Good morning. My name is Jonathan, and I will be your conference facilitator today. Welcome to Chevron's Third 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. [Operator Instructions] As a reminder, this conference call is being recorded. I will now turn the conference call over to the Vice President and Chief Financial Officer of Chevron Corporation, Ms. Pat Yarrington. Please go ahead.

Okay, thank you, Jonathan. Welcome to Chevron's third 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 third quarter 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 third quarter earnings were $1.3 billion or $0.68 per diluted share. Third quarter results included $290 million and 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 million, earnings for the quarter totaled $921 million or $0.49 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 $5.3 billion and our debt ratio at quarter end was 23.7%. Our net debt ratio was approximately 20%. During the third quarter, we paid $2 billion in dividend. 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 $5.3 billion during the third quarter and $9 billion year-to-date. Year-to-date working capital effects of $1.3 billion and $3.1 billion 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 million in the third 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 $2.2 billion. We continue to pursue a number of potential transactions and we remain confident that we can achieve our $5 billion to $10 billion for total proceeds over this year and next. Cash capital expenditures for the quarter were $4.1 billion, a decrease of $2.7 billion from the third quarter of 2015. Year-to-date cash investment outlays have totaled approximately $14 billion. During the quarter, we advanced $2 billion to Tengizchevroil or TCO in support of the FGP project. This outflow is reflected in our cash flow statement as a borrowing by equity affiliates. The 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 pace of investment. At quarter-end, our cash, cash equivalents, and marketable securities totaled approximately $7.7 billion and our net debt position was $37.9 billion. Turning now to Slide 5; Slide 5 compares current quarter earnings with the same period last year. Third quarter 2016 results were $754 million, lower than third quarter 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 third quarter 2015 assets impairments increased earnings by $535 million between periods. Lower foreign exchange gains decreased earnings by $322 million 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 billion, primarily driven by lower worldwide refining margins and lower earnings from CP Chem. Turning now to Slide 6; here I'll compare results for the third quarter of 2016 with the second quarter of 2016. Third quarter results were approximately $2.8 billion higher than the second quarter. The absence of second quarter 2016 charges associated with special items, and the inclusion of third quarter gains from special items increased earnings by $2.7 billion between periods. Lower foreign exchange gains reduced earnings by approximately $200 million between periods. Upstream results, excluding special items and foreign exchange were comparable between quarters, in line with relatively flat rent prices. Lower operational expenses offset essentially by lower listings and adverse tax impacts. Downstream earnings, excluding special items and foreign exchange were higher by $255 million, primarily resulting from the absence of unfavorable second quarter inventory valuation effects. Prices were generally rising during the second quarter but relatively flat during the third quarter. Turning to Slide 7; here we compare the change in Chevron's worldwide net oil equivalent production between the third quarter of 2016 and third quarter 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, Chuandongbei 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 basic 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 the TCO as we completed the turnaround of the second generation plant. Based on nine months of actuals and our forecast for the fourth quarter, we anticipate full year 2016 production will be approximately 2.6 million barrels per day. Turning now to Slide 8; as we indicated on the second quarter call, we expect to exit the year with December production in the range of 2.65 million to 2.7 million barrels per day or growth in the range of 150,000 barrels per day from the third 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 six weeks, maintenance was conducted on more than 500 pieces of equipment. At its peak, over 8,800 employees and contractors were onsite for the turnaround. The team work 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 million 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 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 cargos and 16 LPG cargos. In addition to LNG volume increases, we achieved first production from Bangka in August, and expect first production from Alder before year-end. We also expect continued growth in our unconventional 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 million 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 cargos to-date, and with both Trains now running, we expect to ship an average of two to three cargos per week. Construction on Train 3 is progressing very well, and we expect first LNG in the second quarter of 2017. At Wheatstone, our outlook for first LNG remains mid-2017 for Train 1. We are leveraging our experience from Gorgon, and are pleased with our progress. Our modules for Train 1 and Train 2 are now onsite 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 cost relative to the original 2011 estimate. We now forecast the total project cost at completion to be $34 billion. Chevron share of the cost to complete the project is included in the $17 billion to $22 billion 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 million 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 at the most -- 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 our 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 have identified 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 the Slide 11; you can see Chevrons acreage position in more detail. This slide is a map of the Permian Basin, inclusive of Southeast New Mexico and West Texas. Our 2 million acres are depicted in blue, 1.5 million of which are in the Midland and Delaware Basins. Also depicted on the map are active Chevron operated developments in blue and are 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 and $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 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 on our ninth rig as we speak, and expect to be at ten by the end of the year. Another ten rigs are currently drilling 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&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&A which is not included in the graph on the lower right, is a component of overall operating expense. Our year-to-date G&A is $3.50 a barrel, declining through the year and more than 20% from 2015. The third 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 well-head. 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 third quarter 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 it 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 billion 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 billion lower than 2015. And our C&E is trending below the guidance range, previously provided for this year. We will likely end the year below $25 billion in capital outlays, in fact potentially coming in closer to $24 billion. 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. Second, we are beginning to see evidence of that cash flow growth, notably now that Gorgon Train 1 is operating well, and Train 2 is successfully online, and with Gorgon's Train 3 and Wheatstone's Trains 1 and 2 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. Third, 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 price world, our Permian assets they 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 cost coming down with C&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 balance 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 you. [Operator Instructions] Our first question comes from the line of Jason gamble 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 finding and development cost was probably one of the most important metrics that you have in the basin. Can you talk about how you are benchmarking yourself against some of the E&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 and 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 are able to address the issues directly at financial performance that aren't often available from a less complete dataset. I suppose there is 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 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 the growth, in fact we've added five rigs over essentially the second half of 2016. That's the pace of rig additions of about one rig a month. Productions grown from the third quarter of last year by 24% further supporting the notion that we're growing. And our pace and rate of indications [ph] 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 generate -- generating free cash flow. We do expect to grow, as you noted you can see that on the Slide 13. And as we go forward, we have options; we continually monitor our performance and we adjust.

