Good morning, and welcome to Chevron's 2014 Security Analyst Meeting. I'm Jeff Gustafson, the General Manager of Investor Relations. It's great to have you here with us today. I'd also like to welcome those of you joining us via webcast. Before we begin, I have a few important reminders.
First, and in the interest of safety, please take a moment to locate the nearest exit. In the event of an emergency, the St. Regis Hotel staff will provide further instructions. 2nd, please silence all cell phones and other digital devices. And finally, remember to take your name badge with you if you need to leave the room.
You'll need it in order to reenter. During the program today, we will provide a comprehensive update on Chevron. We'll begin with both corporate and financial overviews followed by more extensive discussions about our primary business segments, namely Downstream and Chemicals and of course, our Upstream business. Our agenda features presentations by our Chairman and Chief Executive Officer, John Watson our Vice President and Chief Financial Officer, Pat Yerington the Executive Vice President of Downstream and Chemicals, Mike Wirth the Vice Chairman and Executive Vice President of Upstream, George Kirkland and Jay Johnson, Senior Vice President of Upstream. At the conclusion of Mike's segment, we'll take a short break.
We'll also have plenty of time for questions later in the program. Other executives with us here today include Rhonda Zaygakki, the Executive Vice President of Policy and Planning and Steve Green, our Vice President of Policy, Government and Public Affairs. For those joining via webcast, I'd like to invite you to participate in the Q and A segment. Please submit your questions to us by 11 am Eastern Time through the Investors section of the company's website, which can be found at chevron.com. And finally, today's presentation contains estimates, projections and other forward looking statements.
Please take a few moments to review the Safe Harbor statement, which is available in the appendix of your booklets and on our website. Thank you for your attention. I'd now like to introduce our Chairman and Chief Executive Officer, John Watson. All right. Thanks, Jeff.
Good morning. I'd like to welcome everyone to Chevron's 2014 Security Analyst Meeting, including those of you listening via webcast. We are looking forward to providing you information about our performance, our strategies and the outlook for our business as well as answering your questions. Let me start by highlighting some of the key messages we plan to convey this morning. First, world energy demand continues to grow and crude oil and natural gas will remain vital in meeting that need.
Satisfying demand growth is a great business opportunity for us, but there are costs and other challenges. 2nd, our strategy remains consistent and are well aligned with these macro realities. We remain focused on execution both in our base business and major capital projects. 3rd, we have a strong portfolio with industry leading financial and operating performance. Finally, we are poised to deliver significant growth in production to the end of the decade and this should serve as a catalyst for shareholder value creation between now and then.
I'd like to start today by highlighting our personal and in process safety performance. We had just 58 injuries that required a day away from work all year or 0.02 per 200000 hours worked. This is remarkable given that we have over 250,000 employees and contractors working on our sites each day and they log some 590,000,000 hours of work. We continue to lead the industry. We also remain focused on process safety.
Simply put, this is keeping hydrocarbons in the pipes and vessels designed to contain them. Last year, I highlighted spill volumes. We are still world class on that metric. This year, I am showing the industry standard measure Tier 1 loss of containment performance, which includes oil and gas releases that result in spills, fires and other incidents. We're not yet where we want to be, but we are improving.
Let's move on to the macro environment. Economic growth requires affordable energy. Here in the U. S, the shale boom has boosted supplies, lowered prices for consumers, and aided job growth. It has greatly contributed to this country's economic recovery and made the U.
S. The envy of countries around the world. With a growing global population and more disposable income, people will consume more energy. By 2,030, global energy demand is expected to grow by about a third or 2% per year. Oil and natural gas is projected to make up over half of total energy demand for the foreseeable future because it's affordable and readily available to consumers.
Renewables such as wind, solar and biofuels will contribute more. But increasingly, we're seeing policymakers taking a close look at the cost of their renewables programs. The continuing industry challenge is to provide the energy the world needs in an affordable manner. Let's look at the supply challenge in greater detail. This chart compares future demand projections for crude oil to the existing supply.
Industry production shown in dark blue declines about 15% per year without reinvestment. With reinvestment in existing fields, base business infill drilling and workovers can reduce the decline to 4% to 5% per year. The base business reinvestment alone will not satisfy future demand requirements. Continued exploration and industry investment in new fields is needed. We estimate that over 200,000,000,000 barrels of base business projects and new field production will be needed by 2,030 to meet demand.
These new energy sources are from increasingly complex fields and locations with notable geological, technical and geopolitical hurdles. It will require enormous investment in both people and capital to meet demand. We estimate $7,000,000,000,000 to $10,000,000,000,000 will be required in this period or over $500,000,000,000 per year. Let's take a closer look at the cost side of the equation. We believe oil prices reflect the marginal cost of supply plus a premium that can vary over time for uncertainty and instability in supplies.
This chart illustrates the sources of new supply and the range of cost to bring those supplies to market according to Wood Mackenzie. Supplies sourced from OPEC, primarily in the Middle East, will continue to be the lowest cost source available. These countries clearly remain critical to meeting future world demand. Less conventional production sources such as deep and ultra deepwater, shale and tight resources and oil sands are growing in importance. In fact, these sources represent the majority of near term developments to the end of the decade.
While we can debate the specifics about the range, there is little debate that the breakeven prices at the margin increasing and approaching $100 per barrel or more. The quest to meet the demand wedge of the last decade resulted in higher prices. Higher prices created incentive to find and develop oil resources putting upward pressure on the cost of oilfields, goods and services. The chart on the left shows industry costs more than doubled in the last decade with only a short break for the world financial crisis. And contractors and suppliers that provide critical goods and services continue to have backlogs.
The chart on the right shows the backlog in 4 key areas. Add in tight local labor markets, civil unrest and other risks and the challenge to our industry to meet demand is great. Chevron has responded to these conditions in many ways. Notably, we've instituted much greater contractor and supplier oversight into our project management system. We have also said no when costs get out of line.
The Rosebank project is one example where a good oil resource development is being slowed to improve the expected economic return. Stressed projects will be enabled by lower costs, better fiscal and other conditions or they won't happen. And if enough projects are deferred, prices rise. This is how markets work. Growing world demand, inexorable decline curve and replacement cost realities and traditional oil geopolitics make us bullish on oil.
Let's move on to LNG. This chart shows anticipated demand growth and sources of new supply. Demand for LNG is expected to double by 2025. Most of this growth will occur in Asia, primarily China and India. But other customers are entering the market.
There are now 29 countries purchasing LNG. On the supply side, we see a big opportunity, well over 100,000,000 tons of new LNG to meet demand by 2025. This opportunity is on top of supply that will come from the 4 sources already considered in the bar on the chart. That's existing supply, international and U. S.
Projects under construction and other probable U. S. Projects. The scale of investment required for greenfield LNG projects to meet this demand Buyers and sellers will need to work together to find a value proposition that works for both. Sellers need a revenue stream that supports an economic investment and buyers need reliable supply that is priced competitively with their alternatives.
What's worked for U. S. Projects reflects unique circumstances, low cost resource, existing pipelines and brownfield sites. A different value proposition will be required to enable the next wave of greenfield projects. To sum up my view on markets, we believe the world economy will continue to grow and energy demand will grow with it.
There is underlying strength in the oil markets resulting from inevitable field declines and in LNG markets from significant demand growth. It is a great business environment for my company. They are essentially unchanged from last year and remain appropriate for the macro realities I've just described. Our upstream is growing profitably and is focused on building legacy assets primarily associated with crude oil and LNG. Our Downstream and Chemicals business has improved returns and is pursuing selective growth opportunities in higher return sectors.
Our gas, midstream and technology organizations support the upstream and downstream businesses in meeting their objectives. And finally, we are selectively committing resources to renewables and energy efficiency initiatives. We focus on growing value consistent with our strategies. Our business requires disciplined investment decisions as we have many choices of owned and available opportunities. In the upstream, it starts with the rocks.
For new assets, we look for high quality resource with attractive fiscal terms and the potential to be of scale. We favor early entry where we can apply our proprietary technology and capabilities over time. We are value driven. We apply standard investment criteria to new and owned opportunities using discounted cash flows. We use probabilistic tools that consider a range of outcomes and risks including those listed on the chart.
We set the overall spending level at the corporate center to deliver a balance of current return to shareholders via dividend and long term value growth via investment. We keep spare capacity on the balance sheet to mitigate risk of commodity prices and other factors. Most of our investment dollars go to the upstream as this is where we feel returns are best. Downstream investments are more limited, generally geared toward reliability and maintenance in our refineries and petrochemical projects. We sell assets early in life if they can't make our economic hurdles or late in life when they lack materiality and may compete better for forward investment with another owner.
Selling midlife assets is generally not favored as this is when we can add value best, applying our technology and know how. Our strategies, investment approach and funding decisions have provided us with a superb portfolio of developed assets and new opportunities. We are predominantly an upstream company. Within the upstream, we remain weighted to oil and oil linked pricing projects going forward. Our developments are increasingly legacy type in nature.
These assets are typically plant, not resource constrained with flatter decline rates and long lived cash flow profiles. Many have future expansion potential. We are also well diversified geographically with a high proportion of current investments going to Asia and North America. Let me shift to financial where our strong portfolio continues to generate peer leading results. 2013 was a solid year for the company.
We posted earnings of $21,000,000,000 and achieved a return on capital employed of 13.5%. Strong earnings and cash flow supported a sizable increase in the dividend, our 26th consecutive annual increase. We also repurchased $5,000,000,000 of our shares and funded a $42,000,000,000 capital program that included 4,000,000,000 dollars in new unconventional opportunities and exploration. I am very pleased with our shale and tight formation additions in the Permian, Duvernay, Liard and Horn River assets in North America, Cooper Basin in Australia and Vaca Muerta in Argentina. I also like the conventional acreage we picked up in the Kurdistan region of Iraq.
As I indicated last year, we are returning our balance sheet to a more traditional AA structure, though it remains pristine. Our strong earnings have been a function of our portfolio and investment choices. We continue to invest wisely in order to profitably grow our business. We have demonstrated the ability to invest for superior growth while remaining very competitive on ROCE. We are 2nd in the peer group despite significant work in progress capital on the books.
And we are competitive on this measure not only against our largest integrated peers, but also relative to large independents shown by the green line on this chart. We also think it's important to grow our share our earnings per share over time. We continue to lead our peers on this index rolling 5 year EPS measure. We believe growing the numerator is key to our leadership on this metric. As we ramp up production over the next few years, we believe the outlook for maintaining this leadership is good.
With leading performance in operating and financial metrics, it should come as no surprise that we continue to lead in total shareholder return as well. This is the 5th consecutive year we have led our peer group in the trailing 5 year TSR. We also lead the peer group and the S and P 500 in 10 year TSR. If I updated these 5 10 year rankings through yesterday's closing prices, you would see we still lead our competitors. There are 2 specific topics related to our plans that I would like to address, production growth targets and capital spending.
