ConocoPhillips' CEO Hosts Analyst Meeting (Transcript)

| About: ConocoPhillips (COP)

ConocoPhillips (NYSE:COP)

Analyst Meeting

February 28, 2013 8:30 AM ET


Ellen DeSanctis - Vice President, IR and Communications

Ryan Lance - Chairman and CEO

Matt Fox - Exploration and Production EVP

Al Hirshberg - EVP, Technology and Projects

Jeff Sheets - EVP, Finance and CFO


Doug Terreson - ISI Group

Doug Leggate - Bank of America

Paul Sankey - Deutsche Bank

Faisel Khan - Citigroup

Ed Westlake - Credit Suisse

Iain Reid - Jefferies

Jason Gammel - Macquarie

Paul Cheng - Barclays

Blake Fernandez - Howard Weil

Robert Kessler - Tudor, Pickering

John Herrlin - SocGen

Evan Calio - Morgan Stanley

Roger Read - Wells Fargo

Scott Hanold - RBC Capital Markets

Boris Raykin - Granite Associates

Ellen DeSanctis

Good morning, everybody and welcome. My name is Ellen DeSanctis, and I’m the Vice President of Investor Relations and Communications for ConocoPhillips. For those of you in the room, thank you so much for being here today, and for our listeners on the phone, thank you for your participation as well.

This morning you are going to hear from four of our senior executives and let me take a moment and introduce them to you now. Ryan Lance, is our Chairman and CEO; Matt Fox, is our Exploration and Production EVP; Al Hirshberg, is the EVP of Technology and Projects; and Jeff Sheets, is our EVP of Finance and our Chief Financial Officer.

In addition, we have some other members of our senior leadership team here this morning and I welcome those of you in the room to introduce yourself to them after this morning's event.

And now let me take care of a few quick but important administrative matters. This morning's meeting will be webcast live. Our materials are now available on our website. A replay and a transcript of this call will be available shortly.

And then finally, I know several of you have looked ahead in the book, so you already know this, we will be making some forward-looking statements this morning. Our future performance could differ materially from the expectations we share today. The risks and uncertainties in that performance we’ve outlined in this cautionary statement shown here as well as in our periodic filings with the SEC, the most recent of which it was our 10-K filed on February 19th.

And now, it is my sincere privilege to invite Ryan Lance to begin the meeting.

Ryan Lance

Well, thank you and good morning, everyone. It is my pleasure to also welcome you to ConocoPhillips’ first investor analyst meeting as an independent company. You’ll notice the title of the slide, it’s unchanged since we launched this company in May of last year. We do think we represent a new class of investment for investors and we are looking forward to sharing our plans with you today.

Our whole organization is fully committed to organically growing and creating value for ConocoPhillips. I’ll tell myself, my entire leadership team and 16,900 employees all of us are align with getting this done.

So what does new class of investment mean? It means that our goal is to consistently and deliver stable and predictable returns to our shareholders. We are going to do that through a very diverse and global asset base, rule strong technical capability, a committed workforce and financial strength.

So it is about organically growing this company, growing the production, growing the margins, growing the cash flows and growing the returns. And we are off to a great start in 2012, we had a great start in 2012 and let me just share a little bit about what our performance was for last year.

Certainly, the strategic highlight of the year was completing the separation of our downstream business. So ConocoPhillips emerged as a E&P company completely and totally focused on this side of the business.

We were executing our plans. We are running well. We announced dispositions to core up the portfolio and help fund our growth programs. We met our volume targets for the year, with some notable achievements 100,000 barrels a day out of our Eagle Ford area and growing, 100,000 barrels a day out of our oil sands position and growing, and our first production out of our large Gumusut Field in Malaysia.

We delivered 156% reserve replacement which for company our size is a pretty considerable achievement, the business is running well. Our growth programs are on track, our projects are on track and we are building momentum on the exploration side both unconventional and conventional.

Now 2013 and 2014 are important years on the exploration side, we got to put runs on the board, but we are off to a really good start. I’m not going steal Matt’s thunder because I’m going to let him tell you about some of the success we’ve had on the exploration already.

Financially, we’ve maintained a strong balance sheet, our A credit rating. We funded almost $8.5 billion to shareholders this last year through share buyback and dividends, and certainly delivered strong shareholder return and that shown here on this next slide, push buttons here.

So you look at our performance in 2012 and the shareholders were well rewarded. We outperformed the peer group and we outperformed the S&P 500. So we are off to a great start.

But we understand that it's the end of February. The clock is ticking and it is about what are we doing in 2013 and what are we doing to deliver on our plans. So we spend rest of our time talking about what our plans look like going forward.

So we started ‘13 in a great position as a company, globally, diverse, a great set of assets. We are the largest North American based independent company, 1.5 million barrels a day of production, 8.6 billion barrels of reserves, 80% of those reserves are located in OECD countries, giving our portfolio a lower risk field relative to the competition.

We've got another incredible attributes around the portfolio, large, legacy positions around the world, considerable number of development programs in around those legacy positions to keep our production flat over the timeframe we will talk about. Inventory of high quality, development projects, they are adding topline growth and high margins to our production and our financials.

And we’re positioned around the world in many of the key areas. We have significant technical capability. We have a strong balance sheet and financial flexibility, and an ongoing commitment to our shareholders.

But we are in an environment, we are executing this business, prices are relatively high today, but uncertain futures, and this shows the range of uncertainty around the forward look on commodity prices. My crystal ball is any clearer than many of you in this room today.

And the range of these prices whether on the high-end or the low-end is a subject of what you think supply/demand is going do and some of the geopolitical factors that impact that. And we know that we are seeing local and regional dislocations in some of the prices like WCS are led back to bitumen in the Canadian oil sands in North American NGL prices.

What I will say is when we develop our plans, we are typically on the low-end of these ranges as we think about our long-term plans that we’re trying to execute in the company. We see that we run scenarios now and we think about the business factors, the cost environment and the regulatory environment that we are in, and we make sure our plans are resilient at the top end and low end of these ranges.

One other important point, the margin analysis that you are going to see today, big part of our value proposition is based on real prices of Brent at $100, WTI at $90, WCS is $70 and $350 Henry Hub.

But against that uncertain future world we think we’re well-positioned as a company. We do believe that our diversification, our size and our scale are competitive advantage. We are not reliant on one product, one geography, one geology to succeed as a company and we think that's an important competitive advantage in this business today.

We're focused on organically growing the company. We are going to make our investments in high-quality development programs in and around our legacy assets. We are going to execute major project programs that deliver top end growth through our production and very high margin when they come on.

We’ll apply our significant technical capability. We'll maintain our financial flexibility and we are also looking to rebalance the portfolio a little bit. So we've talked about divestitures to core up the portfolio. We’re also looking at trying to rebalance overtime. The reason we're doing this is to try to drive the portfolio to a lower cost of supply and provide more flexibility in the portfolio.

This means, like large asset positions like APLNG and oil sands, we would like to reduce our exposure to some of those areas over time. Now, these are great assets and great resource positions but with our growing unconventional and deepwater opportunities, we would like to rebalance the portfolio over time.

We’re not in a hurry. We’re not going to do a bad deal. We’re going to do a deal that make sense to the company but we’ll tell our plans today to assume that we’re going to lighten up in assets like APLNG and the Canadian oil sands over time.

But it is about creating good choices and options in this portfolio. We have a great legacy position to draw upon and we've captured a lot of great compelling opportunities for the company. So it is about trying to balance the portfolio to the higher set of opportunities that deliver the best returns and margins for the company.

So that's a bit of the -- how we’re going to go through and do this. This is the one. And that's unchanged as well from when we launched the company in May. This is our value proposition. And it is to deliver stable, predictable returns to the shareholders. We’re going to do that through a relentless focus on safety and execution.

We’re going to run this business well. We know how to do it. It’s part of our legacy. It remains a core part of what we're doing as a company. We’re going to offer a compelling dividend. We’re going to offer 3% to 5% production growth, 3% to 5% margin growth with an ongoing priority for returns, not only absolute returns but returns relative to the competition.

So at the end of the day, it’s a dividend, its 6% to 10% growth in production and margin delivering double-digit returns. That’s we’re all committed to go to and that’s the value proposition we have for this new class of investment.

Now, this is how we’re going to fund our capital program, where we’re going to direct our capital and the kind of production that we’re going to deliver. We’re reaffirming what we came out in May last year and said long-term, we’re going to grow this company 3% to 5% and that's off our base in 2012 that we’ve talked about last May.

Now, we do see a bit of a dip in our production in 2013. We also talked about that in May and that’s coring up the portfolio and selling the assets that we've announced. We expect to close those this year. But off of that base in 2013, that's pretty impressive growth for a company our size.

We have clear line of sight to 1.9 million barrels a day by 2017. And that growth is real, the growth is in execution today and is delivering high-margin. So let me talk about the margin into that story, which is the other half of the value proposition that we’re offering here to the investors.

So the left-hand slide -- left-hand side of the slide, those were the five major growth areas that we’re executing around the world today. And you'll see relative to the portfolio today, these investments are in areas where it's a different product mix, it’s mostly liquids and oil and it’s in geographies or areas that have lower effective tax rate relative to our base portfolio.

And that delivers the margins that are shown on the right-hand side of the chart. So it isn’t about just growing production. It’s about growing high-margin production. And Matt and Jeff are both going to come up and talk about the opportunities and details and clarity around where this growth is coming from and where this margin is coming from. So it's clear what we're doing, how we are going to deliver it and where it’s coming from.

Now, as I think about our cash flows, we think about the priorities for that cash and the dividend remains the top priority in our business. It underpins our performance and provides a predictable return to our shareholders. And our commitment is that we will grow that over time modestly as our cash flows grow.

And I've seen it. It does enhance capital discipline in the company. It does work. And it remains our top priority. Next, we’ll invest in the capital program that has deep rich inventory of opportunities both in and around our legacy assets and grow the company and an exploration program to continue that growth and development well beyond the timeframe that we’ll talk about today.

The balance sheet is important. It's an asset in the company just like any other assets that we’re developing. So we’re going to maintain that strength that provides us flexibility through the cycles. And we’ll consider share repurchases. We’ll do that when the environment provides that opportunity and provided it competes against the investments that we have in our portfolio today.

So what are you going to hear today. So Matt’s going to come up. He is going to talk about our base in the legacy assets we have around the world. What we're doing to enhance and maintain and defend the base production we have around the world today.

He is going to talk about rich and a deep inventory of development programs in and around those legacy assets to keep our production flat. The major projects that are in execution for topline growth and high-margin opportunities for the company and the upside that we’re experiencing in building out of our exploration program, both unconventionally and conventionally.

Al is going to come up. He is going to talk about how we’re using technology and innovation to drive greater performance out of our base, our projects, our development programs and help our exploration organization get access to rich opportunities around the world.

And then finally, Jeff is going to come up and he is going to talk about the margins. He is going to talk about the growth. It’s real. It’s an execution where we’re making our investments and how we are driving in increasing our cash flows. So we can fully fund this capital program that I talked about in the dividends.

So with that, that will complete my opening comments. I'll come back later and close it up and take questions but I'd like to turn it over to Matt. And he is going to talk about the base portfolio, where we’re making the investments in driving the margin in this business.

Matt Fox

Thank you, Ryan. Good morning, everyone. So I’m going to do this morning is build upon Ryan's opening remarks and talk about our five-year plan in some detail. And my objective is to give clarity and confidence in our ability to grow our production and our margins by 55% a year over the next five years and give you some line of sight and to what's coming after those five years from our exploration program.

So let’s get started. This is the slide that Ryan just showed and I'm showing it because of my boss likes it, I like it. I'm also showing it because they -- if you look at the capital allocation strategy that’s represented on the left-hand side of this chart. This is really what drives our future production growth, our margin growth and our growing returns.

And my presentation is designed to work through this capital allocation strategy and give you a clearer line of sight into the details of where the growth is coming from. So we intend to spend about $16 billion a year over the next five years.

We’re going to invest about 10% of that in base maintenance. So that’s thing -- that capital investments that improve our operating efficiency or extend the life of our existing asset base. And most importantly, this capital investments to maintain their operating integrity of our legacy assets.

We’re going to spend about 45% of our capital on what we call development programs. And what that means in our vernacular is, these are really drilling-led programs. And they’re either drilling around our legacy production assets with very little infrastructure cost required and very little incremental operating costs or the drilling programs are creating new legacy assets for, as in places like the Eagle Ford and the Bakken.

