Good morning. My name is Jonathan, and I will
be your conference facilitator today. Welcome to Chevron's Second Quarter 2016 Earnings Conference Call. At this time, all participants are in a listen only mode. After the speakers' remarks, there will be a question and answer session and instructions will be given at that time. As a reminder, this conference call is being recorded.
I will now turn the conference call over to the Vice President and Chief Financial Officer of Chevron Corporation, Ms. Pat Yarrington. Please go ahead.
Okay. Thank you very much, Jonathan. Welcome to Chevron's 2nd quarter earnings conference call and webcast. On the call with me today are Jay Johnson, Executive Vice President, Upstream and Frank Mount, General Manager of Investor Relations. We will refer to the slides that are available on Chevron's website.
Before we get started, please be reminded that this presentation contains estimates, projections and other forward looking statements. We ask that you review the cautionary statement on Slide 2. I'll begin with a recap of our Q2 2016 financial results, and then Jay will provide an update on our upstream business prior to my concluding remarks. Turning to Slide 3. Slide 3 provides an overview of our financial performance.
This company's 2nd quarter loss was $1,500,000,000 or negative $0.78 per diluted share. Included in the quarter were impairments and other charges of $2,800,000,000 These are primarily associated with certain assets, where through a combination of reservoir performance and price, revenue from oil and gas production is not expected to recover costs. Excluding these items, as well as the impact of asset sale gains of $420,000,000 and foreign exchange effects of 279,000,000 dollars earnings for the quarter totaled $661,000,000 or $0.35 per share. A detailed reconciliation of special items and foreign exchange is included in the appendix to this presentation. Cash from operations for the quarter was $2,500,000,000 and our debt ratio at quarter end was approximately 23%.
Our net debt ratio was a bit under 20%. During the Q2, we paid $2,000,000,000 in dividends. Earlier in the week, we announced a dividend of $1.07 per share, payable to stockholders of record as of August 19, 2016. We currently yield 4.2%. Turning to Slide 4, cash generated from operations was $2,500,000,000 during the Q2 and $3,700,000,000 year to date.
Upstream cash generation was stronger than the Q1 commensurate with rising crude prices. Working capital effects of $2,000,000,000 $2,000,000,000 in deferred tax items, for example, those associated with tax loss positions, reduced year to date operating cash. These are generally transitory effects which reverse in future periods. We expect a portion of the working capital drain to reverse later this year. Proceeds from asset sales for the quarter totaled $1,300,000,000 mainly from the sale of our New Zealand marketing assets, Canadian natural gas storage assets and pipeline assets in North America.
Cash capital expenditures were $4,500,000,000 a decrease of over $3,000,000,000 from Q2 2015 and down more than $1,000,000,000 from the Q1 of 2016. At quarter end, our cash, cash equivalents and marketable securities totaled approximately $9,000,000,000 and our net debt position was 36,000,000,000 dollars Turning to Slide 5. Slide 5 compares current quarter earnings with the same period last year. 2nd quarter 2016 results were $2,000,000,000 lower than Q2 2015 results. Special items, primarily the absence of the Q2 2015 gain on the sale of Caltex Australia Limited, partially offset by the Q2 2016 gain on the sale of New Zealand Marketing, reduced earnings by $1,400,000,000 between periods.
In both quarters, depreciation expense was impacted by impairments and other charges. The swing in foreign exchange impacts improved earnings by $530,000,000 between periods. As a reminder, most of our foreign exchange impacts stem from balance sheet translations and do not generally affect cash. Upstream earnings, excluding special items and foreign exchange, decreased $528,000,000 between quarters. Lower crude realizations were partially offset by lower exploration and operating expenses as well as other unrelated positive variances.
Downstream results, excluding special items and foreign exchange, decreased by $535,000,000 primarily driven by lower worldwide refining margins, partially offset by lower operating expenses. Turning now to Slide 6. I'll now compare results for the Q2 of 2016 with the Q1 of 2016. 2nd quarter results were $745,000,000 lower than the Q1. Net special items for impairments, project suspensions and other related charges decreased earnings by $2,200,000,000 between periods.
Foreign exchange created a positive earnings variance of nearly $600,000,000 between periods. Upstream results, excluding special items and foreign exchange, increased approximately $1,200,000,000 between quarters, primarily reflecting higher realizations in line with our price sensitivity, as well as lower exploration and depreciation charges. Downstream earnings, excluding special items and foreign exchange, were lower by $79,000,000 as lower operating expenses were more than offset by inventory revaluation effects. The variance in the other segment largely reflects unfavorable corporate tax items. Jay will now review our worldwide quarterly production and provide an update on our upstream operations.
Jay?
Thanks, Pat. I'll start with Q2 2016 production and then provide an update on a few of our key upstream projects. Slide 7 compares the change in Chevron's worldwide net oil equivalent production between the Q2 2016 and the Q2 2015. Net production decreased by 68,000 barrels a day between these quarters, yielding first half twenty sixteen production of 2,600,000 barrels a day. Shale and type production increased by 50,000 barrels a day, primarily due to growth in the Midland and Delaware basins in the Permian, with the Marcellus, Vaca Muerta, Duvernay and Liard basins also reflecting year on year growth.
Major capital projects increased production by 37,000 barrels a day as ramp ups continue at Jack St. Malo, Chongqing Bay and Angola LNG, and we saw initial production from Gorgon. Disruptions due to external events accounted for the temporary shut in of 63,000 barrels per day, which included the partition zone, security issues in Nigeria and fires in Canada. The sale of our Michigan assets and several assets in the Gulf of Mexico Shelf resulted in decreased production of 44,000 barrels a day. The decrease of 48,000 barrels a day in the base business and other bar reflects normal field declines and higher turnaround activity, partially offset by new base business production from Brownfield Investments.
