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 joining us via webcast to Chevron's 2016 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 St. Regis 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 reenter. 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 section where John and Jay will be joined by Pat Yarrington, Vice President and Chief Financial Officer, Pierre Breber, Executive Vice President of Downstream and Chemicals, and Mike Wirth, Executive Vice President of Midstream and Development. 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 the website. Thanks for your attention. I'd now like to introduce our Chairman and Chief Executive Officer, Mr. John Watson. Thank you.
Thanks, Frank, and good morning. I'd like to welcome everyone to Chevron's 2016 Securities Analyst Meeting, including those of you listening via webcast. Our presentations today are focused on what we're doing to create value for our shareholders going forward in a low-price environment. Let me start with the four key messages I'd like to convey today. Preserving and growing the dividend is important to our shareholders and to management. All of our actions are aligned with this objective. In order to grow the dividend, we have to continue to make attractive investments that will generate earnings and cash flow. We have to pace investment outflows and have a cost structure that match a lower price world. We are reducing both capital and operating spend accordingly. As we finish projects under construction, spend is coming down and production is growing, improving our net cash flow balance.
We're prudently using some of our borrowing capacity to finish projects under construction and to pay the dividend. We've kept a strong balance sheet precisely for times like these. We recognize the need to improve financial returns. We expect to improve them in part by directing a higher proportion of our capital to high return, shorter cycle, and brownfield opportunities. Let me give you a quick review of 2015 and our long-standing financial objectives to set the stage for discussion of our actions going forward. We always start with safety because the backbone of good financial results is to operate incident and injury-free. 2015 was our best year overall in personal safety, process safety, and environmental performance. This chart shows the days away from work injury and oil spill rates for Chevron and major competitors. We continue to lead the industry on these measures.
Our refineries operated very well last year with high reliability and utilization. We were able to supply customers when others couldn't, enabling record Downstream and Chemicals earnings. Our Upstream base business also operated very well, continuing to keep base declines below 2%. Our financial priorities are clear and consistent. Number 1 is to maintain and grow the dividend as the pattern of earnings and cash flow permit. We've done this well. We've paid a dividend continuously since 1926, and we've grown our annual per-share payout now 28 years in a row and have a 10-year average annual growth rate of 9%. 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 pay and increase the dividends. This requires investments through price cycles that can be volatile.
We work to keep sufficient balance sheet capacity to withstand these cycles and feel it is prudent at this time to use some of this capacity to finish projects under construction and pay the dividend. We've defined a strong balance sheet as an AA long-term debt rating, and this remains our objective. Rating agencies have responded to the low price environment by downgrading a number of companies in the industry, including Chevron. S&P has downgraded Chevron to AA- stable. You'll see in a subsequent chart we currently have one of the strongest balance sheets in the industry and believe we can manage additional debt during this low price period without jeopardizing our long-term financial strength. At times, we generate cash surplus to what we feel we can profitably invest, sustain in dividend increases, or use to strengthen the balance sheet.
During these periods, we will return cash to shareholders by repurchasing shares. 2015 was a very tough year for the industry and our company. We had many significant accomplishments, but weak earnings and returns. We saw low oil and gas prices, which hurt Upstream revenue and required charges for investments no longer economic at low prices. Our Upstream business incurred losses. Downstream, driven by strong refinery utilization and reliability, had record results. When you add it all up, earnings were $4.6 billion. Cash flow from operations reflected low earnings, but we outperformed the price sensitivity we'd provided to you because of strong Downstream results and the work we've done to reduce costs across the enterprise. With low earnings and significant pre-productive capital, our ROCE was also low at 2.5%. Consistent with lower prices, Chevron and competitor Upstream earnings per barrel declined in 2015.
We remain in the band of our competitors, but no longer lead. This is because we are more oil-weighted in our revenue stream than our major competitors at greater than 75%. Downstream earnings per barrel were excellent and led the industry. This performance is the result of systematic work over many years to reshape the portfolio, reduce costs, run reliably, and steward capital carefully. What are we doing to get better going forward? We're focused on improving free cash flow and covering the dividend in 2017. This slide is an illustration of how we plan to do this at $52 Brent. $52 is the actual average price for Brent in 2015 and is in line with the current average sell side analyst price forecast for 2017. Let me walk you through the chart. We consumed a little over $12 billion in 2015 at $52.
Spending will decline significantly over the next two years as we complete projects under construction, high-grade new spending, and continue our efficiency improvements. Upstream cash flow from operations will increase as we bring on more high cash margin barrels and reduce operating expenses. You'll see both higher volume and higher per barrel margins without a price increase. Offsetting this, we've assumed some reduction in downstream earnings as industry margins were high in 2015. Also, the Future Growth and Wellhead Pressure Management Project will consume operating cash flow at our Tengizchevroil affiliate in Kazakhstan and require co-lending by partners. Similar to how previous project co-lending was reported, these loans to our TCO affiliate will be reported in the investing section of the cash flow statement.
Our previously stated range of $5 billion-$10 billion in asset sales proceeds combined for 2016 and 2017 may result in lower proceeds in 2017 alone than the $5.7 billion generated in 2015. Let's look at some of the components in this chart. We're aggressively reducing spend and driving cost out of our business. The chart on the left shows the guidance range for total capital and exploratory spending over the next three years. For 2016, we've indicated that our budget is $26.6 billion. With low prices persisting, we're managing spend to the lower end of the $25 billion-$28 billion range we previously communicated. As we complete projects under construction, spending will come down in future years. Our new guidance range for 2017 and 2018 is $17 billion-$22 billion. We're also reducing operating and administrative expenses.
OpEx was down over $2 billion in 2015, and we expect a similar reduction in 2016. Savings are coming from procurement actions to get better pricing, efficiency improvements from work process reviews, and payroll reductions as we size the organization for the amount of work we expect to have. Our company payroll was down 3,000 in 2015, and we expect another 4,000 reductions in 2016. As we implement organizational change, we're taking care to preserve capability that will be needed in future years. Production is going up and substantially. Production increases as we bring on and ramp up projects that have been under construction. At Gorgon, we reached an important milestone yesterday, making LNG from train 1, and we'll be shipping our first cargo next week. We have two more trains to come online this year and next.
We'll see first gas from Angola LNG restart within a few weeks. Mafumeira Sul is expected to begin in the second half of this year. Wheatstone, Sonam, Hebron, and Clair Ridge are planned to start up next year. Stampede and Big Foot are expected to come online in 2018. These are long-lived assets with benefits for years to come. As the spend from these projects winds down, we're very well positioned to ramp up spending in our shale and tight portfolio, where investments are economic at moderate prices. Our costs in the Delaware and Midland Basin are very competitive, and our learnings and improvements are being shared and realized in the Marcellus, the Duvernay in Canada, and Vaca Muerta in Argentina. Our production guidance range is for 0%-4% growth this year.
Uncertainties in the speed of project startup and ramp-up, timing of asset sales, price effects on production sharing contracts, capital spend levels, and the return of partition zone production create a range of possible production levels in this and any future year. We anticipate volume growth through the end of the decade at a broad range of prices that are consistent with the sell side analyst range. Per barrel cash margins are also growing, even at flat prices. This chart compares our 2015 cash margin with projected 2017 cash margin at different price levels. At flat prices, the margin improves $2 per barrel due to lower cost barrels coming online and our actions to reduce expenses. As prices rise, we obviously do even better. For example, at $70 per barrel, the after-tax cash margin grows by nearly $10 per barrel from 2015 levels.