In early 2010, we set a target to grow upstream production to 3,300,000 barrels of oil and gas equivalent per day by 2017. We had confidence in putting out this target because we knew we had a strong queue of opportunities that would compete well for capital. We had just taken FID on Gorgon and we expected Jack St. Malo, Wheatstone and others would soon follow. Our growth strategy remains intact, though some things have changed.
Oil prices are higher and U. S. Gas prices lower than we expected we have made some portfolio choices that now impact our outlook for 2017. Our expectation for 20 17 production is now 3,100,000 barrels per day, up 20% from 2013 with more growth through the rest of the decade. There are 4 categories of impacts that explain the change from 3.3 projected last year to 3.1 this year.
First, higher oil prices reduced cost reimbursement and other entitlement barrels in some contracts. We have moved our assumed oil price from $79 per barrel first assumed in 2011 to $110 per barrel that it has averaged over the last 3 years. This impact should come as no surprise as our assumptions were clear. And of course, the overall earnings impact of higher prices is positive. 2nd, as a result of continued low gas prices in the U.
S, we've slowed the pace of our investments in the Marcellus and extended the time period of our financial carry. This is a value based decision that reduces production through 2017. 3rd, we will be selling more assets than originally planned. We expect total company asset sale proceeds of $10,000,000,000 over the next 3 years, most of which will occur in the upstream. Finally, the net effect of portfolio additions, project deferrals and project slippage has had a small impact overall.
We are also including an allowance for unknown events. In December, we released our 2014 capital exploratory budget of $39,800,000,000 This represents about a $2,000,000,000 reduction from 2013 spending. We have indicated 2013 represents a relative peak in total spending and 2014 represents a peak for LNG project spend at approximately $10,000,000,000 mostly on Gorgon and Wheatstone. We have also indicated we expect C and E spending to flatten over the next few years and I expect that to be the case through 2016. Spending in 2017 and beyond will be a function of project approvals and the cost and price environment.
I do expect our pre productive capital intensity to decline significantly as we move forward. We have been asked why our spending does not decline after the Gorgon Wheatstone peak and the answer is straightforward, because spending on projects like the Tengiz expansion, Permian Tide Oil Play and Gulf Coast Petrochemical Complex are ramping up. These investments are a very good use of funds. You will hear much more about production, financials and projects from Pat, Mike, George and Jay later this morning. Before we get started, let me remind you of some important organizational changes took place effective January 1.
Jay Johnson now has responsibility for our upstream operating units. Joe Jaza has responsibility for key technical support and service organizations that serve upstream, downstream and midstream businesses. Pierre Breber now runs our gas and midstream business. Longtime followers of our company know these individuals well. Jay and Joe report to George.
When George retires later next year, they will report to me. Other key executive positions, including Mike and Pat, have not changed and I have a very good team. Now, let's get started with more details from Pat on financials.
Okay. Good morning, everyone, and thank you, John. It's nice to see you all here again. This year, I'll be covering our capital plans and specifically what they deliver from a competitive standpoint. I'll offer some guidance on asset sales and capital intensity.
I'll also review our balance sheet and offer insights on how we use our financial strength. And finally, I'll close with the all important value proposition, highlighting the growth in operating cash flows that will result from our investments and the support they provide for enterprise value growth and future shareholder distributions. Our focus is on managing the business to generate strong returns and healthy cash margins. These lead to competitive distributions and also enable reinvestment for future growth. Here's a simple depiction of what matters in our business, the investment cycle.
It all starts at the top by having a high quality projects queue. A strong queue allows us to be selective and disciplined in our investments. It means that projects compete internally for capital and that not all projects are funded. The best investments produce strong earnings and cash margins, which in turn sustain a strong balance sheet. They also allow us to amply reward shareholders through both share price depreciation and distribution.
We've delivered. We have created the top quality queue in the industry. We have generated the highest cash and earnings margins. We have maintained a strong balance sheet and rewarded our shareholders. We've been reinvesting to revitalize the Q, which supports continued value growth.
Let's look in more detail at our investment priorities over the next 3 years. We're anticipating C and E outlays of around $40,000,000,000 for each of these years. On the left is spending by region. Our outlays continue to be geographically diverse with weighting towards Asia and North America. Our investments in Asia include the Gorgon and Wheatstone LNG projects.
We expect peak LNG spending will occur this year and then will then decline as these two projects move towards 1st production. North America is expected to capture a growing portion of our near term investments, including the Gulf of Mexico, the Permian and Canada. On the right is spending by category. Upstream accounts for almost 90% of the total, while downstream and chemicals account for about 8%. Over the 3 years, almost 60% of our capital program is dedicated to major capital projects for upstream, principally LNG, deepwater and shale and tight resource projects that fuel our future growth.
Space business outlays are projected to be just over 30% of our total spending with shale and tight resources comprising about 11%. Having a strong investment profile is a good thing if it's being invested wisely. That's how we create shareholder value. Our in terms of reinvestment rate. And going forward, as cash from operations increases and as capital spending levels out, we see this ratio decreasing steadily over the next several years.
On the right is what our average reinvestment profile is expected to generate for investors. The strongest production growth in the peer group over the medium term and for Wood Mackenzie out to the end of the decade. Saying it another way, and this is a key differentiator, we offer notably stronger production growth per reinvestment dollar than the peer group. Portfolio rationalization is another important element of capital discipline. Looking back 3 years, our asset divestment proceeds have totaled around $7,000,000,000 coming largely from our midstream and our downstream operations.
Looking ahead the next 3 years, we expect proceeds from divestments to increase to about $10,000,000,000 overall. These divestments will be more focused in our upstream operations and George will elaborate more fully about this later this morning. This is a routine evaluation for us, identifying assets either do not currently or will not in the future compete as effectively for capital against other assets in our portfolio. They are value based decisions that take into account the lifecycle of the assets. We have assets already identified as potential sale candidates, but we generally do not preannounce these for obvious commercial reasons.
The outcomes here in terms of timing and eventual proceeds will be driven by one thing, the ability to capture good value. We've been able to invest heavily for growth and at the same time remain very competitive on returns. Our recent returns reflect a high proportion of pre productive capital as you see on the far left. We anticipate pre productive capital decreasing noticeably in each of the next 3 years as several of our large flagship projects come online and as capital spending evens out. This chart shows the growth in our cash flow per share indexed to 2,008.
For the last 4 years, we've led the peer group. Our cash flow per share has grown by 25% over the last 5 years, while most peers have declined. Our past investments have delivered high value growth, growth that took advantage of a strong oil price environment. These investments are now substantial cash generators. We're poised to repeat this cycle as our current slate of projects come online.
At the same time, we're investing for the future, we're also rewarding our shareholders today. For several years now, we've had superior dividend growth. We've increased the dividend at a compound annual rate of nearly 11% over the past 10 years. This is the best in the peer group and almost 50% better than the S and P 500. Since 2004, when we first initiated a share repurchase program, we've had $40,000,000,000 of buybacks, resulting in a net 11% reduction We've had superior 3 year, 5 year and 10 year total shareholder returns, which validate our cash use decisions.
And at slightly under 6%, our current distribution yield is very competitive. In the past, I have discussed our commitment to maintain our AA credit rating. I have also discussed our view of the balance sheet as a risk These objectives remain intact. As we said we would, we move towards a more traditional capital structure in 2013, and we expect that trend to continue. We levered up modestly last year, ending the year with a debt ratio of 12%.
We're in a very sound position to fund competitive and growing shareholder distributions along with our capital program. This outcome is fully consistent with our previous guidance on our financial priorities. Our first priority is to maintain and grow our dividend. We're doing this. Our second priority is reinvesting in the business to give our shareholders a stake in a growing and more valuable enterprise.
Our third priority is to maintain our financial strength and flexibility. Our balance sheet remains robust. And finally, we're committed to returning additional available cash to our shareholders. We've done this in most years of the last decade. We've consistently applied these priorities and we've sensibly balanced these objectives over time.
I see this consistency of our approach and outcomes continuing in the future. Last March, I highlighted the significant growth in cash generation that we expected, and that expectation has changed. Assuming $110 average Brent price, our operating cash flows are expected to exceed $50,000,000,000 in 2017. In fact, we see cash generation growth well beyond that as indicated here by the blue arrow. Cash C and E in 2017 and beyond is hard to predict with any degree of certainty.
Many elements will come into play. For example, commodity prices, supporting a larger base business, the precise timing of project developments, and of course, industry cost levels. While it is hard to precisely know the angle for each of these arrows, I do feel confident saying the gap between the two for our free cash flow is expected to widen over time. The projects we're investing in, both upstream and downstream are attractive. We believe they will be accretive to our current cash margins, making our portfolio in 2017 a stronger cash generating portfolio than today.
We expect our current investments will lead to further share price appreciation and will also enhance our ability to sustain and grow shareholder distributions in the years to come. I'd like to now turn the podium over to Mike to discuss our Downstream and Chemicals business.
Thank you, Pat, and good morning. It's a pleasure to see everyone again and to discuss Chevron's Downstream and Chemicals business. I'll begin with an overview of our portfolio and our advantaged positions. The pie charts in the center panel show how we plan to change our capital employed over the next 3 years. We continue to shift our portfolio toward the higher return lubricants and chemicals segments with less relative exposure to R and M outside of Asia Pacific.
In chemicals, our olefins business has access to advantaged feedstocks in North America and the Middle East. And our Aromatics business has easy access to the growing North market. Our refining assets are concentrated around the Pacific Rim, where we have more than 3 quarters of our total capacity and the top hydrocracking position. This sets us up well for future demand growth, particularly for diesel and jet fuel. Moving to strategy, my message is unchanged.
We're focused on delivering competitive returns and growing earnings. Our supporting strategies of operational excellence, growth in the higher return segments, a focused R and M portfolio and integration with our upstream business are the foundation of everything we do. I'll expand on the first three items in that list throughout my presentation. I'd like to take a minute to talk about the 4th integration with Upstream. We routinely run equity crudes in El Segundo, Pascagoula, Salt Lake City and several refineries in Asia.
Beyond that, we support upstream with both people and technology, support and commissioning, start up, turnarounds and operations. We have refining experts in Nigeria, Angola, Kazakhstan, Venezuela, Australia and other upstream units around the world. We are committed to delivering competitive returns within the segments and also adding value to our upstream. I'll break the rest of my comments today into 3 sections. First, I'll review the Downstream business environment and market fundamentals.
Then I'll cover our performance in 2013. And I'll close with a discussion about our plans for growth. The demand picture hasn't changed much since last year. The fundamentals underlying our business reflect the realities of the global economy. On the left hand charts, you can see that petrochemicals and lubricants are expected to experience strong demand growth for quite some time.
