Good morning, welcome to Chevron's 2014 Security Analyst Meeting. I'm Jeff Gustafson, the General Manager of Investor Relations. It's great to have you here with us today. I also like to welcome those of you joining us 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 St. Regis 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 will provide a comprehensive update on Chevron.
We'll begin with both corporate and financial overviews, followed by more extensive discussions about our primary business segments, namely Downstream and Chemicals, and of course, our Upstream business. Our agenda features presentations by our Chairman and Chief Executive Officer, John Watson, our Vice President and Chief Financial Officer, Pat Yarrington, the Executive Vice President of Downstream and Chemicals, Mike Wirth, the Vice Chairman and Executive Vice President of Upstream, George Kirkland, and Jay Johnson, Senior Vice President of Upstream. At the conclusion of Mike's segment, we'll take a short break. We also have plenty of time for questions later in the program. Other executives with us here today include Rhonda Zygocki, the Executive Vice President of Policy and Planning, and Steve Green, our Vice President of Policy, Government, and Public Affairs. For those joining via webcast, I'd like to invite you to participate in the Q&A segment.
Please submit your questions to us 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 the appendix of your booklets and on our website. Thank you for your attention. I'd now like to introduce our Chairman and Chief Executive Officer, John Watson.
All right. Thanks, Jeff. Good morning. I'd like to welcome everyone to Chevron's 2014 Security Analyst Meeting, including those of you listening via webcast. We're looking forward to providing you information about our performance, our strategies, and the outlook for our business, as well as answering your questions. Let me start by highlighting some of the key messages we plan to convey this morning. First, world energy demand continues to grow, crude oil and natural gas will remain vital in meeting that need. Satisfying demand growth is a great business opportunity for us, there are costs and other challenges. Second, our strategies remain consistent and are well-aligned with these macro realities. We remain focused on execution, both in our base business and major capital projects. Third, we have a strong portfolio with industry-leading financial and operating performance.
We're poised to deliver significant growth in production to the end of the decade. This should serve as a catalyst for shareholder value creation between now and then. I'd like to start today by highlighting our personal and process safety performance. We had just 58 injuries that required a day away from work all year, or 0.02 per 200,000 hours worked. This is remarkable given that we have over 250,000 employees and contractors working on our sites each day. They logged some 590 million hours of work. We continue to lead the industry. We also remain focused on process safety. Simply put, this is keeping hydrocarbons in the pipes and vessels designed to contain them. Last year, I highlighted spill volumes. We're still world-class on that metric.
This year, I'm showing the industry standard measure Tier 1 loss of containment performance, which includes oil and gas releases that result in spills, fires, and other incidents. We're not yet where we want to be. We are improving. Let's move on to the macro environment. Economic growth requires affordable energy. Here in the U.S., the shale boom has boosted supplies, lowered prices for consumers. It aided job growth. It has greatly contributed to this country's economic recovery. It made the U.S. the envy of countries around the world. With a growing global population and more disposable income, people will consume more energy. By 2030, global energy demand is expected to grow by about a third or 2% per year. Oil and natural gas is projected to make up over half of total energy demand for the foreseeable future because it's affordable and readily available to consumers.
Renewables such as wind, solar, and biofuels will contribute more. Increasingly, we're seeing policymakers taking a close look at the cost of their renewables programs. The continuing industry challenge is to provide the energy the world needs in an affordable manner. Let's look at the supply challenge in greater detail. This chart compares future demand projections for crude oil to the existing supply. Industry production, shown in dark blue, declines about 15% per year without reinvestment. With reinvestment in existing fields, base business infill drilling and workovers can reduce the decline to 4%-5% per year. Base business reinvestment alone will not satisfy future demand requirements. Continued exploration and industry investment in new fields is needed. We estimate that over 200 billion barrels of base business projects and new field production will be needed by 2030 to meet demand.
These new energy sources are from increasingly complex fields and locations with notable geological, technical, and geopolitical hurdles. It will require enormous investment in both people and capital to meet demand. We estimate $7 trillion-$10 trillion will be required in this period, or over $500 billion per year. Let's take a closer look at the cost side of the equation. We believe oil prices reflect the marginal cost of supply plus a premium that can vary over time for uncertainty and instability in supplies. This chart illustrates the sources of new supply and the range of cost to bring those supplies to market according to Wood Mackenzie. Supply sourced from OPEC, primarily in the Middle East, will continue to be the lowest cost source available. These countries clearly remain critical to meeting future world demand.
Less conventional production sources, such as deep and ultra-deep water, shale and tight resources, and oil sands are growing in importance. In fact, these sources represent the majority of near-term developments to the end of the decade. While we can debate the specifics about the range, there is little debate that the break-even prices at the margin are increasing and approaching $100 per barrel or more. The quest to meet the demand wedge of the last decade resulted in higher prices. Higher prices created incentive to find and develop oil resources, putting upward pressure on the cost of oil fields, goods, and services. The chart on the left shows industry costs more than doubled in the last decade, with only a short break for the world financial crisis. Contractors and suppliers that provide critical goods and services continue to have backlogs.
The chart on the right shows the backlog in four key areas. Add in tight local labor markets, civil unrest, and other risks, the challenge to our industry to meet demand is great. Chevron has responded to these conditions in many ways. Notably, we've instituted much greater contractor and supplier oversight into our project management system. We've also said no when costs get out of line. The Rosebank project is one example where a good oil resource development is being slowed to improve the expected economic return. Stressed projects will be enabled by lower costs, better fiscal and other conditions, or they won't happen. If enough projects are deferred, prices rise. This is how markets work. Growing world demand, inexorable decline curve and replacement cost realities, and traditional oil geopolitics make us bullish on oil. Let's move on to LNG.
This chart shows anticipated demand growth and sources of new supply. Demand for LNG is expected to double by 2025. Most of this growth will occur in Asia, primarily China and India, but other customers are entering the market. There are now 29 countries purchasing LNG. On the supply side, we see a big opportunity, well over 100 million tons of new LNG to meet demand by 2025. This opportunity is on top of supply that will come from the four sources already considered in the bar on the chart. That's existing supply, international and U.S. projects under construction, and other probable U.S. projects. The scale of investment required for greenfield LNG projects to meet this demand is significant. Buyers and sellers will need to work together to find a value proposition that works for both.
Sellers need a revenue stream that supports an economic investment, buyers need reliable supply that is priced competitively with their alternatives. What's worked for U.S. projects reflects unique circumstances, low cost resource, existing pipelines, and brownfield sites. A different value proposition will be required to enable the next wave of greenfield projects. To sum up my view on markets, we believe the world economy will continue to grow, energy demand will grow with it. There is underlying strength in the oil markets resulting from inevitable field declines, and in LNG markets from significant demand growth. It is a great business environment for my company. Our success has been driven by very consistent strategies. They are essentially unchanged from last year and remain appropriate for the macro realities I've just described.
Our upstream is growing profitably and is focused on building legacy assets, primarily associated with crude oil and LNG. Our downstream and chemicals business has improved returns and is pursuing selective growth opportunities in higher return sectors. Our gas, midstream, and technology organizations support the upstream and downstream businesses in meeting their objectives. Finally, we are selectively committing resources to renewables and energy efficiency initiatives. We focus on growing value consistent with our strategies. Our business requires disciplined investment decisions as we have many choices of owned and available opportunities. In the upstream, it starts with the rocks. For new assets, we look for high-quality resource with attractive fiscal terms and the potential to be of scale. We favor early entry, where we can apply our proprietary technology and capabilities over time. We are value-driven. We apply standard investment criteria to new and owned opportunities using discounted cash flows.
We use probabilistic tools that consider a range of outcomes and risks, including those listed on the chart. We set the overall spending level at the corporate center to deliver a balance of current return to shareholders via dividend and long-term value growth via investment. We keep spare capacity on the balance sheet to mitigate risk of commodity prices and other factors. Most of our investment dollars go to the upstream, as this is where we feel returns are best. Downstream investments are more limited, generally geared toward reliability and maintenance in our refineries and petrochemical projects. We sell assets early in life if they can't make our economic hurdles or late in life when they lack materiality and may compete better for forward investment with another owner. Selling mid-life assets is generally not favored, as this is when we can add value best, applying our technology and know-how.
Our strategies, investment approach, and funding decisions have provided us with a superb portfolio of developed assets and new opportunities. We're predominantly an upstream company. Within the upstream, we remain weighted to oil and oil-linked pricing projects going forward. Our developments are increasingly legacy type in nature. These assets are typically plant, not resource-constrained, with flatter decline rates and long-lived cash flow profiles. Many have future expansion potential. We're also well-diversified geographically, with a high proportion of current investments going to Asia and North America. Let me shift to financial performance, where our strong portfolio continued to generate peer-leading results. 2013 was a solid year for the company. We posted earnings of $21 billion and achieved a return on capital employed of 13.5%. Strong earnings and cash flows supported a sizable increase in the dividend, our 26th consecutive annual increase.
We also repurchased $5 billion of our shares and funded a $42 billion capital program that includes $4 billion in new unconventional opportunities and exploration. I'm very pleased with our shale and tight formation additions in the Permian, Duvernay, Liard, and Horn River assets in North America, Cooper Basin in Australia, and Vaca Muerta in Argentina. I also like the conventional acreage we picked up in the Kurdistan region of Iraq. As I indicated last year, we're returning our balance sheet to a more traditional AA structure, though it remains pristine. Our strong earnings have been a function of our portfolio and investment choices. We continue to invest wisely in order to profitably grow our business. We've demonstrated the ability to invest for superior growth while remaining very competitive on ROCE. We're second in the peer group despite significant work-in-progress capital on the books.
We're competitive on this measure not only against our largest integrated peers, but also relative to large independents, shown by the green line on this chart. We also think it's important to grow our earnings per share over time. We continue to lead our peers on this index rolling five-year EPS measure. We believe growing the numerator is key to our leadership on this metric. As we ramp up production over the next few years, we believe the outlook for maintaining this leadership is good. With leading performance in operating and financial metrics, it should come as no surprise that we continue to lead in total shareholder return as well. This is the fifth consecutive year we've led our peer group in the trailing five-year TSR. We also lead the peer group and the S&P 500 in 10-year TSR.
If I updated these five and 10-year rankings through yesterday's closing prices, you would see we still lead our competitors. There are two specific topics related to our plans that I would like to address, production growth targets and capital spending. In early 2010, we set a target to grow upstream production to 3.3 million barrels of oil and gas equivalent per day by 2017. We had confidence in putting out this target because we knew we had a strong queue of opportunities that would compete well for capital. We had just taken FID on Gorgon, and we expected Jack/St. Malo, Wheatstone, and others would soon follow. Our growth strategy remains intact, though some things have changed. Oil prices are higher and U.S. gas prices lower than we expected, and we've made some portfolio choices that now impact our outlook for 2017.