Asset sales are a routine part of our business, and they generate needed cash. We've been successful over the past two years, capturing good value with $11.5 billion in proceeds. We plan to generate $5 billion-$10 billion more over the next two years. The criteria for divestments is straightforward. We'll sell assets that don't have a strategic fit, won't compete for capital, and are worth more to another party, and where we can receive fair value. We generally don't discuss specific assets targeted for sale until we have a transaction. However, there are some assets where we have data rooms open and there is knowledge in the public domain. You can see that list in the center of the chart. Our balance sheet is strong, and we intend to keep it that way.
This chart shows the relative debt ratio position and incremental debt capacity of major and independent oil and gas companies as of year-end 2015. On the vertical axis is the debt to debt plus equity ratio, and on the horizontal axis is incremental debt capacity available to reach a 30% debt ratio, which we choose only for purposes of illustration. Chevron has amongst the lowest debt ratios at 20%, and nearly $30 billion in incremental debt capacity available to reach 30%. Many independents and some majors have significantly more balance sheet stress and significantly less borrowing capacity. We consider this strength a competitive advantage in times like this. Now we'll use some of our debt capacity this year, but intend to manage activity carefully to maintain prudent financial strength and flexibility.
Over the last few charts, I've talked about restricting cash outflows and managing debt levels in the near term to deal with the current low price environment. We also need to improve earnings and ROCE. Chevron had higher relative returns in a higher price environment, as shown on the chart, where we beat our competitor average and the S&P 500 over the last five years. We slipped in 2015 for several reasons. We have some portfolio differences from our competitors. We have more upstream in our asset mix, we have more oil than gas in our upstream production mix, and we have a significant amount of pre-productive capital on the books as we approach many project startups. The pathway to better returns is through five changes listed on the right side of this chart.
First, pre-productive capital, or capital that is part of projects under construction or that produces no revenue, has been near 50% of capital employed for the last three years, and that ratio is coming down. We expect capital in this category to drop to around 25% by 2018. Second, we'll spend a much higher percentage of our capital on short cycle-based business, shale and tight, and brownfield incremental projects than in the recent past. In general, these are higher return projects because they take advantage of existing infrastructure and require less and shorter duration pre-productive capital. Third, we've had very good execution on short cycle activity, but inconsistent performance on longer cycle projects. We're taking action to improve this performance. Jay will talk more about this in describing work being done in advance of the Kazakhstan project. Fourth, we're improving our cost structure, taking down unit operating costs.
Fifth, we do expect some recovery in oil prices over time, which will benefit us. At $52 Brent in 2015, or the prices that we're seeing today, returns will be low. As shorter cycle, higher return investments replace approximately $20 billion in annual depreciation, and as prices rise, we expect ROCE to improve. This chart shows the shift in our capital program over the next few years. As Gorgon, Wheatstone, and other long cycle time projects are completed, the percentage of spend in shorter cycle projects will go from about 40% last year to about 65% in 2018. Thanks to our advantaged position in the Permian and development drilling options in locations like the San Joaquin Valley or Thailand, or deepwater development wells through existing hosts, we have a deep queue of activity that is economic at low to moderate prices.
The Tengiz project is a longer cycle time brownfield development in a location where we've had a history of success. We're weighted to the upstream and have significant oil price exposure in our upstream production mix, so we'll benefit from higher prices. The downturn has been deeper and lasted longer than we and many others expected. Using EIA data, this chart depicts worldwide liquid supply in dark blue and demand in light blue. The gray bars represent the shortfall from or surplus to inventory. $30 per barrel oil is finally bringing on the short-term supply response we all expected, as depicted by the gray bars. Capital is being withdrawn from the industry on long cycle activity as well. Hundreds of billions of dollars in projects has been deferred or canceled as host governments, national oil companies, and private companies grapple with revenue shortfalls.
With demand continuing to grow at around 1 million barrels per day per year, the market is expected to come into balance over the next year or so, and the industry will gradually have to work hard to meet growing demand without volume from the deferred or canceled projects. Prices will improve. When they do, we'll be well-positioned. In fact, I like our upstream and downstream portfolio positions. On the upstream side, we have world-class legacy-type oil assets in Kazakhstan and gas assets in Australia. We have a premier shale position in the Permian, with additional development opportunity in low-cost basins in the U.S., Canada, and Argentina. We have outstanding mature assets in Thailand and San Joaquin Valley. We have enviable deepwater holdings in the U.S. and West Africa, and we have complementary holdings and asset options elsewhere. We have a tightly integrated, profitable downstream and chemicals portfolio.
Our fuels refining and marketing business is in attractive markets. We've been gradually shifting our exposure to higher return lubricants and chemical segments. Our petrochemicals position is feedstock advantaged on the Gulf Coast and in the Middle East. We're happy with our portfolio. That concludes my overview of the portfolio and the actions that we're taking to improve cash flow and returns. I'll ask Jay to elaborate on our upstream activities. Jay?
Good morning. I'm now going to talk about how upstream aligns with and supports the direction that John just described. He shared a chart that forecasts production performance through the end of this decade. I'm going to show that our existing base business, coupled with an increasing focus on our Permian shale position and the startup of our major capital projects, drives our strong production performance. This is despite significant reductions in capital and operating expense. I'll start by reviewing 2015 performance and then talk about what we're doing to improve the cash and earnings margin in the upstream, both in the near and longer term. We're focused not only on increasing production, but on reducing our cost structure, building efficiency in our day-to-day operations, and improving our performance on major capital projects.
I'll provide updates on our current projects and key assets and close with an overview of the strong queue of future development options in our portfolio. In 2015, we delivered strong operational performance, growing annual production by 2%. Increases in production came from ramp-ups on major capital projects, including Jack/St. Malo and Tubular Bells in the deepwater Gulf of Mexico and the Bibiyana expansion in Bangladesh. We also saw contribution from startups at Lianzi in the Angola-Republic of Congo Joint Development Area, Moho Nord in the Republic of Congo, and the next phase of the Agbami development in Nigeria. Shale and tight volumes grew approximately 30%, driven primarily by our Permian assets. Lower oil prices also resulted in increased production volumes due to entitlement effects.
Offsetting these increases were the shut-in of the Partitioned Zone, the impact of asset sales, and a base decline of less than 2%. One of the drivers of our production growth is Jack/St. Malo. The project was delivered on time and on budget in late 2014. This is our first lower tertiary project in the deepwater Gulf of Mexico, and performance to date has been very encouraging for future developments in this play. Production continues to ramp up as wells are brought online. Total production is currently around 75,000 barrels a day from six wells, and three additional wells are expected online by mid-year. Stage 1 performance has been strong in all areas. Well performance has met expectations, and operational reliability has been very high at 96%. In addition, our development drilling performance on the project is in the top quartile for the Gulf of Mexico.
Given the positive results from stage 1, we're now progressing with stage 2, which includes four additional wells that will come online starting next year. The development wells associated with Jack/St. Malo are good examples of the types of investments we're funding in this reduced price environment. In 2015, we achieved a reserve replacement ratio of 107%, putting our five-year ratio at 113%. Last year, we saw significant increases from our shale and tight assets based upon strong well performance and additional geologic data. The majority of these came from our Permian assets. Additional volumes were booked at Wheatstone, driven by well results and updated seismic interpretation. Strong production performance drove positive reserve adds in our base business, including revisions at Tengiz, Thailand, Nigeria, and the Gulf of Mexico. Commodity price impact provided a net benefit to entitlement volumes for production sharing and variable royalty contracts.
