Those are amazing projects, and that's just a small sample of what we do. I do have one update. George told me just a few minutes ago that the Bigfoot hull has arrived in Corpus Christi, it's no longer en route. It's there. I hope that does give you a bit of a feel for the big projects that we have underway. George, Jay, and Mike will share more specifics, of course, a little bit later. The business environment for our business remains strong, and we're continuing to advance our growth plans we first outlined in early 2010. We said then that we plan to grow upstream production to 3.3 million barrels per day by 2017. Last year, we showed you this chart that indicated the projects that underpin this objective were well-defined. You can see our confidence is greater today.
More than 90% of the 3.3 target production comes from fields that are online today or tied to projects that are under construction. The remainder is in short-cycle projects. You'll hear later that our deep project queue will deliver growth beyond 2017. Now let's get started in more detail. Pat will begin by covering the financial highlights. Pat?
Good morning, everybody, and thank you, John. I'll be covering our 2012 financial performance, our near-term investment plans, and our financial priorities. 2012 was another very good year for Chevron. Earnings were $26 billion, and operating cash flows totaled $39 billion. Both annual figures are about 20% higher than our five-year historical average. Over the same timeframe, we've generated over $100 billion in earnings and over $150 billion in operating cash flows. We've definitely moved up the net income league tables. Our 2012 net income ranks us third among all U.S. companies and in the top 10 globally. Our strong earnings have been a function of our portfolio and our investment choices. We've invested wisely and been able to intelligently grow our business. You've seen this chart before. It has a very important message.
On the left is our growth in capital employed versus our peer group, indexed from year-end 2007. On the right is our return on capital employed over time. We've demonstrated the ability to invest for growth and at the same time remain competitive on ROCE. Normally, growth and returns are competing objectives. We've been able to do both simultaneously because of our capital discipline and the quality of our investment opportunities. This chart shows growth in our cash flow per share, again indexed back to 2007. In 2010, we moved beyond the top of the peer group band. In 2011, we substantially widened the gap relative to our nearest competitor. In 2012, we continued to lead the peer group. Our cash flow per share has grown by nearly 70% over the last five years, which is double the growth rate of our closest peer.
Our investments have delivered high-value volumetric growth that took advantage of a strong oil price environment. These investments are now substantial cash generators. We use the incremental cash to simultaneously reward our shareholders, fund our future growth projects, and strengthen our balance sheet. Let's look first at the outlays that fund our future growth. For 2013, our capital program is $36.7 billion. On the left is spending by region. Our spending continues to be geographically diverse, with weighting towards Asia due to our Gorgon and Wheatstone projects. Investments in North America are also robust, reflecting opportunities in the deepwater and in unconventional resources. On the right is spending by category. Upstream accounts for about 90% of the total, while downstream and chemicals account for about 6%.
Over 50% of our capital program is dedicated to major capital projects for upstream, principally LNG and deepwater projects that are fueling our future growth. Our base business outlays are projected to be about 30% of the total spending. These investments help stem natural field declines and support increased activity in new asset areas, something that George will discuss later in more detail. I said last year that having a strong investment profile is a good thing if the capital is being invested wisely. This is how we create value for our shareholders, by finding the best resources and developing the right projects. We continue to do this very well, and therefore continue to have healthy capital spending, progressing a project lineup that is arguably the best in the industry. Even so, we continue to be only mid-pack in terms of reinvestment rate.
Yes, our capital employed has grown, but our cash flow has grown even faster. For our average capital intensity, our investors get a production growth over the next five years that far and away exceeds that of our peer group. A similarly favorable comparison emerges if we broaden the competitor band to include the largest E&Ps as well. Simply put, our average reinvestment rate is resulting in the strongest volumetric growth. We're not in it just for the barrels. Not all barrels are created equal. We invest for value, not volume. We believe we're positioned for an extraordinary growth in our operating cash flows. You see this portrayed on the left side of the slide. We're starting today with the highest upstream earnings and cash margins.
We're projecting the strongest five-year production growth profile in the industry, and we believe our current investments have attractive economics to the point where overall cash margins on our 2017 portfolio are expected to be stronger than the cash margins on our current portfolio. That's really saying something, given our number one position on cash margins today. Our current portfolio is about 80% oil price linked, and in 2017, this should still hold true. We expect at least one-third of the Brent price will continue to be realized in our net cash margins. Having the best margins combined with the strongest growth results in a significant boost in cash operations. Our operating cash flows could exceed $50 billion in 2017, assuming last year's average Brent price. That's a nearly 30% increase in cash flows over the next five years.
At the same time we're investing for growth, we are also rewarding our shareholders. Since 2004, when oil prices started appreciating in real terms, we've posted a superior dividend growth pattern. Since then, our dividend has grown at a compound annual rate of 11%. This is the best in our peer group and nearly double the rate of the S&P 500. Since 2004, we've also had $35 billion of share buybacks, resulting in a net 9% reduction in shares outstanding. We've rewarded our shareholders, we've strategically invested in the business, and we've built the strongest balance sheet amongst the peers. Over the next couple of years, we expect the combination of investments and shareholder distributions will move us towards a more traditional net debt position. It's our clear intention to remain competitive on shareholder distributions to share our cash-generating success with shareholders as our projects come online.
John showed you Chevron's superior record on five-year and ten-year total shareholder returns versus the global energy peer group. As I'm sure you can appreciate, we're very proud of this record. If we expand the comparisons beyond the traditional peer group, we also rank extraordinarily well. We're number 1 in the five-year period, returning 5% more than the broader market and 8%-9% more than both our global peers and the largest E&Ps. Over 10 years, we also outperform on TSR against these same two groups. We have an outstanding history of value creation, and our investment opportunities position us well to repeat. Every day, we get closer to having key projects come online. Every day, our growth profile is further de-risked, and every day, we believe we are closer to a re-rating of our P/E multiple.
I'll close now with our financial priorities, which you have seen before. Our first priority is to maintain and grow our dividend. Our actions demonstrate this commitment. Our second priority is reinvesting in the business into high-quality projects that sustain and grow our firm and create tremendous value for our shareholders. George will show you how the projects under construction now, once online, strengthen the cash margins of our overall portfolio. Our third priority is to maintain our financial strength and flexibility. Finally, we're committed to returning any surplus cash to our shareholders. Our actions demonstrate this commitment as well. Frankly, we've sensibly balanced these objectives over time, and we have every intention to repeat. I'd like to now turn the podium over to Mike to discuss our downstream operations. Mike?
Thank you, Pat, and good morning. It's a pleasure to be here today and to discuss Chevron's downstream and chemicals business. I'll break my comments into three sections. First, I'll review our strategy and the business environment. I'll cover our performance in 2012, and I'll close with a discussion about growth. Our strategy remains unchanged. We continue to focus on improving returns and growing earnings across the value chain. The supporting strategies of operational excellence, portfolio focus, asset competitiveness, and selective growth also remain unchanged. The fundamentals underlying our business reflect the realities of the global economy. On the left-hand charts, you can see that lubricants and petrochemicals are expected to experience strong demand growth throughout the decade. On the right-hand charts, the outlook for fuels shows more modest growth.
For all segments, Asia will be the primary driver, with lubricants and chemicals growing faster than fuels and distillate growth continuing globally. Changing feedstock dynamics are reshaping the competitive landscape in North America, driving down the price of feedstocks for both petrochemicals and refining. The left-hand chart shows ethylene cash cost by feedstock and region over the last four years. The Middle East continues to have the lowest cash costs by far, but only for the few producers with existing feedstock contracts. North America facilities using gas-based feedstocks now have a real advantage versus Naphtha-based plants. This has only increased as drilling has concentrated into liquids-rich plays, and we don't see it changing anytime soon. Our ethylene cracking portfolio is entirely positioned in these two attractive regions. In refining, we continue to believe that large, efficient, flexible, and well-run facilities will be the most competitive.
While we've seen crude supply changes benefit mid-continent refiners the last year or two, this is likely to be a more short-lived effect. We already see infrastructure emerging to reduce these discounts to basic quality and transportation differentials. In the long run, we'll continue to shape our portfolio and improve our operations to deliver top performance through the business cycles in both of these segments. Let's move to a review of performance. 2012 was another good year, both operationally and financially. Reliable operations are our top priority across all our business segments. Take a look at this chart. Chevron is ranked number one in refinery utilization over the last three Solomon surveys, covering the period back to 2006. In 2012, we operated at roughly the same level as our industry-leading performance in 2010.
Solomon data for competitors will be available later this year. We expect to compare favorably once again. Top-tier reliability remains the bedrock of our operations. We intend to sustain this performance through both operational and turnaround improvement initiatives. On this chart, I've summarized a final update on our restructuring. We've exited less attractive markets, driven down supply costs through terminal rationalization, and reduced station ownership to decrease capital employed. We've significantly reduced our workforce, creating an organization with fewer layers, a bias towards action, and sharper accountability. All this while only modestly reducing volumes. The result is a more focused footprint, simpler operations, reduced costs, all designed to sustain strong returns in the years ahead. Our restructuring is complete and the focus is on value, not volume.
That restructuring was part of a three-year commitment I outlined in 2010 to improve R&M returns 7% by 2012 through improvements in refining, marketing, portfolio, and costs. Last year, I told you that by the end of 2011, we'd already exceeded our target. At the end of 2012, returns are up 10% as a direct function of the aggressive improvements we've captured in these controllable aspects of our business. We handily beat our commitment. When you take into account the improvement in industry margins, actual returns are up 18%. As we turn the page on that effort, let's look at relative competitive results. In 2012, R&M earnings improved again and were just over $3 per barrel. This places us a strong number two among our peers, very close to number one, and with a fairly wide gap to all the others.
We delivered an 18.1% return on capital employed for all of downstream and chemicals, which we also expect to rank number 2 among our peers when final 2012 capital employed data is available. I'll move to the future and targeted growth. I'll summarize our plans for key segments and what you can expect to see in the next few years. Starting with Asia, where we'll grow earnings by focusing on the most competitive and attractive positions. In the map on the left-hand side of this chart, you see the facilities that position us to take advantage of Asia demand growth. In North Asia, our position is anchored by GS Caltex at Yeosu, South Korea. This is a world-class refining and petrochemical complex, combining the world's fourth-largest refinery and third-largest aromatics plant. In Southeast Asia, our flagship refinery is in Singapore.
