Talisman Energy's CEO Hosts Toronto Investor Day Open House and 2013 Guidance Conference (Transcript)

| About: Talisman Energy (TLM)

Talisman Energy Inc. (NYSE:TLM)

March 06, 2013 8:30 am ET


Lyle McLeod - Vice President of Investor Relations

Harold N. Kvisle - Chief Executive Officer, President, Independent Director and Member of Executive Committee

Paul R. Smith - Executive Vice-President of North American Operations

Paul C. Warwick - Executive Vice-President of Europe-Atlantic

A. Paul Blakeley - Executive Vice-President of Asia-Pacific

Richard Herbert - Executive Vice-President of Exploration & Development

L. Scott Thomson - Chief Financial Officer and Executive Vice President of Finance

John A. Manzoni - Former Non Independent Director, Member of Executive Committee and Member of Health, Safety, Environment and Corporate Responsibility Committee


Greg M. Pardy - RBC Capital Markets, LLC, Research Division

Curtis Gillis

Peter K. Ogden - BofA Merrill Lynch, Research Division

Darren T. Peers - NWQ Investment Management Company, LLC

Brian Singer - Goldman Sachs Group Inc., Research Division

Matthew Portillo - Tudor, Pickering, Holt & Co. Securities, Inc., Research Division

Christopher Feltin - Macquarie Research

Ryan Bushell - Leon Frazer & Associates Inc.

Lyle McLeod

[Audio Gap]

items out of the way here to start off the day. In the unlikely event that we do have a fire alarm, we would proceed through the doors to my right, down the stairwells into the main lobby and then proceed up the side exits into the master point parking lot. But I don't think we'll be in that situation today, hopefully.

Second thing I have to go through is a little bit of legalese. So as always, this presentation contains forward-looking information statements, which are based on certain material factors and assumptions and are subject to risks and uncertainties. Accordingly, our actual results may differ from those projected, and I refer you to the advisory in that regard contained in the written materials accompanying this presentation.

Okay. So that out of the way, I have to go through 3 pages of these, our agenda for the day. We'll start off with an overview of Talisman from our CEO, Hal Kvisle. And then we'll move on to discuss our North American business. Paul Smith will be talking through that. Then we're going to have a short 15-minute break, and I request that everyone keep to this time frame because we've got a pretty full agenda and a pretty full house here as well. So I'd like to keep us on time with that. After the break, we'll hear from -- hear about our North Sea business from Paul Warwick, and then follow it up -- we'll hear about our Asia Pacific business from Paul Blakeley. It's the Paul show today. And finally, Richard Herbert will talk us through our pretty exciting Colombia and Kurdistan businesses. Then we'll conclude with a short wrap from Hal and then move on to a question-and-answer period.

And again, if we sort of stick to the agenda, hopefully we'll have a good time for a good and healthy Q&A session. And after that, we do have lunch available. It will be in the room sort of across the little hallway here, and all of our executives will be available for further sort of Q&A and discussion during that lunch. So it's a pretty full day, and we have a pretty full house. So with that, I'll stop and turn it over to Hal.

Harold N. Kvisle

Thank you, Lyle. Good morning, everyone, and thank you for coming to our event today. We, of course, want to update you on the status of things that we're doing within Talisman to redirect and reshape the company. You will hear today about our plans to sharpen our performance throughout the cycle and everything that we do from finding, development on to production and generation of cash flow. These are really the high-priority items within Talisman today.

We have some large investment programs in different parts of the world. Getting those performing in a top quartile way is a major focus of what we're doing at Talisman today, and I'd like to talk about that. And finally, talking a little bit about our 2 core regions of the Americas and Asia-Pacific. These are areas that we've decided we're going to focus our efforts in, and we'd like to talk about those and share with you our plans for the assets in other parts of the world.

So without further ado, I'll jump into it. The first slide that I have here is really titled Addressing the Issues, what we want to convey to you, what we think the issues are that we face in Talisman today and what we're doing about them.

The first is the reality of the past 5 years. We've been through a 5-year period of heavy investment in a number of different areas around the world, and we were very focused on growing the company at 5% to 10% to 12% per year. And the reality is, that didn't happen. And so today, we need to stabilize the company and refocus our efforts and change the way we go about creating shareholder value.