We also had a strong year with resource additions. Our exploration program delivered excellent results in 2015, adding 1.8 billion barrels of resource with a success rate of 62% and a finding cost of $1.22 a barrel. Key contributors to resource came from our shale and tight assets in the Permian and Appalachia, along with successful wells in West Africa, Northwest Australia, and the deepwater Gulf of Mexico. Our long-term exploration program has outperformed peers, as you can see from the Wood Mackenzie analysis. The chart on the right shows discovery costs per barrel over a 10-year period. The same study also shows us leading competitors in full cycle exploration returns over the same period. Just as importantly, our resource base provides us the flexibility to scale back our exploration spend in the near term.
The next component of our strategy is to reduce our cost structure, which includes both lowering cost of goods and services and improving our efficiency. We reduced our unit cash production cost by 23% in 2015, and we continue to lower our costs. We're systematically working through each of our business units to ensure we have an efficient organizational structure and an appropriately sized workforce. Our actions are aligned with planned activity levels, and by the end of this year, we expect a 20%-25% headcount reduction in total upstream workforce relative to 2014. Almost half of the planned reductions have already occurred. In the supply chain, we continue to leverage our purchasing power. A good example is in the oilfield tubulars category, where we've achieved a 30% reduction in unit cost by consolidating suppliers and increasing standardization.
While reducing the cost of goods and services is important, we're also focused on identifying and capturing opportunities to more efficiently run our business. Such improvements are within our control and stay with us despite external market forces. I'll highlight a few examples. In the deepwater Gulf of Mexico, we're using intelligent well completions to minimize cost and improve reservoir recovery. These remotely controlled completions allow us to selectively produce different downhole zones without rig-based workovers. On a recent well at Tahiti Field, an intelligent well completion allowed us to produce two stacked reservoirs without a costly rig intervention. This improved the expected well recovery by an estimated 50%. We've also continued to improve our deepwater drilling performance, as you can see on the chart, and last year increased our drilling rate by 30% relative to the year before.
Collectively, these and other efficiency improvements translate to reductions in development cost and improved economics for our deepwater opportunities. At Tengiz in Kazakhstan, implementation of a new approach to well stimulation has reduced cost by 70%. Cost-effective debottlenecking has increased total production capacity by 16,000 barrels of oil a day. In addition, access to the expanded Caspian pipeline and optimization of the rail fleet has reduced transportation costs by 25% since 2013. In California, we're using artificial intelligence technology to leverage vast amounts of historical well performance data to identify new well locations and stimulation candidates. By applying these techniques, we've seen production increases of about 30% over traditional methods. In Houston, a small team of technical experts in our machinery and power support center are using predictive models to remotely monitor and analyze the performance of over 2,000 pieces of large rotating equipment located across six continents.
By detecting failures before they happen, we can take preemptive action that avoids unplanned shutdowns and significantly lowers repair costs. These are just a few examples of how we're focused on delivering bottom-line impact and getting the most out of our investments. One of our greatest opportunities to improve is in project execution. Engineering issues are one of the largest contributors to project delays and increased cost. As a result, we're moving to complete more of the design basis in-house and targeting a higher level of engineering definition for our projects prior to making an investment decision. We're also conducting comprehensive assurance reviews to verify designs are robust, constructable, and will deliver the expected operational performance. Our contracting strategies are being adjusted to better match scopes of work with contractor capabilities, relying on Chevron project teams to manage the interfaces.
Before beginning fabrication or construction, we're using execution readiness reviews to ensure that we have comprehensive plans in place that are supported by critical infrastructure and resources. Quality management has also been a challenge. Virtually every one of our projects has experienced issues with poor quality of equipment, materials, and preassembled units. We're going deeper into our supply chains to detect and correct material problems early on, and we're assigning responsibility for specific items of equipment to Chevron project engineers. We believe that these actions will address the majority of the issues we've encountered with our major capital projects and ensure that our future investments deliver the value that's expected. Now I'd like to share updates on a number of our major capital projects. As John said, at Gorgon, the plant's online, and we're producing LNG.
We expect to ship the first cargo next week, and we'll be ramping up production over the coming months. On Trains 2 and 3, all modules are on site and construction is progressing. Train 1 learnings have been extensively reviewed and are being applied to improve construction and commissioning for Trains 2 and 3. We're planning for subsequent trains to be ready for startup at roughly six-month intervals. At Wheatstone, all modules for Train 1 and common facilities are on their foundations, and module deliveries for Train 2 are meeting schedule milestones. The key focus at site right now is the progressing of piping and cabling work. The LNG loading jetty is complete, as you can see in the photo, and the hydro testing program continues and testing of the first LNG tank has been successfully completed.
On the upstream portion of the project, eight of nine wells have been drilled and completed, platform commissioning is ongoing, and final acceptance testing for the trunk line and all subsea flow lines has commenced. Looking ahead, the drilling program is expected to finish around mid-year, at which time all nine wells will be ready for production. Completion of platform commissioning is also anticipated later this year. Our outlook for first LNG is mid-2017. While Gorgon and Wheatstone are the primary drivers for our volume growth, a number of other major capital projects are expected to start up this year, along with ramp-ups at Lianzi and Moho Nord, which came online in the fourth quarter of 2015. First gas was achieved at the Chuandongbei project in China in January, and Train 1 production is running at design capacity.
Startup of the second and third trains is expected in the second quarter. At Angola LNG, all repairs and design improvements are complete, and the plant is in the final stages of commissioning. Following plant restart, we expect to ship the first LNG cargo in the second quarter. Also in Angola, all four platforms are installed at Mafumeira Sul, and hookup and commissioning work is ongoing. The drilling program continues, and first production is expected in the second half of this year. Alder in the North Sea and Bangka in Indonesia are also expected to start production this year. A number of other capital projects are currently in execution that are scheduled to come online and contribute to production volumes over the next few years. On the Big Foot project, the design of the tension leg platform and the mooring system has been validated.
The collapse of the tendons was due to failure of the connections between the temporary buoyancy modules and the tendons. The initial site recovery work is complete. The tension leg platform has been moved to a safe location, and inspection work has confirmed that all wells and the subsea template can be reused, along with most of the components of the recovered tendons. Fabrication of new tendons and required temporary installation equipment is expected to commence in the second quarter, and the current outlook for first production is in the second half of 2018. Other projects currently in execution include Sonam in Nigeria, Hebron off the east coast of Canada, Clair Ridge in the North Sea, and Stampede in the deepwater Gulf of Mexico. These projects are all expected to begin production in the 2017 to 2018 timeframe.
As John described earlier, you'll see a shift in our capital allocation towards shorter cycle base and shale and tight assets as we bring more of our major capital projects to completion. First among these opportunities is the Permian, where we have a large royalty advantage acreage position, and our view of the resource potential continues to increase. Our transition to horizontal factory mode is now fully operational, utilizing four well pads and increasing lateral lengths. In 2016, nine horizontal development programs are planned, with around seven operated and nine non-operated rigs. We expect to drill around 175 wells this year. Fully integrated long-term development plans are in place that incorporate high grading of the opportunity queue based on appraisal and well performance data, along with associated infrastructure requirements. The chart shows our outlook for growth in the Permian through 2020, which reflects a range of potential activity levels.
The low end of our range is similar to the 2020 forecast we shared with you at last year's meeting, with around 100,000 barrels a day of potential upside. Our objective is to be fully competitive with other operators in terms of unit development and operating costs. Then use our advantaged royalty position to give us leading financial performance. We've made significant progress in our execution performance as development programs have moved into factory mode and delivered efficiency improvements. We continue to drive unit development costs lower, both through the reduction of well costs and through higher recoveries. Over the last year, we've reduced horizontal well costs by around 40%. The upper chart shows a 50% improvement in drilling days per well in our Bradford Ranch horizontal program in the Midland Basin.
