Chevron Corp (CVX) — Q3 2016 Earnings Call Transcript

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 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 $5.3 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 asset 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 increase 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 increase 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 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 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 ramp 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 continues 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's 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 after the most efficient short cycle operations in Chevron and in the 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 have identified and verified 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 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 snapshots that assume 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 in 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.

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 capital expenditures are 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 speak 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 capital expenditures 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?

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 non-operated joint venture competitors where we also invest. 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 non-operated joint venture 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 the pace. We are already experiencing growth; we've added five rigs in the second half of 2016, which translates to about one rig per month. Production has increased by 24% since the third quarter of last year, further confirming our growth. Our pace and rate of development are intentional. We are focused on achieving strong returns, and I do not see any limitations on capital in the Permian Basin. Our rig additions are strategically aimed at ensuring we achieve our desired outcomes that support high returns and eventually lead to generating free cash flow. We do expect to continue growing, as shown on Slide 13. Moving forward, we have various options; we continuously evaluate our performance and make necessary adjustments.

And Jason, I want to add to that. We have a history of selling assets when we believe they no longer provide long-term strategic value or if others can derive more value from them, thus optimizing our portfolio. Our approach to asset sales has been consistent over the years. A crucial part of deciding to sell is having a strong grasp of the asset's value. In the Permian Basin, asset valuations have fluctuated significantly over the past few years, accompanied by extensive appraisal and evaluation work. While we’ve gained a better understanding, the valuation has still experienced notable changes. In some instances, property values have increased by as much as 10,000 times. That's something we need to be cautious about; rushing into a sale could lead to poor decisions. Therefore, we will focus on conducting thorough valuation and appraisal work to fully understand what the asset is worth. If it does not align with our long-term development plans, we will certainly explore other ways to monetize it.

Thanks, Jason.

Thank you.

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-operated 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. 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. If I look at the Tengiz expansion, you mentioned a development cost of $18 per BOE for a $36 billion investment in September. Why is the spending in the Permian so much less, showing what appears to be a $10 F&D cost per barrel? Perhaps Pat can address that.

Yes, it is. Paul, just a couple of things. Referring to Slide 13, we previously mentioned that we could potentially double our current activity levels at the top end of that light blue portion. We are currently spending 1.5, and you might see that doubling. This is our current outlook, but we will provide an update at the March Security Analyst Meeting. Regarding the Future Growth Project (FGP), it’s essential to understand that we are fully funding both the Permian and FGP. We view both areas as critical for our growth. We are not neglecting the Permian for FGP. What many overlook about FGP is the significant loss of value that would occur if we didn't proceed with the well-head pressure management project, as the field would enter a serious decline, resulting in a loss of value in our legacy asset. We are undertaking FGP and WPMP simultaneously due to synergies; this is a joint development approach. There’s substantial upside that isn’t reflected in many models concerning FGP, particularly regarding debottlenecking, which we hope to show in our future performance. Additional gas handling facilities are included that will enable greater oil production; we have discussed the contingencies, even though we were only at 50% of engineering when we initiated FGP. Furthermore, we hope this leads to a concession extension down the line. There is significant potential upside in FGP, and I believe Jay effectively outlined these factors during our second quarter call.

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

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

Thank you, Pat.

Good morning. I have two questions. Bruce, what recovery rate do you use to arrive at the 9 billion barrel figure? Are you indicating that it's around 10% or 12%? What do you anticipate the recovery rate might be in the next 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 where we 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 just as we have in other asset classes that we operate in and are more mature.

Will you be able to share what the recovery rate forecast might 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. We're now expecting the total project cost to reach $34 billion, which is an increase of about $5 billion from our original request made in 2011. During the initial years of construction, the market was much more competitive. We've discussed before our delays in module delivery, which were a main contributor to the cost increase. These delays were due to the poor performance of one of the fabrication yards, where the contractor struggled to manage the size and scope of the project effectively. We recognized this issue early on and redirected some work to other yards, but modules still ended up being late. Another factor contributing to the cost increase was an underestimation of the materials required. When we made the final investment decision on Wheatstone, engineering was about 15% completed, and our estimates were based on rough guidelines. As engineering progressed, we realized the quantities needed were significantly higher, which was another key reason for the cost rise. This issue also occurred with the Gorgon project, and we are actively working to improve our project execution to avoid similar problems in the future. At the time of FID for FGP, we had nearly 50% of the engineering completed, so we're implementing better practices for upcoming projects.

Thank you.

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 are 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.

Thank you for that. For my follow-up, I would like to ask Pat about the costs related to finding and development in the Permian and Tengiz. As you evaluate the deepwater opportunities in the portfolio, especially on the brownfield side, how does that compare at this point as costs continue to decrease?