The charts on the right-hand side show we have the overall scale in this region to be a top supplier of high-value products. We also have the scale at the facility level to be efficient and competitive. Our refineries are linked to strong market positions. We've improved our ability to generate strong returns from these assets and will continue to do so with targeted capital investment and strong operating performance. Turning to petrochemicals, we have a strong foundation with Chevron Phillips Chemical, or CP Chem, now the largest private sector petrochemical producer in the Middle East and the largest producer of high-density polyethylene in the world. I mentioned earlier that 100% of our ethylene cracking capacity is located in the Middle East and North America, where we have cost-advantaged feedstocks. This foundation and strong operating performance is a formula for excellent financial results.
CP Chem has delivered leading cash return on assets among their peers for multiple years now and is advancing projects to further capitalize on this unique position. For example, we expect a final investment decision on a new Gulf Coast cracker this year. With a proprietary technology advantage in olefins and aromatics and a robust growth plan centered on world-scale facilities and cost-advantaged feedstocks, CP Chem is well-positioned to continue delivering profitable growth. Moving from commodity chemicals to specialties, Chevron is the only oil company with a wholly-owned specialty chemicals business, which develops, manufactures, and markets additives for lubricants and fuels. Oronite has a strong global supply chain, long-standing relationships with original equipment manufacturers, and is the only additive company with world-scale manufacturing plants in all key demand centers. Plans for growth include investments in both supply chain and technology.
At our Singapore plant, already the largest in Asia, construction is underway that will double the plant's original capacity. We'll expand production of key additive components, such as detergents and dispersants to meet increasing demand. Technology investment will maintain Oronite's leadership in several product lines and provide our customers the ability to differentiate their products. Oronite earnings have tripled over the last four years while operating costs rose only modestly. This segment delivers strong returns and has the capability to continue to grow profitably. Lubricants is another high-return, high-growth segment. Chevron is the only major lubricants company with an integrated business, from base oils through additives and finished lubricants. We're currently the number 1 producer of premium base oils in the Pacific Rim, with plants at Richmond and Yeosu. When the Pascagoula plant comes online, we'll be the largest supplier of premium base oils in the world.
We're expanding capacity in the Americas and Asia by investing in supply chain infrastructure with new blending plants in China, Southeast Asia, and Brazil. Earnings have more than doubled over the last four years while costs have been reduced. We're committed to leveraging our leading technology and market positions to continue to grow in this segment where returns have been consistently strong. Key projects. This chart shows six important major capital investments. CP Chem continues to make good progress on U.S. Gulf Coast projects to take advantage of existing infrastructure and attractive feedstocks. These include a 1-hexene plant slated to start up next year and a new world-scale ethylene cracker and derivative units expected to start up in 2017. Our Pascagoula base oil plant is scheduled for startup late this year. The Oronite Singapore expansion will come online in phases in 2014 and 2016.
GS Caltex is commissioning a new gasoil cracker, which should be in full operation this month, helping make Yeosu the largest processor of heavy oil in Korea. The two pie charts on the right show how our portfolio is growing and shifting to a more balanced weighting of the attractive chemicals and lubricants segments and Asia Pacific R&M. To close, I'd like to summarize three points. First, our strategy remains sound. We're improving returns through executing the fundamentals in our base business with a smart and more focused portfolio and assets that have the scale, flexibility, and complexity to be competitive at any point in the cycle. Second, our performance is strong. Safety and reliability remain at industry-leading levels. Earnings per barrel and returns are top tier, and we've exceeded all our performance commitments.
Finally, we're investing in carefully targeted growth projects in the right markets and segments to strengthen and diversify earnings and sustainably deliver top-tier competitive results. I'm confident we'll improve again this year. That concludes my remarks, and I'd now like John and Pat to rejoin me on stage.
Okay. Thanks, Mike. We'll welcome your questions now. First, a few ground rules. Please hold your upstream questions until later in the program. You'll get plenty of chance with George and Jay. If you have a question, raise your hand, and I'll take it. Wait till the microphone comes to you so that everyone can hear it, please give us your name and company affiliation. Okay, Arjun
Thanks. A downstream question from Mike, if that's all right. The issue of RINs has come up here in the last few days in the E10 blend wall. Can you talk about Chevron's relative positioning as to whether you feel exposed to this issue or not? The other regulatory question is on the ongoing issues in California and AB 32, and is there any update there in terms of how those regulations are progressing? Thank you.
Right out of the box with an easy one. Mike, you want to try that one?
All right. Well, for those of you that haven't been following the Renewable Fuel Standard, a RIN is a Renewable Identification Number, which is a 38-digit number that manufacturers, importers, or blenders of fuel are required to assemble enough of these 38-digit numbers to submit to the government each year to satisfy a volume obligation that says you're blending enough biofuels or procuring the credits that reflect that blending to satisfy the volumes mandated by the standard. There are four different flavors of these things, ranging from corn-based all the way on through to cellulosic, which we really haven't seen much of other than RINs that turned out not to be real. In the corn-based category, up until now, there's been plenty of supply, and the blend obligations have been less than 10% in aggregate for the market.
RINs have been relatively inexpensive, a few pennies per RIN and not of much value. We're now reaching a point where the aggregate blend volume is in excess of 10% for the market, and that's a problem, and it's a problem we've been talking about for years. You'll hear it referred to as the blend wall because frankly, people like Chevron are unwilling to sell blends higher than 10%. Consumers are reluctant to purchase at that level. Auto manufacturers' existing fleets are not warrantied for fuel above 10%, and there are real concerns around product liability and vehicle performance. Now we have a position where people are required to procure more of these things than are likely to be available in the market.
There are rules about carryforward from the prior year and things which were intended to create a little bit of a buffer, but that is rapidly running out. The price of these credits, which are tradable, has skyrocketed over the last few weeks from less than $0.10 as the year began to over $1 as of late, and there's a real concern about that. Specifically to Chevron's position, Arjun, we tend to have more marketing sales and therefore more blending of fuels that we sell than we do refining production. We're in a natural long position on RINs and have been, and we'll probably hit the blend wall as an individual company much later than others would.
On the other hand, importers, merchant refiners, or refiners whose marketing position is much smaller than their marketing production need to procure these RINs from the marketplace, and as the market seems to be tightening up, the price obviously has risen, and frankly, we've been a seller of RINs into this market with our natural long position. We can satisfy our compliance obligation and still have some excess that we can sell into the market. As a company, we're not in a particularly vulnerable position on this today, but I will tell you that this is a regulation that just doesn't work. I think that's got to be confronted by the federal government, and I think the Renewable Fuel Standard will need to be changed. AB 32, I'll give you a shorter answer on that. We're in the early phases of compliance on it.
We've seen a couple of auctions now, the credits are trading in a little bit over $10 a ton range. We've got an efficient refining system relative to our competitors in California and are less exposed in the early years to the costs of AB 32. I will tell you, in the back half of this decade, everybody gets hit. You get the Low Carbon Fuel Standard coming in, which is likely to increase fuel prices perhaps significantly, and the California economy remains pretty fragile. The net impact of the reduction of emissions from AB 32 on a global scale is virtually unmeasurable. The impact on the California economy is not. It will be significant. We also think AB 32 eventually will need to be revisited, and we certainly will be working with various stakeholders in California to address that.
I wish I could tell you he was making all that up, but these are really onerous regulations. The important thing is we're a big enough company. We can learn how to manage these things, but they're going to hurt consumers, they're going to raise energy costs both at the retail level and for businesses, we don't think that's a good thing for a struggling economy. Yes. Doug?
Thanks, John. It's not really an upstream question.
We'll try and take one anyway.
I'm going to try one.
Okay.
The growth rate that you've laid out, the 3.3 million barrels a day, you never really talk about asset sales, but you've clearly got a pretty impressive portfolio of new projects coming on stream. What does that do to high-grading the portfolio, and how should we think about how potential cash from asset sales is redeployed, maybe to buybacks or whatever?
Well, we do periodically, I would describe it as trim the tail, both upstream and downstream. Last year, we sold about 20,000 barrels a day, and we routinely hive off the bottom end of the barrel. One of the things that we found over time is technology only goes in one direction, and you have what economists would call friction when you sell, tax effects and the like. Churning the portfolio and being a trader in oil fields, we don't think is a very efficient way to go. Clearly, if we see an opportunity where a field where we don't see the opportunity to apply technology going forward Someone's willing to pay us a nice price for it, we'll part with it. One example I'll give you where we've hung on to properties where others haven't is in West Texas.
George is going to talk a little bit later. A big part of our position there is acreage we held onto that we didn't know would be developable in different horizons, that now, with the advent of tight resources and shales, we are able to. We'll sell assets when it makes sense to do so and use them for, I would say, general corporate purposes. Mike has shown that we've done it in a big way downstream. We've sold some, what, $8 billion worth of assets over the last five or so years as we've cleaned up our portfolio on the downstream. We're willing to do that and recycle the dollars into more productive use.
Yes. Go ahead, Paul.
Thank you. Morning, John.
Morning.
Paul Sankey, Deutsche Bank. John, arguably, there's only two integrated oil companies left in the U.S. now, you and Exxon, you yourselves have just announced a pretty significant downstream restructuring program. Could you talk sort of strategy-wise about whether you really are just becoming a super giant E&P and really the legacy downstream that you have is really stuff that you can't sell or is good enough to keep? If there really is still integration in your asset base, and you really do want to maintain integration. I guess ultimately the question is: do you think refining is just structurally a low return business that you don't want to be in because the returns are so much superior in the upstream? Thank you.
Sure. Well, our downstream and chemical business, we earned 18% last year. It's been a good return business. We are more selective in where we're investing. We have generally sold the service station businesses that we have. Our brands are still present, but we don't own a significant number of service stations anymore. We do think our refineries are very competitive and are a source of value creation for us, and we do think the integrated model still works. There are a lot of examples of that. Our San Joaquin Valley crew goes into El Segundo Refinery. We process disadvantaged crudes at Hawaii and our Thailand refinery. So there are ways to create value in the system by having an integrated model. That doesn't even count what's happening in our upstream business, where what you think of as an upstream business, the lines are being blurred.
