Good morning, welcome to Chevron's 2015 Security Analyst Meeting. I'm Jeff Gustavson, the General Manager of Investor Relations. I'd like to welcome those of you in the room with us today, as well as those joining via webcast. Before we begin, I have a few important reminders. First, in the interest of safety, 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 digital devices. Finally, remember to take your name badge with you if you need to leave the room. You'll need it in order to reenter. During the program today, we'll begin with a corporate presentation, followed by a comprehensive overview of our upstream business.
Our agenda features presentations by our Chairman and Chief Executive Officer, John Watson, the Vice Chairman and Executive Vice President of Upstream, George Kirkland, and Jay Johnson, Senior Vice President of Upstream. We'll end the morning with a Q&A session where John, George, and Jay will be joined by Pat Yarrington, our Chief Financial Officer, and Mike Wirth, the Executive Vice President of Downstream and Chemicals. For those joining via webcast, I'd like to invite you to participate in the Q&A segment. Please submit your questions by 11:00 A.M. Eastern Time through the investors section of the company's website, which can be found at chevron.com. Finally, 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 again for your attention.
I'd now like to introduce our Chairman and Chief Executive Officer, John Watson.
Well, thanks, Jeff. Good morning. I would like to welcome everyone to Chevron's 2015 Security Analyst Meeting, including those of you listening via webcast. We're looking forward to providing you with information about our strategies, performance, and outlook. We have shortened our prepared remarks to provide more time for questions and interaction. Let me start by highlighting some of the key messages I'd like to leave you with this morning. I'll start very simply. The fundamentals of the oil and gas business, we believe, remain attractive for our company and for investors, as our products are vital to the growing world economy. As a result, our business strategies remain sound. We're an integrated company with investments favoring the upstream. We operate decentralized business units for accountability and inject functional excellence from central support and service organizations. Our financial priorities have not changed.
We invest for dividend growth and capital appreciation within a conservatively run balance sheet. The near-term business environment has changed, dramatically since last year, with lower oil prices and weaker gas markets. You'll see that our actions are aligned with this reality. We're reducing capital spending this year, have flexibility to reduce it more in future years as we complete projects under construction. We have significant cost reduction programs underway, both in the supply chain and through our internal efficiency efforts. Our asset sales goal has been expanded. We're targeting assets at the end of life and other assets that no longer fit in our portfolio where we think we can obtain good value. Our intent is for free cash flow to cover the dividend in 2017 and thereafter. Free cash flow growth is generated from volume growth and lower spending.
We'll cover all these topics in some depth this morning. First, let's talk safety. Incident-free operations protect our employees, contractors, and the environment, and it's also a very low-cost strategy. We just completed our best year ever on virtually every measure of personal safety, process safety, and environmental performance. This slide shows the days away from work rate and Tier 1 loss of containment, a process safety measure which includes fires, spills, and other incidents. Both measures continue their downward trend, and we remain the industry leader on personal safety. I have a few brief comments on 2014. Of course, we have significant earnings power and demonstrated it with last year's earnings of $19 billion and cash from operations of $31 billion. Our ROCE was 11% with significant capital in projects under construction. On these construction projects, we passed numerous milestones.
Several major projects came online on time, on budget, and we made good execution progress on others that will start up over the next two years. Our earnings enabled another dividend increase, marking our 27th straight year of increases in the annual payout. Our asset sale program was a significant contributor to cash and earnings and helped us retain balance sheet strength. Our debt ratio is 15%, or 8% net of cash balances. Finally, we're in a long cycle business and need to replenish our resource base. We did so in a very efficient manner last year, adding about 1.4 billion barrels in a highly successful exploration program. We continue to track at or near the top of the competitor band on earnings per barrel for both upstream and downstream. For upstream, the large gap between us and peer competitors has been narrowed with the decline in oil prices.
Recall we're somewhat more oil price sensitive than our major competitors, with 80% of our production directly or indirectly linked to oil. We think this is the right positioning and will benefit us over the long run. Our downstream organization had a very good year, with top-tier reliability. Our portfolio, which is primarily U.S. and Asia-based, has no material European exposure, which gives us an advantage relative to our peers. We've been a good investment over a long horizon. Our TSR over 10 years beat our peers and the S&P 500. Over five years, we also outperformed our competitors but trailed the S&P. The whole sector underperformed the S&P over the last couple of years, so did we. In fact, TSR for us and most others was negative in 2014, which is clearly an unacceptable outcome.
We'll spend the rest of the morning showing you why we're a good investment for the years ahead. The long-term outlook for the energy business is favorable, as I indicated earlier. Virtually every independent assessment of energy demand shows it growing significantly over the next 20 years. Demand is supported by economic growth and rising population and living standards, as more than 2 billion people are expected to enter the middle class over this time period. Oil and natural gas will remain critical to meeting the world's energy needs and will continue to make up over 50% of primary energy supply. The challenge for our industry will be to meet the demand. That challenge is very real because oil fields can decline at 10%-15% per year without reinvestment.
With spending on maintenance, workovers, infill drilling, existing fields can be held to 3%-6% decline annually or up to 5 million barrels per day globally each year in decline. In order to make up for this decline and meet rising demand, the industry will need to develop 290 billion barrels of new oil resources. The resource is there, and industry technology continues to advance to find and produce it. Increasingly, though, new supply will come from more complex and remote sources with higher full-cycle development costs, Arctic deep water, heavy sour, and the like. The IEA estimates that $12 trillion, that's trillion dollars, of investment will be needed during this period. Much of this investment will require some combination of higher prices, lower costs, or better fiscal terms to meet full-cycle investment requirements.
Today, we have a surplus of supply over demand, resulting from growing shale and tight volumes in the U.S. and increasing conventional production in Iraq, amongst other places. This has resulted in growing levels of inventory in 2014 and early 2015. While full-cycle economics do help determine long-term pricing, they are irrelevant to short-term oil markets, and prices have fallen toward cash costs to produce. Further, there is momentum in supply from projects that have been under construction, and industry costs are coming down, enabling more supply. Though possible, we're not expecting OPEC cuts or other supply disruptions to balance the market. We're quite sober about prices in 2015. We're starting this low price period with a very modest surplus by historical standards, as shown on this chart. Surplus production going to inventory, which is shown in orange, is less than 1 million barrels per day.
Spare capacity not producing, shown in blue, is perhaps 3 million barrels per day. Both are small compared to the size of the market, which is now 93 million barrels per day. Low prices should spur demand to some degree. With weak world economic growth, it's going to take more to balance markets in the near term. That leaves downward supply response from lower spending as the primary balancing mechanism. Big spending cuts are now rolling through the industry. The focus of discussion has been the U.S., with sharp reductions in spending, rig counts, and output estimates. In just 3 months, estimated production for December of this year, which is shown on the chart at the right, has been cut 500,000 barrels per day.
The spending reductions around the world have received considerably less discussion, although international supplies make up more than 85% of world crude and NGL supply. Host governments and national oil companies are facing very tough choices between funding to maintain and grow production or funding social and other spending. We also expect this to translate into investment reductions and lower oil supplies. We believe these market forces will bring supply and demand into balance in 2016, moving prices up. Natural gas markets also face weakness and competition from coal in the power generation business in Africa. Worldwide demand for gas is growing at twice the rate of oil, and we continue to see opportunities for LNG sales.
Since last year, some of the supply gap on this chart has been filled by additional projects started in the U.S., but it's not yet clear how the remainder will be filled as projects, particularly those outside North America, are cost and return-challenged at today's prices. Our view is that low cost of supply projects in the U.S. and Canada will be advantaged. Against this backdrop, we've reaffirmed our long-term strategies but are making adjustments to address the near-term market realities. You'll hear a great deal today about the new legacy positions we're creating in the upstream business. Our downstream is producing excellent returns and delivering growth in the chemicals and lubricant product lines. Our gas and midstream business delivers services to the upstream and downstream through our pipeline, shipping, power, and trading operations.
We've taken a different route than some of our competitors in the midstream by selling assets that are not required to support our upstream and downstream. We've received excellent value for pipeline and power assets. We differentiate ourselves through the application of technology. For example, the Jack St. Malo development, which just started up in the Gulf of Mexico, is a great illustration. You'll hear more about this later today from Jay. Our geothermal business in Indonesia and the Philippines makes us the largest renewables producer amongst our competitors and has been very nicely profitable. Our financial priorities are unchanged and very clear. We will maintain and grow the dividend as the pattern of earnings and cash flow permit. We've increased the annual per-share payout for 27 consecutive years and grown it at an 11% rate for the last decade.