That -- the production associated with those development projects mitigates base decline, in fact more than mitigates base decline as you can see on the right. They completely offset base decline. So that’s a very important part of our capital investment and I’m going to give you some detail and confidence in how these development programs will do, we’ll do just that.

Then I’m going to spend about 30% of our capital investing in major projects around the world. So these are typical major projects for a large E&P, major capital investments with a lot of infrastructure upfront, some delayed gratification before production arrives. In fact, that gratification isn’t really significantly delayed because the production from our major projects that’s going to kick in at the end of this year and continues to grow all the way through this five-year period, resulting almost 3% to 5% growth.

But we are not satisfied with just five years of growth. So we are investing 15% of our capital in exploration and appraisal to deliver growth beyond 2017. And I'm going to talk about that in more detail later. So that’s a high-level view of a few of those presentations going and I’m going to start now by giving you some color on our base.

So the base production is the foundation upon which we build this growth and is very important for us as an organization to make sure that we are protecting the base properly. And we have very rigorous and systematic operations excellence programs in place that are applied across the whole company where we have knowledge sharing -- in fact, we have a award-winning knowledge sharing across the whole organization to make sure that things that we learn in the North Sea can be applied to Malaysia, things that we learn in Alaska can be applied in Australia and so on.

Now, often when people say but surely the stuff that you learn in the North Sea in an offshore environment from an unconventional reservoir, that can be applied to unconventional reservoirs in Texas, kind it? Well, absolutely it can. Because it turns out that a lot of conventional wisdom can be applied to unconventional developments that you will see that as we go through the presentation.

So, I will give you one example. In Stavanger, Norway, we have a state-of-the-art integrated operations center. This is as good or better than anyone else has in the industry, and what integrated operations center onshore does is it manages our integrated planning and optimizes our day-to-day production in our fields offshore in Norway.

So we've taken those processes, those tools and we’ve transferred that to integrated operations center in Houston that is going to manage the operations for our Eagle Ford development and Al is going to talk a bit more about actually augmenting that to customize it for an onshore environment, such as one example but there are loads of examples of where these learnings from parts where our portfolio can be applied to other parts of the portfolio and is one of the strengths of the diversity that the company has.

So the decline -- I’m going to show you decline rates for each of the major segments as we go through the presentation. The average decline rate unmitigated is about 10% a year over these five years. The mitigated decline is zero, but the underlying decline from wells that we’re producing at the end of 2012 is about 10% a year. It’s a bit higher in our dry gas assets and it’s a bit lower in our liquids-rich and oil assets, but averages by 10% a year. And then the development programs completely offset that decline.

So, I’m going to go on and talk about the development programs. So these development programs are going to add 600,000 barrels a day of production by 2017. Now that's a pretty impressive production add over five years. I think you would agree. About 250,000 barrels a day of that is going to come from what we call our legacy conventional business. So that’s an international developments around our major projects, our major assets. I'm going to talk about those in more detail.

Over 200,000 barrels a day of that comes our three major programs in the Lower 48, the Eagle Ford, Permian and the Bakken, I’m going to talk about them in detail. And then it’s made up to 600,000 barrels a day through additional North American unconventional developments that I will also talk about. So, I'm going to go through each of these in turn. And I’m going to start with Alaska and work clockwise around the globe to give you some detail on each of this.

So starting with Alaska and before I go into the details on Alaska, I just want to clearly this slide because of lot of these slides that we are going to talk about look the same as four-pack. What are you going to see on the right-hand side are some numbers? How much we are going to spend in capital over the next five years? What the F&D characteristics are out of that capital spent? And then some factoids around what we're doing.

In the bottom right, you're going to see two bar graphs. The one on the left is our current production mix within that segment or asset base. It varies a little bit and the one on the right is the incremental characteristics of the -- incremental production is coming from these development programs.

This gives you a sense of what's happening to the margins associated with these development programs. On the left, you are going to see the incremental production that comes from the programs. And on the top left, you are going to see a pretty picture or map, okay.

So that’s just clears. You are going to see a lot of these slides and I don’t intend to talk about. All the details are on these slides. You guys can do that. You can read that at your leisure. So just hitting the high points. In Alaska, we have numerous development opportunities in and around the existing assets, all the way from Prudhoe to Kuparuk to Alpine and the associated satellite fields.

And what we are doing is we are applying high-technology drilling capabilities and things like coiled tubing drilling, steerable liner drilling guided by time lapse 3-D seismic surveys that we call 4-D seismic. And Al is going to talk more about this technology or these technologies actually in his presentation.

So that investment results in an incremental 35,000 barrels a day by 2017, which mitigates the base decline in Alaska to about 3% a year. Now this doesn’t include the Alpine West major project. When we add Alpine West then the base decline is mitigated to about 2% a year.

Now there are a lot of these opportunities across our legacy asset Basin slope. But the fiscal regime in Alaska is not as competitive as it needs to be to make sure that those opportunities are fully exploited. And we know that the Alaska legislature and the governor are working on ways to improve the investment climate in Alaska. And when that’s done, we can see additional opportunities that we could take advantage of to grow production in Alaska and to grow production through the Trans Alaska Pipeline System.

So moving from Alaska, now to our Western Canada business unit. We have an incredible legacy asset base in Western Canada and what we're doing here is we are taking advantage of unconventional technology, long horizontal wells, multi-staged fracs to go into our legacy asset base and find new ways, essentially revitalizing this asset base using these unconventional technologies across multiple plays.

These development programs will add over 100,000 barrels a day of production by 2017, and mitigates the base decline over this period to zero, a zero decline rate. So there is a dip in 2014 and ’15. And all of these projects have rates of return above 20%. We are not going to invest in them unless they do. And what you can see, the reason the returns are high is if you look at the bottom right chart, the liquid yields from these investments has doubled the current liquids yield of our Canadian Western Canada asset base.

And the NGLs that are shown up here, these are C3 Plus. Ethane is sold in the gas stream. So these are C3 plus, so they are valuable NGL barrels. So, if I move now from Western Canada to our European development programs. And here we are focused on extending and growing the value of our legacy asset base. Some of this is basic blocking and tackling, infill drilling, managing our water floods well, but we are also find high-technology at 4-D seismic and intelligent well installations to make sure we really are getting the best of our existing assets here.

And you can see again on the bottom right that the incremental production is a better liquids mix and the base production. So the margins are going to grow associated we think this incremental production and that contributes about 40,000 barrels a day by 2017 and mitigates base decline in Europe to 7%. Now, when we add the major projects that are going on Europe. I’m going to talk about in the few minutes, we actually growing our European production over these five years.

So let’s move on from Europe now to Southeast Asia and talk about the incremental production associated with our development programs there. Now really the story in our Asia-Pacific, Middle East region is about major projects. But for completeness I included this here, because we do have incremental opportunities here that are drilling high value gas in Indonesia, drilling infill and extension wells in Bohai Bay. The third phase of development at the Bayu-Undan field adding LNG and condensate production. This contributes about 25,000 barrels a day by 2017, that’s same sort of high margin mix that we currently have in our Asia-Pacific, Middle East segment.

So, I just want to pause for a moment here, because I’m about to come back to the Lower 48 and talk about our development programs here. But what I just should you was more than 200,000 barrels a day of production.

All of which is coming higher margins than our current base and all of it coming from around our legacy assets. And we have more opportunities like this that are emerging around all our legacy asset positions was 200,000 barrels a day of increasing margins from our legacy assets outside the Lower 48.

So now we’ll move to the Lower 48, I’m going to talk first of all about our Permian conventional opportunity set. I’m going talk later of our Permian unconventional opportunity set.

The Permian Basin is a Basin that keeps on giving, really as a remarkable Basin and we have 1 million acres held by production in the Permian. We see a lot of opportunities in our conventional assets to add high-value barrels and you can see on the bottom right here. This is essentially all oil that we’re adding through these conventional programs.

This investment over these five years as 40,000 barrels a day to the conventional production and it results in a 7% compound annual growth rate in the Permian conventional.

And there are lots of additional opportunities within our Permian conventional asset base all held by production and we will see more growth from our Permian conventional base in the years beyond this.

So let's move on now and talk about our two major development programs in the unconventional areas. I’ll start first by talking about the Bakken.

So we're right in the heart of the trend of the Bakken. We’ve got 600,000 acres in total in this area 200,000 of it is right on top of the Nesson Anticline and we’ve got 400,000 of mineral acreage also that will have development potential in the unconventionals too.

So you can see on the bottom right, this is all oil and this compared to existing Lower 48 average product mix. We’re going to add 45,000 barrels a day by 2017 and that’s an 18% compound annual growth rate from our Bakken assets.

And there is lots of opportunities remaining here, more than 1,400 identified well locations, 600 million barrels of resources, of those 600 million barrels of resource, we have only booked so far about 90 million barrels. There is a lot of growth remaining in our Bakken position.

Now if I move from Bakken to the Eagle Ford. Now the Eagle Ford in our view is the best unconventional play in North America. If you are in the right part of the play there and we believe that we're right in the middle of the sweet spot for the Eagle Ford. And the sweet spots is where you are in a volatile oil and gas condensate window, because that’s where you have high compressibility, low viscosity, so you get high rates and high recovery factors, and you get significant fraction of that from oil and NGLs as you can see in the bottom right.

Now, we acquired this acreage at $300 an acre. We were one of the very first movers into this Basin and we identified the sweet spot, and Al, is going to talk more about how we identified the sweet spot and how the technologies that we’re applying here are going to grow the value of this unconventional position and our other unconventional positions.

So in the Eagle Ford, we are going to add about 130,000 barrels a day by 2017 and that’s an average of 16% compound annual growth rate over this period. And we’ve got more than 2,000 identified well locations still to drill, of the 1.8 billion barrels of resources that you see here, we put about 200 million barrels of that so far, huge amount of growth, huge amount of potential remaining in the Eagle Ford.

So now what I want to do is to put the Eagle Ford, the Permian conventional and the Bakken in the context of our overall Lower 48 development programs. So I'm doing in this one is adding to that other legacy development opportunities in places like the San Juan, the Barnett, the Gulf of Mexico and the development opportunities exist in our Niobrara and Permian unconventionals, and we are going to talk more about both of those a little bit later in the exploration section.

But what we are adding here is 365,000 barrels a day by 2017, for about 5% to 6% compound annual growth rate. And let’s talk for a moment about the graph in the bottom right here.

Our current production in the Lower 48 is 60% gas and 25% oil. The incremental production that we are adding is 60% oil and 25% gas, complete change in the mix in the portfolio and it doesn't take a rocket surgeon to work out that this is going to improve the margins in our Lower 48 business.

So I’ve just gone through the details of our worldwide development program inventory and I hope I’ve given you some clarity and confidence, and how we’re going to develop these 600,000 barrels and why they are all coming with improved margins over our current base.

So what I’m going to do now is I’m going to move on and I’m going to talk about our major projects around the world.

Now, all of these major projects are outside the Lower 48 and it really highlights the strength of our diversity and our legacy positions and our new positions. These are going to add 400,000 barrels a day by 2017. And we don't have to wait till 2017. That production going to start showing up in the fourth quarter of this year and 2014 is going to have added 150,000 barrels a day to our production and then growing to these 400,000 barrels a day by 2017.

So what I'm going to do here now is move around the globe starting in Canada with our oil sands position. Now you -- I assume that you guys all know who James Carville, the political commentator that worked on Bill Clinton's campaign and he famously said one time, during the campaign he said is the geologist stupid.

No, he didn’t say geology, he actually say, is a technology stupid, I think anyway it doesn’t matter, we’re both of those covered, both geology and technology covered here, because we have a top tier position driven by the geology where at -- and assets based in the oil sands.

So over 1 million net acres here. You can see in the top right our steam oil ratio is top quartile average steam oil ratio. We are in the right parts of the oil sands and we have a lot of additional acreage that provides further optionality as technology develops to reduce the cost of supply and Al is going to talk about that a bit later.

We have 16 billion barrels of resources in the oil sands just now. We are already the second largest SAGD producer, we produce over 100,000 barrels a day in the fourth quarter of last year and we have got seven major project phases in execution just now. So I’m going to talk briefly about those major projects.

So we have in Surmont our operated position, we have a very large steel Phase II development going on, is going to add about 120,000 barrels a day of capacity to Surmont, that’s three or four times the size of a typical phase of development in the oil sands. First team from Surmont 2 will come in 2015.

We also have several projects going on in our FCCL joint venture at Foster Creek, Christina Lake and Narrows Lake. And Al is going to talk about technology development in the oil sands in a bit more detail.

But what we see here, these projects and execution and this assumes that we do dilute our possession somewhat in the oil sands, even with that dilution we double our production by 2017 from 100,000 barrels a day to 200,000 barrels a day and it comes at attractive margins about $40 a barrel of margins.