We've got a gas to liquids plant that's coming on stream later this year in Nigeria. We've got a number of different LNG facilities, which look a lot like refineries from the outside. We've got processing plants in Venezuela and elsewhere that look a lot like refineries, so the expertise and people that come out of that business are also a source of advantage. Finally, I would just say, if it were a standalone company, making $4 billion a year would rank pretty high in the S&P 500. It's hard to replace that. When you're generating high returns, you have opportunities for growth. I think it remains a good business to be in. It will be a smaller piece of the pie given the significant opportunities we have upstream.
Yeah. Go ahead, sure. Ed.
Yeah. Ed Westlake, Credit Suisse. You mentioned new legacy assets, I think, in the opening remarks.
Yeah.
Obviously the criticism of Gorgon and Wheatstone is it's taken a lot of capital in the foundation phase for those projects. Can you talk a little bit more broadly about how you see the capital intensity of the portfolio change as you go to the next wave of growth beyond 2017? I have to ask Mike about that $3 long-term WTI Brent, because most refining investors will be selling their portfolio holdings at that price. Any comments on the chart? Thanks.
Well, first off, legacy investments by definition are of a size and scope that are going to require capital investments. If you just take a look at Gorgon and Wheatstone, you don't just come up with 400,000 barrels a day of our share production very easily. Of course, there's capital associated with it. Tengiz is a major oil field and will require additional investment. There is capital. I think what's important is that we've been pretty wise about that capital. If you look at the returns we're generating, as you look at the profit per barrel, whatever measure you like, they've been good investments. They are of a size and scale that do require capital. I think any legacy size asset will have a substantial capital component to it. The key is it competitive and is it going to deliver us the returns?
Mike, you want to talk a little bit about.
Yeah, Ed, we showed an externally sourced view on the WTI-Brent differential, though you all have your own views on when and how that thing will be narrowed. The reality is everybody's working on infrastructure projects right now. It's been a little hard to predict the rate of growth of production. I think the one thing we do know is that it will narrow, and that the means to narrow it are pretty well understood and not particularly complex other than sometimes the permitting issues. The point I was trying to make is the structural advantage for gas-based feedstocks for petrochemicals is likely to be a more long-duration phenomenon than the WTI-Brent disconnect.
Yeah. Evan.
Hi, Evan Calio of Morgan Stanley. Maybe my question falls in between this segment and the next segment on midstream, just in the sense I know that you've recently formed a new business unit that consolidates midstream assets.
Maybe you could share the strategy of that unit and whether or not the creation of that unit means more potential monetization given the significant premium paid in the midstream market relative to your valuation, and how you think strategically going forward.
I'll let Pat talk a little bit about how we feel about MLPs in a moment, but let me talk briefly about the organization itself. We've actually had a gas and midstream organization for some time that's reported to George as we've been gearing it up. It has organizations that actually support both upstream and downstream, our shipping company, our pipeline company, as well as our gas commercialization work and gas trading organizations. The reason we decided to move it away is we thought that our gas business is on the cusp of being a much larger component of our business, and we felt it made sense to put all our trading activity under one roof. Mike has had the liquids, the crude and products trading reporting to him.
We thought it made sense to bring the crude products and gas trading together, and to bring a little more focus onto the midstream opportunities. We do have some sales that we have planned in the pipeline business. We've monetized one pipeline in the Pacific Northwest, and we do understand the valuations are good. Maybe I'll let Pat talk a little bit more about our view of how we're going to do that.
Sure. We basically understand completely what the MLP structure offers in terms of early monetization and sort of the tax advantages and the leverage advantages that come with that. We've looked at it vis-à-vis our portfolio, and have basically come down to the point of saying, if it's a strategic asset and it's something we want to retain control of, then it stays in the portfolio. If it's a non-strategic asset and we're willing to have that control go, then that is something that we would look to divest. Actually, divesting into MLPs is a good way for our shareholders to kind of capture the value of this MLP market, so that really will be our approach.
Good time to sell into those. We just think that the governance challenges that come with the MLP structure, particularly if you are interested in keeping control, that governance structure over time can erode where you don't have the complete alignment that you'd like to have, so we'd just like to keep it clean. If it's strategic, we keep it in the portfolio. If it's not, we'll go ahead and sell it, and sell it into the MLPs where you get good value.
In general, we're not a huge fan of having publicly traded affiliates. Put it that way.
Yes. Paul. Yeah.
Thank you, John. Paul Cheng, Barclays. Two question, one for Mike and one for Pat. Pat, if we're looking at your production profile that you guys target to 3.3 million barrels per day, the project is quite well-defined, and some of the large projects will start to roll off in 2014. Should we look at from a capital intensity standpoint, after rapid increase in the last several years, we may see another increase in 2014 and start to slow down on the growth? That's the first question. For Mike, if you're looking at portfolio restructuring, you have done a lot. At this point that you still see there's a lot left to be done, or that you're pretty much done.
I guess my question is more related to, is there any strategic reason to maintain your minority ownership in Caltex Australia, as John just mentioned that you are not totally crazy about having ownership in publicly traded company and doesn't really have an exit strategy? Also that in Africa you do have position. Is that so profitable that you want to maintain it? It's sort of like an oddball out there. For your California two refinery, how much is the light oil you can actually run? Does it even make sense given the wide difference of today plan to say maybe spend some money to have a cracking operation to bring more of the light oil into those operations? Thank you.
I think that's two questions.
It's four.
Let me take the first part of it, and I'll let Mike take the second part. Just on the capital side. We've said before, Paul, that we're in the midst of a heavy period of capital spend. Our capital spending this year, as we've outlined, is $36.7 billion. Spending in 2014 and 2015 will be higher than that. We don't give long-term guidance that's pinpointed because what we've seen by those that have put out such guidance over the last five to seven years is they just haven't been very accurate. That's no criticism. That just reflects the difficulty gauging the cost of goods and services, exchange rates, and the like. We will have continued heavy spend the next couple of years. By the way, I said, in general, we don't like publicly traded affiliates.
We're happy with Caltex Australia, but I'll let Mike talk a little bit more about that.
Okay. There were a series of questions in the portfolio heading, Paul. I will tell you that we are pretty close to the end of the big sweep that we've done through the portfolio as a part of the restructuring. We've still got a process underway with our assets in Pakistan and in Egypt, and would expect to have news on those later this year. We're largely complete with the bigger restructuring. We continue to review things on an ongoing basis, that means that any asset that is underperforming and doesn't have a plan and a realistic prospect for improving that performance to an acceptable level becomes an asset for consideration for divestment. I don't have anything specific I want to announce on that front. Africa falls into that category. Caltex Australia, as John says, it's 50%, it's not really minority.
It's a 50/50 holding in Caltex Australia, we've been pleased with the performance of that affiliate. Your final question had to do with light oil into the West Coast refineries. We can run in the neighborhood of 75,000 barrels a day at either of our West Coast refineries, the two large ones in California, before we run into process constraints that limit our ability to get more light ends through the refineries. We have run Bakken crude at the Richmond refinery. We know how to get it in there. It's kind of trains, planes, and automobiles. We use rail cars to a terminal where we then barge into Richmond. It's doable, we have done it and will continue to do it. I think the broader issue that applies to both the California refineries, Pascagoula, is disadvantaged feedstocks are not only found in the mid-continent.
There are disadvantaged feedstocks in other areas of the world and disadvantaged for other reasons than logistics to get them to market. We continue to invest in our facilities to run feedstocks that have an economic advantage for the refining system from a variety of sources. These can be heavy crudes, they can be high viscosity crudes, they can be high acid crudes. Our bread and butter is optimizing our operations by bringing in the most attractive feedstocks every day, every month, every year, we continue to work on that on a constant basis for all of our facilities.
Okay. I'm thrilled there are more questions, we're going to take a 10-minute break. You will have another chance after George and Jay speak. Remember, take your badge with you so that you can get back in 10 minutes, we'll start up again with George.
Good morning. Paul, good morning. It's good to be back and review Chevron's Upstream business. We had a good year in 2012, and today I'll provide insights on our performance, and with Jay's help, outline our plans for 2013 and beyond. First, an overview of Chevron's Upstream portfolio. Chevron has a diverse Upstream portfolio, with production in 26 countries, and in nearly all the world's key hydrocarbon basins. We have four regional operating companies and 15 business units. Our strong local presence is supported by central organizations to ensure consistent standards. We have centralized functional teams in exploration, drilling, reservoir management, and base business. Our Chevron Energy Technology Company, ETC, provides highly skilled technical research and services for our business units. Our Project Resources Company, PRC, provides the world-class project professionals needed to execute our major capital projects with excellence.
Our midstream organization, our gas and midstream organization, helps us commercialize our production, and particularly our LNG. We have strong leaders in country, supported by centers of functional excellence, and we believe this gives us a competitive advantage. This supports our core strategies and delivers profitable growth. Let's now review our strategies. Our strategies remain unchanged. We're pursuing profitable growth in our operating areas while we explore and build new legacy positions. While strategy is important, execution is key, and as you'll see in this presentation, we are delivering a leading growth profile and superior financial performance. Today, I'll be focusing on three themes: performance, base operations, and growth. Let's begin with our 2012 performance. In 2012, net production was 2.61 million barrels per day, about 2% lower than 2011. Our base operations delivered strong performance. The production decline remained on trend at about 4%.
The largest impact to our production in 2012 was the precautionary shut-in of the Frade field in Brazil, which had an annualized impact of 29,000 barrels per day. Our major capital projects added approximately 85,000 barrels per day, including a full year of production at the Thailand Platong II project and the start up and ramp up of production from Usan, Egusi II, Tahiti 2, and Caesar Tonga. Production gains from major capital projects were less than anticipated due to the startup delays at the Angola LNG project. First LNG is anticipated during the second quarter. Next, I'll highlight our strong reserve performance. Chevron added approximately 1.1 billion barrels of proved reserves for a replacement ratio of 112%. I want to emphasize we've exceeded 100% over the last three and five-year periods.
In 2012, net additions came from a variety of sources, with relatively little from new FID bookings. We continue to see strong contributions from previously sanctioned projects. 2012 was our highest year for positive revisions in the last 10 years, primarily from favorable drilling results throughout the organization. Our largest positive revisions were in Gorgon, Tengiz, and our Wolfcamp assets in the Permian Basin. In addition to success with our development drilling, we continue to have success with our exploration program, and I'll cover that next. According to Wood Mackenzie, Chevron remains the leader in exploration resource replacement over the last 10 years while spending less than most of our competitors. Our internal assessment of resource replacement is even higher, with over 10 billion barrels of resource found over this period, a resource replacement ratio of over 100%. Our 10-year well exploration success rate of 54% is outstanding.