We're able to increase it by investing in attractive energy projects. We make investments within a conservatively run balance sheet. We believe an AA credit rating provides us with the right amount of low-cost capital and good financing flexibility and is the right boundary condition. You'll recall a couple of years ago, I told you a strong balance sheet would protect us during a period of heavy spend should prices decline. I also told you we would gradually restore leverage as we complete our projects under construction. We've done this prudently, augmenting project spend with steady share repurchases. We do view share repurchases as the flywheel to return surplus cash to shareholders. Over the last decade, we've repurchased $45 billion worth of stock at an average price of $84 per share and reduced shares outstanding by a net 14%.
We've maintained a very strong balance sheet with ample debt capacity. With low prices, we've suspended share repurchases, and we'll use some of our balance sheet capacity over the next two years to complete projects under construction. In 2017, I expect our cash equation to be balanced within the double A boundary through a series of actions and outcomes. First, we're expecting to deliver net upstream volume growth of 20%, or more than 500,000 barrels of oil equivalent per day at cash margins that are accretive to the portfolio. Second, we intend to reduce capital spending as the construction on these new projects is completed. From 2015, we see $8 billion or more in downward annual spending flexibility by 2017 and significant expense savings as well. Third, asset sales are expected to contribute $9 billion in proceeds over the next three years.
I'll address each of these on the next few slides. The first lever to deliver free cash flow is volume growth. This is primarily an outcome of the LNG and deepwater projects under construction. Share-related volume also grows, in fact, offsetting the base decline. We expect to produce 3.1 million barrels per day in 2017 and have a portfolio capable of delivering value and growth thereafter. The second lever to deliver free cash flow is reduced spending. In January, we released our 2015 capital and exploratory budget of $35 billion. That's a 13% reduction from last year. The top of the light blue bar is a level of spend that is consistent with covering the dividend in 2017 at $70 Brent. The barbell shows the range of potential spend with attractive returns. Actual spend will depend on prices, cost of goods and services, and other factors.
You'll note we expect growing downward spend flexibility. Major growth projects already under construction in 2014 are shown in dark blue. Spending on these projects declines over the next few years. For example, spending on Gorgon and Wheatstone alone declines from $8 billion this year to less than $1 billion in 2017. Incremental short-cycle spend in our base business and shale development is being screened at current prices. Some programs have been curtailed, but most are economic and continue. Critical maintenance and reliability work continues as well. For those projects that have not reached final investment decision, we're pacing engineering and design work both to conserve cash and drive costs down. The primary exception is the wellhead pressure management and Future Growth Project. We expect to take final investment decision on this project later this year. It's one of the few that we expect an FID on this year.
We're also high-grading and pacing the exploration program. We're working on costs. Our upstream costs have been competitive, but the industry costs of goods and services have more than doubled over the last decade. As activity slows, we're seeing spare capacity emerge in most areas of the supply chain. We expect to see rate reductions in most categories of spend in the 10%-40% range. That hasn't been uncommon. IHS forecasts their capital cost index to fall about 10% in 2016. How far the index actually falls, or how long the low prices persist will determine how effectively we can work with suppliers to bring costs down further. We're also working very hard on internal efficiency efforts. This comes from Lean Six Sigma process and workflow improvement studies and other staffing reviews to size the contractor and employee workforce to fit the expected workload.
This is the fifth time our management team has seen prices fall 50% during the course of our careers, so we know how to manage costs for either a long or a short cycle downturn. For example, back in the short-lived low price period in 2008, we reduced operating and administrative expenses by $4 billion, or 15%, by the following year. I expect significant contributions from current efforts to be realized in projects, operations, and administrative categories. Divestitures are a normal part of our portfolio work and contribute proceeds to help manage the balance sheet. We divest assets that no longer have a strategic fit and where we can obtain good value. Upstream divestitures are typically focused on assets at the beginning or end of life. Last year, we announced a $10 billion three-year asset sales program. We made excellent progress in 2014, realizing $6 billion in proceeds.
We completed well-timed sales in Chad and the Canadian Duvernay and had great success selling pipeline assets into a hot MLP market. We've extended the program to four years and increased the total targeted amount to $15 billion. We're committed to delivering free cash flow to cover the dividend in 2017 and growing free cash flow thereafter. This chart shows you how we get there, starting from this year as a base. We're showing $60 Brent for 2015 and $70 for 2017. That's close to Brent futures prices. This is not Chevron's forecast. We consider a range of price forecasts for internal planning purposes. In 2015, operating cash flows will not cover the $31 billion cash portion of our capital spending program, plus dividends. We will fund the deficit with asset sales proceeds, cash drawdowns, and borrowing. By 2017, we intend to cover the dividend through three changes.
First, higher prices. $10 per barrel adds $3 billion-$4 billion to cash flow on existing production. Second, more than 500,000 barrels per day of net new production and other operations would add $10 billion-$11 billion of cash flow. Our new LNG and deepwater projects have relatively low operating expenses, early tax benefits, and deliver accretive cash flow per barrel to the portfolio. Third, we'll spend less because the projects under construction will be largely completed, and we invoke the flexibility I described earlier. Several other factors could help us in this price case. We haven't baked in all rate reductions we're likely to see in the supply chain if this price scenario plays out. We haven't considered all the benefits of a strong U.S. dollar should this trend continue, as some expect. We're not counting asset sales proceeds to cover the dividend in 2017.
We haven't shown 2016, but we expect to consume less cash than in 2015. In this illustration or other reasonable sensitivities off this case, we expect to manage the balance sheet comfortably within the AA parameter. That brings me back to where I started. We like the oil and gas business. We have consistent and clear business strategies and financial priorities. We're constructive on the long-term price outlook, but sober about the current realities of lower prices. We're taking significant action to balance the cash equation and cover the dividend by 2017. We expect to deliver volume growth and emerge on the other side of this downturn leaner and better. All of our actions are geared toward delivering value through dividend growth and stock price appreciation that is both best in class and an attractive option to all investors.
George and Jay will now present the Upstream story. We'll take some questions. I'll ask George and Jay to join me. I'll just make a couple of comments as they're coming up to the stage here. First, as all of you know, George, a face you're familiar with, is reaching mandatory retirement age. He'll be retiring around the middle of the year. I would just like to publicly express my appreciation to him. You can't imagine how great it is to have George in the company. He's a legend in the business. He's done great things to add value to this company. His passion is well known to all of you. He still has a couple more international trips left, believe it or not. He is throwing himself with that same passion into transition, and has helped Jay greatly in transition.
Jay, of course, is very seasoned and well-prepared for the role. This will be the last time you'll see George in front of this audience. I would just like to acknowledge this, and I hope you'll join me in thanking him for the great work he's done.
Thank you.
Thank you.
Thank you, John. Thank you very much, and good morning to everyone. I'll tell you that Jay and I are glad to be here once again to review with you Chevron's upstream business. Let me call your attention to that photo. There's only one thing missing on that photo for me. That's an LNG tanker taking on LNG at the end of it. I really do look forward to that very much. I'll now move to the next slide. Today, I'll be talking about the performance section. In that section, I'll cover portfolio strategies at a high level, and then provide some insights on our historical performance, including 2014's. Jay will then take you through how we're managing the upstream business in the current low-price environment. He'll then wrap up our industry-leading growth story. I'd like to begin with our portfolio.
Chevron has a diverse upstream portfolio with production in 23 countries and in nearly all of the world's key hydrocarbon basins. Our geographic and asset class diversity is a strength, ensuring we remain competitive in all macro environments. Our upstream assets are managed through 4 regional operating companies and 15 business units, an organizational model that has served us well for many years. As we move towards 2017, our production distribution will change. Our Europe, Eurasia, and Middle East production stays relatively flat during this period, while our Africa and Latin America unit is expected to grow by almost 100,000 barrels a day. North America production is also expected to grow by almost 100,000 barrels a day through new deepwater Gulf of Mexico projects and by increases in our shale and tight production.
Our Asia Pacific region's production is forecasted to grow by over 300,000 barrels per day, driven by our Australian LNG projects. Just like our portfolio diversity and our organizational model, our strategies are a part of the foundation that has enabled us to create value and to deliver industry-leading results for the last decade. While the strategies have remained constant, we adapt our nearer-term tactics to manage our business in dynamic environments like what we saw in 2008 and 2009, and like what we're seeing now. Jay will cover the actions being taken throughout the upstream to deal with the low-price environment. Consistent execution of our strategies has served us well and will continue to do so into the future. Let's take a look at production. In 2014, net production was approximately 2.6 million barrels per day, very close to our initial production guidance.
