnect.