Good morning and welcome to Chevron's 2012 Security Analyst Meeting. I'm Jeanette Ourada , General Manager of Investor Relations. We're very pleased to be here with you today, and I'd also like to welcome those of you joining us via webcast. Before we begin today's program, I have a few important reminders. First, we ask that you take a moment to locate the nearest exit. In the event of an emergency, the St. Regis staff will provide further instructions. Second, as a courtesy to everyone in the room, please silence all of your electronic devices. Finally, remember to take your name badge with you if you leave the room. You will need it to re-enter. Our program today includes a comprehensive update on Chevron.
Our agenda features presentations by Chevron's Chairman and Chief Executive Officer, John Watson, Pat Yarrington, Vice President and Chief Financial Officer, Mike Wirth, Executive Vice President of Downstream and Chemicals, George Kirkland, Vice Chairman and Executive Vice President of Upstream and Gas, and Gary Luquette, President of North America Exploration and Production. This year, we've asked Gary to join George in discussing some of our upstream assets. We'll take a few questions at the conclusion of Mike's segment, and a brief break will follow. We've set aside more time for questions later in the program. Also here with us today are Rhonda Zygocki, Executive Vice President of Policy and Planning, and Steve Green, Vice President of Policy, Government, and Public Affairs. For those of you joining us via webcast, I'd like to invite you to participate in the Q&A segments.
Please submit your questions to us by 11:00 A.M. Eastern Time through the Investor section of the company's website at chevron.com. Today's presentation contains estimates, projections, and other forward-looking statements. I encourage you to take a few moments to review the Safe Harbor Statement, which is available in the appendix of your booklets and on our website. Thanks for your attention. Now, my pleasure to introduce Chevron's Chairman and Chief Executive Officer, John Watson.
Thanks, Jeanette, and welcome both to the audience right here in the room and to those of you that are listening on the webcast. We do look forward to providing detail on Chevron's performance, our strategies, and our plans for the future. I'll provide a summary of key messages you'll be hearing throughout this morning. First, we have a strong track record of delivering results. We lead our peer group in safety, earnings per share growth, and TSR, amongst many other measures. Second, our strategies remain sound, and we have an advantaged portfolio of upstream projects that are staged to deliver growth through this decade and beyond. Third, we're focused on execution in all aspects of our business. We have the people, the processes, and the portfolio to continue to deliver value to our shareholders. Let's start on performance, where we always do with safety.
Last year, we talked at some length about Chevron's safety journey. I said we have a strong safety culture, and we work to learn from our incidents and those of others. The numbers show just that. Every key safety and environmental performance measure has improved dramatically over the last decade, and 2011 was another good year statistically. We had world-class low industrial injury rates, as you can see on this familiar chart. Similarly, a spill volume chart would show us tracking with the best in the industry. Expectations are higher than ever with the public and regulators, and of course, they should be. Despite industry-leading performance, we're not incident-free. We'll continue to learn and improve and drive toward incident-free operations. Now, let's look at our financial results. Our advantaged portfolio, plus strong operating performance, delivered record earnings of $27 billion and a return on capital employed of 21.6%.
We also had record cash flow from operations of $41 billion. We had two dividend increases in the year for a combined 12.5% increase in the quarterly rate, and we purchased $4.25 billion in common stock. We funded growth projects and added to the portfolio while retaining a very strong balance sheet. We delivered earnings growth that has outpaced our peers. This chart shows indexed earnings per share growth over the last five years for Chevron and our peers. We're number one by a wide margin. In fact, if you look at EPS growth of independents and non-energy stocks in the S&P 500 over five and ten-year periods, you would see a similar pattern. We've grown EPS faster than the vast majority of major equities. The superior earnings growth and favorable outlook for our business have translated to the ultimate performance measure, TSR.
This is the third year in a row that I've been able to tell you we've led our peer group over the previous five-year period. At 11.2%, we had nearly double the return of our nearest competitor and, of course, outdistanced the break-even S&P 500. You'll note we now include Total on this chart. We've added them to all competitor charts and plan to drop ConocoPhillips when they split later this year. Our strong performance is a result of consistent execution of sound strategies. You've seen our strategies before; they haven't changed. Today, I'd like to tell you why they remain the right strategies. Oil and gas exploration and production remain a very good business. Energy demand is growing, and we expect oil and gas will retain its predominant role in meeting the energy needs of a growing world economy. Hydrocarbons can be developed affordably and at scale.
Chevron has sought after advantages: people, technology, know-how, and relationships that can help governments and others develop their resources to fuel their economic growth. In building our portfolio, we've intentionally favored investments in oil projects and gas projects with oil-based pricing where it's possible. We've done this because the supply-demand balance for oil is much tighter than for gas. We also like gas, and the world has a lot of it thanks to discovered but undeveloped conventional resources far from markets and shale gas in North America and potentially elsewhere. In the near term, the heart of our gas strategy is to commercialize our large discovered conventional resource base through LNG, notably in Australia. We've contracted to move most of our LNG to markets with strong demand and long-term oil-linked pricing. We expect this regional pricing structure to be sustained.
Shale gas development is booming in North America and beginning overseas. The business was built in the U.S. by independents. Majors and others jumped into a hot market, sometimes giving carry interests and getting little control. In contrast, we are returns-driven and see shale gas as a long-term play in our portfolio. We entered this space at a good price in the low-cost Marcellus, getting both carried interest and control. Outside the U.S., we're using a low-cost, early-entry approach where we see high-quality shales close to existing markets. Now, downstream is a tough margin business. It has few barriers to entry. In many places, governments intervene in fuel markets, and national oil companies continue to build refining capacity into a well-supplied market. Overcapacity is slow to rationalize itself. However, a well-run downstream can create value.
We believe profitability comes from strong market positions and the right manufacturing configuration, advantaged feedstocks, and a focus on higher-growth chemical and lubricant product lines. We're shaping our portfolio accordingly. I'll also note our manufacturing capabilities help our upstream business, as raw materials increasingly require processing at the source. To sustain our advantaged offering in upstream and create value downstream, we must keep our technical edge. Technology is the key to improving recoveries from existing fields and finding new ones. We take a leveraged approach to technology. We fund critical proprietary technology while collaborating with providers for rapid adoption of technologies better developed by others. You'll hear a few examples of our technical advantages later this morning. We believe the world will need all forms of energy to meet growing demand. We'll invest in renewables where we can do so profitably without depending on subsidies.
Our geothermal business meets this test. At this point, other technologies have not. Our research continues around non-food biofuels, and we're piloting solar to steam and other technologies. In addition, we apply proven technology into our existing businesses and those of others to reduce energy use and improve energy efficiency. We've improved our own energy efficiency by about a third over the last 20 years. Our corporate strategies are clear, and they guide us well. We've taken deliberate actions based on these strategies that have shaped our portfolio. We are very heavily upstream and oil-weighted, with a strong asset base and project queue. We have a smaller downstream exposure that is competitively positioned to supply growing markets. As I've just shown you, this portfolio, combined with consistent execution, has generated outstanding results. Next, let me foreshadow some key points that you'll hear in more detail in the segment presentations.
In the downstream, as we near the end of our restructuring, we've delivered the promised performance improvement. Mike will update you on our progress and share our plans for targeted growth in chemicals and lubricants. In the upstream, George will show you our industry-leading performance across a wide range of measures. He and Gary will then walk you through our portfolio of projects by asset class. You'll see the status of our developments and gain insight into the depth of our capabilities. You'll see we're on track to deliver the growth we first promised two years ago at this meeting. We plan to grow oil and gas production more than 20% between now and 2017 to 3.3 million barrels per day. To deliver this growth, we need to continue executing our major capital projects well. We have a long history of delivering world-scale oil and gas projects in challenging environments.
All the projects on this slide were executed concurrently. Each had specific technical and execution risks. Tengiz, sour gas injection second-generation plant in Kazakhstan, is the highest pressure, highest H2S volume reinjection facility in the world. Agbami in Nigeria had the world's largest FPSO at installation. Phase 12 at our Duri Field in Indonesia continued development of the world's largest steam flood operation. Tahiti set industry records for a single piece truss spar and total well depth in the Gulf of Mexico. Peak manpower for these projects exceeded 24,000 workers. We successfully brought all of these projects online, and they're delivering as advertised. Our new generation of projects are world scale in size and scope, and we're well equipped to deal with their complexities. Construction is heavily modularized to limit on-site work, and we continue to strengthen our project management systems. Our project delivery model is very effective.
We staff a global project management organization dedicated to supporting development and execution of our largest major capital projects. This organization maintains a robust community of technical professionals from multiple functional disciplines. These professionals are embedded in our business units worldwide to provide the appropriate skills to manage and coordinate our projects. This organization has centers of excellence to ensure each and every project has access to the most up-to-date execution tools and that best practices are shared across the organization. In recognition of our success in managing capital projects, we won the Spirit of the ECC Award last year from the Engineering and Construction Contracting Association. Now, nowhere is execution more important than our Gorgon LNG project, where we're now 40% complete. I want to show you some footage of the project so you can visualize that progress. Let's roll that video.
Gorgon is one of the world's largest natural gas projects and the largest single resource investment in Australia's history. With an estimated economic life of over 40 years, the natural gas fields of the Gorgon project will play a key role in helping Chevron meet growing energy needs in Asia and Australia. The project includes the construction of a three-train, 15 million ton per annum liquefied natural gas plant on Barrow Island and a domestic gas plant with the capacity to supply 280 million cubic feet per day of natural gas to the Western Australian market. When the project is complete, about three LNG shipments a week are expected to be loaded via a four-kilometer-long loading jetty for transport to Asian markets. Gorgon also incorporates a carbon dioxide injection project, which, when built, will inject up to four times more carbon dioxide underground than any existing project in the world.
The Gorgon project is unprecedented in scale and remains on schedule for first gas in late 2014. A key characteristic of this project is its development on Barrow Island, a Class A nature reserve. We've implemented a strict quarantine program to preserve the natural species on the island for future generations. As part of our efforts to protect the environment, the Gorgon project was designed with a limited footprint and using a modularized approach. Many of the components for the LNG facilities are being prefabricated and assembled at various locations around the world and will then be transported to Barrow Island. Major LNG module construction is well underway in South Korea. The first of the pipeworks has been completed in China and Indonesia.
Work is progressing with electrical substations and transformers in Australia, gas turbines in Italy, LNG loading arms in Germany, heat exchangers in Pennsylvania, heaters and modular housing units in Thailand, pipe coating in Malaysia, major vessels in South Korea, and subsea trees in Scotland. Construction began on Barrow Island in December 2009. Since then, our infrastructure and site preparation projects have steadily advanced. Clearing and site preparation at the Gorgon gas treatment plant are complete. Key underground and civil works have begun, and construction of the liquefied natural gas tanks is well underway. We successfully completed an extensive dredging program, which will provide safe shipping access to Barrow Island. The program met strict environmental requirements to protect coral and the marine environment. In July, we reached a major milestone when the Pioneer Materials Offloading Facility was connected to the Barrow Island causeway.
The facility has started receiving vessels, which has doubled our supply capacity between our Perth supply base and Barrow Island. To help minimize environmental impact on the Barrow Island shoreline, work progressed to drill and place the feed gas pipelines and support lines under the shoreline. We've also begun to lay the pipelines that will link the wells being drilled in the Gorgon and Io- Janz fields to the gas treatment plant. Our new ultra-deepwater semi-submersible drilling rig, the Atwood Osprey, arrived in the waters off northwest Australia in June 2011, marking the beginning of the project's two-year development drilling campaign. Drilling is well underway, with the Osprey now working on its fifth development well in the Gorgon field. As the size of the on-island workforce increases, the construction village has grown. This state-of-the-art facility will help us house a workforce of around 5,000 during peak construction.
