Good morning. I'm Frank Mount, General Manager of Investor Relations for Chevron. I'd like to welcome those of you in the room and those of you who are joining us by webcast to Chevron's 2017 Security Analyst Meeting. Before we begin, a few important reminders. First, please take a moment to locate the nearest exit. In the event of an emergency, the hotel staff will provide further instructions. Second, please silence all cell phones and other devices. Finally, remember to take your name badge with you if you leave the room. You'll need it in order to re-enter. Today's presentation will begin with a corporate overview by our Chairman and Chief Executive Officer, Mr. John Watson, followed by a review of our Upstream business by our Executive Vice President of Upstream, Jay Johnson.
We'll end the morning with a Q&A session where John and Jay will be joined by Mike Wirth, Vice Chairman and Executive Vice President of Midstream and Development, Pat Yarrington, Vice President and Chief Financial Officer, and Pierre Breber, Executive Vice President of Downstream and Chemicals. Before we begin, a reminder that today's presentation contains estimates, projections, and other forward-looking statements. Please take a few moments to review the safe harbor statement, which is available in your booklets and on our website. Thanks for your attention. I'd now like to introduce our Chairman and Chief Executive Officer, Mr. John Watson.
Thanks, Frank. Good morning, and welcome everyone to Chevron's 2017 Security Analyst Meeting, including those of you listening via webcast. We're all looking forward to providing you with information about our performance, our strategies, and the outlook for our business, as well as answering your questions. Let me start with three key messages that I'd like to convey today. First, the actions we're taking will enable us to be cash balanced in 2017 and continue growing free cash flow thereafter. We're finishing projects under construction to reduce capital spend and bring on new sources of revenue. We're further reducing capital spend by focusing our work on activity that is profitable at lower prices and returns cash sooner. We're reducing operating expenses and being more efficient in all that we do. We're completing planned asset sales, and we're doing these things while operating safely and reliably.
Second, we're focused on improving project, book, and cash returns on investment. This will happen as projects are completed and revenue is realized from growing volumes. It will be driven by an emphasis on shorter cycle time, high return investments in base business and share developments, and it will be aided by ongoing reductions in operating expenses and improvements in how we manage major capital projects. Finally, we're focused on unlocking value from our entire portfolio. We're able to take these actions because we have an advantaged, balanced portfolio of opportunities highlighted by legacy assets in Australia, Kazakhstan, and the Permian. Of note, in the Permian, we're ramping up to 20 operated rigs by the end of 2018, and we'll generate free cash flow there by 2020 at a flat $50 Brent price. We also plan to realize value through swaps or sales of significant acreage.
We're evaluating cases that add an additional 10 or more rigs after 2018, and these cases suggest we could see production above 700,000 barrels a day within a decade. Let's get started with our health, environment, and safety performance, the foundation of success in our business. This slide shows our days away from work rate and loss of containment incidents. The latter is a process safety outcome, which includes fires, spills, and other incidents. We have leading low industrial injury rates and an excellent record of keeping oil and gas in the tanks, vessels, and pipelines where it belongs. Our focus is on preventing high-consequence personal and process safety events. We work hard to properly identify operating risks in the business and mitigate them, including disciplined validation that those mitigations are functioning as intended. This is a long-term journey. We continue to make good progress.
On the financials, 2016 was a transition year for Chevron. Our earnings and cash flow reflected this. Low oil and gas prices depressed upstream revenue and required write-offs of investments no longer economic at lower prices. Downstream earnings returned to mid-cycle levels from 2015 highs. Recovery earnings was evident in the second half of the year as prices improved. We took the actions I discussed earlier to reduce costs, limit cash consumption, and protect the balance sheet. We closed the year with a debt ratio of 24%, one of the lowest in the industry. We were able to preserve and grow the dividend, paying out $8 billion in cash distributions. Despite lower prices, our cash margins continued to be quite competitive, as shown on this chart.
Using data from the 10-K oil and gas tables, our upstream cash margins were just under $18 a barrel at $44 Brent. With the changes in the composition of our portfolio from new projects and divestitures, we expect margin expansion, even at flat prices. We are leveraged to oil prices through the fiscal terms and oil weighting in our portfolio. We will benefit from higher prices. Although down from the highs of 2015, downstream cash margins per barrel remain strong as our refineries operate reliably. In both segments, I expect we will continue to be highly competitive within our peer group. Our financial priorities are clear and consistent. Our number 1 priority is to maintain and grow the dividend as the pattern of earnings and cash flow permits. We increased the annual per share cash payout in 2016 for the 29th consecutive year.
Producing oil and gas is a depleting resource business. Over time, we must invest in attractive energy projects to provide the earnings and cash flow to increase the dividend. Our capital spending guidance range is $17 billion-$22 billion per year through 2020. We will maintain a strong balance sheet in this volatile commodity price business. I expect a debt ratio in the 20%-25% range through 2020 at $50 per barrel oil. At times, we generate cash surplus to what we feel we can profitably invest, confidently sustain in dividend increases, or use to strengthen the balance sheet. During these periods, we will return cash to shareholders by repurchasing shares. Chevron's total shareholder return outpaced our major competitors and the S&P 500 in 2016. Chevron's TSR is number 1 relative to our peers for any cumulative holding period going back 25 years.
We appreciate the support from our investors, but we recognize markets are forward-looking and expectations are very high. We need to continue to deliver on our commitments and manage our advantage portfolio for growing cash flow and competitive returns. We expect to be cash balanced in 2017 at $50 a barrel. This slide shows how we get there, moving from a baseline of $11.8 billion in cash consumption in 2016. Approximately $2 billion is generated moving from $44 to $50 Brent, given our cash flow sensitivity of about $350 million per $ change in oil prices. Upstream cash flow from operations will increase from higher volumes and higher per barrel cash margins. Combined downstream and corporate operating cash flow shouldn't change significantly. Cash capital spending reductions will contribute over $3 billion consistent with lower budgeted spend.
We made a capital contribution to TCO of $2 billion last year in the form of a loan. We don't expect to make another contribution this year. In fact, we expect TCO will resume paying a dividend in 2017. We also expect higher proceeds from asset sales than the $2.8 billion generated in 2016. The case for improved cash flow assumes negative timing effects from affiliate dividends, working capital, and the realization of income tax benefits. Collectively, these impacts on cash flow are expected to be less in 2017 than 2016. Finally, we have upside if Brent exceeds $50 a barrel. This chart shows cash flow improvement will continue into 2018 and beyond at a flat $50 oil price. We expect upstream cash flow from operations to continue to grow as we bring on more high cash margin barrels.
Even at flat prices, you'll see both higher volume and higher per barrel margins. At $50 Brent, capital spending will be lower than in 2017 and toward the bottom of our $17 billion-$22 billion range. Asset sales proceeds will decline, falling below the level seen in our most recent years. At $60 or $70 Brent, free cash flow improves significantly as higher revenue more than offsets incremental spending from an expected increase in the cost of goods and services and a modest bump in activity. Growing free cash flow, of course, increases our capacity for shareholder distributions and balance sheet improvement. Chart 10 shows we're delivering on our commitment to reduce spend. 2016 capital exploratory spending was down 34%, or nearly $12 billion from 2015, and approximately $4 billion less than our announced plan.
Reductions were achieved by finishing major projects under construction, pacing and high-grading future investment, and realizing efficiency gains and supplier cost reductions. We are further reducing spend in 2017 to $19.8 billion, $15.1 billion in cash spending from consolidated companies and $4.7 billion in spend by equity affiliates. This puts 2017 budgeted spend in the middle of our $17 billion-$22 billion guidance range for the period out to 2020. This year's highlights include $2 billion on Gorgon and Wheatstone, $3 billion on the Wellhead Pressure Management Project and the Future Growth Project in Kazakhstan, $2 billion in the Permian, and $2 billion for downstream, including the Chevron Phillips Chemical Company expansion and Richmond renewal projects. Again, if we're still in the $50 world, you will see our spend tracking at the bottom end of this range.