We've done some key things. Debt reduction. The bulk of the proceeds from the Sinopec transaction in December went to reduce debt and get our debt-to-cash-flow ratio at a level where I'm comfortable it's not going to be an issue for us going forward. We've reduced and refocused our capital program on projects that will bring cash flow in a shorter time frame and, I believe, create more value for shareholders.

We've done some pedestrian things like commodity price hedging. This has been important to Talisman, and I think we've refined the way we've done it. And we'll have a greater degree of hedging, not as a speculative activity to try to beat the market, but simply to stabilize cash flow and give us more predictability as we plan for the time ahead.

You'll have read in the guidance that we released and have already commented on this morning that we have identified 2 core regions: the Americas, consisting of Canada, the U.S. and our oil assets in Colombia, will be a very strong core region for Talisman and an area of focus; and Southeast Asia, or what we now call Asia-Pacific. We've had great success in Asia-Pacific in the last decade, and we want to continue to build on that. We will develop joint venture or divest the rest of our portfolio over time. We would like to move as quickly as possible to trim the company down and focus on the 2 core regions, but there are hurdles we need to get over with just about every asset before we can do some of the things that we want to do.

In Talisman today, we have a large and very valuable portfolio of assets that produce little or no cash flow, and some of this is the direct result of the activities we've been pursuing in recent years. But we need to take steps to surface the value of those assets, either by developing them and turning them into cash flow or by divesting them. We are committed to $2 billion to $3 billion of divestment of assets over the next 12 to 18 months, and we would obviously focus those efforts on assets that generate less rather than more cash flow.

In terms of our capital program we'll share with you today, we're heavily focused on oil and liquids growth here in North America and Colombia, and we're focused on gas that attracts an international gas price rather than the North American gas price in our operations in other parts of the world.

And finally, a particular important initiative for me, we need to focus on operational excellence in everything we do at Talisman. Getting things done better, faster, safer and at lower cost is the #1 priority for our company. Operational excellence in fact exists in many of our operations, but it has not been a high priority at the corporate level. We're going to change that and really set some high expectations for people around the way we operate our assets and deliver value from them.

Giving you an overview, a map of the world here that shows the different areas that we are planning to focus our efforts on. Today, we want the company to come across as being focused on 2 core regions: Americas and Asia-Pacific.

In the Americas in the next 2 to 3 years, we'll be focused on liquids growth in places like Eagle Ford and Duvernay. And at the same time, we want to sustain the option value of the long-term potential of our large gas resource base. We today sit on approximately 36 tcf equivalent of contingent resource here in North America. This is an enormous number, but we also appreciate that many of our competitors are sitting on enormous resources of shale gas as well. It's a game changer, to use a common phrase here in North America today. This is a different world that we're going to be in. It's a world where the successful gas producer will be the low-cost gas producer. Low on the cost curve is where we need to be to lead that margin of profit and cash flow.

Also, in the Americas, focused on Colombia oil. I've made 2 trips now to Colombia, spent considerable time there working with our team. We have some terrific assets in Colombia. We've been frustrated by a slow pace of development as a result of delayed regulatory approvals. But recently, things have started to come through, and we're very excited about what lies ahead on our Colombian asset spread.

We are planning to divest a significant portion of our North American gas resource base. We simply are not a large enough company. We do not have the financial resources, and I don't think the market could accept a rapid development of all of our gas resource here in North America. Two areas in particular that we're focused on as divestment candidates, Montney in British Columbia, which has about 2/3 of our total resource base. And in the Montney, we would examine a couple of different options. One is a complete exit from the Montney play. The other is that there are really 3 distinct areas to our Montney position, I'll come to it later; and our progress may consist of divesting or forming a joint venture on 1 or 2 of those, but not all of them.

And in the North Duvernay, I'll show a slide in a few minutes to talk about that. At the other end of the map, Asia-Pacific is about 1/3 of Talisman's total production, and it's the region that has a great track record of growth and value creation, 8% annual growth over the medium term. We expect to generate between $300 million and $500 million a year of free cash flow after CapEx per annum going forward in Asia-Pacific, and that is a great example of, I think, what we want -- how we want the whole company to develop.

In the middle, we have places like the United Kingdom, Norway and Kurdistan, and rationalization of our assets in those areas is obviously a priority in the next couple of years.