Village's cyclone-rated accommodation clusters help reduce the time and cost associated with demobilizing and remobilizing our teams when cyclones occur. 2012 will be an important year for the Gorgon project. We're preparing for the arrival of the first major modules on Barrow Island. We also expect to start construction of the domestic gas pipeline and begin drilling in the Io- Janz field. Chevron is poised to increase production 20% by 2017, and Gorgon is the centerpiece of our growth story. As the project ramps up to full capacity, its production will plateau at 450,000 barrels of oil equivalent per day. Given our ongoing exploration success, we see potential for future expansions. With this growth profile, Chevron is well-positioned to supply energy to the growing economies of Asia for decades to come.
I hope that the video helped you. You know, George and I meet every month with the project manager and the line management, not just on Gorgon but on other projects, and it's been wonderful to see the progress and the amazing things that our people do on not only this project but others. George will share more specifics on this project a little bit later. Before turning the mic over to Pat, let me reiterate the point I started with. We're performing well. We have compelling strategies and plans to deliver growth, and we're highly focused on execution to realize value for our shareholders. Now, I'll turn it over to Pat to cover our financial highlights. So, Pat.
Thank you, John. I'll start by reviewing our 2011 financial performance. You'll see that we continue to distance ourselves in a positive way from our peers. I'll also cover our future investment plans and our financial priorities. Now, 2011 was a record year for Chevron for both earnings and operating cash flow. Earnings for the year were $27 billion, over 40% higher than in 2010. Operating cash flow was $41 billion, 30% more than in 2010. Over five years, we've generated earnings of nearly $100 billion and cash flow of $146 billion. Now, I'd like to do a little compare and contrast to three years ago when oil prices hit their peak and talk about value versus volume. In 2008, most of the industry last experienced record cash flow. This past year, our operating cash flow was 39% higher than three years ago.
A key driver was the 6% increase in net production, as seen on the lower chart. Comparing cash flow growth with production growth for the group, it's clear that we've been value-driven rather than volume-driven. This is a fundamental principle underpinning every decision that we make. Let's look at another cash flow metric. This chart shows cash flow per share indexed to 2006 and shows five years of data since then. In 2010, we moved beyond the top of the peer group band, and in 2011, we substantially widened the gap relative to our nearest competitor. This is the result of having an advantaged portfolio and superb execution. These projects delivered high-value volumetric growth, growth that took advantage of a strong oil price environment. The net result has been prolific cash generation, which is allowing us to simultaneously reward our shareholders, fund our future growth, and bolster our financial position.
Let's take a look now at returns. The chart on the left is our growth in capital employed versus our peer group, again indexed to 2006. We've been investing heavily into a strong queue of projects and growing the business. On the right is our ROCE over time. We've demonstrated outstanding performance on both an absolute and a relative basis. We have substantially narrowed the ROCE gap with our nearest competitor, growing at a very fast pace and producing absolutely stellar returns. Now, we create value for our shareholders by having the right strategies and funding attractive capital projects consistent with those strategies. Our capital program does precisely that. For 2012, our program is $32.7 billion. Here you see some additional insights into our investment priorities. On the left is spending by region.
Spending continues to be geographically diverse, with weighting towards Asia-Pacific as a result of our Gorgon and Wheatstone projects. On the right is spending by category. Upstream accounts for 87% and downstream for 11% of the total program. I commented last year about our relative capital intensity, and I'd like to comment again with another year of data. This chart shows relative reinvestment, basically total investment divided by cash from operations. We've had strong capital programs in recent years because we've had excellent projects to invest in. We've invested nearly $97 billion in upstream over the last five years. Even with this headline figure, we're not as capital intensive as many of our peers. We've been disciplined on the investment side, and the projects themselves have been tremendously successful cash generators.
Having a strong investment profile is a good thing if the capital is being invested wisely, and we are investing wisely. Now, let me turn to our financial priorities. You've seen these before. There's no new news here. Our first priority is to maintain and grow our dividend. I'll come back to that in just a moment. Our second priority is reinvesting in the business. We have a high-quality, high-quantity development queue. This is a position that separates us from our peers, and we have confidence that these projects will earn good returns and will drive our future growth. Our third priority is to maintain our financial strength and flexibility. We view a strong balance sheet as a competitive advantage. Finally, we are committed to returning any surplus cash to our shareholders. We have a solid track record here.
Frankly, we balance these objectives quite well, and our TSR performance confirms that. Returning now to dividends. Our dividend growth pattern is superior. We've had 24 consecutive annual increases. I'm sure you took notice of our two dividend increases in 2011. Combined, this represented a 12.5% impressive increase in the quarterly rate. Since 2004, when oil prices first began to appreciate, our dividend has grown at a compound annual rate of 11%. This has significantly outperformed the 3% compound annual growth rate of the S&P 100 over this same time period. This shows our pattern of sharing the benefits of our performance and price appreciation with our shareholders. Since 2004, we've had over $30 billion of share buybacks. Moving now to our balance sheet, we've clearly been very prudent with our capital structure. We ended 2011 with a debt ratio of 7.7%, obviously an ultra-low level.
At year-end, we were in a $10 billion net cash position. We had the strongest balance sheet in the peer group. We've deliberately kept our financial structure with some flexibility. Now that we've taken some multiple substantial long-lead projects to final investment decisions, it's important that we be able to consistently fund them and to weather periods of price and margin volatility. Let me be clear. We do have a positive view on long-term oil prices. However, we need to be completely capable of handling temporary excursions to lower oil prices, similar to what happened in 2009, even though we see these as low-probability events. Said another way, our balance sheet is a risk mitigator. John just showed you our superior record on TSR, and we are tremendously proud of that. What's interesting, too, is the balance we've shown between share price appreciation and dividends.
The share price appreciation goes to my earlier point that we've invested in the right projects and grown the business the right way. In addition, we've had attractive dividend growth. None of our peers over this five-year period can match this absolute result, nor the balanced manner in which it was achieved. We're committed to delivering disciplined growth and shareholder value for a long time to come. Now, I'd like to turn it over to Mike to discuss our downstream business. Mike.
Thank you, Pat, and good morning. It's a pleasure to see everyone again and to discuss Chevron's downstream. I'll break my comments into three sections. First, I'll review our strategy and the business environment. Then I'll cover our performance in 2011, and I'll close with a discussion about growth. Based on our beliefs about the underlying industry fundamentals, for several years, we've been preparing for the kind of conditions we face today. We remain focused on improving returns and growing earnings. The foundation is a relentless commitment to operational excellence, operating safely and reliably each and every day. We've created a more focused refining and marketing portfolio in geographies with more attractive underlying fundamentals, with the asset scale, flexibility, and conversion complexity to ensure cost competitiveness and maximum margin capture. We're targeting growth in the business segments that offer the best combination of opportunity and returns.
The fundamentals underlying the various downstream business segments reflect the realities of the global economy. On the left chart, you can see the outlook for transportation fuels continues to be challenging, with relatively modest demand growth over the next decade and a history of surplus capacity. Margins are likely to remain under pressure, with the impact most acute in mature markets. On the right chart, you can see that both petrochemicals and premium base oils are expected to experience strong demand growth over the next decade, outstripping existing capacity. These markets are likely to experience tighter fundamentals, leading to better margins, as this demand growth will be satisfied only through investment in additional capacity. We've been reducing our exposure to refining and increasing our exposure to both petrochemicals and lubricants. Taking a closer look at the fuel's demand outlook, it really becomes a tale of two worlds.
The emerging economies of the non-OECD, especially Asia, are expected to see the majority of demand growth, while the mature economies are expected to lag behind. It also becomes a tale of two fuels. Distillates are expected to see the lion's share of the growth, while gasoline growth remains much more modest. I'll remind you that in the past, I've shown you that our system is more oriented to hydrocracking, which can produce more distillate than our competitors. We're well positioned to benefit as distillate demand accelerates. Now, let's look at our fuel's footprint. We're advantaged here, too. Equivalent distillation capacity is an industry measure that reflects both the throughput capacity and conversion complexity of a refinery. It's a good measure of the economic capability of a refining system. As you can see on this map, almost three-quarters of our total equivalent distillation capacity is in the Pacific Rim.
On the right side of this chart, you see this data on a competitive basis. We are well positioned in the Pacific Rim growth market, with much less exposure to the rest of the world than our competitors. The demand outlook for the higher-return segments of petrochemicals and lubricants is strong. Over this decade, petrochemical demand growth is expected to increase by more than 40%, primarily in Asia and the Middle East. We've been involved in multiple new petrochemical plants in the Middle East over the last few years. In lubricants, we expect premium base oil demand will grow by more than 80%, with Asia and the Americas driving the growth. We'll use our new base oil plant at Pascagoula to better balance supply to the Americas and free up more Richmond barrels for Asia.
I'll say more about both of these segments in a few minutes when I discuss growth. Let's move to a review of performance. 2011 was another good year, both operationally and financially. In 2010, I outlined a commitment to improve R&M returns of 7% over three years by 2012 through improvements in refining, marketing, portfolio, and costs. We've exceeded that commitment at the two-year mark. At the end of 2011, actual returns are up 8% as a direct function of the aggressive improvements we've captured in these controllable aspects of our business. Overall returns are up even more. When you take into account the improvement in industry margins, actual returns are up more than 14 percentage points. This excludes chemicals and non-recurring items, both of which were net positive over the period. I'd like to update you on some of the specific actions driving this improvement.
We committed to $700 million in refining improvements through cost reductions and efficiency gains and controllable margin and yield improvements, while maintaining our focus on safe and reliable operations. I'm pleased to report that 2011 results already exceeded our 2012 target. We've captured a total of $850 million before tax through yield and margin improvement, lower contractor spend, better turnaround and maintenance efficiency, and reduced catalyst costs. We've increased our improvement target for 2012 to $1 billion. Every year I've been here, I've talked about reliable operations as a top priority. At the end of last year, we received the most recent Solomon benchmarking report covering full-year 2010 performance for refiners around the world. Chevron ranked number one in refinery utilization for the third consecutive time, covering a span of the last six years, continuing to separate ourselves from the competition.
Hot, cheer, reliable is the bedrock of our operations, and we intend to sustain world-class performance. This year, we've launched specific initiatives related to turnaround planning and execution to further improve reliability performance. The Solomon survey reports a number of other benchmarking metrics as well. The left chart shows the Solomon Energy Intensity Index, a measure of energy efficiency in refining, with better performance indicated by a lower index. We've improved over the last decade and have been in a virtual tie with the leader for the last eight years. Refining is an energy-intensive process, and energy efficiency is key to success. The right chart shows net cash margin, a measure of cash margin after operating expense. On this chart up is better. Over the last decade, we improved our ranking from number six to number two and expect to deliver top-tier performance regardless of the margin environment.
Moving to portfolio, in 2011, we made further progress in our commitment to focus our footprint. We exited 27 countries last year, primarily in Central America, the Caribbean, Europe, and Africa. In addition, we divested the Pembroke Refinery and our UK and Ireland marketing businesses and 13 other product terminals. Since 2005, we've generated more than $8 billion in cash as a result of portfolio actions. Our work is not yet finished. We've signed deals to sell businesses in Spain, eight more countries in the Caribbean, and our Perth Amboy, New Jersey facility. I expect all these transactions will close this year. We've signed and already closed on the sale of Alberta Envirofuels, an iso-octane plant in Canada. GS Caltex is soliciting bids for their power division, which is large and profitable but not core to their strategy.
Reviews of our Egypt and Pakistan fuels businesses and Caltex Australia Refining are underway, with decisions on the future of those operations expected this year. On this chart, I've combined updates on a number of measures that I've previously reported to you. I just mentioned we exited 27 countries last year. We're now at more than a 60% reduction from our starting point in 2006. We further reduced terminal count and service station ownership, both of which are now down by about half. We reduced our workforce by another 2,300 and are now down 36% on R&M headcount over the last three years. Volumes, on the other hand, have decreased by a smaller amount, and equity refinery production is now much better balanced with total sales. We've put greater emphasis on core markets. We've simplified our model.