Our expectation for 2017 production is now 3.1 million barrels per day, up 20% from 2013, with more growth through the rest of the decade. There are 4 categories of impacts that explain the change from 3.3 projected last year to 3.1 this year. First, higher oil prices reduce cost reimbursement and other entitlement barrels in some contracts. We've moved our assumed oil price from $79 per barrel first assumed in 2011 to $110 per barrel that it has averaged over the last three years. Of course, the overall earnings impact of higher prices is positive. Second, as a result of continued low gas prices in the U.S., we've slowed the pace of our investments in the Marcellus and extended the time period of our financial carry. This is a value-based decision that reduces production through 2017.
Third, we'll be selling more assets than originally planned. We expect total company asset sale proceeds of $10 billion over the next three years, most of which will occur in the upstream. Finally, the net effect of portfolio additions, project deferrals, and project slippage has had a small impact overall. We are also including an allowance for unknown events. In December, we released our 2014 capital and exploratory budget of $39.8 billion. This represents about a $2 billion reduction from 2013 spending. We've indicated 2013 represents a relative peak in total spending, and 2014 represents a peak for LNG project spend at approximately $10 billion, mostly on Gorgon and Wheatstone. We've also indicated we expect C&E spending to flatten over the next few years, and I expect that to be the case through 2016.
Spending in 2017 and beyond will be a function of project approvals and the cost and price environment. I do expect our pre-productive capital intensity to decline significantly as we move forward. We've been asked why our spending does not decline after the Gorgon and Wheatstone peak, and the answer is straightforward. Because spending on projects like the Tengiz expansion, Permian tight oil play, and Gulf Coast petrochemical complex are ramping up. These investments are a very good use of funds. You'll hear much more about production, financials, and projects from Pat, Mike, George, and Jay later this morning. Before we get started, let me remind you of some important organizational changes that took place effective January 1. Jay Johnson now has responsibility for our upstream operating units. Joe Geagea has responsibility for key technical support and service organizations that serve upstream, downstream, and midstream businesses.
Pierre Breber now runs our gas and midstream business. Longtime followers of our company know these individuals well. Jay and Joe report to George. When George retires later next year, they will report to me. Other key executive positions, including Mike and Pat, have not changed. I have a very good team. Let's get started with more details from Pat on financials.
Good morning, everyone, and thank you, John. It's nice to see you all here again. This year, I'll be covering our capital plans and specifically what they deliver from a competitive standpoint. I'll offer some guidance on asset sales and capital intensity. I'll also review our balance sheet and offer insights on how we use our financial strength. Finally, I'll close with the all-important value proposition, highlighting the growth in operating cash flows that will result from our investments and the support they provide for enterprise value growth and future shareholder distributions. Our focus is on managing the business to generate strong returns and healthy cash margins. These lead to competitive distributions and also enable reinvestment for future growth. Here's a simple depiction of what matters in our business, the investment cycle. It all starts at the top by having a high-quality project queue.
A strong queue allows us to be selective and disciplined in our investments. It means that projects compete internally for capital and that not all projects are funded. The best investments produce strong earnings and cash margins, which in turn sustain a strong balance sheet. They also allow us to amply reward shareholders through both share price appreciation and distributions. We've delivered. We have created the top quality queue in the industry. We have generated the highest cash and earnings margins. We have maintained a strong balance sheet and rewarded our shareholders. We've been reinvesting to revitalize the queue, which supports continued value growth. Let's look in more detail at our investment priorities over the next three years. We're anticipating C&E outlays of around $40 billion for each of these years. On the left is spending by region.
Our outlays continue to be geographically diverse, with weighting towards Asia and North America. Our investments in Asia include the Gorgon and Wheatstone LNG projects. We expect peak LNG spending will occur this year and then decline as these two projects move towards first production. North America is expected to capture a growing portion of our near-term investments, including the Gulf of Mexico, the Permian, and Canada. On the right is spending by category. Upstream accounts for almost 90% of the total, while downstream and chemicals account for about 8%. Over the 3 years, almost 60% of our capital program is dedicated to major capital projects for upstream, principally LNG, deepwater, and shale and tight resource projects that fuel our future growth. Base business outlays are projected to be just over 30% of our total spending, with shale and tight resources comprising about 11%.
Having a strong investment profile is a good thing if it's being invested wisely. That's how we create shareholder value. On the left, I show our reinvestment ratio, the proportion of cash from operations put back into the business. On a historical basis, we continue to be only mid-pack in terms of reinvestment rate. Going forward, as cash from operations increases and as capital spending levels out, we see this ratio decreasing steadily over the next several years. On the right is what our average reinvestment profile is expected to generate for investors, the strongest production growth in the peer group over the medium term per Wood Mackenzie out to the end of the decade. Saying it another way, this is a key differentiator, we offer notably stronger production growth per reinvestment dollar than the peer group. Portfolio rationalization is another important element of capital discipline.
Looking back 3 years, our asset divestment proceeds have totaled around $7 billion, coming largely from our midstream and our downstream operations. Looking ahead the next 3 years, we expect proceeds from divestments to increase to about $10 billion overall. These divestments will be more focused in our upstream operations, George will elaborate more fully about this later this morning. This is a routine evaluation for us, identifying assets that either do not currently or will not in the future compete as effectively for capital against other assets in our portfolio. They are value-based decisions that take into account the life cycle of the asset. We have assets already identified as potential sale candidates, we generally do not preannounce these for obvious commercial reasons. The outcomes here, in terms of timing and eventual proceeds, will be driven by one thing, the ability to capture good value.
We've been able to invest heavily for growth and at the same time remain very competitive on returns. Our recent returns reflect a high proportion of pre-productive capital, as you see on the far left. We anticipate pre-productive capital decreasing noticeably in each of the next 3 years as several of our large flagship projects come online and as capital spending evens out. This chart shows the growth in our cash flow per share indexed to 2008. For the last 4 years, we've led the peer group. Our cash flow per share has grown by 25% over the last 5 years, while most peers have declined. Our past investments have delivered high-value growth that took advantage of a strong oil price environment. These investments are now substantial cash generators. We're poised to repeat this cycle as our current slate of projects come online.
At the same time we're investing for the future, we're also rewarding our shareholders today. For several years now, we've had superior dividend growth. We've increased the dividend at a compound annual rate of nearly 11% over the past 10 years. This is the best in the peer group and almost 50% better than the S&P 500. Since 2004, when we first initiated a share repurchase program, we've had $40 billion of buybacks, resulting in a net 11% reduction in shares outstanding. We work to achieve the right balance between what's returned to shareholders and what's reinvested in the business. We've had superior three-year, five-year, and 10-year total shareholder returns, which validate our cash use decisions. At slightly under 6%, our current distribution yield is very competitive. In the past, I've discussed our commitment to maintain our double-A credit rating.
I've also discussed our view of the balance sheet as a risk mitigator and as a tool to both weather and take advantage of unforeseen circumstances and opportunities. These objectives remain intact. As we said we would, we moved towards a more traditional capital structure in 2013. We expect that trend to continue. We levered up modestly last year, ending the year with a debt ratio of 12%. We're in a very sound position to fund competitive and growing shareholder distributions, along with our capital program. This outcome is fully consistent with our previous guidance on our financial priorities. Our first priority is to maintain and grow our dividend. We're doing this. Our second priority is reinvesting in the business to give our shareholders a stake in a growing and more valuable enterprise. Our third priority is to maintain our financial strength and flexibility. Our balance sheet remains robust.
Finally, we're committed to returning additional available cash to our shareholders. We've done this in most years of the last decade. We've consistently applied these priorities. We've sensibly balanced these objectives over time. I see this consistency of approach and outcome continuing in the future. Last March, I highlighted the significant growth in cash generation that we expected. That expectation hasn't changed. Assuming $110 average Brent price, our operating cash flows are expected to exceed $50 billion in 2017. In fact, we see cash generation growth well beyond that, as indicated here by the blue arrow. Cash C&E in 2017 and beyond is hard to predict with any degree of certainty. Many elements will come into play. For example, commodity prices, supporting a larger base business, the precise timing of project developments, and of course, industry cost levels.
While it is hard to precisely know the angle for each of these arrows, I do feel confident saying the gap between the two, or our free cash flow, is expected to widen over time. The projects we're investing in, both upstream and downstream, are attractive. We believe they will be accretive to our current cash margins, making our portfolio in 2017 a stronger cash-generating portfolio than today's. We expect our current investments will lead to further share price appreciation and will also enhance our ability to sustain and grow shareholder distributions in the years to come. I'd like to now turn the podium over to Mike to discuss our downstream and chemicals business.
Thank you, Pat, and good morning. It's a pleasure to see everyone again and to discuss Chevron's downstream and chemicals business. I'll begin with an overview of our portfolio and our advantaged positions. The pie charts in the center panel show how we plan to change our capital employed over the next three years. We continue to shift our portfolio toward the higher return lubricants and chemical segments with less relative exposure to R&M outside of Asia Pacific. In chemicals, our olefins business has access to advantaged feedstocks in North America and the Middle East. Our aromatics business has easy access to the growing North Asia market. Our refining assets are concentrated around the Pacific Rim, where we have more than three-quarters of our total capacity and the top hydrocracking position. This sets us up well for future demand growth, particularly for diesel and jet fuel.
Moving to strategy, my message is unchanged. We're focused on delivering competitive returns and growing earnings. Our supporting strategies of operational excellence, growth in the higher return segments, a focused R&M portfolio, and integration with our upstream business are the foundation of everything we do. I'll expand on the first three items in that list throughout my presentation. I'd like to take a minute to talk about the fourth, integration with upstream. We routinely run equity crews in El Segundo, Pascagoula, Salt Lake City, and several refineries in Asia. Beyond that, we support upstream with both people and technology, supporting commissioning, startup, turnarounds, and operations. We have refining experts in Nigeria, Angola, Kazakhstan, Venezuela, Australia, and other upstream units around the world. We're committed to delivering competitive returns within the segment and also adding value to our upstream. I'll break the rest of my comments today into three sections.
First, I'll review the downstream business environment and market fundamentals. I'll cover our performance in 2013, and I'll close with a discussion about our plans for growth. The demand picture hasn't changed much since last year. The fundamentals underlying our business reflect the realities of the global economy. On the left-hand charts, you can see that petrochemicals and lubricants are expected to experience strong demand growth for quite some time. On the right-hand charts, the outlook for fuels is positive but less bullish. We've eliminated our exposure to Europe, where margins are under the most pressure, and we like our position in Asia, where we'll see the most demand growth for all products. Drilling down a level, changing feedstock dynamics are reshaping the landscape here in North America, driving down the cost of raw materials. The left-hand chart shows ethylene cash costs by feedstock and region since 2008.