Beyond this example, we're seeing similar improvement across the board, with year-on-year drilling footage per day increased 45% for our horizontal wells. We believe our current drilling performance is competitive in both the Midland and the Delaware Basins. Completion performance is also competitive, with the number of frac stages per day more than doubled year-on-year. Well recoveries have increased by around 30% for our Bradford Ranch program through optimization of completion designs. Cost and ultimate recovery for our most recent wells in the Salado Draw and Bradford Ranch programs are shown on the slide. When you combine our royalty advantage with the good rocks and competitive execution performance, it translates to compelling economics and a deep queue of opportunity. The lower chart shows our current view of the price required to achieve break-even economics for our Permian wells.
We estimate that there's currently around 1,300 operated well locations that offer a 10% rate of return at $40 WTI or less. Importantly, we've only fully assessed about 30% of our operated acreage, and we expect that the ultimate well queue will be even deeper as our assessment efforts continue. We also hold valuable positions in other shale and tight plays and are leveraging our learnings from the Permian to maximize value across all of our shale and tight positions. The appraisal program continues in the Duvernay play in Canada, where our drilling performance leads competitors. Since the program commenced in late 2014, unit development costs have been reduced by 35%. In Argentina, the Vaca Muerta development has moved into horizontal factory mode, where well costs have been reduced by 20% since late 2014.
Initial 30-day peak production rates are encouraging, with some recent wells achieving rates of around 800 barrels of oil per day. The combination of lower cost and increased well recoveries has reduced unit development costs by around 30%. Given the current gas prices in Appalachia, a measured pace is being taken in developing our Marcellus and Utica acreage. Good progress has been made in lowering development costs, which have been reduced by around 40% since early 2014. This is a large resource, and we're well-positioned for profitable growth as prices recover. In addition to our shale and tight portfolio, we have a strong inventory of attractive base investment opportunities. While these cover different asset classes and geographies, they share characteristics that are common. They leverage existing infrastructure, and they typically offer ratable investment and production.
Relative to greenfield projects, investment in base assets usually have a lower subsurface and execution risk, as well as shorter cycle times. Our well factory operations are legacy assets where there's a large queue of similar opportunities that lend themselves to efficient factory mode development. These include the Gulf of Thailand, the San Joaquin Valley in California, and legacy assets in Indonesia. Continuous improvement and a drive to higher efficiency are central to our well factories, and we're applying many best practices from these locations to our shale and tight operations. An attractive queue of brownfield opportunities also exists in the deepwater. As an example, the Ebomi FPSO came online in 2008, but we continue to drill additional wells to maintain field plateau production.
In the Deepwater Gulf of Mexico, around 80% of our capital investment over the next two years is directed to brownfield developments, including programs at Tahiti and Jack/St. Malo. For individual deepwater development wells, typical break-even economics are between $20 and $40 Brent. Outside of Deepwater, our conventional infill drilling and workover programs continue to help us offset decline across our base business. Across the upstream, we utilize a systematic approach to identify economically attractive opportunities to debottleneck facilities, improve reliability, and increase effective capacity. A major brownfield opportunity that we've talked about many times is the Future Growth and Wellhead Pressure Management Project in Tengiz. WPMP is the portion of the project that provides additional wells and pressure boosting facilities to maintain production levels in the existing plants as reservoir pressures decline. This base portion accounts for around 60% of the capital investment for the total project.
FGP adds additional production and injection trains to increase total production by 250,000 to 300,000 barrels of oil a day. It'll also increase the ultimate recovery from the reservoir. FGP builds on the sour gas injection technology already proven in existing operations at Tengiz. The project is being paced so that the project team can reduce cost and capture savings available in the current environment. We continue to work with the Kazakh government and our partners to accomplish these objectives and expect to take a final investment decision around mid-year, following alignment on cost and project financing. Earlier, I discussed our commitment to improve project performance across the company. The FGP-WPMP project leverages proven technology and previous Tengiz project experience. Additionally, we're applying learnings from previous major capital projects to deliver strong execution performance.
Engineering is currently greater than 40% complete, well ahead of where other major projects have been at FID. Having a more advanced engineering design provides a better understanding of the quality of materials, equipment, and labor required to execute the project. It also mitigates the adverse impact of engineering delays and any late design changes. We've experienced design errors on a number of projects, particularly with the design of flare and vent systems and the sizing of vessels. On FGP-WPMP, we conducted formal design assurance reviews and verified the entire process design and confirmed the sizing and specification of all major equipment. In terms of the contracting strategy, we selected a module fabricator early, and they have a team working with us to ensure we're designing the modules in a way that makes them easy to build.
We've also packaged the site work into six major contracts to better match contractor capabilities and integrated our team with the lead contractor. This will clarify leadership and accountability and reduce layers of management and cost. When it comes to execution readiness, it's important that designs are complete and project infrastructure is in place before it's needed. We've begun pre-investing in the project camps, beds, roads, and other infrastructure to ensure we're ready when execution begins. I'll give you an example of the advantage this can bring. We've learned the hard way that on a modularized project, completing all underground work and having foundations ready to accept modules on arrival is important. For this project, all of the underground elements have been fully designed and incorporated into a 3D model. The last point I'll mention is around improving quality management.
We've implemented a robust Chevron-led quality management plan on the project, and we're using some of our best talent to provide early detection and resolution of quality issues. For example, each equipment package is assigned to a project engineer that owns all aspects of quality control and assurance from the design stage through fabrication, startup, and handover to operations. We're confident that these actions will improve our ability to deliver this project predictably and reliably. Up to this point, I've focused my remarks largely on the near-term performance, investments, and actions to help us weather the current price environment. Beyond the end of the decade, we maintain a strong, diverse resource base of future opportunities, some of which are highlighted on this map. The map shows a selection of future projects that are pre-sanctioned and under evaluation.
Major capital projects will still be required to sustain production and renew the base. Going forward, we plan to take a more ratable and selective approach to these investments, funding only those with the most attractive economics. These projects offer diversity in location and asset class, including conventional, LNG, deep water, and heavy oil, each of which are expected to present profitable opportunities in the future. Conventional exploration and appraisal wells planned over the next few years are also shown. We continue to pursue high-impact opportunities, which we're prioritizing within our reduced exploration spend. With this deep queue of strong, diverse opportunities, we remain confident and optimistic about our future beyond 2020. Before turning you back over to John, I'll just reiterate that we're focusing on improving project execution and lowering our costs.
The startup of our major capital projects and the growth of our shale and tight assets drive the production profile that John showed you earlier. As major capital projects are completed, we're reducing our capital spend and transitioning to higher return, shorter cycle investments. Thank you.
Thank you, Jay. That brings us back to the chart I showed at the outset with key messages. Our objective is to maintain and grow the dividend. We're driving to balance the cash equation over the next 2 years by reducing spending and bringing online and ramping up new projects. In the interim, we'll use some of our balance sheet capacity but maintain balance sheet strength and flexibility. We'll grow volume and margins over the next few years and are well-positioned to take advantage of the many shorter cycle asset development options in our portfolio. We have a well-balanced set of assets, both upstream and downstream, and long-term options as well for when costs and price come into better balance. That concludes our prepared presentations. Pat, Pierre, and Mike, if you'll please join us on the stage, we'll get to your questions.
While they're coming up here, I'll just remind you're used to seeing Mike in the downstream role. Mike has moved over to gas and midstream, and he also has strategy and development. Pierre has moved over to the downstream. Of course, Jay has already been here, and Pat you know very well as our CFO. Pat and I are in the same roles. Others have changed since a year ago. Let's start right here in front. Doug.
Thanks, John. Doug Leggate from Bank of America. I wanted to hit 2 questions, if I may. First of all, on slide 14, you talk about the CapEx shifting to shorter cycle.
Yeah.
