Chevron (CVX) Q2 2016 Results - Earnings Call Transcript

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Chevron Corp. (NYSE:CVX)

Q2 2016 Earnings Call

July 29, 2016 11:00 am ET

Executives

Patricia E. Yarrington - Chief Financial Officer & Vice President

James William Johnson - Executive Vice President, Upstream

Frank Mount - General Manager, Investor Relations

Analysts

Philip M. Gresh - JPMorgan Securities LLC

Paul Sankey - Wolfe Research LLC

Paul Y. Cheng - Barclays Capital, Inc.

Doug Leggate - Bank of America Merrill Lynch

Blake Fernandez - Howard Weil

Edward George Westlake - Credit Suisse Securities (NYSE:USA) LLC (Broker)

Douglas Terreson - Evercore ISI

Neil Mehta - Goldman Sachs & Co.

Evan Calio - Morgan Stanley & Co. LLC

Ryan Todd - Deutsche Bank Securities, Inc.

Roger D. Read - Wells Fargo Securities LLC

Brad Heffern - RBC Capital Markets LLC

Operator

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.

Patricia E. Yarrington - Chief Financial Officer & Vice President

Okay. Thank you very much, Jonathan. Welcome to Chevron's second 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 two.

I'll begin with a recap of our second quarter 2016 financial results, and then Jay will provide an update on our Upstream business prior to my concluding remarks.

Turning to slide three, slide three provides an overview of our financial performance. The company's second quarter loss was $1.5 billion or negative $0.78 per diluted share. Included in the quarter were impairments and other charges of $2.8 billion. 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 million and foreign exchange effects of $279 million, earnings for the quarter totaled $661 million 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 $2.5 billion. And our debt ratio at quarter end was approximately 23%. Our net debt ratio was a bit under 20%.

During the second quarter we paid $2 billion 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 four, cash generated from operations was $2.5 billion during the second quarter and $3.7 billion year to date. Upstream cash generation was stronger than the first quarter, commensurate with rising crude prices.

Working capital effects of $2 billion and $2 billion 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 $1.3 billion, 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 $4.5 billion, a decrease of over $3 billion from second quarter 2015 and down more than $1 billion from the first quarter of 2016.

At quarter end our cash, cash equivalents, and marketable securities totaled approximately $9 billion. And our net debt position was $36 billion.

Turning to slide five, slide five compares current quarter earnings with the same period last year. Second quarter 2016 results were $2 billion lower than second quarter 2015 results.

Special items, primarily the absence of the second quarter 2015 gain on the sale of Caltex Australia Limited, partially offset by the second quarter 2016 gain on the sale of New Zealand marketing, reduced earnings by $1.4 billion between periods. In both quarters depreciation expense was impacted by impairments and other charges.

The swing in foreign exchange impacts improved earnings by $530 million 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 million 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 million, primarily driven by lower worldwide refining margins, partially offset by lower operating expenses.

Turning now to slide six, I'll now compare results for the second quarter of 2016 with the first quarter of 2016. Second quarter results were $745 million lower than the first quarter.

Net special items for impairments, project suspensions, and other related charges decreased earnings by $2.2 billion between periods. Foreign exchange created a positive earnings variance of nearly $600 million between periods.

Upstream results, excluding special items and foreign exchange, increased approximately $1.2 billion 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 million, 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?

James William Johnson - Executive Vice President, Upstream

Thanks, Pat. I'll start with second quarter 2016 production and then provide an update on a few of our key Upstream projects.

Slide seven compares the change in Chevron's worldwide net oil equivalent production between the second quarter 2016 and the second quarter 2015. Net production decreased by 68,000 barrels a day between these quarters, yielding first half 2016 production of 2.6 million barrels a day.

Shale and tight 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, Chuandongbei, 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 Partitioned 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 eight 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 Partitioned Zone would be restarted by mid-year, which hasn't happened. As a reminder, in the first quarter of 2015 this field produced over 75,000 barrels a day, Chevron's 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 third quarter will be adversely impacted by a large number of turnarounds, including the second 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 1 and 2, and all three trains at Chuandongbei. We are 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 2.65 million to 2.7 million barrels per day.