We've reduced costs while retaining scale where we have competitive positions, all designed to deliver stronger returns. Our focus is on value, not volume. All this work has translated to the bottom line. In 2011, our adjusted R&M earnings per barrel were $2.21, the best among our peers for the second consecutive year. We delivered a 14.3% adjusted ROCE for all of downstream and chemicals, which we expect to rank number two among our peers when final 2011 capital employed data is available. I'm pleased with the strong, competitive financial performance we've delivered. At the same time, we've been restructuring and solidifying our base business. We've also been laying the foundation for profitable growth. Earlier, I mentioned the segments we want to focus on. Now I'll tell you about our plans to grow earnings and what you can expect to see in the future.
I've talked about optimizing our portfolio from a geographic perspective as we've narrowed our footprint. Let me describe what it looks like from a business segment point of view. These two bars show the relative capital employed of our business segments in 2011 and how that will change in the coming years. You can see the shift to a more balanced portfolio, with relative weighting shifting from refining and marketing to the other higher-return segments. While the shift is modest at first, it will continue over time. Through our portfolio activities, both divestment and investment, we're building a more geographically focused and more segment-balanced earnings portfolio. Now, I'd like to share a closer look at some of the specific areas we intend to grow in Asia and in the chemicals and lubricants businesses. I'll start with Asia, where our strong position is anchored by GS Caltex at Yeosu.
This is a world-class refining and petrochemical complex, combining the world's fourth-largest refinery and third-largest aromatics plant. For comparison, this facility has nearly as much feed capacity as Richmond, El Segundo, and Pascagoula combined. The refinery can process over 850,000 barrels a day of crude and other feedstocks. On the upper graph, Yeosu is consistently first quartile in Solomon utilization and has deep integration of fuels, petrochemicals, and base oil. In the lower graph, you can see the impact of our recent and ongoing investments in heavy oil upgrading as equivalent distillation capacity continues to grow. This is a world-class facility with the scale, configuration, and performance to take full advantage of Asia demand growth. We've been steadily improving our capability to generate stronger returns from this asset, and we intend to continue to do so.
Turning to petrochemicals, we have a strong foundation in Chevron Phillips Chemical, with 38 plants worldwide and major production centers in the U.S. and Middle East. CP Chem has delivered top quartile return on assets among their peers for the last three years. When their new ethylene cracker in Saudi Arabia starts up this year, CP Chem will be the largest producer of high-density polyethylene in the world, with the leading proprietary technology. This startup will make CP Chem the largest IOC petrochemical producer in the Middle East. They're rapidly moving toward a feed decision this year for a world-scale ethylene cracker on the U.S. Gulf Coast. This would be the first greenfield facility to take advantage of the feedstock associated with U.S. shale gas production. Land has been allocated, preliminary design and technology selections have been made, emissions credits have been secured, and permitting is underway.
Low-cost feedstock is essential for competitive success in chemicals. The chart on the right shows ethylene cash cost in various geographies and includes both ethane and NAPA feedstock for North America. CP Chem has 100% of its ethylene capacity in the Middle East and North America, a tremendous advantage in this market. Lubricants is a high-return, high-growth segment of our business. Chevron pioneered the premium base oil market when we developed our proprietary ISO dewaxing technology. Virtually all of the global demand growth for lubricants will be in the premium base oil sector. We're currently the number one producer of premium base oils in the Pacific Rim, with plants at Richmond and Yeosu. When the Pascagoula plant comes online next year, we'll be number one in the world, and we're considering further investment in production at Singapore.
This is part of our overall lubricants portfolio, which includes finished products with particular strength in heavy-duty motor oils, where earnings are up four-fold over the last five years, and returns have consistently outpaced R&M. We'll leverage our leading technology and market positions to continue to grow this business. Chevron is the only oil company with a wholly owned specialty chemicals business which manufactures high-quality additives for lubricants and fuels. Oronite is a top performer in this segment. We have a strong global supply chain, strong relationships with original equipment manufacturers, and world-scale manufacturing plants and technology centers in all key demand centers. Our Singapore plant is the largest additives facility in Asia. Oronite has market share leadership positions in a number of market segments and has delivered better returns than our fuels business over the past three years.
Oronite is well-positioned to capture growth in this higher-return segment, particularly in Asia, where we're further expanding capacity to meet this demand. We're investing in each of these businesses to meet the demand growth I talked about earlier and reshape our portfolio. At Pascagoula, our world-scale premium base oil plant is expected to start up next year. In Saudi Arabia, CP Chem's world-scale ethylene cracker and derivative units are in the final stages of commissioning and startup. Last month, we took FID on a multi-year expansion of our Singapore additives plant. The first phase is targeted to start up in 2014. At Yeosu, a new vacuum gas oil conversion unit is slated to start up next year, improving the yield of high-quality products as part of our third heavy oil upgrading project there. To close, I'd like to summarize three points. First, our strategy remains sound.
We've expected a challenging market environment, and we've prepared for it. We're improving returns through executing the fundamentals, building a smart and more focused portfolio with assets that have the scale, flexibility, and complexity to be competitive. Second, our performance is strong. Safety and reliability are at industry-leading levels. Earnings and returns are top tier, and we've met or exceeded our performance commitments. Finally, we're investing in carefully targeted growth projects in the right markets and segments that will strengthen and diversify our earnings to sustainably deliver competitive results. We've demonstrated we can deliver top operating and financial performance, and I'm confident we'll deliver further improvements again this year. That concludes my remarks, and now I'd like to ask John and Pat to rejoin me on stage.
All right. Thanks, Mike. We'll take some questions now. A couple of rules. First, please hold your upstream questions until later in the program. You'll get plenty of chance later after George and Gary present their remarks. Next, if you have a question, please raise your hand and I'll call on you. Wait till you get the microphone before you ask your question, and we ask that you state your name and company affiliation. Out of respect for your colleagues, limit yourself to one question and a quick follow-up if necessary. Okay, let's get started. Arjun, you had your hand up first.
It's Arjun Murti with Goldman Sachs. I think it's a question for Mike or maybe you, John, regarding the refining restructuring. I certainly appreciate the divestment in the Atlantic Basin. It's a challenged market. It's never been your big area. You've highlighted the Pacific Basin as your core focus, and I get the Caltex, Australia. You've taken a hard look at that. At the end of the day, between Pascagoula, Saudi, Singapore, and South Korea, it looks like you really are more focused on a series of advantaged assets as opposed to Pacific Rim or Pacific Basin per se. My question is really, where does that leave California? Australia is a challenged market. You're looking at it. The Atlantic Basin was a challenged market. You've mostly gotten rid of it.
I realize California is the heritage and it's a bigger position, but it looks like your strategy is focused more on individual assets, and I'm just wondering where that leaves California. Can you somehow spin it out, IPO it, sell it, do something to that asset? Thank you.
Let Mike talk a little bit about California, but let me make a couple of comments first, Arjun, if I could. First, we highlighted our interest in the Korean refinery, but we also have interest in refinery in Singapore and Thailand, and we do have a regional strategy. Yes, we have a legacy basis in the United States and in California, but there are connections between these markets, of course. I'll tell you, we're not likely to IPO something, so I'll maybe take that one off the table, but I'll let Mike talk about the competitiveness of our California refineries and how we see that fitting in the portfolio.
Yeah. Arjun, a couple of things. First, your comment on advantaged assets. You're right. We do want to invest in strong advantaged assets and continue to build on those strengths.
The Pascagoula investment is to serve a global base oil market and to really have a global position there, and that's important with the customers in that segment and the qualifications and standards for lubricants. The Pascagoula investment actually allows us to serve our European and Latin America markets more efficiently than we can out of Richmond and Yeosu and potentially out of Singapore and focus further growth into that area as we have a global base oil business. The Saudi petrochemical investments feed straight into Asia demand for those products, and they really are focused on those growth engines. When you get down to California, it is a place where we still have the two largest refineries. They're both very complex refineries. They're both very competitive refineries. We have the strongest brand position in California by a long shot. We have a tremendously strong market position.
We've got good integration with our upstream in Southern California with the position in the San Joaquin Valley crude, and we've invested to run more San Joaquin Valley heavy at El Segundo. We have strong integrated economics underlying a good part of our California portfolio. In a market that may be subject to some pressures as the economy there has faced some challenges, we have a number of competitors that are in much weaker positions than we are. While it may not be the focus for growth investment in our portfolio, we intend to keep those assets and our brands and our position in a strong competitive posture, and we'll let others make the tough decisions in those markets.
Yes, over here.
Great. Thanks. Evan Calio, Morgan Stanley. We're, in many ways, witnessing a North American energy renaissance that has highlighted in some new and some historical ways the value in integration. My question relates to the unique integration element of Chevron with both the upstream U.S. North American natural gas NGL production and chemical as a consumer on the NGL side. I mean, how do you look at potential parallel growth of what is, and I'm not trying to get too into the upstream portion of the question, but it's related to your planned growth at CPC on the chemical side. How do you look at the opportunity of a twin growth that may give you a more unique position in looking at that molecule versus someone who's just betting on the price of that molecule where you're a natural consumer?
It's an interesting point. I think it was last year at this meeting that I said in my 30 years with the company, I've never seen a time when it made more sense to be an integrated company. We've talked about disadvantaged feedstocks and the need for manufacturing at the source and things of that sort. What we've seen since that time is only a greater opportunity for integration in the petrochemical segment, as you described and as Mike discussed. I think there is an opportunity to take some of these feedstocks. There is a supply, some supply shifts taking place. You're seeing cheaper crude in the center of the country. You're seeing more liquids put in the business. You're seeing more NGLs. You never thought you'd see the opportunity for dramatic growth in the petrochemical business in this country again, and yet there's that very real opportunity.
We haven't talked about some of the crudes that we take from South America and otherwise into Pascagoula. We do have increasingly more crudes that require refinery configurations compatible with those crudes, and we often test those crudes in our refineries and develop a market through our refineries. I haven't talked about the people side of the integration that's there as well on things like our Gas-to-Liquids project in Nigeria and Angola LNG, the bunch of downstreamers helping start that up. The integration takes place in many forms, and I think you just highlighted another example that we're seeing this year. Mike, I don't know if you have...
I think you've covered it.
Okay, any other comments? Okay, thank you. Go right here in front. Yes, Paul. The lights are a little bright. I can't all see you, so that's why we asked you.
Hi. Paul Sankey from Deutsche Bank. I'd like to ask some questions for Pat if I could, John. Pat, you seem to be saying that the cash that you're running on the balance sheet is really extremely conservative in case there's a major downturn in oil prices. I think there's a perception that there may be a concern about CapEx overruns or even the potential for acquisitions is why you're holding such a conservative balance sheet. If I understand you correctly, what you're saying is that you want to retain the AA in almost any macro scenario. Looking back at 2009, which was a pretty extreme low, obviously, you made $22 billion in cash from operations around, and you got about $6 billion of dividends. We know that you're about $27 billion net of CapEx a year.
It still seems excessively conservative to me, even when I look at the most extreme downside scenario, for you to be holding so much cash on your balance sheet, especially when the stock looks relatively undervalued against your competition. Was that a question?
There are a lot of statements in there.
I'll take some of those. You did cover quite a bit of territory there. First, our cash distributions this year to shareholders, based on the quarterly rate that we're at so far, will be over $11 billion, including repurchases. Certainly, we're cognizant of returning cash to the shareholder, and we have that pattern of increasing the dividend, which, as the pattern of future earnings and cash flow permit, we'd be delighted to continue to do. We understand cash distributions are important. Our projects are on schedule. The capital budget is significant this year. There are really three factors that can influence cash flows very significantly. There's sort of the downstream margin environment. There's gas prices, both U.S. and abroad, and then there are oil prices. Certainly, we're seeing very strong oil prices now. As Pat indicated, we've got significant projects underway.