So moving on from the oil sands now across the Atlantic to the U.K. and I’m going to deliver this next slide in the accent of the indigenous peoples of Scotland. So they -- here we have some really good investment opportunities and major projects here. The Jasmine project in particular is a real world-class project.

We’re going to see first production from Jasmine in the fourth quarter of this year and we have a lot of additional projects and we’ll go through details of the additional projects that are going on in the U.K. right there in Britannia, Clair Ridge, East Irish Sea. But these projects at about 55,000 barrels a day by 2015, 2016 and then maintain that production essentially through the remainder of the five-year period.

Now Jasmine is the largest discovery in the North Sea, the U.K. sector of the North Sea for many, many years and there is a lot of remaining exploration potential in fault blocks around Jasmine.

So in the wellhead platform that we re putting now in Jasmine has many spare slots and we intend to do the exploration from this platform so we can immediately tie it back and put on production, so there is a lot of remaining potential in Jasmine in particular. So these 55,000 barrels a day comes at cash margins of around $55 a barrel, so again above our existing average cash margin.

To move across to the other side of the North Sea to Norway. Here we have several major projects underway. And Norway really is one of the assets, the legacy assets that defends our company. We have an outstanding reputation in Norway. In fact we were just recently awarded a Gold Crown award as the best operator in the country and we’re very proud of that, the fantastic group of people, fantastic asset base.

And we have two major projects in execution around the Greater Ekofisk area. Remember I said that the Permian was the Basin that keeps on given, while the Greater Ekofisk area is a field that keeps on giving as well, because we’ve been there for four years and we’re going to be there for four more years and these two projects in Eldfisk South and -- Ekofisk South rather Eldfisk II are going to continue to improve recovery.

Ekofisk South is going to come on production at the end of this year, Eldfisk II at the end of next year, and there are several other major projects underway in Norway also. And these major projects add about 60,000 barrels a day by 2017 with that production big starting to show up at the end of this year. And again that production comes at higher margins than our current base.

Just move on now to Malaysia, now this is an area we have five years ago we started from scratch in Malaysia and we’ve build a very attractive business there over these last five to six years or so.

We got four developments and execution, three deepwater developments at Gumusut, Siakap North-Petai and Malikai, and one shelf development at KBB. Gumusut and SNP are going to deliver first oil at the end of 2013, okay. Then it will grow through 2014. Those projects add about 60,000, 70,000 barrels a day by 2017, most of that showing up by 2015 and a very high margins as you can see in the chart in the bottom right.

We were not done with Malaysia yet. We’ve got four other discoveries either in the early stages of engineering around the appraisal phase, so we are going to see additional growth in Malaysia in the years to come.

So I’m going to move on now and talk about our Australia-Pacific LNG project. As you know this is a large-scale project developing coal seam gas to LNG. The LNG has been contacted the JCC linked prices.

We are focus now on two 4.5 MTPA trains. There we have the plot space as you can see in the top left for two more trains. We have the EIA tell us to develop two more trains. So we have flexibility on this site to grow.

APLNG adds about 80,000 barrels a day of production by 2017 as you can see in the bottom left and adds high margins. And this assumes that we dilute -- this production assumes that we dilute our position in APLNG a bit further.

So the project is about 30% complete both upstream and downstream part of the project. We recently went through a bottoms up review of the cost and schedule associated with APLNG.

That bottoms up review told us from a schedule perspective, we are still on track for our first cargo in the middle of 2015 from the first train and we’ve actually celebrated our schedule expectations for the second train and we now expect that to be operational by the end of 2015.

We have seen some cost increases about 7% increase on an Aussie dollar basis. Most of the money on this project is spend in Aussie dollars. Those increases have come from drilling and gathering costs from some changes in the regulations associated with the water, handling, some increases in third-party projects whether we participate in on the upstream part of this project. And some increasing contingency that for the remaining 7% to 8% spend.

The downstream project, the work on Curtis Island we see no increases there at all. Now depend on how did those, since we sanctioned the project. The Aussie dollar has strengthened quite significantly against the U.S.

So that 7% increase on sort of our spent dollar basis, which really describes the underlying characteristic of project that’s going to look more like 20% to 25% increase on the U.S. dollar basis, dependent on how FX works out over the next few years. So that’s the APLNG project.

Now we have several other projects, I’ve just grouped together here, there are going on mostly around our legacy positions. So includes things like the Alpine West project in Alaska, that’s extending our infrastructure west and opens up more opportunities in the NPR-A and projects in China and Indonesia. And I included this for completeness also because they add 60,000 barrels a day of production and high margin production over these next five years.

So to summarize, well, I’ve just gone through now was the growth and production and margins is coming from our major growth projects 400,000 barrels a day all of outside the Lower 48. So hope that’s giving you some clarity and some confidence and where this growth is coming from and the fact that this growth is real and these projects are in execution.

So what I’m going to do now is change gears and start, and talk about our exploration program. Our exploration strategy is to have a value based balance of conventional and unconventional exploration in our portfolio. And we believe that we have developed a very balanced and valuable exploration portfolio. And this has been done essentially, Larry Archibald has rebuilt our exploration portfolio over the last five years to deliver this what we believe is an outstanding asset base.

Now in 2013, we’re going to spend about 50 -- we are going to spend about $2.3 billion an exploration in total, that’s about 50-50 conventional, unconventional, that’s about two-thirds in the U.S. and one-third internationally.

As a pretty heavy year in the U.S. because we have some significant appraisal work ongoing and unconventional positions in the Lower 48, and we are really ramping up our Gulf of Mexico deepwater exploration program. I’m going to talk about both of those in a moment.

So I’m not going to talk about everything this is in our exploration portfolio for the sake of time, I’m going to focus on a few of the assets, exploration assets in the portfolio. I’m going to start with unconventional assets in the Lower 48.

So I spoke about the Permian conventional position earlier. But our Permian unconventional position is great too. We have a million acres held by production here and we are high grading our portfolio to make sure that we are focusing first on the things that we really need to understand and can see the highest short-term value for, there is a lot of long-term potential here beyond that.

So we are focus particularly in our exploration efforts and the areas outlined here in the Midland Basin and the Delaware Basin. Some of this acreage we added recently to core up our positions there, so we are going to through the exploration period and looking through the held by production. We are seeing encouraging results and we expect to see significant growth from unconventional development in the Permian over the coming years.

We are going to move on now to what we think is potentially a new core area and unconventionals in the Lower 48 for us and that’s in the Niobrara. Over the last year or so we've quietly built up 130,000 acres of a very consolidated position and what we believe is a new sweet spot in the Niobrara.

We have drilled four horizontal wells in 2012. The rock properties look good. The early production results are encouraging. We are getting very high liquids yields. These are liquids yields that are higher than Eagle Ford not quite as high as Bakken but somewhere between those two.

So we feel very good about the liquid yield. In fact we feel so good about this that we are going to drill 32 wells as we move through the appraisal and then towards the development phase in the Niobrara in 2013.

So we move over the Lower 48 now we move north to Canada. We have a really strong unconventional position in Canada as well, really focused around four plays, where we have 600,000 acres in total across these four plays. We have over 100,000 acres in the liquids-rich part of the Duvernay. We have over 100,000 acres in the liquids-rich part of the Montney. We have about 120,000 acres in the Horn River Muskwa.

Now I think everybody knows that the Muskwa is one of the best unconventional reservoirs in North America, it’s a beautiful shale. The issue in Horn River area is that is in the gas window, so it’s a dry gas.

So we’ve actually done here, where does that beautiful shale exist elsewhere in Canada and we’ve identified a play in the Central Mackenzie Valley and the Canol Shale, which is essentially the same shale, this in the liquids-rich, volatile oil, gas condensate window like the Eagle Ford and we have built a 216,000 acre position there.

We are drilling two exploration wells right now, now we are drilling one right now, we’ll drill one after that. And those are vertical wells, just to make sure that we’ve got the right shale, we’ve got the right maturity that we believe and next year we’ll come back and drill horizontal wells and test this. This is a very exciting play.

Okay. Now part of our strategy has been to take our unconventional expertise internationally where we think it make sense, so looking for low entry costs or looking for very, very high quality proven shales. So I’m going to talk very briefly about a few of those just now.

So this slide covers Poland and Australia. We have a really nice acreage position in Poland. We’ve drilled several wells there already. We are focus now in the very Baltic region that’s about 500,000 acres where we have a 70% working interest and we are now the operator. And we think this play really could work.

We’ve got one horizontal well drilling. We are learning things about how to optimize the completion. We’ve got more drilling plan in 2013 to test how the shale thickens as we move through the North and so we are hopeful that this will turn into an attractive unconventional development opportunity.

In the Canning Basin, a very low cost entry into 11 million acre position. We have drilled one vertical well so far. We’ll drill one or two more this year. We recently registered equity and dispositions through part of our [final] deal, a three-part [final] deal that we did with PetroChina.

And we’ve just recently announced two further additions to our international unconventional portfolio. Two deals in the Sichuan Basin in China. We believe that this marine shale is probably the best candidate for unconventional development in China.

So we picked up two really significant positions, one with Sinopec in the Qijiang which is on the eastern side of the Basin and one with PetroChina on the western side of the Basin that does and we look forward to working with Sinopec and PetroChina on these studies over the next few years.

And then we announced yesterday I think a move into Columbia, we are into the La Luna Shale which we see as a real world-class thick, oil proven shale that we think could be a great unconventional reservoir, so that [final] agreement has been completed. So over 100,000 acre position that we have 70% equity, we’ll drill our first well there this year.

So that’s a quick overview of our international and domestic, and unconventional position. What I want to do now is to move and talk about the other side of our exploration strategy, our unconventional position.

I’m going to start Asia-Pacific with two areas there, what we are doing in Australia and some -- and new position will picked up in Indonesia.

So we discovered the Poseidon gas field in 2009, it’s a very large acreage position. We have started an appraisal program there and this appraisal program is focused on determining, what's the right development method for the Poseidon discovery.

So it’s an extensive program that started last year will run through to at the end of this year and into 2014. We recently found out 20% of our equity here to PetroChina as part of the deal I mentioned earlier.

We’ve also recently acquired a 49% interest in a very interesting PSC in Central Kalimantan in Indonesia. This is a play that hasn't been explored since before the Second World War and we are intrigued by this play. We’ve picked up a low cost option. We are going to drill three wells in through the end of 2014 and we see potential for a lot of upside in this play and we are very excited about that.

So I’m going to move west now to Angola. You can see in the bottom of this chart that this Angola play that we are chasing is essentially the same play this meant so many large discoveries on the Brazil side of the Atlantic.

We believe when we picked up this acreage. Our hypothesis was that play will exist on the eastern side of the Atlantic as well. So we picked up these Blocks 36 and 37. Since we pick them up the Cameia discovery has been announced, which immediately offsets our blocks a little bit on board. So the play has been de-risked on this side of the margin.

We have 2.5 million acres of an operated position here. We have just acquired 3-D seismic. The 3-D seismic is very encouraging. So the combination of the play being de-risked and the 3-D seismic that we’ve seen gives us real encouragement of the potential of this deepwater position in Angola. We’ve just contracted a new deepwater rig field right at the beginning of 2014 and will drill a four well program back-to-back to explore best position.

I’m going to finish the discussion on exploration with our Gulf of Mexico exploration position. In about 2008, around the time when Larry arrived, we stepped back and had a complete review of what we are chasing in the Gulf of Mexico. And over that time, we’ve completely rebuilt our acreage position here.

We have focused the position. We are focusing on new plays because we believe that the Gulf of Mexico has a huge amount of yet to find resources. And we believe if you end the light with a right play, it’s going to have a very competitive cost of supply. So we focused our acreage acquisition on getting the right plays.

And you can see we’ve doubled our possession just over the last couple of years. We are now one of the top five leaseholder's in the Gulf of Mexico. And a lot of our leases are held with long tenure on them and that may not mean a lot to you guys but it means a lot to us because it gives you a lot of flexibility and how you get through and explore this large acreage possession over time.

So 2013, we’re really ramping up the testing of this acreage possession. We’re going to drill somewhere between five and eight wells this year. The five that we know we’re going to drill are showing -- are shown on the chart. I’ll talk about them in a minute. There are three more that we expect to drill but we are still working on some of the details of those.

So before the Macondo event, we had actually already made two significant discoveries in the Gulf of Mexico in the Paleogene at Tiber and at Shenandoah. We've just finished drilling a well at Shenandoah and appraisal well at Shenandoah. I’m going to describe what we learned there in the next slide.