Turning to slide nine, 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 Train 2 and Train 3. Construction on Train 2 and Train 3 is progressing very well. We expect first LNG from Train 2 early in the fourth quarter and from Train 3 in the second quarter of 2017.

At Wheatstone, our outlook for first LNG remains mid-2017 for Train 1. The cleanup and testing of all nine 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 startup activities. Train 2 construction work is also progressing per plan, with startup expected six to eight 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 four LNG and seven 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 third quarter.

At Chuandongbei, 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, Mafumeira Sul, or Bangka.

Turning to slide 11, our next capital priority is to fund high-return short-cycle base and shale and tight investments. First 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 second quarter 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've said before, one of our primary benchmarking metrics for our Permian assets is development cost per barrel. Since the second quarter of last year, we've reduced our unit development costs 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 $5.6 million per well, which is a 25% 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 100th company-operated horizontal well in 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 startup of the eighth well. The first 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 and 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 billion barrels of oil equivalent.

Turning to slide 15, FGP/WPMP is estimated to cost $36.8 billion, which includes $27 billion for facilities, $3.5 billion for wells, and $6.2 billion 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 first 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 counter cyclical 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 in-field 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.

Patricia E. Yarrington - Chief Financial Officer & Vice President

Okay. Now turning to slide 18, we are delivering on our committed spend reductions. You'll note the steep reduction in quarterly C&E average over the past three years. Year to date, capital expenditures are down 31% when compared with 2015. We're on a trend line for 2016 C&E of $25 billion or less.

For 2017 – 2018, we anticipate capital expenditures between $17 billion and $22 billion. If the current price environment persists, we will revisit the bottom end of the range, as our primarily 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 $2.9 billion 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 $1.4 billion, 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 billion to $10 billion target for total proceeds over this year and next. And as I said last quarter, we have line of sight on around $2 billion 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're eminently doable. We believe they are a realistic part of our cash balancing program.

Looking out the next 12 months 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 dividend, 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?

Question-and-Answer Session

Operator

Certainly, thank you. Our first question comes from the line of Phil Gresh from JPMorgan. Your question please.

Philip M. Gresh - JPMorgan Securities LLC

Hey, good morning.

Patricia E. Yarrington - Chief Financial Officer & Vice President

Good morning.

Frank Mount - General Manager, Investor Relations

Hey, Phil.

James William Johnson - Executive Vice President, Upstream

Good morning.

Philip M. Gresh - JPMorgan Securities LLC

Thanks for all the color in the slide deck today. My two quick questions are going back to the Analyst Day and then 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 million to 3.0 million [barrels per day] target generally still held at that point in time. Obviously there has been a lot of transitory items this year and then there are some asset sales. 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.

James William Johnson - Executive Vice President, Upstream

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 the 2% into the 2% to 4% range (sic) [zero to 4% range] because of the cutbacks in capital. But we still 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.

Philip M. Gresh - JPMorgan Securities LLC

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?

James William Johnson - Executive Vice President, Upstream

We'll give further updates on our production targets I think at the 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 four additional rigs. So that's going from six 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. And we feel quite confident we can do so.

Frank Mount - General Manager, Investor Relations

Thanks, Phil.

Philip M. Gresh - JPMorgan Securities LLC

Thanks.

Operator

Thank you. Our next question comes from the line of Paul Sankey from Wolfe Research. Your question please.

Paul Sankey - Wolfe Research LLC

Hi. Good morning, everyone.

Frank Mount - General Manager, Investor Relations

Good morning, Paul.

Paul Sankey - Wolfe Research LLC

I think I've got the longest term question I've ever asked here, which is the Kazakh concession expires in 2032. Is that correct?

James William Johnson - Executive Vice President, Upstream

Yes, 2033.

Paul Sankey - Wolfe Research LLC

2033. Is that included in your economic assumptions as a sort of end point for the – I mean I know it's kind of crazy. But obviously if you're investing for stuff in 2022, 10 years, 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?

James William Johnson - Executive Vice President, Upstream

Yeah. We base all of our economics and 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.