We also have some valuable, what I'd call non-core, non-operated properties that generate very strong cash flow for us. People often ask me, "What are you going to do with Algeria?" Well, I'll come to that. It's an attractive property that is not something that takes a lot of our time and attention, and it's a very strong cash flow generator. And there are some significant relationship reasons why we would want to keep an asset like that. So we'll touch on some of those things here over the course of the morning.

Just to recap that we have in fact been busy and working hard on things over the last 6 months. I think we've accomplished a fair bit. Getting the Sinopec transaction done in the U.K. North Sea was extremely important to Talisman. The team, both in Aberdeen and in Calgary, worked very hard to get that transaction completed. We did that in December, and we generated $1.5 billion of cash proceeds from that. And we now have a very workable joint venture with Sinopec, 51% Talisman, 49% Sinopec, and that's up and running. And we're pursuing that business with them in the U.K. North Sea.

We continue to move forward in Asia-Pacific. We completed the transaction to acquire Kinabalu, a producing property in the Sabah region of Malaysia, and we are extending into exploratory activities in the land spread surrounding Kinabalu. We have a development property in Vietnam, HST/HSD, where a couple of offshore platforms in other facilities are in the final stages of installation. And we expect first cash flow from that oil property about midyear of this year.

We've put a lot of work and discussion and effort into redefining and refocusing our global exploration program. It's important, I think, that Talisman focus on areas where it has unique local knowledge and where we know something in detail about the opportunities and prospects we're pursuing. We also need to focus on exploration opportunities that have a shorter time cycle, where we can get production out of them more quickly. We've made great progress on exploration in Colombia and in Kurdistan. We'll spend a little time on that later this morning.

Over the past 3 or 4 months, we've taken some very tough decisions in North America. We've curtailed our investment spend in the Marcellus. And I want to emphasize, this should not be seen as a negative reflection on the Marcellus property. I've seen few properties in my career that have the quality and predictability of our Marcellus gas. But at this point in the gas price cycle, it's important that we pull back.

We're redirecting our capital this year in our efforts in focusing on liquids development in the Eagle Ford. We are, as I said, moving to divest all or a portion of our position in the North Duvernay, around Kaybob, and the Montney play in Northeast B.C.

We are making significant progress on cost reductions in all aspects of the business, capital costs, operating costs, G&A and overhead costs in our head office. And we continue to strengthen our balance sheet through debt reduction and, as I mentioned, systematic hedging as we look forward on both the gas side and the oil side.

There has been a very focused strategic process going on in Talisman over the last 3 or 4 months involving roughly the top 100 people in the company. We got together for several days in Alberta in December and worked through some difficult issues and, as a group, came to answers as to how we're going to do this going forward. I think that's important, that the entire senior team of the company is engaged and involved in these efforts.

As you look at the North Sea, Paul Warwick will give us a little more detail on this later this morning, but you can see that the North Sea, in the U.K. particularly, is going to be a much smaller part of our overall portfolio. As a percentage of Talisman's production, the North Sea has gone from 30% down to around 10% of our total daily production. However, it's still valuable. That 10% of our production does deliver more than 15% of our corporate cash flow.

So with Sinopec, we intend to invest joint venture money to fund high-value activities, things that we perhaps should have been doing over the past 5 years. We've fallen a bit behind, and now it's going to take a focused effort to get the North Sea back on track through infill drilling. We've got a lot of infrastructure, platform improvements, things like that, that we need to do; programs to extend the life of some of the mature fields in the North Sea and dramatic improvements in operating efficiency. Paul Warwick will talk about that.

As I mentioned, we're moving to 2 core regions. And when you think about what these 2 cores mean to us, first of all, the 2 core regions will consist -- about 90% of our total production will be there, 85% of our proved and probable reserves, 90% of our reserves value, 95% of the contingent resource base of the company and about 85% of our unrisked prospective resource. So it's a 2-region model, but it does include some of the most valuable properties in the company. And by any measure, it represents about 90% of Talisman going forward.

For those assets that are outside of our 2 core regions, we intend to manage them for value. Some of them we will hold for production and cash flow, some of them we will divest to other people. Some of this will take a little bit of time. But what we need to do is remain focused on transactions that bring the most value to shareholders.