We will drill an appraisal well on Tiber this year also. So we’re going back to appraise our existing discoveries. We’re also drilling three wildcats. The Coronado well was actually spudded in 2012. We got to 3-D about a month ago. I’m going to talk about -- a little bit about what we’ve learned in Coronado.

The Ardennes well, we’ve just spudded in the beginning of this month. So we’re looking forward to seeing the results of Ardennes. And the Thorn well which is a Pliocene/Miocene target is our first reentry as a deepwater operator into the Gulf of Mexico. We’ll drill that in the third quarter of this year.

So let met talk about what we’ve learned from the Shenandoah and Coronado. Now, I can’t give you a lot of details here. But what I want to do is just put these two discoveries in the context of our local possession here.

Now, we felt that this possession was going to be a really good [zip code] for the Paleogene. And we picked up quite a significant acreage position. Shenandoah appraisal well was a follow-up to 2009 discovery where we discovered more than 300 feet of net pay. The appraisal well was drilled a mile away from that. And we’ve got very encouraging results from that appraisal well.

The Coronado wildcat was nearby. Again that's a 3-D and we’ve had very encouraging results from Coronado too. And we expect to be back on location at Coronado before the end of the year. And look at the follow-up potential we have in this zip code.

The Ardennes well that I spoke about, that’s in the same area and that’s spudded and drilling already. And that position that we have to the Northwest, 100% ConocoPhillips acreage, new 3-D seismic, a low prospect activity. So we’re really encouraged about how our deepwater Gulf of Mexico portfolio is playing out and expect to see a lot more to come from this as time goes on.

Okay. So that's me, essentially gone through most of the exploration portfolio. There are other exciting things but in the interest of time, I haven’t discussed all of it. But our strategy of value-based balance of conventional and unconventional exploration, we think is one that takes advantage of our competitive knowledge and allows us to be focused on our diverse set of opportunities for long-term growth beyond 2017.

So I’m just going to wrap up now. And this graph on the left-hand side is the one I showed you earlier. I’m going to change this now and show you that instead of and categorized by the type of project, categorized by the production that’s coming from those projects and what you can see here is that our North American gas position remains relatively flat production over these five years.

We’re not investing gas in North America but we do have associated gas coming with our oil and liquids-rich plays. International gas grows a tiny bit. NGLs are pretty flat. LNG is growing. Oil Sands is growing but most of the growth is coming from oil. A lot of that in North America but not only in North America and they are across the globe.

And Jeff is going to refer back to these sources of growth when he talks in his part of the discussion about the margin growth. But it is very clear the best incremental production is coming at higher margins than our base production just now.

So what I have shown you is we have a divest resource rich portfolio, a high-quality legacy base, a significant development program across the whole world associated with our legacy base and building new legacy positions, major projects in execution are going to start adding production this year and grow production continuously over the next five years and a really strong exploration portfolio.

And we believe that this portfolio is very well positioned to deliver this high-margin growth. And it’s already also very well positioned to result in reserves replacement. If you go through the math on the development program slides, I showed you, you’d be able to do some subtraction and division and what gave that those development programs loan to replace 60% of our production with reserves, just a development programs.

You then think about the fact that more phases of our oil sands will be sanctioned over these five years. If you think about the fact, we’ve got several many projects actually in every stages of engineering and appraisal that will be sanctioned over these five years.

And we have our exploration program, resulting in discoveries that will be sanctioned over these five years. We are very confident in our ability to replace significantly more than 100% of our production with new reserves as we go through these five years.

Okay. I started the presentation by saying that my goal was to give you clarity and confidence in our ability to grow our production and our margins over the next five years. And I hope I have been able to do that.

But what I can’t tell you is that everybody in the company holds $16,900 that Ryan mentioned. It is very clear to us what we need to do, very, very clear. We have a lot of confidence in our ability to execute it and we are completely committed to getting it done. So that concludes my presentation.

As I went through the presentation, I spoke several times about the technologies that we are using and to protect our base for our development programs, for our major projects and for exploration. Al Hirshberg is going to come up now and talk about some more details of that technology program and why it is so important to us. So thank you. Al?

Al Hirshberg

Thanks Matt. So Matt has just taken you through our investment inventory and showed you how we are going to use that investment inventory to grow our production volumes on our margins over the next five years. What I would like to do next is explain to you, how are we going to use our technical capability, combined with that investment inventory to drive increased competitive advantage and shareholder value through our technology capability.

I'm going to take you through same as Matt did, the different phases of production as I show you these technology examples, the base, our development programs, our major projects and then exploration. I'm also going to refer back to the recently 43 billion barrels of resource base that Ryan mentioned earlier that shown in the pie chart at the bottom right. One thing to keep in mind is that we've only moved the crude reserves 20% of that 43 billion barrels that shown in the pie.

So we’ve got 35 billion barrels more in that resource base. They are going to be using technology to drive it over into crude reserves on economic basis. So now lets movement into the some of my technology examples. I think you’re really going to like the first one I've got for you because it's an example of one of the best reservoir optimization stories in the history of our industry.

I'm talking about the Ekofisk field. You see the chart on the bottom right shows you that when we first developed this field in the 1970s, we thought we would only be able to get about 15% of the original oil in place in the reservoir out. Now, after decades of an integrated technology movement and developing new techniques over the time, we now believe we’ll recover well over 50% of that original oil in place.

So as you think about low recovery rates that we have in our unconventional reservoirs today, I think it’s useful to keep this kind of perspective in mind that what technology can do for us over long periods of time. I show a list there in the bottom left with some of the technologies that we've used over time to get this kind of result. And I’ll just mention one of them in particular is 4-D seismic that Matt referenced earlier.

The 4-D seismic that we’re using at Ekofisk is not your everyday 4-D seismic. What we have at Ekofisk is what we call life of field seismic. So we have a permanent installation on the seafloor with on bottom cabling and geophones that allow us to essentially sort of push the button as often as we want to get a new update of how the oil and gas water are moving in the reservoir and do that at low cost.

So through these kind of technologies over this period of time with this increase in recovery, we've added over 2.4 billion barrels of incremental recovery of what we thought when we first developed the field. That's a huge win for ConocoPhillips and for that matter for the country of Norway.

So as we look around our base resources around the company, few of the legacy assets that Matt was talking about earlier. And we think about how we can apply the same technologies, we see today over 2 billion barrels of additional resource that we think we can move over to reserves using these same kind of technologies and do it with good economics.

Next, I want to talk about two advanced drilling technologies that we’ve developed in the company that are really helping us around the world, both of them we’ve honed these techniques in Alaska. Alaska is a place where we’re working very hard to develop and produce every last barrel that we can get at economically.

So the first technology that we've been working on honing in Alaska is coiled tubing drilling. This is a technique that we used to try to get hard-to-reach pockets of oil that have been bypassed and aren’t being produced by our existing development wells and do it without spending a lot of money.

So in the example that I show here is our Kuparuk Field in Alaska. So what we’re doing is we’re using 4-D seismic to illuminate pockets of oil that are in separate fault blocks for whatever reason they are not producing into an existing wellbore. So these pockets are narrow wellbore but they are not producing. We can see that from the 4-D seismic.

We could develop -- we could access these pockets using conventional drilling but it’s just not economic. We needed a lower cost way to get at this oil. This is what got us working on coil tubing drilling.

So with this technique, we’re using very small tools. On the end of coiled tubing, it allows us to twist and turn through the rock. We can turn with these tools over 60 degrees in just 100 feet of movement with the drill bit. As that allows us to go right to these pockets that we found with the 4-D, in this case we show what we call an octa-lateral.

So we've actually found eight different zones near this wellbore that we could go and hook up using coiled tubing drilling. And so we've done that. All eight of these zones that we’re not producing, tied back to this one wellbore. So that’s a very cost-effective way to get at those zones that weren’t producing before. And so it makes economic sense for us even in a high-class place like Alaska.

Second drilling example, I’d like to show you in Alaska is drilling -- casing drilling, where we’re drilling with the casing in place and also the ability to steer steerable drilling liners. And so what drives us to this technology is it enables us to be able to drill through unstable reservoirs, unstable wellbore, pressure depleted formations.

So normally, when you have these wellbore instabilities, if you try to drill and then come back and run casing, you can’t do it fast enough because the wellbore collapses. So here, we’re actually using the casing to drill. And so the casing is already in place as we drill a hole. That gives us a mechanical method to be able to still access those resources.

So this technology contrasted with the last one, the coiled tubing drilling that I showed you, with coiled tubing drilling, we’re accessing resources that we could get to conventionally but we’re doing it at a much lower cost. Here, we’re accessing resources that physically we just couldn't get to using conventional techniques from our existing well pads.

So it's opening up significant additional resources for us. And as we have perfected this technique in Alaska, now we look around the world in our diverse portfolio where else we can use this is technology, we see hundreds of millions of barrels of additional resource that we’re going to be able to access that we couldn't get to before using these techniques.

So that’s two or three examples in our conventional reservoirs around the world. But I’d like to move onto next is the unconventional space. I think you could see very clearly from what Matt showed you that unconventional reservoir development is shaping up to be a very big deal in ConocoPhillips. It’s a big part of our growth plans going forward.

So I want to take a little bit of time to take you through some of the technology that we’ve developed that’s going to allow us to do this in an industry-leading way. So I think we've been able to develop and the Eagle Ford is a great example for us to use in industry-leading position and what everybody can see is an industry-leading shale position.

And of course, some people say that these unconventional reservoirs are really the province of the smaller independents that the little guys can out compete the bigger companies. I’ve even heard -- I heard last night that some people think that this unconventional development is just a commodity thing. Anybody can do it. It's all the same. You just look over the lease line, see what the other guy is doing.

I’m going to show you some data on these next few charts. I think we’ll demonstrate that, but that's not true in our case. On the left is 14 key technical capabilities that we think you need to have to really be a top-tier unconventional reservoir developer. And in subsequent slides, I’m going to delve into each of those four areas in more detail. But first, I want to focus in on the value that we are creating using these technologies, using the Eagle Ford as an example.

The plot shows you some data from the Wood Mac study, where each dot represents one of the competitors in the Eagle Ford and they have calculated on NPV10 basis. What the value that is being created per acre for each company's acreage position in the Eagle Ford? And you can see that ConocoPhillips has a leading spot there with our red dot up near the top.

The interesting thing though about this work that Wood Mac did, is it’s all done on a money-forward basis. It ignores what your entry cost was in the way that they’ve calculated this. So when you look at the value that they show for us per acre at $35,000 of NPV10 per acre and then you consider that we got -- we acquired this acreage for $300 an acre. That's really impressive shareholder value creation. It's a little less impressive.

Some of the other dots that maybe kind of high up on the chart, but the company has paid dollars per acre similar to that NPV10 value to get into the play. That’s a big distinction I would make between the two. So how was ConocoPhillips able to develop this enviable position that we have in the Eagle Ford?

I want to spend sometime in the next few charts, showing you some of the technical methods that we’ve used. And the first thing that comes to mind is sweet spot identification. I think it's clear to everybody that not all of these shale plays were created equal. And within a given shale play, not all the acreage was created equally and so if you're going to be good, the very first step is you got to be able to find the sweet spots in a new area. When you do that you get the kind of results that you see on the bottom two plots.

On the bottom left, ConocoPhillips, our average well produces a lot more than our competitors average wells and we can ramp production very quickly even without running to huge of a number of rigs. We’ve been able to ramp from essentially zero in 2010 to 100,000 barrels a day by the end of last year. So how do we do this?

We use a multi-disciplinary approach. We have a dozen different technical disciplines that we have tightly integrated together, working to develop our proprietary methods for how we find these sweet spots. And I think it's pretty clear as you look around the industry, there is these very few companies that have been able on a repeatable basis to be able to identify these liquids-rich sweet spots in a new play and to get in early at a low cost of entry and a massive significant acreage position in the sweet spot of the field.

And I think Matt just showed you a couple of those that we’ve got coming, the three that everybody knows about already that we've had a low cost of entry and already successful are the Eagle Ford, the Bakken and the Permian. But, Matt was showing you the Niobrara and Canol examples of additional places where we’ve used our technical capability to get in early at a low-cost and find, what we think are the new sweet spots.

And as he mentioned and say the Niobrara, for example, we've already got drilling results that tell us that we have identified a new sweet spot there and that is going to -- it will soon be on our list of additional places that you will hear about when we’ve been able to accomplish that.