Paul Sankey - Wolfe Research LLC

Got it. Thank you, Jay. Nearer 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.

Patricia E. Yarrington - Chief Financial Officer & Vice President

Right.

Paul Sankey - Wolfe Research LLC

Is there anything special?

Patricia E. Yarrington - Chief Financial Officer & Vice President

Yes, I'd mention two things. I mentioned them in the official comments. One is working capital and the other is deferred tax. And on a year-to-date basis both of them are worth about $2 billion 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 carryforwards. 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 you think about this impact, and it's pretty significant on a year-to-date basis. Again, $4 billion across the two of those.

Paul Sankey - Wolfe Research LLC

Yes.

Patricia E. Yarrington - Chief Financial Officer & Vice President

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.

Frank Mount - General Manager, Investor Relations

Thanks, Paul.

Paul Sankey - Wolfe Research LLC

Could I just ask a quick follow-up? Sorry. The working capital effect, isn't that from prices going up during the quarter? So wouldn't it – why would it reverse if prices went further up from here?

Patricia E. Yarrington - Chief Financial Officer & Vice President

So I mean a 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.

Paul Sankey - Wolfe Research LLC

Yes.

Patricia E. Yarrington - Chief Financial Officer & Vice President

We obviously are being impacted by lower activity and then just changes in prices and cost structures.

Paul Sankey - Wolfe Research LLC

Thanks, Pat.

Frank Mount - General Manager, Investor Relations

Thanks, Paul.

Operator

Thank you. Our next question comes from the line of Paul Cheng from Barclays. Your question please.

Paul Y. Cheng - Barclays Capital, Inc.

Hey, guys. Good morning.

Frank Mount - General Manager, Investor Relations

Hey, Paul.

James William Johnson - Executive Vice President, Upstream

Hey, Paul.

Paul Y. Cheng - Barclays Capital, Inc.

Jay, two question 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 third quarter and Train 3 will be the first quarter 2017. And also I think that the historical data that you guys are suggesting 3 months to 6 months of the startup period or the ramp-up period. Now talking about 6 months 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?

James William Johnson - Executive Vice President, Upstream

Paul, couple things. We've always said that our expectation is that Train 2 and Train 3 would start up at roughly six-month intervals. And we're pretty much still on that plan. We started up the first train in March, so we're projecting early in the fourth quarter 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 Train 2 and Train 3. 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 six to eight months. We base that looking at LNG projects around the world. That's a normal ramp-up period. As I've said before, it's not so much that you're on this smooth curve from startup 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 six to eight-month ramp-up period. But again with Train 2 and Train 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

Paul Y. Cheng - Barclays Capital, Inc.

Second question on Tengiz future growth project. Maybe I'm wrong, but my current assumption is that if I have, say, $10 on the transportation cost, and 5% is on the price realization to Brent price, and assume a 20 – there's 18% royalty and 30% income tax, it looks like even at $80 Brent, I only get maybe less than 10% internal rate of return for the full project. I just wanted to see whether you can comment on that, whether that internally that you guys looking for a much better return. And if it's $80, why will you, say, sanction the projects?

James William Johnson - Executive Vice President, Upstream

So I think our economics are a little bit different than yours, 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 – or sorry, FGP overall, I think there are a couple things in terms of the economics. We have a very good understanding of this reservoir. It's largely been derisked. 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 second generation plant, that started up in 2008, 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 increase in 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 are other assessments out there like Wood Mac [Wood Mackenzie]. 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 than what Wood Mac is counting on. Both of those would drive value into the project. And finally, Wood Mac 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.

Paul Y. Cheng - Barclays Capital, Inc.

Thank you.

Frank Mount - General Manager, Investor Relations

Thanks, Paul.

Operator

Thank you. Our next question comes from the line of Doug Leggate from Bank of America Merrill Lynch. Your question please.

Doug Leggate - Bank of America Merrill Lynch

Thanks. Good morning, everybody.

Frank Mount - General Manager, Investor Relations

Good morning, Doug.

