Good morning. My name is Jonathan, and I will be your conference facilitator today. Welcome to Chevron's Third Quarter 20 16 Earnings Conference Call. 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 Yerington. Please go ahead.
Okay. Thank you, Jonathan. Welcome to Chevron's 3rd quarter earnings conference call and webcast. On the call with me today are Bruce Niemeyer, Vice President, Mid Continent Business Unit 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 Q3 2016 financial and operational results, and then Bruce will provide an update on our Permian Basin business prior to my concluding remarks. Slide 3 provides an overview of our financial performance. The company's 3rd quarter earnings were $1,300,000,000 or $0.68 per diluted share.
3rd quarter results included 290,000,000 in special items related to a deferred tax benefit from the U. K. Tax rate change and the receipt of an Ecuador arbitration award. Excluding these special items as well as the positive impact from foreign exchange effects of $72,000,000 earnings for the quarter totaled $921,000,000 or $0.49 per share. A detailed reconciliation of special items in foreign exchange is included in the appendix to this presentation.
Cash from operations for the quarter was $5,300,000,000 and our debt ratio at quarter end was 23.7%. Our net debt ratio was approximately 20%. During the Q3, we paid $2,000,000,000 in dividends. Earlier in the week, we announced an increase in our quarterly dividend to $1.08 per share, payable to stockholders of record as of November 18, 2016. Our annual per share payout for 2016 will be $4.29 per share and represents the 29th consecutive year of growth in the annual per share payout.
We currently yield 4.3%. Turning to Slide 4. Cash generated from operations was $5,300,000,000 during the 3rd quarter and $9,000,000,000 year to date. Year to date working capital effects of $1,300,000,000 $3,100,000,000 in deferred tax items, for example, those associated with tax loss positions, reduced year to date operating cash. These are timing effects.
Proceeds from asset sales totaled $800,000,000 in the 3rd quarter, including the sale of selected Gulf of Mexico assets. These transactions had a minimal impact on earnings in the quarter. Year to date asset sale proceeds are $2,200,000,000 We continue to pursue a number of potential transactions and we remain confident that we can achieve our $5,000,000,000 to $10,000,000,000 target for total proceeds over this year and next. Cash capital expenditures for the quarter were $4,100,000,000 a decrease of $2,700,000,000 from the Q3 of 2015. Year to date cash investment outlays have totaled approximately $14,000,000,000 During the quarter, we advanced $2,000,000,000 to Tengiz Chevroil, or TCO, in support of the FGP project.
This outflow is reflected in our cash flow statement as a borrowing by equity affiliates. This first co lending tranche provides sufficient funding as the project commences. Future advances are expected and the timing will be dependent upon oil prices, TCO's internal cash generation and the project's pace of investment. At quarter end, our cash, cash equivalents and marketable securities totaled approximately $7,700,000,000 and our net debt position was $37,900,000,000 Turning now to Slide 5. Slide 5 compares current quarter earnings with the same period last year.
3rd quarter 2016 results were $754,000,000 lower than Q3 2015 results. Special items, primarily the deferred tax benefit related to the U. K. Tax rate change, the award of an Ecuador arbitration claim and the absence of Q3 2015 asset impairments increased earnings by $535,000,000 between periods. Lower foreign exchange gains decreased earnings by $322,000,000 between periods.
As a reminder, most of our foreign exchange impacts stem from balance sheet translations. Upstream earnings, excluding special items and foreign exchange, were largely flat between quarters as lower crude realizations were offset by lower operating expenses and favorable tax impacts. Downstream results, excluding special items and FX, decreased by $1,000,000,000 primarily driven by lower worldwide refining margins and lower earnings from CPChem. Turning now to Slide 6. Here, I'll compare results for the Q3 of 2016 with the Q2 of 20 16.
3rd quarter results were approximately $2,800,000,000 higher than the 2nd quarter. The absence of Q2 2016 charges associated with special items and the inclusion of 3rd quarter gains from special items increased earnings by $2,700,000,000 between periods. Lower foreign exchange gains reduced earnings by approximately $200,000,000 between periods. Upstream results, excluding special items and foreign exchange, were comparable between quarters, in line with relatively flat Brent prices. Lower operational expenses were offset essentially by lower liftings and adverse tax impacts.
Downstream earnings, excluding special items and foreign exchange, were higher by $255,000,000 primarily resulting from the absence of unfavorable 2nd quarter inventory valuation effects. Prices were generally rising during the Q2, but relatively flat during the Q3. Turning to Slide 7. Here we compare the change in Chevron's worldwide net oil equivalent production between the Q3 of 2016 and the Q3 of 2015. Net production decreased by 26,000 barrels per day between quarters.
Major capital projects increased production by 77,000 barrels a day as ramp ups continued at Gorgon, Jack St. Malo, Shandong Bay and Angola LNG. About half of this bar is Gorgon. Shale and tight production increased by 50,000 barrels per day, primarily due to the growth in the Midland and Delaware basins in the Permian, with all shale and tight basins reflecting year on year growth. More than half of this bar is Permian production.