In 2012 was even better. We added over 1.3 billion barrels with a success rate of 74%. The map shows the location of key 2012 exploration discoveries. We announced 6 natural gas discoveries in the Carnarvon Basin, each adding to our significant gas position. In the retained Browse Basin acreage, we had a significant gas discovery, the Crown 1 well. We've also continued to see strong results from our shale and tight resource portfolio, with significant additions from the Wolfcamp Trend in the Permian Basin and the Duvernay in Canada. Next, I'll cover resource replenishment. From year-end 2007 through 2012, our total unrisked resource replenishment was 154%. Over this timeframe, we produced almost 5 billion barrels and divested 2.5 billion. That was offset by over 10 billion barrels in resource additions from exploration, acquisitions, and maturing organic opportunities.
Results will be even higher once we complete our assessment of the recent acquisitions in the Delaware Basin in New Mexico and the Liard and Horn River Basins in Canada. In fact, our unrisked resource could approach 70 billion barrels. Our exploration success and business development activities provide us with an attractive portfolio with significant potential for organic growth. Let's now review our leading financial performance. Last year, our upstream costs were $31.16 per barrel. This was approximately $2 higher than 2011 due to increased turnaround and labor cost and higher DD&A. Our upstream cost structure and the cost structure of our competitors increased the last few years, largely driven by higher costs of goods and services. Complete competitor data for 2012 is not yet available. However, we expect that our upstream costs will remain competitive with the peer group.
Realizations for the competitor group are also incomplete but can be estimated, and we expect to remain the leader, holding a $4.50 a barrel advantage over our closest competitor. The quality of our assets and our portfolio weighting to oil provide us with an advantage. On a volumetric basis, we're 70% weighted to oil and predominantly tied to Brent, Mars, Louisiana Light, and Kern River. In addition, a large portion of our gas sales are linked to oil, making our portfolio, on a pricing basis, equivalent to 80% oil. With a leading position in realizations and a competitive cost structure, we've delivered unmatched earnings margins. Our 2012 earnings of $23.70 per barrel are over $5.50 higher than our nearest competitor. We've led our peer group in this metric for over three years, and we've also outperformed the large U.S. E&Ps over the same period.
I'm very pleased with our leading position and the large gap separating us from our competition. Complete competitor ROCE results for 2012 are not yet available. However, our return on capital employed of 21.5% is expected to rank at the top of our peer group once again. In summary, we're making the right investments, executing well, and as a result, leading our competitors on key financial metrics. Our 2013 upstream C&E budget is $33 billion and is focused on progressing our major investments, our Australian LNG projects, the Gulf of Mexico deepwater projects, and finding new opportunities through exploration. For this year, about 10% of the upstream budget is targeted for exploration. 60% is directed to major capital projects, with about $10 billion going to Gorgon, Wheatstone, Jack St. Malo, and Bigfoot. The remaining 30% of our investment goes to base business.
This is up $1 billion due to increased activity in areas such as the Permian. Our investments are aligned with our strategies, they strike a balance between long-term growth through exploration and business development, mid-term growth through major capital projects, and near-term production from our base operations and small capital projects. We're focused on delivering value from this capital, as you saw on the previous chart, we're doing just that. Now let's take a closer look at our base operations, a critical component of our leading performance. Over 2 million barrels a day of our production comes from our base operations. Mitigating our base decline is a critical component of our long-term growth. With a consistent focus on operating efficiency and reliability, plus targeted investments in small capital projects, we sustained a decline of around 4%.
From 2007 through 2011, our small capital project investments added over 700,000 barrels per day. These projects deliver near-term production to mitigate the base decline, because they leverage existing facilities, they have high returns, typically over 50%. We're actively pursuing further enhancements of our base performance through new technology, such as our proprietary i-field application that allows us to actively monitor and optimize well performance. Our high base activity positions us well for developing shale and other tight resources. We presently have several business units that apply factory-style drilling techniques, they operate large numbers of wells. Chevron is one of the top two companies globally in the terms of total net wells drilled. We have 100 drilling rigs and 120 workover rigs currently in operation, our rig count will continue to grow. Among our largest base operations are our world-class steam floods.
Kern River Field has over 10,000 wells in operation it's been producing for over 100 plus years. Over 65% of the oil in place has been recovered, current production is 70,000 barrels a day. The Duri Field in Indonesia has over 8,000 wells in operation, has been producing for over 60 years, recovery is over 40% of oil in place. We continue to develop this asset, which currently produces 150,000 barrels per day. We've also been successful in the Pattani Basin in the Gulf of Thailand, where we operate a unique factory-style drilling program in an offshore environment. We're also applying these manufacturing best practices in our Marcellus and Permian Basin operations. Both hold years of growth potential. In the Marcellus, we have an active drilling campaign with 8 drilling rigs in operation. This program has a carry with approximately $850 million remaining.
We now have long-term production data on more than 65 wells, the reservoir outcomes are on the high end of our expectations. These wells have averaged 1.8 Bcf in 30 months are on track to recover over 5 Bcf per well. We implemented our proprietary deconstructable tank design, reducing our average well pad size by 50% driving a significant reduction in both pad construction and reclamation time. We've also instituted improvements in drilling and fracking efficiency to reduce well development cost. All of these and future process improvements will be utilized and transferred to resource plays around the world. In the Utica, which is a potential liquid growth area for us, we've drilled 4 wells and fracked 2 of them. We anticipate spudding an additional 8 wells in 2013. Another key liquid area for us is the Permian Basin in West Texas and New Mexico.
The Permian is attracting a lot of industry attention as a revitalized, liquid-rich type play. We're currently the second largest producer in the basin, with nearly two billion acres under lease. In 2012, in the Midland Basin, we participated in over 300 gross wells. Well results are meeting expectations, and we plan to further increase our activity levels. The Delaware Basin is less mature but has great potential with stack plays in the Bone Spring, Avalon, and Wolfcamp. Our initial field evaluations are expanding the productive area of these major reservoirs in our acreage. The recent acquisition from Chesapeake added 243,000 acres to our existing Delaware Basin position. We now have almost one million acres across this basin. 2013 will be an active year in the Permian as we plan to drill over 400 wells. We're acquiring more rigs and plan to have 23 in the area by year-end.
With our acreage position and the quality of these reservoirs, the Permian Basin will remain one of our key legacy assets. Today, our legacy production is 1.3 million barrels per day. Legacy assets have flat to low production declines over the next 10 years. Some have large reservoir potential and are facility limited, like Tengiz, while others remain flat through the reinvestment in the base. Over the next decade, we forecast our percentage of legacy production to increase from 49%-60% with the startup of major capital projects like Gorgon, Wheatstone, and Tengiz Future Growth, as well as the growth in the Permian and the Marcellus. With our strong portfolio, we're confident in our ability to deliver and grow production. In this section, I'll highlight how our confidence in achieving our 2017 production target has increased, and then Jay will provide an overview of longer term growth opportunities.
As John mentioned earlier, we continue to progress our major capital projects. We have new projects coming online every year, and we estimate these projects will contribute over one million barrels per day to our 2017 production. Only 1% of our production target is associated with projects starting up in 2017. The vast majority of the production growth comes from projects starting up in 2014, 2015, and 2016. This increases our confidence in achieving our 2017 objective. Let's take a closer look at these upcoming startups. Over the next five years, 50 projects, each with a Chevron share of $250 million, are scheduled to start up. 16 of these, as highlighted on the map, have a net Chevron investment exceeding $1 billion. Over the next two years, we plan to bring on seven large NCPs.
Our large deepwater projects, which I'll cover in more detail in a minute, and an Angola LNG, EGTL, and Chuandongbei . In late 2014, we plan to start up the first train of Gorgon and ship the first cargo of LNG in early 2015. In late 2016, we plan to start up Wheatstone. Let's now take a closer look at these projects, beginning with the deepwater, where we're particularly pleased with our progress. Papa-Terra in Brazil is scheduled to start up in late 2013. The topsides for the tension leg well platform and the FPSO recently arrived in Brazil. Well work continues with ongoing drilling and completions. Construction continues on Jack St. Malo, where we've completed hull fabrication activities in South Korea, and the hull is under transport to Texas for integration with the topside modules.
Last year, we spoke about our plans to implement new technology on our Jack St. Malo wells to improve our recoveries and reduce costs. We've now stimulated three wells using the Enhanced Single-Trip Multizone frac pack with very encouraging results. On one well, this single-trip frac pack saved 50 days of rig time, a very significant cost savings given deepwater rig rates. The frac pack did a great job stimulating the reservoir. Testing was constrained by equipment, but we saw rates of over 13,000 barrels per day. These sorts of technology breakthroughs could help us unlock the Wilcox potential, improving recoveries and increasing the economics of our existing developments and our future developments like Buckskin and Moccasin. Bigfoot is also making significant progress. The hull sailed away from South Korea at the end of last year and has arrived in Texas for topside module integration.
We've also begun batch drilling the wells. Tubular Bells has made progress on the spar and topsides fabrication and continues with the development drilling program. As you saw in the video, construction at Gorgon is going well. We've completed more than three full years of construction, and the project is 60% complete. We made significant progress in 2012. 92 prefabricated pipe rack modules were installed. Two prefabricated process modules were set on their foundations. Drilling progressed on all 18 development wells, completion operations have begun. A very active year is planned for 2013. The first gas turbine generator has arrived on site, and the second generator is scheduled to be set on its foundations by the end of the second quarter.
The remaining LNG train one process modules are scheduled to arrive on Barrow Island by year-end, the domestic gas pipeline is scheduled to begin supplying gas for plant commissioning in early 2014. Currently, 65% of our equity LNG is under long-term contracts, our goal is 80%-85% term sales by startup. Now let's look at Wheatstone, our other legacy LNG project in Australia. Activity is ramping up and on plan. More than $19 billion in contracts have been awarded. Our focus at Onslow is on site infrastructure, roads, beds, and water. The first 2 phases of the camp are complete. Plant site earthworks are progressing well. Equipment manufacturing is underway around the world, and deliveries have commenced. Fabrication of the topside modules for the offshore platform is also progressing well. On LNG marketing, about 80% of our equity LNG has been contracted on a long-term basis.