The Middle East continues to lead, with North America gas-based crackers now a close second. Both have a significant advantage over naphtha-based plants in Asia. Our ethylene portfolio is positioned entirely in the two most attractive regions. The right-hand chart illustrates one external view of how North America production growth continues to impact crude price differentials. Over the last few years, discounted crude pricing has primarily benefited mid-continent refiners. As infrastructure brings more supply to the Gulf Coast, other grades are also beginning to discount to Brent, illustrated here by LLS. As this effect moves into the market, we'll see better crude opportunities at our large coastal facilities. Both these trends benefit our downstream and chemicals business. I'd also like to make a few comments about the regulatory environment. Over the last half-century, we've experienced a steadily evolving landscape of new regulations.
When first introduced, these rules tend to create uncertainty. In time, markets and companies adapt, and the stronger competitors succeed. The most recent chapter in this story is driven by concerns about climate change. The same pattern of adaptation and adjustment has begun. At the federal level, EPA has proposed lower blending targets. We're starting to see the acknowledgment that the RFS is flawed and should be repealed or reformed. In California, we're earlier in the implementation process than at the federal level. Some of the same realities are beginning to emerge. The Air Board intends to make modifications to the LCFS. Key policymakers are concerned about keeping California competitive. While it's a little early to predict exactly how the regulations will evolve, I expect they will, as consumers, businesses, and economics will demand it.
With our strong portfolio and decades of experience in adapting and succeeding in this kind of an environment, I'm confident we'll meet these challenges, just like we always have. Let's look at performance. 2013 was different than the recent past, both for our competitors and for Chevron. The entire industry experienced a retrenchment of earnings and returns last year. At $1.25, R&M earnings per barrel are number 2 among our peers. We delivered a 10% return on capital employed, which we expect to also rank number 2 when the final 2013 capital employed data is available. While industry results trended downward, we maintained the relative gains we've seen over the last few years. I'd also like to talk about petrochemical financials. Chevron Phillips Chemical, or CPChem, is the largest private-sector petrochemical producer in the Middle East. The largest producer of high-density polyethylene in the world.
CPChem has delivered peer-leading cash returns for multiple years now. A key element of this performance has been outstanding reliability, as evidenced by their utilization rate, which has been well above the industry average over the last three years. CPChem also has efficiency, proprietary technology, and scale. With 100% of their ethylene capacity in the feedstock-advantaged regions of the Middle East and North America, this is a formula for excellent financial results today and well into the future. Reliability is a top priority across all our business segments. For the 3 biennial Solomon surveys beginning in 2006, Chevron ranked number 1 in refinery utilization. In the latest survey period for 2012, we operated at nearly the same level as our industry-leading performance in 2010. However, we slipped to number 2 due to the impact of the August 2012 fire at Richmond.
In 2013, utilization declined further, primarily due to the timing of the Richmond restart. Since then, we're back on track, as evidenced by our second-half 2013 utilization of more than 84%, shown by the yellow dot on the chart. We finished last year strongly and carried good momentum into 2014. Top-tier reliability remains essential to our operations and the key to profitability. We've redoubled our focus on specific initiatives to further improve reliability and turnaround execution. In the past, I've explained how we've created a more focused refining and marketing portfolio in geographies with more attractive underlying fundamentals. Our marketing business flows primarily through independent distributors and retailers. This keeps capital and operating costs low and puts a premium on strong brands. In the Americas, our Chevron and Texaco brands anchor our refinery output. Chevron commands the highest brand premium of any American gasoline brand.
We hold the number one market share in our core market of five Western states. In 2013, we saw sales increase nearly 5% in a market that was up less than 1%. We expect similar results in Asia Pacific, where the Caltex brand has been a star for more than 75 years. Initiatives to optimize station ownership and locations are targeted to increase market effectiveness 11% over the next four years. We'll continue to keep our product quality high and our brands strong. Now let's talk about portfolio. While we've done a lot over the last several years, we're not finished. We continue to divest non-strategic assets. Last year, we completed sales of a pipeline and terminal system in the Northwestern U.S., a terminal and retail network in Florida, and our Romania and Czech Republic lubricants businesses.
Over the last decade, we generated more than $12 billion as a result of portfolio actions. Yesterday, we closed the sale of our fuels business in Egypt. We expect to close on the sale of Pakistan this year, and we've got a number of midstream assets we expect to sell this year and next. Now turning to the future. I'll summarize our plans for targeted growth in key segments and what you can expect to see over the next few years. I'll start with chemicals and our advantaged portfolio. CPChem will start up the world's largest on-purpose 1-hexene plant in Texas this year. They're in a first-mover position on a world-scale ethane cracker and derivatives units on the Gulf Coast and are the only company holding approved permits to start construction.
By 2017, CPChem's olefin and polyolefin capacity will increase 32% to more than 10 million tons per year. In Asia, GS Caltex's Yeosu complex is one of the largest single-site aromatics facilities in the world. They're planning to expand this capacity by 35% over the same time period, contingent upon project economics and the ability to fund internally to serve the expanding North Asia market. Both our olefins and aromatics businesses have robust growth plans centered on world-scale facilities and are well-positioned to deliver profitable growth. Now let's move to lubricants and specialty chemicals. Chevron's portfolio in these higher-margin businesses is unique. We're the only major oil company with a wholly owned additive business, a leading premium base oil position, and top-tier technology in high-growth segments like heavy-duty engine oils. Premium base oils are exceptionally low in sulfur and aromatics and offer significant performance advantages.
We're nearing completion of the Pascagoula project, which will increase our capacity more than 70% and make Chevron the largest producer of premium base oil in the world. Oronite is a leading producer of specialty chemical additives and has world-scale manufacturing plants and technology centers in all key demand regions. This year, our Singapore plant, already the largest in Asia, is expected to more than double its initial capacity with the completion of a major expansion project. We're also increasing capacity in France. Oronite's production capacity is scheduled to expand 20% by 2017, in line with anticipated global demand growth. Here's a summary of our major capital projects. CPChem plans to start up the new hexene plant this year and is targeting 2017 for their new ethylene and derivative units. Pascagoula base oil should reach mechanical completion in the next few weeks and be at full production by mid-year.
Oronite's expansions in France and Singapore are slated to come online in phases beginning this year, and a new paraxylene unit in Korea is expected to be complete by the end of 2017. These projects are in the right location with advantaged feedstock or market access, and all of them leverage our existing asset base, technologies, and partner relationships to drive future earnings growth. To close, I'd like to summarize three points. First, our strategy is sound. We'll deliver competitive returns through executing the fundamentals in our base business with a smart and focused portfolio and assets that have the scale, flexibility, and configuration to be competitive. Second, safety and reliability are the foundation of everything we do. We're committed to further strengthen our performance in these areas, which enables superior profitability.
Finally, we're investing in the right growth projects targeted in the right markets and segments to strengthen and diversify earnings and sustainably deliver top-tier competitive results. That concludes my remarks. We'll now take the 15-minute break. Please remember to take your badges with you so you can get back in. See you in 15 minutes.
Ladies and gentlemen, please take your seats. We're ready to begin the program. Thank you.
Good morning. It's my pleasure to once again review with you Chevron's upstream business. Today, I'll provide insights on our 2013 performance, our industry-leading portfolio, and with Jay, cover our tremendous growth story. First, an overview of Chevron's upstream portfolio. Chevron has a diverse upstream portfolio with production in 26 countries and in nearly all of the world's key hydrocarbon basins. Our upstream assets are managed through four regional operating companies and 15 business units. Our 2013 production was almost equally distributed among our operating companies. With our anticipated 2017 production growth, our production distribution will change. Our Asia Pacific region's production is forecasted to increase by over 300,000 barrels per day, driven by our Australian LNG projects. North American production is expected to grow significantly through the Deepwater Gulf of Mexico additions and by increases in our shale and tight production.
Production growth beyond 2017 will be heavily influenced by the large Tengiz expansion projects, and this region should show considerable growth in the 2018 to 2020 period. Our strategies have been constant for over a decade. We're pursuing profitable growth in existing operating areas while building new global legacy positions. These strategies are all about creating value. Consistent execution on these strategies has yielded industry-leading financial results with an unmatched growth profile through this decade. Today, we'll be focusing on three themes: performance, portfolio, and growth. Let's begin with our 2013 performance. In 2013, net production was approximately 2.6 million barrels per day. Our base operations delivered strong performance with a decline rate of less than 3%, and shale and tight production grew by more than 15%.
Our lower-than-planned production growth for major capital projects was predominantly related to startup and ramp-up delays at Angola LNG and, to a lesser extent, Usan in Nigeria. Overall, we achieved 98% of our guidance and are well-positioned for continued growth. Next, I'll cover our 2017 production target. When we first announced our production target in 2010, we specifically tied the target to a price: $62 per barrel. A year later, we reaffirmed our target at $79 and absorbed the price impact on production. Since then, oil prices have moved up significantly, and Brent prices have averaged approximately $110 per barrel over the last three years. We are now updating our 2017 production target, assuming a price of $110 a barrel. Yes, this higher price reduces our 2017 outlook by about 55,000 barrels per day. As you know, the positive financial impact of higher prices overwhelms this volume loss.
Since our March 2013 analyst meeting, we decided to further reduce and defer investments in U.S. natural gas due to market conditions. We're slowing our Marcellus drilling, which reduces our production growth by 45,000 barrels per day. We made similar decisions in 2011 and 2012 when we deferred planned investments in the Piceance and Haynesville. Recently, we decided to accelerate the sale of some assets that we had planned to hold. The effect of the increased asset sales on our 2017 target is estimated at 35,000 barrels per day. We've also made some valuable additions to enhance our portfolio. The Delaware Basin and Argentine assets have added 35,000 barrels per day to our 2017 forecast. Delays at Shandong Bay and the remainder of Tengizchevroil future growth production have moved almost 50,000 barrels per day of growth beyond 2017.
The changes I've just covered would result in a forecast of 3.15 million barrels per day in 2017. Predicting production levels closer than a percent or two is difficult. U.S. gas investments, greater asset sales, or market conditions would impact production. For this reason, we have included a future uncertainty allowance of 50,000 barrels per day. As John stated, our forecast is now 3.1 million barrels per day at $110 Brent price, a 20% increase in production relative to 2013. Now we'll look at our performance in exploration, resource additions, and reserves. WoodMac data shows that Chevron is the leader in exploration resource replacement over the last 10 years, and in the top tier of our peer group in cost. Our assessment is we've discovered 10 billion barrels of resource over this period.
Our 10-year well exploration success rate of 56% is truly outstanding. In 2013, we achieved a 59% success rate and added almost 1 billion barrels of resource. The map shows the location of the key 2013 exploration additions. We had great success in North America shale and tight resources. Our strongest resource adds came from the Permian. We announced our success in the Duvernay in Canada. Also had good results in the Marcellus and Utica. We expanded our long list of Australian discoveries with the Satyr and Kentish Knock wells. We drilled successful wells in the Gulf of Mexico, Thailand, Angola, the North Sea, and in the Partitioned Zone. The barrels added in 2013 are in attractive fiscal regimes. I'll cover resources and then reserves. Let's start with a long-term view.