The chart shown on Slide 8 was presented in January and outlined our production guidance and uncertainties for 2016. The cumulative impact of the uncertainties has been unfavorable, and we expect to be near the bottom of the annualized guidance we provided. For example, we anticipated that oil production in the partition zone would be restarted by midyear, which hasn't happened. As a reminder, in the Q1 of 2015, this field produced over 75,000 barrels a day Chevron share. We've also worked through various start up issues at Gorgon that impacted our first half production.
We've been successful with our upstream divestment program, which is impacting our production. Transactions closed this year represent a daily production rate of just over 40,000 barrels a day, and we expect to see an additional 15,000 to 30,000 daily barrels leaving the portfolio before the end of this year. In addition to these uncertainties, production in the Q3 will be adversely impacted by a large number of turnarounds, including the 2nd generation plant at Tengiz. At the same time, our long anticipated queue of projects is now coming online. In the second half of this year, we expect to see sustained production from Angola LNG, Gorgon Trains 12 and all three trains at Chongqing Bay.
We're also expecting continued growth from the Permian, which I'll talk further in a few minutes. The overall result is that we expect to exit the year with the December production in the range of 2,650,000 to 2,700,000 barrels per day. Turning to Slide 9. Funding the completion of projects under construction is our first capital allocation priority. At Gorgon, we're currently producing at 70% of Train 1's capacity or approximately 90,000 barrels per day.
In early July, we took a short shutdown to address a number of issues and repair a minor leak. Production resumed mid July and the plant has been running smoothly since that time. We're incorporating all the experience gained from Train 1's construction, completion and initial operations into Trains 23. Construction on Trains 23 is progressing very well. We expect first LNG from Train 2 early in the Q4 and from Train 3 in the Q2 of 2017.
At Wheatstone, our outlook for first LNG remains mid-twenty 17 for Train 1. The cleanup and testing of all 9 development wells has been completed and the rig has been released. Initial results are in line with expectations. At the plant site, piping, electrical and instrumentation work is currently progressing very well. We're working to maintain this progress as we begin the transition to completion, commissioning and start up activities.
Train 2 construction work is also progressing per plan with start up expected 6 to 8 months after Train 1. Slide 10 shows our other 2016 startups. At Angola LNG, modifications were completed at the plant and production restarted on May 20. Since restarting the plant, we've loaded 4 LNG and 7 LPG cargoes. The plant was tested at 75% capacity and ran smoothly prior to the planned shutdown for strainer and other maintenance activities.
The modifications to the gas conditioning section operated as designed and all other repairs are complete. We expect to achieve sustained production during the Q3. At Changdong Bay, Train 3 started up in late May and all three trains have delivered at full capacity and are now operational. There have been no changes since our previous updates on Alder, Matamorosul or Banco. Turning to Slide 11.
Our next capital priority is to fund high return short cycle base and shale and tight investments. 1st among these opportunities is the Permian, where we have a large royalty advantaged acreage position. We're making excellent progress in the Permian towards the growth we discussed at our analyst meeting in March. Production this quarter was 21% or 24,000 barrels of oil equivalent per day higher than the Q2 of last year. Efficiency gains and a shift to more Chevron operated rigs have more than offset the reduction in total rig count.
We're delivering our plan with fewer rigs and less cost. Turn to Slide 12. As we said before, one of our primary benchmarking metrics for our Permian assets is development cost per barrel. Since the Q2 of last year, we've reduced our unit development cost by approximately 30%. We've been able to accelerate our performance improvements by incorporating industry best practices and applying lessons learned from our joint ventures and contractors.
As shown by the data, our development cost is competitive with our joint venture partners. The table shows improvement in our drilling and completion cost performance from recent pad drilling programs. For 7,500 foot laterals in the Midland Basin, we're averaging $5,600,000 per well, which is a 25 percent reduction from what we showed you at our analyst meeting in March. Our recovery per well is also improving as we continue to implement learnings and optimize our lateral lengths, well completions and drawdown strategies. Earlier this year, we exceeded 2,000 barrels of oil equivalent per day in a 24 hour well test on a 7,500 foot lateral well in the Greater Bryant G area.
We also put our 1 100th company operated horizontal well on production and continue to gain confidence in our acreage characterization and performance. We're taking a disciplined measured approach to development, and we're optimizing and prioritizing the large number of available well locations. We're delivering on our objective to be a competitive operator whose royalty position provides an incremental competitive advantage, and we're consistently improving our financial performance. Slide 13. In addition to the Permian and other large scale short cycle businesses such as San Joaquin and Gulf of Thailand, we have a number of attractive major capital projects that leverage previous investments.
The projects listed on this slide all take advantage of existing infrastructure, reducing development costs and cycle time. As they build upon existing developments, they also tend to carry less subsurface and execution risk. The average development cost for these projects is around $15 a barrel. At Jack and St. Malo, we continue to ramp up production.
In June, the combined production for both fields reached 110,000 barrels a day. This was accomplished through continued high facility reliability and the start up of the 8th well. The 1st Stage 2 well is expected to come online next month. Turning to Slide 14. A major brownfield opportunity that we've talked about many times is the future growth in wellhead pressure management project in Tengiz.
As we announced earlier this month, the TCO partnership sanctioned the project. WPMP provides additional wells and pressure boosting facilities to maintain production levels in the existing plants as reservoir pressures decline. FGP builds on the sour gas injection technology already proven in existing operations at Tengiz. It adds additional production and gas injection capacity to increase total oil production by around 260,000 barrels a day. The project is designed to capture execution and infrastructure efficiencies and will take advantage of current market conditions.