Our base business decline was 66,000 barrels per day. Production from new wells and other brownfield investments in the base added 39,000 barrels per day and helped hold the overall base decline rate to less than 2%. The sale of our Michigan assets and several assets in the Gulf of Mexico shelf resulted in decreased production of 47,000 barrels per day. Disruptions due to external events accounted for the temporary shut in of 27,000 barrels per day, mainly due to security issues in Nigeria. Our planned turnaround activity was heavier than this time last year, resulting in a decrease of 26,000 barrels per day, the most significant of which was at TCO as we completed the turnaround of the 2nd generation plant.
Based on 9 months of actuals and our forecast for the Q4, we anticipate full year 2016 production will be approximately 2,600,000 barrels per day. Turning now to Slide 8. As we indicated on the Q2 call, we expect to exit the year with barrels per day from the 3rd quarter average. A major contributor, as previously discussed, is TCO's return to production on September 9, following the largest planned turnaround in its history, ahead of schedule, under budget and without serious incidents or injuries. Over the course of 6 weeks, maintenance was conducted on more than 500 pieces of equipment.
At its peak, over 8,800 employees and contractors were on-site for the turnaround. The team worked proactively with over 30 contract companies on all stages of planning, preparation and execution. This was a large undertaking that was exceptionally well executed. The second contributor to volume growth in December is the ramp up of our LNG projects, notably Gorgon. At Gorgon, Train 1 production is stable and Train 2 is now online.
At Angola LNG, the plant reached a rate of approximately 5,000,000 tons per year of LNG. Production has been suspended while minor modifications to reach full capacity are completed. Short duration shutdowns are often experienced as facilities are ramped up to their full capacity. ALNG expects to restart the plant within the next couple of weeks and will continue to ramp up and fine tune the system. Since the initial restart earlier this year, they have shipped 8 LNG cargoes and 16 LPG cargoes.
In addition to LNG volume increases, we achieved 1st production from Vanka in August and expect 1st production from Alder before year end. We also expect continued growth in our unconventionals and from our base business investments. Turning now to Slide 9. At Gorgon, total Train 1 LNG production has been stable at an average rate of 110,000 barrels per day, which is about 5,000,000 tons per year. We are also producing about 6,700 barrels per day of condensates.
As mentioned, Train 2 is running and producing LNG. Production is expected to ramp up over the coming months. We have shipped 17 cargoes to date, and with both trains now running, we expect to ship an average of 2 to 3 cargoes per week. Construction on Train 3 is progressing very well, and we expect first LNG in the Q2 of 2017. At Wheatstone, our outlook for first LNG remains mid-twenty 17 for Train 1.
We are leveraging our experience from Gorgon and are pleased with our progress. All modules for Train 1 and Train 2 are now on-site and the installation of piping, electrical and instrumentation continue as planned. As we have foreshadowed, the delay in module delivery at Wheatstone has impacted project costs relative to the original 20 11 estimate. We now forecast the total project cost at completion to be US34 $1,000,000,000 Chevron's share of the cost to complete the project is included in the $17,000,000,000 to $22,000,000,000 capital guidance range that we have previously communicated for the 2017 to 2018 years. Bruce will now provide an update on our activities in the Permian.
Bruce?
Thanks, Pat. Turning to Slide 10. As we have shared previously, Chevron enjoys a very strong acreage position in the Permian Basin. Our acreage is extensive, covering about 2,000,000 acres. We have major holdings in the best basin locations and enjoy a significant royalty advantage over our competitors.
Our strategy in the Permian is centered on building a large scale asset that delivers strong returns and generates free cash flow. To accomplish this, we have implemented a well factory modeled after the most efficient short cycle operations in Chevron and in industry. The goal of this factory is to create repeatable, high value outcomes at sufficient scale that are material for Chevron. Decisions around many key design elements are consistently implemented. Not only the obvious ones such as horizontal lateral length, well spacing and completion parameters, but also hundreds of other decisions that we face on a routine basis for which we want consistent outcomes.
As we identify and verify improvements, they are quickly implemented into our basis of design. Our pace has been intentionally deliberate to allow us to incorporate the learnings and experience from our own work and that of the industry. The result is a high degree of confidence that we will achieve the outcomes we expect. Our results are competitive and continue to improve. Turning to Slide 11.
You can see Chevron's acreage position in more detail. This slide is a map of the Permian Basin, inclusive of Southeast New Mexico and West Texas. Our 2,000,000 acres are depicted in blue, 1,500,000 of which are in the Midland and Delaware basins. Also depicted on the map are active Chevron operated developments in blue and our non operated development areas in purple. We believe the quality of our acreage position is exceptional with multiple stacked geologic targets.
Today, we estimate that almost 600,000 of our acres have a net value in excess of $50,000 per acre. We have an additional 350,000 acres with a net value between $20,000 $50,000 per acre. The balance of our acreage is a mix. Some is of lower quality, some is still under evaluation, some lacks nearby infrastructure and some requires further appraisal. These estimates are a snapshot that assumes a simultaneous development, a flat $50 WTI price and are burdened with all development and production costs as we see them today.
We're active in several company operated and non operated joint venture development areas. We're currently running 8 drilling rigs on our operated acreage. We're standing up our 9th rig as we speak and expect to be at 10 by the end of the year. Another 10 rigs are currently drilling on our non operated development areas. We prioritize development areas by value, which considers expected ultimate recovery, cost of development, oil gas split, availability of surface infrastructure and our overall certainty of outcome.