Over 5 years, we produced almost 5 billion barrels, divested over 2 billion. All of that was offset by over 12 billion in unrisked resource additions from our resource factory of exploration, business development, and organic growth through technology application. Our resource replenishment is strong over one, three, and five years. 2013 was a particularly good year, with significant additions related to Kitimat, the Duvernay, and the Delaware Basin. Let's look at proved reserves. One-year reserves replacement ratios can be variable, as the reserves associated with major capital projects reaching FID is a significant factor. In 2013, we added over 800 million barrels of proved reserves for a replacement ratio of 85%. Over the last three years, Chevron has delivered 123% reserve replacement and 100% over 5 years. Let's review our financial performance. In 2013, we delivered leading realizations among our competitors.
We hold more than a $1 a barrel advantage over our closest IOC competitor and an average of $10 over a large group of E&P and integrated companies. Our 70% oil-weighted portfolio provides us a significant advantage. Last year, our upstream costs were $32.93 per barrel, approximately $1 higher than 2012 due to increased subsurface labor costs and higher DD&A. Our competitive upstream cost structure is notable since higher operating costs are generally associated with oil operations. Our ability to deliver leading realizations and a competitive cost structure has led to the highest earnings margins in the industry. Once again, our earnings per barrel performance leads the competition at nearly $23. That is over $5 a barrel above our nearest competitor and our 18th quarter with leading performance. Also outperform the other large E&Ps and integrated companies by over $9 per barrel on average.
We have had the highest ROCE in the upstream sector since 2011. Our 17.2% ROCE in 2013 is industry-leading. In summary, we are delivering leading financial results as we grow our resources and production. Let's take a closer look at the Chevron portfolio and how we manage it to drive this leading performance. As you can see, in 2004, Chevron's earnings per barrel were at the competitive average. Through our consistent value-focused investments in our base business and major capital projects, we are outpacing all of our peers by a large margin. These industry-leading results flow from our differentiated portfolio and our sound decision-making. Managing and growing a portfolio requires a long-term view. I'd like now to review the components that feed our future production and value growth. We begin with the resource opportunities.
They come from exploration, acquisitions, and our ability to increase recovery from our existing portfolio through technology. Success in these areas grows our overall resource base. The consistency of our evaluation process is key to identify and develop the most economic opportunities. Initial reserves are generally recognized when we reach our final investment decision. Reserves then move to production and revenue generation and have completed their path through the resource factory. It is imperative that we continue to replenish our queue and feed the future with high-value projects. Next, I'll cover more on how we manage these resources to production. Let's start with our base business. Investing in our base assets is a key part of portfolio management. Through these efforts, our portfolio's natural decline rate of 14% has been reduced to 3%. We've had great success and are now revising our guidance from 4% to 3%.
Our base investments, including shale and tight, generally target lower-risk developments and have a short cycle time to production. This investment category generally returns over 50%. As major capital projects move into the base, additional high-return investments become available. Next, I'll cover how we manage our assets through their life cycle. Prioritization of the portfolio is done by evaluating discretionary funding. We look at the economic ranking of our opportunities and select the investments considering subsurface and surface risk and, of course, economic reward. Assets that don't presently compete for capital are either deferred, recycled, or divested. These divestments occur early or late in the production life cycle. Examples of these early-life divestments include the joint development area between Nigeria and São Tomé, Browse in Australia, and our former Mariner and Bressay assets in the North Sea.
Examples of mature asset divestments include Cook Inlet in Alaska, our assets in the Netherlands and Norway, and our normal pruning in the Gulf of Mexico and the U.S. Mid-Continent. Given the quality of our portfolio, these assets that don't compete for current funding are valuable to others. Our disciplined portfolio management has delivered peer-leading results. Our 2014 Upstream C&E will deliver profitable growth through this decade. We have a budget of $35.8 billion in 2014 as we reach our peak spending on multiple projects. We expect a similar spending level through our three-year business plan window. Our 2014 to 2016 C&E program is strategically divided into three key time frames to deliver the right value mix. 10% of our C&E is dedicated for exploration to provide long-term opportunities that deliver barrels into the next decade.
60% goes to our major capital projects, which are key for delivering mid to long-term growth. These investments provide step changes in our production and add high-value barrels. Some of the key 2014 project investments are Gorgon, Wheatstone, Jack/St. Malo, and of course, Bigfoot. 30% of our investments go to our base business, delivering near-term value by mitigating decline and growing key assets such as the Permian. These capital investments create the foundation of our future production and financial performance. Let's take a closer look into our U.S. liquids portfolio. Chevron is the largest hydrocarbon liquids producer in the U.S. Most of our direct competitors have invested more heavily in domestic gas over the past eight to 10 years, while we've maintained a focus on higher-value liquids. We've slowed our gas investments over the last several years, directly responding to market conditions.
In the U.S., we're not only the largest liquid producer, but also have the greatest U.S. earnings margin and are near the top on an absolute earnings basis as well. Next, I'll dive a bit deeper into the U.S. portfolio and review our Permian position. We've been in the Permian for many years. Back in 2011, we produced our 5-billionth barrel from the basin. Today, we are the second-largest producer. We have the largest undeveloped leasehold in the Permian and have over 10% of the leased acreage in the prolific Delaware Subbasin. In both the Midland and Delaware Subbasins, less than 50% of our acreage is developed. Another key advantage to our acreage is that much of it has been in our portfolio for many years. Therefore, has low royalty rates. In fact, across the Permian, 60% of our acreage has no royalty and 30% has low royalty.
This means that 90% of our acreage position has a significant competitive advantage. Our acreage position provides us an enviable opportunity for growth, with over 17,000 oil and gas well prospects identified and additional exploration potential estimated at another 8,000-10,000 well locations. The Permian Basin is uniquely advantaged over other U.S. continuous plays due to the multiple stack plays. This is an acreage multiplier in the terms of resource and development potential. For example, our Midland and Delaware leases have 1.5 million surface acres, which is equal to over 7 million reservoir acres. The stack plays allow for efficient development and production for multiple zones. Multiple wells can be drilled from a single pad location, and producing infrastructure can be shared. Compared to other basins, this lowers the risk and the cost per well, and the access to export infrastructure is also advantaged.
We're optimizing our developments for value creation. We're not in a drill or drop position, so we can focus on the resource and prioritize our developments. According to WoodMac data, our development plan has the highest compound growth rate of the top five Permian producers over the next few years and again delivers long-term profitability. Our Midland Basin growth is coming predominantly from the Wolfcamp play. On the Chevron acreage, we have identified over 8,200 well prospects. In 2013, we drilled 330 wells, and we expect to drill a similar number in 2014. In the liquids-rich Delaware Basin, we also hold significant undeveloped acreage with over 6,000 well prospects. We've seen production rates of over 1,200 barrels per day in the Delaware Basin, and because of that, we plan to increase our drilling rate. In 2013, we drilled 135 wells, and our target in 2014 is 175.
To date, the wells we've drilled are a mixture of development, appraisal, and some exploration. As we shift into a factory drilling mode, our plan is to continue to increase rig and well counts. Looking out to 2020, we expect over 250,000 barrels a day of production coming from the Permian. Of this, we forecast approximately 77% will be liquids. Once again, the Permian is a key legacy asset in our portfolio and will continue to be one of the leading producers in the basin. Our growth in profitable shale and tight resource basins also extends outside of the U.S. into the Canadian Duvernay and the Argentine shales. As announced last year, we have strong performance with our exploration program in the Duvernay, with well rates up to 7.5 million cubic feet of gas and 1,300 barrels of condensate per day.
We're increasingly confident that our 325,000 net acres are well positioned in the sweet spot, an area rich with condensate. In Argentina, progress is being made to develop the Vaca Muerta shale. The shale is thick and laterally extensive. Initial well tests indicate this is a world-class shale play and approximately 140 gross wells will be drilled in 2014. Production is expected to grow to around 80,000 barrels per day by 2017, half of which will be Chevron share. The Vaca Muerta shale also underlays our existing El Trapial asset in Argentina, where we are testing four exploration wells in 2014 to further assess the shale potential. These plays all have exploration and development opportunities and will contribute valuable growth through the decade. We have a diverse gas portfolio in the U.S. with significant development opportunities. However, the gas market is presently weak.
We're positioned to deliver substantial gas growth when the conditions are right. Our acreage has low holding costs, so deferring investment is the right decision. We can adjust our plan as the market changes, as we don't have to drill to maintain acreage. We've identified over 5,000 gas well prospects that don't presently compete for capital. We'll begin developing this acreage when the market conditions provide an attractive economic opportunity. Our leading upstream financial performance and our industry-leading project queue are a product of our strategy, execution, and value focus. All of our investments and assets must compete for capital. Our anticipated capital allocation over the next three years is shown on the right, with 90% of the C&E going to oil-linked assets. We'll continue to strategically invest some funds in profitable gas developments.
Less than 2% of our C&E over the next three years is dedicated to U.S. gas, and these investments have a drilling carry. Our U.S. oil investments are advantaged with limited exposure to pipeline constraints. Jay will now cover our upstream growth.
Thank you, George. Good morning, everyone. Let me start by taking a look at our worldwide view of key assets that will drive our growth to 2017 and beyond. We have more than 70 projects, each with a Chevron share of over $250 million scheduled to start up by the end of this decade. In the near term, we're seeing growth from major capital projects that have recently started up and are increasing production. We also have numerous projects expected to start up between this year and 2016, most notably developments in the Gulf of Mexico and our two LNG projects in Australia. By 2020, we expect additional growth from projects in the Gulf of Mexico, West Africa, and of course, Kazakhstan.
Shale and tight resources are also major contributors to our growth, as they account for 7% of our current production and are expected to grow to 15% by 2020. Let's take a closer look at the status of some of these projects, beginning with our project ramp-ups. Angola LNG, Usan in Nigeria, and Papa-Terra in Brazil are already producing and are expected to grow production in 2014 and beyond. ALNG is currently running around 50% capacity and has shipped three LNG and two LPG cargoes this year. The variable composition of the plant's associated gas supply has impacted its initial performance. We expect the plant to remain at about 50% capacity until permanent modifications can be completed in 2015. This will allow ALNG to consistently produce at its full capacity of approximately 180,000 barrels equivalent per day. At Usan, development drilling is expected to continue into 2018.