Given our asset development plans and even with routine additions to the portfolio, it's hard to see a case where spending is above the top of this band through the end of this decade. As we complete an extraordinary period of long cycle time projects, the strength of our new asset base allows a seamless migration to profitable short cycle time activity. In fact, as this chart shows, about 75% of our spend is expected to generate cash within two years. The primary exceptions to this are the TCO project and exploration work. As we've discussed previously, we believe the TCO expansion is a counter-cyclical investment being done at the right time and on the right asset. It will start up in 2022. The remainder of our spend will be focused on activity that generates cash within 24 months.
We'll spend to complete projects under construction, like Gorgon, Wheatstone, Mafumeira Sul, Big Foot, Hebron, Clair Ridge, Moho Nord, and the CPChem Expansion project that have near-term start-up dates. We'll continue brownfield work, such as development drilling from existing deepwater hosts like Jack/St. Malo, Agbami, and Tahiti. We have profitable base business work in our conventional upstream and downstream that generates near-term revenue. Of course, we have the shale and tight investments highlighted by our work in the Permian. Spending is coming down, but production is going up, and substantially. The bars show volume growth through 2020, with and without asset sales. Growth over the next two years comes from the project start-ups and ramp-ups I just mentioned. Production before asset sales is depicted in light blue. 2017 volume is expected to grow 4%-9% on this basis.
Uncertainty in the speed of project start-ups and ramp-ups, price effects on production sharing contracts, and external events, including the timing of restart in the Partitioned Zone, create the range. 2018 growth will continue with the full year benefits of Wheatstone and other ramp-ups. 2019 and 2020 will see some growth, albeit at a more moderate pace, with the second half 2018 start-up of Big Foot and volume from our shale and tight investments. 2017 asset sales could reduce this year's production 50,000-100,000 barrels a day from the 4%-9% range. Cumulative asset sales could reduce top line 2020 production by a total of 150,000-200,000 barrels a day. We're comfortable that these asset sales are good value decisions. Volume grows and margin expands. This chart compares our 2016 Upstream cash margin with expected 2017 and 2020 cash margins.
At $50 flat Brent, the cash margin improves $2 per barrel this year due to lower operating cost barrels coming online, lower margin barrels being divested, and ongoing cost efficiencies. By 2020, the margins are expected to increase another $2-$3 per barrel. As prices rise, we obviously do even better. For example, at $70 per barrel, which is consistent with the consensus analyst forecast, the after-tax cash margin is expected to grow by more than $7-$8 per barrel from the flat $50 case in 2020. We've reset our cost structure. 2016 operating and administrative expenses were down 16%, or almost $5 billion from 2014. We're lowering costs by improving work processes, negotiating better rates from contractors and vendors, and becoming more efficient in all that we do. We have simplified a number of organizations to fit the work that we anticipate.
Our employee workforce is down 9,500 since the end of 2014. We expect further reductions in costs in 2017 and beyond, despite growing volumes. Last year, we provided guidance of a $5 billion-$10 billion in asset sales proceeds for 2016 and 2017 combined. In 2016, we made good progress with $2.8 billion in proceeds. We sold assets for value that were not essential to delivering our strategy, couldn't compete for capital with our current opportunity set, and were worth more to others than to us. We expect 2017 proceeds will likely move us towards the upper end of the 2016 to 2017 guidance range. We generally don't discuss specific assets targeted for sale until we have a transaction. However, there are some assets where knowledge is in the public domain, which we list on this slide. You'll see more announcements of those in progress during the coming months.
Our balance sheet is a differentiator, and we intend to keep it that way. This chart shows Chevron's historic debt ratio since 1980. Oil price cycles, specific transactions like the mid-'80s Gulf acquisition, and the recent decision to hold balance sheet capacity during a period of high spend influenced our capital structure over time. The average debt ratio throughout the period is approximately 25%, and today it stands at 24%. We expect the debt ratio in the 20%-25% range through the rest of the decade at $50 per barrel oil. The flexibility afforded by our short cycle project queue and the benefit of low-cost debt financing gives us comfort in carrying more debt than we did in the last decade. I said at the outset that we're focused on generating cash and improving returns.
This chart brings these goals together and illustrates how cash from operations grows as a % of capital employed. The growth in volume, margins, and portfolio actions combine to deliver about a 5% improvement in this measure of cash returns at flat $50 Brent. Of course, with higher prices, returns would only grow from this base. That completes my discussion of our near-term plans to improve performance. Before turning the stage over to Jay to provide more details on upstream, I'd like to offer a few broad comments about our portfolio. First, the downstream. We have a tightly integrated and profitable downstream in chemicals business. It earns good returns and is complementary to our upstream business by running certain equity feedstocks and providing processing and commercial expertise. These are high-performing businesses where we continue to evaluate opportunities for profitable growth.
Our refining and marketing business operates in integrated value chains in the U.S. and Asia. These are markets we like. We've been shifting our exposure to higher return segments such as lubricants, additives, and petrochemicals. In petrochemicals, we're feedstock advantaged on the Gulf Coast and in the Middle East. Our upstream portfolio is second to none. We're anchored by three legacy positions, a leading gas position in Australia that is now becoming a significant cash generator with resource development opportunities to keep Chevron and industry plants utilized and growing. A high-quality sour oil and gas position in Kazakhstan, built around the giant Tengiz field, which we are now expanding based on technical success demonstrated over the last 20 years, and an emerging and well-recognized resource development opportunity of more than nine billion barrels in the Permian.
These three legacy positions are outstanding. Importantly, because they are relatively young assets, they represent future high quality, high return investment opportunities. Chevron's upstream is built for success near term, also for the foreseeable future. Let me now turn it over to Jay to provide more details on the upstream business. Thanks.
Thank you, John. Good morning. It's a pleasure to present our upstream story to you today. The photo is a picture of the Wheatstone platform as it prepares for startup later this year. The platform is a gravity base. It sits in 260 feet of water. When it's operational, it'll gather and dehydrate two billion cubic feet of gas a day before sending it to the Wheatstone LNG facility. Our goal in the upstream is to provide competitive returns regardless of commodity prices. Across the upstream, we're focused on expanding cash and earnings margins by reducing our operating costs. We're building efficiency into our day-to-day operations. We're increasing the reliability of our facilities and completing major capital projects under construction. We're also being selective with our capital, favoring shorter cycle, higher return investments that build on existing facilities and infrastructure.
Assets that can't compete for capital represent higher value to others are being divested. We're expanding our cash margins by increasing cash inflows and decreasing cash outflows. As John mentioned, as the chart on the upper left shows, we expect production growth of 4%-9% this year before asset sales. We also expect production to continue to increase beyond this year as additional projects come online as the Permian continues to grow. The chart on the lower left shows the composition of the change in our upstream cash margin between 2016 and 2017 at a flat $50 oil price. You can see that the combination of our self-help initiatives, startup of higher value production, and divestment of lower margin barrels increases the proportion of high cash margin barrels. We're also reducing our cash outflows.
The chart on the upper right shows our upstream capital expenditures, which are down over 50% since 2014 as we finished major capital projects, improved efficiency, lowered our costs. For example, in 2016, we delivered our drilling program for about $1 billion less than the same footage would have cost in 2015. Finally, as shown on the lower right, we've reduced our unit production costs by 30%, a savings of more than $5 a barrel relative to 2014. The next slide provides information on our resource replenishment. It's important that we continue to economically replace our production with new resources and reserves to sustain our business. As you can see from the chart on the upper left, we've added 26 billion barrels of resource over the past decade.