Incremental recovery is expected to be 2,000,000,000 barrels of oil equivalent. Turning to Slide 15. FGP WPMP is estimated to cost $36,800,000,000 which includes $27,000,000,000 for facilities, dollars 3,500,000,000 for wells and $6,200,000,000 for contingency and escalation. The development cost for the project is $18 a barrel. Operating and transportation costs are expected to be consistent with our existing operations.
TCO has secured financing to ensure uninterrupted project funding, utilizing a combination of bank loans, co lending and bonds. Demand for the 1st tranche of the bond offering was strong and the bonds were placed at an attractive interest rate. Go to Slide 16. As I've discussed, we're committed to improving our project execution performance across the enterprise. I've used this slide previously to describe the actions we're taking on the projects in order to deliver strong execution performance and mitigate the amount of contingency consumed.
We're confident these actions will improve our ability to deliver this project predictably and reliably, and I'll update you on a few examples. Engineering is currently greater than 50% complete, well ahead of industry practice of 25% or less at FID. Having a more advanced engineering design provides a better understanding of the quantity and quality of materials, equipment and labor required to execute the project and reduces the likelihood of out of sequence work and construction delays due to engineering issues. The project team and principal contractor have been integrated into one team with fewer layers of management, lower cost and more effective leadership. Turning to Slide 17.
We're pleased to see this project enter execution and are excited about the value the project brings to Kazakhstan, TCO and our shareholders. Tengiz is a world class reservoir and FGP WPMP provides the foundation for the continued economic development of the field. The project utilizes technology already proven at Tengiz. It addresses declining reservoir pressure and enhances recovery from the reservoir. This countercyclical investment takes advantage of the current market in terms of cost savings, fabrication capacity and contractor capabilities.
Project economics are attractive within the current concession life and include 20% contingency. The project provides additional upside opportunities, including future infield drilling, facility debottlenecking, increased oil production from existing plants as well as additional enhanced recovery projects. A concession extension or utilizing less contingency would also provide additional benefits. Tengiz has been an excellent asset for Chevron and this investment will allow Tengiz to continue to generate value into the future. I'll now hand back to Pat to discuss our progress on spend reduction.
Okay. Now turning to Slide 18. We are delivering on our committed spend reductions. You'll note the steep reduction in quarterly C and E average over the past 3 years. Year to date capital expenditures are down 31% when compared with 2015.
We're on a trend line for 2016 C and E of $25,000,000,000 or less. For 20 17, 2018, we anticipate capital expenditures between $17,000,000,000 $22,000,000,000 If the current price environment persists, we will revisit the bottom end of the range as our primary goal is to be cash balanced. Year to date operating expense is also down, down 8% when compared to 2015, and we expect a downward quarterly trend to continue in the second half of this year as we realize the full year run rate of organizational actions and supply chain initiatives. Turning to Slide 19. Just a quick update on our asset sales program.
Over the last 10 years, on average, we have received proceeds from asset sales of $2,900,000,000 per year. With the sale of our interest in Caltex Australia, 2015 was the highest dollar transaction year. Year to date, we have received proceeds of $1,400,000,000 covering several transactions. New Zealand marketing, Canadian Gas Storage Assets, Pipeline Assets in California and Upstream Assets in the Gulf of Mexico. We have a number of potential transactions presently being worked.
The larger publicly known transactions are noted on the slide. There are a few attributes that these transactions have in common. The assets are not essential to delivering on our strategy. Their valuations are not particularly oil price sensitive and there are multiple interested buyers. We believe our sales program is executable and that we can secure good value.
We have confidence in achieving our $5,000,000,000 to $10,000,000,000 target for total proceeds over this year and next. And as I said last quarter, we have line of sight on around $2,000,000,000 for 2016. I'd like to close the presentation here on Slide 20 by reiterating a few key points. We remain committed to becoming cash balanced in 2017. Our projects are coming online, and we're making huge strides in lowering our cost structure and getting our capital outflows down.
We're on track with our asset sales program. We see those as back end loaded with more occurring in 2017 than this year. They are eminently doable. We believe they part of our cash balancing program. Looking out the next 12 to 24 months, our profile is just as we have long said it would be, strong volume growth and cash flow margin accretion at the same time.
That's a powerful combination offering tremendous value growth for our shareholders. Our financial priorities remain unchanged. We're committed to growing the dividend as earnings and cash flow permit. We recognize the value our shareholders place on dividends and the value they place on our long history of annual dividend payment increases. So that concludes our prepared remarks.
We're now ready to take some questions. Please do keep in mind that we have a full queue, so try to limit yourself to one question and perhaps one follow-up if necessary. We'll do our best to get everyone's questions answered. Jonathan, can you please open the line?
Certainly. Thank
Our first question comes from the line of Phil Gresh from JPMorgan. Your question please.
Hey, good morning.
Good morning.
Thanks for all the color in the slide deck today. My two quick questions are going back to the Analyst Day and then kind of tying it to what you said today. The first one would just be on the production growth outlook looking out to 2017 in the fuzzy bar chart. At the time at the Analyst Day, you had mentioned that the 2.9 to point 0 target generally still held at that point in time. Obviously, there's been a lot of transitory items this year and then there's some asset sales.
So I was just wondering if
you could give us a little bit
of an update as we look ahead to 2017, either on the number itself or some of the moving pieces we should think about with respect to that number?
So I think as we look forward at the production, the thing that's coming through are the major capital projects. And as they start up and we're seeing good performance out of those, I think that part of our performance is very strong as is the growth coming from assets like the Permian and our other base business. And actually, our decline rates have been very good. We will see potentially some decline. We're expecting to go maybe from 2 into the 2 to 4 range because of the cutbacks in capital, but we still pretty see pretty good performance from all of our base assets.