Satellite developments are being reviewed as tiebacks to the FPSO as future growth opportunities. Papa-Terra achieved first oil in 2013. The second well on the FPSO is already on production, and the ramp-up is expected to continue through 2016. First oil from the Papa-Terra tension leg platform is expected by the end of the third quarter this year. Now, let's continue with some of our significant deepwater projects. Our performance on Jack/St. Malo continues to demonstrate our strong project execution capabilities. In 2013, the hull sailed from South Korea, the topside modules were installed, and the platform was moored in its final position in the Gulf of Mexico. With over 99% of the construction, 75% of the subsea installation, and 80% of the hookup and commissioning completed, the project remains on budget and schedule for a late 2014 startup. Bigfoot is another project with significant progress in 2013.
The hull arrived in Texas for integration, and all topside modules were installed. We finished drilling all the wells for the initial startup, and this year we expect the platform rig will be installed, the hull will be moored on location, and the commissioning campaign will begin. We expect to start production at Bigfoot in mid-2015. Another important project in the Gulf of Mexico is Tubular Bells. The construction of the spar and topsides has significantly advanced, and they are now installed at their offshore location, and startup is expected before year-end. Production from these projects reinforces our position as the largest liquids producer in the U.S. and a major producer in the Gulf of Mexico. Now let's turn to our LNG projects. Gorgon continues to make steady progress towards first LNG, with construction now over 78% complete.
To date, 20 of 21 modules needed to produce LNG have been delivered to Barrow Island. While not on the critical path, the 21st module is expected to be delivered in June. All Train 2 modules and most Train 3 modules are scheduled to ship before year-end. Train 2 and then Train 3 are scheduled to come on stream at six-month intervals following Train 1. The domestic gas pipeline and all offshore pipe lay are complete. The LNG jetty and the first LNG tank are on schedule for completion this year. By year-end, 18 wells are expected to be completed, each designed to deliver over 200 million cubic feet of gas per day. Only 16 of these high-volume wells are initially needed to meet plant requirements. We're expecting a mid-2015 startup. I'll now cover the Wheatstone progress. This project is now around 30% complete.
The development drilling campaign commenced in January, and the overall progress on the Wheatstone offshore platform is 50%, with the steel gravity structure scheduled for installation later this year and the topside in the first half of next year. The wharf can now accept marine shipments, and completion of the first LNG tank foundation and delivery of the first process module are also planned for this year. The takeaway is that Wheatstone LNG remains on track. Now let's talk about TCO. Tengiz has significant expansion potential. We have a trio of projects to optimize existing production, expand processing capacity by an estimated 300,000 barrels per day, and roughly double the Caspian pipeline export capacity. We expect the Caspian pipeline to realize incremental capacity in stages before ultimately reaching 1.4 million barrels per day in 2016. Around 100,000 barrels per day is anticipated to be available this month.
In late 2013, alignment was reached between the Kazakh government and TCO for the expansion. Early funding has enabled orders to be placed for long lead equipment, as well as allowing construction to commence on a nearby port that enables delivery of prefabricated modules. These are major steps towards reaching FID later this year. Together, these projects are designed to grow the plant and field capacity beyond 1 million barrels per day. Looking further out, I'd like to talk about four projects in our post-2017 Deepwater project queue. Stampede entered FEED in 2013 and has completed appraisal well drilling. The selected concept is a tension leg platform delivering an approximate capacity of 80,000 barrels of oil per day. We're currently reevaluating Rosebank and Mad Dog 2 to generate scenarios with viable economics. With large potentially recoverable resources, optimized development plans could deliver valuable barrels from each of these assets.
The Buckskin Moccasin hub development concept is still in the early planning phases with an ongoing appraisal program. Now, leaving the Deepwater, let's look at two major projects in Canada. The Hebron project is advancing with the gravity base structure under construction in Canada and fabrication of the topside underway in Korea. The project is expected to start up in late 2017. The Kitimat LNG project will be an important contributor to future LNG market supply. Kitimat LNG is continuing to progress and maintain its first-mover advantage. A critical milestone in the path to a final investment decision is the placement of 60%-70% of the production under firm gas sales commitments. Now let's look at two of our longer-term expansion opportunities. The Wafra First Eocene large-scale steamflood pilot continues to progress and has achieved oil recovery rates greater than 50%.
The recovery factor is at the high end of our expectations and supports a full field development with FEED anticipated in 2015. Given the results of the first pilot, another pilot is being planned for the deeper Second Eocene. Initial well patterns are being drilled this year. Our largest LNG facility, Gorgon, has brownfield expansion potential with over 11 TCF of gas available. The expansion targets gas in the Shandong and Geryon fields. As with other LNG projects around the globe, Gorgon expansion will require LNG sales contracts to underpin an economic development. These projects all contribute to an enviable portfolio that strengthens our position. Today, our portfolio includes about 50% or 1.3 million barrels per day of production from legacy assets, which we define as having flat to low production declines over a decade or longer.
By 2020, production from our legacy assets should reach more than 60%, with new production from our LNG projects, expansion at Tengiz, and our shale and tight resources. The significance of these assets is that they deliver reliable long-term production. Even our shale and tight plays have ratable spend profiles that sustain long-term growth. This growth in our legacy assets increases production and investment certainty. This year, we plan to drill more than 75 exploration and appraisal wells worldwide. Our focus areas are key as they leverage existing business and acreage positions to maintain and grow production. North America, the Gulf of Mexico, West Africa, and Australia are areas with proven exploration success. Our test areas provide new basin opportunities to expand resource capture. As an example, the Kurdistan region of Iraq has demonstrated significant potential with multiple horizons of oil.
Our initial two exploration wells in Rogi and Sarta have encouraging results. More wells are planned this year to further evaluate the potential. We define impact wells as having over 100 million barrels of potential, and we plan to drill 12 impact wells this year. We have a diverse exploration queue that includes conventional and shale and tight opportunities. With our portfolio of global deepwater projects, shale and tight resources, LNG projects, and multiple expansion opportunities from important legacy assets such as Tengiz and Wafra, we not only have growth potential through this decade, but well into the future to continue to deliver high-value barrels. George will come back to make some closing comments. Thank you.
Thanks, Jay. Like earnings per barrel, our cash margins lead the industry. In 2013, Chevron's upstream cash margins were approximately $38 per barrel, very similar to 2012. Competitor data is not available for 2013. We expect to lead on this metric and to lead by a large margin. Consistent competitive data became available in 2009. As you can see, we've not only been leading, but we have differentiated our performance relative to our peers. This position on cash generation is frankly what has allowed us to invest for the future and to concurrently make strong shareholder distributions. Our forecast is even better. We expect that the cash generation of the new investments will be accretive to the portfolio. We firmly believe our production and financial growth position is the strongest among any of our competitors.
With our major capital projects coming online, we forecast continued growth through the end of the decade. Projects like Gorgon, Wheatstone, Jack/St. Malo, Bigfoot, and others are expected to add over 800,000 barrels per day in 2017. Beyond 2017, projects such as the TCO expansion, Hebron, and growth from the Permian and other shale and tight basins add more new production. I would like to close by re-emphasizing that our performance, portfolio, and growth story continue long term. In summary, we continue to deliver top earnings and cash margin performance by maintaining our value-driven investment strategy. With a robust opportunity queue and our growing legacy position, I'm confident that we will continue to differentiate ourselves as the industry leader in the upstream business. I would like to thank you for your attention. Now John will come up for a few closing remarks and then Q&A.
Okay. Thank you, George. That concludes our prepared presentations. Just to recap what I said at the outset, we feel the business environment will be very good for our business, and we're well-positioned to prosper through the end of the decade and beyond. Our strategies are right, and our portfolio continues to deliver excellent results, and we're poised to deliver substantial volumetric and financial growth. To ensure delivery of value, we're focused on strong execution of our base business and major capital projects. Now, Mike and Pat will join me up here on the stage, and we'll start taking some questions. Arjun?
John, you've been pretty disciplined so far acquisition-wise, and particularly related to shales, which is not a question over the years. Thanks. It's Arjun Murti with Goldman. John, my question was on acquisitions related to shales. You've highlighted certainly a lot of optimism in the Permian. You've got the Duvernay and Vaca Muerta. You've been very disciplined over the years. Some of the valuations, say, in the Bakken, for example, do seem to have come off the euphoric highs from a few years ago. Can you provide any updated thoughts on how you're thinking about the acquisition environment?
Sure. Well, George made a comment that we need to continuously replenish the resource pool, we've done that over time, and we've done it through several means. We do it through exploration, discovered resource, and acquisitions from time to time. Last year was a big year, really in more the discovered resource and some of these tight resources, because we thought that the opportunity was right. Over the years, we've watched the Bakken, and frankly, we'd like to have a position there, but the valuations have been high, and we just couldn't make the economics work. We've stayed away. I think we have a good portfolio right now. We've got plenty of growth ahead of us in the Permian. Arjun, I can't rule out opportunities that might come forward, but we feel good about what we've got right now, we're not looking.
We've got a pretty full pot right now, we're not looking. Yeah, thank you. Please do introduce yourself. I can't always see everybody because of the lights. Thank you.
Doug Terreson, ISI. John, Chevron's been pretty constructive on oil prices and more so than its peers during the past decade. I think that you reiterated that viewpoint today. On this point, slides six through eight indicated rising marginal cost for crude oil due to higher costs and less attractive terms I think you talked about too, which implies changes to industry spending near the $80 Brent threshold, if I read the chart correctly. My question is, would you agree that $80 Brent may be a new threshold for global spending? I know it's just an approximation, or did I misread that chart? Then second, how does Chevron manage for greater value creation in the environment that you envision? Meaning, how do you manage the balance between growth and returns given what appear to be a more challenging industry condition going forward?
Sure. Well, a couple thoughts. First, one of the points on that chart is there's still a lot of resource that can be developed for less than $100 and less than $80 a barrel. There's a whole range of operating environments out there, deep water, certainly some of the OPEC nations have low cost resources. What the chart was really meant to convey is that at the margin, as we go into deeper water and as we've seen these rising costs, there comes a point where some projects just won't be able to compete for capital. Certainly for us and presumably for others. We've seen more projects in those asset classes fall over, or companies have announced delays. I don't know that there's a hard threshold because fiscal terms vary considerably, whether it's deep water or in other areas.
I wouldn't want to put a hard and fast rule, but we certainly know of projects that at $100 a barrel aren't economic any longer. In terms of how we take a look at our priorities during this period, one of the things I commented on is that we do our economics, really, we do probabilistic economics, we take a look at costs. We've always evaluated our opportunities under a range of different price and cost and production scenarios. We actually put together what we term in our business S-curves, and really have a view of the upside and the downside of projects. That won't change now. If we start to see a better environment on the cost side of things, that'll be reflected in how we look at our projects going forward.
I know George talked. See if he's got any specific thoughts on some of the trends that we're seeing now in costs and his thoughts.