If I look at the percentages versus the absolute reduction in spending-
it looks that it's about the same, around $13 billion. Can you just clarify that's the right interpretation? The follow-on is, what is the implication on the underlying decline rate of that shift in capital? Thanks.
Yeah, it's a good observation. Since the absolute level of spend is coming down, when you apply the percentages to it, spend is coming down, and there are implications. We've been high-grading the work that we've been doing in the base business. I'm going to let Jay talk a little bit about what's happening to decline rates, because it does impact decline rates. Jay?
We are going to see somewhat higher decline rates. Right now, we've been able to maintain our base, fully invested at less than 2%, including our shale. As we move forward, we'd expect to see that probably increase to more like less than 4%, not including the shale. When we add the shale and tight back in, we should be in that 1%-2% kind of a range. We'll be able to maintain roughly the invested decline rates that we see today in our base. As projects like Gorgon and Wheatstone come into the base, right now we treat those as major capital projects, but as they start production, they add decades-long stable production to us and actually help us with that equation.
Shale and tight growth, like in the Permian, tends to increase your decline rates because obviously the nature of those types of wells have individually high decline. The balance is we should stay pretty stable to where we are, but we will see the uninvested decline rate increase.
Yeah. We have made some changes. Things like the San Joaquin Valley. We've got, what, one or two rigs working there now? We used to have eight or more, and it's just been high-grading what's in our portfolio. That activity can return in due course, there is some scalability in the base business. When you curtail capital, it does impact decline rates. Yes.
John, during the past decade or so, the super majors have grown, but they've kind of struggled to grow, and it often came at the expense of returns and valuation. While you guys are probably going to have the best growth in the peer group over the next couple of years, and I think you indicated greater emphasis on returns today with your pathway to higher returns slide. My question is, what do you think that the industry was surprised by during the past decade? Do you think it was changes to industry structure? Was it cyclical factors, or do you think it's just temporary items such as the pre-productive capital element that you mentioned earlier? Maybe more importantly, how do these items, I think, affect your ability to defend your competitive advantages in the future, if you think that there's been any change here?
Also, what is the optimal balance between growth and returns in the future? Has your thinking changed there given these outcomes?
Well, sure. That covers a lot of territory, and I guess I'd offer a couple comments. One, if you go back to the early part of this decade, we knew we were heading into a period where we were going to have more pre-productive capital. Book returns, book ROCE is impacted when you have pre-productive capital. The projects themselves, we in the industry felt would be profitable. We've been returns focused. The actual outcomes can vary, certainly in the short term because of pre-productive capital and ultimately based on the price environment that we see. We have seen a lower price environment. A lot of the projects that the industry started since the beginning of the decade were premised on higher prices. Book returns are low. If you look at earnings across the sector, that's pretty apparent, particularly in the upstream.
Even in the shale and tight, a lot of the shale and tight companies, the P&L hasn't been great during this period. I think there is a lot of change taking place in the business right now. We're all working to get more efficient, to adapt to a lower price environment, and to bring our costs down. Jay talked about some of the things we're doing to improve efficiency. We think those types of benefits will be sustainable. In terms of some of the surprises that we've seen, we did see some surprises. I would say the biggest surprise for us was in the supply chain and some of the performance of our contractors and vendors. Name brand companies, either because of the stress, complexity, whatever it might be, haven't performed as well as we would like.
It's not just for Chevron, it's been for the entire sector. That's why Jay talked about on a project like Kazakhstan, we're doing more work ourself. We're making sure that contractors, when you have multiple contractors, that the interfaces are better managed. We're having to do multiple levels of QA, QC work because even though we had checks and balances in place, it wasn't as effective as we'd like it to be. There were lots of learnings during this period. Maybe the last thing I'll say is we emphasized a lot of short cycle activity, and I think you're going to hear that around the industry because not very many long-term projects are economic at $30 or $40 a barrel. Long term, it is going to take new assets from a number of different asset classes to meet demand expectations.
Right now, oil and gas are in relative surplus. The world is consuming 96 million barrels of liquids per day. That's growing about a million barrels per day, and shale and tight represents five. As natural decline takes over, we're going to need new assets. We've just got to make sure that we can deliver those new assets and deliver, whether it's a deep water development or a new project at Tengiz or others that the industry is undertaking, better than we have done over the course of this decade. Maybe that's a long answer. Paul.
Thank you, John. Paul Cheng, Barclays. If I may, two questions. The first one is probably for Jay. Jay, you are doing all the right things trying to improve the project execution, there's a price to be paid, means that you need to have more manpower or the activity that ticking on your own watch. From that standpoint, what is the organizational capability in a going forward basis? How much investment you can really take on without losing your improved project execution? What is a reasonable growth rate in the longer-term basis that we can assume from you? Not even forget about the balance sheet issue or the finance, just on your organizational capability. The second question is for John. John, wondering that if the bid ask price in the market remain, because that means you have the balance sheet.
I think you indicate that you may be up to $30 billion of the borrowing capability, and it's a cyclical business, and at some point that the price will rebound. Is it a good time if there's a good bid-ask relationship there for you to make acquisition instead of asset sales?
Okay. Several questions in there. Jay, maybe you can talk both the people side on projects and what we're doing to make sure we keep capability because we have talked about reducing our workforce. I'll come back on the acquisition question.
I'll take this on in a couple ways. One, even though the amount of content that we're going to be doing is a little bit bigger, we already have those capabilities built today, so it's not like we have to build them going forward. Our overall activity level is coming down dramatically, as you saw on the slides. It's more selective application of these two projects, and I think we'll be well within our capabilities. As we move our organizational structures to be more efficient, we are seeing reductions in our manpower. One of the key things we're looking at is where do we need the capabilities going forward. We're looking at the demographics of our workforce. We're looking at the activity levels that we anticipate, the project loads that we anticipate.
In some areas, we've actually increased our manpower while the overall manpower is coming down to make sure we have those capabilities covered. In terms of what we have going forward, we have a great installed resource base. As we have core projects like Tengiz, Wheatstone, and Gorgon, these provide stable platform for brownfield developments for a long time to come. They do have less execution risk, and it takes fewer people than a greenfield project like what we've just been through. I just don't see us taking on multiple mega projects simultaneously like we've just been through. We seized an opportunity, and I think it was the right move to do it, but it was difficult to get through. Going forward, I'd see these projects more ratable and a more ratable growth profile as a result.
Yeah. Just to follow on a little bit. The growth profile that we showed you with those fuzzy bars on that one production chart was really meant to tell you that just with what we have under construction and with the level of activity that we're showing you, including the level of capital spend, the range of the capital spend, we see volumetric growth out through the end of the decade. Beyond that, we've also got a good queue. We think we'll have the capability to grow for a long time to come. Ultimately, you will need some of those major capital projects, but with the depth in our base business portfolio, with the depth in our shale portfolio, and with the projects we've already got lined up, we see growth.
We're in a fairly unique position in the industry right now where we're cutting spend pretty dramatically, but we're going to see higher volume, which enables us to get cash balanced. We replaced reserves this year. On the general subject of acquisitions, I've told you all many times, we're in the business of acquisitions. We acquire leases, we acquire discovered resource, and we acquire companies at times. We don't have to do an acquisition right now. You can see we've got a nice profile going forward. We've got a lot of work ahead of us, and our focus is on getting the most out of what we have. We are cognizant of what's out there, and if the right opportunity were there, we certainly would take advantage of it. It isn't my primary focus. Yes, how about Evan?
Hi, Evan Calio of Morgan Stanley. Maybe John, I can follow up on the fuzzy bars that you just talked about.
Okay.
Look, I know you removed longer term production guidance.