Turning to Slide 12. To achieve strong returns, we focus on all elements necessary to generate cash flow, capital efficiency, operating expense and product realizations. The graph in the upper right corner shows development cost per barrel, which in our view is the ultimate measure of capital performance as it incorporates all sub metrics. We have achieved a 30% development cost reduction from 2015, fully inclusive of drilling, completions, facilities and associated G and A. We've accomplished this through a focus on improving expected ultimate recovery, driving execution efficiencies and implementing supply chain savings.
This is delivering capital performance that is competitive with the operators of our joint ventures. The trend of improvement is mirrored in our overall unit operating expense. The lower right graph reflects both the downward trend and competitive performance of our direct lease operating expense and illustrates a significant reduction of 45% from 2015. Our lease operating expense includes all costs required to operate a well and its associated facilities during its life. We expect these wells to produce for decades, so attention to operating efficiency unlocks value.
Additionally, G and A, which is not included in the graph on the lower right, is a component of overall operating expense. Our year to date G and A is $3.50 a barrel declining through the year and more than 20% from 2015. The 3rd critical aspect of cash flow is product realizations. We've leveraged the scale of our core positions to systematically secure cost effective priority access through the entire crude and gas value chain rather than simply selling production at the wellhead. Because of this, we have options available to respond to changing market and industry conditions.
Turning to Slide 13. We expect activity and production from the Permian to grow through the end of the decade. As we discussed in our Analyst Day last March, by the end of 2020, Chevron's Permian shale and tight production is expected to reach 250,000 to 350,000 barrels per day. As you can see on the chart, we have initiated this growth. Production continues to track ahead of expectations and is 24% higher than Q3 2015.
We continually monitor our performance and have the option to adjust the pace of our growth as needed to optimize value from this asset. While growing production is important, we're focused on expanding margins by increasing efficiencies in our operations and on capturing maximum value from the resource base. We believe we're well positioned to make the Permian a legacy asset with strong returns and free cash flow. Now I'll hand back to Pat to discuss spend reductions. Pat?
Okay. Thank you, Bruce. Now on Slide 14, We continue to reduce our spend. You can see on the charts the huge progress that we've made and continue to make in curtailing our outflows. We expect 2016 combined operating expense and capital expenditure outflows to be down more than $12,000,000,000 or more than 20% from 2015.
We expect to meet, if not exceed, the commitment we made earlier in the year to have 2016 operating expenses come in $2,000,000,000 lower than 2015. And our C and E is trending below the guidance range previously provided for this year. We will likely end the year below $25,000,000,000 in capital outlays, in fact, potentially coming in closer to $24,000,000,000 This is a tremendous amount of progress in a relatively short 24 month period of time to reset these key financial parameters consistent with a lower for longer price environment. Turning to Slide 15. I'd like to close with just a couple of points.
First, our financial priorities have not changed. Sustaining and growing the dividend is our first priority. The increase this quarter demonstrates that commitment, which is underpinned by confidence in our future earnings and cash flow growth. 2nd, we are beginning to see evidence of that cash flow growth, notably now that 1 is operating well and Train 2 is successfully online. And with Gorgon's Train 3 and Wheatstone's, Trains 12 planned to come on in fairly rapid succession over the next five quarters.
We have approximately 85% of the production from these five trains sold under long term contracts. And at today's contractual LNG prices, this represents a significant revenue and cash margin boost. 3rd, we have successfully transitioned to a lower price environment. Of course, we are not resting on these recent accomplishments. We will continue to look for opportunities to improve cost and capital efficiency.
We are poised to be a very resilient competitor in a low priced world. Our Permian asset base speaks directly to this. Here we have an abundance of riches in terms of the physical asset base and we are successfully demonstrating the ability to develop this resource in a highly capital efficient returns focused manner. With costs coming down, with C and E and capital intensity coming down, with our major LNG projects and the Permian production coming online to boost cash margins and production, our overall financial picture is set to improve in a meaningful way as we move into 2017. Our objective is to get cash balanced in 2017, assuming $50 Brent prices.
All of these improvements I've just noted, as well as targeted asset sales where we can transact for value, are key components supporting that objective. So this concludes our prepared remarks, and we're now ready to take some questions. Please keep in mind that we do have a full queue and try to limit yourself to one question or perhaps one follow-up if necessary. We'll certainly do our best to get all of your questions answered. So Jonathan, could you open the lines, please?
Certainly. Thank Our first question comes from the line of Jason Gammel from Jefferies. Your question please.
Thanks very much everyone and thanks especially for the incremental disclosure on the Permian. I'd like to direct my question there. Bruce, you mentioned that the funding and development cost was probably one of the most important metrics that you have in the basin. Can you talk about how you're benchmarking yourself against some of the E and P companies in the basin? And how you think that might improve as you get your infrastructure into place?
Thanks for the question, Jason. On Slide 12, we showed finding and development cost per barrel. The lighter bars are the Chevron operated activity and the darker bars are those of our NOJV competitors where we also invest. The that is our best direct benchmarking comparison because we invest in the wells and we're able to see the full value chain that is created. We're able to address the issues directly of financial performance that aren't often available from a less complete data set.