Our base operations delivered strong performance with a decline rate of less than 3%. We also sold a number of later-in-life assets, such as Chad, the Netherlands, and some South Texas gas. Shale and tight production grew by 41,000 barrels per day, around a 35% increase. We ended the year with several key startups, including the Bibiyana expansion in Bangladesh and Tubular Bells, as well as Jack/St. Malo in the deepwater Gulf of Mexico. I'd like to cover exploration, a long-term competitive differentiator. 2014 was an excellent year for our exploration program around the world. We made 35 discoveries at a 66% success rate, and we added 1.4 billion barrels of resource to the portfolio.
Our success was driven by conventional offshore oil plays, including West Africa and the deepwater Gulf of Mexico, gas discoveries in Australia, as well as the shale and tight plays in the Permian and Duvernay. Over the 10-year period, our exploration results are similarly strong, with over 10 billion barrels added at $1.79 per barrel finding cost. WoodMac data shows that Chevron is the leader in value creation from exploration over the last 10 years, double our nearest IOC competitor. Since they completed their study, we've announced two significant discoveries in the Gulf of Mexico, Anchor and Guadalupe. Next, I'd like to cover resources and then reserves. Resource replenishment is a long-term metric. During the last 10 years, we've produced over nine and a half billion barrels and divested almost eight billion.
Our success through the drill bit and in capturing discovered resource opportunities has added 29 billion barrels, and these are unrisked resources. Much of this growth over this period is in North America and Australia. Resource replenishment is strong over the last three, five, and 10 years. Our 225% resource replenishment over 10 years has put us in an enviable position. We have a large resource base and a strong queue of opportunities. We can be selective on what opportunities to fund and what additional resource to pursue. Now let's look at proved reserves. During 2014, we achieved an 89% reserve replacement ratio. One year reserve replacement ratios can be variable, as reserves are typically booked when major capital projects reach a sanction decision. In spite of a very limited number of project sanctions during 2014, strong base business revisions drove a solid replacement ratio.
We delivered 96% and 98% RRR over the last five and 10 years. Our target continues to be 100% reserve replacement ratio. Now I'd like to move on to financial performance. In 2014, we led the IOC competition with nearly $18 in earnings per barrel production. This was the fifth consecutive year of being in the top position. Falling oil prices in the fourth quarter drove a reduction in 2014 realizations, nearly $7 per barrel less than 2013, and consequently, lower earnings. Last year, our upstream costs were about $36 a barrel. The chart shows our historical position relative to our competitors, consistently in a leading position. These costs include production costs, exploration expense, DD&A, and other expenses. Essentially, all the costs that when subtracted give pre-tax net income.
Our competitive upstream cost structure is notable since oil-weighted portfolios, such as our own, generally entail higher operating costs. The ability to deliver a leading competitive cost structure has been a contributor to the highest earnings margin in the industry. Although we're at a good starting point and begin with a strong foundation, we're not being complacent. We're pulling levers to help us improve performance and manage costs during this price downturn, and we'll show later some of our ongoing efforts that are continuing to drive costs out of the system. Now turn to the next slide. Our upstream business is on a strong foundation. Although the current price environment is a challenge, we've been through these periods before, and we know how to manage through them.
The systems and processes we've put in place have resulted in leading performance for a decade across many areas of the business and set us up well for the future. I am confident that Jay and our experienced management team will continue to build on our own foundations. Thank you again for your attention, now I'd like to turn it over to Jay.
Thanks, George. Thank you, George. Good morning. The last six months have been a dynamic time in our industry, as John mentioned earlier, a repeat in some ways of the four previous low price cycles that have occurred since 1980. We've managed through these cycles before, we know the levers to pull, I'll begin this morning by explaining how we're managing Chevron's upstream business in this low-price environment. Then I'm going to talk about our unmatched growth story, which remains intact. We're focused on improving our cash flow, particularly during this period of low prices. We're reducing our spending, first by high-grading our activity, then by lowering our costs, both internally and from suppliers. Finally, we're increasing our efficiency. Simply put, getting more for less. To generate more cash, we're also divesting assets which don't compete in our portfolio.
Of course, our volume growth is expected to significantly increase our cash flow. I'll talk about each of these, starting with our upstream C&E. You can see that we've lowered our 2015 C&E program by $5 billion relative to 2014. Major capital projects already under construction are our first priority and are depicted on the chart by the dark blue bars. This year, approximately half of our capital budget is allocated to these projects. By 2017, this falls to less than 15% as construction is completed and the projects start up, greatly increasing the flexibility in our capital spending. Now to preserve this flexibility, we're pacing economic projects that are still in the planning phase. The funds for these projects are designated by the yellow bars.
Managing the timing of these projects provides significant capital flexibility and allows us time to capture a lower cost structure when the project eventually moves to construction. Now let's focus on the medium and light blue bars, which represent our second funding priority. Base business includes critical asset integrity and maintenance work, high return base business investments, and our shale and tight portfolio. These investments represent around 35% of our 2015 C&E program. As John said, our asset integrity and maintenance work are considered non-discretionary. Investments in infill wells, workovers, and our shale and tight portfolio are tested for economic performance against current prices. Finally, we fund selected longer-term investments, including our exploration. As shown earlier, our past performance in securing new resource allows us near-term flexibility in funding our exploration and discovered resource acquisition activities.
In a continuing low-price world, we have the flexibility to further decrease our 2016 and 2017 C&E spend, as shown by the gray bars. The barbells on the chart indicate the potential range of spend as lower cost structures are realized and projects with attractive returns are moved to execution, consistent with our corporate cash priorities. Let's take a look at our cost reduction efforts. We entered this downturn with a competitive cost structure, it's not enough. We're aggressively pursuing multiple approaches to further drive costs out of our system, that begins with our supplier costs. The chart shows the primary categories of our upstream operated spend. Our procurement and supply chain organization, together with the business units, has set targets of 10% to 40% for each category and are actively securing reductions from our suppliers.
We're seeing reductions in short cycle categories first, such as well construction and land-based rigs. If negotiations prove unsuccessful in achieving the targeted cost, we're moving to rebid contracts. We're looking for cost reductions internally as well, we've been systematically working through our business units and project teams to ensure we have efficient and effective organizations. We began this process prior to the current downturn with our Nigeria and European business units and have recently moved to our Appalachian, Gulf of Mexico, and Southern Africa units. As our assets and operations evolve, our organizations must continually evolve with them. I've talked about reducing our activity levels and cost structure, an equally important component to improving cash flow is increasing our capital and operating efficiency. This means getting more for less.
We've proven our ability to deliver high efficiency in upstream manufacturing environments, including the Gulf of Thailand, the San Joaquin Valley, and Indonesia, where we've demonstrated industry-leading performance. Shale and tight developments require a similar manufacturing approach. Over the last several years, we've driven significant improvements in several key performance metrics. For example, over the last two years in the Permian, we've reduced our drilling and completion costs, we've increased the number of wells per rig year, and we've reduced the number of days from spud to production. As we transition from vertical to horizontal development drilling, we're focused on delivering even larger and more significant efficiencies across our Midland and Delaware Basin operations. In the deepwater Gulf of Mexico, technology is driving improved economic performance. Enhanced seismic captured through ocean bottom nodes helps optimize both the placement and the number of wells, ultimately lowering costs and increasing recovery.
In deepwater drilling, we've delivered a 25% reduction in drilling days per 10,000 feet over the last two years. On the completion side, our development and implementation of the single-trip multi-zone frac pack increases completion efficiency and reduces rig time. It's already delivered nearly $200 million in savings, and the savings grow with each additional well we drill and complete. Seafloor pumps reduce back pressure on deep reservoirs and deliver increased recovery. In the case of Jack/St. Malo, this is expected to yield an improvement of 10% to 30%, which equates to 50 to 150 million barrels of additional oil recovery. Successful application of technology is lowering costs and increasing recovery and improving the economic outcomes from our deepwater projects. The fourth element in improving cash flow is portfolio management. We actively manage our large upstream portfolio, taking actions that create maximum value for the business.
As shown on the slide, we farmed down or divested a number of assets over the last six years to generate value. In 2014, our proceeds from upstream-related asset dispositions were approximately $4 billion. We use farm downs to manage cash, optimize value, and reduce risk. A recent example is the Duvernay, where we brought in a trusted partner, realized value identified in our early exploration program, and reduced our capital exposure and risk as we move into the appraisal and development phase. We typically divest assets that can't compete for capital in our portfolio, which are often either early or late in life. Recent examples include Cambodia, Chad, and the Netherlands. The benefits from divesting assets include not only the early realization of cash, but also avoiding future capital investments in a lower-performing asset.