As we look at our 2 core regions, firstly in the Americas, we have the large gas resource plays in Canada and the United States, some of which have significant liquids potential. We also have Colombia where, as I said, we're getting to the point of moving ahead more quickly now that we seem to have some of the environmental permitting issues out of the way. Enormous heavy oil potential on Block 9, Block 6 and some of the other areas that we have in Colombia.

In Asia-Pacific, of course we have a great track record. Paul Blakeley will speak more about that in the time ahead this morning. As we look at unlocking net asset value, we've set some 2013 goals. We do aim, first of all, from our core properties, to sustain volumes and cash flow and to do that with a significantly reduced capital program, focusing our investments on liquids and on high-value international gas.

On the exploration front, we will invest to delineate the very substantial oil discovery that we've made in Kurdistan and to continue the appraisal of the significant gas resource that we're onto in Papua New Guinea. Our top priority for the next months of 2013 will be the $2 billion to $3 billion divestiture or joint venture targets that we have in the Duvernay, in the Montney and in the North Sea and reinvesting the proceeds of these divestments. First of all, we do have a gap, you'll see this morning, in our 2013 capital program. We do have a number of excellent incremental development opportunities. We have places, for example, in the Marcellus, where we can invest at an attractive rate of return even in today's low gas price without exhausting the potential of the Marcellus. We have a lot of running room there.

And thirdly, share repurchase. This is not an announcement that we're going to do a share repurchase, but it would be obviously one of the options that we need to look at if our shares continue to trade at a discount to value.

Looking at the 4 priorities that I've talked about publicly for some time now that we're going to focus on to drive value creation, first of all, a lot of this is cultural change. We need to change the way people within the Talisman organization think about their jobs and what they place as high priorities. And I think this message is getting across quite well, and people are embracing it.

First of all, living within our means. In each part of our company, we have to fund our capital programs from our cash flow. There will be some cash transfer from one region to another but generally, we need to embed the thinking that we've got to be self-funding in every part of the company.

We will sell assets, but we'd like to do it to maximize value to shareholders, not selling assets to fund the gap in our capital program. We target as to maintain a debt-to-cash flow ratio between 1 and 1.5. And if we can live within that range, we'll be strong and well prepared for difficult times when they come along. We'll also be prepared when unique opportunities come along. The dry powder that, that brings us, I think, will be valuable to us.

Secondly, focusing our capital program on opportunities that bring cash flow sooner and cash flow that's sustainable with less risk. That sounds Utopian. Everybody wants that. But with a smaller capital program, we can in fact focus on the opportunities that are meeting those characteristics and the -- things like exploitation of existing assets; further development, particularly of oil pools; optimizing production; and in many of our areas, there are bolt-on acquisition opportunities that we think would fit well and have synergies for us.

Third priority is to improve operational performance. We need to squeeze more cash flow and more value from every barrel that we produce. And fourth, unlocking value from our big development portfolio here in North America, in Papua New Guinea, in Kurdistan and in the remaining assets in North Sea.

Investing within cash flow that I mentioned is one of our top priorities, allocating that cash flow to deliver strong results. On the left-hand side of this chart, we show cash flow versus investment by product. So you can see what the components of our cash flow will be in 2012 and what they were in 2012 and what we're looking at in 2013. The green bar in liquids remaining relatively steady over time. North American gas generating significant cash flow in 2010, but due to pricing that's crimped quite a bit in 2012 and 2013. We have curtailed drilling in the Marcellus, which has reduced gas production there, and also in Alberta. So our total North American volumes on the gas side are going to be down, and the cash flow coming down, as you can see, with them.

On the bars on the left-hand chart at the right-hand side of those, the gray bars represent the cash flow that were -- sorry, I've got the bars -- I described them backwards here. The red and green bars represent the investments we're making. The gray bar represents the cash flow. And you can see that in the last few years, we had to do significant divestments to balance the gap between cash flow and reinvestment.

On the right-hand side, we show where we're investing capital by region in North America, Colombia, North Sea, Asia-Pacific and the rest of the world. And we've made some significant moves this year. We have reduced our CapEx in a number of areas. You'll see that we're going to go up in Asia Pacific and up in Colombia this year. Capital investments will go down in North America, down in the North Sea and in the rest of the world.