I suppose there's a narrative that a company of our size can't be competitive, but in the case of Chevron, we are. The NOJV partners that are listed on this chart are some of the best in the basin. And you can see on the chart that our performance today is competitive and
improving. That's great. If just as a follow-up, can you maybe address the pace of development that you think you could achieve? I recognize that you've got your projection of volumes through 2020, but with such a huge acreage position, what type of rig program do you think you could ultimately apply in the basin? And then I suppose the other question there would be, just given the position you have, would you maybe consider monetizing some of the position through acreage sales or through joint ventures?
Let me start with pace first. So we are already growing. As I noted, we've initiated growth. In fact, we've added 5 rigs over essentially the second half of twenty sixteen. That's the pace of rig additions of about 1 rig a month.
Production has grown from the Q3 of last year by 24%, further supporting the notion that we're growing. And our pace and rate of additions are intentional. Again, we're focused on returns. I don't feel capital limited in the Permian Basin and our additions are targeted to ensure that we're getting the outcomes we intend and that are supportive of high returns and eventually generating free cash flow. We do expect to grow as you noted.
You can see that on Slide 13. And as we go forward, we have options. We continually monitor our performance and we adjust.
Yes. And Jason, let me just add a thought to that. As you know, we have had a practice when we have had pieces of our portfolio where we felt there wasn't longer term strategic value or we felt others could would offer more value for us than it would obtain in our portfolio, we've been willing to make asset sales and we've had a very routine practice of having asset sales over a long number of years here. I think the key to getting to that point in the decision process though is having a really good understanding of the value of the asset. And in the Permian Basin, there's been a great deal of fluidity in that valuation over the last couple of years.
There's been a great deal of additional appraisal and evaluation work and there's been a great deal of greater understanding, but there still has been significant movement. In some cases, pieces of property have moved up by a factor of 10,000 fold. And that's the kind of thing that you would not want to get on the wrong side of, if in your haste to make a decision about selling an asset. So our process will be to try to do evaluation and appraisal look, get a really good understanding of what this asset valuation is. And to the extent that we don't find it fitting into our longer term development plans, then that of course we would look to other monetization options.
Thanks
Jason. Thank you. Thank you. Our next question comes from the line of Paul Sankey from Wolfe Research. Your question please.
Good morning everyone. Thanks. A follow-up for Bruce on the Permian. How much are you guys spending there annually? Could you give us an idea of the level of CapEx and the outlook for CapEx?
Yes, Paul. We're spending presently in the area of about 1.5 Yes, Paul. We're spending presently in the area of about $1,500,000,000 annually across both the company operated and our non operated joint venture programs.
And so the outlook for that is flat, is it? Or is that going to go up?
I would expect it to go up. At our current pace, we're delivering a growth profile. You can see on Slide 13, what we shared at the Analyst Day last March in terms of production growth, and there will be some growing activity that would support that. We are continually getting more efficient and so the capital invested that we expect going forward will be more efficient as kind of reflected by the finding and development cost trend that we showed on slide 12.
Understood. So if I look at the Tengiz expansion, you're spending previously in September, you'd said $18 per BOE of development cost for I think a $36,000,000,000 investment. Why would you be spending so much less in the Permian at what I think looks like a $10 F and D cost per barrel? Maybe that one's for Pat.
Yes, it is. So Paul, just a couple of things. I mean, if you go back to Slide 13 here, I think we have said that, and we said this back in the salmon throughout the year here that we could see that top light the top end of that light blue portion of the profile there would result in approximately a doubling of our current activity levels. And so we're spending 1.5% here. You can see us potentially doubling that.
And that is kind of the current view that we have. But again, this is an area that we'll update you when we get to the March Security Analyst Meeting. In reference to FGP, the future growth project in 10Gs, I think it's important to know that we are funding both of these projects, both the Permian fully and FGP. We think of these projects, these areas as being absolutely critical growth areas for us. So we're not starving the Permian because we've taken on FGP.
I think what people often miss around FGP is that there would be a tremendous loss of value if we didn't go forward with the wellhead pressure management project because the field would go into decline. It would be in serious decline and that would be loss of value in the legacy asset. We're doing FGP and WPMP together because of synergies. It's a joint development concept. And there's a lot of upside that has not been kind of built into a lot of people's models, I guess, I would say about FGP that relate to debottlenecking.
What we've been able to demonstrate in the past, we hope to be able to do on a go forward basis. There's additional gas handling facilities built in here that will over time allow greater oil production. Contingencies we've talked through about being kind of fully contingent even though we're at 50% of engineering when we took FID. And then, of course, down the road, obviously, we hope that this turns into concession extension. So there's a lot of potential upsides to FGP.
I think Jay did a great job on our Q2 call in kind of running through all of those parameters.
Got it. So what you're saying is the $18 is a very conservative $18 per barrel development cost there is a very conservative number and it would be competitive with the Permian ultimately when all those things are considered?
We think we need both assets in our portfolio, yes.
Thank you. Thank you, Pat.
Thank you. Our next question comes from the line of Paul Cheng from Barclays. Your question please.
Hey guys, good morning. Good morning. Two questions if I could. Bruce on the one is the recovery way that you use to get to that RMB9 billion? Are you using 10%, 12%?
And what do you expect and foresee that, that recovery rate may change over the next, say, 5 years?
Yes. So the 9,000,000,000 barrels is from a portion of our acreage that is currently highly characterized. It varies by horizon and by area in the basin, be it Midland or Delaware Basin. Recoveries are generally single digit. And we know that in a basin or to play at this state of maturity, there is a lot of upside potential.