Doug Leggate - Bank of America Merrill Lynch

I wonder if I could have one for – thanks. I wonder if I could – one for Pat and one for Jay. Pat, I'm not quite sure how to ask this one, but it's a follow-up to Paul's question about deferred tax. One of your competitors, ConocoPhillips, gave some sensitivities about what the impact of deferred tax is. It's quite meaningful. They say on earnings, every $10 is like $1.5 billion on cash flow. However, up to a certain level, like $60 oil, it's about $2.5 billion 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 could be quite material.

Patricia E. Yarrington - Chief Financial Officer & Vice President

Doug, it's a great question. I'm not prepared here to give you 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'd be in a better place, off of this current business plan that we're putting together, to be able to address that question.

Doug Leggate - Bank of America Merrill Lynch

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 folks' expectations of your future cash flow.

My follow up is really for Jay. And I don't know to what extent you can answer this, Jay. But my understanding is John [Watson] was recently in New York over the last several months and was talking about the longer-term spending restrictions if you like, or the level at which he expects to see, beyond your current five-year planning horizon. And more importantly had 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 whether my understanding of that is accurate.

James William Johnson - Executive Vice President, Upstream

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 billion to $22 billion 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.

As to 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.

Frank Mount - General Manager, Investor Relations

Thanks, Doug.

Doug Leggate - Bank of America Merrill Lynch

To be clear, Jay, just a point of clarification. That 25% number is broadly right. But it's a global number, not a U.S. number?

Frank Mount - General Manager, Investor Relations

Yes.

Patricia E. Yarrington - Chief Financial Officer & Vice President

Yes.

James William Johnson - Executive Vice President, Upstream

Yes.

Doug Leggate - Bank of America Merrill Lynch

Great. Okay, thank you.

Operator

Thank you. Our next question comes from the line of Blake Fernandez from Howard Weil. Your question please.

Blake Fernandez - Howard Weil

Folks, good morning.

Frank Mount - General Manager, Investor Relations

Good morning, Blake.

Blake Fernandez - Howard Weil

Jay, I realize you went through the execution readiness on Tengiz. I guess my question is really around the potential for that $6.2 billion 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 billion coming to fruition?

James William Johnson - Executive Vice President, Upstream

Absolutely there's a chance to mitigate the risk. I mean what we've really tried to do is both be 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 and 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.

Blake Fernandez - Howard Weil

Got it. I'll leave it there. Thank you.

Frank Mount - General Manager, Investor Relations

Thanks, Blake.

Operator

Thank you. Our next question comes from the line of Ed Westlake from Credit Suisse. Your question, please.

Edward George Westlake - Credit Suisse Securities (USA) LLC (Broker)

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 us an update as perhaps where OpEx and SG&A, where the new bottom of that cost structure could get to?

Patricia E. Yarrington - Chief Financial Officer & Vice President

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, yeah, $25 billion sort of range. We think that's where we could end, possibly a little bit lower than that. We're actually trending on $24 billion at the 6-month mark, but we're thinking $25 billion might be – sorry. $24 billion may be where we end the year. So somewhere between $24 billion and $25 billion I think is the appropriate level for you to think about.

And then in terms of 2017 and 2018, we've given you the range there of the $17 billion to $22 billion. 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 billion between 2014 and 2015. And our target is to come down another $2 billion between 2015 and 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.

Edward George Westlake - Credit Suisse Securities (USA) LLC (Broker)

And then a question for Jay. One of the criticisms I guess with the majors, which you addressed in slide 12 on the Permian, is the relative costs and the EURs. I mean you have – I think last year at the Analyst Day, what did I see? It was $7.1 million. And now you're talking about some of the average wells in some of the plays being $5.6 million.

And your EURs I think at the Analyst Day were I guess 960 million [BOE] in the Delaware and 850 million [BOE] in the Midland. But obviously the purer plays who've been able to I guess get out on the front foot in terms of press releases are doing a lot of work with completion technology to boost EUR.

So maybe just give us some color as to how you see your competitive positioning relative to I guess a lot of the people who are just the other side of the gate? And even in some of the same wells as you?

James William Johnson - Executive Vice President, Upstream

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 advantaged 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.