In 2013, the platform substructure fabrication and offshore dredging will begin. We also plan to complete the first phase of the construction village. About one-half of our equity LNG from Gorgon and Wheatstone will be delivered to our customers via Chevron LNG ships. Currently, six LNG ships are on order and should begin arriving over the next several years. Next, let's review how our major capital projects and our base business investments grow our portfolio. Last year, we shared a breakdown of production growth by asset class. The outlook this year remains similar. Our LNG production increases to over two and a half times our current rates, underpinned by Angola LNG, Gorgon, and Wheatstone. In the deepwater, we see strong performance as production approaches 500,000 barrels a day in 2017 from the ramp-up of projects.
Our shale and tight resources have significant growth, growing to over 250,000 barrels a day, an increase of more than 45% or 80,000 barrels per day from last year's projection. Our conventional heavy oil and sour oil and gas assets slightly increase by 2017. Bottom line, our growth story is even stronger. Last year, 7% of our 2017 production was still under evaluation. This year, only 2% is in the evaluation phase, a natural progression as we mature our projects. Production in 2017 from our base assets had a year-on-year increase of over 160,000 barrels per day. This increase is due to projects moving from construction to production and increased drilling activity in shale and tight resources. As our projects mature, we're not only gaining confidence in our delivery of 3.3 million barrels per day, we're building momentum for growth beyond 2017.
Jay will now cover our opportunity set that extends beyond 2017.
Thank you, George. Good morning. Let me start by taking a look at our worldwide view of key assets that will drive our growth beyond 2017. As you can see on the map, we have a large portfolio of assets that are projected to contribute growth, production, and value beyond the 2017 timeframe. These assets are in various stages of maturity, ranging from frontier exploration to development drilling in mature assets. As George mentioned earlier, we're leveraging our strong base operations organization to develop our emerging shale and other tight resources. We recently added six new opportunities, which have the potential to be long-term growth contributors. We also have 13 major capital projects in early phases of development. These projects are forecasted to add production between late 2017 and 2022. In addition, we've been actively acquiring new opportunities to supplement our portfolio.
These new assets are aligned with our strategy to enter the right plays early and to focus on organic growth. I'll cover a number of these growth areas, starting with the expansion of our LNG portfolio. Our entry into the Kitimat LNG project and the world-class Liard and Horn River Basin developments has been a great addition to our portfolio. Gas from these fields is expected to feed an initial two-train, 10 million tons per annum LNG facility. The first phase of development is currently in FEED. We're still in the early assessment of the Liard and Horn River Basin. Our partners' estimates show that these developments could hold recoverable resource volumes well in excess of 50 Tcf. With such a large resource base, these fields could readily support additional LNG trains.
Our largest LNG facility, Gorgon, has an LNG capacity of 15.6 million tons per annum in the first three trains. Our partnership has 11 Tcf of discovered resource in the Carnarvon Basin available to support a fourth train. This initial phase of expansion targets the Chandon and Geryon fields. Both Kitimat and Gorgon Train Four are new legacy projects that are forecasted to provide production and cash flow for decades. Our confidence in moving forward with the expansion of the Gorgon project is driven by our ongoing exploration success in the Carnarvon Basin, where we have the largest portfolio of exploration acreage among our competitors. Our continued success in exploring the basin is demonstrated by the 20 discoveries that have been announced since 2009, which includes seven discoveries over 2012 and 2013.
These discoveries have added a total of 10 Tcf of resource, or more than one and a half billion barrels of oil equivalent. It's not over yet, as we're planning to drill two additional impact wells in the Carnarvon Basin this year. With our sustained exploration success in Australia, we're confident there's sufficient resource potential to support further expansions, not only at Gorgon, but also at our Wheatstone development. Let's turn from LNG to another type of large expansion opportunity. Tengiz is currently producing at a rate of 750,000 barrels of oil equivalent per day, and the field has the potential to produce much more. The first step to unlocking this potential is to provide additional export capacity. The Caspian Pipeline expansion project is designed to increase pipeline capacity to just under one and a half million barrels a day and was sanctioned in 2011.
The CPC expansion is currently 35% complete. We expect to be able to access initial incremental capacity from the project in 2014. The next step in our expansion of Tengiz is the Wellhead Pressure Management project, which is currently in FEED, with FID expected late in 2013. The Wellhead Pressure Management project is designed to sustain current production levels by installing a pressure boost facility that allows wells to operate with lower back pressure, resulting in additional well capacity to support the expansion of the TCO facilities. With these enabling projects, the Future Growth Project, or FGP, is designed to increase Tengiz production capacity by utilizing the technology that was developed for the SGP, the previous expansion. That technology was put into service and proven in 2008 and has been operating successfully ever since.
Together, these projects are expected to grow TCO's production to over one million barrels of oil equivalent per day. Another important area of our long-term growth builds on our extensive experience with thermal recovery projects and involves the Wafra field, located in the partition zone between the Kingdom of Saudi Arabia and Kuwait. We've been in the partition zone for 64 years. In 2009, we started the large-scale steam flood pilot. This project is evaluating the feasibility of thermal recovery of heavy oil from the Wafra First Eocene carbonate reservoir. We are very pleased with the initial results. Information from the pilot is helping us test various technologies to determine how best to proceed with the full field development.
The first stage is expected to have a production capacity of 80,000 barrels of oil per day with a steam injection capacity of 150,000-200,000 barrels of steam per day. We also have an active steam injection pilot in the Second Eocene reservoir. We're currently maturing the project into a large-scale pilot, which will utilize many of the facilities associated with the First Eocene LSP. The Second Eocene also holds great potential for increasing the ultimate recovery of the reservoir. Based on our results to date and our decades of experience from operating the highly successful steam flood projects in Duri, Indonesia, and San Joaquin Valley, we see potential to increase oil recovery from 5% primary recovery to greater than 50%. Our growth story beyond 2017 would not be complete without talking about a few of our large offshore projects.
Hebron was sanctioned at the end of 2012. The project consists of a standalone gravity-based structure designed to handle the harsh sea conditions off the coast of Newfoundland and Labrador, Canada. The facility is designed to process 150,000 barrels a day of heavy oil and is expected to start up in late 2017. In the U.K., we're processing the Rosebank project, which is a large deepwater oil development northwest of the Shetland Islands. The FPSO for the project is designed to handle 100,000 barrels of oil per day. The project entered FEED in 2012, and we expect to reach FID in 2014. We're also in the initial stages of evaluating a hub development of the Buckskin and Moccasin fields in the Gulf of Mexico, a development strategy similar to Jack and St. Malo.
We're currently drilling the first appraisal well at Moccasin and plan additional appraisal wells at Buckskin later this year. Now that I've highlighted some of our longer-term major capital projects, let's move to our exploration activity, which, with success, will provide the resource to underpin future developments. I'll start with 2013. We continue to have an active exploration program. In 2013, we plan to invest about $3.4 billion in exploration and to drill 90 exploration and appraisal wells worldwide. We take a global view in allocating our exploration dollars to efficiently and effectively assess our acreage. Our focus areas are areas of demonstrated scale and prospectivity that form the core of our exploration program and where we concentrate significant portions of our exploration activities and resources. We recently added North American shale and tight resources as a new focus area.
With our recent success, we plan to continue our exploration program with additional drilling in the Permian, Marcellus, Utica, Duvernay, and now in the Liard Basin. We plan to drill 14 impact wells this year, more than in either 2011 or 2012, with eight of these wells in focus areas. In addition to activity in our focus areas, we've also ramped up areas in our test areas. These are areas that, with success, may become future focus areas. As an example, this year we plan to drill two exploration wells in the Kurdistan region of Iraq. Our other test areas can broadly be divided into two key asset classes: deepwater and shale and tight resources. These test areas are in the early stages of the exploration process. With their low entry cost and upside potential, they fit well in our portfolio.
We're gathering seismic and well data to determine their development potential. Our ability to form effective partnerships and to apply technology has made us successful not only in capturing, but in being able to progress the exploration and assessment of these long-term opportunities. Of course, with success, we could see production from some of these resources within the next decade. In summary, we not only have a clear line of sight to deliver our 2017 growth objectives, but a robust opportunity set to drive growth beyond 2017. Now I'll hand back to George for closing remarks.
Thank you, Jay. I would like to close with a review of our growth story. Like I said, we're on track to deliver our production target of 3.3 million barrels a day by 2017. Our base operations are performing well, and we're progressing our robust queue of projects. In 2013, we plan to grow production by 1.5% with the startup of Angola LNG and the ramp-up of Tahiti producers. In addition, we forecast growth in production in the Permian and Marcellus. In 2014, our large Deepwater projects begin coming online. In 2015, we plan to see our first cargo from Gorgon, followed by the first cargo from Wheatstone in 2016. We feel very good about our 2017 target, and we anticipate continuing to grow beyond 3.3 million barrels per day. We plan on doing this while delivering superior financial performance.
In 2012, Chevron's upstream cash margins were approximately $37 per barrel. While data from all our competitors is not in, we fully expect to lead on this metric as we've done for the past several years. When we look at the projects we're bringing online over the next five years, we forecast that they will be accretive to our portfolio cash margin. This superior performance is a result of our focus on our base business and selecting and executing the right projects with excellence. We lead our peer group in key financial metrics. We've accomplished this through our focus on operational excellence, both in base operations and in the execution of our major capital projects. We remain committed to delivering value while delivering an expected 25% growth in production over the next five years.
We're focused beyond the next five years, working to expand our queue of opportunities that will allow us to continue to deliver strong performance. Thank you for your attention. Now John will come up for a few closing remarks, then we'll get to Q&A.
Before we take questions, I'd just like to summarize a few things that I stated at the beginning. I hope you're convinced that we're delivering industry-leading results. We showed you information in both segments and in total that suggests we're doing quite well relative to our competitors. There's a lot of activity going on out in the world. Certainly, a considerable amount of turmoil, discoveries taking place in gas markets, lots of changes in the world, but there's demand for energy, and our strategies really haven't changed very much and remain very well aligned with where they've been in the past. The message this year on growth is that the 2017 target is on track, but there's more beyond that. Last year, you had asked about that. Finally, we're focused on execution. You can have very good plans, but you got to execute it.
We showed you a video that gives you an idea of the scope and scale of the projects that we have underway, but we remain focused on execution every day, and we're striving to get better every day. With that, I'll invite Pat and Mike to join us on stage. Just a couple of reminders. If you have a question, raise your hand and I'll direct you to the appropriate person, and please wait until a microphone gets to you. We'll start over here with Jason.