The asset sales program, we'll give some further updates when we get to the SAM meeting on where we stand there. Some of those were already baked into that forecast. And of course, as we move forward and build a business plan this year, a lot of it's going to be responsive to the environment that we find ourselves as we move forward. I think a key thing is that these new barrels coming online from Permian and from these major capital projects are accretive to our existing portfolio, and so we expect to see strong cash generation as we move forward. Okay.
And then my follow-up is just on the Permian. At the Analyst Day, you had talked about a potential doubling of the capital budget to meet this strong growth profile through 2020. It sounds like the costs are coming in very well. So maybe just talk about how you think about growth versus capital preservation. If you can do more with less, would you focus on reducing the capital or would you try and actually increase this production target over time?
We'll give further updates on our production targets, I think, at a SAM meeting. But what I would say in the meantime is we continue to want to grow our Permian business. So we are adding an additional rig in August. We expect to have a total of 4 additional rigs. That's going from 6 currently to 10 rigs by the end of this year in the Permian and would expect to see good performance coming from those rigs.
One of the things we've tried to do is take a measured pace so that we preserve the productivity and the capital efficiency that we've been able to capture so far. We want to make sure we do that as we ramp up. We feel quite confident we can do so.
Thanks, Bill.
Thanks. Thank you. Our next question comes from the line of Paul Sankey from Wolfe Research. Your question please.
Hi, good morning everyone. I think I've got the longest term question I've ever asked here, which is the Kazakh concession expires in 2,032, is that correct? Yes, 2,033. 2,030 3. Is that included in your economic assumptions as a sort of endpoint for the I mean, I know it's kind of crazy, but obviously if you're investing for start up in 2022, 10 years is 11 years is not that much later in terms of the scale of the project.
Are the economics that you've run assuming that the concession goes away?
Yes. We base all of our economics on decision making on the actual end of life of the concession, but obviously there's considerable upside. I think, both for the country and for the companies if we continue to progress the concession with an extension.
Got it. Thank you, Jay. Near term, were there any special items that we should consider in the cash flow? I asked a similar question to Exxon. That makes this an unrepresentative quarter because obviously the cash balances right now are not even covering the dividend.
Is there anything special?
Yes. I'd mention 2 things. I mentioned them in the official comments. 1 is working capital and the other is deferred tax. And on a year to date basis, both of them are worth about $2,000,000,000 each.
From a working capital standpoint, I indicated that we expect a portion of that will reverse this year. The deferred tax impacts will also reverse. And you need to think about these as tax loss carrybacks or tax loss carry forwards. Across the world, it depends on specific circumstances and specific jurisdictions what the specifics of that are. But in either case, we can either take these back against prior income or we can carry them forward against future income.
So in our case, I know, for example, we will be filing for amended tax returns in 2017. So the point is that those negatives, both on working capital and deferred tax, are negatives right now, but they become positives in the future. And so when I when you think about this impact, and it's pretty significant on a year to date basis, again, dollars 4,000,000,000 across the 2 of those. When you take that into account and you think about Gorgon and Wheatstone coming online and the $2 a barrel margin accretion that we gave you over the whole portfolio, our outlook on cash flow generation going forward is quite positive. Thanks, Paul.
That's right. Could I just ask a quick follow-up? Sorry, the working capital effect isn't from prices going up during the quarter, so wouldn't it why would it reverse if prices went further up from here?
So I mean, part of it is inventory, part of it in this particular time just happened to be cargo timing on receivables versus payables. So we've analyzed it to quite an extent and we're pretty comfortable saying somewhere in the neighborhood of at least half of it will go down between now and the end of the year. We obviously are being impacted by lower activity and then just changes in prices and cost structures.
Thanks, Paul.
Thank you. Our next question comes from the line of Paul Cheng from Barclays. Your question please.
Hey, guys. Good morning. Hi, Paul. Jay, two questions in here. First, Gorgon, Train 2 and 3, previously, I think the expectation is that maybe a little bit sooner, Train 2 will be maybe the Q3 and Train 3 will be the Q1 of 2017.
And also I think that historically that you guys are suggesting 3 to 6 months of the start up period or the ramp up period. Now talking about 6 to 8 months, is that being just conservative on your part or that there's something fundamentally when you're looking at the LNG business lead you to believe that the ramp up period and everything that may just take a bit longer than historically has been?
Paul, a couple of things. We've always said that our expectation is that Trains 23 would start up at roughly 6 month intervals, and we're pretty much still on that plan. We started up the 1st train in March, so we're projecting early in Q4 for Train 2 and then Train 3 will follow along behind. So there's latitude in those quarters. We are seeing very good construction progress on 23.
And importantly, all the lessons, as I said, that we've learned not only during the construction time, but in the design and all the modifications we've had to make. As we've started up Train 1, all that's been built into Train 2 as well as the actual hours to complete these projects. So we feel very encouraged by the results we're seeing. We're happy with the construction progress. We're well into commissioning of Train 2.
So there it's pretty much as we expected. As far as the ramp up, our view has been 6 to 8 months. We kind of base that looking at LNG projects around the world. That's a normal kind of a ramp up period. As I've said before, it's not so much that you're on this smooth curve from start up to full capacity.
But as you start up one of these plants, there are issues that have to be dealt with. And so you have periods of downtime as you go down to make modifications or fix some of the equipment that you have difficulty with on startup, tuning loops, things like that. So it's really a function of the downtime and the overall effect is a curve as you approach 100% capacity. So we still expect that 6 to 8 month kind of a ramp up period. But again, with Tru and 3 and the benefit of the experiences we're gaining on Train 1, they're identical designs.