We have a technology organization that's working hard every day to take the first stage of development and improve upon it much as we have in other asset classes that we operate in and are more mature.
Will you be willing to give in what the forecast that what that recovery rate may look like in 5 years?
No, not at this point.
Okay. Pat, the second question that weak stone you're talking about the cost increase. Given the lower Australian dollar and supposedly weaker labor market, which has translated into better productivity, Can you elaborate a little bit more what's causing the cost increase?
Sure, Paul. As I said, we're now expecting a $34,000,000,000 total project cost. So that's up about $5,000,000,000 from the original AR. That original appropriation request was taken in 2011. And as you can all appreciate, the 1st few years of construction there was in a much more heated market.
But we've talked in the past about our late module delivery and this really was one of the primary drivers behind the cost increase. They were delayed due to poor performance at 1 of the fabricating yards. It came to be that the contractor was unable to effectively manage the size and the scale of the work scope that we had given that particular contractor. So we recognized that somewhat early on and we did end up redirecting some of the work to other yards. But even so modules were late.
A second factor that I would comment on is really an underestimation of the quantity of materials that were required. At the time we took FID on Wheatstone, we had engineering was at about 15% complete. And so the rest was based on rules of thumb and factors. As we matured the engineering definition, the amount of quantities needed increased substantially. And so that really was a secondary reason behind the cost increase.
I would say the second element was something that we had seen on Gorgon as well, and it is one of the primary areas where we are trying to improve our project execution going forward. As you know, we had FGP when we took FID on FGP, we were at about nearly a 50% engineering level. So this is one of the primary improvement practices that we're putting in place for future projects.
Thanks, Paul.
Thank you. Our next question comes from the line of Phil Gresh from JPMorgan. Your question please.
Hey, good morning.
Hey, Phil.
Bruce, you had made a comment in one of the earlier questions about a free cash flow focus. And I was just kind of wondering if you take together what you've said about capital spending and the production outlook, When would you expect the Permian to become free cash flow positive? And how do you think about some of the assets in the Permian that might need some more material infrastructure spending? Is that something that you guys are really willing to spend a lot of money on in the next few years? Or are you more focused on kind of more immediate cash flow?
So thanks for the question, Phil. We'll provide more color and specifics in the Analyst Day next March. We do have internal projections on when the overall program reaches free cash flow and that obviously depends on a number of factors including the trajectory that we pursue. And I'll remind you again, we have many options to adjust based on the results that we see. We do have an integrated approach where we not only connect the upstream activity that we're engaged in drilling and completing wells, but pair that with midstream activity to move product to the market centers that we choose.
We typically engage in that through commercial transactions. It's a very competitive basin. There's a lot of companies that operate in that space. We typically deploy our capital in the areas where we can differentiate our performance in drilling and completions. And then working with high quality third party suppliers, look to them to move the crude to market, operate gas processing and NGL fractionation activities.
Okay. Got it. And then my follow-up, I guess maybe this would be best for Pat kind of following on what Paul was asking about, dollars 10 F and D in the Permian, dollars 18 for 10 geese. Where would you say as you're assessing the deepwater opportunities in the portfolio, particularly the brownfield side of things, how would that stack up at this stage, as costs continue to come down?
Brownfield would be very good. Greenfield would be a little bit more challenged, but Brownfield would be very good.
Okay. Thanks.
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. Hi
Doug. Hi Doug. Hi Doug. Hi Doug.
Hi Doug. I'm not sure And I guess what I'm really trying to understand here is what are the limiting factors on the Permian given its flexibility, lower execution risk, the absence of the kind of cost issues you've had in things like Gorgon and Wheatstone. I guess what I'm asking is, is the Permian big enough to drive a much more meaningful strategic shift and how allocate Chevron allocates capital longer term? Is that what we're looking at here?
I think best if I take that one here, Doug. I think when you have such an extraordinary asset base in the Permian, when it has as much kind of depth and breadth to it, and I don't mean that in a literal sense, but a figurative sense, such huge economic strength, everything in the portfolio really needs to be judged against those options. And so when I think about, we don't believe we want to be just a single asset class company. So we have great strategic capabilities and basin positions in the Gulf of Mexico deepwater. We have the Tengiz project that we talked about.
We have the LNG project. So we have pretty broad based portfolio here and we're not looking to take all activity down to the Permian. But the value of the Permian and its tremendous economic capability and its capital efficiency, its great flexibility, its short cycle, high return attributes, does make other parts of the portfolio have to compete for capital against that. So I think it raises the bar on where that incremental dollar is going to go. And I think Permian will get the first call, but we will manage it as a portfolio.
And over time, you should still expect us to have some significant other projects, but we can pace those projects quite nicely, I think, and match against always coming back to and matching against the opportunities that the Permian provides for us.
So put simply part, the Permian is going to take market share from the rest of your portfolio. Is that a good way of thinking about it?
I think that's reasonable within limits. I think that's reasonable, yes.
Okay. My follow-up is very clear in
the security analyst meeting. We'll go through more of this in March because I think that's really where it's the appropriate time to lay out on portfolio.