On the right hand charts, the outlook for fuels is positive, but less bullish. We've eliminated our exposure to Europe where margins are under the most pressure. And we like our position in Asia where we'll see the most demand growth for all products. Drilling down a level, changing feedstock dynamics are reshaping the landscape here in North America, driving down the cost of raw materials. The left hand chart shows ethylene cash costs by feedstock and region since 2,008.
The Middle East continues to lead with North America gas based crackers now a close second. Both have a significant advantage over naphtha based plants in Asia. Our ethylene portfolio is positioned entirely in the 2 most production growth continues to impact crude price differentials. Over the last few years, discounted crude pricing has primarily benefited midcontinent refiners. As infrastructure brings more supply to the Gulf Coast, other grades are also beginning to discount to Brent, illustrated here by LLS.
As this effect moves into the market, we'll see better crude opportunities at our large coastal facilities. Both these trends benefit our downstream and chemicals business. I'd also like to make a few comments about the regulatory environment. Over the last half century, we've experienced a steadily evolving landscape of new regulations. When first introduced, these rules tend to create uncertainty.
In time markets and companies adapt and the stronger competitors succeed. The most recent chapter in the story is driven by concerns about climate change and the same pattern of adaptation and adjustment has begun. At the federal level, EPA has proposed lower blending targets and we're starting to see the acknowledgment that the RFS is flawed and should be repealed or reformed. In California, we're earlier in the implementation process than at the federal level, but some of the same realities are beginning to emerge. The Air Board intends to make modifications to the LCFS and key policymakers are concerned about keeping California competitive.
While it's a little early to predict exactly how the regulations will evolve, I expect they will as consumers, businesses and economics will demand it. With our strong portfolio and decades of experience in adapting and succeeding in this kind of an environment, I'm confident we'll meet these challenges just like we always have. Now let's look at performance. 2013 was different than the recent past both for our competitors and for Chevron. The entire industry experienced a retention of earnings and returns last year.
At $1.25 R and M earnings per barrel are number 2 among our peers. We delivered a 10% return on capital employed, which we expect to also rank number 2 when the final 2013 capital employed data is available. So while industry results trended downward, we maintained the relative gains we've seen over the last few years. I'd also like to talk about petrochemical financials. Chevron Phillips Chemical or CPChem is the largest private sector petrochemical producer in the Middle East and the largest producer of high density polyethylene in the world.
CPChem has delivered peer leading cash returns for multiple years now. A key element of this performance has been outstanding reliability as evidenced by their utilization rate, which has been well above the industry average over the last 3 years. CPChem also has efficiency, proprietary technology and scale. With 100% of their ethylene capacity in the feed stock advantage regions of the Middle East and North America, this is a formula for excellent financial results today and well into the future. Reliability is a top priority across all our business segments.
For the 3 biennial Solomon surveys beginning in 2006, Chevron ranked number 1 in refinery utilization. In the latest survey period for 2012, we operated at nearly the same level as our industry leading performance in 2012 fire at Richmond. In 2013, utilization declined further primarily due to the timing of the Richmond restart. But since then we're back on track as evidenced by our second half twenty thirteen utilization of more than 84% shown by the yellow dot on the chart. We finished last year strongly and carried good momentum into 2014.
Top tier reliability remains essential to our operations and the key to profitability. We've redoubled our focus on specific initiatives to further improve reliability and turnaround execution. In the past, I've explained how we've created a more focused refining and marketing portfolio in geographies with more attractive underlying fundamentals. Our marketing business flows primarily through independent distributors and retailers. This keeps capital and operating costs low and puts a premium on strong brands.
Highest brand premium of any American gasoline brands. We hold the number one market share in our core market of 5 Western States. In 2013, we saw sales increase nearly 5% in a market that was up less than 1%. And we expect similar results in Asia Pacific where the Caltex brand has been a star for more than 75 years. Initiatives to optimize station ownership and locations are targeted to increase market effectiveness 11% over the next 4 years.
We'll continue to keep our product quality high and our brands strong. Now let's talk about portfolio. While we've done a lot over the last several years, we're not finished. We continue to divest non strategic assets. Last year we completed sales of a pipeline and terminal system in the Northwestern U.
S, a terminal and retail network in Florida and our Romania and Czech Republic Lubricants businesses. Over the last We expect to close on the sale of Pakistan this year. And we've got a number of midstream assets we expect to sell this year and next. Now turning to the future, I'll summarize our plans for targeted growth in key segments and what you can expect to see over the next few years. I'll start with chemicals and our advantaged portfolio.
CPChem will start up the world's largest on purpose one exein plant in Texas this year. They're in a first mover position on a world scale ethane and derivatives units on the Gulf Coast and are the only company holding approved permits to start construction. By 2017, CPChem's olefin and polyolefin capacity will increase 32% to more than 10,000,000 tons per year. In Asia, GS Caltex's Yaosu complex is one of the largest single site aromatic facilities in the world. They're planning to expand this capacity by 35% over the same time period, contingent upon project economics and the ability to fund internally to serve the expanding North Asia market.
Both our Olefins and Aromatics businesses have robust growth plans centered on world scale facilities and are well positioned to deliver profitable growth. Now let's move to Lubricants and Specialty Chemicals. Chevron's portfolio in these higher margin businesses is unique. We're the only major oil company with a wholly owned additive business, a leading premium base oil position and top tier technology in high growth segments like heavy duty engine oils. Premium base oils are exceptionally low in sulfur and aromatics and offer significant performance advantages.
We're nearing completion of the Passy Willa project, which will increase our capacity more than 70% and make Chevron the largest producer of premium base oil in the world. Auronite is a leading producer of specialty chemical additives and has world scale manufacturing plants and technology centers in all key demand regions. This year our Singapore plant already the largest in Asia is expected to more than double its initial capacity with the completion of a major expansion project. We're also increasing capacity in France. Oranite's production capacity is scheduled to expand 20% by 2017 in line with anticipated global demand growth.
Here's a summary of our major capital projects. CPChem plans to start up the new hexene plant this year and is targeting 2017 for their new ethylene and derivative units. FASCOGUELLO base oil should reach mechanical completion in the next few weeks and be at full production by mid year. Auronites expansions in France and Singapore are slated to come online in phases beginning this year And a new paraxylene unit in Korea is expected to be complete by the end of 2017. These projects are in the right location with advantaged feedstock or market access and all of them leverage our existing asset base, technologies and partner relationships to drive future earnings growth.
So to close, I'd like to summarize 3 points. First, our strategy is sound. We'll deliver competitive returns through executing the fundamentals in our base business with a smart and focused portfolio and assets that have the scale, flexibility and configuration to be competitive. 2nd, safety and reliability are the foundation of everything we do. We're committed to further strengthen our performance in these areas, which enables superior profitability.
Finally, we're investing in the right growth projects, targeted in the right markets and segments to strengthen and diversify earnings and sustainably deliver top tier competitive results. That concludes my remarks. We'll now take the 15 minute break. Please remember to take your badges with you so you can get back in. See you in 15 minutes.
Good morning. It's my pleasure to once again review with you Chevron's upstream business. Today, I'll provide insights on our 2013 performance, our industry leading portfolio and with Jay cover our tremendous growth story. First, an overview of Chevron's upstream portfolio. Chevron has a diverse upstream portfolio with production in 26 countries and in nearly all of the world's key hydrocarbon basins.
Our upstream assets are managed through 4 regional operating companies and 15 business units. Our 2013 production was almost equally distributed among our operating companies. With our anticipated 2017 production growth, our production distribution will change. Our Asia Pacific region's production is forecasted to increase by over 300,000 barrels per day driven by our Australian LNG projects. North American production is expected to grow significantly through the deepwater Gulf of Mexico additions and by increases in our shale and tight production.
Production growth beyond 2017 will be heavily influenced by the large Tengiz expansion projects and this region should show considerable growth in the 2018 to 2020 period. Our strategies have been constant for over a decade. We're pursuing profitable growth in existing operating areas while building new global legacy positions. These strategies are all about creating value. Consistent execution on these strategies has yielded industry leading financial results with an unmatched growth profile through this decade.
Today, we'll be focusing on 3 themes: performance, portfolio, and growth. Let's begin with our 2013 performance. In 2013, net production was approximately 2 point 6,000,000 barrels per day. Our base operations delivered strong performance with a decline rate of less than 3% and shale and tight production grew by more than 15%. Our lower than planned production growth for major capital projects was predominantly related to start up and ramp up delays at Angola LNG and to a lesser extent, Usan in Nigeria.
Overall, we achieved 98% of our guidance and are well positioned for continued growth. Next, I'll cover our 2017 production target. When we first announced our production target in 2010, we specifically tied the target to a price $62 per barrel. A year later, we reaffirmed our target at $79 and absorbed the price impact on production. Since then, oil prices have moved up significantly and Brent prices have averaged approximately $110 per barrel over the last 3 years.
We are now updating our 2017 production target assuming a price of $110 a barrel. Yes, this higher price reduces our 2017 outlook by about 55,000 barrels per day. As you know, the positive financial impact of higher prices overwhelms this volume loss. Since our March 2013 analyst meeting, we decided to further reduce and defer investments in U. S.
Natural gas due to market conditions. We are slowing our Marcellus drilling, which reduces our production growth by 40 5,000 barrels per day. We made similar decisions in 20112012 when we deferred planned investments in the Piaance and Haynesville. Recently, we decided to accelerate the sale of some assets that we had planned to hold. The effect of the increased asset sales on our 2017 target is estimated at 35,000 barrels per day.
We've also made some valuable additions to enhance our portfolio. The Delaware Basin and Argentine assets have added 35,000 barrels per day to our 2017 forecast. Delays at Shandong Bay and the remainder of TCO future growth production have moved almost 50,000 barrels per day of growth beyond 2017. The changes I've just covered would result in a forecast of 3,150,000 barrels per day in 2017. Predicting production levels closer than a percent or 2 is difficult.
U. S. Gas has further reductions in U. S. Gas investments, greater asset sales or market conditions would impact production.
For this reason, we have included a future uncertainty allowance of 50,000 barrels per day. As John stated, our forecast is now 3,100,000 barrels per day at a $110 Brent price, a 20% increase in production Brent price, a 20% increase in production relative to 2013. Now look at our performance in exploration, resource additions and reserves. WoodMac data shows that Chevron is the leader in exploration resource replacement over the last 10 years and in the top tier of our peer group in costs. Our assessment is we've discovered 10,000,000,000 barrels of resource over this In 2013, we achieved a 59% success rate and added almost 1,000,000,000 barrels of resource.