We want to be sure that we can continue to fund them. Being really blunt about it, when it comes to acquisitions, we have the balance sheet to do acquisitions, whether we had less cash or more cash now. We're in the business of bringing on new opportunities into our company, and our balance sheet is strong enough, whether it has the current level of leverage or somewhat less than that. I really don't think the balance sheet is going to determine whether we acquire an opportunity like we did with Atlas last year. It'll be the economics that drive any acquisition. When we've done acquisitions, I think you've all been pretty pleased. We've acquired Unocal. We acquired Texaco. We acquired Gulf. All those have worked out well. We're fortunate that right now we don't have to do an acquisition. We're value-oriented.
We'll add to the portfolio as we find the opportunities. I've said before, I don't intend to pile up cash on the balance sheet indefinitely. That's why we've increased the dividend significantly. That's why we've increased the pace of repurchases, and we have the capacity to do that again, should we see the environment that dictates that, net of the potential downsides that could hit the commodity market. As we get closer to these projects coming online, the need for us to carry the amount of net cash on our balance sheet will diminish.
Effectively, it is that the situation of concern about the level of CapEx and the need to hold cash to avoid, if CapEx overruns occur for example, it's more about that than about.
It's not the level. It's the stage we are in the process where we have a number of, for example, our preproductive capital net right now, capital that is not yet producing, is in the high 20s. It'll be in the low 30s over the next year or two. We will see a lot of that cash coming to us, and some of the risks of a commodity price downside will have dissipated. Mark.
John, thank you. Mark Gilman, Benchmark. I had a specific question for Mike. With some of the changes that we've seen in the North American crude landscape or market, just calling the minor changes is probably an understatement. Your Burnaby asset takes on kind of a different-looking role. It would seem to me it might offer some potential. I was wondering about your thoughts on that subject.
All yours.
If you look at our portfolio, our big refineries tend to be on the water and somewhat distant from where these interesting feed dynamics have been most acute. Burnaby and our Salt Lake City refinery both are positioned with infrastructure connections to the interior of North America, and both have been able to find a different crude market than they've historically seen and have been able to take advantage of that. These are not our largest-scale refineries nor our most complex refineries, but they have been highly profitable and are assets that have been very contributory to our performance overall. Burnaby is the only refinery in British Columbia. It is connected by the Transmountain Pipeline up into Alberta, and it's a well-run facility that has performed very well for us, like I say, as has Salt Lake City.
What about growth plans, though?
You know, physically, it is in a fairly tight footprint. It has primarily residential neighborhoods around it, and we've got limited plot space there to consider anything from the standpoint of major expansion, Mark. It certainly, in terms of small de-bottlenecking and other types of projects, which we've done historically over time, offers a certain amount of opportunity. If you're thinking of a new plant or something like that, I'm not sure the plot space there would be.
Is there greater potential at Salt Lake?
Salt Lake has a little bit more plot space, and we're investing right now in upgrading our crude unit reliability and performance of our crude unit there. Salt Lake has a little more room for expansion.
I think that's three. Why don't we try Ed next here?
Maybe a follow-up to Paul's question for Pat. You've shown us in the slides how good CapEx leads to growth in cash flow and also improvement in returns. You only tend to give us sort of one year's CapEx at a go, and I appreciate there's a lot of uncertainty in terms of the CapEx. As we sit here, could you help us with a range over the next couple of years, maybe a rate of growth of CapEx that you expect?
Go ahead.
Okay, sure. You know, we deliberately only go out one year, and there's obviously good rationale behind that, and it has to do with just fluctuations on the cost side of the equation. I would say, too, on projects that we are moving into out of FEED and into FID, there can be some delays in that second and third year or fourth year plan that we don't anticipate early on. For those reasons, we have kind of constrained ourselves to giving you just one year of C&E outlook. Having said that, we give you an awful lot of information about which projects, the cumulative time period over which those projects are going to be spending money. We've said Gorgon is a 60-month, five-year program. Wheatstone, same kind of thing. We give you an awful lot of the building blocks for you to build your own profile.
2012 and 2013 are going to be high LNG construction years, and we've said that. This year is $8.5 billion in LNG. Next year is going to be also a heavy LNG year. We also have significant outflows associated with our deepwater Gulf of Mexico projects. We give you an awful lot of the pieces and tell you how much is major capital projects, how much is base business, how much is exploration. You've seen an increase there. We're hopeful that you can add them up and come to something in the same ballpark. I think it's safe to say that we will have robust spending for the next couple of years.
Okay, thanks. We'll try one right here. I'm sorry, I can't see who it is right behind you.
Thanks. Faisel Khan with Citigroup.
Yeah, hi, Fais.
How you doing? If you can elaborate a little bit more on the ethylene project in the Gulf of Mexico, when would that come online? What's the target market for that production? How do you think this North American market is going to evolve over the next few years for ethylene and polyethylene?
Yeah, Mike, talk a little bit about it. Mike, you want to give a few more details?
Sure. You know, depending upon which forecast you look at, ethane production associated with increased gas production is expected to go up 60%, 80%, 100%, enough to support multiple greenfield crackers. We would expect, and you hear other people talking about other projects as well, CP Chem's project, from everything that I know, is far into the process as anybody, so that puts us in a good position to capture some of that first mover advantage in terms of greenfield plants. Current timeline would put it online in 2016 or 2017. I don't want to be more definitive than that because we really haven't even taken the FEED decision. If you were to forecast on kind of other project history, that's the general timeline I think that you would see.
In terms of the markets, it remains to be seen exactly how the markets may set up then. There's certainly a market in this hemisphere for polyethylene. There's strong markets in Asia as well. The logistics, when you've got the kind of cash cost position that you would with advantaged feedstocks, you can take and actually put those products into markets around the world very competitively with naphtha-based crackers into almost any polyethylene market that you would choose. There's a large global market for these products that is growing, and you tend to optimize your logistics and netbacks into whatever your final market is. There are plenty of options for markets for that facility.
Okay, one more question before the break. We'll just go right behind. Is that Paul?
Yeah.
Okay, I see you very well. Paul, go ahead.
Thank you.
Just identify yourself for the benefit of the audience.
Paul Cheng, Barclays . This is probably for Mike. W ith the change in the crude market and the natural gas market in the U.S., the gas-oil ratio seems like it's going to remain pretty advantageous for using the gas feed. If I look at your major refineries, the three, Pascagoula, El Segundo, and Richmond, is that opportunity to take advantage of that kind of ratio, including maybe idling the reformer? I think the whole market is long-octane, and that if we idle the reformer and that using, instead of using refinery gas, using natural gas feed as for power generation or that building hydrocracker, that kind of opportunity, is there anything there to fundamentally change the probability on those three major core operations that you have? Thank you.
Covered a lot of territory there. You want to try?
Yeah, you point out, I think, an interesting dynamic, which is with the relative advantage that natural gas has, there's a whole host of things that historically in a refinery you would look at one way that you now look at another way. How you want to fire equipment, how you want to generate hydrogen, which units, particularly with the changing feedstock dynamics and the yield structure, as you look at feedstocks over time, where you see the upgrading margins. There are undoubtedly opportunities in there, and we are looking at that. I mentioned we've already got the strongest hydrocracking position relative to FCC or fluid cat-cracking in the industry. This is kind of in the realm of, it's not totally normal business, Paul, it's the kinds of things we're constantly looking at from an optimization standpoint.
You trade off feedstock optionality with operating costs, with capital costs, and you look to debottleneck or to tweak your configuration and balance all of those out. There are opportunities in there. They are not large capital projects that I would envision at this point. We're being pretty circumspect about further expanding the amount of capital employed in our U.S. R&M business because of the demand dynamics in the marketplace. We'll continue to be focused on how do we get strong returns and value out of those refineries and have a pretty tough bar in terms of large-scale capital investments into the big refineries. We'll keep them safe and reliable. In terms of capacity expansions or massive new investments in conversion, I wouldn't anticipate that in the U.S. refining system.
Okay, thanks for those questions. I know there were some hands up. We'll be back after the final presentations and take questions on all subjects. We'll take a 10-minute break. Remember to take your badge with you so that you can get back in. We'll be back in 10 minutes. Thank you.
We're about to start. If we could get to our seats, I would say a big thank you. The good news is I can't see individuals too well, so I can't call your name. Good morning. It's good to be back and review Chevron's upstream business. We had a great year in 2011, and today I'll provide insights on last year's performance and outline our plans for 2012 and beyond. First, an overview of Chevron's upstream portfolio. Chevron has upstream operations in nearly all the world's key hydrocarbon basins. Our current production and resource base are about evenly divided across four regions. Production is approximately 2.7 million barrels a day, and crude reserves are about 11.2 billion barrels. In addition to its geographic diversity, our portfolio also includes a variety of asset classes: deepwater, heavy oil, unconventional, sour oil and gas, and LNG.
Today's presentation will focus on three themes: strategy, performance, and growth. To begin, I'll highlight our key strategies and how they influence our investment plans. In the performance section, I'll summarize our 2011 accomplishments and our leading competitive position. Finally, I'll close with an update on our future plans, covering near-term exploration and the projects that will underpin our production growth over the longer term. Gary Luquette will cover an important part of our growth story: our deepwater, heavy oil, and unconventional businesses. Let's review our strategies. These have remained consistent for many years, and you've all seen them before. We focus on six strategies: delivering operational excellence, maximizing recovery from our base business, selecting and executing with excellence the right major capital projects, growing our resource base through continued exploration success, commercializing our large undeveloped natural gas resource base, and capturing new opportunities.
Through consistent execution of these strategies, we've delivered leading operational and financial performance. All these strategies are about resources. How we're managing them and growing them is critical. Our preference is to grow the resource factory organically, which is why we like exploration and early entry resource opportunities acquired through business development. We believe that by applying our technology and execution capabilities, we create the greatest value from these resources over the long term. Once we have the resources, we invest in the right projects, projects that deliver production with superior financial results. Now let's take a closer look at our 2012 C&E budget. Our 2012 upstream C&E budget of $28.5 billion is focused on building legacy positions with major investments in LNG projects, the deepwater Gulf of Mexico, and shale opportunities around the world.
For this year, 10% of the upstream budget is targeted for exploration. About 60% is directed to major capital projects. Our LNG spend is about $9 billion, primarily focused on Gorgon and Wheatstone, and we expect 2012 and 2013 to be peak years for our global LNG investments. The remaining 30% of our program is for base business. This amount is up about 15% as a result of the recent Marcellus acquisitions and a strong opportunity set across the base business. I'd also like to point out that over 85% of our North American investments are directed at oil projects. In summary, we're executing the right strategies, we're making the right investments, and as you'll see, we're delivering leading results. Now I'll cover our 2011 performance and competitive standing. In 2011, net production was 2.67 million barrels per day, 90,000 barrels per day lower than 2010.
The year-on-year increase in Brent oil price from $79 to $111 reduced our net entitlement by 32,000 barrels per day. Our base production declined about 4%, which is right on trend. We've captured significant gains by reducing our declines to this level and have maintained this rate for several years. Base production would have even been better if a few external events had not happened. The combination of decline and external events reduced production to 103,000 barrels per day versus 2010. Growth of approximately 45,000 barrels per day came from our major capital projects, including a great ramp-up at our Thailand Platong Gas II project. Major capital project production gains were less than anticipated due to slower ramp-ups at Perdido, Tombua-Landana, and a one-year delay at Caesar-Tonga, which you have just heard just started production in the last couple of days.