Well, I guess a related question, my follow-up is that there's been, we haven't talked much about disposals, I guess, in a couple of quarters. I'm guessing a high grading exercise, if you want to call it that, like the Permian, changes the map a little bit in terms of what competes for capital. There's been some speculation around Bangladesh, which is sizable. Obviously, I think you've talked about that publicly. You just give us an update as to where you see the changing map on the disposal, both in scale and perhaps any identified assets that have changed since we since your Analyst Day?
Yes. We really haven't changed our view. I mean, we look at asset sales when we can get good value, that's 1st and foremost, not strategic or we don't see kind of the compelling relationship within the Chevron portfolio. We've announced certain, assets for sale. We put a list out in the Q2, there.
The list essentially is the same. I can confirm that there are commercial discussions going on in and around Bangladesh. But I'll go back to the primary element here, which is we want to get good value. And so on any of these transactions that we've sort of queued up and are beginning to have people into data rooms either in an early round or a secondary round, if in
fact we don't get the value proposition that we're seeking, then we'll just
move on. Okay. And then,
Thank you.
Thank you. Our next question comes from the line of Ed Westlake from Credit Suisse. Your question, please.
Yes. Good morning. So that Slide 12 is great and shows how you've made improvement. I mean, I guess you're still a little bit above the development costs of the non operated JV partners. Maybe is that geographical?
Is there some different ways that you approach the business? So just maybe some color on that.
Sure, Ed. Yes, and we're providing you on this chart quarterly data, and it's an aggregation of everything that was completed in that particular quarter. And you're right to suspect that there's a little portfolio aspect to what goes on in any particular quarter. We have operations in both the Midland and Delaware Basin on the company operated side and on the NOJV side as well. And the mix of activity in any particular quarter are going to cause those bars to be up and down a little bit.
If we had the Q4 of 2015, you'd see 2 quarters where the company operated bars are a little lower and then the last two quarters where the NOJV bars are a little lower. But we would look internally in a much finer level of detail, Wolfcamp B wells in the Central Midland Basin, 1.5 mile laterals and are we comparable in that activity or not and what do we address about that. So the overall performance is competitive. And I will tell you that there is a competitive group. There's a lead pack in the Permian and we're a part of that.
And I think the data on Slide 12 shows that and some of the quarter to quarter variations are simply a function of which particular wells are completing. And because our costs include full cycle, there are facility costs in our bars in the quarter in which we start wells in a new area and have central tank batteries or other things that are being executed in that period.
And then I mean, it's just a great portfolio with also tax and royalty advantages, and you'll want to get after it. The rest of the industry is getting after it. Maybe just give us some high level thoughts about inflation. I mean, on the one hand, there's probably still learnings that can improve that development cost as you progress? On the other hand, things might get a little hot over the next few years.
So maybe just some high level thoughts as to how you think about that.
Yes. We've certainly driven in the last 2 years to a very positive position. We operate in a dynamic price environment and a dynamic activity environment. Over the last few years, we really leveraged the scale of Chevron where we have an advantage to do so. So tubulars or the pipe that goes in the wells is a key cost component and Chevron buys a lot of pipe around the world.
So we're able to leverage our worldwide supply chain effort to bring advantage to pricing to what we do. We also consolidate work with key suppliers. I have consolidated work to give us the right combination of unit price, execution performance, access to technology and the ability to grow with us. And then we've put in place some contractual arrangements with unit based fixed terms, some are index based, some use performance incentives, but they're all intended to keep us on the competitive side of the price curve, irrespective of what commodity prices are doing. Structurally, the things that stay with us in any price environment are multi well pad designs, which we've done for a very long time.
The acreage position that we have that allow us to drill longer lateral lengths efficiencies in we engage in on a daily basis in terms of something we call zipper fracking where you have activities occurring simultaneously. And those will stay us regardless of what price does.
Thanks, guys. Thank you. Our next question comes from the line of Neil Mehta from Goldman Sachs. Your question please.
Good morning, everyone. Pat, really good progress here on capital spending. Where do you believe we're tracking relative to guidance here in 2016 for CapEx? And then relative to the $17,000,000,000 to $22,000,000,000 any early look of how the deflation you've seen in 2016 will carry forward?
Yes. So I think, we had said before that 2016 we thought would come in at 25, around 25. I think last time I said even below 20 5. And this time, I'm really thinking we'll probably be closer to 24. So significant reduction from a year ago's time.
We're in the process of doing our business plan right now. The range that we put out for 2017 to 2018 is in the $17,000,000,000 to $22,000,000,000 range. I think we will be in that range. We're just going through and doing the prioritization at the moment and we'll come out typically with a C and E press release after our Board approves the plan and I don't really want to get ahead of that. But obviously, all of the efficiencies, the cost efficiencies that we've seen, Bruce just talked through some of those in his business unit, but those are going on around the globe, in terms of supplier optimization, supplier rationalization, and getting our supply chain costs down.
That will continue, and I think we'll hold on to that. The one area where there probably is a little bit of an inflationary element will be the Permian because that's where investment is being attracted. But when you look around the rest of the world, that is really not happening in the rest of the world. Investment is not going to those locations. So we're not seeing those kind of cost pressures.
So we believe the efficiencies through the supply chain organization that we've been able to capture will hold there.
That's a good follow-up. And maybe this is for Bruce here. But as you see activity pick up in the Permian, do you see any bottlenecks, either from an infrastructure perspective, labor perspective or other parts of the resource that will make it difficult for you to achieve the high end of the range that we talked about?