The map shows the location of the key 2013 exploration additions. We had great success in North America shale and tight resources and our strongest resource adds came from the Permian. We announced our success in the Duvernay in Canada and also had good results in the Marcellus and Utica. We expanded our long list of Australian discoveries with the Sater and Kenneshnock wells and we drilled successful wells in the Gulf of Mexico, Thailand, Angola, the North Sea and in the partition zone. The barrels added in 2013 are in attractive fiscal regimes.
Next I'll cover resources and then reserves. Let's start with a long term view. Over 5 years we produced almost 5,000,000,000 barrels, divested over 2,000,000,000 and all of that was offset by over 12,000,000,000 in unrisked resource additions from our resource factory of exploration, business development and organic growth through technology application. A particularly good year with significant additions related to Kedimat, the Duvernay and the Delaware Basin. Now let's look at proved reserves.
1 year reserves replacement ratios can be variable as the reserves associated with major capital projects reaching FID is a significant factor. In 2013, we added over 800,000,000 barrels of proved reserves for a replacement ratio of 85%. Over the last 3 years, Chevron has delivered 123% reserve replacement and 100% over 5 years. Let's now review our financial performance. In 2013, we delivered leading realizations among our competitors.
We hold more than $1 a barrel advantage over our closest IOC competitor and an average of $10 over a large group of E and P and integrated companies. Our 70% oil weighted portfolio provides us a significant advantage. Last year, our upstream costs were $32.93 per barrel, approximately $1 higher than 2012 due to increased subsurface labor costs and higher DD and A. Our competitive upstream cost structure is notable since higher operating costs are generally associated with oil operations. Our ability to deliver leading realizations and a competitive cost structure has led to the highest earnings margins in the industry.
Once again, our earnings per barrel performance leaves the competition at nearly $23 That's over $5 a barrel above our nearest competitor and our 18th quarter with leading performance. We also outperformed the other large E and Ps and integrated companies by over $9 per barrel on average. We have had the highest ROCE in the upstream sector since 2011 and our 17 point 2% ROCE in 2013 is industry leading. In summary, we're delivering leading financial results as we grow our resources and production. Now let's take a closer look at the Chevron portfolio and how we manage it to drive this leading performance.
As you can see in 2004, Chevron's earnings per barrel were at the competitive average. Through our consistent value focused investments in our base business and major capital projects, we're outpacing all of our peers by a large margin. These industry leading results flow from our differentiated portfolio and our sound decision making. Managing and growing a portfolio requires a long term view. I'd like now to review the components that feed our future production and value growth.
We begin with the resource opportunities. They come from exploration, acquisitions and our ability to increase recovery from our existing portfolio through technology. Success in these areas grows our overall resource base. The consistency of our evaluation process is key to identify and develop the most economic opportunities. Initial reserves are generally recognized when we reach our final investment decision.
Reserves then move to production and revenue generation and have completed their path through the resource factory. It is imperative that we continue to replenish our queue and feed the future with high value projects. Next I'll cover more on how we manage these resources to production and let's start with our base business. Investing in our base assets is a key part of portfolio management. Through these efforts, our portfolio's natural decline rate of 14% has been reduced to 3%.
We've had great success and are now revising our guidance from 4% to 3%. Our base investments including shale and tight generally target lower risk developments and have a short cycle time to production. This investment category generally returns over 50%. As major capital projects move into the base, additional high return investments become available. Next, I'll cover how we manage our assets through their lifecycle.
Prioritization of the portfolio is done by evaluating discretionary funding. We look at the economic ranking of our opportunities and select the investments considering subsurface and surface risk and of course economic reward. Assets that don't presently compete for capital are either deferred, recycled or divested. These divestments occur early or late in the production lifecycle. Examples of these early life divestments include the joint development area between Nigeria and Sao Tome, Browse in Australia and our former Mariner and Bresee assets in the North Sea.
Examples of mature asset divestments include Cook Inlet in Alaska, our assets in the Netherlands and Norway and our normal pruning in the Gulf of Mexico and the U. S. Mid Continent. Given the quality of our portfolio, these assets that don't compete for current funding are valuable to others. Our disciplined portfolio management has delivered peer leading results.
Our 2014 Upstream C and E will deliver profitable growth through this decade. We have a budget of $35,800,000,000 in 2014 as we reach our peak spending on multiple projects. We expect a similar spending level through our 3 year business plan window. Our 2014 to 2016 C and E program is strategically divided into 3 key timeframes to deliver the right value mix. 10% of our CE is dedicated for exploration to provide long term opportunities that deliver barrels into the next decade.
60% goes to our major capital projects which are key for delivering mid to long term growth. These investments provide step changes in our production and add high value barrels. Some of the key 2014 project investments are Gorgon, Wheatstone, Jack St. Malo and of course Bigfoot. 30% of our investments go to our base business delivering near term value by mitigating decline and growing key assets such as the Permian.
These capital investments create the foundation of our future production and financial performance. Now let's take a closer look into our U. S. Liquids portfolio. Chevron is the largest hydrocarbon liquids producer in the U.
S. Most of our direct competitors have invested more heavily in domestic gas over the past 8 to 10 years, while we've maintained a focus on higher value liquids. We've slowed our gas investments over the last several years directly responding to market conditions. In the U. S, we're not only the largest liquid producer, but also have the greatest U.
S. Earnings margin and are near the top on an absolute earnings basis as well. Next I'll dive a bit deeper into the U. S. Portfolio and review our Permian position.
We've been in the Permian for many years. Back in 2011, we produced our 5,000,000,000 barrel from the basin. Today, we are the 2nd largest producer. We have the largest undeveloped leasehold in the Permian and have over 10% of the leased acreage in the prolific Delaware sub basin. In both the Midland and Delaware sub basins less than 50% of our acreage is developed.
Another key advantage to our acreage is that much of it has been in our portfolio for many years and therefore has low royalty rates. In fact, across the Permian 60% of our acreage has no royalty and 30% has low royalty. This means that 90% of our acreage position has a significant competitive advantage. Our acreage position provides us an enviable opportunity for growth with over 17,000 oil and gas well prospects identified and additional exploration potential estimated at another 8000 to 10000 well locations. The Permian Basin is uniquely advantaged over other U.
S. Continuous plays due to the multiple stacked plays. This is an acreage multiplier in the terms of resource and development potential. For example, our Midland and Delaware leases have 1,500,000 surface acres, which is equal to over 7,000,000 reservoir acres. The stack plays allow for efficient development and production from multiple zones.
Multiple wells can be drilled from a single pad location and producing infrastructure can be shared. Compared to other basins, this lowers the risk and the cost per well and the access to export infrastructure is also advantaged. We are optimizing our developments for value creation. We're not in a drill or drop position, so we can focus on the resource and prioritize our developments. According to WoodMag data, our development plan has the highest compound growth rate of the top 5 Permian producers over the next few years and again delivers long term profitability.
Our Midland Basin growth is coming predominantly from the Wolf Camp play. On the Chevron acreage, we have identified over 8,200 well prospects. In 2013, we drilled 3 30 wells and we expect to drill a similar number in 2014. In the liquids rich Delaware Basin, we also hold significant undeveloped acreage with over 6,000 well prospects. We've seen production rates of over 12 100 barrels per day in the Delaware Basin and because of that we plan to increase our drilling rate.
In 2013, we drilled 135 wells and our target in 2014 is 175. To date, the wells we've drilled are a mixture of development, appraisal and some exploration. As we shift into a factory drilling mode, our plan is to continue to increase rig and well counts. Looking out to 2020, we expect over 250,000 barrels a day of production coming from the Permian. Of this, we forecast approximately 77% will be liquids.
Once again, the Permian is a key legacy asset in our portfolio and will continue to be one of the leading producers in the basin. Our growth in profitable shale and tight resource basins also extends outside of the U. S. Into the Canadian Duvernay and the Argentine shales. As announced last year, we have strong performance with our exploration program in the Duvernay with well rates up to 7,500,000 cubic feet of gas and 1300 barrels of condensate per day.
We are increasingly confident that our 325,000 net acres are well positioned in the sweet spot, an area rich with condensate. In Argentina, progress is being made to develop the Vaca Muerta shale. The shale is thick and laterally extensive. Initial well tests indicate this is a world class shale play and approximately 140 gross wells will be drilled in 2014. Production is expected to grow to around 80,000 barrels per day by 2017, half of which will be Chevron's share.
The Vaca Muerta shale also underlays our existing El Trapiel asset in Argentina where we are testing 4 exploration wells in 2014 to further assess the shale potential. These plays all have exploration and development opportunities and will contribute valuable growth through the decade. We have a diverse gas portfolio in the U. S. With significant development opportunities.
However, the gas market is presently weak. We're positioned to deliver substantial gas growth when the conditions are right. Our acreage has low holding costs, so deferring investment is the right decision. We can adjust our plan as the market changes as we don't have to drill to maintain acreage. We've identified over 5,000 gas well prospects that don't presently compete for capital.
We'll begin developing this acreage when the market conditions provide an attractive economic opportunity. Our leading upstream financial performance and our industry leading Project Q are a product of our strategy, execution and value focus. All of our investments and assets must compete for capital. Our anticipated capital allocation over the next 3 years is shown on the right with 90% of the C and E going to oil linked assets. We'll continue to strategically invest some funds in profitable gas developments.
Less than 2% of our C and E over the next 3 years is dedicated to U. S. Gas and these investments have a drilling carry. Our U. S.
Oil investments are advantaged with limited exposure to pipeline constraints. Jay will now cover our upstream growth. Thank you, George. Good morning, everyone. Let me start by taking a look at our worldwide view of key assets that will drive our growth to 2017 and beyond.
We have more than 70 projects, each with a Chevron share of over $250,000,000 scheduled to start up by the end of this decade. In the near term, we're seeing growth from major capital projects that have recently started up and are increasing production. We also have numerous projects expected to start up between this year 2016, most notably developments in the Gulf of Mexico and our 2 LNG projects in Australia. By 2020, we expect additional growth from projects in the Gulf of Mexico, West Africa and of course Kazakhstan. Shale and tight resources are also major contributors to our growth as they account for 7% of our current production and are expected to grow to 15% by 2020.
Let's take a closer look at the status of some of these projects beginning with our project ramp ups. Angola LNG, Lusan in Nigeria and Pompatera in Brazil are already producing and are expected to grow production in 2014 and beyond. ALNG is currently running around 50% capacity and has shipped 3 LNG and 2 LPG cargoes this year. The variable composition of the plant's associated gas supply has impacted its initial performance. We expect the plant to remain at about 50% capacity until permanent modifications can be completed in 2015.
This will allow ALNG to consistently produce at its full capacity of approximately 180,000 barrels equivalent per day. At Ulsan, development drilling is expected to continue into 2018. Satellite developments are being reviewed as tiebacks to the FPSO as future growth opportunities. Papatera achieved first oil in 2013. The second well on the FPSO is already on production and the ramp up is expected to continue through 2016.