Yeah
Many of the folks in the room have to try to come up with an estimate of what that would be.
Yeah.
Can you dimension any ranges around 2017?
Yeah.
Is it assumed that your guidance from 3Q of last year of 2.9 to 3 is no longer valid? Has management compensation or guidance changed in any kind of way, shape, or form around volumes?
No, all the guidance we've given you still holds. The guidance we gave you third quarter last year was 2.9 to 3.0 in 2017, excluding any asset sales. The reason that we've shown some range in there is there are four or five things that introduce possible variation. We've got six trains of LNG coming on over the next couple of years, including Angola LNG. A couple of months one way or the other makes a difference. We've got the Partitioned Zone . We're scaling spend. If we're still in a $30 world, we're going to have lower spend. You've got cost barrel impacts. You can have the difference between $70 and $30 is 100,000 barrels a day just in cost barrel.
Makes a very big difference. $70 and $30 is 100,000 barrels a day just in cost barrel.
Makes a very big difference, we're just trying to show you the reality of the range that is there. What's true, though, is if you anchored on 2020, and maybe that's the easiest way to do it. If you anchor on 2020 that's out there, Gorgon, Wheatstone, all these projects will be online and fully ramped up. Gorgon and Wheatstone alone are close to 400,000 barrels a day. The 10 projects that Jay showed you on those two charts is over 200,000 barrels a day in 2020. We have other capital projects from the infill drilling and work we're doing in the deep water, plus 300,000 barrels a day of potential growth in the shale.
What I'm telling you is because we've spent much of the capital and because we have low-cost options from the base drilling activity and from the shales, we have potential to grow through the end of the decade. Now, we also have asset sales, and we've got some assets that are earmarked for sale. It will depend on the timing of those sales. You've seen some trade press around packages in the Gulf of Mexico. We've got to execute those, and we've got some other things that we're looking at. We've signaled a few on that chart that are in the downstream, we're also looking carefully at selective assets in the upstream. Executing those will depend upon getting fair value. That's why we showed some range on those charts.
Nothing we show in those charts is meant to be inconsistent with the guidance we've given you previously. Final comment, we've never been rewarded compensation wise based on volume. Volume has always been an outcome. It was an outcome of the major capital projects. In fact, we've had a number of changes over that time as we've responded to industry conditions. If I go back to 2010, the gas market in the U.S. was much different, and we in the industry had big plans to grow. Well, nobody's drilling for natural gas, and our expectations for the gas market right now are such that activity is likely to be low for a few years. We are responsive to conditions. We are returns oriented.
The best thing that I can tell you to do in terms of compensation is to take a look at our CD&A in the proxy this year or last year. 85% of the compensation for the people that are sitting up here is a function of TSR, either directly through options or through relative TSR ranking. We're very focused on outcomes that will generate value that you will realize and that we will realize. Yes, please. Right here.
Great.
Hey, good morning. Phil Gresh, JP Morgan. Two questions. One is on the Permian, obviously, you've shown a lot of growth potential there. Wondering if you could give us some color on the capital side, what you spent in 2015, what would be required in the next couple of years. Maybe you can't give it out to 2020, but over the next couple of years, how you're thinking about required spend to achieve that growth. Then on the LNG side, wondering if you could just elaborate on the operating cost structure, the DD&A cost there, and just to give us a better idea of how much of the cash flow you're seeing is expected over the next couple of years, and how much net income specifically.
You want to take the shale one?
Sure. In the Permian, we've modeled out a couple of different scenarios, and that's why you see the range that we gave you on the slide. The bottom end of that range is very consistent with what we showed you last year, and that's what's in our base plan that we've presented in terms of the capital and everything else. As we look forward, we've modeled increases that are pretty modest, actually. We can do it with ultimately like a doubling of the number of rigs from where we are today. It's not a huge insurmountable increase to get to that upper curve, and there's potential even beyond that. What we do want to do is maintain the efficiency of our development in the Permian. We look at three different components.
We're looking at development cost unit, development cost, how much does it cost you to develop that barrel? How much does it cost you to produce it through operating cost? What's your realization? That's your gas oil mix and how you get it to market. We want to make sure we keep all those in balance so that we ensure the highest return from the Permian. Capital roughly anywhere from where we are now up to double on that proportion of it all comfortably within the capital profiles that we gave you.
I think it's only about $3 billion in the Permian. It's not like it's a huge portion of the capital program. Just on Gorgon and profitability, as Gorgon came up yesterday, which of course is a big milestone for us, people are turning to the question that you asked on profitability. One of the things that's not always remembered out there is that it's going to be a 40-year project, and it's a huge resource base, and if you look at depreciation rates for Gorgon, it'll be $20-$25 a barrel for both upstream and downstream combined. Operating costs are in the single-digit areas. At the kind of prices we're seeing today with the oil link contracts that predominate our sales base, it's going to not only be profitable, but obviously it's going to generate prolific cash flows for a long time.
Wheatstone is in the same general range. We think these will be good projects for a long time to come. That's where we're headed. Phil.
Thank you, John. I was going to ask about what I thought were the skyscrapers in the clouds, but they've become the fuzzy bars. Appreciate the clarity that you gave on those. Just to follow up to the last comment you made, can you talk a little bit more about the pricing of Gorgon? Because I think what you just said was that at today's prices, it will be very profitable. Is that because of the S-curve, or is it just a fact of the netback at these prices being good? My bigger question is, the industry has had an issue with procyclicality, with everyone doing the same thing all at the same time. Everyone's now saying, "We're going to cut our CapEx, cut our big projects, and we're going to flex in U.S. unconventional.
By the way, all these costs will be maintained at lower levels.
Yeah.
It feels like that can't happen. Can you just address what you're doing to be not pro-cyclical, what you're doing unlike others, and how you differentiate in that regard? Thank you.
Sure. Mike, why don't you talk a little bit about what we can say on our LNG contracts and pricing?
On the LNG contracts, they are long-term oil-indexed contracts, and we really don't have S-curves that are in place. We're going to see prices that reflect the contracting environment of a few years ago, which is different than the contracting environment that we have today. We are relatively well covered to cover the ramp-up period of time. As we move through that, and as we establish reliable operation, you look at our Northwest Shelf plant where we're at 95% coverage or so on long-term contracts. We'll move from the 80-ish range that we're in now gradually up to a higher level as we get the six trains on and we establish reliable operations there. Good, strong oil indexation, long-term contracts with good buyers who understand these markets and are not prone to chase short-term changes, but really looking for long-term reliability of supply.
Would the cash generate price?
Yes.
A couple of things. I'll just add on your comment of cyclicality in the business. When we would start up all these big queue of projects, we knew there was some downside risk to price. In fact, a few years ago at this meeting, I commented on that when we had more cash than debt on our balance sheet. We didn't expect prices to drop to where they are today. We'd prefer to not have a big herd effect, if you will, in terms of projects. The reality is the LNG market is different than we expected, so I don't expect to see too many projects moving in the very near term, just based on economics of new supply alone. As we're completing projects under construction, we need to live, as they say, within our means during this period.
We are taking some, what you might call counter-cyclical moves. I think you'd say the Tengiz project is one that's not premised on $40 oil. It's going to require a higher price, but we think that's the right thing to do. By the time that comes online, we think it will prove to be a good investment. We're also preserving a fair number of options. If you look at what we're doing in the Gulf of Mexico, for example, we've talked about our Anchor discovery. We've talked about Tigris. We've got three or so exploration wells that we'll be drilling this year. Those are not premised on $40 full-cycle economics either. Costs are coming down. Full-cycle costs are coming down. We are making some of those counter-cyclical moves. We are having to make some choices. We do need to bring costs down.