Well, on the cost side, it is different in different areas. We have seen some costs come down on the onshore drilling costs. Land rigs have gone down. I think we're in a period, maybe we're going to see a flattening or maybe even a little bit down on some of the deepwater rigs. We're seeing more deepwater rigs come out of shipyards, so maybe we're at a point where we're going to be at a plateau on that. I will tell you, costs are still very high in the subsea arena for the hookup portion of it, the manifolds, all that piece is high and it is impacting some of the deepwater projects. There is more variability than there was in probably the past 10 years. Everything seemed to move up. We are seeing some differences in different segments.
Ed?
Ed Westlake, Credit Suisse. Thanks for the CapEx outlook, a few extra years, it helps. I have a question, I guess, around the contingencies. What's the worst-case CapEx scenario that you could think about if some of the Aussie dollar changes or projects perhaps don't progress as smoothly as you think?
I don't know what the worst-case is. If you noticed in some of our outlook for 2015 and 2016, we put a little bit of shading up there because there can be some variability. Look, we have a pretty good understanding of what costs are likely to be for Gorgon and Wheatstone at this point. We've done a lot of contracting, obviously, in Gorgon, we're at the final stages. We have a pretty good idea of what costs will be. There can be variability in exchange rates, I'll tell you, we're managing capital pretty closely right now. We've put a budget of $40 billion, and we're watching that very closely. There will always be some ups and downs, that's why we put a little bit of a shading around that.
We can see the top-line cash that we need to generate in order to continue to pay and grow the dividend as the pattern of earnings and cash flow permit. We're fairly committed to it.
Specifically in the Permian, you've got 50,000 barrels a day of production growth. If an E&P company had one and a half million acres in the Permian, they'd probably put something up somewhat higher. Can you talk about your confidence in or maybe why that trajectory is the shape it is and maybe the constraints you see that others don't, and maybe talk to your ability to execute in shale?
I know George is dying to answer that question, so I'm going to let George answer that one.
There's several things there. First off, for us, we are in a different position than almost all our competitors on the lease. Most of them have tied up their leases in the recent past. They have lease positions that have royalties in the 20%-25%. They have drill and drop. They don't have a lot of choices. They got to move. We like being a little more ratable and make use of and find the sweetest spots to drill first and use the leverage of those first investments are the strongest for in the future, the infrastructure they create, they will create more value and more of these opportunities in the future that aren't quite as good, not maybe in quite as good a spot on the reservoir side. They will still be good economics because they're leveraging off our earlier investments.
You can't do that if you just mow through it. You just can't. We don't have to do that. We're looking at a large growth over this period. My number is something like 130,000 barrels of growth. That's big. That in effect is equal to a couple of major capital projects of kind of average size. It puts us in a good position that we got a nice ratable, in effect, major capital project that's ratable capital, that's also ratable on barrels each year. It's a little bit smoother. For me, I like to get to that point in the Permian, and I'd like to get to that point in the Duvernay. It'd be very nice to have a couple of assets like that that you can be ratable growth, ratable capital
Know those barrels are coming and not be quite as dependent on being one quarter early or one quarter late or 6 months late on a major capital project. Big advantage to having a couple of those in our portfolio. Okay, let's see. I'll take one. Paul, I guess, here.
Thank you, John. Paul Cheng, Barclays. If I could, two questions. John, I think for the last quarter, when you started talking more about the high costs and lead to some projects being dropped off. In the past, you're talking about organizational capability limit and the supply chain. If we look at today, which is actually a bigger constraint factor for you to take on projects?
Well, I think the two go together. Part of the reason we've seen costs rise is because the supply chain is tight. I showed you that chart that indicated that the backlog for contractors is generally high. George indicated there are some areas where we may see some loosening in the market, but fundamentally, it's a strong market for oil field services and equipment, and we don't see that changing. As far as our own people go, we've been very successful at adding capability to our organization over time. About half the hires in the technical ranks that we've done over the last five years have been experienced hires. We certainly continue to hire on college campuses, but with the boom we've seen over the last decade, we've gone outside the company. We brought in some great professionals.
Right now, we think we're able to attract the people that we need. We've instituted, as I referenced in my comments, more oversight in the contractor community and QA, QC, and planning and a number of other areas to be sure that contractors are executing as we hope they will. We feel we've got the people to do the work. There's still the tightness in the supply chain, and that's reflected in prices.
The second question, probably for Pat. In your chart, you show you're targeting by 2017 cash flow from operation maybe over $50 billion. In 2013, it's about $35 billion, That's an increase of over $15 billion. George had talked about the average cash margin for the upstream is $38. You are targeting 500,000 barrel per day increase in your production, That's about $7 billion. Can you help us back to bridge the gap? Where is the other $8 billion? Thank you.
I'll give some arithmetic for you there, Pat.
I think the component that you're missing perhaps is the fact that we said that the overall portfolio in 2017 would be stronger than the overall portfolio today. It's not just on the increment, it's on the full portfolio.
So-
In other words, it's the 3.1 million barrels a day at a cash margin that is higher than today's cash margin of $38 a barrel. That makes up the difference. We also have contributions coming in in 2017 from the Pascagoula Base Oils plant as well as CP Chem. The vast majority of that increment is, of course, related to upstream.
I'll try one back there. Yes. I'm sorry, I can't see right out.
That's all right. Roger Read, Wells Fargo. Thanks.
Yes. Hi, Roger.
Maybe just to follow up on the cash OpEx side. If we look at one of the biggest projects coming on, Gorgon, can you give us some idea of how we should think about cash costs with that? Obviously, you'd expect them to expand given those numbers. Then the second part, given the troubles with Angola LNG in terms of getting it up to speed, and I recognize the gas stream not as consistent maybe as what you expect at Gorgon. Can you give us an idea of the testing you've done so far that gives you confidence that once you're up and running on Gorgon, the startup should be relatively smooth or as smooth as can be hoped for?
Yeah, I don't know that we'll give you a precise forecast for OpEx for Gorgon. Why don't let Jay talk to you about both those subjects.
In terms of first the reliability, ALNG versus Gorgon, as you pointed out, they are very different projects. Gorgon is using dedicated gas for the field, both Jansz-Io and Gorgon to supply the field. The issues with ALNG have been on the gas conditioning that go into the LNG facility. The LNG facility itself is performing to expectations. We're quite comfortable in terms of the prediction of performance for Gorgon. At ALNG, what we're doing now is evaluating adding additional separation capacity for liquids on the front end as well as additional dehydration capacity. What we'll do is take a turnaround to install that additional capacity, that's what will allow the plant to come to full rate speed. In terms of Gorgon's cash generation capability, it is a-
You said cash OpEx?
Well, whichever way to think about it.
Oh, okay.
Whichever way to think about it.
I think about in terms of its ability to generate cash in terms of first of all, you're looking at largely oil-linked contracts that generate very robust pricing for the project. Very large scale in terms of the production and the cost per barrel. This is an asset that will generate I would say robust cash generation for decades, and it really serves as a great source of cash generation for us going forward.
Maybe just to add a comment to help you on that, not specifically point out the Gorgon, but Gorgon is a huge part of the cash move for us going forward. That chart that we showed probably near the very end in the upstream segment where we showed the cash
Margins of the total portfolio going up. The existing portfolio doesn't change that much. The impact of the improvement, the accretive nature of it, is really all driven by these new additions. These new additions are cash accretive in total to the whole portfolio.
Very good. Yes, Doug.
Thanks, John. Doug Leggate from Bank of America. Maybe this question is for Pat on the balance sheet. I know we're talking long-term time frames here, you have said several times that your capital expenditure in 2013 was probably your peak. Does that time frame associated with it, because as we look forward, as your cash flow grows, are we then suggesting that Chevron's going to move into harvest mode at some point? Does beyond 2017, does the CapEx continue to ratchet higher? I've got a follow-up, please.
I think I was the one that used the term relative peak, maybe I'll try that. All I was trying to get across is that as you go down the road five, 10 years, we'll be a bigger company. I don't know what the cost of goods and services, I don't know what the price environment is going to be. To say that something is a peak forever just didn't seem like the prudent thing to say. 2013 is a peak for capital spend as far as we've planned. Going forward, a harvest mode implies liquidation or something of that sort. We have these big projects coming on. Gorgon and Wheatstone, our combined spend on these two projects is over $40 billion. We've got nothing like that.
We've got some great projects in our queue, but we've got nothing like that, where we're going to spend $40 billion within a six, seven-year period of time.
I guess the related question is, this is my follow-up. If I look at the portfolio capital intensity, it's still, George made a great point about your unit cash margins, but you're spending the same as a company 40% bigger than you and delivering not dissimilar growth. Do you expect that that changes? I guess that's what I mean by harvest mode. Is there a point where Chevron starts to throw off free cash as opposed to the cash burn that Pat talks about by moving the balance sheet by
Let's talk about that. I think you're referring to our largest competitor who spoke the other day. They're a terrific company. My understanding, based on what was presented, is they produced 4.2 million barrels a day in 2013, and in 2017 they'll produce 4.3 million barrels a day. That's pretty flat. What we're saying is that we're going from 2.6 million barrels a day to 3.1 million barrels a day. That's 500,000 barrels a day of increase. That's a fairly significant difference going forward. I think it's important, if you look at a couple of the charts where we showed decline curves, you can invest at a low rate and decline at 3% or 4% a year until you run out of base business projects.
To realize growth, either to get you up to even or get you to 3% growth or 4% or 5% growth on top of that, it takes a large increment of capital. I think that's what you're seeing right now for us. That's why you're seeing spending that's comparable. I think there'll be different outcomes from that spend. Yes.
Thanks, John. It's Robert Kessler, Tudor, Pickering. I'd like to follow up on your just most recent comment about base versus growth CapEx and maybe drill down into Tengiz specifically. When I look at the three projects there, two of them look like maintenance projects to me, the way they're phrased. As you look up to get to that million barrel a day production level, how much of the overall spend is what you would call maintenance type spending that persists maybe on beyond reaching that million barrel a day threshold, and how much is the growth CapEx?
Yeah. Well, we've got two projects, and I'll let Jay describe them. It's important to distinguish between the two, and I'll let Jay do that.
Yeah. Thank you. There are, as John said, two projects that are going to be conducted at the same time in Tengiz. The first is called Wellhead Pressure Management Project. I think this is the one you may be thinking of about maintenance. It's really not. What it simply is a boost to take all the existing field production and compress the gas and pump the oil up to the high pressures that the plants require, effectively lowering the back pressure on the wells, which allows us to get more production out of an existing well base. The alternative would be to have to drill a lot more wells. It actually is contributing to that decline, arresting the decline out of the existing wells. The second project is Future Growth Project. This builds on the pilot work we did with sour gas injection that's been so successful.