It gives us a little bit of a head start in terms of that ramp up for the second two trains.
Second question on 10 gs future growth project. Maybe I'm wrong, but my current assumption is that if I have, say, dollars 10 on the transportation cost and 5% discount on the price realization to brand price and assume a 20% 18% royalty and 30% income tax. It looked like even at $80 brand, I only get maybe less than 10% internal rate of return for the full project. Just want to see whether you can comment on that, whether that internally that you guys looking for a much better return? And if it is $80 I mean, why we will sanction the projects?
So I think our economics are a little bit different than Paul. I can't get into details of the fiscal terms that we work under with the contract, but we do see a better rate than what you're seeing. The transportation costs are quite good with CPC. Of course, with FGP, some portion of the throughput would have to go by rail, but it's going to be within the envelope of what we've already moved by rail prior to the expansion of CPC. So we're quite comfortable with that.
When we look at Gorgon overall sorry, FGP overall, I think there's a couple of things in terms of the economics. We have a very good understanding of this reservoir. It's largely been de risked. We've been operating it for 23 years. We have a very strong operating organization and maintenance organization there that's given us very high reliability.
So between the good reservoir models and our understanding of that reservoir as well as the operation and reliability we get from the facilities, this is a very good project for us in terms of the scale and the amount of capacity it adds. We also see that the market conditions right now are favorable and the project is ready for execution. As we've talked about, the engineering is well advanced, over 50%. The procurement is 67%. We have a very good understanding of what it's going to take to execute this project, and we've got a lot of the infrastructure already in place because effectively this builds on the infrastructure that's already in Tengiz.
So we see it as a relatively low risk project from all those factors. In terms of the opportunities, though, we see a lot of upside opportunity. We've done a great job in the past at Tengiz, and we've really got a proven track record of extracting incremental value out of the infrastructure once it's installed. If you look at SGP, for example, the 2nd generation plant that started up in 2,008, this really tested the new technology that's being used at FGP. And since startup, we've been able to increase the capacity of that facility by 22% over nameplate, which gives us a lot of incremental capacity.
FGP is actually simpler in terms of the processing facilities than SGP, and we would expect to see similar types of upside opportunity. There's also upside when you look at the infill drilling that FGP puts in place and FGP carries incrementally large gas handling capacity more than what's required right now. So as the reservoir pressures continue to decline, not only does it help stabilize the platform, but we take that additional gas handling capacity and use it on existing facilities today and help handle that increasing gas oil ratio into the future. So there's a lot of upside benefits that are yet to come. Of course, when we talked about the opportunity for contract extensions, we feel this is good for the company as well as ourselves.
Now there's other assessments out there like WoodMac. Many of you may have seen it. There's a number of areas where we see some differences in our view and their view. As I said, we have a very well matched accurate reservoir model, history match model. We have a faster ramp up on the project after completion.
We also have a faster decline on the reservoir if we weren't doing the project and what WoodMac is counting on both of those would drive value into the project. And finally WoodMac has almost twice as many wells in their forecast than we carry in our development plan. So those are some key differences I would point out as well as some of the upside potential we see with this project. Thank
you. Our next question comes from the line of Doug Leggate from Bank of America Merrill Lynch. Your question please.
Thanks. Good morning everybody. I wonder if I could have one for thanks. I wonder if I could one for Pat and one for Jay. Pat, I am not quite sure how to ask this one, but as a follow-up to Paul's question about deferred tax, one of your competitors, ConocoPhillips, gives some sensitivities about what the impact of deferred tax is?
It's quite meaningful. And they say on earnings, every $10,000,000,000 on cash flow, however, up to a certain level like $60 oil, it's about $2,500,000,000 for every $10 I'm guessing it's the same kind of thing you're getting at. I'm wondering if you could give some sensitivities around just exactly that issue because obviously the deferred tax credit back is could be quite material.
Yes. Doug, it's a great question. I'm not prepared here to give you kind of a sensitivity around it. It is one of the primary areas of exploration, I would say, as we go through our business planning cycle here, over the next couple of months. It's a critical element for us to understand jurisdiction by jurisdiction what the price sensitivity is, over a variety of price levels.
And so it's something I don't have today, but it's something we are investigating ourselves. And in the future, we would be in a better place off of this current business plan that we're putting together to be able to address that question.
My guess this is an observation, but my guess is, including myself, a lot of folks are scrambling to understand that because I think it could be a big delta on full expectations of your future cash flow. My follow-up is really for Jay and I don't know, Calorie said you can answer this Jay, but my understanding is John was recently in New York over the last several months and he's talking about the longer term spending restrictions, if you like, or the level at which he expects to see beyond your current sort of 5 year planning horizon. And more importantly, I've indicated that the unconventional portfolio could really become a very large part like 25% of the company by the middle of the next decade. I'm just wondering if you can frame that in terms of implications for additional long cycle projects and further my understanding of that is accurate?
Well, I think John's comments about unconventional becoming a larger and larger part of our company are valid. We gave you a capital range of $17,000,000,000 to $22,000,000,000 for next year. We have both TCO and expansion of our unconventional built into that number already. We're actually getting very granular in our planning of capital allocation across all the assets in the company and making sure that that capital is flowing to where we expect to get the highest return. Unconventional with the de risking that we've been able to do in particularly in the Permian and then the way we're using best practice in one field to spread to all the others we have, the Marcellus, the Permian, the Duvernay, Vaca Muerta is really showing benefits right across our unconventional portfolio and we're quite excited about the role this is going to play going forward.