It's not as though we're abandoning some of these other asset classes. We will need them. Just want to be clear, we've said that we think with Brent at $40, I haven't seen where it is this morning, with Brent at $40 a barrel, when you apply the contracts that we have in place, even with a percentage of spot sale cargoes, we think we'll be profitable even at today's prices, given those indexation contracts that Mike was referring to. Yes, we'll go back here. Sorry, I can't see that well.
Thanks. Ryan Todd at Deutsche Bank. Maybe if I could ask you a couple of things around sensitivities around use of cash. As you look forward, you have the bars that you've given out over the next couple of years, which we appreciate. If oil prices were to stay materially lower into 2017 and 2018, what additional flexibility do you have on the downside of that capital budget? As oil prices recover, particularly as they get back above the $52 a barrel breakeven, how do you prioritize the use of cash in terms of share buyback versus capital ramp-up versus other uses?
I'll take the first part of it, I'll let Pat take the second part. We've given you a range of capital spend of $17 billion-$22 billion. That's a fairly good range over the near term. It accounts for the, in general, the range of prices that we expect to see. If, for example, $30 oil stayed for two more years, we would continue to drive costs and expenses down in the business. The industry's had difficulty predicting where the cost of goods and services will go, activity will decline in time. We have rigs, for example, that are coming off contract, deepwater rigs that are coming off contract over the next two years. Costs will come down, or we won't renew those contracts if we're still two years from now sitting at $30 oil.
There is more flexibility downward, we've tried to give you a reasonable range. We do see supply and demand coming back into balance. We've seen estimates that the U.S. tight oil production or U.S. production overall is declining 100,000 barrels a day per month. At these kind of prices, that is going to accelerate. We do think the market will come into balance. We do think prices will get better, we can paint scenarios where, depending upon actions taken by OPEC, the Saudis in particular, and the condition of the world economy, you could get different outcomes. We'll be prepared for those. Assuming we get something better in prices, I'll let Pat talk about the balance between the priorities that we've talked about on the charts.
I think we've been pretty consistent, really. The priority on cash use is, number one, the dividend, sustaining it and growing it over time as we can. Secondly, reinvesting in the business. I think all of the messages that you've heard here today are about being more selective on capital allocation going forward. We're moving towards higher return, a more restricted capital environment, we still have tremendous opportunities for reinvestment organically. That'll be our second priority. Third is restoration of the balance sheet. We're already in a good, strong place as it is, if you assume that there's additional debt that may be consumed this year, there will be a point in time when some of the cash that we generate needs to be returned to the balance sheet. That would be our priority.
I don't see us in the near term here, returning to a share repurchase program.
Yeah, if you look at one of the things I know is on your mind is long-term debt. Maybe you can talk about what we're targeting in terms of debt ratio.
Sure. Right, I'll just go back a little bit and talk about the cycles. When this cycle started, we had a very under-leveraged balance sheet, I think, by most people's account. We had a debt ratio that was 10% or less. We went through the period of the higher prices in our investment, particularly in our significant LNG projects, prices have come down. We were using our balance sheet through this period. 10% is obviously under-leveraged. I think something that would take us out of a strong credit, a strong double A, would be over-leveraged. Somewhere in between through the cycle, I think heading us through the cycle and somewhere in the low 20% debt ratio seems to be appropriate.
We think long-term, a double A rating is important for the size and the scale and the scope of the projects we take on, as well as just the tremendous volatility that we've all seen in commodity prices.
Okay. Ed?
Yeah. Edward Westlake. I guess a follow on the dividends. You've sort of laid out how you can break even at close-ish to $50 oil, and then your production grows a little bit beyond 2017. Assuming that there was, say, no recession, which put more debt on the balance sheet and you had to sort of pay that down before you start to think about dividend increases, should we just assume a ratable increase with the production level? That's my first question. I have a separate follow on.
Well, honestly, we make that decision every quarter based on what we see going forward in the markets. If you look at the pattern of dividends versus the pattern of earnings and cash flow in the business, there's some difference. Just as when prices were very high, we increased the dividend to try to intersect what we felt was a long-term equilibrium, if you will, payout. We'll do the same thing going forward. Obviously, we've increased the dividend at a very slow rate when prices are down. We'll really try to gauge the dividend increases based on what we see in the pattern of earnings and cash flow going forward. That's the best way I can describe it. It's not per se linked to production, because if prices are very low, you don't have the revenue base for dividends.
We think that with the kinds of prices we expect to see and with the production volume we expect to see, we'll see cash flows that'll grow and put us in a position to consider dividend increases.
The follow on is just really around Gorgon. It started up overnight. Obviously, commissioning is going to be, as you've highlighted in the past, up and down. Anything in the initial startup that would give you any cause for concern about how Train 1 will perform?
Go ahead, Jay.
I've actually been really pleased with the way the commissioning has gone on Train 1. Following some of the learnings from Angola LNG, we went back through with an external team, external being not part of the project team, and checked Chuandongbei, checked Gorgon, checked Wheatstone, and went through those in great detail and identified some issues while we were still in construction to make changes on to address some of the things I talked about. I really think those modifications and changes we made early on are paying dividends now that we're going into commissioning and startup. There have been the normal kind of teething things, getting loops tuned and all the rest, fundamentally, the plan has come up, and the initial indications are very positive. I'm pleased.
Jason?
Thanks, John. Jason Gabelman with Jefferies. I had two questions, please. The first one is on Tengiz. The FID has been pushed out. I was hoping you could comment around some of the factors behind that, if it's further concessions in the supply chain, financing of the project in a lower price environment, taking more of the FID in-house, those factors. The second one is on LNG contracting strategy. Recently signed a couple of HOAs with Chinese buyers. Are you comfortable with the level of spot LNG that you'll have in the market between Angola LNG and what's left in Australia, or would you look to further contract volumes? In what is a buyer's market, are the terms going to be acceptable, or do you prefer just to take the spot risk?
Jay spent many years in Kazakhstan. You want to talk about what we're doing there in a little more detail, and then Mike will talk about LNG.
At Tengiz, in a $30 world, it's a big project to undertake. Ensuring that we've gotten everything we can get out of the current cost structure built into the project have been key. We've also been looking to improve the certainty and predictability, as I talked about. There's been a lot of activities just trying to advance our understanding of what the project entails. I would say it's a balance between trying to reduce cost structures with vendors and suppliers, get our contracting strategies right so that we're ready to move forward, advance critical infrastructure, as I talked about. There's a port, in particular, where the modules will land, that we wanted to get a jumpstart on.
Getting the engineering more advanced so that we'd have a better handle on quantities and design issues that we might run into have all been key reasons to just push the FID back a little bit without really losing a lot of ground. The other issue is just the financing of the project and the funding of the project, and making sure all four partners are ready to move forward with the funding. Just as we did on SGP, if you recall, we went out with an external funding package to ensure the cash flows are there, so that once we start, we know we can proceed with the project, really regardless of the price environment we find ourselves in. It's working through those types of issues. There really aren't any other commercial issues or anything else. It's a project that looks good at moderate prices.
Certainly not at $30. There's very few things that do, in a moderate price world, it's still a very attractive project, and we anticipate it moving forward.
Yeah. Just on the financing side. If you go back a couple of years ago, it really appeared that we could finance it out of cash from operations from the venture. At the kind of prices we're likely to see, that's not going to be possible. One thing we've learned on projects, not just in Kazakhstan, but everywhere, we've got to be certain about all partners' ability to fund the project. That's been a big point of emphasis. Mike, there were questions about the LNG sales process.