What this does is actually increase our production capacity an additional 250,000 barrels a day-300,000 barrels a day, and it allows all the gas from that to be reinjected back into the platform for miscible flooding and pressure maintenance. Think of one project as really a base business, as George was talking about, that extends our base and allows us to minimize the amount of drilling we have to do. The second one builds on top of that to add the incremental capacity. The third project was the expansion of the export pipeline, which is pretty evident.
How much CapEx for each of these?
We haven't released CapEx numbers for that. We expect to take FID later this year, that's normally the time when we would put some numbers out around those.
Thanks. One other from me, if I could, real quick, John.
We're going to limit it to two, okay? We'll come back, though.
$10 billion. I thought that was more.
I guess that was the follow-up. Okay, go ahead.
$10 billion of asset sales. What's the upside to that? You referenced it being upstream weighted. What happened in the midstream incremental divestment potential there?
$10 billion is the number that we've got for the next three years. Most of the divestments we've had in the recent past, Mike showed you some numbers, have been as we've been really sizing our downstream and some of our midstream assets the way we want them. We're nearing the end of that in the downstream. In the midstream, we're continuing to monetize pipelines, power plants, things like that really aren't integral to flow assurance for our upstream and downstream businesses. We have some, think of them as merchant or third-party activity going on. We think given the valuations that are out there, we can get more value. We're still going to be in the pipeline business.
We're still going to be in the power business, in fact, in a very big way with self-generated power in our business, with pipelines from Jack/St. Malo, the Caspian Pipeline, and others. We'll still be in the midstream business, but it'll be more clearly associated with the activities that we have underway. You should think of 80%+ of the asset sales that we talked about will be in the upstream end of the business. We'll go over here. Evan.
Thanks, Evan Calio, Morgan Stanley. John, you've been through a few cycles, Last cycle, peak and plateau were really two theories on oil productive capacity, not majors collected CapEx. While different, I think both are constructive on future oil price as well as future returns. Really in this plateau to peak CapEx world, and in a world where we're seeing increasing resource potential, whether that be other countries opening or other unconventional assets, do you expect or has your upstream threshold for projects increased? Has your geopolitical risk decreased? I know the Rosebank, Mad Dog, they're being re-examined. Vietnam, you chose not to enter as some examples. As your threshold changes, is it something that could be a foreboding for improved returns in a flat commodity price?
Well, our economic criteria haven't changed over time. The conditions that go into the economic valuations obviously do change. Part of what you were saying at the outset was more geared toward our view of markets, and I guess the way I look at it is over the last decade, we've seen 750 million people move into the middle class, and that's resulted in demand growth. Despite the sharp increase in prices, we continue to see demand growth, and we continue to see more people that will be entering the middle class around the world. That's why I said we're fairly bullish on increasing demand for energy in general. If you're bullish on the increase in demand for energy, then decline curves take over, and it's going to take a significant amount of investment for our business.
There will be periods where you'll have an ebb and flow in terms of the investment environment, pricing. We've been in a flat period for the last few years. I think what sits behind all of that is this underlying demand. You'll have an imbalance between costs and prices for short periods of time. You can have that, and when you do, markets work. We pull back on projects that aren't economic. Presumably, others in the industry do the same thing, and you get a rebalancing in cost. It either happens through cost or price if we're shrewd about making our investment decisions. I'm not sure if I answered your question, but that's what I mean. Yes.
Thanks. Faisal Khan with Citigroup. You've had kind of delays or cost overruns for a number of projects, EGTL, Angola LNG, Chuandongbei, Bigfoot, and Gorgon. I guess I want to understand is sort of what are the lessons learned from these delays and cost overruns, and how do you ensure that you don't see these sort of issues take place in the future?
Yeah, I guess I'll start with the basics. We didn't get to a leading portfolio with a $5 barrel average margin over all of our competitors if we weren't pretty good at selecting and executing projects. We're living in challenging times for executing major capital projects. I went through some of those earlier. Maybe what I can do is Jay's very knowledgeable about projects. We'll let him talk just a little bit about some of the things we're doing in our project management system to talk about addressing some of the risks that you described.
Thank you. I think it's important, first of all, to think about projects both before they start execution, when you can see delays. FGP would be an example where we thought it would get to FID a little bit quicker. These we pace at the speed that they're going to take to get them right. We're not in a hurry. We're not going to drive them prematurely. Many times it's driven by the commercial and political environments more than they are the technical issues that are associated with these large projects. Projects like you mentioned that are in execution, we tend to have a better handle on the schedule and the pace of these, although you can always get unexpected events arising. In the case of Gorgon, we had some issues with the logistics of trying to get all that material and equipment onto an island.
Those were recognized as an issue and were addressed. We're not having those issues any longer. We had some exchange rates that started going against us in the Gorgon project with a lot of AUD spend. That's now moving back towards center. What we try and do is, as John pointed out earlier, we try and characterize the uncertainties that we face with all of these major projects and build the execution plan such that we can adapt and incorporate these changes and still be able to deliver an economic project at the end. I think as you see with Gorgon, we're now 78% complete. All but one module are on the island for the start-up next year for the LNG. We are seeing good success as we move forward with projects like this. We routinely take the lessons learned, for example, Tengiz SGP.
What we learned in executing that major project was directly transmitted to, for example, the Gorgon team as they looked at a major land-based project. One of the issues you saw was a shift from stick-built construction to modular design, and a project that's built largely through prefabricated modules. This also came from the deepwater, where we have a pretty good history of delivering these projects. That technology then was adapted for onshore service. It's given us better ratability. That is now being applied for FGP and WPMP in turn. As we do these various projects around the world, the lessons learned are routinely captured, and then they're fed into the other projects as we move forward, and we're seeing the results from that effort.
One thing I might, maybe George will comment on, is the nature of our contracts with the contracting community and how those have changed over time.
Yeah. You go back 10, 15 years ago, the projects that we did on scale, the large ones, you could do those with a lump sum bid to a contractor. The projects we're doing today, there is not enough financial capability in those companies. They make a mistake, they're out of business, or they put so much cost, in effect, insurance, into a lump sum bid that it would just kill the economics of it. We have had to look at different ways to deal with our contractors. We tend to break the contracts down into smaller chunks. We have become, in many ways, more of the general contractor. That has forced us to have more people that are capable to put all the pieces together. I think we've been very successful in doing that.
It was a challenge, and it was something we had to recognize right up front. You can't expect a contractor to go do a project where his cost of the project is two or three times the enterprise value.
We've become more intrusive. One of the lessons learned on these capital projects is you can't just sign a contract and expect a contractor to execute, given the stakes in some of these projects. We've been much more intrusive, larger owner's teams, and different tools in our project manager's handbook, if you will. That's the device that's used by our project professionals to be sure that we do capture all the lessons learned and that we are on top of everything the contractors do. In the old days, you sign a lump sum, you let them go, and you came back, and they were done. It doesn't work that way anymore.
My second question was, it's a short question, is that you guys lowered your decline rate to 3% on your base business. Does that not show up in the production outlook? It didn't show up in that bar chart that you guys laid out.
It's not shown up in there that we have just now, with now three years or four years of lower than our 4% decline rate, we've made a decision to-- we see a path forward on the 3%. I would tell you it may even get better after we get to Gorgon and the Wheatstones on and have another set of assets that frankly have flat production. Over that period of time, it could make a difference in our production. We have not built anything in there recognizing that at this point. Most of our business plans have actually moved the last couple of years to a lower decline rate from the business units. Our forecast, once again, is based on our business plans that we work with our business units, and we're seeing their decline rates going forward being less.
I'm going to take one question from online. We have a lot of people on webcast, and maybe I'll give it to Pat. How do you determine if there's a better value in investing in a project compared to returning cash to shareholders via repurchasing? I know some of you have asked that question, I thought I would give her a shot.
Yeah. Obviously, I laid out our cash use priorities. Start with the dividend and then move to the reinvestment in the business opportunities. We have a 26-year dividend growth history. We obviously want to retain that. That's very important to us. We also want to be able to sustain the growth in the value of the enterprise, and we do that by virtue of the quality of the project queue that we have. We're always constantly balancing the near-term returns to the shareholders via dividends and share repurchases against the longer-term value creation opportunity that we've got that, in fact, sustains the ability for the firm to continue to grow dividends in years on out. We constantly play against this tension, and I don't think that you can say that there's a static view at any given point in time.
We always look at it relative to the facts and circumstances that we have at hand.
Thank you.
Having once taken, dividends and a growth pattern off the dividends off the plate.
Okay. Let's try one right in front. Yes.
Paul McCray from Tower Bridge. A strategy question. A number of somewhat cash-strapped E&P companies have made major natural gas discoveries and are moving downstream into LNG. Were your partner, Apache, for example, to need to monetize its investment 50%, I believe, at Kitimat, and they came to you and said, "We're going to be selling it down," would you step up to the plate?
Apache is a publicly traded company. I probably shouldn't speak for them. We obviously have a good partner in Apache for the Kitimat project. I think it's premature to speculate on either they've talked about what their plans are. Our plans, we've got a 50% interest. I wouldn't see our percentage increasing from there. Okay, in the back. Yes.
Asit Sen from Cowen & Company. Two questions, John. First, is Kitimat in the 2015-2016 long term CapEx trajectory? Looks like it's not mentioned on the chart here.
George, you want to talk a little bit about, or Jay, you want to talk a little bit about where spend is?
Kitimat, we have money for Kitimat to do engineering, site work, and do the appraisal work in Liard. We feel it's necessary to do that work. We need to do more assessment work in Liard, and we need to be ready to move if we have gas sale agreements made. We're moving on spending money in that light. We do not have money in there for if we reach a point that we would be ready to go to FID. The FID expenditure profile is really not in there at this point. We expect we've got at least another year of assessment work on Liard. Once again, back to the point, we've got to have gas sales contracts. We're not going to expose the big money post an FID period until we have gas sale contracts in hand.
Okay. My second question is on, since we're talking about cash margins in Gorgon, any early thoughts on Canadian LNG cost structure? Relative to Australia and your thought process when you're evaluating Kitimat relative to T4 and Gorgon.
Well, our efforts in Canada are certainly informed by all the work that we've done in Australia. We don't have firm cost estimates there. Anything either one of you guys want to add about cost?
We're in the stage of trying to get to more firm estimates of cost. We've got good ideas on resource. We want to confirm those. We need to confirm the cost of drilling those wells. They're great wells in Liard, but we've got to find the right well cost to fit with the development. We've got work there. We've got to come up with the design of the well that will make the most sense. We've got work there. It's just premature at this point. We've built off of what we've learned in Gorgon and Wheatstone on the cost structure on the plant side. We have that in hand. I'll go back to the critical element on it is gas sales contracts. We've got to get those.
Okay. Here in the middle.
Thanks. Justin Jenkins with Raymond James. Maybe shifting to the U.S., given the production growth we're seeing and expect to see in U.S. liquids, are you concerned about price differentials and how that may affect development?