First oil from the Papatera tension leg platform is expected by the end of Q3 this year. Now let's continue with some of our significant deepwater projects. Outperformance on Jack St. Malo continues to demonstrate our strong project execution capabilities. In 2013, the Halt sailed from South Korea, the topside modules were installed and the platform was moored in its final position in the Gulf of Mexico.
With over 99% of the construction, 75% of the subsea installation and 80% of the hookup and commissioning completed, the project remains on budget and schedule for a late 2014 start up. Big Foot is another project with significant progress in 20 13. The haul arrived in Texas for integration and all topside modules were installed. We finished drilling all the wells for the initial startup. And this year, we expect the platform rig will be installed, the hull will be moored on location and the commissioning campaign will begin.
We expect to start production at Big Foot in mid-twenty 15. Another important project in the Gulf of Mexico is Tubular Bells. The construction of the spar and topsides has significantly advanced and they are now installed at their offshore location and start up is expected before year end. Production from these projects reinforces our position as the largest liquids producer in the U. S.
And a major producer in the Gulf of Mexico. Now let's turn to our LNG projects. Gorgon continues to make steady progress towards 1st LNG with construction now over 78 percent complete. Today, 20 of 21 modules needed to produce LNG has been delivered to Barrow Island. While not on the critical path, the 21st module is expected to be delivered in June.
All Train 2 modules and most Train 3 modules are scheduled to ship before year end. Train 2 and then Train 3 are scheduled to come on stream at 6 month intervals following Train 1. The domestic gas pipeline and all offshore pipeline are complete. The LNG Jetty and the 1st LNG tank are on schedule for completion this year. By year end, 18 wells are expected to be completed, each designed to deliver over 200,000,000 cubic feet of gas per day.
Only 16 of these high volume wells are initially needed to meet plant requirements. We're expecting a mid-twenty 15 startup. I'll now cover the Wheatstone progress. This project is now around 30% complete. The development drilling campaign commenced in January and the overall progress on the Wheatstone offshore platform is 50%, with the steel gravity structure scheduled for installation later this year and the top size in the first half of next year.
The Wharf can now accept marine shipments and completion of the first LNG tank foundation and delivery of the 1st process module are also planned for this year. The takeaway is that Wheatstone LNG remains on track. Now let's talk about TCO. Tengiz has significant expansion potential. We have a trio of projects to optimize existing production, expand processing capacity by an estimated 300,000 barrels per day and roughly doubled the Caspian Pipeline export capacity.
We expect the Caspian Pipeline to realize incremental capacity in stages before ultimately reaching 1,400,000 barrels per day in 2016. Around 100,000 barrels per day is anticipated to be available this month. In late 2013, alignment was reached between the Kazakh government and TCO for the expansion. Early funding has enabled orders to be placed for long lead equipment as well as allowing construction to commence on a nearby port that enables delivery of prefabricated modules. These are major steps capacity beyond 1,000,000 barrels per day.
Looking further out, I'd like to talk about 4 projects in our post-twenty 17 Deepwater project queue. Stampede entered FEED in 2013 and has completed appraisal well drilling. The selected concept is a tension leg platform delivering an approximate capacity of 80,000 barrels of oil per day. We're currently reevaluating Rosebank and Mad Dog 2 to generate scenarios with viable economics. With large potentially recoverable resources, optimized development plans could deliver valuable barrels from each of these assets.
The buskin moccasin hub development concept is still in the early planning phases with an ongoing appraisal program. Now leaving the deepwater, let's look at 2 major projects in Canada. The Hebron project is advancing with the gravity based structure under construction in Canada and fabrication of the topsides underway in Korea. The project is expected to start up in late 2017. The Kitimat LNG project will be an important contributor to future LNG market supply.
Kitimat LNG is continuing to progress and maintain its 1st mover advantage. A critical milestone in the path to a final investment decision is the placement of 60% to 70% of the production under firm gas sales commitments. Now let's look at 2 of our longer term expansion opportunities. The WAPRA 1st eosine large scale steam flood pilot continues to progress and has achieved oil recovery rates greater than 50%. The recovery factor is at the high end of our expectations and supports a full field development with FEED anticipated in 2015.
Given the results of the first pilot, another pilot is being planned for the deeper second Eocene. Initial well patterns are being drilled this year. Our largest LNG facility, Gorgon, has brownfield expansion potential with over 11 Tcf of gas available. The expansion targets gas in the Shandong and Jerrion fields. As with other LNG projects around the globe, Oregon expansion will require LNG sales contracts to underpin an economic development.
These projects all contribute to an enviable portfolio that strengthens our position. Today, our portfolio includes about 50% or 1,300,000 barrels per day of By 2020, production from our legacy assets should reach more than 60% with new production from our LNG projects, expansion at Tengiz and our shale and tight resources. The significance of these assets is that they deliver reliable long term production. Even our shale and type plays have ratable spend profiles that sustain long term growth. This growth in our legacy assets increases production and investment certainty.
This year, we plan to drill more than 75 exploration and appraisal wells worldwide. Our focus areas are key as they leverage existing business and acreage positions to maintain and grow production. North America, the Gulf of Mexico, West Africa and Australia are areas with proven exploration success. Our test areas provide new basin opportunities to expand resource capture. As an example, the Kurdistan region of Iraq has demonstrated significant potential with multiple horizons of oil.
Our initial 2 exploration wells in Rovi and Sarda have encouraging results. More wells are planned this year to further evaluate the potential. We define impact wells as having over 100,000,000 barrels of potential and we plan to drill 12 impact wells this year. We have a diverse exploration queue that includes conventional and shale and tight opportunities. With our portfolio of global deepwater projects, shale and tight resources, LNG projects and multiple expansion opportunities from important legacy assets such as Penge's and Wafra, we not only have growth potential through this decade, but well into the future to continue to deliver high value barrels.
Now George will come back to make some closing comments. Thank you. Thanks Jay. Like earnings per barrel, our cash margins lead the industry. In 2013, Chevron's upstream cash margins were approximately $38 per barrel, very similar to 2012.
Competitor data is not available for 2013. However, we expect to lead on this metric and to lead by a large margin. Consistent competitive data became available in 2,009 and as you can see we've not only been leading, but we have differentiated our performance relative to our peers. This position on cash generation is frankly what has allowed us to invest for the future and to concurrently make strong shareholder distributions. Our forecast is even better.
We expect that the cash generation of the new investments will be accretive to the portfolio. We firmly believe our production and financial growth position is the strongest among any of our competitors. With our major capital projects coming online, we forecast continued growth through the end of the decade. Projects like Gorgon, Wheatstone, Jack St. Malo, Bigfoot and others are expected to add over 800,000 barrels per day in 2017.
Beyond 2017, projects such as the TCO expansion, Hebron and growth from the Permian and other shale and tight basins add more new production. I would like to close by reemphasizing that our performance, portfolio and growth story continue long term. In summary, we continue to deliver top earnings and cash margin performance by maintaining our value driven investment strategy. With a robust opportunity queue and our growing legacy position, I'm confident that we will continue to differentiate ourselves as the industry leader in the upstream business. With that, I would like to thank you for your attention.
And now John will come up for a few closing remarks and then Q and A. Okay. Thank you, George. That concludes our prepared presentations. Just to recap what I said at the outset, we feel the business environment will be very good for our business and we are well positioned to prosper through the end of the decade and beyond.
Our strategies are right and our portfolio continues to deliver excellent results and we're poised to deliver substantial volumetric and financial growth. To ensure delivery of value, we're focused on strong execution of our base business and major capital projects. Now Mike and Pat will join me up here on the stage and we'll start taking some questions. Arjun? Thanks.
It's Arjun Murti with Goldman. John, my question was on acquisitions related to shales. You've highlighted certainly a lot of optimism in the Permian. You've got the Duvernay and Vaca Merite. You've been very disciplined over the years.
But some of the valuations, say, in the Bakken, for example, do seem to have come off the euphoric highs from a few years ago. Can you
provide any updated thoughts on how you're thinking about the acquisition environment?
Sure. Well, George made a comment that we need to continuously replenish the resource pool. And so we've done that over time. And we've done it through several means. We do it through exploration, discovered resource and acquisitions from time to time.
Last year was a big year, really and more of a discovered resource and some of these tight resources, because we thought that the opportunity was right. Over the years, we watched the Bakken and frankly, we'd like to have a position there, but the valuations have been high and we just couldn't make the economics work. So we stayed away. I think we have a good portfolio right now. We've got plenty of growth ahead of us in the Permian.
Arjun, I can't rule out opportunities that might come forward, but we feel good about what we've got right now. And so we're not looking. We've got a pretty full pot right now. So we're not looking. Thank you.
Please do introduce yourself. I can't always see everybody because of the lights. Thank you.
Doug Harrison, HiSe. John, Chevron has been pretty constructive on oil prices and more so than its peers during the past decade. And I think that you reiterated that viewpoint today. And on this point, Slides 6 through 8 indicated rising marginal cost for crude oil due to higher cost and less attractive terms, I think you talked about too, which implies changes to industry spending near the $80 Brent threshold if I read the chart correctly. So my question is would you agree that $80 Brent may be a new threshold for global spending?
I know it's just an approximation or did I misread that chart? And then second, how does Chevron manage for greater value creation in the environment that you envision? Meaning, how do you manage the balance between growth and returns given what appear to be a more challenging industry condition going forward? Sure.
Well, a couple of thoughts. First, one of the points on that chart is there's still a lot of resource that can be developed for less than $100 and less than $80 a barrel. And there's a whole range of operating environments out there, deepwater, certainly some of the OPEC nations have low cost resources. What the chart was really meant to convey is that at the margin, as we go into deeper water and as we've seen these rising costs, there comes a point where some projects just won't be able to compete for capital. Certainly for us and presumably for others, we've seen more projects in those asset classes fall over or companies have announced delays.
So I don't know that there's a hard threshold because fiscal terms vary considerably, whether it's deepwater or in other areas. So I wouldn't want to put a hard and fast rule, but we certainly know of projects that are at $100 a barrel aren't economic any longer. In terms of how we take a look at our priorities during this period, One of the things I commented on is that we do our economics really with probabilistic economics. So we take a look at cost. We have always evaluated our opportunities under a range of different price and cost and production scenarios.
So we actually put together what we term in our business S curves and really have a view of the upside and the downside of projects and that won't change now. And if we start to see a better environment on the cost side of things, that will be reflected in how we look at our projects going forward. George talked to Steve, he has got any specific thoughts on some of the trends that we are seeing now in costs and his thoughts? Well, on cost side, it is different in different areas. We have seen some costs come down on the onshore drilling cost.