Next, I'll highlight some of our recent base business performance. Our base business processes have been in place for six years, and we can now quantify their impact. We've consistently improved efficiency and reliability, resulting in a cumulative addition of 100,000 barrels per day of production and with strong producing margins. This gain is equivalent to adding another major field to our portfolio. Our outlook for base decline continues to be about 4%, a significant improvement over the 5%- 6% we experienced in the past. Last year, we showed you a subset of 30 greenfield major capital projects that together should recover more than 5.5 billion barrels. In 2011, we sanctioned another four major projects, increasing the total expected recovery to more than 7 billion barrels, and we increased the portion currently booked as crude reserves from 40% to nearly 50%.
Our portfolio of major capital projects is an essential part of increasing our crude reserves. This has been true in the past, and it's certainly true for the future. Now let's take a closer look at our crude reserves. Last year, on an SEC basis, Chevron added 1.7 billion barrels of crude reserves, net of price effects, for a replacement ratio of 171% and increasing our total crude reserves to 11.2 billion barrels. More than 50% of the net additions are a result of the Wheatstone project sanction, the acquisition of Marcellus assets, and the initial booking at Jack St. Malo. Our long-term goal is to deliver reserve replacement that exceeds 100%. Over the past three years, we've replaced 102% of production, and over the past 10 years, we've averaged 94%.
While our reserve replacement will fluctuate from year to year, our portfolio should deliver the reserves that allow us to grow production over the long term. Next, I'll turn to our 2011 major capital project startups and ramp-ups. In 2011, we began production at three major capital projects and continued to ramp up at another four. Our three project startups were an expansion of the upgrader at Athabasca Oil Sands project in Canada. We began operations on the fourth train in the Karachaganak Field in Kazakhstan, and we also began production at the Platong Gas II project in Thailand. Growth barrels were also added from the ramp-up of key projects, including Perdido in the deepwater Gulf of Mexico, Frade in Brazil, Mafumeira Norte, and Tombua Landana in Angola. These projects enhance our performance, supporting production, adding reserves, and delivering strong margins.
Now let's review our competitive position in realizations and cost. Our realizations have exceeded those of our competitors for the second consecutive year. Our portfolio by volume is about 70% weighted to oil. Globally, our crude realizations have a strong connection to Brent, and in the U.S., are predominantly tied to Mars, Louisiana Light, and Kern River benchmarks, all of which have traded to premiums of WTI. In 2011, these factors have driven Chevron's realizations to more than $5 higher than our closest competitor. Last year, our upstream cost went up about $4.50 per barrel, and that was primarily driven by royalty and taxes other than on income, which increased costs by about $3, and fuel, which increased costs by about $1. Upstream cost increases last year were largely driven by higher oil prices. Complete competitive data for 2011 is not yet available.
However, we expect to remain very competitive in the peer group. With a leading position in realizations and a competitive cost structure, we have delivered unmatched cash margins. In 2011, Chevron's cash margins were nearly $39 per barrel, roughly one-third of Brent. This relationship between cash margin and price has been very consistent over time. Based on available data, our per barrel cash margins are more than $10 ahead of our nearest competitor. This performance is a result of the strength of our portfolio and our focus on selecting and executing the right projects. 2011 data for all our peers is not yet available, but based on disclosed earnings, we expect to retain our significant advantage. I'd now like to focus on earnings and return on capital.
Our 2011 earnings of $26.36 per barrel outpaced the nearest competitor in our peer group by more than $7 and the average of our competitors by $9. As you would expect, I'm very pleased with our leading position and the growing gap separating us from our competition. As we've pulled away from our integrated peer group, we've also outperformed the major U.S. E&Ps. Complete competitor ROC results for 2011 are not yet available. However, our return on capital employed of 29% is expected to rank at the top of our peer group. We've delivered top-tier returns over a long period of time. Our upstream ROCE has averaged 25% over the past five years. In summary, we're investing wisely, executing with excellence, and as a result, leading our competition on key operational and financial metrics. Now I'll discuss our growth plans, beginning with exploration.
To achieve our long-term growth objectives, it's critical we continue to add acreage to our portfolio. Since late 2009, we've added about 18 million acres, including nearly 7 million acres in 2011. These additions represent nearly all key asset classes: deepwater, shallow water, and unconventional. About 40% of the total acreage additions have been in shales, including 2 million acres in North America. Next, let's look at our exploration results. Since 2002, exploration investments have added about 10.5 billion barrels of resources. The map shows the location of key 2010 and 2011 exploration discoveries. In 2011, we announced four natural gas discoveries in Western Australia, each adding to our significant gas position in the prolific Carnarvon Basin. We were successful at the Moccasin prospect in the deepwater Gulf of Mexico, our first deepwater exploration well following the drilling moratorium.
In addition, our success continued in Congo, where we announced two oil discoveries early in 2011. We've also seen strong results from our unconventional resource portfolio. About 60% of 2011 resource additions come from success in the Wolfcamp trend in the Permian Basin. Now let's look at how our exploration results compare to our competitors. According to Wood Mackenzie, Chevron remains the leader in exploration resource replacement. As shown on the left chart, between 2002 and 2010, Chevron had a 90% resource replacement ratio, significantly higher than our nearest competitor and 59% higher than the competitor group average. Also, according to Wood Mackenzie, Chevron's underlying finding costs for the period 2002 to 2010 were $1.83 per barrel, the lowest in our competitor group and 37% less than the average of our competitors. This combination of consistent resource additions and capital efficiency clearly provides a competitive advantage for organic growth.
Between year-end 2004 and 2011, our unrisked resource base grew by about 9 billion barrels, or 17%. Over that same timeframe, we have produced about 8 billion barrels and divested about 6. In addition to our exploration success, we've had some other noteworthy resource additions in 2011, in particular our legacy positions in the Permian Basin and the partition zone between Saudi Arabia and Kuwait. The bar graph on the right shows the geographic diversity of our 65 billion barrels of unrisked resources. In 2012, we planned to invest about $3 billion in exploration and to drill about 90 exploration and appraisal wells worldwide. This is a significant increase in spend and activity levels from 2011, reflecting increased activity in new acreage and a continuation of our focus area program.
We plan to drill about 15 impact wells this year, including four wells in Australia and two in the deep water Gulf of Mexico. In our test areas, we have plans to drill offshore Liberia, deep water China, the east coast of Canada, and the ultra-deep gas play on the Gulf of Mexico shelf. Notably, our conventional exploration program accounts for over 80% of the exploration spend. Now let's review our unconventional exploration plans for 2012. Unconventional activity accounts for about 16% of our total exploration spend. We have a busy year planned for 2012. We're currently drilling shale wells in the U.S., Canada, and Poland, and plan to spud wells in Argentina, China, and Romania later this year. In addition to our drilling activity, we also have 2D and 3D seismic acquisition planned to further evaluate our acreage.
In North America, we have a strong set of unconventional opportunities, which Gary will review in a few minutes. Now let's take a look at our project inventory. In total, we have about 100 projects in our portfolio where Chevron's net investment exceeds $250 million. This slide covers two aspects of our project inventory. First, the chart on the left shows the projects by development phase. We have a good pipeline of projects in evaluation, design, construction, and ramp-up. This distribution of projects ensures continued growth and progression of our resources into reserves and then into production. Second, the chart on the right shows the project spend distribution over the next six years by asset class. We expect that LNG will comprise more than 35% of the total investment, while deep water projects account for nearly 30%. I'll now provide details on our near-term project startups.
Over the next three years, 28 projects with a Chevron share of $250 million are scheduled to start up. 11 of these projects, as highlighted on the map, have a net Chevron investment exceeding $1 billion. This year, our major capital project startups include Angola LNG, Usan and Agbami II in deep water Nigeria, and Tahiti II in the deep water Gulf of Mexico. In 2013, our significant startups are at Shandong Bay in China, EGTL in Nigeria, and Papa- Terra in Brazil. In 2014, our startups include the Jack St. Malo, Bigfoot, and Tubular Bells projects in the deep water Gulf of Mexico, and of course, Gorgon in Australia. Next, let's look at our upcoming FIDs. Over the next three years, 12 projects with a Chevron share of over $1 billion are expected to reach final investment decision. During this period, expansions at Tengiz and Gorgon should reach FID.
These 12 projects will deliver growth over the coming decades and play key roles in achieving our production objectives. Now let's take a closer look at the production that will drive our growth. We set a long-term production target to reach 3.3 million barrels per day by 2017. Of our targeted growth, almost 1 million barrels per day is currently in construction or design, the largest two projects of which are Gorgon and Wheatstone. There are another 220,000 barrels per day of projects in the evaluate stage, including the Tengiz future growth project. I'd also like to point out the producing wedge. This reflects a base business decline of about 4%, consistent with our guidance and our recent performance. With about two-thirds of our targeted growth already in construction, we have the momentum and the confidence to deliver this production growth.
In addition to our growth objective, we remain focused on delivering significant value. Currently, our realizations and margins benefit from production that is about 80% oil price linked. We expect this linkage to remain consistent through 2017. With our deep queue of high-quality projects, our realizations and margins continue to benefit from a strong connection to oil. We've organized the remainder of our growth section differently this year, focusing on five of our key asset classes: deepwater, heavy oil, unconventional, sour oil and gas, and LNG. In deepwater, heavy oil, and sour oil and gas, we are expected to remain strong. We're strong there today, and we see this going into the future. In LNG and unconventionals, we have a smaller presence today, but one that will grow significantly. Now Gary will review our deepwater, heavy oil, and unconventional assets. Gary.
Thank you, George. Good morning. It's good to be with you here today. George mentioned that this next segment is going to be broken down into asset classes, and that's exactly what I'm going to do. We're going to start with our worldwide deepwater asset class. We've had a strong presence in deepwater for many years and are focused on maintaining this going forward. Our exploration success has translated into world-class producing fields such as Tahiti in the Gulf of Mexico, Agbami in Nigeria, and BBLT in Angola. These projects, along with many others, are delivering about 375,000 barrels per day. Our success has led to a strong queue of major capital projects, resulting in a full pipeline that is expected to grow our deepwater production to 470,000 barrels per day by 2017. Let's take a closer look at several of these projects.
We have three deepwater projects in various stages of early startup. In Nigeria, Usan, with a peak capacity of 180,000 barrels per day of oil, began production in February. Ten wells have already been drilled, and we expect peak production next year. Also in Nigeria, we expect to start production at Agbami II. This was originally planned for 2011. However, strong production performance in existing wells kept the FPSO at capacity throughout the year. We're presently drilling stage two wells to maintain that production plateau. In the Gulf of Mexico, Tahiti II is progressing despite some delays due to the moratorium. The topside water injection equipment has been installed, and we commenced injection in February. We're currently drilling and completing additional producers, which are expected to reduce field declines and improve ultimate recovery. Looking a little further out, let's review several of our 2014 startups.
At Jack St. Malo in the lower tertiary trend, construction continues. Fabrication of the hull and topsides is underway, and late last year, we began drilling the initial development wells at both Jack and St. Malo. In addition, the nearby third-party operated Julia Field will be tied back to Jack St. Malo hub, increasing our capital efficiency and investment returns. A noteworthy aspect of Jack St. Malo is that its design provides a template for future developments. We're already evaluating its potential use for a Buckskin and Moccasin co-development. Bigfoot is also making significant progress. The hull and the topsides fabrication has begun, and we are currently drilling the initial set of production wells. In 2011, we reached final investment decision on Tubular Bells. This development is estimated to have a total cost of about $2.3 billion, and production will peak at about 40,000 barrels per day.
Like Bigfoot, Tubular Bells will develop a Miocene reservoir. These are characterized by relatively high flow rates and high recoveries. Next, let's take a look at the impact of technology on our deepwater developments. When we drilled the initial discovery wells at Jack and St. Malo, it was clear the lower tertiary trend held a significant resource base. We also recognize the importance of incremental recovery through technology. Our industry's experience is that big fields tend to get bigger, and with continued development and application of technology, the reserve base in the lower tertiary trend will continue to grow. We sanctioned Jack St. Malo on the basis of existing technology and recovery of less than 10%. With incremental technologies, we see the potential to increase ultimate recovery to more than 20%.