Yeah, Jason. We are still in the market for LNG contracts. We're well covered with Gorgon and Wheatstone now for the initial tranche of 80+% on good, strong oil-indexed contracts with really good buyers. We secured the high-quality buyers who really have been in this LNG market for decades, and so we're very pleased with that. We've got a broader suite of people that we're talking to today, some of which you've seen, the HOAs that have been announced, and there are other ongoing discussions. The market is a little bit different today than it was a few years back. Those discussions tend to be for shorter-term contracts. People have different ideas now about how they'd like to structure the pricing, and we still have oil-indexed conversations underway, and I think we'll execute some oil-indexed contracts.
There's also other hybrids and other nature of pricing mechanisms that are more prevalent today. We will execute contracts that we think are good contracts for us and obviously that the buyers find to be acceptable or will sell into the spot market. Certainly at ALNG, early cargoes will go into the spot market, and the first order of business there is to establish reliable operations and demonstrate reliability as a supplier and then start to move to term that up. Early on, spot cargoes there moving towards termed-up contracts. I think you'll see more news in the coming quarters as we progress these negotiations.
Yeah. Let's start right here.
Thanks. Good morning. Roger Read, Wells Fargo. Looking again at the cash flow and capacity questions, all that. You've talked about some upstream assets for sale. Very few questions about downstream or chemicals. Is that an area you could look at for additional financing, whether it's, in the case of chemicals, whether the business can sustain more debt with the big project coming to completion next year? Is it worth considering a complete rethinking of how the company is structured? Would you be willing to sell out of the chemicals business or downstream business and become more focused on the upstream? Just thinking at a time like this, strategic decisions maybe need to be made. Are those being considered any differently than they have been in the past? How that fits into the whole dividend, asset sales, and cash component of the business.
I'll let Pierre talk a little bit about the chemical company in a minute. The virtues of the integrated model have been proved over the last couple years, in my view. If you look at our earnings, our operational earnings from the downstream and chemicals end of the business was about $5 billion last year. It was nice to have $5 billion in earnings last year. We've systematically improved that business, Mike and his team, over a long period of time. Now we are pruning some assets in the portfolio. We have some things for sale. Pierre can talk about the sort of the financing structure of CPChem and our general views of those businesses.
CPChem issued some debt I think last year. It's a big investment period because we have this Gulf Coast cracker going on. I think it's logical to take on some debt. It allows them to continue to pay dividends. CPChem is still a very strong credit. I think it's A minus, about 12% debt ratio, so it's got a little bit of debt in it. Plenty of capacity. On the broader question of that venture, we feel very good about it. In your books, in the downstream part of it on Slide 11, you can see that Chevron Phillips Chemical Company has been delivering leading returns. It has advantaged feedstocks in terms of ethane feed, both in the U.S. and Middle East. John talked a bit about that. We're very aligned with our partners.
Phillips 66 has got a nice project that's 70% complete on track to become online next year. We feel good about how we work together. We feel good about the performance in the joint venture.
Yeah. Good.
Good morning. Sam Margolin, Cowen and Company. I want to revisit the Permian for a second.
This might be captured in your guidance range, Is there sort of a scenario where the total capital program is coming down, but Permian and unconventional shale spending actually goes up on an absolute basis? It kind of connects to an answer you gave earlier about one of the functions of the short cycle is to fill in the base declines, which are sort of growing structurally. Maybe there's sort of a permanent aversion to non-producing capital now, If we get a faster than expected recovery in the commodity, the short cycle might actually gain even more share inside the total program. Is that accurate or fair?
Well, almost everything you said is exactly consistent with what we've been trying to get across. You will see higher spending in the Permian as we increase rigs over time. What we're trying to do is keep the efficiency high, particularly in a low to moderate price environment. Yes, you will see more spending in the Permian. As we continue to make progress in other shales, I think you'll see growth as well. You shouldn't be surprised, by the middle of the next decade, you could see 20%, 25% of our production could be in the short cycle shale and tight activity. Your comment on non-productive, I prefer to call pre-productive capital. We don't want any non-productive capital in our portfolio. There are some longer cycle projects that are going to be needed to meet supply, and we're pretty good in the deepwater business.
We've been pretty good in Kazakhstan. There will be selective long cycle projects, but I think we'll be returning to a more traditional ratio. If anything, there's potential to the upside with the shale and tight opportunity that might not have been envisioned eight or 10 years ago.
Thank you. Good morning. Tapan from Nomura International. I've got a couple of questions actually on cost. If you could just go back and talk a little bit about the change in your assumptions between the Q3 guidance and where we are today. What are you assuming in terms of cost deflation for the 2017 capital spend number, and have you revised lower your exploration spend? The second point, I think you talked about the reduction in OpEx and the $2 billion. I was just wondering whether you could give us a split between upstream and downstream, or guidance on where your upstream cash costs will be in 2016. Thank you.
Sure. I've been pleasantly surprised with the work that, in particular, Jay and his team in the upstream have done this last year. That cash production cost chart that Jay showed, costs were down about $4 a barrel last year. With some of the work we're doing on the organization, and if prices persist at these low levels, we'll continue to drive costs down even further. I've been pleasantly surprised. Some of it is in the supply chain, to be sure, but some of it is also in the improvements that he talked about in the shale and tight area. If you look at what we expect over the next five years to happen to depreciation rates in the shale and tight area, they'll go down 50% or more because of the improved efficiencies that we're seeing in the business.
Our overall depreciation rate will be about flat, despite some projects that were a part of a high-cost cycle coming through. We see operating costs continuing to be reduced. We see greater efficiencies being moved through all segments of the business. Downstream has been, we've been working on our efficiency and improvements in the downstream business, and they represent about 40% or so of our OpEx. A lot of the top-line reductions in OpEx and SG&A that you see on the income statement, for example, have been, a lot of it is in the upstream and in the corporate areas going forward. We talked about $2 billion in OpEx and SG&A from 2014 to 2015 being reduced. We expect another $2 billion that'll come out this year.
We do have higher volume coming in over the next couple of years, we're looking to see unit costs continue to come down. Depreciation will be about flat, exploration will be about a billion and a half in exploration this year, which is obviously less than what we've had in the past. Efficiencies, choices that we're making, and more short cycle spend are really the messages that I would tell you we're trying to drive through the organization. Hopefully that answers it. We'll go for one more over here.
Thanks. Scott Barber with Simmons. John, you talked about the production outlook. I was hoping you could talk a little bit about the outlook for resource-based replenishment, especially with lower spending levels, lower exploration spend, not sanctioning as many major projects. On the other hand, you're shifting to more short cycle brownfield type investments around which I think resource-based ads are perhaps a little bit less visible. Could you talk about the resource-based replenishment outlook and kind of better frame that for us so we can better appreciate that?
Sure. Jay, you want to talk a little bit about where resources are coming from?
We get resource obviously from three places, exploration, we direct purchase other discovered resources, or through advances in technology. Actually, the focus on brownfield, applying technology, improving the efficiency, that's about converting a lot of the resources that we already have on the books into the reserves equation. That's working quite well for us. On the exploration front, obviously if the price continues to persist, there ought to be some assets available out there at much lower cost. We see a lot of opportunity there, we're in a position where we have enough resource already on the books that we're not driven to go have to find more. We've got plenty to work with, especially over the intervening years.
We need to convert it to reserves. I will say that the areas where you'll see resource adds, and I'm distinguishing that from reserves, the resource adds as we continue to assess the Permian. We've had significant resource adds there, and we have more assessments coming there and in other shale and tight resources that we have. Then, of course, any discoveries we have in the Gulf of Mexico are a part of our exploration program will add resource. I am being given the sign that we are out of time for questions. Appreciate your being with us this morning. Thank you for your attention. That concludes the webcast.