After accounting for the production and asset sales, we have a net increase of nearly 7 billion barrels or 170% replacement ratio. In 2016, we added 1.4 billion barrels of resource with a unit finding cost of $0.95 a barrel and an exploration success rate of 79%. The graph on the bottom left shows our track record of industry-leading discovery costs over the last decade. The right side of the chart shows how we're working to improve project execution and delivery. In last year's second quarter earnings call, I discussed how we've applied these initiatives to the Future Growth Project in Tengiz. They're fundamental to good project execution, and we're applying them across our business to new and existing projects. It's helping to deliver project startups and ramp-ups, including those depicted in the map, such as Mafumeira Sul, which started up last month. Turning to our portfolio.
We have an advantage portfolio that's diverse in maturity, geography, and asset class. As shown on the chart on the right, we have 68 billion barrels of resource categorized into 5 asset classes. Our portfolio is centered around 3 legacy positions, conventional oil and gas in Kazakhstan, Australian gas targeted for LNG, and the Permian shale and tight. The Permian and Australian gas assets are prolific and are just starting long production lives. Tengiz is a more developed asset with a significant resource base that underpins the Future Growth Project. Together, these 3 legacy positions represent around a third of our resource, and by 2019 will contribute about a third of our worldwide production. Beyond these legacy positions, we have many high-quality assets.
Examples include deepwater assets in the Gulf of Mexico and Agbami in Nigeria, heavy oil in Southern California, and conventional gas in the Gulf of Thailand, each of which generates significant cash and earnings. Let's move to Gorgon and Wheatstone. At Gorgon, Trains 1 and 2 are producing about 230,000 oil equivalent barrels a day of LNG and domestic gas. We shipped 22 cargoes of LNG so far this year. We initiated production from the Gorgon field in February and are currently starting up Train 3. We applied the experience gained during the construction, commissioning, and early operation of Train 1 to both Trains 2 and 3. As a result, Train 2 started up and achieved over 90% of nameplate capacity within a week, it's been performing very well.
Train 3 construction and commissioning has gone smoothly, we're expecting first LNG before the end of this month, ahead of our previously announced schedule. The picture on the right shows the Wheatstone site, where Train 1 construction is nearing completion, our focus is on commissioning and startup activities. Offshore, all well work, flow lines, and umbilicals are complete. Work on the offshore platform is progressing as we focus on system commissioning and preparations for startup. Our outlook for startup remains around the middle of this year. The map on the left shows our leases, gas fields, and production facilities in Western Australia. We hold the largest gas resource position in the Carnarvon Basin with around 50 trillion cubic feet of gas, we also have the largest equity ownership of liquefaction infrastructure in Western Australia.
Near term, our focus is to achieve full utilization of all five trains. We plan to expand capacity by increasing reliability, followed by debottlenecking and rerating of the process trains. When you combine our large resource base and liquefaction capacity with the transportation cost advantage to Asia that Australia has over the U.S. and Middle East suppliers, we like our position. Over time, we'll work this advantage and monetize the gas through our equity facilities at Gorgon, Wheatstone, and North West Shelf, as well as through other available third-party capacity. Let's turn to another legacy asset, Tengiz in Kazakhstan. Tengiz is a world-class asset that we've been actively developing for nearly 25 years. In 2016, we achieved record annual production. Tengiz continues to demonstrate low operating costs and high reliability.
The chart on the lower right shows the production contributions we're expecting from the Wellhead Pressure Management and Future Growth projects. We're making good progress on both these projects. In the field, we have two rigs on location, drilling multi-well pads. Construction of the port is on schedule, dredging work is ahead of plan, and our focus is on ensuring that the port is operational for the first sea lift in 2018. We started fabrication of pipe racks and modules at both the Kazakh and Korean fabrication yards, and site infrastructure is well underway. It's early days, and the project is on track to deliver first oil in 2022. Let's move to the Permian. We have a superior land position with two million acres across the Permian Basin and a net unrisked resource of 9.3 billion barrels, a figure we expect to grow substantially.
Of the two million acres, one and a half are associated with shale and tight plays in the Midland and Delaware basins. If we multiply our surface area by the presently known benches, we have around 11 million bench acres. We're on path to realized value through a combination of accelerated development and deliberate portfolio actions. Since last summer, we added a rig about every eight weeks to our operated fleet. We're currently standing up our 11th rig, and our plan is to continue to add rigs at this pace, achieving 20 operated rigs by the end of 2018. We expect to generate free cash flow after C&E in 2020 at $50 oil. We're also evaluating cases where we continue to add rigs beyond 2018 and have several scenarios that would grow production to more than 700,000 barrels of oil equivalent per day within the next 10 years.
In addition to evaluating a range of production growth scenarios, we're also planning to swap, lease, or sell between 150,000 and 200,000 acres to develop more efficient developments and monetize assets that don't compete for funding. The next slide shows our performance relative to our competitors. We've made significant progress improving the capital and operating cost efficiency of Permian shale investments. As shown on the graph in the upper left, in 2016, we delivered a 30% reduction in our actual operated unit development and production costs and are competitive with our actual non-operated joint venture partner costs. They're some of the best operators in the basin. With respect to recovery, we're increasing lateral lengths and continuing to evolve our basis of design.
The graph on the lower left compares our actual 2016 average cumulative production from 26 Midland wells with the range of 68 competitor wells on the same basis. The chart on the right compares projected production from our new basis of design with production from our competitors' latest designs. Our Permian recoveries per foot have grown between 30% and 40% since 2015 and are expected to increase another 30% to 50% in 2017. We're competitive on cost, we're competitive on recoveries, and we're getting better every day. With advanced planning and our ability to leverage our global scale, we've secured the crews and materials necessary to execute our program. We source tubulars directly from a global supplier that maintains inventories and provides the pipe at globally sourced prices. Our rigs have staggered contract durations and competitive rates.
We've secured key services with a variety of indexed or performance-based contracts. We took advantage of the recent market downturn to secure pipeline capacity, as well as NGL and gas processing and offtake at desirable rates. We have access to multiple market centers to capture the highest realizations, and we've contracted capacity with options for expansion to support the majority of planned levels of production through the end of this decade. The chart you see on the left is our updated production outlook for the Permian, reflecting our base case of 20 operated and 15 non-operated rigs by 2018. Our current production forecast through 2020 is between 325,000 and 450,000 barrels a day, representing a compounded annual growth rate of 20%-35%, significantly higher than last year's view, as indicated by the dashed lines.
To be clear, we're aggressively incorporating the learnings from this increasingly prolific asset into our forward plans. We'll also continue to be disciplined in our approach to ensure we deliver full value. Our objective in the Permian is to be fully competitive on an operational and offtake basis, and then use our superior royalty position to generate leading financial performance. Remember, this represents our base case. With continued strong performance, we have options for even faster growth by continuing to grow our rig fleet. Until now, I've focused on our legacy positions. A critical contributor to our portfolio is our base business, which is made up of diverse assets that are already on production. Investments in our base projects typically have shorter cycle times and build on existing assets and infrastructure.
Because these brownfield projects leverage previous investments, they typically deliver relatively high return, low risk outcomes, frequently returning cost of capital at oil prices less than $40 a barrel on a flat nominal basis. These are competitive with the best of the shales. In 2017, we plan to spend $8.5 billion of capital on our base and shale and tight assets, which is expected to mitigate the decline of these assets to 2%-3%. When you add in our project startups, our total production is expected to grow between 4% and 9% before asset sales. By the end of the decade, after we've brought on new assets and grown the Permian, we expect the new base, plus shale, to grow about 1%. We're renewing our base with assets such as Gorgon and Wheatstone, which present ongoing opportunities for new brownfield investments.
Let's talk about the front end of our pipeline. Highlighted on the map are areas that represent the three largest resources for each asset class. As you can see, all asset classes are represented in a variety of locations. Much of our resource base is held by production, resulting in relatively low holding cost. We're using technology and best practice to unlock resources, lower unit development costs, and ensure that new developments are competitive for capital. Beyond our discovered resources, we plan to invest approximately $1 billion in exploration activities in 2017 and drill more than 14 exploration and appraisal wells. In closing, we're working our existing assets hard to grow earnings and cash margins and maximize our returns. We're improving our project execution and running our base businesses with high reliability and efficiency.