I've covered how we manage cash by reducing capital, lowering costs, increasing efficiency, and managing the portfolio. Now I'll move to our production growth and the impact we believe it'll have in improving our cash flow. Our foundation for future growth begins with our high return base business. We invest in two major areas to help us mitigate base decline, conventional infill drilling and workovers, and base major capital projects. These are projects that maintain production levels in existing facilities. A good example of this type of project is Agbami Stages 2 and 3, where the investment is designed to keep the existing facilities full but does not expand the production capacity. These types of investments have reduced the portfolio's natural decline rate from around 14% to less than 3%.
When combined with investments in shale and tight, we expect to hold our base production essentially flat over the next few years. Base business investments have attractive attributes, including shorter cycle times with faster, higher returns, lower subsurface risk as the reservoirs and resource are generally better understood, ratable production, and robust economics as these investments leverage existing infrastructure. Base business assets can't support reinvestment indefinitely, and it's critical they be replaced over time. New assets such as Gorgon, Wheatstone, and Jack/St. Malo are the next generation of projects that will not only drive our growth, but will also renew our base. Growing production 20%, from 2.6 to 3.1 million barrels of oil equivalent per day, is enabled by our major capital projects in shale and tight developments.
The 11 red dots on this map represent major capital projects with over $1 billion of Chevron net investment that will be contributing volumes by 2017. The majority of these projects will start up this year and next. The stars represent our shale and tight activities, and the blue triangles represent additional projects that are either in planning or under construction, and that we expect to start up and contribute volumes in later years. One of the most notable of these is TCO's Future Growth Project, which I'll touch on later. We're optimistic about our future and our growth through 2020. I'll focus first on one of our most important growth areas, the Permian Basin. We believe our Permian acreage is second to none, with over 2 million net acres, over 7 billion barrels of oil equivalent resource, and multiple stacked plays .
Even better, 85% of our acreage has no or low royalty. This is a significant differentiator in terms of the value of our barrels, as you can see in the middle panel. While it's always important, this advantage is even more compelling in the current price environment. We've taken the approach of developing our Permian position at a measured pace, and our approach is working. It has allowed us to de-risk acreage through industry activity, move to horizontal wells, and employ our factory model in a deliberate fashion, all of which contribute to more economic development. We continue to see potential for growth in the Permian, as shown on the chart on the right. We've increased our production outlook for the Midland and Delaware basins at each of our investor presentations since 2012. Today, we're forecasting over 250,000 barrels of net oil equivalent daily production by 2020.
The increased growth is coming as we shift from exploration and appraisal activities to development drilling at locations like our Bradford Ranch Wolfcamp development. Bradford Ranch is our first Midland Basin horizontal development. We've recently put two horizontal wells, the Midland number 5 and number 6, on production. The first well, number 5, delivered an initial production rate of 1,300 barrels per day with 88% liquids. The well is a 7,500-foot lateral in the Wolfcamp B. The number 6 well also delivered positive results consistent with the shorter lateral length. There is potential for over 200 wells at Bradford Ranch, the majority of which will be 7,500-foot laterals. With these lateral lengths, we're expecting estimated ultimate recoveries of 800,000-900,000 barrels per well based on our results to date.
As you can see on the map, Bradford Ranch represents just a small portion of our acreage in the Midland Basin. We're particularly excited about this development when you consider the continuing improvements in cost and performance I discussed earlier. In the deepwater Gulf of Mexico, first production was achieved from Jack/St. Malo, a lower tertiary development, in December. The project was delivered on time and on budget. An initial production experience has been excellent. The wells are completing the initial reservoir surveillance program, and the production is already averaging more than 50,000 barrels a day. By the end of this year, we expect to have six of 10 stage 1 Jack/St. Malo wells online. Looking beyond stage 1, we have several subsequent development projects in progress, including our Jack/St. Malo stage 2 development. We anticipate sustained production through the end of this decade.
Let's shift to our Australian LNG projects. George and I were just in Australia and reviewed performance at both Gorgon and Wheatstone. We're pleased with the progress we've seen, particularly over the last several months. Gorgon continues to move steadily towards startup, with first gas expected in the third quarter, followed by LNG exports before year-end. With the project now passing the 90% mark, the focus on train 1 is shifting from bulk construction to systems completion and commissioning. Gorgon's upstream scope is nearing completion, with all 18 wells ready to produce, all offshore infrastructure in place, and all associated pipelines, manifolds, and flow assurance systems installed. 18 wells may not seem like a lot for a project of this magnitude, but as you know, each well is designed to deliver 240-270 million cubic feet of gas each day. On the island, we're making steady progress.
35 of 51 modules are installed, including all of the train 1 and common facility modules needed to produce LNG. Both LNG tanks are complete. The loading jetty is structurally complete, and utility systems such as the electrical distribution, nitrogen, and instrument air are being placed in service. The control center is functional, and our operations team is taking over systems as they're commissioned. A near-term milestone will be the introduction of fuel gas into the plant, which we expect to see any day, followed by the startup of the first gas turbine generator within a month. Startup of trains 2 and 3 are still expected next year. On the commercial front, over 75% of Chevron's equity LNG from Gorgon is covered by sales and purchase agreements with leading customers in the Asia Pacific region.
Gorgon is a world-scale project that is expected to deliver prolific cash generation over the next 40-plus years, and we are getting close to seeing it come to life. We also visited the Wheatstone project, which is now approaching 60% complete. Excellent progress is being made on our upstream campaign, with all nine development wells drilled to the top of the reservoir. The gravity-based structure for the offshore processing platform and the 44-inch trunk line have been installed. The topsides have been loaded out and will depart from Okpo, South Korea, later this month, another major milestone. We continue to make good progress at the Ashburton North plant site, where dredging and piling activities are complete, the wharf is operational, and four process modules have been delivered to site.
As you can see in the picture on the right, the roofs are in place on both LNG tanks, and this year, we expect to finish drilling all development wells, install and hook up the platform topsides, and deliver all train 1 and common facility modules to site. Commercially, 85% of the Wheatstone LNG volumes are committed under SPAs in line with our target. Like Gorgon, Wheatstone is an outstanding project that is expected to deliver decades of cash flow and earnings. In addition to Gorgon and Wheatstone, we have a number of other major capital projects coming online late this year and early next. These projects deliver significant growth volumes as we move towards 3.1 million barrels per day in 2017. Let me begin with the Big Foot project in the Gulf of Mexico, where the project is 94% complete.
Installation is ongoing, with 10 of 16 tendons in place and the floating production unit ready to sail from Corpus Christi during the next favorable weather window. We expect to have the tension leg platform moored and storm safe well ahead of hurricane season. Following the initial hookup and commissioning, we expect rig-based completions and first production later this year. The next project, Angola LNG, has been down since early last year due to a piping failure in the flare and relief system. Since that time, a plan's been developed and put into action to complete the repairs. Angola LNG is also taking advantage of the downtime to implement a number of design improvements, which will optimize the output from the plant. ALNG is currently forecast to restart in the fourth quarter of this year.
Construction of the Congo River crossing has also commenced. Once complete, this pipeline connection will enable delivery of additional gas volumes to the plant from the fields north of the Congo River Canyon. At Moho Nord, we're seeing good progress on the floating production unit, tension leg platform, and subsea production systems. three wells have been drilled, and we expect first production from phase 1 later this year. Our Mafumeira Sul project has achieved several significant milestones during recent months. three of the four jackets have now been installed, and all topside modules are en route. Drilling is expected to commence in the third quarter of this year, with startup anticipated in the first half of next. We're reaffirming our 2017 production target.
With our strong base production, major capital projects in flight, our shale and tight development programs making significant progress, we remain confident in our ability to deliver 3.1 million barrels of oil equivalent per day. Beginning from our starting point of around 2.6 million barrels a day, we continue to expect a base decline of less than 3% over the next several years. In addition, we're planning to complete a series of asset sales, and a forecast is shown on the waterfall. The future strip indicates a Brent price of around $70 a barrel in 2017. While this is not our forecast, it is a convenient benchmark to use for illustration purposes. With this $70 assumption, we'd anticipate a price effect of 50,000 barrels a day relative to 2014. Our growth towards 3.1 million barrels is driven primarily by three major asset classes, shale and tight, offshore, and LNG.