We certainly recognize, Neil, that we have to plan ahead and we do so. When you think about takeaway, our efforts in maximizing realization have a secondary component, which is flow assurance, to make sure that we're able to move to the market centers, the locations where we ultimately wish to sell without being disrupted. When you get to the supply of drilling and completing wells, the suppliers that we work with, we pick intentionally, in part for their ability to grow, both in terms of the availability of the equipment, the type of equipment we want and their staffing plans in terms of how they will staff and maintain that staffing going forward. So there will be some changes overall in the basin, but we're taking a multiyear view and able to look a little bit into the future and base our planning around that.
Thanks, Neil. Thank you.
Thank you. Our next question comes from the line of Blake Fernandez from Howard Weil. Your question, please.
Folks, good morning. Pat, going back to some of the back to the deflationary pressures you're seeing on CapEx, I think you alluded to $50 Brent breakeven, which is pretty consistent with what you had articulated before. Is it fair to think that that number is trending lower also?
We are working very hard to get that number lower, absolutely. And it certainly has moved down from when we first put that target out there, yes. I mean, our actuals are moving in that direction. So yes, we are trying as best we can through operating efficiencies, capital efficiencies to have our outflows contained relative to the inflows that we anticipate coming out there. So it's what I consider to be a cost structure reset and a capital expenditure reset given the environment that we're in.
Okay, fair enough. And then Bruce, on the Permian, it looks like you're trending above the top end of guidance or your range. Obviously, you're adding rigs. We probably haven't seen the full impact of that yet. Is there any reason to believe that you're not on track to potentially surpass what the upper end of this range is here?
Well, we're ahead now and our guidance remains the same at this point to 2020, 250,000 to 350,000 barrels a day. Our Analyst Day in March is the typical time where we would unpack more of that for you and everybody else.
Good deal. Appreciate it.
Thanks, Blake.
Thank you. Our next question comes from the line of Evan Kalia from Morgan Stanley. Your question, please.
Hi, good afternoon and good results today. My first question staying with the Permian. Bruce, I know some of your acreage in Southwest Reeves overlaps Apache's recently announced Alpine High play. Can you share your view on the viability of that play, potential economics and how that would or may compete for capital with your this Permian core that you've laid out today?
Sure, Evan. Well, let me start first by saying we're excited by this activity and hope it's fully successful. We have 180,000 acres in our portfolio and you can see it there on the slide. But it's a great example of how our strategy has played out across the Permian, allowing the industry to derisk and create data that can refine our assessment. Alpine High, that area in the southern part of Reeves County is right now on our overall portfolio pie in that wedge that is labeled less than $20,000 per acre.
Subsurface the subsurface is structurally more complex. It appears to be a little more gassy and it's far from existing infrastructure. But additional positive data certainly has the potential to move that area to higher value. And if it does, we go through a regular resort of priorities and we would adjust our activity as that indicated.
Great. And then maybe my second is, it's a follow-up to some prior Permian questions, but just to understand, I mean, does the upside to your Permian production range, which is the same as it was in May, despite improvements here, Does that represent the limit to how much you can grow in a capital efficient manner and that looks achievable on a 30 rig program at by the end of 2020? If so, like what are the limiting factors in your current plan to how much the Permian can take and subsequently grow?
Well, so our focus in the near term and quite frankly throughout is on capital efficiency. And we are focused not on chasing a particular production curve. Growing production is important. Growing volume is important, but retaining efficiency throughout what we do. And we have many options going forward to adjust our pace of activity up and down.
We have the ability to grow activity, but it is returns that we are ultimately focused
on and
that will drive our decision making going forward.
Thanks, Evan.
Great. Thank you. Our next question comes from the line of Brendan Byrne from BMO Capital Markets. Your question please.
Good morning or good afternoon wherever you're sitting in the world. I want to ask a question away from the Permian, if I can. If I could just get an update on Rosebank in the U. K. North Sea just in terms of know you're out sort of rebidding and renegotiating.
Just how you're seeing that project stack up in terms of its cost? If you can give any update. And if I can have a follow-up, please.
Well, I think all I can say at this point, I mean, we are, in essence, staying with that project in FEED, while we're trying to get the development costs down. So I don't have a lot of specific information to provide for you. But obviously, with what's happened to oil price, what's happened to the optionality that we have here in the Permian, There is a competing for capital element that Rosebank has to fight for within our portfolio. So we're continuing to work at it. We recognize how important Rosebank is to the region.
We recognize how important it is to the U. K. But we have in the past been able to take a second look at the design and get costs down. In the past, we've been able to kind of recharacterize the sub surface and work improvements in there. And we're just still on that same process.
Okay. And follow-up, just how much would the weaker pound assist that project in terms of economics?
Obviously, it would help, but I don't have the ability to quantify that for you at the moment.
Okay. Thank you. Thanks, Brandon.
Thank you. Our next question comes from the line of Anish Kapadia from TPH. Your question please.
Hi. My first question was on some of your other potential international project sanctions. I wanted to get a little bit of an update on the Gulf of Mexico projects, where you're at in terms of the appraisals and potential development. So the ones I was thinking of was the Anchor project, the Tigris project and Sicily.