We have a deep, diverse portfolio built around three legacy positions, supported by a strong base business with ongoing brownfield opportunities. We're constantly reviewing our portfolio and asset allocation to develop our best opportunities and at a pace that we can execute with excellence. As John said, Chevron's upstream business is built for success in the near term and also for the foreseeable future. I'd like to turn it back over to John.
Thanks, Jay. That brings us back to the slide I showed earlier with our key message, which I'll briefly repeat. We're taking actions that will enable us to be cash balanced in 2017 and continue to grow free cash flow thereafter. We're focused on improving project, book, and cash returns on investments. Finally, we're able to take these actions because we have an advantaged, balanced portfolio of opportunities highlighted by legacy assets in Australia, Kazakhstan, and the Permian. That concludes our prepared presentations. I'll ask Pat, Pierre, and Mike to join us on the stage, and the five of us will be delighted to take your questions. Go ahead, I'll repeat the question.
Okay.
Yeah, go ahead.
Can you hear me, John?
Yeah.
Okay. Doug Terreson, Evercore ISI. John, your strategy or a strategy of improved focus on returns on capital has historically been the pathway to better valuation and equity market performance versus your peers and S&P 500. Congratulations on slide 17. However, when you consider that your peers have only generated about a quarter of the performance of S&P 500 during the past decade, it reasons that you might include some alternative performance measures in the mix. Three questions. First, how do you think about this issue? Second, why not make a market index like S&P 500 more prominent in your performance measurement? Do you think that there's a correct balance between peers and S&P 500 to ensure that you stay on top from a performance perspective?
Well, I think the market looks at a family of measures in deciding how they're going to reward you in the marketplace. For example, our TSR has outperformed all of our competitors, and we haven't always had the highest ROCE, and we've outperformed for 25 years. I think the market looks backwards to look at your performance, but it also looks at what they see coming forward, and we have a good story to tell. In fact, if you look at the charts that we show, we typically will show you TSR relative to our major peers, but we'll also show relative to the S&P 500. Depending on what your start period is, we've done well versus the S&P. If you start those calculations after the recovery from the great financial crisis, but before the drop in oil prices, the comparison isn't as good.
We do look at the S&P because we know we have to compete for capital, and in fact, we recently changed our comp system to include in the relative TSR measure that I know that you're aware is a part of our comp system is one of the competitors now, not just the big integrated company. I think it's a family of measures, Doug, but we're all focused on improving returns despite the low price environment that we're in. Thank you. Doug. Other Doug.
Thanks, John. Doug Leggate from Bank of America. Two quick ones if I may. First of all, your decision to hold on to a higher level of debt going forward, what does that mean for the priority for the incremental use of free cash in terms of buybacks and reinvestment and so on? My second one is, as you look at the portfolio mix, I think, Jay, you mentioned that by the end of the decade, shale plus base grows at 1%. What's the maintenance capital or the capital that goes along with that number?
Okay. I'll take the first one and let Jay take the second one. First, when it comes to priority and use of capital, we try to be pretty clear. We like dividends. We understand that you like dividends. As we generate free cash flow, we do favor increase in dividend. The qualifier we put on it is as the pattern of earnings and cash flow permit, because we don't distribute everything. I would never knowingly increase the dividend if I didn't think I could sustain it in perpetuity. We are thoughtful about when we increase the dividend, when we propose one, and when the board agrees. We do need to keep a strong balance sheet. We want to have access to the capital markets. I was pretty specific on some of the numbers we gave you.
We gave you an unconditional range for capital spending, which is regardless of price, it was $17 billion-$22 billion. The debt ratio was really at $50, it said that, look, we're going to generate some free cash flow at $50, we are going to need to keep the debt ratio in a reasonable range. If you have other questions about debt ratio, we can let Pat talk more about our interaction with the rating agencies. We do want to keep the debt ratio in a reasonable range so that we can have the access to the capital markets. Beyond that, if we're generating free cash flow We've shown a willingness to return cash to shareholders through share purchases. We've modeled a lot of scenarios, as you might have imagined.
I guess what I'd say is there's room for some of everything. There's room to nicely increase the dividend. There's room for a little bit more spending. We're rationing ourselves pretty hard right now on capital, there's some short cycle spend there is a range on the capital. If there's surplus, if things are better than we think, we may not want to put all of it to a dividend, we certainly can return some of that cash either to the balance sheet or to our shareholders.
You had made a capital question on.
Oh, yes. Oh, sorry. Maintenance capital.
Maintenance capital. In 2017, as we said, it's about $8.5 billion going into our base. The composition of the base is going to be changing over time as these new projects come in. Essentially out of those five asset classes, you'll see the LNG and the Permian, the shale and tight, take bigger roles in our base. We'll see that at the expense of mainly the conventional areas. Heavy oil and deep water should stay relatively constant. We don't have the base number that we're going to release at this point that far out. What I would say is we see a fairly consistent level of spend in that base, possibly increasing just a little bit as we bring some of these new projects in.
Jay, just for clarification. You said $8.5 billion gets you your base and shale combination decline, the base and shale grows at 1%. What's the capital number that goes along with that?
I didn't hear the end of the question.
What's the capital number? It's $8.5 billion this year, in 2020, what's the capital number?
It'll be higher. We're not going to give you a specific number, but it will be higher. If we're ramping up the Permian as we described, we're spending $2 billion this year. We'll be spending more in the Permian, for example. It will be higher, and there will also be some money that'll be going to capital projects during that period. Certainly, we've got the ongoing spending at Tengiz, and we may choose to initiate a project or two that we've talked about that's in our queue. Jason?
Thanks, John. It's Jason Gabelman with Jefferies. If I could ask one on the upstream and one on the downstream, please.
First on the upstream, the rate of growth in the Permian production is obviously pretty impressive. Even contrasting 700,000 barrels a day with 9.5 billion in resources, it's probably going to continue going up. How do you think about developing this resource in an efficient pre-cash flow generative basis, yet relative to the size of the resource, it's sending out 30, 40 years, and maybe ways of pulling that NPV forward? Second question on the downstream is several of your European competitors have been emphasizing a move into marketing as a relatively stable way of generating earnings and cash flow. That's business that you've kind of scaled back in relative to peers. How do you think about marketing as it relates to the downstream?
You mean retail products marketing?
Yeah, retail products and I suppose really just moving from the refinery through the logistics chain.
Okay. We'll let Pierre handle that one. We'll let Jay handle the first one.
Oh, you want me to do that?
Yeah.
On the Permian, it's a great resource opportunity. The more we learn about it, the more prolific it looks. We have a team set up now to look at, as I said, about 150,000-200,000 acres, which we consider to be kind of in that non-core area around the periphery or stranded or isolated leases that we want to try and move forward and release some of the value that's in those. We're working on that to begin with. Because of our ownership position, we're actually in a great spot because our first value measure is to try and core up areas that we want to do developments to increase and get longer laterals.
Because we own the royalty, we also have the option to lease out land to others that are ready to move forward, or we can go into joint ventures with them. We have lots of opportunities to release value out of this acreage, if not outright sell some of it. At the same time, as we look at building our rig fleet, one of the reasons we're being measured and doing it every eight weeks, which is still aggressive, it allows us to ensure that the supply chain on the front end, everything from developing the rig queue and the well queues and the well designs right through to the provision of all the goods and services is lined up, as well as the offtake on the backside. We've put all that in place now for the tranches that we've shown you.
As we want to continue to grow, we need to make sure that we continue to expand the organization to support that, and we want to make sure we're doing it in an efficient manner. We monitor our actual performance on an ongoing basis, we have that flexibility to make adjustments to ensure that we are getting the returns that we're looking for as we progress these developments. As we look forward, we've got plans in place today to move value forward in time, we also have this huge resource to unlock. As we expand this rig fleet, we start going through hundreds of wells a year and pretty substantial developments. I think it's going to be a good base for us.