You'll also see that we include a buffer of 20,000 barrels a day to address future uncertainties. I've talked about the developments driving our growth to 2017. Now I'd like to shift to some of our projects that will contribute value beyond that time. As mentioned earlier, we're pacing projects not yet in execution to manage cash and take advantage of the lower cost environment. Rosebank is a large, west of Shetlands development with the potential to generate significant value. We've optimized the design basis and incorporated an improved reservoir management plan enabled by an ocean bottom node seismic survey. As a result, we've reduced the number of development wells by 10%, improved the expected recovery by 20%, and reduced the complexity of the FPSO turret. We're also rebidding and renegotiating contracts in order to capture cost savings available in the current market.
In the Gulf of Mexico, we completed appraisal activities for Buckskin Moccasin and have selected a subsea tieback to a third-party host in lieu of a new build hub. This is the most economic alternative for this development. We're continuing engineering optimization as we progress this project towards a future final investment decision. At the Indonesia Deepwater development, we completed drilling for the phase 1, Bangka, and are on plan for first gas next year. However, before proceeding with the phase 2, Gendalo-Gehem, we're optimizing the design basis and working with the government to extend the PSCs, as well as securing LNG contracts and working to lower supplier costs. Let's turn to Tengiz. The Wellhead Pressure Management project is another good example of what we call a base major capital project as it maintains the production levels in our existing plants as reservoir pressures decline.
The light blue area on the chart shows the production contribution that this project provides. We categorize the Future Growth Project as a major growth project, as it increases plant capacity by 250,000-300,000 barrels of oil a day, and this is indicated by the dark blue on the chart. We shifted the investment decision to later this year to take the time to reduce costs by optimizing the design and to negotiate with suppliers to capture savings available in the current environment. In the meantime, we continue to construct critical infrastructure such as the port, camps, and haul roads to reduce schedule uncertainty and execution risk. We are also continuing to progress detailed engineering and are targeting to have nearly 50% of the engineering complete by year-end. Benchmarking shows that higher levels of engineering prior to sanction lead to improved cost and schedule performance.
We're working with the Kazakh government and our partners to agree on the support associated with the project, and we expect to reach a final investment decision in the second half of this year. We recently announced two significant discoveries in the deepwater Gulf of Mexico. The first of these is Guadalupe. While it's a significant discovery, by aligning ownership across 24 leases, which include the Tiber and Gila discoveries, we've enabled a hub development. Developing multiple fields with a single facility reduces investment risk. Having a larger resource base reduces unit development costs, both of which improve economics. As operator, Chevron will bring its industry-leading expertise in the lower tertiary to this development. We also made a significant discovery at Anchor, which has pay across multiple Wilcox sands. Anchor is very promising and will continue to progress the appraisal program this year.
Both these potential developments will leverage the design, project execution, organizational capability, and operational learnings proven so successfully at Jack/St. Malo. We continue to pursue exploration in both our focus areas and selected test areas with impact-level potential. Our focus areas leverage existing business and acreage positions to maintain and grow production. North America shale and tight, and the deepwater Gulf of Mexico, West Africa, and Australia are areas where we have a proven track record of exploration success. Our test areas are designed to provide exposure to new basin opportunities with the potential for significant resource capture. We're in a great position because we have a good near-term exploration portfolio. We can moderate our spend because our recent exploration success and strong resource replenishment noted earlier. How does our growth compare to our competitors? Our 10-year index growth leads all of our peers.
Our growth comes from a variety of assets. With our major projects coming online, we're confident in our growth forecast to 2017. Projects like Gorgon, Wheatstone, Angola LNG, and Jack/St. Malo alone represent over 400,000 barrels a day of growth. The growth in volume is great, but we like the growth in value even more. This slide compares our 2015 portfolio cash margins with our 2017 portfolio. Assuming a modest price recovery from $60-$70 a barrel, the increase in our cash margin is primarily driven by a higher percentage of high-margin barrels coming into the portfolio. These barrels are largely generated by our deepwater and LNG projects. This combination of significant volume growth with a higher cash margin will deliver increased cash flow in 2017. In summary, we're positioned to succeed.
Our diverse portfolio does not rely on a single asset class, we can shift our investments as needed to maximize overall value. Through years of strong resource replenishment, we have a robust opportunity queue, which will be developed in a deliberate, disciplined manner. We have a leading cost structure, we're driving to further improve it, our industry-leading volume growth is unmatched, we expect to deliver top cash margins as well. Thank you for your attention, now my colleagues will join me, we'll take your questions.
Okay. Jay, thank you very much. For those that don't know Mike Wirth, he runs our Downstream and Chemicals business. Mike's done a terrific job in that area. He'll be joining us. Pat Yarrington, our CFO, is also joining us, of course, George and Jay. Just a couple rules. Just raise your hand. We'll have a microphone brought to you. We'd appreciate it if you would introduce yourself so that those online can hear as well, try to limit yourself to one question, we've got plenty of time for questions today. Why don't we start over here, Jason?
Thanks. Jason Gammel, Jefferies. Just want to ask you about the action you're making with the capital program, obviously very significant illustrating the flexibility that you have.
How do you think about balancing the post-2017 production growth with lower capital spending today? Is it going to significantly affect what you would expect production volumes to be?
Yeah, it does make a difference. Certainly when we take spending last year, we had signaled $40 billion type of year. Now it's down to $35 billion and lower in future years. If you spend less, you'll receive less over time. Our 2017 target doesn't change very much because a lot of that was in flight. There have been some adjustments in some of the short cycle spend. There will be some impacts down the line as you defer some of these big projects. Maybe I'll let Jay talk a little bit about what sort of momentum we see in production growth sort of between 2017 to 2020. He can give you some kind of indication of that.
Yeah. The projects that we've slowed to make some of the flexibility available really give us an opportunity to build some of this low-cost structure into those projects and make sure we continue to progress the engineering and get to a more advanced state when we take the sanction decision. Unlike the period we're in now, where we're expecting to grow 6%-7% a year through 2017, we would expect to see a more moderate growth, maybe more around 1% beyond that time. We have quite a bit of momentum that'll carry us right through 2017, probably closer to the end of this decade before we start seeing that moderation.
Yeah. Just one example, Wheatstone. We'll have one train on at the end of 2016. The second train comes on in 2017, obviously in 2018 you get the full year effect, plus the shale volume continues to grow. We've got a couple other like that. The Future Growth Project is now sort of outside that 2017 to 2020 window. That one will probably come in 2021, assuming sanction later this year. Okay. Yeah, Todd? Oh, go ahead. We'll go to you next, Evan.
I know Evan's better looking, Doug Leggate from Bank of America. John, can I take two quick ones, please? Perhaps this one's for Jay, actually, there's been a lot of talk about cash margin improvement.
I'm looking at slide 29, I think it is. Sorry, 33 on your upstream section. I'm comparing it to what you said last year. At $70 oil, the cash margin on the existing portfolio and the new portfolio looks to be identical at $25 a barrel, more or less. On this chart on page 33, it says that your improvement in cash margin is also assuming a $60 number this year and $70 number in 2017. My question is, how much of the cash margin improvement is just the oil price and how much, looking at last year's presentation, is the portfolio, because the portfolio average looks exactly the same? I've got a follow-up, please.
The portfolio really is being driven by the addition of the LNG and deepwater barrels. They're very cash creative when they come on. As John said earlier, there's some tax effects in place, the operating costs on a unit basis also tend to be very low. We'll get very strong contribution from there, that really provides the majority of that cash margin growth and the difference between 2015 and 2017.
Said another way, if you were $60 flat, that orange wedge would still be very large.
Yes.
All we did was just try to conform the price assumptions to what we see in the futures market in all the different cases that we showed you today. We're going to see large cash margins on those deepwater and LNG developments.
Particularly the LNG. The LNG-
Yeah
is particularly strong.
Can I follow up?
Go ahead. Yeah.
My follow-up, John, is just on the post 2017.
Is there an argument, or is what you're kind of telling us today that there's an argument for Chevron to go to a kind of ex-growth model, where you're high-grading the portfolio with your newer developments, but no longer targeting an aggressive kind of top-line growth number? I'm just looking for clarification on that.
Yeah. I wouldn't say we're going ex-growth. All along, the 2017 target that we put in place was an outcome. I know we have some new analysts in the group, but I'll just take you back to 2010 and why we put that growth target in place. During that time period, we had just gone to FID on Gorgon. We expected to go to FID on Wheatstone, and then we had the moratorium in the Gulf of Mexico, but we had some deepwater projects that we thought were coming. We knew we were heading into a period of heavy capital spend, and we knew that that would be very visible. We also knew the growth wouldn't be visible because it was going to take four or five years, up to seven, to get all these things online.