Good question. We've talked about that in the past. We're obviously not in the Bakken. We tend to be more in the Permian. Maybe I'll let Mike talk a little bit about some of what we're seeing on the pricing side. It has an impact both downstream and upstream. Mike, talk about it generally, and then George or Jay can talk about the upstream impact.
I tried to touch on that with the one slide that talked about feedstocks. If you look at NGLs, it is certainly to the benefit of people that are currently in the petrochemical business, as we've seen ethane and propylene prices very advantageous, and it shows up in CPChem's results, and it's part of their plan to move forward with this new cracker. Certainly on ethane, the length of time that condition may persist is important to us, and given the trends that we see right now and really the binary choice that goes with ethane, either into the natural gas or into pet chem feeds, that would look to be something that would be to the advantage of the pet chem business for some time to come, and to the detriment, I guess, if you're producing ethane in terms of realizations versus historic levels.
On the crude side, you've seen the WTI disconnect narrow as we discussed last year was likely to happen, and we're seeing it push now into other domestic crudes. As production continues to increase, the inability to export means you have to try to price those crudes to displace other crudes out of the refining system that are being brought in from somewhere else, and at some point, those discounts are required to incent refiners to buy that crude versus another economic alternative. That's a situation that could persist as well. The wild card there is if the policy constraint were to be lifted, now those crudes can get full market value in export markets and those differentials could disappear, which is actually why on that LLS chart comes back, because there's an assumption I think that PIRA makes in their work that the export ban is rescinded.
From our standpoint on WTI, we've been somewhat naturally hedged. The amount of WTI priced crudes we run in our refining system, roughly equivalent to the WTI priced crudes that we produce and sell into the market. We haven't been really hurt so much on that. As it pushes down into some of these other crudes, we also run those crudes in our system. As an integrated company, we do have an offset when those things happen as opposed to the pure producer who is just looking at a reduction in realization.
Anything you want to add, George?
Yeah. Specifically on the LLS one, we made a decision, and I think a very good decision a couple of years ago, to invest in a pipeline that comes from the deepwater Gulf of Mexico and goes directly to our Pascagoula refinery. For a certain amount of those barrels and a large piece of our barrels, we are about as naturally hedged as you can be with our barrels going directly to the refinery, and that's a positive. Not all our barrels, but a large percentage of them.
Yeah.
Just maybe one other thing. You saw Mike's trajectory on this differential and how it goes away. It goes back, like you said, to what we saw in West Texas, really on for many of the crudes there. In this country, when there is an arbitrage, somebody works hard to squeeze it out, and they do it pretty efficiently.
Market plans.
The markets here really work at an exceptional level. I wish I could say that for every place, but they work exceptionally well here.
I'll leave it there. Thanks.
Yeah. Thank you. I think right behind you was a question.
Good morning and g ood morning, Sir. Pat, if I could just follow up on some of the priorities of cash flow that you gave earlier. You mentioned obviously funding the dividend and the capital program are priorities, but it looks once you get to 2017, certainly you'll have a lot more cash flow than you've had these past few years. Can you talk a little bit about the balance there between whether it be debt repayment and building back a negative net debt position as you've run before, or whether it's maybe a little bit greater dividend growth or maybe even relatively more share repurchases compared to what you've done in the past?
I don't want to get specific about projections out there. I think we've been consistent in saying that dividends have priority. We'll obviously take a look at what the capital program needs to be to support future value growth. Right now, we're sitting at a 12% debt ratio, I think we have pushed ourselves, partly through the share repurchase program, into a more efficient capital structure. I don't see a need for us to back away from that, quite frankly, because I think most people, ourselves included, would have said when we had a 7% debt ratio and we had net cash, that we were under-levered. I think having a little bit more efficient capital structure would be a nice place to be if the circumstances warrant that.
Okay, thanks. You mentioned a lot about the gas sales agreements needed for FID on some of these projects. Can you just talk about what you currently see in the market? I know you mentioned the deficit when we get to 2020 or so with LNG supply relative to demand, but what are you seeing right now in the market when you're trying to market some of these projects? How do you balance marketing, call it Kitimat versus some of your expansions in Australia?
Well, I talked a lot about the gas markets, what I see is a lot of tension right now, actually, between buyers and sellers. It's easy to explain why. We're seeing very low natural gas prices in this country, whether it's customers in Japan or in Europe, they have to compete with our businesses, they're seeing the advantage of low-cost gas, they want some of it, both for their businesses and for their consumers. They're also looking at the cost of gas in the U.S. and saying, "Whoa, we could put a liquefaction plant and transport it and get it over to Japan or Korea, and do so at a competitive price." They're trying to push prices down. That's a natural thing for them to do.
I made a comment that it's one thing for that on brownfield plants where there's existing infrastructure in place. I think when you look at cost, transportation, and perhaps a longer-term view of domestic gas prices, I think you end up in a different place. Our view has been for a long time that for the Asian market, that oil-linked pricing made more sense. That's the alternative. If you think about the margin, what the alternative is, it tends to be burning oil in many cases. That's how that market grew up over time. We think the realities of costs are such that it's going to take stronger prices. If you look at some of the very low price expectations that have been cited in the media, our projects won't go ahead with those prices, whether in Kitimat or Australia.
It's going to take a meeting of the minds by customers and suppliers, or we'll see that gap widen over time. Right now, I don't think that we are market limited in selling LNG. We're supply limited, that's why you're seeing spot prices above crude parity right now. I think it's important that the industry and customers find that meeting of the minds so that our industry can continue to meet the energy needs that are out there by the 29 some countries that are now importing LNG. If we want to get a little more specific?
Well, just maybe the huge risk out there right now is that there's not a meeting of the minds. There's not economic projects created through some mechanism of their participation or the pricing. There's not a project, then there is no gas for the demand. There's only two projects, at least that I saw last year, that reached FID in the LNG world.
What do you mean?
The one in the U.S. and Yamal. It was not a lot of projects, and relative to the growth, it doesn't meet the demand in the future.
You'll note in our chart, we gave the benefit of the doubt to a number of projects that are planned in the United States, and there's still a big gap, and we think it's going to take strong pricing to make them go. Yes, that's it.
Hi, it's Iain Reid from the Bank of Montreal. Just a question about Tengiz again, John, if I could. Obviously, Tengiz is pretty important and pretty at the top of the earnings and cash flow barrel metrics you've talked about. You talked about an agreement you made with the government to allow the expansion to go ahead. I'm just wondering whether anything in that is going to impair in any way the kind of leading earnings per barrel numbers you've been reporting out of Tengiz in terms of what you need to do in order to move the project forward. Is there something else in there which should be clear?
Well, I'll make a couple general comments and I'll let Jay speak. Obviously, we've had a very good relationship with the government of Kazakhstan. We've had consistency in the application of our contract over time, and it benefits them greatly, and they know that. There's variable royalty and other provisions that enable them to be quite successful, and that's why they've supported that contract. I'll let Jay talk a little bit about going forward with the project.
Thank you. The contract that's in place in Tengiz persists, and the terms that FGP and WPMP are being built under are under the original contract. There is no change. This agreement really comes from what we were talking about earlier in terms of learning lessons from previous projects. It involved the financing of the project for the government share. It involved local content expectations. This project is heavily focused on smartly using local content. There's fab yards in Kazakhstan, which we will be utilizing, but we'll also be doing a lot of construction in the more traditional Asian fabrication yards. It involved agreements around the logistics, how things would be brought in, foreign workers' licenses.
All the things that can derail a project during execution, we wanted to reach agreement upfront and try and make sure we had clear expectations with the government on the progression of the project. It really didn't affect the terms of the project per se.
Okay. Just one other thing if I could. You mentioned 12 wells in, I think this year, which you're particularly excited about. I wonder if you can just give us a bit more details about where those wells are going to be drilling.
You mean the impact exploration wells?
Yes, the 12 high-impact ones.
These wells are across the globe. About half of them are in our focus areas, half are in these new test areas. There are a number of them in Kurdistan region of Iraq that I mentioned earlier. We've got exploration wells in the Duvernay and in the Permian, as well as Gulf of Mexico.
Okay, thanks.
Yes. Over here.
It's Faisal Khan from Citigroup again. I wonder, Mike, if you could tell us how much foreign crude that you could back out of the U.S. refining system from where you are today, and the second question is, have you looked at using the free trade agreement between Korea and the U.S. to move crude to your plants over there?
The amount of foreign crude we run in the system, it's in our annual report supplement, you can see that. We have longstanding term supply agreements with some suppliers from outside the country that are very important to us and underpin our refining economics, particularly on the West Coast with some of the crudes we bring in from the Middle East. The logistics to get domestic crudes into the West Coast refining system are pretty challenged. With good quality crudes from the standpoint of matching our refining system and a long-term relationship that's yielded very competitive crude pricing over the years, I think both we and our suppliers have been well-served by that.
To displace crudes, I think you need to see more of that happen where the logistics are favorable to bring domestic production into the refining system, which tends to be in the Gulf Coast. We really get our Pascagoula Refinery where you could see that happen. It's an economic optimization question. I mean, we're after that every day, looking at our alternatives, both domestic and non-U.S. Going forward, it's a function of those markets and the logistics and pricing as to how that balance would work out. I can't say that we've looked at using the Korea-U.S. free trade agreement to bring crudes from the U.S. to Korea, which I guess is your second question. We can't export crudes today, I don't think that the free trade agreement changes that materially.
I think until you see the export policy of the government modified, a scenario like that is unlikely. Korea's got pretty good logistics from the Middle East and other places as well, I think you're going to find places that are closer to the source of the crude that are likely to be more economic than taking U.S. crudes all the way across to Korea.
Okay. Sure.
Microphone's coming.
Thanks, John, for the follow-up. I was just flicking through the slides as you were talking. I wanted to go back to Paul's earlier question about the margin. It looks like the proportion of oil-linked production doesn't really change. The mix changes a little bit from oil to oil-linked-
The total sort of oil leverage, I guess, doesn't really change over the portfolio. Paul's earlier point, I guess, was the unit margin improvement to close the cash flow gap. Can you give us some idea as to how you expect unit margins to evolve with the change in the portfolio mix over the next three or four years? Thanks.
Well, George, are you talking about cash margin, or I mean, the cash margin, as George said, from the major capital projects that we have are modestly accretive to the portfolio. We feel very good. Now, that's actually the entire portfolio, right?
That is the whole portfolio.
That's the whole portfolio. That's why I say we feel very good about these projects. Remember, for Gorgon and Wheatstone, 75% of the gas is placed, and it's placed at contracts that are oil-linked. I hope that answers it. Okay. I think I see fewer and fewer hands. In fact, I see no hands in the air. I think we've answered all your immediate questions. I'll thank you very much for your time and attention and your investments in Chevron. Thank you.