Brownfield would be very good. Greenfield would be a little bit more challenging but brownfield would be very good.

Okay, thanks.

Thanks. Good morning, everyone. I'm not sure who wants to address this, but Chevron has historically focused on major projects and exploration. I'm trying to understand the limitations on the Permian, considering its flexibility, lower execution risk, and the absence of cost challenges like those encountered with Gorgon and Wheatstone. My question is whether the Permian is substantial enough to influence Chevron's long-term capital allocation strategy. Is that the direction we are heading?

I believe I can address that, Doug. When you have such a remarkable asset base in the Permian, along with its significant depth and breadth, it's important to evaluate everything in the portfolio against those options. We don't want to limit ourselves to just one asset class; we also have strong strategic capabilities and positions in the Gulf of Mexico deepwater, the Tengiz project, and the LNG project. Our portfolio is quite diverse, and we don't intend to focus all our activities solely on the Permian. However, the Permian's considerable economic potential, capital efficiency, and flexibility, along with its short-cycle high-return characteristics, mean that other areas of our portfolio must compete for capital. This elevates the expectations for where our additional investment will go, and while the Permian will be prioritized, we will manage it as a comprehensive portfolio. Over time, you can expect us to continue pursuing significant projects elsewhere, which we can carefully pace in alignment with the opportunities presented by the Permian.

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 the portfolio.

I have a follow-up question. We haven't discussed disposals much in the past few quarters. I'm thinking about how the Permian could alter what competes for capital. There's been speculation regarding Bangladesh, which is quite significant; I believe you've mentioned that publicly. Could you provide an update on how you see the landscape for disposals changing, both in terms of scale and any specific assets that may have shifted since the Analyst Day?

Yes. Our perspective remains unchanged. We consider asset sales primarily when we can obtain good value; this is our main focus, rather than strategic alignment with the Chevron portfolio. We have announced certain assets for sale and provided a list in the second quarter, which remains largely the same. I cannot confirm whether there are commercial discussions occurring in Bangladesh. However, I want to emphasize that our priority is to attain good value. In any of the transactions we are considering and have begun inviting parties into data rooms, whether in the initial stages or later phases, if we do not secure the value proposition we are aiming for, we will simply move on.

Thanks very much.

Thanks, Doug.

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 with 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 non-operated joint venture side as well. 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 non-operated 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 the 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.

This is an excellent portfolio with tax and royalty benefits. It's important to pursue this, as the rest of the industry is also engaging. Could you share some general thoughts on inflation? On one hand, there might still be insights that could lower development costs as you move forward. On the other hand, inflation could rise significantly in the coming years. Please provide your overall perspective on this.

We have definitely made significant progress in the last two years. We function in a rapidly changing pricing and activity environment. Over the past few years, we have effectively utilized Chevron's scale to our advantage. Tubulars, or the pipes used in wells, are a major cost factor, and Chevron purchases a considerable amount of piping globally. This allows us to utilize our worldwide supply chain to gain pricing advantages. Additionally, we have consolidated work with key suppliers to ensure we have the right balance of unit price, execution performance, access to technology, and the capability to grow alongside them. We have also established various contractual arrangements, some with fixed terms and others that are index-based or include performance incentives, all designed to keep us competitive in terms of pricing regardless of commodity price fluctuations. Consistently, what remains effective in any pricing environment includes multi-well pad designs, our acreage position allowing for longer lateral drilling, and the efficiencies we create through active management of daily operations.

Thanks, Bruce.

Good morning, 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?

We previously indicated that we expected 2016 to come in around $25 billion, and I had mentioned it might even be below that. Now, I think we will be closer to $24 billion, which is a significant decrease from the previous year. We're currently working on our business plan and have projected a range for 2017 to 2018 of $17 billion to $22 billion. I believe we will fall within that range as we prioritize our plans. Typically, we will issue a C&E press release after our board approves the plan, and I want to refrain from commenting too much before that. However, we are seeing efficiencies and cost savings globally, particularly in supplier optimization and rationalization, which should help reduce our supply chain costs. This trend is expected to continue. One area that may experience some inflation is the Permian, as investments are drawn there, but overall, we are not encountering similar cost pressures elsewhere in the world. Thus, we feel confident that the efficiencies we've achieved through our supply chain organization will be sustained.

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 are able to look a little bit into the future and base our planning around that.

Thank you.

Good morning. Pat, returning to the deflationary pressures you're experiencing on CapEx. I believe you mentioned a $50 Brent breakeven, which aligns with what you discussed previously. Is it reasonable to assume that this figure is also trending lower?