So some of the technical -- the techniques that we use to generate some of these results is what I want to show you on this next page. To really be good at full field development, optimizing the full field in an unconventional space as you move from the early phases into full development, we think requires a combination of disciplined science, which informs analytical models combined with the ability to go to the field and rapidly experiment to feed that and take good data to feed back into your models.

So what we observe oftentimes in our larger competitors in the unconventional, is they seem to spend too much time perfecting the science in their models, don't move quickly enough to the field. On the other hand, what we see sometimes in our smaller competitors is that they don't have the capability to even do the science and really they are in trial and error mode. They are out in the field just trying things. And when you're working that way, it doesn't leave you with a predictive capability that you can use to go to that next play and find the right spots and be able to move quickly to optimize your development.

So, I think some of the prove points of our ability to do this are shown there on the chart. In the Eagle Ford since 2010, on the same acreage using these technologies, we’ve more than doubled what our estimated ultimate recovery is, but more than a 50% growth in the Bakken. A little example here on the bottom right shows you the kind of things we do to achieve that result.

The light blue part of the plot shows you a series of wells in the Eagle Ford, what our average production was using a certain completion technique that we were using last year. Then, we had a new idea of a single change to the way we were doing the frac jobs. We tested our models, we’ve moved quickly to the field to try it out and saw it was good and switch to that, implemented that change.

And then, if you look at the next batch of wells that we drilled and completed using this new completion technique that's what shown in the dark blue wedge there. So it's interesting that just one good new idea implemented quickly can give you a very significant uplift in your production, in your recovery in a given area.

So the bottom left is one last thing I want to mention on this chart. When we go to the field, we are not -- as I said earlier just in trial and error mode, we are taking a lot of high-quality data. What’s in the picture there is a fiber-optic-based system that we’ve developed that straps to the outside of the production casing. And it allows us to measure real-time pressure and temperature. So, while we are cementing that casing in plays, while we are pumping the frac job during the flow back and during production subsequently, we can see the temperatures and pressure.

What this has done for us is allowed us to really perfect the way that we do these frac jobs. The way we execute them and we can see contrary to what you read about sometimes. We could see that in our completions, every one of our fracs and these multi-stage frac is producing into the wellbore. We are getting production from each of our fracs. We could see that in real-time using these techniques.

A couple more capabilities you need to have to be the one of the top operators in the unconventional is you need to be very efficient driller and you need to be good, obviously at production operations. So, a little bit of data on those two things on this chart. In the top, you see the bar chart that's again third-party data just like all data I've been showing on these pages. That shows how many rig days has each of the competitors in the Eagle Ford needed to drill 10,000 feet a hole in the Eagle Ford. And you can see in the red bar for Conoco Phillips that we are amongst the most efficient of the drillers in the Eagle Ford.

And I should point out that this is data from the period before we’ve reached that held by production status. We expect to get to HBP status by the summer and then at that point we’ll move to pad drilling. And that’s going to improve our drilling efficiency significantly even further. So this is even before that point in time.

Another point, I'd like to make is that that's an advantage for a company of our size and scale -- size and scope is that we were able to have a lot of expertise in the supply chain side of things. And so in early last year, when we saw gas prices dropping in the U.S. and there was some softening in the contractor market, our supply chain experts were able to move very quickly and renegotiate our stimulation contracts. And we saved over $200 million last year from those renegotiated stim contracts.

I also want to mention a little bit about production operations. We have put in place in the Eagle Ford, what we call IOF, integrated oilfield of the future. And so what we've done here is we've installed our own private Wi-Fi towers across all of our acreage in the Eagle Ford. This allows our personnel in the field to use iPads and other mobility devices to be able to access real-time operating data across the entire field and to be able to collaborate with each other and their engineering colleagues back in the office.

In this particular picture, you see a couple of our guys at a construction site and they are able to use their iPad to access construction drawings back in the office. So a lot of capability that that gives us, and we think the combination of all these things allows us to get the most out of our unconventional resource developments without overcapitalizing. So that’s a fair amount of detail around some of the techniques that we are using and the technologies we’ve developed for unconventional.

What I would like to do next is move to another important area for the company and that is the oil sands. You saw on my very first slide, when I showed you the resource pie that the oil sands is a very large part of our resource and the company. And so it's an area that we've been working on a long list of ideas to improve the economics of our major developments in oil sands for a number of years, and these ideas start out -- start out, come from our people that we test them with our models and in the laboratory.

We move to the field to verify that they are going to work once our models tell us we have a good idea. You see a list there of some of the ideas that that we are now implementing. But overall the target here for us is, we move forward into our new major project developments in the oil sands, is to reduce our cost of supply by $20 a barrel, that’s what we are after.

And you can see from the little bar chart in the bottom right that we are well on our way to doing that. The first green bar shows you the ideas contributing to that $20 reduction that we are already implementing in the field, they’ve been fully tested. The next green bar shows you -- it represents the ideas that we are -- that good but we are still doing some development and testing on together. We think we will able to get a $20 per barrel reduction on our cost of supply.

When you look at the ideas that we are chasing to do this, fundamentally, they're all aimed at reducing our steam oil ratio, our already first quartile steam oil ratio that Matt showed you earlier. So when you do that, what it brings improved economics. It reduces your cost of supply but it also reduces your water usage, and it reduces your air emissions. And so it’s a win-win all around as we develop these technologies in the oil sands. And with our 16 billion barrels in our resource base of oil sands, we have a big multiplier for any improvements that we come up with in oil sands technology.

The final example that I’d like to show you is some work that we are doing in technology to improve our exploration performance and I want to focus in here on the deepwater. Frankly, in deepwater technology, it's an area where we have had some catching up to do and that's exactly what we've been doing over the last handful of years in deepwater technology.

We have very significantly expanded our proprietary in-house seismic imaging capabilities, and we’ve tightly integrated that with our expert Basin modeling skills. You can see that in the little picture there on the right, shows you those two technologies being integrated. Those two technologies combined with our ability, as an independent to move quickly have given us a competitive advantage as we move into the deepwater.

And so I think you've seen a very advantageous prospect portfolio that Matt showed you earlier that we’ve been able to develop in both the deepwater Gulf of Mexico and deepwater Angola using these technologies. And as Matt also mentioned, our early results from our exploration wells are proving up the competitiveness of our prospect portfolio.

In addition, we got two operated new build drilling rigs coming next year. This is going to open our aperture further and allow us to increase our potential here in the deepwater. So, if I can wrap up now to summarize, I think we’ve really build an impressive team that’s working on our technology in Conoco Phillips. We’ve got the people that have allowed us to create competitive advantage and differential value creation for our shareholders using technology.

We are not trying to be the leader in all across the waterfront technology. We are targeted to the areas that directly benefit the things that are in our resource base and allow us to grow our production and our margins cost effectively, developing a capability that allowed us to compete around the world for new acreage. And so, I think what we've showed you so far this morning, Matt has taken you on a tour around the world of all, of our investment inventory and how we are moving it to grow our production, our margins, improve our returns.

I’ve showed you some of the technical methods that we are going to use to improve those results even further. And now, I would like to call out, Jeff Sheets, our Chief Financial Officer. He's going to pile this together here and show you the impressive financial results that come from all this work.

Jeff Sheets

Thanks, Al and good morning, everyone. So we had -- Ryan started the morning with a bit of a discussion about strategies. So the strategy in short form is we are investing for profitable growth and repairing that profitable growth with a compelling dividend. And we think that’s the recipe for creating strong and predictable returns for our shareholders.

So we had, Matt, walk you through a lot of granularity about where that growth is coming from and the margins that come with that growth. And what Al just talk about and the point we want to make sure that is understood is, this is a technology-driven business. And be in a company of the size and scale and with the technical capabilities that kind of fulfill us. That’s created shareholder value in the past and it’s going to create shareholder value for us going forward.

So, what I want to do is wrap it up and talk about numbers and particularly cash flow numbers. And if there's kind of one fact that I want to take away from this morning's presentation is that the investments that we are making are going to create an incremental $6 billion to $7 billion of cash flow. So when you put that number in perspective, if you look at our assets that have been in our portfolio, that are going to be part of our continuing operations going forward.

In 2012, those assets generated a little less than $15 billion in the cash flow. So if you had the same kind of price environment we had in 2012, you would have about $7 billion of cash flow by 2017. So it would be $15 billion going to $21 billion, $22 billion of cash flow. If we have a price environment like Ryan talked about earlier where you were a more $90 in real-WTI, then you maybe closer to $6 billion of cash flow.

But again the key message is we’ve got to step change in cash flow coming. So, what I will talk to you first about is what’s the financial strategy for making that happen? It’s pretty straight forward strategy. I mean, what are we doing? We are taking the cash flow from operations and we are taking proceeds from the sale of non-strategic assets and we are reinvesting that in a set of programs and projects, which going to take our production from 1.5 million BOE today to 1.8 million in 2016 and 1.9 million in 2017.

In that cash flows coming out, the production is coming at good margins, so as our cash flow is growing to the point where we can fund the capital program and fund the dividend that's higher than today’s dividend and fund the capital program that continues to create growth for the company.

Now, we’ve talked a lot about growth this morning. But it’s not going to be growth for the sake of growth. We are always going to continue to be focused on returns as well. And so metrics like ROCE are going to continue to matter for us, and I will talk a little bit about our thoughts around that in the subsequent slide.

We also recognized that we operate in an environment where there is lot of volatility in commodity prices. So having a strong balance sheet is key for us going forward and it’s just going to be one of our priorities.

But the top priority for us as Ryan mentioned earlier is the dividend. And we are a company that believes that we’re in an industry. And we’re of the size company that the significant part of what shareholders are looking for from us is dividend that's they can count on as the stable part of their shareholder return and then can count on that growing over time.

So in the near term though executing this financial strategy is helped by the execution of our asset sales program. That’s what I want to talk about next. So at the end of last year, we announced about $9.5 billion worth of asset sales. And you see the list of assets appear, the exit from Kashagan project in Kazakhstan selling our assets in Algeria, Nigeria and Cedar Creek Anticline assets in the Lower 48.

And what all these assets have in common is they are non-strategic assets for us. They don’t help us meet our long-term strategic objectives. And we’re doing all these asset sales in a manner that's very tax efficient.

And we’ve sold these assets to buyers who view this as strategic assets. And that's reflected in the value that we’ve received for the assets. So we’ve received full value for assets. And if you look at these assets as a whole, in 2012 they generated a little over 60,000 barrels a day of production and they represent little bit more than 350 million BOE of reserves.

So what we’re doing is we’re taking the proceeds from the sale of these non-strategic assets. And we’re reinvesting them into things that are core to our portfolio going forward. And it’s those strategic assets that we’re investing in that are going to create the cash flow growth we’ve been talking about.

So we talked about those assets. Since this is the same slide that Ryan had up earlier and really this is the same slide that we’ve been using basically for the last year. It shows that a lot of our growth is driven by these five key growth areas that are coming at higher margins.

As Matt went through with you this morning, there is a lot more to portfolio than just that. There is lots of other investments that are happening in the base part of our portfolio, which have a significant impact on mitigating our base decline. So what I wanted to do with you next is to put all this together and say what’s changing about the portfolio.

So I’m going to spend quite a bit of time on this slide. And I was going to say you go ahead, you are comfortable in your chairs but I’m going to sit in that chair. And I just know that’s not really possible. So as we were preparing this presentation, we kind of voted this slide as the most likely to show up at an analyst presentation -- analyst write-ups after the meetings, we’ll have to see if we were right about that.

So this is what -- because it’s a slide really at the core of what we’re trying to do as a company to create incremental cash flow growth. So in 2012, we produced about 1.5 million Boe a day from the assets we’re going to continue on in our portfolio. So if you fast forward to 2017, and you ask yourselves what's different about our portfolio, compared to 2012, that's what we want to get across here.

So production were grown to around 1.9 a day about 400,000 barrels a day of the increase. But of what’s important is a couple of things about that 400,000 barrels a day. The first is what kind of products make up that growth. And the second is where is that coming from. Because it’s coming from areas where tax rates are generally lower than the average of our portfolio today.

So if you -- and just to make sure that we’re clear about what I’m doing here is I’m comparing 2017 to 2012 so that’s -- includes the impact of the declines in our base production, includes the production from our development programs and it includes the production from our major projects. So this is an all-in comparison of what's going to be different.

So of the growth that we were talking about, about half of it is going to come from the oil production. And of that oil production about 70% of that oil production comes from the Lower 48 and the rest of it’s coming from Malaysia and projects in Europe. So if you step back and -- and then so -- and so what it’s not coming from is places which have relatively higher taxes rates like Alaska.