At the large major capital projects, we will still have some. That's an important part of our portfolio, but we're going to take a measured approach to these. We're only going to be approving the ones that represent the best value for us and it's going to be in balance with the other opportunities we have as we maintain a very disciplined capital program going forward.
Thanks, Doug.
To be clear to you, just a point of clarification, that 25% number is broadly right, but it's a global number, not a U. S. Number?
Yes. Yes.
Great. Okay. Thank you.
Thank you. Our next question comes from the line of Blake Fernandez from Howard Weil. Your question please.
Folks, good morning. Jay, I realized you went through the execution readiness on Tengiz. I guess my question is really around the potential for that $6,200,000,000 of contingency to maybe not even come in at that level? I mean, I realize you're pretty well along on several fronts, but is there an opportunity to lock in costs at this point? And I guess I'm just trying to understand is there a potential to mitigate the risk of that 6.2% coming to fruition?
Absolutely, there's a chance to mitigate the risk. I mean, what we really try to do is both the reasonable and as practical realistic, I should say, in our view of what contingency is required on these very large projects. And this is based on our past, but also the industry experience in executing these projects. But then what we've tried to do is take our experience on other very large projects like Gorgon and Wheatstone as well as projects we've done in Tengiz and build those in. We've looked ahead and said these are the areas that cause us difficulty on these projects and we've tried to mitigate each one of those.
And I won't go through them in detail again, they're in the slides, I've talked about them before. But engineering represents one of the biggest challenges and our work to advance the engineering before FID, but also advance the engineering before we start the execution. Before we cut the first steel for any of the fabrication, our models will be complete at the 90% point and design assurance verified before we start any of the actual fabrication work on facilities. And we've done a tremendous amount of work on the design assurance reviews and we're working to make sure the procurement is advanced so that when we start the execution in the field, we know that we'll be able to move through that execution smoothly and in sequence. We think all these brought together along with our experience in Kazakhstan is going to help us really stay focused on mitigating any use of that contingency.
Contingency is expected to be used. What we're trying to do is reduce the risk and uncertainty so that we can minimize how much of it we do have to use.
Got it. I'll leave it there. Thank you.
Thanks, Blake.
Thank you. Our next question comes from the line of Ed Westlake from Credit Suisse. Your question please.
Yes. Good morning. I guess first question just around CapEx and OpEx. You've been making some good progress and you've got these downward arrows suggesting that in the second half of the year, we'll still see further progress. I'm just wondering maybe just give some update as perhaps where OpEx and SG and A, whether the new bottom of that cost structure could get to?
Well, I think on the capital side, we've given you everything that we anticipate at this point in time. Right now, we're sitting at the midway part of the year, trending on $25,000,000,000 sort of range. We think that's where we could end possibly a little bit lower than that. We're actually trending on $24,000,000 at the 6 month mark. We're thinking $25,000,000 maybe I'm sorry, 24 maybe where we end the year.
So somewhere between $24,000,000,000 $25,000,000,000 I think is the appropriate level for you to think about. And then in terms of 2017 2018, we've given you the range there of the $17,000,000,000 to $22,000,000,000 But obviously, we need to be market responsive. And so right now, we're thinking it's towards the lower end of that range. And if in fact the market doesn't move prices anywhere off of where they are today, we'll probably be lower than that or certainly at the very low end of that range. So that's as much guidance as I can give you on capital at the moment.
We're rolling up the business plans and we'll have more to say as we get towards the end of the year. On operating expense, our target really, we came down on operating expense $2,000,000,000 between 2014 2015 and our target is to come down another $2,000,000,000 between 2015 2016. We have a number of organizational impacts that have occurred through the first half of this year, but there will be more that will come in the second half of this year. And we also continue to work through the supply chain. We've got another set of targets internally for continued effort to reduce costs through the supply chain.
And then a question for Jay. One of the criticisms, I guess, with the majors which you kind of have addressed in Slide 12 on the Permian is the relative costs and EURs. I mean, you have I think last year at the Analyst Day, what I see, it was $7,100,000 And now you're talking about some of the average wells and some of the plays being 5,600,000. And your EURs, I think, at the Analyst Day were, I guess, 9.60 in the Delaware and 850 in the Midland. But obviously, the PURA plays who've been able to, I guess, get out in the front foot in terms of press releases are doing a lot of work with completion technology to boost the U.
R. So maybe just give us some color as to how you see your competitive positioning relative to, I guess, a lot of Deep Blue, just the other side of the gate and even in some of the same wells as you?
I think we're now fully competitive with these other players. And we may not be flashy, but we're steady. We have taken all these learnings in. We've been very methodical in our approach and very systematic. Our goal, as I said before, is to be fully competitive on an operating basis, so that when you add in the advantage royalty position, it gives us a clear incremental value proposition over competitors.
We'll continue to stay focused on this. And as I said, we're ramping up the number of company operated rigs, but we're going to do so in a manner that allows us to maintain those efficiencies. The one other thing I'd say is that our current view is that we're building infrastructure into some of these initial development projects. And as that infrastructure comes into play, it provides a solid foundation for us to continue to incrementally improve economics as we move forward.
Thank you. Thanks, Ed.
Thank you. Our next question comes from the line of Doug Terreson from Evercore ISI. Your question, please.
Good morning, everybody.
Good morning.
Pat, a few of your competitors recently committed to new capital management plans and performance metrics by which you plan to be held accountable in the future. And on this point, you guys have had a pathway to improve returns in your materials for a few quarters now, and you've clearly made progress on the cost side based on today's results and I think it was Slide 18 or so. So my question is, if oil prices and financial performance recover in 2016 2017, can you envision a scenario whereby your financial priorities might shift for an intermediate term period with, say, return of capital to shareholders having greater priority than spending, for instance? Or do you feel that between the cyclical timing and the low cost that we have today and the quality of your portfolio, the higher spending would almost surely be in the best interest of shareholders. So the question is about how you weigh the different financial options in the recovery scenario.