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 a longer term strategic value or it felt others could -- would offer more value for us and it would obtain in our portfolio, we've been willing to make asset sales and we've had a very routine practice of asset sells 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 has 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 a valuation an appraisal work -- 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 plan, than -- 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 do 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 billion annually, across both the company-operated and our non-operative joint venture programs.

So the outlook for that is flat is it or is that going to go up?

I would expect it to go up. The -- 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 -- 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 are spending -- previously in September you had said $18 per BOE of development cost for I think a $36 billion investment. Why would you be spending so much less in the Permian at what I think looks like a $10 F&D cost per barrel? Maybe that one is 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 same and throughout the year here that we could see that top like -- 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 and -- I think you know 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 well-head 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 that's a joint development concept, and there is a lot of upside that has not been kind of built-in to a lot of people's models, I guess I would say about FGP that relate to the debottlenecking, what we've been able to demonstrate in the past -- we hope to be able to do on a go forward basis. There is additional gas handling facilities built in here that will overtime 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 FIB. And then of course down the road, obviously we hope that this turns into concession extension. So there is a lot of potential upside to FGP, I think Jay did a great job on our second quarter call in kind of running through all of those parameters.

Got it. So what you are saying is the $18 is a very conservative -- $18 per barrel development cost is a very conservative number and it would be competitive with the Permian ultimately when all of these things are considered?

We think we need both assets in our portfolio, yes.

Thank you, Pat.

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

Good morning. Two questions if I could. Bruce on the -- what is the recovery rate that you use to get to that 9 billion barrel? Are you just saying 10%, 12% -- what do you expect and foresee that recovery rate may change over the next, say five years?

Yes. So the 9 billion 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 were to play at the 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 -- what that recovery rate may look like in five years?

No, not at this point.

Okay. Pat, a second question then on Wheatstone, you're talking about the cost increase. Given the lower Australian dollar and supposedly weaker labor market which has translated into better productivities; can you elaborate a little bit more on what's causing the cost increase?

Sure, Paul. As I said, we're now expecting a $34 billion total project cost. So that's up about $5 billion from the original AR. That original appropriation request was taken in 2011 and as you can all appreciate, the first 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 one of the fabricating yard, 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 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.

Thank you.

Thank you. Our next question comes from a line of Phil Gresh from JP Morgan. Your question please?

Good morning. Bruce, you had made a comment on one of the earlier questions about free cash flow focus and I'm 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?

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 our product to the market centers that we choose. We typically engage in that through commercial transactions; it's a very competitive basin, there is a lot of companies that operate in that space. We typically deploy our capital in the areas where we can differentiate our performance and drilling and completions, and then working with high quality third-party suppliers, look to them to move the crude to market, operate the gas processing and NGL fractionation activities.

Okay, got it, thanks. And then my follow-up -- I guess maybe this would be best for Pat, kind of following on what Paul was asking about $10 F&D in the Permian, $18 for Tengiz. 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 challenge 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. Pat and Bruce and Frank, I am not sure who wants to take this one -- but I guess that Chevron has always been a company led by large-scale major project developments, explorations, and so on. And I guess what I am really trying to understand here is what are the limiting factors on the Permian given its flexibility, lower execution risk, the absence of the cost issues you've have had and 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 it allocates -- 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 over 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 but the dollar is going to go and I think Permian will get the first call but we will manage it as a portfolio, and overtime 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 the Permian provides for us.

So is it pretty simply, Pat, 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. And we'll go through more of this 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.

And I guess a related question my follow-up is; there has been -- we haven't talked much about disposals and I guess in a couple quarters. I am guessing a high grading exercise, if you want to call it that way, the Permian changes the map a little bit in terms of what competes for capital. There has been some speculation around Bangladesh which is sizable obviously, I think you have talked about that publicly. Can you just give us an update as to where you see the changing map on disposals, both in scale and perhaps any identified assets that have changed since the 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 first 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 and we've put a list out in the second quarter there; the list essentially is the same, I can't 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.