We put out a number for 2017 to show you what was coming at the end. That was always an outcome, because four to 500,000 barrels a day of that growth was really a function of these big projects. There have been some ups and downs since then that have really been value-based decisions that we've made. For example, less emphasis on the U.S. gas market since that time. On the positive side, shale oil production in the Permian. We always respond to the environment that we're in, but there's momentum from what we have under construction. The comment that Jay made a little bit earlier is that we expect after 2017, we won't repeat this. It's very unusual to go through a period of heavy capital spend as we did.
It was a combination of really circumstances that got us to where we were. We'll make decisions that are based on value going forward. I don't see a circumstance where we'll stack up as many projects as we had previously, but we've still got fair depth in that portfolio, and we'll move those things along, consistent with sort of the corporate cash priorities. We do want to pay and grow the dividend. We do want to keep a strong balance sheet. We'll move those things along. My expectation is that you'll continue to see some growth in the portfolio, but more consistent with what you see across industry rather than this big spurt of growth here in this next short window. Evan, maybe we'll go to you next.
Great. Thank you. Evan Calio, Morgan Stanley. John, you painted a much tighter longer-term picture for the commodities, but a little bit more cautious or aware near-term outlook. Can you discuss the consideration of your unconventional pacing, whether to decelerate pacing? Because it's one of the areas where you have a lot more flexibility and a significant portion of the well is value of the well is in the first one year of production.
Yeah. Well, George, you've lived through this history of how we've decided to pace our unconventional work thing in the Permian. Why don't you talk about that a little bit?
I start back. We've had a lot of people saying we need to be going faster out there, we've really utilized the rate we're going to de-risk the areas, know where to go spend our money, and frankly, we've done this without spending a lot of Chevron money. Our acreage position's so good, we've learned a lot from competitors and their, in some cases, relatively rapid pace of drilling. They've helped us answer a lot of questions about where the quality of the acreage is. We run our economics on all our opportunities out there in this environment of price we see today. We're using the strip price to look at that to make sure we've got good economic decisions being made. They have good returns, acceptable returns at this point. We see that very frankly, in the really the $60 range.
The strip it's in right now, we see that on the ones we're drilling. The reason we test all the ones that we have out there is we don't want the weaker ones to proceed at this point in time. We need to keep moving forward. We need to build the infrastructure. The ones that set this first infrastructure actually build the opportunity set for the resources that are a little bit smaller. The first set of the very best resources really enable future developments, too. They don't have to have as good a resource recovery. We're trying to be very measured, very deliberate, and very economic driven on all our decisions out there.
Paul.
Thank you, John. Paul, thank you. Wolfe Research. First, to second your comments on Mr. Kirkland, it's been a pleasure and a privilege. Thank you, sir. John, on the reduced capital expenditure, we've got about $35 billion this year and about, it looks like $30 billion in 2017. You talked about LNG spending going from eight to one.
That would be obviously a $7 billion savings.
Are we looking then at, obviously, at more spending elsewhere in the portfolio, and I wondered where that extra spending was coming from, or maybe perhaps you're not cutting the LNG spend quite as aggressively. As a follow-up, how much Tengiz, for example, of spending have you now got in that period, which would be for later growth?
Inherent in that forward estimate, we've told you we expect to take FID, Tengiz is in there. The LNG spend does come down, but there are other categories of spend that continue and in some cases grow. Pat, you want to add a little bit more on some of the areas of the capital spend during that period?
I think, Tengizchevroil obviously is in there. Additional unconventional activity is in there as well, and obviously, depending upon the success that you have with exploration, and we just have had some very significant exploration successes that augments what you would be doing in the deep water from an appraisal standpoint.
One of the things, the reason Jay made the point on some of those base capital projects that we have is, for example, Agbami. We're continuing development drilling to keep Agbami full over time, Tahiti, some of the deep water developments. You have some projects that we don't consider big new growth projects, but they're keeping the facilities full and leverage the existing infrastructure. Those sorts of spending are highly economic. What's challenged in this time are some categories of what I would call full cycle brownfield, excuse me, greenfield type investments, and those we're going to scrutinize very closely during this period.
Understood. Thank you.
There's supposed to be a follow-up. Okay.
Yeah, the follow-up is, you've got, I think you said $9 billion worth of asset disposals over the period.
Yeah
with, I think, 65,000 barrels a day of production.
Yeah.
The two components of that. Firstly, is that $9 billion, or what percentage of that is the 65 approximately? And secondly, how much of your production right now today is cash negative at $60 Brent and $50 WTI, say? Is your portfolio cash positive right across the board, or is there stuff that's actually underwater right now? Thanks.
I'll take the asset sale one, and then I'll let maybe Jay talk about the other. On the asset sales side, one of the things we do is we try to keep the exact assets that we're going to sell proprietary until they happen, because I don't think it helps your negotiating position very well to identify those assets. You've seen over the last decade, Mike's cleaned out his portfolio very systematically and built a leading business. We just talked about the midstream and the success we've had there. We've still got more opportunities in those segments, but we also have some assets in the upstream. Now, we don't sell at any cost. We do think we have some assets where the current price environment won't impact value significantly on the upstream side.
Over the next three-year period, we think we'll find a window for several upstream assets that we think will represent a good value for us and an opportunity for someone else who can realize more, and we'll continue to have some in the downstream and midstream area. Maybe Jay, you want to talk a little bit about margins in the business?
Really across our business at this point, we're seeing positive cash prior to C&E. What brings us down, of course, is the C&E spending that's ongoing. In each of our asset classes on existing assets that are in production, we're actually seeing positive cash returns for the most part.
Great.
Thanks. Asit Sen from Cowen and Company. In the $25 per barrel cash margin number, does that include any benefits from ongoing cost savings, efficiencies, would that suggest an upside? Because a 10% decline in your $36 per barrel cost structure could be meaningful.
Yeah. I think very little. This is a very fast-changing market right now for goods and services, and some of the contracts that we sign are renegotiating or opportunities that we're seeing are just now being baked in. We've leaned forward a little bit with some cost reductions, but by and large those numbers haven't been impacted by what I would call a structural shift or reduction in costs.
Just to add that most of that is related to capital.
Yeah.
Much of that saving. We've got to invest the capital before we get to appreciate it later. It's got a little bit of lag.
Ongoing OpEx is labor and things like that, which depending upon which category, you may or may not see a lot of reduction. Okay.
Follow-up.
Okay. Paul. Okay.
Just on the Permian activity, Jay, great chart on the efficiency and performance chart. Could you talk about year-over-year activity improvement, like 2015 versus 2014, rig count or well completions and all that?
Yeah, the rig counts are actually coming down a little bit. We're down five rigs from where we were last year, but the number fluctuates up and down just as activity levels and projects come in and out. We're down about five rigs. We had 30. We're at 25. In terms of the well activities, for example, last year we said we'd drill 500 wells in the Permian. We actually drilled about 550. Our efficiency was much higher than we expected. What we're doing this year is, as we shift away from vertical wells into more horizontal, the actual number of wells will decrease. You'll see more like 375 as kind of the current target in the Permian Basin this year. The vast majority of those are horizontal wells, more productive.
How about Ed?
I guess two questions. The first one on cost deflation. You said 10% to 40% as a number. Most people in the industry are talking 20% to 25%. Is the extreme end certain sub-sectors or is it including drilling efficiencies? As you think about overall costs, it's not just cost deflation, but there is efficiency through the business.
That's right.
Where do you think overall costs could come down? I have a 10-part follow on.
I would expect nothing less. Jay was careful to distinguish between the efficiency and sort of the cost from the rate side. Jay, maybe you've got some examples. We try not to be specific to vendor, but why don't you talk about some of the specifics, a little bit more detail on what we're seeing?
Maybe I'll stick to categories rather than individual vendors. What we're really trying to do is for each of those categories I showed you of our spend, we work with some independent consultants that help us with market intelligence. We take our own experience in terms of what we're seeing, other rate reductions that we get in one business unit compared to another business unit. Then we're also working with our global supply chain to look at what we did in 2008 and 2009, and what kind of reductions we saw. We use those to triangulate a target for each of those production categories on what we think we can try and achieve in terms of spend. A lot of it depends on whether you're under active contract.
For example, you have deep water rigs, those are under longer term contracts, whereas land-based rigs tend to be 30-day sometime contracts and can roll over much more quickly. That's where you get the range, and what we're trying to do is through each category, define a range, go out, work with those vendors and suppliers to secure that. Where there's competition and we're not seeing the reductions that we think we should be able to achieve, we open those back up, and we'll go out and bid and re-tender to secure the current market price. Most vendors are looking for that long-term relationship with us, and we've been pretty successful working with them to find that, what I'd call first mover reduction. They're also going back and looking at their own supply chains and putting pressure further back up the line to bring down their costs.