Land rigs have gone down. I think we're in a period maybe we're going to see a flattening or maybe even a little bit down on some of the deepwater rigs. We're seeing more deepwater rigs come out of shipyards. So maybe we're at a point where we're going to be at a plateau on that. I will tell you costs are still very high in the subsea arena for hookup, the hookup portion of it, the manifolds, all that piece is high and it is impacting some of the projects, some of the deepwater projects.
There is more variability than there was in probably the past 10 years. There everything seemed to move up. We are seeing some differences in different segments.
Thanks for the Ed Westlake, Credit Suisse. Thanks for the CapEx outlook, a few extra years it helps. I have a question I guess around the contingencies. What's the worst case CapEx scenario that you could think about if some of the Aussie dollar changes or projects perhaps the suite progresses smoothly as you think?
I don't know what the worst case is that I we put if you noticed in some of our outlook for 2015 2016, we put a little bit of shading up there because there can be some variability. But look, we have a pretty good understanding of what costs are likely to be for Gorgon and Wheatstone at this We've done a lot of contracting. Obviously, in Gorgon, we're at the final stages. So, we have a pretty good idea of what costs will be. There can be variability in exchange rates.
But I'll tell you, we're managing capital pretty closely right now. We've put a budget of $40,000,000,000 and we're watching that very closely. So there will always be some ups and downs. That's why we put a little bit of a shading around that. But we can see the top line cash that we need to generate in order to continue to pay and grow the dividend as a pattern of earnings and cash flow from that.
So we're fairly committed to it.
And then specifically in the Permian, you've got 50,000 barrels a day of production growth. If an E and P company had 1,500,000 acres in the Permian, they'd probably put something up somewhat higher. Can you talk about your confidence in or maybe why that trajectory is the shape it is and maybe the constraints you see that other zones and maybe towards your ability to execute in shale?
I know George is dying to answer that question, so I'm going to let George answer that one. Well, there's several things there. First off, for us, we are in a different position than almost all our competitors on the lease. Most of them have tied up their leases in the recent past. They have lease positions that have royalties in the 20% to 25%.
They have drill and drop. So they don't have a lot of choices. They got to move. We like being a little more ratable and make use of and find the sweetest spots to drill first and use the leverage of those first investments are the strongest for in the future the infrastructure they create, they will create more value and more of these opportunities in the future that aren't quite as good, not maybe in quite as good a spot on the reservoir side. They will still be good economics because they're leveraging off our earlier investments.
You can't do that if you just mow through it. You just can't. We don't have to do that. We're looking at a large growth over this period. My number is something like 130 1,000 barrels of growth.
That's big. That in effect is equal to a couple of major capital projects of kind of average size. So it puts us in a good position that we got a nice ratable in effect major capital project that's ratable capital, that's also ratable on barrels each year. So it's a little bit smoother. For me, I'd like to get to that point in the Permian and I'd like to get to that point in the Duvernay.
It'd be very nice to have a couple of assets like that that you can be ratable, ratable growth, ratable capital and know those barrels are coming and not be quite as dependent on being 1 quarter earlier, 1 quarter later, 6 months later on a major capital project. So big advantage having a couple of those in our portfolio. Okay. Let's see. I'll take one.
Paul, I guess, here.
Thank you, John. Paul Chan, Barclays. If I could, two questions. John, I think for the last comment, you started talking more about the high cost and mid to some project being dropped off. In the past, you're talking about organizational limit and the supply chain.
If we look at today, which is actually a bigger constraint factor for you to take on projects?
Well, I think the 2 go together. Part of the reason we've seen costs rise is because the supply chain is tight. I showed you that chart that indicated that the backlog for contractors is generally high. George indicated there are some areas where we may see some loosening in the market. But fundamentally, it's a strong market for oilfield services and equipment.
And we don't see that changing. As far as our own people go, we've been very successful at adding capability to our organization over time. About half the hires in the technical ranks that we've done over the last 5 years have been experienced hires. And we certainly continue to hire on college campuses, but with the boom we've seen over the last decade, we've gone outside the company, we brought in some great professionals. Right now, we think we're able to attract the people that we need.
And we've instituted, as I referenced in my comments, more oversight in the contractor community and QA, QC and planning and number of other areas to be sure that contractors are executing as we hope they will. But we feel we've got the people to do the work. There's still the tightness in the supply chain and that's reflected in prices.
The second question, probably for Pat. In your chart, you saw you're targeting by 2017 cash flow from operation maybe over RMB 50,000,000,000. In 2013, it's about RMB 35,000,000,000. So that's an increase of over RMB 15,000,000. If George had talked about the average cash margin for the upstream is $38 You are targeting 500,000 barrels per day increase in your production.
So that's about RMB 7,000,000,000. Can you help us to bridge the gap? Where's the other RMB 8,000,000,000? Thank you.
I guess some arithmetic for you there, Beth.
I think the component that you're missing perhaps is the fact that we said that the overall portfolio in 2017 would be stronger than the overall portfolio today. So it's not just on the increment, it's on the full portfolio. So in other words, it's the 3,100,000 barrels a day at a cash margin that is higher than today's cash margin of $38 a barrel. That makes up the difference. We also have contributions coming in, in 2017 Pascagoula base oil plant as well as CPChem.
But the vast majority of that increment is, of course, related to upstream.
I'll try one back there. I'm sorry, I can't see it right.
That's all right. Roger Read, Wells Fargo. Thanks. Maybe just to follow-up on the cash OpEx side. If we look at one of the biggest projects coming on Gorgon, can you give us some idea of how we should think about cash costs with that?
Obviously, you'd expect them to expand given those numbers. And then the second part, given the troubles with Angola LNG in terms of getting it up to speed, I recognize that we're the gas stream not as consistent maybe as what you expected at Gorgon. Can you give us an idea of the
testing you've done so far that gives you confidence that once
you're up and running on Gorgon, the startup should be relatively smooth or as smooth as can be hoped for?
Yes. I don't know that we'll give you a precise forecast for OpEx for Gorgon, but I wanted to let Jay talk to you about both those subjects. So in terms of first the reliability, ALNG versus Gorgon, as you pointed out, they are very different projects. Gorgon is using dedicated gas for the field, both Hyogent and Gorgon to supply the field. The issues with ALNG have been on the gas conditioning that go into the LNG facility.
The LNG facility itself is performing to expectations. So we're quite comfortable in terms of the prediction of performance for Gorgon. At ALNG, what we're doing now is evaluating adding additional separation capacity for liquids on the front end as well as additional dehydration capacity. What we'll do is take a turnaround to install that additional capacity and then that's what will allow the plant to come to full rate speed. In terms of Gorgon's cash generation capability, it is a Did you say cash OpEx?
So I think about in terms of its ability to generate cash in terms of the first of all, you're looking at largely oil linked contracts that generate very robust pricing for the project, very large scale in terms of the production and the cost per barrel. So this is an asset that will generate, I would say, robust cash generation for decades and really serves as a great source of cash generation for us going forward. Maybe just add a comment to help you on that and not specifically point out the Gorgons, but Gorgon is a huge part of the cash move for us going forward. And that chart that we showed probably near the very end in the upstream segment where we showed the cash margins of the total portfolio going up. Well, the existing portfolio doesn't change that much.
The impact of the improvement, the accretive nature of it is really all driven by these new additions. These new additions are cash accretive in total to the whole portfolio.
America. Maybe this question is for Pat on the balance sheet. And I know it's we're talking long term timeframes here, but you have said several times that your capital expenditure in 2013 was probably your peak, but does that timeframe associated with it? Because as we look forward as your cash flow grows, are we then suggesting that Chevron Chevron is going to move into harvest mode at some point or does beyond 2017 does the CapEx continue to ratchet higher? I've got a follow-up please.
Well, I think I was the one that used the term relative peak, so maybe I'll try that. All I was trying to get across is that as you go down the road 5, 10 years, we'll be a bigger company. I don't know what the cost of goods and services. I don't know what the price environment is going to be. So to say that something is a peak forever just didn't seem like the prudent thing to say.
2013 is a peak for capital spend as far as we've planned. And going forward, harvest mode implies liquidation or something of that sort. We have these big projects coming on. Gorgon and Wheatstone, our combined spend on these two projects is over $40,000,000,000 We've got nothing like that. We've got some great projects in our queue, but we've got nothing like that where we're going to spend $40,000,000,000 in a within a 6.70 period of time.
I guess the related question then is and this is my follow-up. If I look at the portfolio capital intensity, it's still George made a great point about your unit cash margins, but you're spending the same as a company 40% bigger than you and delivering not dissimilar growth. Do you expect that that changes? I guess that's what I mean by harvest mode. Is there a point where Chevron starts to throw off free cash as opposed to the cash burn that Pat talks about by moving the balance sheet
Let's talk about that. Let's talk about that. I think you're referring to our largest competitor who spoke the other day and they're a terrific company. My understanding based on what was presented is they produced 4,200,000 barrels a day in 2013 and in 2017 they will produce 4,300,000 barrels a day. So that's pretty flat.
What we're saying is that we're going from 2,600,000 barrels a day to 3,100,000 barrels a day. That's barrels a day. That's 500,000 barrels a day of increase. And I mean, that's a fairly significant difference going forward. I think it's important, if you look at a couple of the charts where we showed decline curves, you can invest at a low rate and decline at 3% or 4% a year until you run out of base business projects.
But to realize growth, either to get you up to even get you to 3% growth or 4% or 5% growth on top of that, it takes a large increment of capital. And I think that's what you are seeing right now for us. And so that's why you're seeing spending that's comparable, but I think there will be different outcomes from that spend. Yes.
Thanks, John. It's Robert Kessler, Tudor Pickering. I'd like to follow-up on your just most recent comment about kind of base versus growth CapEx and maybe drill down into Tengiz specifically. When I look at the 3 projects there, 2 of them look like maintenance projects to me the way they're phrased. As you look up to get to that 1,000,000 barrel a day kind of production level, how much of the overall spend is what you would call maintenance type spending that persists maybe on beyond reaching that 1,000,000 barrel a day threshold and how much is the growth CapEx?
Yes. Well, we've got 2 projects and I'll let Jay describe them. But there's it's important to distinguish between the 2 and I'll let Jay do that. Yes. Thank you.
There are, as John said, 2 projects that are going to be conducted at the same time in Tengiz. The first is called wellhead pressure management project. I think this is the one you may be thinking of about maintenance. It's really not. What it simply is, is a boost to take all of the existing field production and compress the gas and pump the oil up to the high pressures that the plants require, effectively lowering the back pressure on the wells, which allows us to get more production out of an existing well base.
The alternative would be to have to drill a lot more wells. So it actually is contributing to that decline, arresting the decline out of the existing wells. The second project is future growth project. This builds on the pilot work we did with sour gas injection. It's been so successful.