Thank you.
Yeah. John showed the chart that has our three fuels value chains. We really look at the business on an integrated basis. We're managing from the refinery through the retail or the marketing. We're not really fussed on where we make the money. We have the teams organized and the scorecards organized to optimize value across the value chain. Right now, I'd say retail margins are strong and refining is a bit weaker, but that can ebb and flow, our focus is really on making sure that we work the margin across the whole value chain. If it shows up in retail, that's fine. If it's on refining, that's also fine. We're pretty balanced. Really, the way we're setting up is our refinery production kind of goes through our retail network.
Paul?
Thanks.
Thanks, John. Paul Sankey at Wolfe Research. You've upgraded your volume outlook for the Permian, I think you've set a $50 breakeven, a $50 oil by 2020. You're at a 20+% CAGR. All these numbers are very impressive. Those are actually somewhat behind the leading edge of the industry, even if we look at your charts, we can see on slide 10 that actually your performance is in line with average. We know that your acreage is, I think, good to better than others. Can you talk a little bit about what it is to be a super major versus these E&Ps? Do you have higher costs in terms of safety? Are you putting in more money up front in infrastructure? What is it to be your business model versus these guys' business model? What are the advantages and disadvantages?
I'd say you're a little bit late to the play. I wonder how you're going to catch up and exceed performance. Thanks.
Actually, the purpose in us showing you some of those numbers is to show that we are competitive on cost. We have adopted a strategy of taking best practices and incorporating them. I'll give you an example. I mentioned the fourth quarter call, we added 500 million barrels of resource spending nothing by watching what offset operators do. One of the reasons we have a low finding and development cost is because we're moving in a fast follower fashion. That doesn't mean that we don't have proprietary technology that we're applying to our business. We are, and we're not cherry-picking data. We're giving you actual data that's there. We are competitive. That was really, I think, the point that Jay was trying to make.
In terms of growth, there are a lot of big numbers that are out there in terms of ultimate recovery and production rates that are out there or growth rates, we've got a range around the growth rate. I think 20%-35% kind of growth is as good as anybody. We're not starting from zero, we're starting at 140-something thousand barrels a day now. I think we are competitive. I would just sort of as a, maybe it's a bit flippant, but we invented factory drilling. If you look at what we do in the Gulf of Thailand, if you look at high-intensity drilling that we've done elsewhere such as Bakersfield in California, we actually know how to do this. I wouldn't represent that we're necessarily trying to grow at the fastest rate.
We're really focused, as Jay said, on growing at a reasonable rate, but being sure that we get good returns on the investments that we are investing in.
Thanks, John.
Maybe just one other add to that is I do think one particular advantage we can bring is our global reach on supply chain. As I mentioned on the tubulars, we're coming direct from a mill. They're handling our inventory, so we don't have that sitting on our books, but we use global pricing, which is outside of any immediate region that may see other kinds of pressures. When we deal with a lot of these contractors, these are the same big contractors we deal with worldwide. They're going to want to preserve a relationship with us worldwide, over and above what's happening in a specific region.
Thanks, guys. The follow-up is, I thought of you as having really four legacy areas. The missing one for me now is the deep water. It's not that long ago that it would've been one of your highlight areas. You've raised your Permian guidance. Are we really knocking out the deep water with the Permian, to put it simply?
No, the deep water. I'll let Jay talk a little bit about where we are in the deep water, and I'll add to it when it's through.
I would say that the deep water is still a critical area for us and really important. It's just that in terms of any one single asset that represents one of these legacy positions, it's not really there. From a deep water, you saw the resource position. That resource position for deep water is actually bigger than that, because a number of our assets sit in multiple asset classes. A good example would be Jansz and Gorgon are technically deep water developments. It's just that they provide LNG, so we put them in the LNG bucket. The technology and the skills that we have around deep water are critically important. We're bringing our development costs down for new deep water developments. We expect to see them very competitive.
I think deep water's going to still represent a good place for new resource and new developments as we drive those costs down and use our expertise. Our deep water drilling costs went down 30%. Our rate of penetrations are up, both on the exploration and the development drilling side. All those things are coming together to really make deep water, I think, competitive as we move forward.
Ed?
Ed Westlake, Credit Suisse. Two, I guess, financial questions. Firstly, disposals. I think Jay spoke of coring up 150,000-200,000 acres or something in the Midland. You obviously have that chart showing as you go out there's a cumulative 150,000-200,000 barrels a day of disposals.
Right.
Presumably lower margin. You've got that $5 billion-$10 billion range. Presumably disposals don't just stop at 2017. Maybe some sort of color as to the medium-term contribution to free cash flow from disposals is my first question. The second question is around the dividend. It's attractive against the S&P. Obviously, within the majors asset class, there are higher dividends that are out there. Maybe some sort of color as to what the plans are to grow it. Thank you.
Pat, you want to try that one?
On the dividend?
Sure.
Yeah, absolutely. I'd love to talk about dividends. It is our number one priority. We are in the position of getting cash balance with asset sales this year. I think your initial question talked about cascading asset sales. We do see perhaps some contribution in the outer years, but our intention is to get cash neutralized this year with asset sales and be cash neutral without asset sales living within our means in 2018 and 2019. We do intend to grow the dividend over time, as John said, as earnings and cash flow permit. We're structured to try to be able to do that with proper investment. You mentioned that we are from a cash yield standpoint, a dividend yield standpoint, perhaps not as competitive as all of those.
I would say on a cash basis, we certainly are competitive with the peer group, and it's something that we watch and monitor very extensively. We want to grow the dividend. We want to build a foundational business that allows us to sustain and grow the dividend over time.
Okay. Go back there.
Disposals. Asset sales. I don't know.
Asset sales. Go ahead.
Asset sales.
They've averaged what? $2 billion-$3 billion over the years. There's always going to be some background level of sales. We're going through a period now where it's a little bit heavier, both with the rationalization that we've done in the midstream and downstream over the past few years, and then some of the ones that are currently in the queue. There's always some background level. It's a little difficult to predict. Yes, go ahead.
Thanks. Ryan Todd at Deutsche Bank. Maybe if I could ask a couple. One, in the Permian, what are the constraints on your ability to deploy capital in the Permian over the next three to five years? Is it predominantly top-level cash flow, or is it field-level logistical constraints? How do you think about limits on your ability to deploy capital there? As a follow-up, CapEx is overwhelmingly pouring into U.S. shale and particularly to the Permian Basin. We saw one of your peers last week talk about a pretty aggressive ramp there in the Permian as well, and certainly the U.S. E&Ps.
How do you think about the risk of inflation and constraints going forward, like we saw in the oil sands 10 years ago or in Australian LNG five years ago, and the risks of that versus opportunities elsewhere in the portfolio in less inflationary regions, I guess?
How are we fixed to manage costs and what-
On the cost side, first of all, for our current level of activities, we've got contracts in place, so we're pretty well fixed. Now, some of those contracts use indexes so that we can remain competitive as prices change. Others are fixed term or staggered durations. We also have performance-based contracts. We've got a variety of different forms that we use depending on the nature of the service of the goods and material coming in. As I said, we also have the global reach because a lot of the people we're working with in the Permian are our partners on a global basis, and so we're using competitive pricing. We have not seen any kind of cost inflation outside of that immediate area in the Permian in the world. We're able to really use that to leverage our position.
There may well be some pressure going forward, but we're well positioned both through our contracts we have in place and the leverage that we have, as well as the gains in efficiency and performance we continue to see to stay focused on our returns in the Permian. I think the other advantage, when you look at something like what happened in Australia, that's where you're committing to build large, massive plants with big investments. Once you start that program, you're very committed. Whereas the Permian is very flexible. You're moving developments. You can move them in and out. You can slide them. Particularly Chevron, because of our land position, we have the ultimate flexibility in terms of when we drill these. We're not driven by drill or drop contracts.