By doubling recovery, we have effectively added a half billion barrels to Jack St. Malo, and we're looking forward to applying what we learn here to other lower tertiary developments. Now let's turn to heavy oil. We've been a leader in heavy oil and enhanced oil recovery techniques for decades. Currently, our heavy oil production is more than 460,000 barrels per day and accounts for about 17% of our total production. This asset class is characterized by low decline, long-lived assets, which are key to our base business and provide a stable source of production, earnings, and cash flow. By 2017, our heavy oil production is forecast to be about 400,000 barrels per day, declining annually about 2.5% during this period shown. Longer term, however, we have considerable growth potential in this asset class from the partition zone and also in Latin America.
Now let's take a closer look at several key heavy oil assets. Chevron has decades of experience in the application of thermal recovery. Steam flooding, first used in the mid-1960s in the San Joaquin Valley, provided our first full-scale application. Since then, the Kern River field has produced more than 2 billion barrels of oil. Today, the recovery factor is about 60%, and we're driving this towards 80%. Our success in the San Joaquin Valley provided lessons that we've applied to Indonesia's Duri field. Initiated in the early 1980s, the Duri steam flood more than tripled daily oil production, enabling the field to hit 2 billion barrels of cumulative production in 2006. So far, we've recovered about 40% of Duri's oil in place, and we're working on our 13th aerial expansion of the field.
We're taking lessons from San Joaquin and Duri to the partition zone, where more than 50 years of production from the Wafra Fields' first Eocene reservoir has recovered about 5% of the original oil in place. We've been piloting steam flooding at Wafra since 2007. The large-scale pilot in the first Eocene is performing very well, and a separate pilot program has been initiated for the second Eocene reservoir. Next, let's review some of the technology that makes all of this possible. What sets Chevron apart is our extensive practical knowledge and hands-on experience. We use proprietary facilities to generate low-cost steam and our own distribution systems to ensure high-quality steam is delivered to each injection well. Coupled with state-of-the-art reservoir heat management, our approach has led to a sustained advantage. In the San Joaquin Valley, we've had steam oil ratios that have consistently outperformed our main competitors since 2006.
Since about 25% of the cost of each barrel is for fuel to generate that steam, we've created an advantage in both operating expense and, of course, in margin. We're also focused on the application of this expertise around the globe. We built our International Heavy Oil Center of Excellence in Bakersfield, California. Here, we're developing the next generation of heavy oil experts, training teams from Indonesia, Venezuela, and the Middle East, who will all play key roles in supporting international heavy oil developments. Just like we do for deepwater and heavy oil, we'll take a global approach to unconventional resources. This is consistent with our strategy to get into the right plays early and to focus on organic growth. This asset class is early in life, and our production today is relatively small, but we see it as an area of significant long-term growth.
We currently hold more than 8 million acres of leases with unconventional potential. These are distributed around the world and include the U.S. and Canada, as well as emerging areas like Argentina, China, and Europe. We also have a leading position in some of the key liquids-rich shales. With our legacy acreage, we're able to make selective investments to improve our understanding of sweet spots. In the case of our North American dry gas assets, we're able to preserve options for better market conditions. Since we closed on the acquisition of Atlas and other acreage in 2011, we built a strong position in the Marcellus and Utica shales. After an active Marcellus drilling program in the past year, our early well results indicate a high-quality resource, and reservoir outcomes are exceeding our expectations. With natural gas prices where they stand today, we're investing at a measured pace.
Our objectives are to drill to earn leases where justified, to use our remaining $1.3 billion carry, and to grow our execution capability. We're positioned to further ramp up drilling and production once the gas market improves. In the Utica, which has liquids potential, we are one of the largest leaseholders with 600,000 net acres. We're executing our exploration and appraisal activities in 2012, including drilling wells, acquiring seismic, and thoroughly analyzing nearby competitor activity. Our objective is to increase our understanding of the Utica's potential and be in position to accelerate development when appropriate. As companies buy into shale plays like these, they make headlines. What doesn't make headlines is that we've held the acreage in multiple shales for decades. Let me show you an interesting chart. In the lower 48, we hold more than 3 million acres in unconventional plays, most of which are shales.
In contrast to some of our competition, much of this acreage is either held by production or fee, allowing us to pursue the most attractive projects instead of drilling to earn leases. Our positions are also well placed with many of the plays located in wet gas and liquids trends. We've already had noteworthy success. As George mentioned, in the Midland Basin Wolfcamp play, we recognized significant resources in 2011, and we plan to participate in more than 200 wells this year as we continue to develop our acreage. In the Delaware Basin, we also have a significant position: more than half a million net acres of Wolfcamp shale and more than 100,000 acres of Avalon shale, both of which are wet gas plays and part of our legacy leasehold. This year, we plan to drill up to six operated wells.
We'll also continue to leverage our non-operated positions with an additional 16 wells planned to accelerate evaluation of this play. In addition, we anticipate completion of proprietary 3D seismic that will continue to advance our understanding of the area. As you can see, the depth of this portfolio allows us to focus development on the most profitable opportunities. Now let's take a look at our international shale assets. Since our initial entry into Poland in late 2009, we've built an impressive position of more than 4 million acres across Central Europe. In Poland, we finished drilling our first well in February and also completed our initial 2D seismic acquisition program. We'll soon spud our second Poland exploration well located in the Frampol block. Operations are ongoing, and we're continuing to progress permits and well locations for additional drilling during the year.
In Romania, we've acquired 2D seismic and expect to start our drilling program late this year. As you may know, a moratorium has been placed on hydraulic fracturing in Bulgaria. We're engaging with the government and believe that industry will be able to successfully allay their concerns. However, in the unlikely event we're not successful, we have minimal financial exposure in Bulgaria. Another area where we're ramping up activity is in Canada's Duvernay shale. In 2011, we increased our position to about 250,000 acres. This is another shale with significant liquids potential. Early results from our drilling program have been encouraging, and we plan to drill and complete additional wells as part of our continued evaluation of this play. In Argentina, our shale position is located below our currently producing El Trapial field in the Neuquén Basin and consists of about 110,000 acres.
Our leases there are well positioned with liquids potential. We recently extended our lease to 2032, and our plans are to begin initial exploratory drilling this year. In China, we're currently participating in a joint study agreement with Sinopec covering about 940,000 acres. We've already completed acquisition of 2D seismic and spud our first well earlier this year. As you can see, we have a lot going on in deepwater, heavy oil, and unconventionals. A common theme amongst these asset classes is the development of technology and competency in one project or location, which we can then deploy to multiple projects globally. Now with that, I'll hand it back to George.
Thank you, Gary. I'd now like to review the final two asset classes: our sour oil and gas and LNG categories. Today, our sour oil and gas production is about 350,000 barrels per day, about 85% of which is from our Tengiz field in Kazakhstan. By 2017, our sour oil and gas production is forecast to be nearly 500,000 barrels per day. Let's take a closer look at the projects that underpin this growth. Construction is underway on expanding the Caspian pipeline. This will allow us to increase exports via pipeline and enable the next expansion of the Tengiz field, the Future Growth Project, or FGP. We're looking forward to entering FEED at FGP this year. Key hurdles have been removed, and we're building on what we learned at SGI/SGP. Once online, FGP is expected to increase production by 250,000- 300,000 barrels per day.
In Central China, the Shandong Bay project is leveraging our expertise in sour gas. The project consists of three gas fields with a potentially recoverable resource of 3 trillion cubic feet. Although we've had a delay getting access to land, we expect to reach startup in 2013. Now let's review our LNG portfolio. Currently, LNG makes up about 7% of our production. By 2017, our LNG portfolio, driven by Gorgon, Wheatstone, and Angola LNG, is projected to reach 460,000 barrels per day. These projects are major contributors to growing production towards our objective of 3.3 million barrels per day. Beyond these initial projects, we see additional growth from expansions at Gorgon and Wheatstone, and we're pursuing other opportunities such as the Gendalo-Gehem project in Indonesia, which is currently in FEED. Let's take a closer look at our key LNG developments.
The startup of Angola LNG is a big step in Chevron becoming a major producer of LNG. Currently, all systems are mechanically complete, feed gas is available, and we are performing final commissioning activities. We expect the first cargo will be loaded during the second quarter. Once at peak rate, the facility is expected to produce about 175,000 barrels per day of oil equivalent. LNG from the project will be marketed globally, flowing into the markets that generate the greatest value. Next, I'll focus on the Gorgon project. As you saw in the video, construction at Gorgon is well underway. We've completed more than two full years of construction and are now approximately 40% complete. We've made significant progress in 2011. We've completed dredging, we've been drilling development wells, and construction activity has ramped up around the world. We have a very active year planned for 2012.
The first module for Train 1 is expected to arrive on Barrow Island. In addition, we plan to start construction on the domestic pipeline and begin the completion operations on the Gorgon development wells. We continue to hold our cost estimate of $37 billion, and startup is expected in 2014. This will be the first year that we'll have a considerable amount of construction activity on Barrow Island, providing the opportunity to better understand labor productivity at the plant site. We'll be monitoring productivity and the impact of foreign exchange rates during the year. These factors will determine any potential change to our cost forecast. We currently have about 70% of our equity LNG sold on long-term contracts and are planning to increase this to approximately 85%- 90% before startup. Now let's look at Wheatstone, our second LNG project in Australia.
Wheatstone was sanctioned last September as a two-train, 8.9 million ton per annum LNG development. This project is expected to cost $29 billion. Activity is ramping up. We've awarded more than $30 billion of contracts and construction of roads and key infrastructure is already underway. About 60% of our equity LNG has been sold on long-term contracts, and we're planning to increase this to approximately 85%- 90% before startup. Our plan for 2012 is focused on completion of the initial pioneer camp and to cut first steel on the platform topsides. Let's turn to our Australian exploration program. We have the largest portfolio of exploration acreage in the Carnarvon Basin. We've had a long string of successful exploration wells in Australia, 13 successes out of 14 wells drilled since 2009. These wells have added a total of 7 TCF of resources, more than 1 billion barrels of oil equivalent.
We plan to drill four impact wells in Australia in 2012. With our sustained exploration success in Australia, we continue to gain momentum for LNG expansions. We plan to intercede on the first expansion on the Gorgon project later this year and are evaluating additional expansion potential at both Gorgon and Wheatstone. Now, let me close by returning to our 2017 long-term production guidance. Earlier this morning, John mentioned that we're on track to deliver our production target of 3.3 million barrels per day in 2017. Remember, we first set this target early in 2010 at a time when oil prices were $62 per barrel. As you know, oil prices impact our production. On this chart, we've recast our production to show our performance on a consistent price basis. As you can see, we're on track with some years above the forecast and some years below.
Many of you also like to look at actual prices, so let's go to the next slide. Here we show production at actual prices, actual oil prices once again. First, I'd like to point out that in 2010, when oil prices rose to $79 per barrel, we held our 3.3 million barrel objective fixed, effectively increasing our production target. Second, when looking at our production with actual higher oil prices, you'd expect us to trend slightly below. Remember, this is a good thing because higher prices enhance the value of the total portfolio. We are confident that we are on track to achieve our long-term growth objective while delivering superior financial performance. I want to thank you for your attention, and now John will come up for a few closing remarks. John?
Okay, thanks, George. You've heard a lot today. Let me sum up our value proposition. We have an advantaged portfolio. We are upstream weighted, and our development projects are attractive value-adding investments. In the downstream, we have a streamlined and efficient asset configuration that's very well suited to take advantage of selective growth opportunities. We've previously demonstrated our ability to bring multiple world-class projects online concurrently. We remain focused on execution and are well equipped to manage our projects. Versus our peers, our revenue stream is more driven by oil prices than natural gas prices. As we ramp up LNG production, this pattern will be maintained through oil-linked LNG pricing contracts. George mentioned earlier that our cash margins have consistently been about one-third of Brent in recent years. We expect this relationship to continue as we deliver our current generation of growth projects.