What this does is actually increase our production production capacity an additional 250,000 to 300,000 barrels a day. And it allows all the gas from that to be re injected back into the platform for extends our base and allows extends our base and allows us to minimize the amount of drilling we have to do. The second one builds on top of that to add the incremental capacity. The third project was expansion of the export pipeline, which is pretty evident.
How much CapEx for each of these?
We haven't released CapEx numbers for that. We expect to take FID later this year and that's normally the time when we would put some numbers out around those.
Thanks. One other for me if I could real quick, John.
We don't want to do too. Okay, we'll come back though.
10,000,000 dollars
I guess I was on the phone. Okay, go ahead.
$10,000,000,000 of asset sales, what's the upside to that? And you referenced it being upstream weighted. What happened in the midstream incremental divestment potential there?
Yes. $10,000,000,000 is the number that we've got for the next 3 years. Most of the divestments we've had in the recent past might show you some numbers have been as we've been really sizing our downstream and some of our midstream assets the way we want them. We are nearing the end of that in the downstream. In the midstream, we are continuing to monetize pipelines, power plants, things like that that really aren't integral to flow assurance for our Upstream and Downstream businesses.
So we have some think of them as merchant or third party activity going on and we think given the valuations that are out there, we can get more value. We are still going to be in the pipeline business. We are still going to be in the power business. In fact, in a very big way with self generated power in our business with pipelines from Jack St. Malo, the Caspian pipeline and others.
So we will still be in the midstream business, but it will be more clearly associated with the activities that we have underway. You should think of 80% plus of the asset sales that we talked about would be in the upstream end of the business. We will go over to Evan.
Thanks. Evan Kalia, Morgan Stanley. John, you've been through a few cycles. And last cycle, productive capacity, not majors collective CapEx. And while different, I think both are constructive on future oil price as well as future returns.
So, really in this plateau to peak CapEx world and in a world where we're seeing increasing resource potential, whether that be other countries opening or other unconventional assets. I mean, do you expect or has your upstream threshold for projects increased? Has your geopolitical risk decreased? And I know that you Rosebank, Mad Dog, they're being re examined. Vietnam, India chose not to enter as some examples.
So
are your as your threshold changes, is it something that could be a
foreboding for improved returns and
flat commodity price?
Well,
our economic criteria hasn't changed over time. The conditions that go into the economic valuations obviously do change. Part of what you were saying at the outset was more geared toward our view of markets and I guess the way I look at it is over the last decade we've seen 750,000,000 people move into the middle class and that's resulted in demand growth. So despite the sharp increase in prices, we continue to see demand growth and we continue to see more people that will be entering the middle class around the world. So that's why I said we are fairly bullish on increasing demand for energy in general.
And if you are bullish on the increase in demand for energy, then decline curves take over and it's going to take a significant amount of investment for our business. So there will be periods where you will have an ebb and flow in terms of the investment environment, pricing. We have been in a flat period for the last few years. But I think what under what sets behind all of that is this underlying demand. And you'll have an imbalance between costs and prices for short periods of time.
You can have that. And when you do, markets work. We pull back on projects that aren't economic, presumably others in the industry do the same thing and you get a rebalancing in costs. It either happens through cost or price if we're shrewd about making our investment decisions. I'm not sure if I answered your question, but that's what I'm trying to yes.
Thanks. Faisal Khan with Citigroup. You've had kind of delays or cost overruns for a number of projects EGTL and Golar LNG, Shenzhen Bay, Bigfoot and Gorgon. I guess I want to understand is sort of what are the lessons learned from sort of these delays and cost overruns and how do you ensure that you'll see these sort of issues take place in the future?
Yes, I guess I'll start with the basics. We didn't get to a leading portfolio with a $5 a barrel average margin over all of our competitors if we weren't pretty good at selecting and executing project. We're living in challenging times for executing major capital projects and I went through some of those earlier. Maybe what I can do is, Jay is very knowledgeable about projects. We'll let him talk just a little bit about some of the things we're doing in our project management system to talk about addressing some of the risks that you described.
Thank you. So, I think it's important, 1st of all, to think about projects both before they start execution, when you can see delays. FGP would be an example where we thought it would get to FID a little bit quicker. These we pace at the speed that they're going to take to get them right. We're not in a hurry.
We're not going to drive them prematurely. Many times, it's driven by the commercial and political environments more than they are the technical issues that are associated with these large projects. Projects like you mentioned that are in execution, We tend to have a better handle on the schedule and the pace of these, although you can always get unexpected events arising. In the case of Gorgon, we had some issues with the logistics of trying to get all that material and equipment onto an island. Those then were recognized as an issue and were addressed if we're not having those issues any longer.
We had some exchange rates that started going against us in the Gorgon project with a lot of Australian dollar spend. That's now moving back towards center. But what we try and do is, as John pointed out earlier, we try and characterize the uncertainties that we face with all of these major projects and build the execution plan such that we can adapt and incorporate these changes and still be able to deliver an economic project at the end. And I think as you see with Gorgon, we're now 78% complete. All the one module are on the island for the start up next year for the LNG.
We are seeing good success as we move forward with projects like this. We routinely take the lessons learned, for example, Tengiz SGP, what we learned in executing that major project was directly transmitted to, for example, the Gorgon team as they looked at a major land based project. And so one of the issues you saw was a shift from stick build construction to module design, and a project that's built largely through prefabricated modules. This also came from the deepwater where we have a pretty good history of delivering these projects. And that technology then was adapted for onshore service.
And so it's given us better rateability that is now being applied for FGP and WPMP in turn. So as we do these various projects around the world, the lessons learned are routinely captured and then they're fed into the other projects as we move forward and we're seeing the results from that effort. One thing I might maybe George will comment on is the nature of our contracts with the contracting community and how those have changed over time. Yes. Just you go back 10, 15 years ago, the projects that we did on scale, the large ones, you could do those with a lump sum bid to a contractor.
The projects we're doing today, there is not enough financial capability in those companies. They make a mistake, they are out of business or they put so much cost in effect insurance into a lump sum bid that it will just kill the economics of it. So we have had to look at different ways to deal with our contractors. We tend to break the contracts down into smaller chunks. We have become in many ways more of the general contractor that has forced us to have more people that are capable to put all the pieces together.
I think we've been very successful in doing that. But it was a challenge and it was something we had to recognize right up front. You can't expect a contractor to go do a project where his cost of the project is 2 or 3 times the enterprise value. We've been we've become more intrusive. One of the lessons learned on these capital projects is, you can't just sign a contract and expect a contractor to execute, given the stakes in some of these projects.
So we've been much more intrusive, larger owners' teams and different tools in our project managers' handbook, if you will, that's a device that's used by our project professionals to be sure that we do capture all the lessons learned and that we are on top of everything the contractors do. In the old days, you signed a lump sum, you let them go and you came back and they were done. It doesn't work that way anymore.
My second question was, it's a short question, is that you guys lowered your decline rate to 3% on the base business. Does that not show up in the production outlook? Because it doesn't show up in that sort of bar chart that you guys laid out?
It is it's not shown up in there that we have just now with now 3 years or 4 years of lower than our 4% decline rate. We have made a decision to we see a path forward on the 3%. I would tell you it may even get better after we get the Gorgon and the Wheatstone zone and have another set of assets that frankly have flat production. Over that period of time, it could make a difference in our production. We have not built anything in there recognizing that at this point.
Most of our business plans have actually moved the last couple of years to a lower decline rate from the business units. So our forecast once again is based on our business plans that we work with our business units and we're seeing their decline rates going forward being less. I'm going to take one question from online. We have a lot of people on webcast and maybe I'll give it to Pat. How do you determine if there's a better value in investing in a project compared to returning cash to shareholders via repurchasing?
Because I know some of you have asked that question, so I thought I would give her a shot.
Yes. So we I mean, obviously, I laid out our cash use priorities, start with the dividend and then move to the reinvestment in the business opportunities. We have a 26 year dividend growth history. We obviously want to retain that. That's very important to us.
But we also want to be able to sustain the growth in the value of the enterprise. And we do that by virtue of the quality of the Project Q that we have. And so we're always constantly balancing the near term returns to the shareholders via dividends and share repurchases against the longer term value creation opportunity that we've got that in fact sustain the ability for the firm to continue to grow dividends in years on out. So we constantly play against this tension. And I don't think that you can say that there's a static view at any given point in time.
We always look at it relative to the facts and circumstances that we have at hand. Having once taken dividends and a growth pattern off of dividends off the plate.
Okay. Let's try one right in front.
Paul McCrea from Tower Bridge. A strategy question. A number of somewhat cash strapped E and P Companies have made major natural gas discoveries and are moving downstream into LNG. We're your partner, Apache, for example, to need to monetize its investment 50%, I believe, at Kitimat and they came to you and said, we're going to be selling it down, would you step up to the plate?
Apache is a publicly traded company and I probably shouldn't speak for them. We obviously have a good partner in Apache for the Kitimat project and I think it's premature to speculate on either what they've talked about what their plans Our plans, we've got a 50% interest and I wouldn't see our percentage increasing from there. Okay. In the back, yes. It's Sam from Cowen
and Company. Two questions, John. First, is KTMAT in the 20 15, 2016 long term CapEx trajectory? It looks like it's not mentioned on the chart here.
George, you want to talk a little bit about or Jay, you want to talk a little bit about where our spend is? Kitimat, we have money for Kitimat to do engineering, site work and do the appraisal work in Liard. We feel it's necessary to do that work. We need to do more assessment work in Liard and we need to be ready to move if we have gas sale agreements made. So we're moving on spending money in that light.
We do not have money in there for if we reach a point that we would be ready to go to FID. So the FID expenditure profile is really not in there at this point. We expect we've got at least another year of assessment work on Liard. And once again, back to the point, we've got to have gas sales contracts. We're not going to expose the big money post an FID period until we have gas sale contracts in hand.
And my second question is on, since we are talking about cash margins in Gorgon, any early thoughts on Canadian LNG cost structure, so relative to Australia and your thought process when you're evaluating Kitimat relative to T4 and Gurgaon?
We've certainly been our efforts in Canada are certainly informed by all the work that we've done in Australia, but we don't have firm cost estimates. But anything you guys want to add about cost? We're in the stage of trying to get to more firm estimates of costs. We've got good ideas on resource. We want to confirm those.
We need to confirm the cost of drilling those wells. They are great wells in Liar, but we've got to find the right well cost to fit with the development. So we've got work there. So we've got to come up with the design of the well that will make the most sense. So we've got work there.
It's just premature at this point. We've built off of what we've learned in Gorgon and Wheatstone on the cost structure on the plant side. We have that in hand. And I'll go back to the critical element on it is gas sales contracts. We've got to get those.