As those costs down, that's a second and third order effect that we also would like to share in as we move forward. Obviously, that takes more time than that first mover reduction. When we talk about the efficiency, it's really hard to put a specific number on it, Ed, because it's all over the globe, literally. Some of the things that we're doing, in addition to what I talked about this morning, include, for example, we have under the i-field, the automation machinery support center. The machinery support center is a single location that we monitor over 1,500 pieces of major rotating equipment, whether they're compressors or generators.
We have one team of experts that can monitor this equipment using diagnostic software and helping to forecast failures, and then work with those business units around the world to help them monitor and understand where their equipment may be heading for a problem, either to avoid the problem altogether or to start the work in advance to be prepared when do we want to take this equipment down, when's the most expeditious time to do the repair or the adjustment. As we put a lot of these different systems in place, we're seeing that effect really start to build right into our cost structure.
The short follow-up is?
Cash margins are going to be an important part of monitoring what you guys have done, you've got a chart in here, and we can compare it versus last year and see if there are changes. The key is going to be when does Gorgon and Wheatstone hit the sort of peak cash margin that they're meant to contribute. I'm just wondering, is there any buildup in terms of initial costs and commissioning in terms of from first cargo, at what point should we expect to see the peak cash margin from, say, the first Gorgon project?
I think the answer is yes. There is a phase-in and a ramp-up as we build capacity. Jay, you want to talk a little bit about it? They were just down there reviewing the startup and commissioning work.
On a big project like Gorgon and Wheatstone, some of the operating costs even start now. Obviously there's no barrels to offset against, so you're very high on your operating costs, and it contributes to our overall cost structure. Once those projects begin operation and go through that ramp-up, and that ramp-up can be in the neighborhood of six months to get a train fully up to speed. When they're at full capacity, that's when you start seeing really good cash margins. Of course, it's going to also depend on where oil prices are and then how the market reacts to that. As well as we settle our operating organization down, we'll see what that steady state cost structure looks like over time.
Of course, you have three trains.
Yes.
Go ahead.
Paul Cheng, Barclays. Actually, I have two questions. One, John, for the next 12 to 18 months, cash preservation will be the number 1 priority for the organization, or that you are also looking at the opportunity set in the M&A, particularly in the North American shale oil, tight oil area. If it does, can you maybe describe how's the bid-ask market today from at least that Chevron standpoint? The second question is for Jay. Can you give us an update about Argentina, the shale oil joint venture? Is the initial commitment, the $1.8 billion, is it essentially that already used up, or that you still have some time to go before that you have to talk about the additional infusion of cash on that? Thank you.
Okay. Well, Paul, thanks. I gave my version of the cash story. Pat, you want to hear from the CFO also. Pat, you want to talk about our cash priorities over the next couple of years, then I'll go to Jay.
Well, it does all start with the dividend growth expectation we've got. That obviously is what we try to do over the long term. Secondarily, it's investing in good projects. I do think, right now, and we did show you the amount of capital that we've got committed in the 2015 time period, the 2016 time period, the 2017 time period, and obviously, our flexibility increases over that period of time. We always do look at M&A and look for opportunities that might be value accretive over time. We're not in a forced position at this point in time. We have a lot on our plate. We have a lot to execute. I would say our priority over the near term is execution-focused, getting these projects online and getting the earnings stream that we've got generated.
From a balance sheet perspective, there is more leeway for us to absorb something from an M&A standpoint, that is certainly not our priority.
Our priority is getting what we have on production. I will say we've been pretty targeted at some of the things we've done. For example, Jay went through this Keathley Canyon transaction. That was done pretty quietly, we acquired some barrels, we think, at a very competitive cost. You wouldn't think of it as big M&A, it was a resource acquisition that was relatively modest in size, it's not unlike what we did in the Permian Basin over the last couple of years, where we've picked up nice pieces of acreage. A big M&A is not something we certainly need to do right now and not my first priority. The second part of the question, Jay?
Argentina. Argentina, it's still I'd characterize as early in terms of the exploration, but we have now identified two sweet spots, and we're migrating the rigs into those two areas to focus on. We have started to see an uptick in our production coming from that area. At this point in time, we're still cautiously optimistic that the project's moving forward and looking attractive. As to where we are in the funding, I don't know exactly.
Just C&E at this point.
Yeah, it's just C&E at this point, and we're working through the initial funding that we provided to them.
Running 16 rigs at this point. Drilling horizontal wells?
Horizontal wells. We've moved from 19 to 16 rigs, which is kind of a steady state at this point in time in the two areas.
Sorry, Jay.
Follow-up. I think you got two already, go ahead.
I just want to make sure I understand that the cash that you initially committed is not run out yet.
The cash was split at the beginning, was a buy-in piece of it that. We've never really disclosed all the terms of that deal, I don't plan to do it today. We are funding the program on a C&E ongoing basis to fund the rigs. We're running 16 rigs in the development piece, we're doing some initial work. We've had some exploration adds to that area down there, which is, at this point, really just G&G kind of expenditures.
We have funded more than the original.
Absolutely.
If that's your question.
Yes.
Yes. Mm-hmm.
The buy-in.
Two very macro questions. Neil Mehta from Goldman Sachs. I want to leverage your five cycles of experience here to talk about the commodity and maybe first on oil. Can you talk about how this cycle is different with shale or not different from the 1980s, last time we had a supply-driven down cycle, and some of the cycles since then? If we surprise to the upside or to the downside relative to the $70 we used in the slide here today, where would that be? The second piece would be on natural gas, which I recognize is a smaller part of the business, but any thoughts and perspective on U.S. natural gas would be helpful.
Yeah, I'm glad you asked the question because we are old enough to have lived through these cycles, and there are some very big differences. I think it's worth spending a couple of minutes on it, because if you go back to the early '80s, I joined the company in 1980. We had come through a period in the '70s when oil was $2 or $3 a barrel, right? Prices rose through a variety of political events that I won't belabor, up to the $30 to $40 per barrel range. Well, the world economy was very energy inefficient, particularly the U.S. You had a shock to the system, prices rose, but consumption came down dramatically. It took time for energy efficiency to be built into the system. During that time, the only way to balance markets was for OPEC to dramatically cut production.
I mean, OPEC cut production 15 million barrels a day at one point. The Saudis went from nine to two during that period, and it opened up huge surplus capacity in the system. That's why I showed that one chart. It took over 20 years to work that capacity off. OPEC's production basically hasn't changed during that period. It went from, in the 30 million barrel a day range. It's still in the 30 million barrel a day range. The world market has gone from 60 to 90. Higher prices enabled and provided a supply response, so non-OPEC sources increased their production, and demand grew. You fast-forward a few years and get into the last decade, and you've seen a growing world economy, mostly China in the last decade, but well beyond China. We're continuing to see oil demand grow.
We saw another, if you want to call it shock to the system, where after that 20-25-year period of $20, where it would go down 50% and up 50% sometimes during that period, we went to another cycle where it came up near $100 a barrel, even to $145, and now down to $50. One big difference between then and now is it has not opened up a dramatic increase in spare capacity. We're only seeing 3 million barrels a day or so in spare capacity, and there's all the discussion about shale, which has mitigated some of the upside price concerns that were there, and it's been a wonderful application of technology. As we are out of balance now, shale is being tested and is one of the marginal sources of supply.
As you move forward over time, there are limitations to the growth that we'll see in shale. I think most forecasts, even with some of the optimism we're showing for the Permian elsewhere, at some point the steep declines take over. You move through the sweet spots, costs rise, and so it will not be the only source of incremental production. The U.S. is 10-12 million barrels a day on a 93-million-barrel base, we will need other sources of supply. In the near term, shale will be a bit of a buffer. If prices rise back to $70 or $75 a barrel, we'll see more production, we'll see rigs activated. We're also seeing a demand response during that period. We're seeing lots of pressures, even at $70 or $75.
There are lots of pressures for host governments out there in funding, you're seeing that take place, and that's true whether oil is at $50 or $70. You're going to continue to see those responses, and some classes of investments or some assets within some of the classes of investments will still be challenged at the $75 range. We can talk about hub class developments and where they might go, the point is there will be projects that will not be economic even at $70, $75, or $80. I hope that answers your general question. As far as the natural gas market, who wants to talk about that? George, you want to talk natural gas market?