Edward George Westlake - Credit Suisse Securities (USA) LLC (Broker)

Thank you.

Frank Mount - General Manager, Investor Relations

Thanks, Ed.

Operator

Thank you. Our next question comes from the line of Doug Terreson from Evercore ISI. Your question please.

Douglas Terreson - Evercore ISI

Good morning, everybody.

Patricia E. Yarrington - Chief Financial Officer & Vice President

Good morning.

Frank Mount - General Manager, Investor Relations

Good morning.

Douglas Terreson - Evercore ISI

Pat, a few of your competitors recently committed to new capital management plans and performance metrics, by which they 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 in I think it was Slide 18 or so.

So my question is, if oil prices and financial performance recover in 2016 and 2017, can you envision a scenario whereby your financial priorities might shift for an intermediate term period? Let's say a return of capital to shareholders having greater priority than spending for instance. Or do you feel that between the cyclical timing and the low costs that we have today and the quality of your portfolio, that higher spending would almost surely be in the best interest of shareholders? So the question is about how you weigh these different financial options in the recovery scenario?

Patricia E. Yarrington - Chief Financial Officer & Vice President

Doug, we've had the same financial priorities for a long period of time. Dividend return to shareholders being first, and then reinvestment in the business second, and then having a prudent financial structure being third. 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.

Douglas Terreson - Evercore ISI

Sure.

Patricia E. Yarrington - Chief Financial Officer & Vice President

I do think – I don't see that there's significant – see any 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 lower return projects. FGP/WPMP is the only significant project that we have taken 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

Douglas Terreson - Evercore ISI

Sure. So thanks for the clarity and the update.

Frank Mount - General Manager, Investor Relations

Thanks, Doug.

Patricia E. Yarrington - Chief Financial Officer & Vice President

Okay. Thanks, Doug.

Operator

Thank you. Our next question comes from the line of Neil Mehta from Goldman Sachs. Your question please.

Neil Mehta - Goldman Sachs & Co.

Hey. Good morning, guys. I just wanted to get an update on two areas of disrupted 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 to production?

James William Johnson - Executive Vice President, Upstream

So in the Partitioned 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'd have for the restart. We've also been bringing our cost structures down. And there will 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

Neil Mehta - Goldman Sachs & Co.

And if I can ask a quick follow-up here. Pat, on your comments on return of capital. For the last two decades to three 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 the broader strategy around dividend growth?

Patricia E. Yarrington - Chief Financial Officer & Vice President

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.

Neil Mehta - Goldman Sachs & Co.

Great. Thanks, guys.

Frank Mount - General Manager, Investor Relations

Thanks very much, Neil.

Operator

Thank you. Our next question comes from the line of Evan Calio from Morgan Stanley. Your question please.

Evan Calio - Morgan Stanley & Co. LLC

Hi. I guess good afternoon, everybody.

Frank Mount - General Manager, Investor Relations

Hi, Evan.

Evan Calio - Morgan Stanley & Co. LLC

Jay, maybe a follow up on Paul's prior question on Tengiz. It really gets to this concern that it's a lower return project, given future lease expiry or otherwise. I'm not really asking for confidential terms. But can you share any expected project return at sanction? Or how it compared to other projects, while gating in the portfolio even maybe by tier?

James William Johnson - Executive Vice President, Upstream

I can't really get into divulging our economics and our view of it other than to say we have been very disciplined in 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 when we consider the performance of a project. And part of it is the risk we're taking on as well as the potential for additional upside to be gained, and I talked about those 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.

Evan Calio - Morgan Stanley & Co. LLC

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?

James William Johnson - Executive Vice President, Upstream

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.

Evan Calio - Morgan Stanley & Co. LLC

Thanks. I appreciate it, guys.

Frank Mount - General Manager, Investor Relations

Yes.

Operator

Thank you. Our next question comes from the line of Ryan Todd from Deutsche Bank. Your question please.

Ryan Todd - Deutsche Bank Securities, Inc.

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 there? Are the wells performing better than assumed in the base case there, activity levels similar? And where would the bias be? Is there an upwards or downward bias do you think for that multiyear outlook?