Thanks, John. Jason Gammel with Macquarie. I just wanted to ask a broader question about the LNG business. Many of your competitors have been willing to take relatively large percentages of their output into a portfolio and then trade that portfolio. You've really focused so far on point-to-point long-term contracts. As you look to put Kitimat, Gorgon train 4, Wheatstone train 3 plus into the market, do you think you'd be willing to take more into portfolio so that you're not really competing for customers across projects?
Well, I'll make a couple comments, then I'll invite George to offer a few words. First off, we do have some flexibility in the contracts that we have. We haven't disclosed a lot of detail around that, but we have some flexibility in our Australian contracts. One of the reasons we're ramping up the midstream activity that I talked about earlier is so that we can have a portfolio. Remember, we're targeting 85% of our sales on long-term contracts, there will be some that will be on top of that. Plus, we haven't signed the contracts yet in Canada. Any comments on Canada and how you see that playing out?
A couple of comments. One, we want to have 60% or 70% to long-term sales before we go into FID on a project. I feel much better when we have that. We know the pricing, we know what underwrites that project. We've followed that model, I think, on Gorgon and Wheatstone, and it's proven to be, I think, a very good model. My expectation on Kitimat, on the marketing side, would be just that. We would look to get 60% to 70% at an HOA level with very good customers before we would go past FID. What I do like an awful lot about Kitimat, and I'll start with the resource, is fantastic. Fantastic resource. Over 50 Tcf. Great individual wells, recoveries, all of that, very good. I like what we've ended up with a partnership.
We've ended up with a partnership, very clean, 2 50% partners. One partner, Apache, focused on the resource side, and they've drilled the wells. They know a lot about that. A really good fit for us, leveraging off what we've done in Gorgon and Wheatstone, where we've done the marketing and building the plant. I think we have built a really successful partnership. Of course, the next step is to get some customers to sign up and get to that 60% or 70% level.
Go right behind you.
Ashit Sen, Cowen Securities. Australia is becoming a bigger part of your portfolio, John, and just trying to understand some recent trends in cost, particularly when it comes to labor cost. Looks like things are improving a little bit, if you could comment on that. Secondly, there's an election coming up and some regulatory issues that we should keep an eye on. Thank you.
Oh, sure. Well, there has been some abatement in cost. I mean, what you've seen is as costs have risen throughout the construction business, not just in our industry, but in mining, you've seen some mining projects that have fallen over. You've seen a general easing in some of those pressures. Having said that, it is a very expensive labor market, to be sure. We've had great ability to bring in the people that we need to move the project along, and in general, we've gotten good support from the government. There are strong unions in the country, we have what? Over 20 different labor agreements, and we've been very effective in managing those issues. When it comes to the politics of the area, in fact, I'm headed there this week. I visit Australia a couple times a year. George visits there regularly.
We have a very strong MD and operating company head that visit there, and we've actually got good relationships with both parties. In fact, we've had one party leading in Western Australia and a different party at the federal level. We've had good relationships with both. One thing they have in common is that they support resource development, and they understand that there are cost pressures in our business, and they understand that we and others are watching them when it comes to fiscal terms or other actions that they might take that would impact our business. Our relationships have been good. Guy in the back there.
Hi, this is Blake Fernandez with Howard Weil. This may be a question for Pat. You had a slide showing the capital employed increasing over time. I'm curious if you could give us some color on the amount of unproductive capital or the amount of capital not currently contributing to the bottom line compared to historical standards.
I think Pat can give you that information.
Sure. At the end of 2012, we were kind of in the mid to high 30%. It's higher than it has been more historically. I'd say more historically, we were in the high 20s, low 30%. You did see a jump here in 2012 because of the major investments that we made this year.
It'll stay pretty high for the next couple years.
Right. You would see we have a lot of projects that are coming online as George just went through in the 2014, 2015, 2016 period of time.
Which obviously makes the returns we're generating all that much better. Okay. Well, let's see. Who has an answer? I guess we're back to round two. Okay, Paul, go ahead. I'm sorry. I'll get you next. Go ahead.
Thanks, Paul. Thank you, George. Thanks, John. You seem clearly very high confidence about the 2017, it's palpable. I think we buy in. We can see the projects. We can see the returns.
Good.
If I was to look back at history and risk what could go wrong, aside from execution, I would list the risks probably first, some sort of tax change or government change in Kazakhstan. Second, Gulf of Mexico reservoir performance. In the past, we've seen execution on top side and then failure underneath. I think you kind of addressed this, but some sort of Australian union, perhaps weather event, something like that. Do you agree with my list of risks? Would you add any, and can you address them? Thank you.
Well, one of the reasons oil price is over $100 is because there are lots of risks, and I could alphabetize them. There is a lot of risk in our business. It's our job to mitigate those risks, and we do so very well. One of the things that we've tried to do is to lay out the year when these projects come online, so you get a feel for just how big a risk is there to the 2017. One of the points that George was hopefully trying to make, we use the same chart twice, so hopefully it came across, is that these projects are fairly mature. We do have to maintain good relationships everywhere we go. Ultimately, Paul, the way I look at it is we have to be a force for good in the country. We have to be doing things that the country needs.
Whether it's Kazakhstan or Australia, they support us. They support us because we've brought jobs, we've been sensitive to the issues that they have, and they're trying to attract additional capital. They know that it's important to maintain fiscal terms. We've delivered on our end of the bargain. I expect that they will. Having said that, there are some risks
George, a couple areas you may want to comment on this space.
You mentioned ones in the Deepwater Gulf of Mexico. We tend to do a lot of assessment wells to understand that reservoir risk, because it is there. In the case of Jack St. Malo as an example, we're doing a very staged project development. The first stage was not what we foresee as the likely outcome of how many wells we would drill, but we used that view to determine whether we wanted to invest. We hedged our bets a little bit on the front end on the technical side. That's why we feel so good about the data that's starting to come out on some of the technologies that we're using there. We tend to do that. We like staging projects where we take that kind of risk out of it, the subsurface risk.
Just to mention one last comment, for us in the international setting, one of the most important things for us to do is meet the terms of our contract. We execute our contract, we do it well, we perform well. The benefits to the government is the greatest, the benefits to the community is the greatest, and of course, it actually is an easier time for us to operate when we do that very best job. That's very important for us, and we really try to stay focused on delivering those contractual terms.
Go ahead. John? Is that John?
Yes, hi. John Herrlin, Soc Gen. Question on the shales. George, you showed fairly robust growth in shale production between 2013, 2017. Could you give us a sense of what the split would be between the Permian and the Marcellus and the Utica in terms of the volume growth? Are you in pad drilling mode there?
We had the curve on that showed how much growth we saw on the Permian. We see by 2017, we're going to be in the almost 200,000 barrels a day level in the Permian by that period. We're going to have over 100,000 barrels a day in the Marcellus, and I'm giving barrel equivalents instead of gas. That's not including what we have in Michigan or elsewhere that came with our purchase there. We expect to grow from about 30,000 barrels a day by the end of this year, up to near 100,000 barrels in the Marcellus. The reason we're seeing so much focus on the Permian is the success we're seeing there. Give you a little context. The last four Delaware Basin wells we drilled, and actually us and partners, we had interests anywhere from 50%-100% in these wells.
Every one of them was over 1,000 barrels a day on IP. We're seeing good performance there. The Wolfcamp wells we're drilling out there, they're much smaller wells, vertical wells in a sense, much cheaper wells, but good performance, meeting expectations. What we're seeing in the Permian is they're meeting our expectations, meeting or exceeding, and they're high liquid content. We're really interested in moving and drilling there. We see liquid contents on most of these, in most cases exceeding 60% of the BOE. They are quite good. We're seeing recoveries that are meeting our estimated ultimate recovery estimates at this point in time, all fit in line with expectation or higher.
Like I said, the last little piece of it, the early view on the Chesapeake acreage that we purchased is we're seeing actually more productive area there, more zones potentially productive than our initial assessment was. We feel very good about that acquisition.
It's a good start. Arjun?
Thanks. It's Arjun Murti with Goldman Sachs. Actually, a follow-up question on shale and execution. Chevron has been successfully focused on the mega projects. It's something that you've done well. I think the question is from an organizational capability. You clearly put out more robust growth plans, so I assume you're feeling good about it. Can a company of your size and scale compete with the leading E&Ps in terms of well cost, a key metric, in terms of being nimble on acreage acquisition when you're feeling better about a certain area? You guys do a lot of things well. I'm not sure some of those things I'd say necessarily one would have had as much confidence as you do with some of the E&Ps.
Then is there anything about the Atlas experience that makes you feel better about adding outside people via acquisition versus trying to build this stuff in-house? Thank you.
Just a comment. I'll let George talk about Atlas and how we feel, but just a couple of comments. One of the reasons George put the chart up that showed the number of wells that we have in Indonesia, the number of wells we have in the Gulf of Thailand, the factory-style operations that we put in place in other areas, is really to show you that we do know how to do that, and we've actually been very successful at that. We're putting in that same type of factory model elsewhere. George can give you an idea of the progress that we're making.
Well, like John said, first thing we wanted to show you, we're already doing that, and I'm not sure all our competitors are, but we've been in the San Joaquin Valley forever. We drill lots of wells there. Permian Basin, we do the same thing. Indonesia, we do the same. Actually, we even apply that in an offshore environment in Thailand, where we're drilling over 300 wells a year in an offshore environment, which is a significant number of wells. So we have that capability. It's about people and processes. We feel we can, with our technology, we think we can compete with anyone in drilling shale wells. Shale activity, at this point, much of it has been very brute force.
We see a lot of opportunity to apply technology to, in effect, reduce costs, frack only the portions of the shale reservoir that really we can get gas out of or liquids out of. We see a lot of technology application that can improve efficiency, cost. When you get the combination of getting the barrels with spending less money, it's usually pretty good for us. Now, we are focused, to our best of our ability, towards the liquid side. That's why it's the Permian Basin, that's why it's the Duvernay. That's particularly in the North America setting.
Yeah. Just into Marcellus, to put it in perspective, one, we've made some visits up to Pittsburgh area, and we've been pleased with what we've seen, and the people, I think, have embraced being a part of Chevron. One of the things that it took us to do with a small company is we had to get our system lined out. Making sure that permits came timely, making sure that infrastructure was put in place timely. George and I get an update every month, I think some of you know, on our major capital projects. One of the things we get an update on every month is how we're doing in the Marcellus. We get an update from our vice president that covers that area, and we see the progress as we come down that cost curve. We do benchmarking.