Yes. Doug, I mean, we've had the same financial priorities for a long period of time. Dividend return to shareholders being 1st and then reinvestment in the business second and then having a prudent financial structure being 3rd. And I don't see those priorities changing going forward. We're going to obviously work to balance those priorities under the circumstances that are presented to us.
But I do think I don't see that there is a significant C and E increases coming for us. I think we're going to increase our dividend when cash flow permits it. We're going to make the investment profile that we've talked about where we're moving to shorter cycle, higher return projects and not as many of the long duration of return lower return projects. FTP, WPMP is the only significant project that we had taken to FID. We do see additional major capital projects in our future, but they're not going to come with the same pace that we have had most recently here.
We want to be much more ratable and predictable in our capital program. And we are going to have to take some of the cash that we're generating in the future and use it to restore our balance sheet.
Sure. So thanks for the clarity and the update.
Thanks Doug. Okay. Thanks Doug.
Thank you. Our next question comes from the line of Neil Mehta from Goldman Sachs. Your question please.
Hey, good morning guys. Just wanted to get an update on 2 areas of disruptive production. First is the neutral zone and the second is Nigeria recognizing the latter could have some sensitivities. What update can you provide on the return of production?
So in a partition zone, this is really an issue between the Kingdom of Saudi Arabia and Kuwait. They continue to engage to work this forward. Our view is that we would like to see a return to production. That's what we advocate. But in the meantime, what we've done are two things.
We've tried to bring all the preservation work and maintain the field in a state of readiness, so it can be restarted. We've also done quite a bit of work to understand and use the opportunity with our technical people to model the entire field and look for efficiencies that we can build into this field when it restarts and we've been quite successful in some of the planning that we have for the restart. We've also been bringing our cost structures down and there'll be more of that to come as this continues forward. In terms of Nigeria, this is an area where we've operated for a long time. There are some issues there.
The government is working these issues. Our priority is on protecting people and making sure that we protect our operations. But I really won't say too much more about it other than this is an issue that continues to be addressed by the government.
And if I can ask a quick follow-up here on Pat, on your comments on return of capital, for the last 2 to 3 decades, you've raised the dividend every year. Are you still on track to do that in 2016? And just if you can comment on broader strategy around dividend growth?
Right. What I can say is that we're fully aware of the 28 year annual dividend payment increase. We're also fully aware that an increase needs to occur in 2016 if we are to keep that pattern alive. The board fully understands the value of the dividend increase and they understand the value of growing the dividend over time. So the Board will be looking at cash generation and our ability from a sustainable sense to support a higher dividend going forward.
I guess I would just reiterate, we do see our cash flow circumstance improving over time here. We've got the confidence in our future growth in production. We've got confidence in our future cash generation. I'll take you back to the $2 per barrel margin increase that we showed at the Security Analyst Day on the portfolio. Assuming flat commodity prices, that's the margin accretion that we get out of these LNG projects predominantly.
It raises the cash margin on the entire portfolio. And we also believe that we can compete very successfully and sustainably over time here with a much lower capital program because we've got assets, for example, like the Permian and other unconventionals. So we feel very comfortable about what our future holds.
Great. Thank you.
Thank you. Our next question comes from the line of Evan Caliente from Morgan Stanley. Your question please.
Hi, guys. Good afternoon, everybody. Hi, Adam. Jada, maybe a follow-up on Paul's prior question on Tanguis. I mean, it really gets to this concern that it's a lower return project given future lease expiry or otherwise.
Not really asking for confidential terms, but can you share any expected project return of sanction or how it compared to other projects, while gating in the portfolio even maybe by tier?
I can't really get into divulging our economics and our view of it other than to say we have been very disciplined our capital. We're putting that capital where we believe it's going to give us a good return. We look at a lot of things and we consider earlier. Ultimately, the economic value of this project will be a function of the prices realized over the period of time between now and the end of the concession. But we're taking a lot of steps to make sure that we're building as much value into this as we can.
We see it as an attractive project.
Great. Maybe just a brief follow-up, if I could. What is the percentage of total project financing targeted here? Just to help better understand what the future cash flow at least out the door look like?
Well, the financing is really in place as an assist. The entire project is not being funded by the financing. We have a combination of co lending, we have a bank facility and we have the bond issuance. So that combination coupled with the cash generation of TCO, which is actually quite strong, should provide sufficient funding for the project as well as ongoing value to the
shareholders. Thank
you. Our next question comes from the line of Ryan Todd from Deutsche Bank. Your question please.
Great, thanks. Maybe one follow-up on the Permian. You have a chart there on the slides, which I think is again relative to the Analyst Day presentation, showing the multiyear outlook for growth in the Permian. If you think about the assumptions that are in that chart both in terms of activity levels and well performance, how would you say that things are trending in the basin right now relative to your assumptions are the wells performing better than assumed in the base case there, activity level similar and where would the bias be? Is there an upwards or downward bias do you think for that multiyear outlook?
Yes. So you can see the red line shows where we actually are relative to that view and we're on plan with the initial relative to that view and we're on plan with the initial growth there. And as we said, we saw about over 20% growth in the Permian relative to last year. Now that's done even with less rigs. We're running about the same number of rigs we expected on the company side.
Our non operated rigs are less, but we're actually accomplishing our objectives with fewer rigs. We're going to be going from 6 rigs 10 rigs by the end of this year, so we're staffing up and ramping up our activity level. I would say the bias on this is upward going forward.