This is production not just for volume's sake but for value. Our development projects are on track to deliver compelling volume growth at good margins. This translates directly to cash generation, and with higher cash generation, our capacity to increase dividends and maintain our peer-leading TSR is enhanced. We've shown you our history of delivering both share price appreciation and dividend growth, and we're committed to continuing that profile going forward. Needless to say, we belong in your portfolio. Glad we can agree on that. Now I'd like Mike and Pat to also join us up here, and we'll be happy to take your questions, not just on upstream but on other matters as well. I'll start over here. Yes.
Hi, it's Kate Maynard of JPMorgan .
Yes.
You've laid out the 3.3 million barrel a day production objective, and you've maintained a $79 oil price this year as well as last year. I can appreciate that in the short term, you've given the production sensitivity to an oil price change of 1,000 barrel equivalents a day per dollar oil price change for 2012. Can you talk about whether that relationship holds into 2017 and specifically whether it's oil price past dependent, so whether there's also a temporal component that might make the sensitivity wider as you look more and more years out? Thanks.
A couple of questions in there. We've chosen to keep the target constant, the price constant, so we don't vary our objective every year because basically the projects that we have are well known, and we're on path to deliver them. The exact amount of production will vary, of course, with price. The difference between $79 and $111, which was the average last year, is about 40,000 barrels a day. The amount can vary. George, you can talk about some of the ins and outs of the contracts and how this can change from year to year.
Yeah, first off, every quarter from now on, just like in the past, we will give you a new estimate of actual impacts and forecasted impacts. My best guidance between now and 2017 is, though, is this 1,000 a barrel. In this price range up to $111, we think that 1,000 barrels per dollar is the appropriate guidance. We think once again, a 1,000 barrel impact with a dollar in production. To give you a little context of that, 10 barrels, and I give this one, Paul, because you of the little sound I heard there when I mentioned that. 10 barrel impact makes 10,000 barrels. $10 impact makes a 10,000 barrel a day impact. That represents for us about a 0.3% impact on our production for a $10 movement.
Remember, we've told you that our cash flows and our earnings increase, and definitely our cash flow increases by about one-third of the rise. It's tied to Brent. That means we get on 99% of our barrels, we get the rise of $3.30 on that 10. We are very price influenced in that sense.
Yeah.
Okay.
If you take away nothing from our presentation today, I hope you take away that we're focused on value, and when prices rise, you get a little bit less production, but there's an overwhelming impact on our profitability and on cash and earnings and all those things that I know you care a great deal about. Why don't we start with the next one over here? Yes.
Hi, it's Iain Reid from Jefferies. George, quick question on the on Tengiz. I think compared to what you told us last year, the FEED has slipped by about, I don't know, a year compared to what you talked about last year. I'm just wondering what the impact on your long-term production planning is of Tengiz. Do you still expect to bring it on stream in 2017, and if it slips out to 2018, what's the impact on your 2017 target? Thanks.
Yeah, we actually haven't changed our guidance very much. As you know, we've been working through issues with the government so that we could move the project into FEED. We expect to get into FEED here shortly, and we have startup planned for 2017. It's a little bit tighter pace than before, but we actually have a project this time that we think will be, it's certainly a gas injection project that's very similar to what we've done previously. We're not building sulfur plants, and we've been readying ourselves for FEED.
Can I just follow up quickly on the partition zone project? You talked a lot about that last year, and I just wonder whether you're still kind of optimistic about that, or is it just a pilot now, or is it a kind of full phase expected by 2017?
George, why don't you talk about our progress there?
We've done the first phase of the first pilot, which was injecting into one of three zones in the Eocene, the first Eocene reservoir. We have now recompleted into the second zone and are looking for response in the second zone, one level up higher in the reservoir section. That injection just started towards the end of last year. We should have response within about 12 months and start getting a read on that. We've also started up another pilot, taking some of our steam capability to try to move forward a pilot in the second Eocene. We've got all those trying to assess really the response to the steam. Our expectations would be that we would develop this huge field in phases, in stages, similar to what we did in Duri.
I would expect developments that would be in the probably the plus or minus 1,500 acre developments at a time. We're trying to progress the first stage of that. We're not quite ready to go into FEED for it, but I would expect we would be in FEED on that first stage within the next 12 months.
Thank you so much.
What sort of volumes that might be? Sorry to.
I think that was. I'd rather wait till next year to talk about that if I could.
I got you too. We're talking in the back there. Yes.
Hi, thanks. It's Blake Fernandez with Howard Weil. I'm just curious, many of your peers have become a lot more active on the divestiture front as of late, and you've outlined some of what you're evaluating on the R&M side of the business, but just corporate-wide, could you talk about how you're viewing divestitures going forward? Thanks.
Sure. Certainly, Mike has been knee-deep in that subject for a long time. I think he talked at some length about the divestitures and the rationalization to our downstream portfolio. Most of that was disconnected marketing assets. On the upstream side, when you look at the portfolio that George showed you and the profits that we're making per barrel and cash flow per barrel, we've got a great portfolio. We prune the portfolio from time to time. We just sold some assets in Alaska, for example. We're certainly, when we get to a point where we don't think we can add much to the assets in place or we don't think there's much potential from advancements in technology, more than willing to sell assets.
One of the things I hope you noticed in Gary's presentation is a lot of companies got out of the onshore business in the U.S., and we stayed. Certainly, we're performing well in Bakersfield, but a lot of that unconventional resource is because we held on to the acreage that we have, and the application of technology is now making other horizons developable. We're thoughtful about acquisitions, and we're thoughtful about divestitures, but we're more than willing to part with things when we don't think we can add much to it. Let me try one over here. Yes.
Hi, it's Robert Kessler, Tudor Pickering Holt. Sorry, it's a fairly specific one for me, but does the recent relative underperformance at the Perdido regional host field give you some pause with respect to your own operated Lower Tertiary developments, Jack St. Malo, and onwards into the future?
Perdido's been making some progress recently. Why don't I let Gary talk a little bit about Perdido and how that may or may not impact our view?
Right. In the case of Perdido, it provided a lot of rich lessons learned around deploying new technology and making sure that you have a robust qualification process in place before deploying that technology. I think it's convinced us even more that we can be successful in the lower tertiary trend, and we can apply lessons learned from that operator's experience at Perdido to improve startup and ramp-up performance at Jack St. Malo and hopefully at Buckskin and Moccasin. Just to bring you current in case you're not, we have now worked our way through most of the issues that were plaguing Perdido early on, and that facility has been setting record production rates essentially on a weekly basis now as we finally stabilized that plant and worked that technology situation through.
Just maybe to add a comment onto that, recognize that the issues at Perdido were not reservoir related. These were all surface facilities or near surface facility related, and our teams have worked together, and there's great progress. That area has been, I think, a great learning, but it doesn't really reflect back to the subsurface.
Just real quick, as a follow-up then, the record from last year looks like 41,000 barrels a day out of 100 for capacity. What's the recent record then?
I think you probably need to check with the operator, but my latest data is they're averaging around 90,000 to 95,000 barrels a day, OEG, on a sustained basis now.
Thank you, John. Pau Sankey again. George, you mentioned a couple of places and then didn't say more about them. One was the Congo. Secondly, in Brazil, can you talk about what you think the long-term outcome will be of the incident that occurred there? Thirdly, are you concerned that maybe your scale of developments might be leading you to operational problems given Brazil and Nigeria?
George, why don't you talk Congo, and I'll come back and talk about the other two, okay?
Congo, we've had good discoveries there. Total is the operator. I think you're talking probably about the Moho projects. We've had good exploration success. The oil is there. The project is there. We have issues that we've got to resolve on the fiscal side with the government. I'm confident once we get past those agreements that we will have a project there that will be moved forward. A lot of confidence in that. There is plenty of resource to make a good project.
As far as Brazil goes, I think it remains to be seen what the future holds for our business there. We've been in Brazil for over 100 years in different areas of the business and have had historically very good relationships there. Now, when we come into any country, they have very high expectations. They know we're the best, and they expect the best from us in terms of how we develop projects, our health, environment, safety record, and a host of other things. If we have a spill like we did, they're disturbed by it. I'm disturbed by it. On the other hand, our people behaved very responsibly, and I talked about that at the first quarter call.
The source of the leak was stopped within four days, and since that time, we've permanently sealed the well and have been working with regulators to make sure that they understand exactly what happened. I think we're getting some of our messages across, but Brazil is a diverse community. They have a strong environmental ethic. They have differences between regional and federal governments, and we'll have to see. I think for Brazil, they've had a very nice pattern, if you look over the last 20 or 30 years, of selectively involving international oil companies, but we need to be treated fairly, and we need to be treated consistently. The rhetoric has been high. Hopefully, we'll be able to work through those issues, and we'll be a player in Brazil for a long time, but it remains to be seen.
No concerns that you have, with the amount of CapEx and development that you're doing, that operationally, there may be a pattern developing of problems?
I mean, we have one operator project in Brazil, which is the frigates project.
I mean, globally, what with the Nigeria problems?
Oh, globally, our operations are strong around the world. I said at the outset of our presentation that we have the best safety record in the industry, very strong spill record, steadily reducing those spills, defining the bottom of the industry. The Nigeria incident is a very sad incident, and I talked about that at the end of the call. That's fired out. We're drilling the relief well now, and we've been working very closely with the government. You notice a very different pattern of response from that government. They understand the strong things that we bring in Nigeria, and our relationship is terrific with the Nigerian government and elsewhere for that matter. Okay, why don't we go try a new one? Faisel, go ahead.
Thanks, Faisel with Citigroup. You talked about how you expect LNG pricing in Asia to kind of remain linked to oil, but you also talked about how there's a lot of gas in the world. I was wondering if you could elaborate why you think this pricing dynamic will kind of remain the way it is, especially given the recent deal we saw with KOGAS in the U.S.
Long question, the short answer is we have always had great diversity in the pricing of natural gas. We have a mismatch between the resource that's been discovered and the demand in the markets that exist. Unlike oil, it's not as easy to move. It's expensive. You have to build significant facilities, either long pipelines or in most cases, LNG facilities. Typically, companies aren't going to go forward with those projects without underpinning it with a pricing arrangement that will work for the longer term. That pricing arrangement is a function of supply and demand. What we've seen in recent times is with the tragedy at Fukushima in Japan and some of the policy decisions that are being made in Germany and elsewhere is that the demand for gas remains robust, demand for LNG remains robust, and we feel very good about the contracts that we have.
George, you're very close to the subject. Any specific comments you want to add?
Just reinforced, you know, gas markets are very regional. The U.S. is very different. It's got domestic supply, and domestic supply is available. If you get to Asia, you don't have that situation. LNG is a replacement energy for either coal or oil or nuclear, and it really doesn't have any direct gas-on-gas competition except from an external basis of LNG. All these markets are different, and then Europe's different once again because it has got diversity of supply, but it still needs outside sources. All the markets are different, and they're driven a little bit different because of that.
Yeah. Mark.
Thanks, John. Mark Gilman, Benchmark. Two questions, one for Gary, one for George. For Gary, you've got two Miocene development projects in the queue, Tubular Bells, which I guess I have some doubts about, and Bigf oot. The industry's experience with the middle and lower Miocene development projects, to say it's been a little mixed, would probably be an understatement. What have you done in terms of the pre-development type activity to try to assure to the best of your capability that the kind of disappointments that have plagued others don't impact those two projects? George, a simple, straightforward question. It's my understanding that you have no sales contracts for Angola LNG. I'm a little curious as to why that's the case, and do you intend to remain essentially a spot market supplier?
George, why don't you take the simple, straightforward one first, then let Gary take the long.