I’m thinking about that kind of make sense because we’re drawn to make investments in areas where there's lower tax. So, you step back and look at this in our oil production overall. It is coming from areas with lower average tax rate than our current portfolio.

So next step, we've got about quarter, this grows about 100,000 barrels a day. It’s going to come from the Canadian oil sands. Again this is an oil linked product obviously in an area with a relatively favorable tax. And this is a layer production that is long-lived low decline, high-margin. I was thinking about the oil production growth, so about 15% of it is going to come from LNG again. And other long-life, low decline, high-margin piece of the business, it is coming from the APLNG project.

And then of this growth, only about 5% of the growth comes from NGLs. In those NGLs, our production increases mostly from North America and about 5% of it come from international gas production. So what is important what’s on this chart as probably what’s not on this chart and that’s natural gas production for North America.

So as Matt talked to you earlier, we see that our North American natural gas production is basically going to be flat as production from associated gas with the shale developments basically offsets decline from our base production.

So you look at this all in and you’re adding 400,000 barrels a day of net growth. If you look at the average cash margin on this net growth, its $40 to $45 a barrel. And you can see if you mix in that with the portfolio today which is averaging around $25 maybe $27 a barrel cash margins but this is what’s going to be driving both production higher and margins higher.

And I think, kind of, one last point for this side is that this isn’t all happening in 2017. It really starts to happen at the end of this year as major growth projects start to come online. So you’ll see meaningful increments up on production and cash flow in 2014 and more in 2015 and on up to the $6 billion to $7 billion a year that I talked about by 2017.

Again so but it's not just the growth for the sake of growth, we’re going to be disciplined about how we’re investing. We’ll continue to look at metrics like return on capital employed. This is an important metric for us.

We put up this chart here where we compare our return on capital employed to those of the largest independent E&Ps. And normally when we show comparative charts like this we’ll show us against where we consider our peer group, which actually includes the integrated majors as well. About one of the show in E&P only comparison and that’s really hard to parse out that out of the integrated results and their results get pretty heavily affected by what's going on our refining and chemicals.

So you see we do relatively well on this metric but we’re really not happy with where we are. So we want to see our returns on capital employed to improve both on a relative basis and an absolute basis over time. So, how do we do that? One, we always going to be focused on ongoing costs and ongoing operating efficiency as the way to improve our returns on capital employed.

Probably, I’ll stop here. Just to mention that in the back of your books, we've got some specific guidance on 2013 on cost level. So we give some guidance on for 2013 on controllable cost levels, DD&A. What do we think the corporate segment net income is going to be as well as a little bit more guidance on how we would see production moving on a quarterly basis during 2013.

So back, talking about our returns, so what’s going to change our returns on capital employed. Our assets sales did make a difference, particularly when you think about things like the Kashagan project where we got $5 billion of capital implied on our books today, it’s not generate income. So you take that off and that helps ROCE metrics.

While but at the same time we are investing pretty heavily in projects like APLNG oil sands which are put implied on our books now, but not creating a lot income. So near-term probably a relatively flat portfolio for ROCE, but then ROCEs grows as these major growth projects come online in a few years time.

Now we’ve talked a lot about growth and returns, but one of the keys in our business is maintaining a strong balance sheet, I wanted to say a couple words about that. So we ended up last year with about little over $4 billion -- $4.4 billion of total cash on our balance sheet. We got asset sales we are executing this year that we are bringing about $9.6 billion so you can see our cash balance probably grow as we go through the year.

We ended the year with $22 billion of debt, short-term maybe that debt comes down some as we generate all this cash. We don't feel like longer term that we need to bring our debt balance down from the $22 billion level that we are at today.

We’ve got A/A1 credit rating that reflects a substantial amount of financial flexibility. And if you think about the growing cash flow profile for the company that implies more financial flexibility, more debt capacity for the company going forward.

So if you think about funding the growth program that we have is not unreasonable to think that we are going to fund part with our cash balance and that we could fund part of it with debt as well.

So if you look, this is going to how we compare on the debt-to-cap compared to our peer group. We’ve got about 30% debt-to-cap, A1/A credit rating. We think about where do we want to be longer term? We think we are about in the right spot from a capital structure perspective. We don't see any need to significantly delever. We don’t see any really advantage to trying to go to what, we would see is a more kind of excessively conservative capital structure. So what that means is that in terms of something like debt-to-cap ratio is probably can be in a 25% to 30% debt-to-cap ratio going forward.

So I want to wrap up my financial discussion with some thoughts on the dividend because as Ryan said earlier that is our highest priority use of cash flow. So if you look at where we are among our peer group now, we are paying a dividend that’s -- it’s around 4.5% that’s right up there with what the European majors are plan paying right now. It's a fair bit higher than what the U.S. integrated majors are paying. It's really quite differential to what’s being paid by the independent E&P's.

Again, this is kind of this is key point that we always synthesizing, this is a core part of our strategy. We believe in the, that we should be getting a significant portion of our cash flow back to our shareholders in the form of a dividend, I think that enhances the capital discipline and its part of the mix of creating strong returns for our shareholders.

So as we think about dividends going forward, if you look back, we’ve increased the dividend really rapidly at ConocoPhillips over the last, or really since the merger of ConocoPhillips back in 2002. We are creating a lot of incremental cash flow going forward and that’s going to give us scope to continue to increase the dividend going forward.

So just to wrap up the financial discussion, just, so what, in a nutshell what are we doing here? We’re taking cash from operations, proceeds from asset sales, investing it in a series of programs and projects which were taken our production levels from 1.5 today to 1.8 in 2016, 1.9 in 2017.

So, think about that, that’s a 25% increase on our production, but because of this productions coming from higher margins. It's more like a 40% to 45% increase in the cash from operations that we are going to be generating. That brings us to the point where we’re going to be able to continue to grow as a company and pay a dividend that’s higher than what we are doing today.

So that includes what I wanted to say on the financial side, Ryan has got a few things he want to say to you wrap the meeting up and then we are going to turn it over to some questions. So I’ll turn it back to Ryan?

Ryan Lance

Thank you, Jeff. So let me recap a little bit about what you've heard today and then open it up for some questions. So hopefully you’ve seen, we’ve open the hood on this growth engine. We’ve got a peak under the hood see what it’s all about. Its high returns, its high growth, its high margin.

Matt showed you where it’s coming from our base legacy assets, our development, our projects. Al showed how we are using technology and innovation to improve the underlying value of all those assets we have in the portfolio, the compelling and momentum building exploration program that we are building.

And Jeff finished it up, the growth is real, it's in execution, we are directing those investments to higher margin opportunities to grow our cash flows and it fund our capital and our dividend plans over this timeframe that you’ve heard about today.

So I’m going to end where we started it all. This is what we’re about. It is run the business well. We know how to do that. We are focused on the execution, running our base business well. Dividend remains the highest priority. We are financially strong. We know what we are doing. We know how to fund our programs. We have it in play. We are going to grow this thing 3% to 5% over the next five year. We are going to grow the margins 3% to 5%, and we have a laser like focus on improving our returns, and that’s the new class of investment that ConocoPhillips offers to our investors.

So let me ended it there, and I’d be happy to take questions, team is here, look forward to hearing questions and comments that you might have about the plan. Doug, over here?

Question-and-Answer Session

Doug Terreson - ISI Group

Ryan ConocoPhillips is record of execution has been pretty positive overtime but when you consider that your portfolio today have investments is probably as strong as been a decade or certainly for time, you’ve got lot to work with? My question is, how does this -- how does the company manage for execution risk, meaning how do you prevent delays and cost overruns such that you're able to attain this 50% rise in cash flow that you talked about today?

Ryan Lance

Yeah. Doug, I think, Matt and Al talked little bit about, it is a big belief you got to be very integrated and functional excellence is important in this business, so it is about operating excellence. We have a four-legged stool our approach -- operations excellence plan. It's about asset and operating integrity. It’s about production and surveillance and optimization. It’s about planning and reliability. So it is about doing the -- running the base business pretty well. It’s our legacy. It’s what we’ve done really well.

I talked about things we are trying to change in this company, the culture we are trying to change and I talk to our people, I tell them, here is what we’re not going to change. It is about how we execute. It is of our passion for safety in the environment, that's absolutely what we are not going to change. And we’ve been building a lot of functional excellence on the major project side too.

We are going to have our instances where things get, we struggle little bit. We've come a long ways in terms of capability and capacity on the major projects side. We actually have a history of doing that, well, we’ll continue to do that well.

But we understand, we got a protect the base. We -- our license to grow our license operate is fundamental to that part of the business. Next to you, Doug Leggate, please. Could you please state your name and your firm you represent please.

Doug Leggate - Bank of America

I hopefully you know that. Doug Leggate from Bank of America. Thanks Ryan. I'm going to try two, but they're inter-related so hopefully I'm not being greedy with time. Obviously, there's been a lot of focus on the dividend and there are a lot of comparative charts and cash flow growth and projections and so on. But there's a couple of things that underpin that, one is that WTI is not $10 below Brent and secondly, the companies you're comparing yourself with are paying their dividend out of cash flow whereas you're not?

So my question is, why, when you're spending $2.5 billion in exploration, which is two-thirds of your dividend and you're projecting this growth in cash flow, which is getting a lot of subjective assumptions. Why is dividend still the core priority? And if -- the related question is, the exploration program is still somewhat embryonic, why the rush, why not get to that cash flow coverage position before you start spending so aggressively in exploration? Thanks

Ryan Lance

Well, I think, it’s a bit of what I call the paradox symmetrics in this business. So it’s not just about delivering the next five years, but this is a seven, eight -- six, seven, eight year cycle time business. So you better be working on things today. In fact most of my time, my leadership time is spend on what can we capture in the portfolio today that’s going to be growth beyond 2017 for us this stop an execution.

So it is important to balance your spend. It's important to spend money on exploration. It’s important to think about what the next decade has in store for this company based on the cycle times we experience in the business.

And as Jeff said, it’s a mature business. This is a business where capital discipline is important. You better be careful, I spend last billion because it does matter where the returns come from and the dividend puts capital discipline into the company. So we think it's an important part of our offering. It underpins the share price -- it underpins our performance and the returns that we offer here and we are pretty committed to that dividend.

So I think when we look at the program. We look at the investments that we’ve got over the next five years. We look where cash flows are going. We can afford the dividend that we are paying. The cash flows are coming. We are going to be able to afford the dividend and capital program long-term and we can still invest in exploration to make sure that we’re growing and adding opportunities into our portfolio that will represent production, reserves, growth and margin beyond 2017 and that’s important. So, Paul, you all get a chance, don’t worry.

Paul Sankey - Deutsche Bank

Hi. Thank you. Paul Sankey at Deutsche Bank. Ryan, you highlighted quite liberally that you saw the potential for more disposals further down the road beyond the existing program and you mentioned to growth assets actually. I was wondering, why you wouldn’t want to rational the Basin and decline challenge that you described here and sold down perhaps certain more mature areas as an alternative plan? Thanks.

Ryan Lance

Well, we continue to look at the portfolio. So what I say the coring up of the portfolio is largely done with the assets that we did. We are always looking at the portfolio and some of the more mature declining less strategic assets. You seen us, we’ve done a bit of that in the U.K. sector of the North Sea. We've done some of that in Lower 48. We’ve done some of that in Canada. We will continue to kind of improving the assets that just a logical thing to do to keep your -- keep the portfolio healthy and manage the base.

What I talked about is moving from a strategic sense, talking about the larger coring up that we’ve done around Kashagan, Algeria, Nigeria in some of those assets. We are trying to rebalance the portfolio. So we are looking at cost of supply more and more flexibility to the portfolio that’s why I talk about lighting up in some of these longer lived assets and freeing up some additional capacity that we can invest into a growing unconventional position and some deepwater, deepwater success that we see coming.

So we want to be prepared to fund that because we think that deepwater is got a competitive cost of supply and fits well within our portfolio. But you’ll us continue to do a little bit of cleanup, probably not at the level that we've described here today and announced today, announced in the last year or so.

Paul Sankey - Deutsche Bank

Thank you.

Ryan Lance

Back there.

Unidentified Analyst

Hi. [Gary Lo from Ethic]. Ryan just two quick questions one is on the Canadian oil sands with the differentials depressed, would you consider deferring the growth projects and potentially the sale?

And two, on the midstream infrastructure, I think previously you commented that you, if you were to spend $500 million to $1 billion in CapEx you would consider an MLP as a more efficient funding mechanism, is that still the case and timing? Thanks.