We feel we have good mitigations in place, but we also feel that we've got a good land position that lets us be adaptive and stay focused on generating the highest returns.
Just an observation follow-up. If you look at what happened up in the oil sands area in Australia, those are pretty remote areas. The Permian Basin is oil country central, and I don't think you would call it as remote an area. I think you're likely to see an influx of goods and services and people if things get better. To the extent that costs rise, we've got a lot of options in our portfolio, and that's part of the reason we show some ranges around these numbers, because you're just not sure how the market might behave. Okay. Paul?
Thank you, John. Paul Cheng, Barclays. Two question, actually. First is on the balance sheet. John, if we look at the mega majors such as you guys, the business model in a sense is that throughout the entire cycle, at the better half of the cycle, you're never going to grow as fast as some of your smaller peer. At the bottom of the cycle, you are more sustainable. Perhaps that can even take the opportunity of the down cycle to enhance your return by either acquiring some assets on the cheap, you did it in the past, or that to get a better negotiation with the government. From that standpoint, with the introduction of the shale oil, you can argue that the volatility may be even higher. Should you even target just historically at the 20%-25% on the debt ratio?
Instead, should you be targeting a much lower so that when you see that call, volatility, you can actually take opportunity? That's the first question. Can I go with the second one, or do you want to answer this one first?
I'm going to give an answer that my chief financial officer will like, and that is that we have the flexibility to reduce debt further, depending upon how much free cash flow we're generating. The point we're trying to make is with short cycle spend and with a really very low cost of debt, it's prudent to carry a little bit more debt than previously. Pat works very closely with the rating agencies, and we want to be sure that we maintain access to capital. The inference of what you say is also, should we be doing acquisitions or things of that sort? As I've told you and others many times before, we're always out there looking for resource. We just picked up an attractive block in Mexico, for example, and we're looking to add to our position over time.
We want to do so on terms that work for us. Right now, we've got a lot to chew on in our portfolio, and we don't necessarily see assets as being undervalued when we look at opportunities. I do expect host governments to be responsive also over time. We have resource in many areas, and in some cases, we're unable to conduct activity economically at lower prices. I also hope in due course we'll see better terms and conditions in place.
The second question is, if you're looking at your organizational capability and also the resource, is there a sweet spot long term what maybe the production growth rate should be? Within that, how big is the portion is the deep water going to be? In your current base plan, what kind of inflation factor that you build in? Thank you.
We've gone through a period, Paul, where we've seen pretty high growth rates that I think I've advertised for seven years aren't sustainable. It was because we had two LNG projects that had to move at about the same time, and some deep water developments that had to move at the same time, in part because of the moratorium. We did stack up projects, and we're now seeing some of that volume growth come about. Over time, we think you need to sustain the business in some reasonable fashion. We're not necessarily targeting a specific growth rate, particularly when you look out five to seven years, we're always going to give you a range. We're really focusing now. We need to improve returns in the business.
We put a lot of capital in the business, and we need to focus on getting the most out of it, whether it's through the base business and shorter cycle spend with higher returns or through some of the incremental work that we can do to debottleneck and rerate facilities that Jay referenced in Australia. Otherwise, getting the most out of the asset base that we have so that we can improve returns on those three bases that I described earlier, cash, book and project. Okay. Go on, Jay.
Hi, Sam Margolin at Cowen and Company. You've got a number of pre-productive assets moving into cash flow positive territory this year, and you mentioned Tengizchevroil is actually going to be contributing cash even in the middle of a capital project. It does seem inevitable that with all these assets starting to throw off cash, that maybe the company within the next half decade or decade reenters a phase where there's a lot of growth in the outer years forecast. Assuming you don't reject that premise outright, I guess within that context, what do you think about the opportunities for post-decade from a resource standpoint? Do you have a preference for gas to oil? Are you looking to integrate potentially some gas assets with a chemical piece that has a higher sort of structural demand piece?
I guess as you enter this kind of free cash phase, what do you think the biggest opportunities are for the outer years?
Well, I guess at a high level, demand for our product is likely to continue to grow. You can debate about how much. Under almost any scenario that the IEA and others postulate, we expect to see continued growth. I imagine we'll capture our fair share of those opportunities. There are a lot of assets in our portfolio that we haven't even talked about. We haven't even talked about our Marcellus position because we've got weak gas prices right now. We haven't talked about our positions in a number of international jurisdictions where there's opportunity to grow. The answer to your question is, yes, I think there will be opportunities to grow. What I've tried to characterize is that we're not likely to be in a phase like you saw the last seven years. That was fairly unusual.
I don't think it's likely to see that. With the share position that I've said before could be 25% now, obviously 25% plus a share of our production in a decade, plus the other assets that we've got. I mean, Tengiz goes on beyond. I would like to just clarify one comment that you made. This year, we expect Tengiz will contribute cash net of spending. On a go-forward basis, it's very profitable. It generates cash, but there will be co-lending that will likely be required during that period. There'll be dividends and co-lending through the life of this project. Remember, our share is roughly $3 billion a year out through 2021. Yes.
Thanks. Phil Gresh, J.P. Morgan. I just want to follow up on slide eight, the cash flow after dividends. Pat, you had mentioned that you expect to get to a $50 breakeven, I think you said by 2018, without asset sales. John, you had made some comments about some transitional nature, obviously in 2016, but also in 2017, you talked about affiliate spend working capital and other factors. I was wondering if you could elaborate a bit on maybe quantify some of those factors for 2017, just to give us some additional comfort that you can get there in 2018 at 50 without asset sales.
Yeah, I think the components you're talking about are some of the negative headwinds that we have had certainly through 2015, more extensively in 2016, and there will be some in 2017. Probably the biggest element of those relates to deferred taxes. That's a circumstance where they're generated really in two different mechanisms. One is as you come off of a high investment period of time into a lower investment period of time, then what you were capturing as accelerated tax depreciation changes versus book, you've got a headwind associated with that. Secondly, and more importantly, more recently, has been circumstances in certain jurisdictions where we have been in a net operating loss position. In those circumstances, either you can, in some jurisdictions, you can carry that money back against prior tax returns. In other circumstances, you can carry it forward.
In 2017, I do know there will be some relief that we will get in circumstances where we can carry back against prior tax returns. It's not a huge number, but there is some, a few hundred million dollars there. More generally, if you posit a $50 flat case, we're not going to be able to reverse those headwinds on a deferred tax basis. In the aggregate, if I think about deferred taxes, I think about working capital, and I think about the difference between equity income and equity distributions, it's probably a penalty, not the same size as John said as we had in 2016, which was almost $5.5 billion-$6 billion, but something on the order of $4 billion plus would be our expectation.
Very sensitive to price.
It is very sensitive to price. As you move from $50 to $60 to $70, some of that recapture occurs.
Yeah. In 2018, at $50, you would still have some headwinds.
We would still have some head-
Not as much as 2017.
Exactly. Exactly. I think if you go back and you look at 2015, we had average Brent prices of around $52. In our case here, it's $50 flat. In 2015, we incurred on a deferred tax basis about $2 billion worth of penalty.
Okay.
That penalty. I don't think any of these are very uncommon in the industry. I think we're-
Understood. In fact, my follow-up for Jay would just be the view that you can get to free cash flow positive by 2020. I know Doug had asked about the base spend, I guess, more specifically in the Permian, if you could elaborate a little bit more as to how you get there, whether it's with certain cash margin number or a certain amount of CapEx that you think would be required in 2020, just any kind of additional color to help us with that. Thanks.
We're projecting forward that we would use today's kind of conditions into 2020, and that's why we say at a flat $50 price. We continue to grow production, obviously, based on that chart. That's all premised on a $50 price. We have 20 rigs, company operated 15 non-operated gross rigs. When you put that together, along with our current performance on the drilling, that's what gets us to the 20 flat. To the extent that there may be some cost increase, we're seeing that our improvement in efficiency and our improvement in the technology and the recoveries offset any of those price grows is our assumption in making that statement.