James William Johnson - Executive Vice President, Upstream

So you can see the red line shows where we actually are relative to that view, and we're on plan with the initial growth there. And as we said, we saw 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 actually less. But we're actually accomplishing our objectives with fewer rigs. We're going to be going from six rigs to 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.

Ryan Todd - Deutsche Bank Securities, Inc.

Okay, thanks. And then maybe if I could switch gears to the Gulf of Mexico, 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 Tiber-Guadalupe-Gibson and those recently impaired leases in those fields, is that project still on plan going forward, or is that one that you guys may be walking away from?

James William Johnson - Executive Vice President, Upstream

So I think of the projects in two categories. We've got an existing set of deepwater 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 with smaller facilities that have a longer plateau of production, higher capital efficiency. So as we look at driving the cost per barrel and 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 really 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.

Frank Mount - General Manager, Investor Relations

Thanks, Ryan.

Ryan Todd - Deutsche Bank Securities, Inc.

Okay, thanks.

Operator

Thank you. Our next question comes from the line of Roger Read from Wells Fargo. Your question please.

Roger D. Read - Wells Fargo Securities LLC

Thanks, good morning.

James William Johnson - Executive Vice President, Upstream

Good morning.

Patricia E. Yarrington - Chief Financial Officer & Vice President

Good morning.

Frank Mount - General Manager, Investor Relations

Good morning.

Roger D. Read - Wells Fargo Securities LLC

I guess just a quick kind of follow-up on the CapEx side. So looked like you're going to underspend this year potentially, at least on track for it. And you think about the guidance for $17 billion to $22 billion over the next couple years. Should we think about the benefits this year are something that are transitory? Or something that are looking a little more permanent? And then maybe either get more for $17 billion to $22 billion? Or you can potentially underspend $17 billion to $22 billion as we think about the next 3 years?

Patricia E. Yarrington - Chief Financial Officer & Vice President

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, Gorgon 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 this 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 billion range. So I think of it as being a sustainable sort of capital level under prices that we have today.

Roger D. Read - Wells Fargo Securities LLC

Right, I understood sustainability. I was more just trying to understand of – is the fact that you're tracking under the $25 billion 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 it, is $17 billion to $22 billion, should it really be maybe $15.5 billion to, say, $20 billion, or something like that?

James William Johnson - Executive Vice President, Upstream

Building on what Pat said...

Roger D. Read - Wells Fargo Securities LLC

On an apples-to-apples comparison.

Patricia E. Yarrington - Chief Financial Officer & Vice President

Yes.

James William Johnson - Executive Vice President, Upstream

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 two things. One 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 SAM 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.

Frank Mount - General Manager, Investor Relations

Thanks, Roger.

Roger D. Read - Wells Fargo Securities LLC

Great. Thanks.

Operator

Thank you. And our final question comes from the line of Brad Heffern from RBC Capital Markets. Your question, please?

Frank Mount - General Manager, Investor Relations

Hi, Brad.

Brad Heffern - RBC Capital Markets LLC

Hi, everyone.

Patricia E. Yarrington - Chief Financial Officer & Vice President

Hi.

Brad Heffern - RBC Capital Markets LLC

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?

Patricia E. Yarrington - Chief Financial Officer & Vice President

Yeah. I mean there were multiple assets involved. But the largest single contributor here was Papa-Terra in Brazil.

James William Johnson - Executive Vice President, Upstream

Yeah. So Papa-Terra 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 operators' 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 Papa-Terra and the performance.

Frank Mount - General Manager, Investor Relations

Thanks, Brad.

Brad Heffern - RBC Capital Markets LLC

Okay. I'll leave it there. Thanks.

Patricia E. Yarrington - Chief Financial Officer & Vice President

Okay. I think that wraps us up for the conference call here for the second quarter. I appreciate everybody's interest in Chevron and appreciate your questions in particular. Thanks very much.

Operator

Ladies and gentlemen, this concludes Chevron's Second Quarter 2016 Earnings Conference Call. You may now disconnect. Good day.

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