Ryan Lance

Well, we are seeing a bit of dislocation I mentioned it in my opening a little bit between, and Doug, you mentioned it as well, what WTI is now trading at $10. Well, yeah, today, it’s now trading at $10 maybe NGLs or bitumen is a bit of more neck back.

Again, we are thinking about this business over five and 10 years. We are going to go through a bit of cycles where we see a bit of dislocation. We are seeing that today. But we do believe infrastructure is coming. We do believe that pipelines and ways to evacuate the groups, we don’t think longer term that those differentials are going to persist.

In terms of MLPs we are always looking at different options and tools within our portfolio to improve the returns, and we’ll continue to look at those all the time. In the back there.

Faisel Khan - Citigroup

Thanks. Faisel Khan with Citigroup. Just on some of the similar topics, your $6 billion to $7 billion operating cash flow growth number. Can you just elaborate a little bit more on what assumptions you make, I mean, is WTI trade $10 under Brent, $20 under Brent is WCS trade $50 as bitumen prices, where is all that paying out and is there recovery in the gas prices, you guys see, you guys assume a recovery in the natural gas price in the U.S. and how much does that make up of the cash flow growth from where we are today?

Ryan Lance

Yeah. So that margin analysis, I’ll try to be clear right in front what that represent, and that was Brent did $100, WTI at $90, so long-term it tend to have and WCS is $70, $20 below WTI, and $350 Henry Hub. So we don't really show much increases on the dry gas that was. But we had to pick a price tag, we had to do something to try to describe the margin analysis to you, that’s we chose. Over here, Ed?

Ed Westlake - Credit Suisse

Thanks. Ed Westlake, Credit Suisse. I think Doug asked about execution risks and still focusing in on the sort of the confidence interval on the production growth. There was a bit of a change I guess from prior guidance, I think in 2016 you were above 1.8 and in this guidance you are slightly below 1.8, is that all disposals, that’s the first question?

And then coming into some of the conventional plays, you got resource numbers, you’ve got production. Can you talk little bit about what's included from say the horizontal Permian, from the Niobrara, from the Canol and maybe Three Forks in the Bakken in terms of those projections that you’ve laid out today?

Ryan Lance

So, I’ll probably have Matt, help me out a little bit on some of that, but in terms of your first question, Ed. The, well, let me go to the last one first, which is, what we’ve kind of get in our plans.

What we came out before when you had maybe precisely about 1.6, so there are some incremental dispositions that are now built in our plans and one of those see again decline that was an opportunity presented itself at the end of the year. And it was unstrategic to us the investments that we saw going forward did compete in the portfolio, and it made sense to the person that we know the company, we sold to and they paid us more value for it.

So it made a lot of sense on both side, that’s a little bit of difference, plus we have factored in some of this rebalancing that I’ve talked about in terms of the oil sands and APLNG.

In terms of what is in the plan out in the future, we’ve taken a risk kind of view of the Niobrara development, Matt, shows up in our plans because we’ve been successful and we are thinking about that in terms of how quickly we can ramp that up and get that in, but that’s the only one I think that’s in the plan. And Matt, you might want to address that some more.

Matt Fox

So in the top blue edge on one of those slides refer to production coming from other North American unconventionals. And as Ryan said, that’s a risk-weighted view and it’s about 90,000 barrels a day. And it’s a risk-weighted view, we’ve just included some of those conventionals working, so it’s a Niobrara risk, Permian unconventional and Duvernay, I think the ones that we chose in that category.

So it’s about 90,000 barrels a day of the production by 2017 is coming from those are the unconventional. So there’s a lot more potential in that and the portfolio, I hope I made it clear, but that’s why we put into the base case here.

Ryan Lance

(Inaudible) over here.

Unidentified Analyst

Thanks, Ryan. Just had a question on the roll of M&A in business development going forward. The legacy company over the last decade has done a lot of stuff, some of which was good like the Cenovus joint venture, the low-cost Eagle Ford acquisition, some of which you’ve ended up reversing selling down APLNG, getting other shots et cetera.

Can you talk about the philosophy going forward? Is there a different approach and I guess, in particular to some of the business development stuff in terms of how you evaluate projects or is it just that you feel better about the organic growth that maybe you did over the last decade?

Ryan Lance

Yeah. I think, we’ve -- when I talk about what's changed in the company, it has been a movement of what's grown this company over the last 10 to 12 years through the M&A channel. And we have turned our focus in the last couple of years and as we’ve come out as an independent company on organic growth. So we talk about the role of mergers and acquisitions.

When we look at it, we just think the option value associated with being a good explorer and finding it organically is a lot better returns for the business for our shareholders. When you talk about acquisition, I have to parse that just a little bit. I’m not talking about the company acquisitions but we’re very active in land acquisition. That’s a large part of our exploration spend.

We acquired over 800,000 acres just in the last year and the half. And we’re doing that to try to get a first mover position or a very, very fast follower in some of these opportunities. So we can find the sweet spot. We identify the sweet spot early. Try to get early and capture the position at a cheap cost. We’re trying to replicate the $300 an acre Eagle Fords. And we did that in Niobrara. And we've done that in the Duvernay, the Montney and the Canol.

And that’s what we’re doing. We’re doing that in Columbia. We’re doing that in other places around the world. So that's a part of A, may be small A but we are spending a fair portion of our exploration dollars right now at $2.2 billion to $2.3 billion on that piece of the business.

You do have to look at exploration differently today. You have to look at it through unconventional lands and the conventional lands. It has different implications due to portfolio.

We’ll do Iain, next and then we’ll get to you.

Iain Reid - Jefferies

Hi. This is Iain Reid from Jefferies. Can I ask a question about exploration. Is it possible to say what level of risk or maybe on the risk reserves you’re testing in your activities in exploration, let’s say, 2013 to ‘14. And maybe if you can try and break that out between the kind of key areas. I’m thinking about Angola pre-salt and the Gulf of Mexico and also maybe as part of that, kind of identify which wells you think are going to deliver the highest bank for block either in terms of reserves proved up or MPV per well?

Ryan Lance

So you want me to jinx our exploration program right out of the sheet, Iain. I can’t say what sort of we were putting in terms of risks type of numbers on it. I just largest go back to what we’re excited about. We’re looking around the deepwater provinces around the world. This business has moved a bit from resource constraints to resource abundance.

We see that on the unconventional side. We see that developing on the deepwater side. We are excited about our deepwater Gulf of Mexico program. We showed you what we're doing in Angola. That said, Iain, talk about some of the others, the Poseidon and the Browse, you talked about. But there's Bangladesh. We’re early mover into the Bengal fan.

We’re taking a hard look at that. We've gone northern into the Barents Sea in Norway. So you saw, it talks about other kinds of areas, but certainly we’re taking a very, very technical science learned approached, how we’re doing it. We’re risking them appropriately. We’re building a global portfolio of opportunities. We’re thinking about unconventional and conventional and risking them differently.

And I think watch the space, ‘13 and ‘14 are important years for us in this space where we’ve got to put some runs on the board. And we’ve already started. We’ve already seen some success.

Jason Gammel - Macquarie

Thanks. Jason Gammel with Macquarie. I just wanted to square some of the comments about the oil sand business and potentially reducing some equity in that business related to comments about potentially bringing the cost structure down by 20 bucks a barrel and seeing the realizations. When do you think you’re going to actually realize the value that should be associated with those cost savings and margin increases?

Is that something you think is a two or three-year time window or is that further down. What level of exposure would you like to have in the oil sands? And are you talking about selling the unproducing assets or would this involve FCCL and Surmont?

Ryan Lance

Well, we’re looking across the whole oil sands portfolio. So we have a 16 billion barrel resource position. And Al and Matt both described the quality of the position that we have. It is made up of three different -- distinct asset. It is our partnership in FCCL. It is our operation in our different partnership with Surmont. And then it’s undeveloped 100% acreage that we own Thornbury, Clyden and Saleski. We’re not going develop that at 100%.

So we’re looking at various options and choices we have to lighten up that position. I don't have a specific target in mind right now but just telling you over time and longer term, we’d like to bring that position down. We've got a great position and we’re going to look at different structures that make sense.

With the dislocation in bitumen right now, we think that short term. We don't see it impacting the market too much today in terms of A and B or in terms of potential suitors. Because the resource position is so large, so long over a long period of time, I think people are looking at that and saying those differentials will start to collapse over time.

But we’re looking at various options around it. And certainly, it was complicated a little bit with the CNOOC acquisition of Nexen. So we have to be aware of what that in terms of developing our plans with how we’re going to do it. So I can’t get too specific with you because we’re looking at lots of different options about how we might to choose lighten up our position there. Paul?

Paul Cheng - Barclays

Thank you, Ryan. Paul Cheng, Barclays. I have three short questions. First, cost inflation. Where you see the biggest pressure right now and what’s your expectation over the next several years, your unique cost inflation pressure?

Second, based on your comments, since M&A is not going to be a prominent part of your overall strategy or portfolio for the next maybe two or three years, just want to confirm. Last one, you are going to do a lot of things and that some could be labor intensive in the Lower 48. So, from a human capability standpoint, where do you stand? Are you reaching close to your human capability limit with all the things that you're doing or that you actually have far more room? Thank you.

Ryan Lance

All right. Thank you. So three questions, make sure, I get these right, Paul. The first one on cost inflation. I guess, we -- you know there is pockets of around the world that are little bit different in the U.S. Lower 48 over the last couple of years. It was rigs and pressure pumping services. But as Al indicated we saw a little bit of reduction in that drop-off coming out of the low gas prices of 2010 and 2011.

But I think generally, we see a couple percent of inflation across the business. There's hot spots, there is labor. Laborers are little bit tougher in Australia these days. So there's bits and pieces of it around certainly the North American businesses seen a little bit more inflation just in some specific aspects of it. But I don’t think over term we see a lot of change relative to a couple of percent.

Paul Cheng - Barclays


Ryan Lance

I think, that would be long-term plan. M&A, Paul, I’m not out there, trying to find a big acquisition for the company. Again, we’re focused on organically growing the company, we got the portfolio to do it. We’ve got the options to go do it. That’s what we’re focused on delivering. I forgot your last.

Paul Cheng - Barclays

Human capability.

Ryan Lance

Human capability. Thank you. Yeah, certainly, all of us are in that kind of position. I think Larry has a favorite saying that if you can spell shale, you can get a job now in the United States. So that certainly probably is still the case. But we’re doing our fair share.

As we came out as an independent E&P company, we’re pretty focused on being able to tell our folks that we’re being competitive against the peer group that we’re seeing. That peer group includes independence and integrated majors.

So we’re doing -- we've done well to reduce our attrition rates down and we’re out in the campuses. We’re experience hiring. We’re hiring out of the campuses. So we know the plans we have in front of us. And we have workforce plan to deliver our plan. So we haven’t hit that constraint yet. Back over to you. Then I’ll come back over here.

Blake Fernandez - Howard Weil

Thanks. It’s Blake Fernandez with Howard Weil. I had a question for you on the dividends. Obviously, you’re in a period of increasing the production and margins in order to kind of reach the cash flow break-even to actually fund the dividend from ops.

And I’m just curious how comfortable are you with the CapEx at the $16 billion level remaining flat. Historically, industrywide, you would tend to think of some inflation there. And then secondly, is it fair to think any additional dividend increases would not come until you’d have actually reach that cash flow break-even level? Thanks.

Ryan Lance

So good question on the CapEx. We think in terms of approximately $16 billion. I think over the next couple of years, three years, it could be a little bit less than that, it could be a little bit more. It’s primarily tied to the dispositions that we have announced. When they close that had some impact on where the capital is going to be and then our efforts as I talked about to rebalance the portfolio.

Blake Fernandez - Howard Weil

So it could be a little bit higher, it could be a little bit lower?

Ryan Lance

But that's why we’re showing approximately $16 billion over the course of this plan. The dividend again it’s part of our underpinning. You should expect modest increases over time. We think that's important. We think that’s something we ought to be doing and that’s what we target at doing and it’s built into our plans.

Robert Kessler - Tudor, Pickering

Thanks Ryan. It's Robert Kessler, Tudor, Pickering. I wanted to ask about Alaska, specifically and your decline mitigation investments more broadly. In Alaska, you referenced mitigating or your intent to mitigate the decline rate is 3% per year over time.

You use Kuparuk as an example, octa-laterals. When I look at Kuparuk, the three-year average decline rate has been 3% up to 2011. 2011, it was -- I'm sorry 5% but it accelerated to 7.4% in 2012. And maintenance activity would appear to have been more significant last year.

So I asked for two reasons. I asked about that for two reasons. One is to understand Kuparuk specifically and why we’re not seeing some results there upfront and more broadly to highlight or ask is there a risk that higher downtime, lower utilization may proceed lower decline rates in your portfolio generally in the strategy?