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.

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. I'm pleased to say that we are enthusiastic about this activity and we hope for its full success. Our portfolio includes 180,000 acres, which you can see on the slide. This serves as an excellent example of how our strategy has been implemented across the Permian, enabling the industry to reduce risk and generate data that enhances our evaluations. The Alpine High area, located in the southern part of Reeves County, is currently represented in our overall portfolio; within that section, it is categorized as being worth less than $20,000 per acre, at the subsurface level. The subsurface in this area is more structurally complex, seems to be gasier, and is distant from existing infrastructure. However, further positive data could increase its value, and if that occurs, we would conduct a regular reassessment of priorities and adjust our activities accordingly.

Great. For my second question, I would like to follow up on some previous inquiries about the Permian. I want to clarify whether the upper limit of your Permian production range, which remains the same as it was in May despite recent improvements, indicates the maximum growth you can achieve efficiently in terms of capital. Do you believe this could be attainable with a 30 rig program by the end of 2020? If so, what are the current limitations in your plan regarding the growth potential of the Permian?

Our near-term focus, and honestly throughout, is on capital efficiency. We are not fixated on a specific production curve; while increasing production and bonds is important, maintaining efficiency in all our activities is our priority. We have various options to adjust our activity levels as needed. Our ability to ramp up activity exists, but our primary concern is on returns, which will guide our decision-making moving forward.

Thanks.

Good morning or good afternoon, depending on where you are in the world. I'd like to ask a question unrelated to the Permian. Could you provide an update on the Rosebank project in the UK North Sea? I understand you are in the process of rebidding and renegotiating, so I’m interested in how you assess the project's costs. If possible, I would appreciate a follow-up as well.

At this point, I can say that we are remaining with the project in FEED as we work to reduce development costs. I don't have a lot of specific information to share, but considering the changes in oil prices and the options available to us in the Permian, Rosebank now has to compete for capital within our portfolio. We understand the significance of Rosebank to the region and the U.K. In the past, we have been able to reassess the design and lower costs, and we have also improved the subsurface characterization. We are still in that 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.

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 on 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 are multiple fields that are involved here; appraisal drilling has been completed and we have filed for a suspension of production here. Officially, we've allowed two 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 top priorities for us differ between the Midland and Delaware Basins, as do the formations we focus on. Our main concern is finding those that yield strong full cycle returns. The oil and gas division and execution costs in these areas determine their ranking for us. In the Midland Basin, we particularly favor the Wolfcamp B and lower Sprayberry formations. We also see potential in some parts of the Wolfcamp in the Delaware Basin. While we are drilling in other formations, there isn't a universal solution; one region may not offer the same value as another. Therefore, in these development areas, we develop a strategy that aligns pace with value. We begin with the best-performing horizon based on returns and then proceed to others, recognizing that there isn't a straightforward answer that applies universally across the basin.

Thanks.

Hi, thanks. Great results; 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 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, 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 queue.

Thank you. I have a question for Pat that's more philosophical in nature. When we consider the capital reduction that major companies like yours have achieved over the past few years, it’s quite impressive. Looking ahead over the next two to five years, I understand there are many variables at play. How do you view a reasonable level of sustainable capital expenditures? If we consider the possibility of spending less than $20 billion a year as seen in 2017, do you think there has been enough structural cost reduction or efficiency improvements to make that a viable medium-term target? Or does it still seem like we are in a state of capital scarcity, suggesting a need to return to a more sustainable level in the $20 billion range?

Yes. The critical factor you're overlooking is what's happening with prices. Regarding price, we believe that in the medium term, we may remain range-bound. We are optimistic about prices and anticipate some appreciation over time, although it is likely to be modest. However, during this period, we maintain that the $17 billion to $22 billion range is appropriate for us. There is significant discussion about the Permian being one of the best investment opportunities, and its advantages include being short cycle, high return, and very flexible, which lowers our capital intensity and gives us greater flexibility than we've had in years. The only other major project we've approved is TCO, with our share of outflows expected to be between $2 billion to $3 billion a year over the next few years, which we find manageable and still fits within the $17 billion to $22 billion range we've mentioned. Therefore, that seems like a reasonable expectation for capital expenditures based on anticipated price scenarios. I believe we have time for one more question.

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?

I believe we have two factors at play; we have experienced some instances of sabotage, including a recent occurrence in the last few days, which is clearly affecting production in Nigeria. However, on the flip side, we are also seeing a series of investments, particularly in extensions and plateau expansion, coming online. Therefore, I believe this won't significantly impact the variance in our projected December exit range. 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.