It's not a good market in the U.S., just to be really blunt, $3 gas-
I give him the tough one
$3 gas is $18 oil in my view. It's hard to make a return there that really pays the cost of capital. I think for me, it's a learning that we've seen many times around the world. We really need to understand domestic gas, and I'd say domestic gas, wherever you're supplying domestic gas, and understand the risk of that investment relative to getting to an international market. When you're in an international market, you have the ability to get international set prices, and that's typically easy for us on the oil side. On the gas side, you can get in a regional market and be very price limited on what you can receive. This will have to change. The U.S. has been, North America, what we've seen on the shale, very well endowed. Very well endowed, at some point, economics have got to come into play.
John Herrlin, SocGen. Two quick ones. With the Permian slide, Jay, on all the efficiencies, I assume that's vertical and horizontal. How much time savings have you gotten on the horizontal side in terms of spud to tie-in, things like that?
We've really just started the horizontal developments. The Bradford Ranch was our first one in the Midland Basin with the horizontal wells. The first two wells, it'll just take some time to see how that works out as we move into that development. I'd expect to see us be very efficient with the horizontal wells. That's one of the areas we have a lot of expertise.
Okay, great. My second question regards CapEx. Is it fair to say for the intermediate term that your base and shale spending will be about 40% of total costs incurred for CapEx upstream?
I'm sorry, the shale and tight will be 40% of our capital?
Base.
Base.
Base and shale. 40% of your budget all together.
I would say I don't see a major shift in that at this point in time. I would see that being pretty stable through this time.
It's gone from 30 to 40.
Thanks. Ryan Todd at Deutsche Bank. I could ask a question on the deep water. I realize some of the deep water is challenged, there seems to be a view that deep water has completely fallen off the cost curve at this point. You guys have a relatively high and varied portfolio of deepwater assets in the coming years. Can you talk a little bit about what you're seeing, what maybe the current cost environment means for differentiation across your deepwater portfolio, what you're seeing on cost at this point, and maybe touch a little bit on the Keathley Canyon deal, what the current environment might mean for more creative opportunities in terms of developing the resource?
Yeah, it's a good question. I sort of baited you with that, talking about hub developments. Jay, you want to talk a little bit about deep water, what works, what doesn't?
Deep water, I know there's a lot of people don't believe in it right now at this price, it really comes down to, just like with any asset class, two things, the quality of the resource and the scale and size of the resource that you're looking at. In the lower tertiary, which is probably the more difficult area to develop because of the depth, if you have a hub that's in the 400 million-500 million barrel range, we see that as being effective even in the current price environment, kind of in that $60, $70 world. If you have a tieback, such as Buckskin now, where there's existing facilities that all you have to do is do the development and tie it back to an existing structure. That probably works more in the 1 million-200 million barrel range, will still be effective.
If you're in the Miocene, you probably need about 10% less resource than what you would have for the lower Tertiary. Will you want to pace these out and make sure they're effective and prepared? Yes. We do see them still working in the current environment, maybe a little bit higher than where we are today. I would also say that the technology is really key because it's the recovery that you can get out of those reservoirs and the certainty of that recovery that really makes a big difference when you're making an investment decision.
The work that we've done and the technologies that have been proven at Jack/St. Malo, for example, really give us confidence in terms of our ability to move into things like Keathley Canyon, where you now are bringing three or four fields into one host facility, reduces that investment risk, as I said, really increases the size of the resource, and also means that you can do less appraisal on each individual field, because collectively you've got a bigger pool to draw from when you decide to fund that host facility.
Great.
Okay.
Maybe just want to follow up on that in, I guess at this point, is it safe to say that the Gulf of Mexico has risen to be amongst the highest quality deepwater assets across your global portfolio? From an efficiency gain point of view, and maybe this is more of an issue for the breakout session, we talked a lot about efficiency gains in the U.S. onshore, do you think they're underappreciating the efficiency gains that you guys are seeing in the offshore portfolio as well?
Well, one of the reasons Jay really went through in some detail some of the technology changes that are happening is just for that very reason. In past meetings of this sort, we've talked about Jack/St. Malo as an example, where we felt the recoveries could go from 10%-20% over time with the application of technology. What he was talking about was some of those very things. There are other deepwater basins that have potential. I will say what gets funded is what is competitive, and what is competitive is also a function of fiscal terms. We're now seeing we've got infrastructure in the Gulf of Mexico, we've got fiscal terms that enable development. Around the world, that isn't always true. There certainly is. Just to be clear, there is plenty of resource around the world.
The issue is can it be developed, and fiscal terms is one of those key determinants. Let's go back in the middle here.
Hi, Phil Gresh, JPMorgan. Just following up on some earlier questions about the essentially 1% production growth target beyond 2017. How do you think about the sustainable CapEx budget to achieve that 1% production growth? Is it equal to this 2017 level? Obviously, there are some projects like TCO that could be pretty sizable. Just trying to get a general sense of how you think about where we're run rating on CapEx coming out of 2017 on a sustainability standpoint.
I think that's a good question. I'd say I think we probably have more work to do to get back to you on it. We haven't given capital forecasts beyond that. The point is, we'll be a bigger company at that time. We'll be producing over 3 million barrels a day, and you do have to sustain some level of spend to sustain production. We tend to be value driven, but we're in a very dynamic environment now in terms of cost. We haven't talked about EPC and other costs that are out there. You will need a level of spend to sustain the enterprise that, other things being equal, will be larger than when you were producing 2.5 million barrels a day. We're heading into a different cost environment.
I don't think I can give you good guidance on what that sustainable level of spend will be. I'm giving you an indication based on some of the early work that we're doing, that we think we can sustain 1% growth with a capital program that will enable us to generate free cash flow during that period. That will be unfolding over the next couple of years in this lower price environment. Go right next to you.
Thanks. Roger Read, Wells Fargo. Going back to the question on deepwater and kind of tying into the cost saves, on the, I think, third quarter call you mentioned rigs weren't really the cost issue, it was more the construction equipment or the construction-related part of it and some of the equipment. Can you give us an idea of what the timeframe maybe to get that under control is? You talked about delaying FIDs, and do we get the 10%-40%, and do we get it in this 25%+ of the pie as we look out to the 2016, well, maybe not 2016, but the 2017 and 2018 and beyond timeframe?
Yeah, I'll let Jay comment. You're right. One of the reasons we showed that chart is because you saw rig costs were only 6% of the total. It gets a lot of the attention, and it's an indicator, but there are other categories. You want to talk a little bit more about some of the other categories, maybe when the EPC market will get better, et cetera?
Yeah. We're working with, it starts with fabrication yards are a big part of your capital costs with these, particularly a new hub where you're putting a new facility out. Subsea costs, moving to better, higher levels of standardization on subsea equipment so that there's more interchangeability both between vendors and within our own system is another area that we're also working hard to bring those costs down. Even things like logistics and having a logistics support center so that we make most efficient use of our boats, aircraft, that can represent a very large part of your operating cost. It's really across the board in terms of how we go after these things. On our deepwater rigs, they tend to be longer term contracts, but they are staggered. We have six rigs, for example, in the Gulf of Mexico.
We stagger those ending periods so that we try and move with the market. That's our goal is to be in the market on those rigs.
Yes. I think this will be the last question for this session.
Okay, thank you. It's Blake Fernandez with Howard Weil. There's a lot of discussion today on cash margins, but when you factor in the DD&A component, return on capital employed can tell a bit of a different story. I guess the question is for one, do you see the LNG projects being accretive on an ROCE basis? Secondly, is that still an internal focus for the team?
Yeah. It's a fair point that the earnings contribution will vary considerably. The cash margin is a little bit easier to talk about. Depreciation rates can vary. For example, if you look at LNG projects, you typically can book a higher proportion of reserves early on, and we've done so. In the case of Gorgon and Wheatstone, they'll be nicely profitable even down at low prices. If you look at depreciation rates that we expect and OpEx, they'll be nicely profitable. Deepwater developments on a book basis, you tend to book the reserves over time. You can't book all the reserves early, your depreciation rates tend to be a little bit higher. Frankly, it varies considerably around the world.
If you look at earnings overall, for us and others, certainly in a low price environment, book earnings are hurt and therefore return on capital employed is hurt. That's true for us and everyone else in the business. The full effects of that will be seen in the first quarter, as you would expect. We've given you some rules of thumb in terms of what the impact on earnings will be from our current portfolio. For those that haven't followed that, it's per dollar is $350 million after tax. That does have a significant impact. Now, we do think that these projects are 20, 30, 40-year projects. They'll have good full-cycle returns over the course of that as measured by discounted cash flows.
The book returns can be highly variable depending upon how depreciation rolls through the income statement and the timing of how those costs come off the balance sheet in the statement. Okay. We're out of time for this session. I'd like to thank you very much for your time and attention. That concludes the webcast.