Because it's actually the one that's more complicated. Angola LNG was predicated on sales to the U.S. market, actually to be delivering gas to Pascagoula to an LNG receiving terminal there. It really makes absolutely no sense to deliver any more gas to the United States at this point in time. We've reached agreement in almost to the final level in Angola to allow us to redirect that gas to the best markets in the world. What we anticipate is that we will take that gas to Europe or to Asia. We've got the ships that allow us to do that as a part of that project. We will move that gas to other markets around the world. It's in all partners' and governments' vested interests to move that gas somewhere else. That's my expectation that we will be doing that.
After we get a little runtime on this plant, I would expect we would then look at some longer-term contracts. Remember, Angola LNG is not your average gas well type of LNG project. It's really heavily associated gas, associated gas from both south of the Congo Canyon and gas that's going to come from us north of the Congo Canyon in our Block Zero operations. That gas is very rich. If you'll notice on some of the slides we had up there, you see big oil tanks and big propane tanks, LPG tanks. It's got a lot of liquid content. We'd like to get a little bit of runtime. It's probably going to be pretty hot at first, hot gas, high BTU. We'd like to get a little runtime, and then we'll make our market a longer-term market plan.
At this point, it's going to be and all the operations, we just would like to get some runtime on it. We don't have all those contractual issues resolved with the government yet. Mark.
Okay, thanks.
Okay, it's Miocene. Okay, maybe I'll tie back to something you said, John, around our project mammoth capability. Whether it's a Miocene, a lower tertiary, whether it's an LNG project in Australia, our approach towards our development projects is one and the same. In the case of these two Miocene projects, we only go to FID when we have confidence that we pick the right development concept and that we can execute that project with excellence. That holds true whether it's Chevron operated, which in the case of Bigfoot it is, or in the case of Tubular Bells, which is now a Hess operated project.
In the case of the Tubular Bells project, we've had significant influence on concept selection, and actually through some early intervention on our part, we changed concept selection, and now we have a concept that we have a higher degree of confidence that we can execute on budget and on schedule. We're working quite well with that operator, augmenting their resources and providing the expertise that we can bring to the project. I mentioned in my presentation that our typical Miocene wells produce at higher rates and have higher recoveries than the lower tertiary trend. I have those expectations for both Bigfoot and Tubular Bells.
Just one other thing, to build on Gary Luquette's comment on that. Remember, we have blind faith that we've had on production and good experience with it. At Tahiti, both Miocenes, both perform well, both have operated well. Both of them operated projects by us. Our confidence is probably greater today on those than what it was prior to these operations.
Yup.
Ed Westlake, Credit Suisse . Shifting to shale, you mentioned 175,000 barrels a day of non-conventional resources. You've laid out that you've got liquid acreage in the Permian, in the Duvernay, in the Utica, etc. Just how much of that 175 do you think is from liquids, just as a rough guess? That's a simple question. The broader one is, what would you say to critics who suggest that Chevron doesn't have the organizational capacity to be successful, particularly say in North American shale, in terms of having enough people to access land or technology, etc.?
I'll take the latter one and let Gary follow up on that and the simpler question. We've got capability. Remember, we have had a short business for some time. Certainly, we added to our portfolio by bringing on Atlas, and we mentioned hundreds of people. More fundamentally, though, we've been doing hiring all over the world. In fact, half the technical hires that we did, we've done over the last few years, have been experienced hires. We are a great draw for people where we might happen to have a geographic or other shortfall, but our technical base is rich. The experience we have is very good, and we'll develop the expertise and enhance the expertise internally with our technology company.
We've got a big organization in Houston that will augment what we have in the field, and we won't move forward if we don't have the capability to execute the plans that we have in place. I mean, that's a part of our project planning that we do anytime we take on activity. Gary, you want to talk a little bit more about it?
Maybe just add a few thoughts, Ed. First of all, we've been drilling horizontal wells and fracking for decades, so there's nothing new. What I believe we're bringing to the organization that came in via the Atlas acquisition is more sophisticated reservoir management techniques. What that means is, as opposed to approaching these shales as a pure statistical play, you have some good ones and some not so good, and as long as the average meets or exceeds the mean, you declare victory. We want to be better than that. We want to identify the sweet spots, and we can do that through geophysics and some of our geologic capabilities, but we want to approach these shales in a very targeted sort of way where we direct our well bores and our fracks to the sweet spots in these reservoirs, and these are things that we've been doing for decades.
We think, you know, laying on top of our decades of experience in drilling and completing horizontal wells, bringing this real disciplined approach to reservoir management positions us well. If there's one area that's a little new to us, it's the constant land activity that's associated with the asset base that we have in the Northeast. Fortunately for us, and that was by design, that's most of the organizational capability that we got through the Atlas acquisition.
Thanks, Gary. Jason.
Thanks. Jason Gammel, Macquarie . Another one in the Gulf of Mexico. How many rigs are you currently running in the Gulf? Given all the development and appraisal activity you have coming up, where would you like that number to be in, let's say, 2013 or the end of the year? Just a little bit further, how many exploration wells, high-impact exploration wells, would you like to drill in the Gulf on an annual basis, given your acreage position?
Right now, we are on the shelf, we're at pre-moratorium activity levels. That's in the 10 to 12 ongoing full rig years on the shelf. In the deepwater, we're actually ahead of our pre-Macondo, pre-moratorium pace. We were at three drill ships at the time the moratorium was put in place, and we now have five deepwater drill ships, actually four on location and a fifth one, the Pacific Santa Ana, that will arrive sometime in April. That level of capability is something that we're going to sustain for the foreseeable future. It's the right level for us. We can execute with confidence. You have to remember that the new norm in terms of permitting is not as streamlined and at the pace it was prior to the Macondo incident. We've got to have confidence in our ability to permit these wells.
Of the five drill ships that we're going to have working over the next 12 to 24 months, four of those will be engaged in development drilling. This is as a result of our success in our exploration program and getting Jack St. Malo and Bigf oot online with a full complement of wells. For us, if we could get anywhere in at three to four deepwater wells per year, I think that's our sweet spot.
Yeah, exploration wells, and that kind of complements what George showed in terms of the global target of wells to support the resource factory. Paul.
Thank you, John. John and George, over the last 12 months, I think there's a big debate in the industry whether the shale oil is going to fundamentally change the demand supply in the global market. We look at most of the companies, including you guys, seems like in the international shale play has been focused on the gas side, not on the oil. Is it because so far you don't see there's an attractive geological structure on the shale oil and don't really believe that exists or that that's more noticeable that you can identify in the gas? If you can maybe share some light on that. As a maybe not totally a second part, somewhat unrelated, Kyrgyzstan and Libya with the changing in political development, how you look at those two could potentially fit into the portfolio of Chevron. Thank you.
Those weren't directly related questions. Let me talk a little bit about shale and our prioritization, and I'll let George talk about the second subject and a little bit more on shale. In general, as we said, the gas markets tend to be disconnected. In the United States, there's been an enormous amount of wells that have been drilled, including many in the shales and right through the shales. There was quite a bit of knowledge about shale. With the well control that we've had as an industry, we've been able to pretty quickly move to the areas that are productive and develop the resources. That's just extended itself into the liquid window. Internationally, it's much different. Far fewer wells have been drilled. What we have done is concentrate our efforts first looking in areas that have markets nearby.
It doesn't necessarily do you a lot of good to find shales in areas where you don't have a connected market. We've looked heavily in Europe. That's why you see the opportunities. China has growing demand. We have concentrated in those areas, and those have been primarily gas-oriented targets. We also are, of course, canvassing for liquid opportunities as well. Some of the acreage we have has an opportunity in that regard. It's much earlier days for shale internationally because we just haven't drilled the wells. We haven't done the work that's been done in this country. George, you may want to talk more about that and then the other last.
The first emphasis is the geologic knowledge of the shales internationally is just not anywhere near what it is in the United States. Remember, we've drilled through many of these shales, and we've seen these as source rocks in the past. We've got penetrations. We've got knowledge. We understand organic content and all those kind of things. Our knowledge level in the U.S. and North America as a whole is much higher. We don't have that . The second piece of it is related to what John was talking about, which was the market. If you're in an international situation and they are gas short on a domestic basis, you've got an opportunity to also be in the gas. We're going to learn a lot more about international liquid side opportunities in shale over the next five years, but it's just much younger. That's the biggest difference.
Want to talk about Kyrgyzstan and what was, I'm sorry, the other? Kyrgyzstan and Libya.
We've been in Libya. We went there in the past. We did some exploration. You know, we're always interested in an opportunity where there's lots of oil and gas, but we're not in a good position. It's not an easy place to break into. A lot of the oil and gas from our view has been discovered. We don't see a big opportunity for us at this point in Libya. May come back two years from now and we'll say we found something new. That's the way the nature of this business. Kyrgyzstan, it's got challenges at this point. I'm not talking about political or anything else. I just would come back to we go back to this value proposition everywhere that we look for our resources. We want to be able to develop a resource that competes with opportunities that we presently have.
At this point in time, we're somewhat of the view we're not sure that it's going to meet that test. That doesn't mean we're not looking at it. It just simply means that we have not yet seen that it meets that test. That's an important test for us. Value creation is very important, not just barrels.
I think.. Evan, I think you have?
It's great. Thanks. Evan Calio of Morgan Stanley again. You guys, you've highlighted your growing unconventional position and legacy unconventional position. I know you've made us all very small owners in the Marcellus shale today. I was maybe somewhat related to Ed's question. I mean, do you have the ability or the will to accelerate spending to really bridge the production gap to this 2014 to 2017 outsized relative production as really it's just one year 2013 is flat?
We will make investments commensurate with the economics that we see. One of the things that we are going for is the carry that we referred to. Essentially, the party that's carrying us is paying 75% of the cost and getting 25% of the revenue, give or take. We are the beneficiary of that carry right now, and that's enabling us to continue our drilling. We are not going to ramp up drilling that's not economic just so we can have a bridge to production. We are going to do what's the right thing from a value point of view. We will be growing our production because during that period, we do have this $1.3 billion carry. We think that will work to our advantage. It will help us develop capability. It will help us work on sweet spot identification and getting more efficient about how we conduct our business.
That will have benefits long term, not only in the Marcellus, but elsewhere that we operate. I think we're down to one more question. I think there was a question right here in front.
Great. Thank you. Charlie Garland, Hamlin Capital Management. Two questions. Can you help us think about future dividend growth? Internally, does the company target, say, a percentage payout on free cash flow or earnings per share? Somewhat relatedly, can you describe senior executive compensation? Is it tied at all to TSR?
I like these questions. On the dividend, we don't have a formulaic approach to the dividend. In general, I would tell you we do look at dividends as a function of earnings and dividends as a function of cash flow. In the past, we've shown a couple of charts in that regard. We didn't do that today, but we do look at that. What you'd see is we're on the lower end of that, despite the growth we've seen in the dividend, that we're on the lower end of that range right now. We're cognizant of that. I've tried to foreshadow how much we value dividend increases. We've increased them 24 years in a row, and I'm very aware of that. In terms of our compensation, my compensation in particular, about 85% of my compensation is at risk. I have a base salary.
There's a cash bonus, but the majority of my pay is a function of two things. One is how our company performs. I'm issued options, and those are issued, of course, at the money. They don't pay out unless we have a positive stock price performance. Secondly, we have performance units. These are kind of interesting. These are different than many companies that get restricted stock where all you have to do is live long enough to get them. These are three-year performance units where, in order for us to vest at all, we have to outperform some of our competitors. There's a payout ratio from 0%- 200% against our top peers. Depending upon our TSR ranking during the period, the payout will be either 0% if we don't beat anybody or it'll be 200% if we beat the other four. We're very cognizant of performance.
I think I and the people at this table are actually more leveraged. In fact, I know we're more leveraged than our major competitors by a fair amount, actually, in that regard. That is the end of our program today. We will have a reception in the lobby area just outside the room. We appreciate your interest in our company, and we thank you very much for joining us today.