Thanks very much.

Thanks, Doug.

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 cost 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. 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 is 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 is going to cause those bars to be up and down a little bit. If we had the fourth quarter of 2015, you'd see two quarters where the company operated bars are a little lower and the last two quarters whether 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, mile and a half laterals and ROE 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 is 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 the new area and have central tank batteries or other things that are being executed in that period.

And then I mean -- I mean this is just a great portfolio with also tax and royalty advantages. And you will want to get after it; the rest of the industry is getting after it. Maybe just give us some high-level thoughts about inflation. On the one hand there is 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?

We've certainly driven in the last two years to a very positive position. We operate in a dynamic price environment and dynamic activity environment. Over the last few years we really leverage 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 -- 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 as we engage in on a daily basis in terms of something we call zipper fracing [ph] where you have activities occurring simultaneously. And those will stay us regardless of what price does.

Thanks, Bruce.

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 billion to $22 billion, any early look of how the deflation you've seen in '16 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 25 and this time I'm really thinking we'll probably be closer to 24. So significant reduction from a year ago time. We're in the process of doing our business plan, right now the range that we've put out for '17 to '18 is in the $17 billion to $22 billion 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&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 will hold onto that. The one area where there probably is a little bit of an inflationary element will all 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 we've been able to capture will hold there.

That is a good follow-up. And maybe this is for Bruce here, 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 that 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 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 multi-year view and able to look a little bit into the future and based our planning around that.

Thank you.

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

Good morning. Pat, going back to some of the -- back to the deflationary pressures you're seeing on CapEx. I think you alluded to a $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; meaning 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 are 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 are 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, I appreciate it.

Thanks, Blake.

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

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 this Permian core that you have laid out today?

Sure, Evan. 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 de-risk 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 it is -- that is labeled less than $20,000 per acre, subsurface. And 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 maybe that looks achievable on a 30-rig program by the end of 2020? And if so, like what are the limiting factors in your current plan to how much the Permian can take and subsequently grow?

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 bond 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.

Thank you. Our next question comes from the line of Brendan Warn from BMO Capital Markets. Your question please?

Good morning or good afternoon, wherever you are sitting in the world. I'm going to ask a question away from the Permian if I can; if I could just get an update on Rosebank in the UK North Sea, just in terms of -- I know you are out sort of rebidding and renegotiating. Just how you're seeing that project stack up in terms of its cost? And if you can give any update 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 prices, 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 when I was continuing to work at it -- we've recognize how important Rosebank is to the region, we recognized how important it is to the U.K. but we have in the past been able to take a look -- a second look at the design and get costs down. In the past we've been able to kind of re-characterize the subsurface and work improvements in there, and we're just still on that same process.

And then a 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, Pat.

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 are at in terms of the appraisals and potential development. So the ones I was thinking of were the Anchor projects, the Tigris project and Sicily.

So an anchor we're still in the appraisal process; we feel positive about it but we're still in the appraisal process there. On the Tigris there is multiple fields that are involved here; appraisal drilling has been completed and we have filed for a suspension of production here. Officially [ph], we've allowed to 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've put out. In terms of the -- high graded area that you have 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 are you currently thinking are going to be developed in that acreage?

The areas that are at the top of our Q 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 Sprayberry are two area -- are two 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 great a 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 best performing horizon on a return basis first, and then follow it with the others. And that -- there is not a simple answer that's fits the whole basin.

Thanks.

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

Hi, thanks. Great result, maybe I'll stick up on the trend and ask one Permian question followed by another one. In the Permian, if you look at your acreage, if you look on the map on 11, and you've shown this map a number of different times but I mean you've 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 managing that acreage going forward?

It's a good question. We are actually very actively engaged in swaps working with individuals that we don't have rights to checkerboard at 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 would 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 Q.

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 -- if we look at what the majors such as yourself have been able to do in terms of capital reduction over the past couple years; I think it's been quite impressive. And as we look forward over the next let's say two to five years, and I realize there is a lot of variable 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 billion a year in a 2017, is -- 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 does that still feel like capital starvation mode and there is a need to bounce back into some level in the 20s as 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. You know 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 and we do think overtime, 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 billion to $22 billion range being appropriate for us. You are 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 of an outflow would be in the range of $2 billion to $3 billion a year over the next few years. So we consider that to be very manageable and that's within the $17 billion to $22 billion range that we've given you. So I think that's a reasonable range on C&E to expect for us under a regional -- 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 but I think we've 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. You 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 it -- obviously a detriment that is impacting Nigerian production. But on the opposite side we've got a [indiscernible] expense – extension, plateau extension investment coming online. So I think that it's not a huge factor in terms of a variance and what we're showing for the December exit range.

I appreciate it.

Okay, thanks. All right, so I think that concludes our call for the third quarter 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 third quarter 2016 earnings conference call. You may now disconnect.