Good morning. It's Theepan Jothilingam from Exane BNP Paribas. Two questions, please, on the upstream. You've certainly showcased the Permian TCO Australian LNG. I was wondering how competitive is Chevron's portfolio outside those three basins in terms of a $50 flat environment? Could you talk about how the organization as an operator is recycling projects to be competitive at $50? Second question is actually just around your exploration strategy for 2017 and beyond. If you could just talk a little bit more about where the emphasis is between high impact and perhaps infill, brownfield extensions. Thank you.
Sure.
In terms of how we're being competitive, we've lowered our cost structures. We've saved $5 a barrel on our production costs over the last couple of years and brought our cost down 30%. We continue to drive to bring that cost structure down. Just as importantly, we're looking at bringing our efficiencies up. We've made great strides in this area. We're using integrated operation centers in a number of our base businesses now that integrate all the different functions together so that we're making decisions on a returns basis as we go forward. We have integrated a lot of our logistics operations, which really squeeze a lot more efficiency out of our transportation cost to support our businesses. These are going on around the company.
As we've also shifted our capital into these base business opportunities, they're shorter cycle, they're higher return, and they're lower risk because they're based on existing assets and existing reservoirs where we understand the nature very well. We're seeing our incremental development costs associated with these types of projects in kind of the $20-$40 range, and they are very competitive, even in a $50 price. Some, depending on the fiscal terms that we're in and all that may not be so competitive, and we're shifting capital away from those areas and focusing on the ones that can be competitive.
Thailand, Nigeria, Bakersfield, all of these are economic at low prices.
Correct.
Yes. I'm sorry, wait, I think he asked about exploration.
Exploration. This year, we've got some important wells. We're going to drill a well up in the Barents Sea. A lot of the exploration area that's very interesting today are the areas that have been either politically or technologically off limits. As we move into the Barents Sea, this was part of the area that was agreed between Russia and Norway. We look forward to that well this year. We have some additional drilling in the Gulf of Mexico adjacent to our Anchor discovery. Those constitute some of the main areas that we'll be focused in as we look forward.
Yes.
Thanks, John. Neil Mehta here with Goldman Sachs. Chevron has a unique perspective on the oil macro because you can see non-OPEC supply, OPEC supply, demand, inventory. John, it'd be terrific to get your perspective on each of these things and what stage of the rebalancing process you think we're in from the group's perspective.
Well, you're right. It's been a moving target in terms of rebalancing. Obviously, OPEC took some actions to try to accelerate that rebalancing. I think they were very deliberate in how they did it. They talked about a temporary reduction in production because they saw demand growing and the market just taking a little bit longer to balance, they wanted to accelerate it. I think they've been very careful not to foreshadow cuts that would extend beyond a certain time period where the market is balanced. I think going forward, they have that flexibility to do that if they choose, and I suspect they probably would given their motivations. Having said that, one of the observations that I would have is the industry keeps getting better. A lot of the attention is focused on the shales and the potential there. I think it's elsewhere as well.
If you look, for example, in the deep water, we've been able to hold Agbami, Jack/St. Malo, and others onto a longer plateau than we might have thought a few years ago with some of the extended reach drilling and other actions that we've been able to take. The plateau has been pushed out a little bit. At $50, not very many new projects will start, however. I do think you eventually do get beyond the plateaus of some projects. Eventually, you do need all those asset classes that Jay showed, and the exact timing is very hard to predict. You've got all sorts of wild cards that are in there in terms of exchange rates, fiscal terms, how fast the technology moves. I do know that it's going to take all asset classes.
The market's 97 million barrels a day, growing roughly 1 million barrels a day going forward. Shale is, what, about 5 million barrels a day. I do think it's going to take all asset classes, notwithstanding the industry's persistent ability to get better over time. We do think that prices will rise in the time ahead, and we're not going back to $100 oil anytime soon, barring some big intervention in markets. I do think that we're going to need better prices so that there's enough new developments that will begin over the next 5 to 10 years.
Thanks. It's Blake Fernandez with Howard Weil. I know you've already talked about cost inflation, within your capital framework of $17 billion-$22 billion, is there an explicit assumption there for reinflation? Are you viewing $22 billion as kind of a hard ceiling through the end of the decade?
Yeah. One of the things that I tried to be pretty specific about the footnotes in some of those charts, and that's why I said it's hard for us to see inflation. When you're talking at the kind of prices we're seeing, $50-$70, I don't see massive inflation coming back to the business. You could see it in an isolated basin. We've said that at $50, we'll be at the bottom of the range of $17 billion. We don't think there will be any cost inflation. If there's a little bit more, then perhaps we'll see some higher costs. We don't see $5 billion in costs from that $17 billion base getting above $22 billion. You could see some increase in costs, but we just don't see in that sort of a price range significant cost inflation coming back to the industry. Yes, go back there.
Okay, sir.
Hi. Roger Read, Wells Fargo. Maybe coming back a little bit to the balance sheet, you mentioned rating agencies as a component of keeping the debt ratio at closer to 24%, but then the graph also shows back in the, I guess, the '90s last down cycle, a much higher level of debt. Would you be willing or what is the pushback from the debt rating agencies in terms of how you grow the dividend over time, maybe leaning on the balance sheet a little bit more, let's say in a $50-$55 oil world?
Yeah. When we have conversations with the rating agencies at a very granular level, they're very familiar with our plans. The margin expansion, the production expansion, the growth and free cash flow, very detailed explanations of timing and circumstances around asset sales. We're very open and transparent with them, and they're very confident, I believe, in that we do exactly what we say we're going to do. Because we've had a hierarchy of dividends first, investments second, balance sheet third, share repurchases fourth, and the fact that we try to balance those over time, I think they have a very good understanding of what our going-forward plan is. They will take a look, and they will do what they need to do based on our metrics.
I think when you look at our profile for free cash flow generation, and our restriction that we have put upon ourselves over this down cycle on C&E, and the limit that we put on C&E, the $17 billion-$22 billion range, and the fact that we've said at $50 that C&E level will be closer to the bottom end of that range. All of those factors give comfort to the rating agencies. They look beyond just the financial metrics. They look to see what's happening operationally, what's happening from an execution standpoint, what's happening in terms of reserve replacement. I feel that they will take all of that into consideration. We do emphasize to them, and to you as well, that keeping a strong balance sheet is a priority for us, and we will do our best over time to balance those considerations.
Okay. Evan?
Thanks. Evan Calio, Morgan Stanley. John, today you really project increasing free cash flow at a lower price, significant running room in the base of your assets, and potentially shorter cycle times. Has the way that you think about M&A changed going forward? You seem to project to be more of a net seller. Then secondly and related, if inflation, which has been a focus here today, is the biggest risk to your U.S. growth and the assets you're highlighting with the highest growth profile, do you see the need to vertically integrate there to ensure deliverability, whether it be sand or completion, as some of the other E&P peers have done? Thanks.
Yeah. A couple comments on M&A. Many of you I've worked with for a long time. If you go back a generation or so, you could look at M&A transactions and the synergy alone could pay for it. I mean real synergy, real cost synergy. I've been on record for some time saying it's harder now. Markets are more transparent. Everyone's gotten more efficient in what they do. Grinding out cost synergies is much harder in transactions. When we talk about, we have a watching brief on lots of opportunities that might be out there, but when we look at the valuations, we see many of them as being pretty rich.
We see company-level M&A as being pretty tough, and I think that's been borne out in a lot, you haven't seen that much M&A relative to what you might have seen a generation ago. I think most M&A will tend to be more tactical or opportunistic. With low interest rates, it's driven valuations up to pretty robust levels. I don't particularly expect a lot of M&A, and I think our portfolio doesn't require it right now. We do need to add to the portfolio over time, but we've done that, and I think you'll continue to see us do that. On the upstream question?