Justin Jenkins with Raymond James. Maybe shifting to the U. S, given the production growth we're seeing and expect to see in U. S. Liquids, are you concerned about price differentials and how that may affect enrollment?
Good question. We've talked about that in the past. We're obviously not in the Bakken. We tend to be more in the Permian. And maybe I'll let Mike talk a little bit about some of what we are seeing on the pricing side.
It has an impact both downstream and upstream. So I'll let Mike talk about it generally and then George or Jay can talk about the upstream impact. So I tried to touch on that with the one slide that talked about feedstocks. And if you look at NGLs, it is certainly to the benefit of people that are currently in the petrochemical business as we've seen ethane and propylene price is very advantageous and it shows up in CD10's results and it's part of their plan to move forward with this new cracker. Certainly on ethane, the length of time that that condition may persist is important to us.
And given the trends that we see right now and really the binary choice that goes with ethane either into the natural gas or into petchem feeds, that would look to be something that would be to the advantage of the petchem business for some time to come and to the detriment I guess if you're producing ethane in terms of realizations versus historic levels. On the crude side, you've seen the WTI disconnect narrow as we discussed last year was likely to happen and we're seeing it push now into other domestic crudes. Really, as production continues to increase, the inability to export means you have to try to price those crudes to displace other crudes out of the refining system that are being brought in from somewhere else. And at some point, those discounts are required to incent refiners to buy that crude versus another economic alternative. That's a situation that can persist as well.
The wildcard there is if the policy constraint were to be lifted, now those crudes can get full market value in export markets and those differentials could disappear, which is actually why that LLS chart comes back because an assumption I think that PURA makes in their work that the export ban is rescinded. From our standpoint on WTI, we've been somewhat naturally hedged. The amount of WTI priced crudes we run-in our refining system roughly equivalent to the WTI priced crudes that we produce and sell into the market. So we haven't been really hurt so much on that. As you get as it pushes down into some of these other crudes, we also run those crudes in our system.
And so as an integrated company, we do have an offset when those things happen as opposed to the producer who is just looking at a reduction in realization. Anything you want to add, Josh? Yes. Specifically on the LLS one, we made a decision and I think a very good decision a couple of years ago to invest in a pipeline that comes from the deepwater Gulf of Mexico and goes directly to our Pascagoula refinery. So for a certain amount of those barrels and a large piece of our barrels, we are as about as naturally hedged as you can be with our barrels going directly to the refinery and that's a positive, not all our barrels, but a large percentage of them.
And I and just maybe one other thing, you saw Mike's trajectory on this differential and how it goes away. It goes back like you said to what we saw in West Texas really on for many of the crudes there. In this country when there is an arbitrage, somebody works hard to squeeze it out and they do it pretty efficiently. The market's pipelines. The markets here really work at an exceptional level.
So I wish I could say that for every place, but they work exceptionally well here. I'll leave it there. Thanks. Thank you. I think right behind you was a question.
Good morning, Alan. Good morning, Star. Pat, if I
could just follow-up on some
of the priorities of cash flow
that you gave earlier. You mentioned obviously funding the dividend and the capital program are priorities. But it looks once you get to 2017, certainly you'll have a lot more cash flow than you've had these past few years. Can you talk a little bit about the balance there between whether it be debt repayment and building back a negative debt position as you've run before or whether it's maybe a little bit greater dividend growth or maybe even relatively more share repurchases compared to what you've done in the past?
And I don't want to get specific about projections out there. I think we've been consistent in saying the dividends have priority. We'll obviously take a look at what the capital program needs to be to support future value growth. I don't right now, we're sitting at a 12% debt ratio. And I think we have pushed ourselves partly through the share repurchase program into a more efficient capital structure.
I don't see a need for us to back away from that quite frankly, because I think most people, ourselves included, would have said when we had a 7% debt ratio and we had net debt, net cash, we were under levered. So I think having a little bit more efficient capital structure would be a nice place to be if the circumstances warrant that.
Okay, thanks. And then you mentioned a lot about the gas sales agreements needed for FID on some
of these projects. Can you
just talk about what you currently see in the market? I know you mentioned the deficit when we get to 2020 or so with LNG supply relative to demand. But what do you see right now from in the market when you're trying to market some of these projects? And how do you balance marketing, call it, Kitimat versus some of your expansions in Australia?
Yes. Well, I talked a lot about the gas markets, and what I see is a lot of tension right now, actually between buyers and sellers. And it's easy to explain why. We're seeing very low natural gas prices in this country and whether it's customers in Japan or in Europe, they have to compete with our businesses and they're seeing the advantage of low cost gas and they want some of it both their businesses and for their consumers. So they are also looking at the cost of gas in the United States and saying, boy, we could put a liquefaction plant and transport it and get it over to Japan or Korea and do so at a competitive price.
So they're trying to push prices down. That's a natural thing for them to do. And I made a comment that it's one thing for that on brownfield plants where there's existing infrastructure in place. But I think when you look at cost, transportation and perhaps a longer term view of domestic gas prices, I think you end up in a different place. Our view has been for a long time that for the Asian market that oil linked pricing made more sense.
That's the alternative. If you think about the margin, what the alternative is, it tends to be burning oil in many cases. That's how that market grew up over time. We think the realities of costs are such that it's going to take stronger prices. If you look some of the very low price expectations that have been cited in the media, I mean, our projects won't go ahead with those prices, whether in Kitimat or Australia.
So, it's going to take a meeting of the minds by customers and suppliers or we'll see that gap widen over time. I mean, right now, I don't think that we are market limited in selling LNG. We're supply limited. And that's why you're seeing spot prices above crude parity right now. And I think it's important that the industry and customers find that mine so that our industry can continue to meet the energy needs that are out there by the 29 some countries that are now importing LNG.
Do you want to get more specific? Well, just maybe the huge risk out there right now is that there is not a meeting of the minds. There is not economic projects created through some mechanism of their participation or the pricing, but there is not a project then there is no gas for the demand. And there is only 2 projects at least that I saw last year that reached FID on in the LNG world. The one in the U.
S. And Yamal. So it was not a lot of projects and relative to the growth, it doesn't meet the demand. And you'll note in our chart, we gave the benefit of the doubt to a number of projects that are planned in the United States and there's still a big gap and we think it's going to take strong pricing to make them go. Yes.
Hi. It's Ian Reid from the Bank of Montreal. Just a question about Tengiz again, John, if I could. Obviously, Tengiz is pretty important and pretty at the top the earnings and cash flow metrics you've talked about. And you talked about an agreement you made with government to allow the expansion to go ahead.
I'm just wondering whether anything in that is going to impair in any way the kind of leading earnings per barrel numbers you've been reporting out of Tengiz in terms of what you need to do in order to move the project forward or is there something else in there which we should be clear? Well, I'll make a couple of general comments and I'll let Jay speak. I'll just say we've got a very good relationship with the government of Kazakhstan. We've had consistency in the application of our contract over time and it benefits them greatly and they know that. There is variable royalty and other provisions that enable them to be quite successful and that's why they've supported that contract.
I'll let Jay talk a little bit about going forward the project. Thank you. The contract that's in place in Tengiz persists and the terms that FGP and WPMP are being built under are under the original contract. So there is no change. This agreement really comes from what we're talking about earlier in terms of learning lessons from previous projects.
So it involves the financing of the project for the government share. It involved a local content expectations. This project is heavily focused on smartly using local content. There's fab yards in Kazakhstan, which we will be utilizing, but we'll also be doing a lot of construction in the we how things would be brought in, foreign workers licenses, all the things that can derail a project during execution. We wanted to reach agreement upfront and try and make sure we had clear expectations with the government on the progression of the project.
So, it really didn't affect the terms of the project per se. Just one other thing if I could. You mentioned 12 wells and I think this year which you're particularly excited about.
I wonder if you
can just give us a bit more details about where those wells are going to be drilling. The impact exploration wells? Yes, the 12 high impact. So these wells are across the globe. About half of them are in our focus areas, half are in these new test areas.
There are a number of them in Kurdistan region of Iraq that I mentioned earlier. We've got exploration wells in Duvernay and in the Permian as well as Gulf of Mexico. Okay.
It's Faisal Khan from Citigroup again. I wonder if you could Mike, if you could tell us how much foreign crude you pick back out of the U. S. Refining system, like, than where you are today? And the second question is, have you looked at using the free trade agreement between Korea and the U.
S. To move crude to the plants over there?
The amount of foreign crude we run-in the system, it's in our annual report supplement and so you can see that. We have long standing term supply agreements with some suppliers from outside of the country that are very important to us and underpin our refining economics, particularly on the West Coast with some of the crudes we bring in from the Middle East. The logistics to get domestic crudes into the West Coast refining system are pretty challenged. And so with good quality crudes from the standpoint of matching our refining system and a long term relationship that's yielded very competitive crude pricing over the years, I think both we and our suppliers displaced crudes, I think you see more of that happen where the logistics are favorable to bring domestic production into the refining system, which tends to be in the Gulf Coast. And so we really get our Pascagoula refinery where you could see that happen.
And it's an economic optimization question. I mean, we're after that every day looking at our alternatives, both domestic and non U. S. So going forward, it's a function of those markets and the logistics and pricing as to how that balance would work out. I can't say that we've looked at using the Korea U.
S. Free trade agreement to bring crudes from the U. S. To Korea, which I guess is your second question. We can't export crudes today and I don't think that the free trade agreement changes that materially.
So I think until you see the export policy of the government modified a scenario like that is unlikely. Korea has got pretty good logistics from the Middle East and other places as well. And so I think you're going to find places that are closer to the source of the crude that are likely to be more economic than taking U. S. Crudes all the way across to Korea.
Okay.
Thanks, John, for the follow-up. Just looking through the slides as you were talking. I wanted to go back to Paul's earlier question about the margin. It looks like the proportion of oil linked production doesn't really change. The mix changes a little bit from oil to oil linked, but the total sort of oil leverage, I guess, doesn't really change over the portfolio.
So Paul's earlier point, I guess, was the unit margin improvement to close the cash flow gap. Can you give us some ideas to how you expect unit margins to evolve with the change in the portfolio mix over the 3
or 4 years? Thanks.
Well, George, are you talking about cash margin or are you talking about the cash margin, as George said, from the major capital projects that we have are modestly accretive to the portfolio. So, we feel very good. Now, those that's actually the entire portfolio, right? That is the whole portfolio. That's the whole portfolio.
So that's why I say we feel very good about these projects. And remember for Gorgon Wheatstone, 75% of the gas is placed and it's placed at contracts that are oil linked. I hope that answers it. Okay, I think I see fewer and fewer hands. In fact, I see no hands in the air.
So I think we've answered all your immediate questions. I'll thank you very much for your time and attention and your investments in Chevron. Thank you.