Okay. So on Anchor, we're still in the appraisal process. Feel positive about it, but we're still in the appraisal process there. On Tigris, there's multiple fields that are involved here. Appraisal drilling has been completed and we have filed for a suspension of production here.
On Sicily, we've allowed the leases to elapse.
Okay. Thank you. And then I had a question for Bruce on the Permian. Again, thank you for the useful slides that you put out. In terms of the, I suppose, the high graded area that you've talked about, the 600,000 acres, Within that, I was wondering if you could give some idea of the number of locations that are contained within that in your current thinking and which benches you're looking at, currently thinking are going to be developed in that acreage?
Well, the areas that are at the top of our queue vary between the Midland and Delaware Basin as do the horizons. The things that we're most interested in are again those that create the right kind of full cycle returns. And so the oil gas split between those areas, the cost of execution of those areas are what causes it to be in the top tier for us. So in the Midland Basin, Wolfcamp B and Lower Spraberry are 2 horizons that we like a lot. We also like some aspects of the Wolfcamp in the Delaware Basin.
We're drilling wells in a few other horizons. But there isn't a one size fits all. You'll move to one part of the basin and that particular horizon that you're interested in is just not as greater value as others. So what we do in these development areas is put together a strategy that paces development based on value. We go to the best performing horizon on a return basis first and then follow it with the others.
And that is not a simple answer that fits the whole basin.
Thanks, Anish.
Thank you.
Thank you. Our next question comes from the line of Ryan Todd from Deutsche Bank. Your question please.
Hi, thanks. Great result, maybe I'll stick on the trend and ask one Permian question followed by another one. But in the Permian, if you look at your acreage, if you look on the map in 11 and you've shown this map a number of times, but I mean, you still got a lot of checkerboard acreage across core portions of the Permian Basin. Any further interest at this point in potential JVs or partnerships like you did with Cimarex in the past that would allow for an increasing amount of long laterals and capital efficient developments? Or how do you think about that managing that acreage going forward?
So it's a good question. We're actually very actively engaged in swaps, working with individuals that would own or have rights to checkerboarded acreage and we've actually executed quite a number of those. It does allow us to extend laterals, concentrate facilities and infrastructure in certain places. We will also contemplate joint ventures where that leads us to the right kind of return outcomes, if a combination of acreage in some way leads to a more efficient result. But I will tell you that what's been more active for us in the last year and a half has been finding acreage consolidations that we can make through swaps.
And that's bolstered by the fact that our company operated execution is becoming highly efficient and those are the sorts of activities that are driving returns to the top of our queue.
Great. Thanks. And then maybe if I could ask one, maybe a question for Pat there, kind of a high level philosophical one. I mean, if we look at what the major city itself have been able to do in terms of capital reduction over the past couple of years, I think it's been quite impressive. And as we look forward over the next kind of, let's say, 2 to 5 years, and I realize there are a ton of variables in this.
How do you think about what a reasonable level of sustainable CapEx is? I mean, if you talk about potentially being sub $20,000,000,000 a year in 2017. Has there been enough structural cost deflation or efficiency gains that that is kind of a reasonable medium term level to think about longer term or is that still feel kind of like capital starvation mode and there's a need to bounce back into some level in the 20s that's more sustainable over the medium term?
Yes. So I think the critical variable that you're leaving unsaid there is what's happening to price. Just a little bit on price, I think our own view here is that in the medium term here, we're potentially going to be range bound. We are constructive on price. I mean, we do think over time here you will there will be price appreciation, but we see it being relatively modest.
But in the period that we're talking about here, I don't see that change changing our view of the $17,000,000,000 to $22,000,000,000 range being appropriate for us. You're hearing an awful lot about the Permian being, one of the best investment opportunities that we have. And the great thing about that is that it's short cycle, it's high return, it's very flexible. And so that gives us it lowers our capital intensity, gives us greater flexibility than we have had in several years. And the only other major project that we've sanctioned at this point in time is TCO.
And our share of that in terms would be in the range of $2,000,000,000 to $3,000,000,000 a year over the next few years. So we consider that to be very manageable and that's within the $17,000,000,000 to 22 dollars range that we've given you. So I think that's a reasonable range on C and E to expect for us, under a reasonable range of prices that might be anticipated. Okay, I think we have time. All right.
Sorry, I didn't mean to cut you off there. I think we got time for one more question.
Thank you. Our final question then comes from the line of Pavel Molchanov from Raymond James. Your question please. Thank you, guys. Just a quick one about Nigeria.
Mentioned losing 28,000 a day in Q3. What kind of recovery have you seen on your Nigerian assets so far this quarter? And what is embedded in the exit rate guidance that you gave for the year?
Well, I mean, I think we have two factors going on. We have had some instances of sabotage, as we've talked about. We had a more recent one here in the last couple of days. So that's obviously a detriment that is impacting Nigerian production. But on the opposite side, we've got Agbami.
Agbami extension plateau extension investments coming online. So I think that it's not a huge factor in terms of a variance in what we're showing for the December exit range.
Appreciate it.
Okay. Thanks, Pavel. All right. So I think that concludes our call for the Q3 here. I'd like to thank everybody for your time on the call.
We certainly appreciate your interest in Chevron, and we appreciate everybody's participation on the call. Thank you very much.
Ladies and gentlemen, this concludes Chevron's 3rd quarter 2016