Yeah, I think on the upstream question, we've taken the view that we don't have to be in those businesses. We use our global reach, we use our global relationships to work with contractors who have the ability to reach in and secure those resources that we need. We feel very comfortable we're covered with those contracts. We have what we need for our supply chain for the growth that we showed you, and we'll continue to work those relationships just to make sure we have the supply coming to us as I talked about earlier.
Our industry is one of the most outsourced industries. We generally don't own the rigs. We've got construction companies we hire. It's very much dependent on service companies and contractors, and we don't see necessarily it being unique in the Permian. John?
John from
John from, two quick ones. Given the restructuring that you took since 2014, do you think you're adequately sized to deliver your short and long-term growth plans? That's for you, John. The second one is for Jay. How easy will it be to do Permian swaps? Also, how long are your horizontals?
Okay. Sure. We've been very much focused on trying to ensure we keep the right. I assume you're referring to human resource, and are we properly sized for that? We've worked very hard to do that. The challenge for us, frankly, with our employees has been as we come through this period of heavy spend, a lot of the projects we're going to be ramping down in terms of people. Some of the reduction in employment has been natural, and it's been contractors as well. As we've finished projects, there's been a natural drawdown in the organization. We've also been very careful to keep some of the critical skills.
For example, we haven't discontinued hiring of some of the key petrotech disciplines in the U.S., we have kept some people beyond just the strict minimum that we might need for operations today, so that we do have the flexibility to add rigs in the Permian or to take on a deep water project or any of the other activity that we might need. It's a tight balance, and we've tried to be pretty careful in how we approach those reductions as we get more efficient. Jay?
Yeah. Your specific question on the laterals where our goal is to drill mainly 7,500-10,000-foot laterals, depending on the particular license that we're working, the development that we're working. There's really four key parameters that we look at in designing our wells and our development plans. It's lateral length, the well spacing, cluster density, and then the proppant loading. The combination of those four really are key to ensuring that we get the return from the well. We're not trying to set a record for highest production or getting the most sand loading per stage. What we're looking for is the return that we get for every barrel we produce out of that particular development. In terms of the swaps, the swaps have been fairly straightforward to do. It adds value to both players on these swaps.
When we can both drill longer laterals, it's truly a value creation opportunity on both sides. It's rarely a win-lose. Rather, working with other companies to swap acreage and build longer lateral development positions works for both of us. The key is because we own so much of our acreage, we don't want to get too far out in front of our developments because then we're on a time clock once we make that swap. What we want to do is have sufficient time before development's going to begin. We can do the land position, develop the well queue, and move into that development in an efficient manner. It's really part of that supply to the development factory drilling that John talked about that's just like our supply chain and the other aspects of being efficient in our development.
Okay. Who haven't I gotten? We're getting near the end. Right here in the middle. That's fine. We'll get both of you.
Hi, it's Anish Kapadia from Tudor, Pickering Holt. First question is, looking at the buybacks again, what are the triggers that you see to come into place to restart buybacks? Is that the debt ratio getting below 20%? Is there a sustained level of oil price that you require for that? Second one's just a quick clarification on Slide 9. You show around $3 billion of cash flow that is going to be a reduction in cash flow from the asset sales. Just wondering what's the kind of cash in from those asset sales that you expect? The final one is on your CapEx, the $17 billion-$22 billion range. I was wondering if you could give some examples of what would drop out at the bottom end of the range and what would come into the CapEx budget at the top end of the range.
Okay, we'll see if I can remember all those things. When it comes to asset sales proceeds, what we're showing on that cash flow chart is that we expect significant asset sales this year. As you look in the outer years, there's a negative delta on the contribution from asset sales because the proceeds will simply be smaller. I think that answers the one. In terms of share buybacks, I think you said it all in your question in terms of what we would look at. Our priority is on increasing the dividend, but we try not to get over our skis on the dividend because I would never knowingly increase the dividend if I didn't think I could sustain it in perpetuity.
If we got to a position where our balance sheet was in a comfortable and good range, got to a position where we were increasing the dividend at a rate that we thought was appropriate and we're generating surplus cash flow, we're more than willing to give some back to the shareholders through repurchases. What was the third one?
C&E and Tengiz.
Oh, what falls out of the capital program?
High-end, yeah.
If we're at the high end of the capital range, I don't think it's anything other than what you've heard here. I think we have some flexibility to increase our base business investments. Right now, we're high grading quite a bit, but if we saw prices stay where they are and firm a little bit, we could add rigs in Bakersfield. We could add rigs in Thailand. We can add rigs in a number of locations. You would see some additional spending that would be devoted to that type of high return activity. I also expect as you get out toward the end of the decade, an Anchor development, for example, in the Gulf of Mexico is an example of an opportunity that could go.
Remember, the capital associated with 1 or 2 of those types of projects is much smaller than the big flagship type developments that we've indicated. I'll take one more question from right here, because you've had your hand up.
Thank you. It's Brendan Warn from BMO Capital Markets. I guess just on outside of your Permian business and to add to your growth beyond 2020, so your 2% that you talk about, are there any sort of near-term FIDs that we should be thinking about, and particularly just where, say, Rosebank is in that pecking order, and also, say, for Canada, Kitimat? If you can touch on those couple of projects for me, please. Just clarification more just so I understand, in terms of the 20 operated rigs you're looking to add by end 2018 at $50, is that regardless of oil price, that sort of number? I probably have a view that we're in the $60 oil price range. Am I expecting we're going to be an additional 10 rigs on top of that?
Go ahead and take the first one.
Okay. I'll take the Kitimat and Rosebank. Rosebank, as you know, is a deepwater project west of Shetland. We've used this period of time in the low price to really revamp that project. We've gone through all the way back to the reservoirs. We've got good seismic. We have redesigned the subsurface as well as the surface facilities. We've moved the hull, for example, from being one of the largest turrets ever built in the world to now comfortably well within the envelope of what's established in the industry. Our goal is to de-risk these things and really take them back to basics.
We're looking to stretch out some of our production profiles because while it may give you slightly less net present value, it gives us much higher capital efficiency because we can continue to drill the reservoirs and keep these facilities full for a much longer period of time. They're smaller, easier to build. Rosebank has attractive economics. Actually, to build on the last question, we have far more economic projects today than we're willing to spend money on. It really lets us high grade. It's not so much a matter of can we get some other economic projects to invest in? It's just which ones do we choose and when.
These deepwater projects John mentioned, Anchor, things like Rosebank, we're not looking to just pile them on top of each other, but as I said before, we want to do these where we can assure excellent execution and at a pace we can have execution. We're looking to sequence them into our capital programs, and we're looking to make sure that we build on the learnings of each one and roll it into the next. Kitimat is really more about when do we expect to see additional demand for new LNG. Our main focus right now is on Gorgon and Wheatstone, getting those to a reliable, steady state operation, and then once we have that, looking at how to debottleneck those and get the maximum capacity out of that existing set of processing trains. At the same time, we've been doing appraisal drilling at Liard.
We've got wells on production. It's very encouraging. It looks like a prolific resource. We're spending a lot of time looking at the development of the processing facilities for Kitimat. We have to get that cost down to a point where it can compete heads up with the Gulf of Mexico for Asia deliveries. That's our goal.
Yeah.
I think as we put all that together and then we combine that with the market, we'll have a good indication of when's the right time for Liard.
Just a quick comment on the rig question. The case we showed on the chart is 20 operated rigs and 15 non-operated rigs by the end of 2018, and it's at a $50 case. There's some variation around what the recoveries will be, so we've shown a range in the production. We can choose. What I said earlier is that Jay and his team have evaluated a number of other cases that as we continue to deliver the kinds of returns we expect and realize the kind of recoveries that we talked about and with additional improvements, we can add additional rigs. What we've said is we've really got our supply chain lined out to do what we've described up to 20 rigs by the end of next year. Then we're evaluating cases to see where we go from there.
We always have a chance to update you next year. With that, I'll thank you very much for your time and attention. That concludes our webcast.