We know where we are, and we're making very good progress on that curve. I think that's a long way for both of us to say, we think we can handle this, too. Go ahead, Doug.
Thanks, John. Doug Leggate from Bank of America. I want to come back to the production targets again. The 2010 target, when you laid that out, obviously we've talked about this before, that the oil price was a bit lower.
You're still using that same oil price. Atlas has been added since then. Chesapeake acreage has been added, and you're probably spending a bit more. My point being, you've a lot more stuff and you're doing a lot more with that stuff.
Are we at the point now where even if oil prices if they stay pretty much where they are, that the 3.3 million target is still good? I've got a follow-up if I may, to George.
Yeah, I think that's basically the message we've said with all the projects that are under construction. We put out that target in 2010. Seven years out is quite a ways. A lot of the projects hadn't gone to final investment decision. We had gone to FID on Gorgon, but we hadn't gone to FID on Wheatstone or some of these other deep water projects. In fact, we had a moratorium going on for some of this time. Yet we went forward with the goal because we knew we had a good portfolio of opportunities. What we see now is that these projects are underway and there's a high confidence. There's very little that hasn't gone to FID. Now, price can have some impact on base business and other activity, but you saw that's a pretty small, a smaller slice of the wedge. We invest for value.
We're going to invest commensurate with the environment that we see out there. As you've seen, most of it is under construction and ramping up. The likelihood that we'll get there is getting better every year as we get closer and more of those projects come online.
Thanks. My quick follow-up. George, could I just ask you to give us an update on what your plans are in the Utica? How quickly you expect to accelerate there? Thanks.
This year, we should start seeing results from the wells we've fracked, we've drilled for. We have two fracked, and we've got another eight or so planned to try to get drilled this year. It puts us in a good position to start answering the questions. Questions we need to understand, productivity. We need to understand liquid content. Very important for us is it predominantly gas? Is it gas liquids? Is it C5 plus? We need to answer those questions. That will tell us how fast we will want to move post that because it will tell us the attractiveness of the economics. Maybe I'd add one comment back on the 2017. There were pieces that have moved between what we said in 2010 to 2017. One piece that was in our numbers in 2017 was Tengiz. Tengiz has slipped basically out of 2017 into 2018.
Of course, that raises our confidence in that we're going to have growth in 2018. I mean, it's pretty straightforward when you have a new development that's going to be 250,000 or 300,000 barrels a day of new production, and we have 50% of it. You got a lot of confidence that you're going to have a good growth year in 2018.
We've also had property sales. There's been some ebb and flow in the project portfolio, which is I think your point. Yet we're still-
John brings up a really good point there. The thing we probably don't forecast as well is property sales. It was 15,000, 20,000 barrels a day that went away in the Cook Inlet that wasn't fully in the plan when we first went out there, but it made sense for us at that point to do it. You have some ins and outs, and we try to adjust with that. We didn't know the Permian was going to be so good either, so that's one of those cases that goes both ways.
Okay. Ed? Oh, Ed here.
Yeah, two questions. Ed Westlake at Credit Suisse. Coming back to capital intensity and these foundation projects and thinking about Kitimat, do you think the returns on the Kitimat foundation project will be sort of Wheatstone-like, or do you think they're going to be better or capital intensity? However you want to address that question.
A question on global shale. Based on the portfolio that you've got so far, which areas should we be most excited about thinking about growth beyond 2017? Thank you.
Well, on the Kitimat side, I don't think we have a lot to say because we've only been on the project a month, we don't have cost estimates. When we do, we'll be happy to share them. I think it's fair to say we're going to learn from what we had at Gorgon and Wheatstone and other projects. We have a nice site there. We know we've got a cost-competitive position on the upstream side with fairly prolific wells. It's just early days. When it comes to shale, maybe I'll let Jay talk a little bit about Central Europe is front and center for us. Maybe you can talk a little bit about that area.
Well, in Central Europe, we're in the very early days of shale exploration. We've accumulated quite an acreage position. We've got close to 4 million acres now under contract. We're negotiating with another approximately 3 million acres that are all along the geologic trend we see running through Central and Eastern Europe. All these countries are very focused on understanding and assessing their energy potential. While there's a lot of misinformation and issues floating around, we're getting strong government support. We're making a lot of good progress in working with regulators, government, and local communities to help them understand just what's involved as we move into a shale exploration program. Some of the initial issues that we ran into there, we're making progress now. We expect to drill additional wells in Poland this year, as well as Romania, additional seismic work.
While it's early days and there's a lot of things to cover, Europe doesn't have necessarily the contractor base that we have in the U.S. It doesn't have the infrastructure for pipelines that we have in the U.S. and the access. We're still very encouraged by the progress we're starting to make in these early exploration efforts in this trend.
Not many wells have been drilled either in these areas. Yes, Paul. Oh, I'll come back over here next.
Thank you, John. Paul Cheng, Barclays. George, can you give us an update about Argentina? Where is the lawsuit sitting right now, and how your investment pace may be impacted by that? Second question is that in your future growth or testing area, Russia is noticeably missing and to a lesser extent, maybe Mexico. Can you give us some idea why those two may not be in your portfolio for testing? Is it you don't like the resource base or you don't like the fiscal regime? Thank you.
I'll let George take the Russia question. I think the first one was the Ecuador question, so maybe I'll take that and make a few comments. I know most of you are very familiar with the case, and the evidence that we've put forward that shows just how pervasive the fraud is, I think is pretty well known. Most recently, of course, one of the judges that accepted bribes in Ecuador has come to the United States and given a deposition and other corroborating evidence supporting the fact that he was bribed by the plaintiff's lawyers. There's no question about the facts in the case, and so we're pursuing offensive and defensive measures. A tribunal in The Hague has moved at a certain pace, but the rulings we've had there under the bilateral investment treaty have supported us.
Ecuador was ordered to take all steps necessary to prevent enforcement by all levels of government, and they haven't done that, and they have been found to be in violation of their treaty by that same panel. That information is important because the plaintiff's lawyers are seeking enforcement actions around the world in several locations. One happens to be Argentina. Those enforcement actions go through various steps, some of which are jurisdictional and otherwise. In the case of Argentina, they were successful in having a temporary embargo placed on our operations there. We think that was an inappropriate ruling, and we think whether it's Argentina or any other government that follows rule of law will, at the end of the day, find in our favor. For the time being, we're continuing to conduct business.
Of course, any ramp-up in activity in Argentina, as you would expect, would be conditioned on us having full and free access to our cash and other resources. We'll see how that plays out. We've been a good partner in Argentina for a long time, and I expect that they will find more value in having Chevron with a continuing presence there than honoring a corrupt verdict from U.S. trial lawyers. George, you want to talk a little bit about Russia?
I will do it in a general sense. First off, you guys always want to know where we're looking next, of course, we don't ever speak about any of that that's in the cooker, right? The thing that we're working on. We're always looking for good resource opportunities around the world that match resource and on the fiscal side, a return. We are very return driven. We have the beauty right now of a very good portfolio with a long runway on it. Our focus for that reason is on early in life, early life cycle, and opportunities that meet that portfolio requirement. If they don't compete with our portfolio and our portfolio opportunities, they don't make it in it. It's pretty simple. If they're not good enough to compete, don't spend the money to put them inside.
We live by that every day that if it doesn't compete, it doesn't come in. Russia specifically has great resource opportunities
We've got to find one that matches our need to resource and return, and we'd love to be there just like any place else. Our formula is pretty straightforward.
Yeah. Our relationships are good. Jay spends a lot of time with the Russians on the Caspian Pipeline and other matters, and so our relationship is good, but it's one of those commercial issues. Not unlike what happened in southern Iraq, where we spent an enormous amount of time preparing to enter through the bid rounds, but we just didn't see the economics, so we weren't able to move it forward. There's a question back there. Yes. I can't see who it is.
Yeah. Thanks. Faisel Khan-
Oh, hi, Faisel
Citigroup. You guys mentioned you tripled your earnings in Oronite and doubled your earnings in lubricants in the graph show, but what's the notional number there so we know exactly how much earnings power you've added? I have a follow-up on the Gulf of Mexico.
How much do you want to say, Mike? Go ahead. Well, Faisel, we don't break our earnings down into those segments. I will tell you they've gone from being businesses that might've been on the margin as we've gone through our restructuring and improvement initiatives in the Downstream to ones that are clearly in the center of portfolio. They've moved from what I would call a marginal impact to having substantial contributions, making substantial contributions within our portfolio. We just don't break them down any further than that.
Okay. On the Deepwater Gulf of Mexico, George, I think in the past, you've referenced this 12% recovery factor in Jack Saint Malo, and you said that with additional data, maybe that's moving up. It looks like you've acquired some additional data even further than what you had before. What are those recovery factors now, or where do you think that's headed, and what about Coronado?
You're dying to talk about this one.
Yeah. That's true.
I want to back up a little bit. We came probably maybe as many as three years ago and told you about this technology, these single-trip frac pack that we were going to be developing. We didn't know the outcome of what that was going to be. We actually went and tested it in Rangely, Colorado, onshore, and then we went down to the San Joaquin Valley and had another full-scale test of that tool, that equipment. We just put out the announcement that it was quite successful. Give you some idea of the impact of it. It saved us on these three frac packs we installed. We saved between 20 and 50 days of rig time. That at the 50 end is about a $50 million savings. That one went perfectly well. Everything worked.
On the other side, though, we do see that we can save 20 to 30 days of rig time per completion. Now the second piece of it, does it give us the kind of completion quality that we need? That was the second piece where we told you it was equipment limited at 13,000 barrels a day of production. Based on the data we look at, we think we've got a very good chance of making IPs on these Jack Saint Malo wells in the 20,000 barrel a day range at startup. That's big news for us. We've cut the cost, which great for the future and future drilling operations there. We see the rates.
On the longer range plan of raising the recovery, in the early recovery, we actually thought the stage 1 we put in, we were looking at recoveries down in the 8%-10% range. For these two fields, that would give you about a half a billion barrels of recovery because there's about 5 billion barrels of oil in place between these two fields. Our goal is to get up to 20%. We're looking at pumps on the sea floor, which actually are going to be as a part of this stage 1, will give us a little bit of that. We're looking at pumps, ESPs inside the wellbore that will give us a little bit more. We think there is a path on technology to get to recoveries 20% or greater, doubling the recoveries, in effect, creating another half a billion barrel oil field with technology.