Okay, thanks. And then maybe if I could switch gears to the Gulf of Mexico. I mean, you've had a number of different projects in various stages of appraisal or development there. Any thoughts on how those resources are shaking up where the Gulf of Mexico how you see those types of projects stacking up potentially within your portfolio going forward? And maybe one specific one, one of your partners that was in the joint development project, I think for Tyre Guadalupe Gibson and those recently impaired leases at this field.
Is that project still on plan going forward or is that one that you guys may be walking away from?
So I think of the projects in kind of 2 categories. We've got an existing set of de flutter projects that are already in operation in the Gulf of Mexico and they are very profitable. And more than that they provide a good platform for additional investment as we talked about earlier in the presentation. Going forward, the key really is getting our development cost down, and we're very focused on doing that in a couple of ways. Our deepwater drilling has improved fairly substantially.
If you look at just in the last year or so, we've seen 30% faster drilling rates in the deepwater. And with the cost of rigs, that has a big impact. As we move forward, we expect to see our rig costs go down as well as the rates of drilling progress go up. We're also looking at the facilities and getting them right sized. What I mean by that is rather than chasing for peak production, for example, we may go to smaller facilities, have a longer plateau of production, higher capital efficiency.
So as we look at driving the cost per barrel, the development costs down, I think that's what's going to be required for new projects to be competitive with other opportunities in our portfolio. Once these projects are on, they have relatively low operating costs, we get good margins out of them. It's just the time between the initial exploration program and development wells and ultimately the production that burdens these projects from an overall financial return standpoint. In terms of the Tiber that you asked about, this project is still under assessment. I really don't want to comment too much further, but we're evaluating it.
There may be some additional appraisal work to do, and then we'll be putting that against some of the other opportunities that we have. We do think the deepwater represents a good resource base and it is important for meeting global demand in the future. So we think production from this area will continue. But as I said, our focus is on driving those development costs down so that these projects are competitive with other opportunities in the portfolio.
Thanks, Ryan.
Okay. Thanks.
Thank you. Our next question comes from the line of Roger Read from Wells Fargo. Your question, please.
Thanks. Good morning.
Good morning. Good morning.
I guess just a quick kind of follow-up on the CapEx side. So look like you're going to understand this year potentially at least on track for it and you think about the guidance of 17% to 22% over the next couple of years. Should we think about the benefits this year or something that are transitory or something that are looking a little more permanent and then maybe either get more for a 17% to 22% or you can potentially underspend 17% to 22% as we think about the next 3 years?
Yes, Roger. I think one of the primary drivers in moving from the 2016 circumstance to 2017 and beyond is the trailing off of these projects under construction. I mean, just the LNG projects, Corrigan and Wheatstone, for example. I mean, that is a significant reason behind the drop off in the capital spending between the years. But also going forward, as we've talked about the portfolio shift that we have, where we have a lot more of our future investment coming forward in the shorter cycle Permian based activity as opposed to the long cycle and large duration major capital projects, that's really what drives the change in the absolute level of spending.
We've made a commitment as well. There's an affordability component here. We've made a commitment as well to get cash balanced in 2017. And because of the opportunity that we've got both in the brownfield extensions as well as in the Permian unconventional like activity, we believe we've got a very competitive capital program at a $17,000,000,000 range. So I think of it as being a sustainable sort of capital level under prices that we have today.
Right. No, I understood sustainability. I was more just trying to understand if is the fact that you're tracking under the 25 due, I guess, more to the large projects that do come to an end? Or are you seeing an actual improvement in sort of underlying spending, service costs, equipment costs, whatever they are? Trying to think about is 17% to 22%, should it really be maybe 15.5% to say 20% or something like that on an apples to apples comparison?
Yes. Building on what Pat said, I think there's a lot of things that drive capital spending and it can be everything from our current price environment to foreign exchange rates. But what we've really focused on in this near term have been 2 things. 1 is driving down the pricing from our vendors and contractors. That's probably more transitory.
But we've also been very focused on building efficiency in how we conduct our operations, and we've talked about that in previous calls and at the SAND meeting. That work continues across the business. And as we drive more and more efficiency into our spend, we own that, we'll be able to retain that going forward. I think the other big area for us is improving the execution of projects. And it's partly doing things better internally, and I've talked about what those things are, they're on that slide, but it's also taking advantage of market conditions like we're in now where we can get the best yards working on our projects, we're not competing for yard resources and contractor capabilities.
We can get the A team on these projects and that really helps us execute better and that's sustainable through this period.
Thanks, Roger. Thanks.
Thank you. And our final question comes from the line of Brad Heffman from RBC Capital Markets. Your question, please.
Hi, Brad.
Hi, everyone. I know we're past the top of the hour, so I'll keep it short. I was just curious on the impairment commentary in the prepared remarks. I think weaker reservoir performance was mentioned. Obviously, we're all used to seeing price related impairments at this point, but I was curious if you could put a finer point on what assets that related to, is it all legacy stuff or is it anything from major projects over the past few years?
Yes. I mean, there were multiple assets involved, but the largest single contributor here was Papatera in Brazil.
Yes. So Papatera is one where we've been disappointed in the performance of this asset. We have gone ahead and seconded a number of our Chevron people into the operator's team. We're working with the operator to determine not only what is happening with the reservoir, but also where we go from here. So we'll give you more update at some point in the future, but at this point in time, it's largely around Popatera and the performance.
Thanks, Brad.
Okay. I think that wraps us up for the conference call here for the Q2. I appreciate everybody's interest in Chevron and appreciate your questions in particular. Thanks very much.
Ladies and gentlemen, this concludes Chevron's 2nd quarter 2016 earnings conference call. You may now disconnect. Good day.