Ryan Lance

Let me ask Matt. Do you want to take that one?

Matt Fox

So the decline rate change in Kuparuk last year was really a very larger maintenance program in Kuparuk. The underlying decline across the whole slope from Alpine, the satellites in Prudhoe and Kuparuk is going to be mitigated to about 3% on average over the five years, maybe a little bit earlier but more early as you can see in the graph. You can scale that off and that’s our expectation of the aggregate of the slope.

I think I said from -- at the Alpine West project, it becomes about 2%. And if the fiscal regime changes to encourage additional investment, opportunities exist to divest the decline in Alaska, opportunities from expanding our development programs and adding major projects. So we’re hopeful that will happen because a lot of opportunity still exists in our Alaska business.

Robert Kessler - Tudor, Pickering

And do you think that again along the lines of a lower utilization rate, while you work on the fields to mitigate the decline rate longer term, do you expect the field to come down as you tie in?

Matt Fox

No. I don’t expect to see. Apart from the planned maintenance activity, which varies from year-to-year depending on what maintenance we’re actually doing. No, I don’t expect to see any significant degradation in direct operating efficiency in Alaska for that matter across the board. And there is some additional downtime in our European assets in particular, this summer as we’re preparing to tie-in Ekofisk South, Eldfisk II and Jasmine. So we will have an unusually high level of down time in our European assets this year.

Robert Kessler - Tudor, Pickering

Thank you, Matt.

John Herrlin - SocGen

Herrlin, SocGen. In the Lower 48 states over the last three years, your CapEx has gone from 1.8 billion to 5 plus. You’ve address how you’re going to be kind of integrated in your approach to fuel management but these Basin s are all fairly competitive. So I’m curious as to what you're spending or activity capacity is in Lower 48 states. Is the 5.3 we’re seeing more or less static assuming a lot of time to ensure in terms of your spend or could you actually ramp that up if you so desired?

Ryan Lance

No. Our plans is, I said as we rebalance our portfolio and we get our production -- held by production and our intention is to ramp up the spend in the unconventionals. We’ve got the capacity, the capability to go and do that. That's advantage of our large position that we have in North America.

We can move rigs around to where the programs are working and where they are not working so well. But our intention is you should see us ramping up some of that spend over time.

John Herrlin - SocGen

But how much higher, that’s what I’m wondering?

Ryan Lance

Well I don't have specific numbers in mind. I think as we -- again we’re trying to pace it with infrastructure that’s coming in and the opportunity sets there. And when we figure out ultimately what down spacing, it’s the most optimum for things like Bakken and Permian and the Eagle Ford.

We don't know that quite yet. We’re taking a more measured approach to make sure we don't overcapitalize this place. Some our overcapitalizing it. I know that. I don't -- I can prove it definitively with science, that's what we’re intending to do.

So before we get carried away, we’re going to make sure we optimize the completions. We’re going to make sure the infrastructures there and I’m going to make sure we know how to -- this ultimate spacing we think is optimum to drill down to. We don’t quite know that yet in most of these unconventionals that we’re developing today.

John Herrlin - SocGen

Okay. I have one for Matt. With the Niobrara, you didn’t given any well specifics. Can you tell us what you -- what they were testing or what the EORs might be?

Matt Fox

I think I said we drilled there four wells and none of those have been on long-term test. We’ve been drilling relatively short laterals. We’ve been testing different orientations of the laterals.

So we don’t really have anything that would be our representative number to put out there as what we ultimately expect to have from these wells. But the results are very encouraging. The yields in particular are very encouraging. We were trying not to become more apparent but this is not beneficial through a number that wouldn’t be representative.

Ryan Lance

One back here please.

Evan Calio - Morgan Stanley

Thank you. Evan Calio of Morgan Stanley. Two questions largely, follow-up in nature number one. Could you quantify an amount of what percentage of the five-year, $25 billion North American Lower 48 CapEx spend that would be infrastructure related and this is significant infrastructure associated spending number there, I’m sure?

And secondly, with regards to Alaska, there have been very recent proposals to kind of roll back tax progressivity and Conoco's spending but for your Chukchi payment is largely tapered since ‘06 in the introduction of that higher tax. Any thoughts there on the tax and if it were to be made flat, do you see capital opportunities there greater than current? Thank you.

Ryan Lance

Yeah. So your first question on the $5 billion of Lower 48 spend. I think there's about a $1.5 billion and $2 billion that is in the infrastructure that we’re building. So we are making sure that we protect the net back to the leases. So if that means putting in facilities, pipelines and extra infrastructure to go do that, we’ll make those investments to protect our net back and our prices and optimize the developments.

Now, we are looking to get on third-party infrastructures well but that gives you a rough idea, maybe of what we’re trying to do. In Alaska, we certainly -- we've told the governor and Matt described it today as well. We'd be willing to make additional investments in Alaska. It would be competitive in our portfolio, if there was less productivity built-in that currently exists in the fiscal regime that Alaska has. We are hopeful that they are going through session right now.

There's been multiple proposals that have been floated around. Some are little bit better than others. But the message we have is that we do see additional opportunity in all three of the major fields, Prudhoe Bay, Kuparuk and Westover and Alpine. If there was a more competitive fiscal regime, we would be willing to invest more money up there than obviously within that create more opportunities. Over in the corner you will get the next, Faisel, yeah.

Roger Read - Wells Fargo

Yeah. Just a question coming back to kind of dividend, again versus the CapEx question and balance sheet debt levels in the business that’s inherently volatile price wise and everything. If the dividend is important and growth is important, why not take some of the free cash here from the asset sales and improve the balance sheets such that come ‘14 or ’15, if we were to hit a lower oil price period for a short time, or even a medium time that you'd be able to pursue the growth opportunities out to ‘17 and not have to make a step back. In other words, what is the full thinking on the cycle balance sheet strength, which while looks good today with a very different, $50, $60, $70 oil price environment.

Ryan Lance

Jeff, you wan to take that one?

Jeff Sheets

So if -- again, look at where we are today, $4 billion of cash at the end of the year, $9.5 billion of asset sales proceeds coming in, we are going to be building cash. Now, obviously we are spending capital and paying the dividend at a rate excess of cash flows. So some of the asset sales proceeds are going to be use to fund that. But probably all in, we close all these things we end up with more cash on the balance sheets. So we’ve got a lot of flexibility to fund on and through ’14 and ’15 and prices stay where they are in this gap but it closes.

So, if look at our plans today, we don't really use the balance sheet to make that happen. But the balance sheet is there, if prices are different then what we think they are going to be and we need to use a balance sheet. There is space to do that. So really it’s kind of a belts and suspenders. We got cash from operations. We got asset sales proceeds. We got cash on the balance sheet already and we got debt capacity.

So it really shouldn't be any doubt that through a series of price environments that we can fund the capital and the fund the dividend so. Whether the balance sheet, whether it's there, has cash or whether is there as a lower debt balance, we think it still represents balance sheet strength.

Faisel Khan - Citigroup

Thanks. Faisel from Citigroup. Just going back to APLNG, I just wanted to clarify some of the comments that you made. The project is about 5% to 7% over budget and then I heard a number of 20% in U.S. dollar basis. Can you just clarify exactly currency-to-currency, what we are using here and what the numbers are for the budge for APLNG and where we are with that?

Ryan Lance

Matt is my engineer. He’s got the decimals in his brains.

Matt Fox

Yeah. I would say about a 7% increases over the -- on an Aussie dollar basis. We spend about 30% of the capital. That 30% was spent with -- obviously U.S. exchange rate of about $1.04 or $1.05 in favor of the Aussie dollar. If you look at the forward curve, the forward curve has the U.S. dollar strengthening and that is swapping over to be a stronger U.S. dollar, more comparative to the U.S. dollar. We don’t know exactly how that’s going to work out.

So our expectation, the range that I gave you of 20% to 25%, that’s based on the assumption of the average over the life of the project as parity to the average over the life of the project is more like $1.04, $1.05. So that was the basis. Was that your question, Faisel?

Faisel Khan - Citigroup

Yeah. (Inaudible)

Matt Fox

That's right. And the reason I draw the distinction here is that -- what, I’m most concerned about is the project being executed well. I can't do anything about FX. But what I can do things about is making sure the project is being executed well. So the reason that we did this, bottoms-up review was to give us comfort that we are executing this project well.

Other projects in Australia have seen serious cost overruns, much more serious cost overruns than you’ve seen in APLNG. The bottom line in APLNG is projects running well. Yeah, we are seeing cost pressures, the wages and changes in regulations. But the project is running well and on an as spent dollar basis, the 7% increase is disappointing but it is not all that bad. Now, when we translate that to U.S. dollar basis, the FX is going to be where FX is going to be.

Ryan Lance

Over here.

Scott Hanold - RBC Capital Markets

Yeah. It’s Scott Hanold from RBC Capital Markets. A couple of questions. The first is in the Gulf of Mexico. You've got that patch of a 100% owned I guess 180,000 acres in Green Canyon. What is your view in terms of, what you would like to be in terms of working interest as you go on looking those prospects and what could be sort of the deal terms look like for Conoco?

And the second question is on the Eagle Ford Shale in your 1.8 billion barrels of resource potential. What type of recovery does that assumes? Is there any improvement from where we are right now and where ultimately does that go to? Is it -- is there something you guys are working on right now that you can to that get you there?

Al Hirshberg

Yeah. Certainly, Gulf of Mexico, we typically won't do things that are 100%. But we would like to be the operator of the stuff that we have. You're able to get leverage on good prospects in the Gulf of Mexico. So, Rob was going to be out there and looking, probably not developing things or exploring for things that are 100%. We would like to stay in the operator, which means we will keep a majority interest but we will look for leverage to reduce the risk and bring partners into those kinds of opportunities.

On the Eagle Ford, Matt can correct me if I’m wrong. But we are planning and drilling today on 160s and we are thinking probably down to 80-acre spacings or probably reasonable to go do. We have some questions below that. So what we’ve built into our plans is efforts to move to 80-acre spacing. Go ahead, Matt. You want something to add.

Matt Fox

The resource space is based on the assumption that we -- it’s not based on assumption that we have improve the recovery further. It’s based on current type curves. A current assessment of what we should expect to 80-acre spacing. And as Al said, we are looking at technology improvements and our expectation would be to grow the resource space but that’s not going to reflect -- that’s now what’s reflected in the numbers that we showed today.

Scott Hanold - RBC Capital Markets

What is the actual recovery percentage you are assuming for the reservoir itself?

Matt Fox

This goes back to the understanding of the underlying physics of these unconventional reservoirs. It’s not easy to understand how much of the hydrocarbons, how much hydrocarbons are going to be in the first place, how much of the kerogen has been converted to oil or gas. It’s not easy to fully understand the porosity.

So it’s difficult to -- people throw out recovery factors based on what they know and recovery factors are in the -- typically for these sort of plays are in the high single digits, are in their oil rich plays. But the bottom line is that people are honest. They don’t really know what the recovery factors are because they are not 100% sure where the oil and plays really is.

Ryan Lance

Maybe take one more. Maybe not. One over here. Okay. Last question, please.

Boris Raykin - Granite Associates

Boris Raykin, Granite Associates. I had a question about kind of your strategy in the Permian Basin and sort of the gift that it keeps on giving and especially in the conventional part versus the unconventional. So what kind of returns you are seeing there, what are your strategy is for developing that and how much running room you have there?

Ryan Lance

Well, as Matt described, we’ve got a huge 1.1 million acre held by production position, which gives us a lot of luxury. We can go faster, slow and make sure we are doing it right. We are pretty agnostic whether it's unconventional or conventional right now. We are just really trying to drill the highest returns stuff. We are not in a hurry. We can pace it with infrastructures.

So even though, this is a 100-year old Basin, it still needs some infrastructure to be able to take on this growth. It needs gas plants. It needs more evacuation capacity going out of the Basin. We're not in a hurry to drill because we don't -- we’ve got it held by production. So we are pretty agnostic about, whether it's conventional or unconventional, just trying to rank it and do the most profitable things first.

Ryan Lance

Let me thank you again for your interest and your participation today. I think for those that can stick around, we have some lunch on the seventh floor. I would just reiterate probably the one thing, which is this is what we are about. This is our value proposition. We are going to run the business well. Our dividend is differential. We are going to grow it. It’s not just growth-for-growth sake. It is high-margin growth and we really do have a laser like focus around improving the returns in this business. So that’s what ConocoPhillips is about and I thank you for your attention.

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