Now, we're not there yet, our belief is only reinforced by our recent success with this single-trip frac pack.
Coronado and the other?
Coronado is still in the evaluation stage. I would expect we would announce the outcome of Coronado on the second, probably the second quarter call. I think I'm on that one.
Okay. Right here. I'll catch you next. Yes.
Great. Evan Calio, Morgan Stanley.
Hi, Evan.
A portfolio balance question. Look, LNG's been a significant portion of your growth through 2017 and beyond. There clearly is a market opportunity. Is it a function of how opportunities stack up, or do you see any portfolio balance, organizational capabilities that would limit you as an operator in other potential LNG projects? Then a second question is maybe any update, particularly on the onshore lower tertiary, which I know you've been active in several wells there. Thanks.
Okay. I'll let George take the latter one. Basically, one of the beauties of the LNG projects that we have is that they're well staged. We're completing Angola LNG right now. Gorgon is staged to come on late 2014 with first cargo in 2015. Wheatstone is a couple of years behind that. The Kitimat project figures right in that sweet spot zone. Let's put it this way, we would not be talking about that project if we didn't think we could staff it. We've put a team together already. They're getting started working with Apache, and we were hitting the ground running. Organizational capability is a big part of a consideration for any project. Frankly, it's one of the reasons we didn't enter Southern Iraq.
It was going to be a big commitment of people, and we didn't think the returns were commensurate with the use of manpower as well as the use of capital. We feel good about it. The second part of it, George?
Well, once again, we have a great lease position in the Lower Tertiary. We've got discoveries now, Moccasin and Buckskin. We're in the assessment process. We want to get the assessment, the appraisal wells there drilled, because we want to get them to the next step. We do need to narrow the range of our views on the resource there. We'll be drilling probably almost every year in the next few years, a couple of wells in the Lower Tertiary exploration wells. That's my expectation that we'll see that. We really have a portfolio of opportunities in the deepwater Gulf of Mexico that would really justify six deepwater rigs. We have five deepwater rigs working. The amount of work that goes to exploration at this point is heavily driven by the appraisal and development activity.
We would like to be progressing our exploration actually a little bit faster.
We got four rigs working development wells.
We got four rigs working full-time development wells, and part of the time, a fifth rig working development wells. That's really our focus at this point. We've ramped up a lot. We've never ran five rigs before. Before the moratorium, we were only running three, and it takes a lot of people capability to run that many rigs. We are looking at the possibility to see if we could get to a six rig. If we can't do it really well, we're not going to do it. It's a fact that you have to do it really well, and it does take a large number of people. The good news is we've got a great portfolio.
Evan, I thought I heard you say onshore. Did you say onshore?
Did you say onshore?
Yes, that's right.
Oh, okay. Okay, I'll move.
You get a two-
I'll move 100. You'll get a two for one. I'll move 150 miles north. Lineham Creek, I will tell you that our partner, I think possibly, frankly, jumped the gun. We don't make announcements on wells in progress in drilling. When we get completed with Lineham Creek, which is a deep play on the shelf, we'll quickly inform that. We are not finished that well yet. I think we were down at about the 26,000, 27,000 foot depth. We just don't do that until we do our assessment. We get our data, our logs, and we'll tell you about it after that. We do have a great portfolio that we picked up for this deep shelf gas play.
We picked it up in lease sales in probably the prior three lease sales before there was a lot of discussion around it. If it works, we got a great position. These leases were very reasonably priced. The wells are very, no doubt, a challenge. It's what we do in exploration. The good news on it, the first wells actually have been onshore wells. They're actually being drilled from an onshore rig.
Okay. Right there was a question. Yes.
Thank you. Alan, good morning, sir. Clearly, as you just detailed, you have a very large LNG portfolio in 2017. Can you talk a little bit about your outlook for the sustainability of the price linked to oil and maybe how that relates to your contracts and how you think that market develops post-2017? I have a quick follow-up.
Sure. Well, first, we have some 65% of Gorgon that's in long-term contracts. We have 80% of Wheatstone. We have these contracts in place, these contracts are staggered, but generally, they go well into the next decade and beyond. We have these contracts in place. They have, in some cases, reopeners. We don't talk a great deal about that, but we're set for a considerable period of time with oil-linked contracts. We're in the midst of negotiating with any of a number of different parties right now. What you're seeing out there in the marketplace is buyers have seen discoveries. They see shale gas in the U.S. They see gas discoveries in East Africa. They see that developers make announcements very quickly about when gas is going to come on stream.
I think it's important to look at when FID is taken on these projects and to look at the long term. There are complexities, as I said in my remarks, to all of these projects. I think it's important to really look at what's actually happened and what the history has been. Our view is that we're going to continue to need very strong pricing. We think oil-linked pricing makes sense for these buyers, given their alternatives, that's certainly what we strive for. We won't take Final Investment Decision on projects that don't have economics that support the costs that are going to be incurred.
Yeah. In California, that seems like a similar position to what you have in the Permian, where you have a very large legacy position, a lot of people on the ground. Some people have talked about unconventional there. You've touched on it a little in the past. Is that something you ever see moving into your portfolio, or are we just still too early in the process for that? If you could maybe comment on the potential for unconventional in California a little bit.
Well, we've been very successful in Southern California. Been there for 100 years. Others have, for the last four or five years or more, made a number of very bold statements about the potential. We've been much more circumspect, and I'll invite George to give you an update of what our view is today.
Start off saying our view of the Monterey really hasn't changed over the last four or five years since we had the first question. We continue to see the Monterey as primarily a structural play. It does work, but you need structure. Once again, I'll hedge this a little bit and say for Chevron, if it's in the continuous portion of the Monterey, we don't see production rates that will compete for opportunities for investment in our portfolio. We will find it where you've got the structural play, where you've got a trapping mechanism, because we see a lot of this shale or the formation, the oil and the gas that's in the Monterey has migrated. You have to remember California's a pretty active seismic area, and one of the things that we do when we frack is we shatter the shales to create flow paths.
Well, there is a risk there that in some of these continuous plays that it has migrated. Our view is still there, that it is a for us, and I emphasize the for us, we see it more as a structural play and not a continuous play.
Okay.
David Wheeler, AllianceBernstein. I think there's a lot of confidence in the production growth and the cash flow growth from $39 billion into the low 50s. One of the outstanding questions seems to be CapEx, heavy CapEx the next few years. John, you mentioned it's hard to forecast it. Can you help us on that, though, a little bit? Base CapEx goes from $8 billion to $10.5 billion over two years. Does that keep going up $1 billion a year because legacy projects increases the percentage? I guess the other big-ticket item is Australia, additional phases of Gorgon and Wheatstone. Are the returns going to be there given the cost inflation to go ahead with Gorgon five, six? Thoughts on big-ticket spending there.
Well, this year in Gorgon and Wheatstone, we're spending some $9 billion, so this is unquestionably a big year. We have a couple of additional years, obviously, where those have construction activity. That's why I made the comment that we're going to have more spend the next two years than we have this year. We are in a period of capital spend. One of the reasons we don't give longer term forecasts, David, is exchange rates, cost of goods and services, even on the base business, can change quite a bit. If you look back, go back and chart all those estimates, because we've done it. They haven't been very accurate. Yet you'll remember.
The reason we felt confident giving you a production forecast going out a long period of time is because there's some association between the revenue side and the cost side. When you get a run-up in costs if you didn't have the prices. There's some correlation between the two. We really haven't put out a longer term forecast. The only thing I'll tell you is, if you look at the results, profit per barrel, cash flow per barrel, they're good. George has run through and every year, our criteria. Pat's talked about it at some length. We walk away from opportunities that don't have the right kinds of returns associated with them. I appreciate there's a desire to see more, but I'd rather not put something out that's going to be inaccurate.
Can I give it a little comfort?
Of course.
Just a little bit.
Please do.
Remember, there's Angola LNG that's basically we've spent the money. EGTL, we've spent the money. We have a series of projects that are coming down. What we're always trying to do is get that balance. It's hard to get that balance perfect. There are times where you'll have a project that shifts a little bit, and if one shifts a little bit later and one shifts a little bit earlier, you have that impact. My expectation is we're going to move the ones, we're going to get them done. There is some capital increases I do expect in the Permian, where we've got great opportunity there, but it's not these huge numbers. I could see over a three, four-year period, I think we could spend $300 million-$500 million more a year there than we presently are.
Shorter cycle.
Shorter cycle, quick return. You spend the money and you start getting the revenue stream pretty quick.
Yes. Back there. I think this may be the last question. We're running short on time. Yes.
Thank you, Ralph. This is Caesar, TDS and Management. Question for Pat. You mentioned maintaining financial strength. You also mentioned returning surplus cash. You have a strong net cash position. I wonder if you can share with us some of your specific targets you have, free cash position, maybe stock buybacks, your credit ratings, your balance sheet, any specific targets that you might have?
I'll just say she made a very important statement in her comments about the direction of our net cash position, but I'll let her talk a little bit more about that.
Right. So in terms of financial strength and flexibility, we have long targeted a AA position, and so we hold that as something we want to make sure that we retain the capability to secure. We have also said dividends are our number one use of cash. We have a long pattern of growing those dividends. You should expect that to continue as long as the earnings and the cash flows are there. That is a very important component. The share repurchases are the most flexible component of our uses of cash. That really will be kind of the net residual, the net outcome.
When I said that we were moving towards a more traditional net debt position, what I was really thinking of. If I just put some numbers to this, $40 billion in cash flow, $37 billion on a nameplate or a nominal C&E, but on a cash basis, that is $33 billion. Our dividends that we paid are about seven. If you just look at it on that basis, we would be at zero cash generation or net cash generation for the year. On top of that, we have had a $5 billion a year share repurchase program. If you just look at 2013 and think that the commodity prices are going to be like 2012, then you could see that we would have a drawdown in our net cash position by about $5 billion. That is really what I was referencing.
Yeah. As we get out closer to the end of 2014, you will see us, we will be in a net debt position. You will see us returning to a more traditional capital structure. We have various levers that will get us there. Okay. I think we are out of time. I thank you very much for your attention and good questions, and we will see you next year.