Our target in big numbers is a $3 billion capital program, down from around $4.5 billion, and $2.5 billion in cash flow, leaving the $500 million gap that we intend to cover through divestments. And as we move forward in future years, the whole objective is to get this in balance so that our cash flow and our capital program are more closely aligned. As you can see from this chart, we've made significant progress since 2011 in bringing those 2 together. 2013, I think, will be a very important year in demonstrating that we can do that.

As we look at where we invest our capital, we have a high grading opportunity ahead of us. You can -- we've attempted to map out on this chart, first of all, what is the operating netback on the horizontal scale and what's the opportunity for production growth on the vertical scale. The green circles represent oil weighted properties. Red would represent gas. And you can see the most difficult investment opportunity we have right now is Canadian conventional gas over on the far left. It sits with a relatively low operating -- well, a very low operating netback at this point in time due to -- just where gas prices are. And we would have significant opportunity to grow that. But the objective in the near term is to remain in the gray shaded bar where -- what we're trying to do there is sustain the production and sustain our position over the next 3 or 4 years until we think greater opportunities for investing in the stronger gas commodity market will come along.

At the other end of that gray band is Shaunavon, one of our great heritage properties in Western Canada, where we continue to produce heavy to medium gravity crude oil. A great netback, a netback that will get better once some of the oil pipeline bottlenecks out of Western Canada are removed. But a high-growth rate opportunity would be Eagle Ford, where we do have the opportunity to increase both gas and liquids production, and that's a major focus for the current year. Kinabalu, obviously at the top, Colombia and the 2 Vietnam projects generating very large netbacks. So what we have to look at I think right now, firstly, what kind of capital is it going to take to sustain our position in each of our major core areas? And secondly, what are the opportunities for really high growth rates with high netbacks? That's the combination that we're focused on.

I mentioned more focused exploration. And you can see in this chart here that long-dated exploration shown on the blue bars really reached its peak in 2011 as the company was looking at a number of areas around the world. In 2013, we have scaled that back dramatically. It's simply what we have to do as we try to live within our means from a capital point of view.

We will, this year, spend about $100 million on long-dated exploration and about $150 million or more on near term, depending on permitting in Colombia and how things go in Kurdistan. We're going to focus over the next 5 years on opportunities that are closer physically to our core operating areas and closer in time to an on-stream date, things that we can find, develop and bring on stream more quickly.

So we have had exploration of up to 25% of a large capital program. We're aiming to bring that down to 10% to 15% of a smaller program. And looking at long-dated exploration, it would be around 5% of the total program going forward.

I have talked in previous quarterly calls about the value that we can create from flat production. And I showed on an earlier slide that gray band where we saw properties that offered the opportunity to generate strong netbacks at a relatively flat production year-over-year over an extended period of time. And on those, the objective is to move to a wider netback firstly by reducing cost, but sometimes by product substitution. In the Eagle Ford, for example, we are able to direct most of our money to date to liquids-rich opportunities.

So if you see this chart that I've just put up, in 2012, we had production of about 425,000 boe a day. We did significant divestments during the past year, notably in the North Sea, and that left us with a production rate of around 395,000. In the current year, we are seeing our North American gas production decline as shown on the red bar, but we're seeing growth on international gas, notably in Southeast Asia, at a much higher netback price, and growth in liquids. So we will go through the year at about that 385,000 to 395,000 level of production, and we expect to increase cash flow as a result of moving away or letting our volumes decline somewhat in relatively low-value North American gas and focusing on growing production in higher-value areas.

As an example of operational excellence that I mentioned earlier, sometimes not the most exciting topic but I think very important for Talisman right now, the top chart shows what we've done to drive drilling cycle time down by almost 20% per annum in terms of the number of days it takes to drill in a case of well. Now the bottom chart shows the progress we've made, 9% per year in reducing the cost of drilling and completing a well in the Eagle Ford. Our focus there is to drill more wells for the same amount of capital, get those wells through the drilling and completion process more quickly, get them tied in an on-stream, all leading to lower finding and development costs, faster production and more cash flow.

In terms of overhead, there's been discussion about what we're trying to do in terms of reducing G&A costs. What we want to do in net terms is reduce our G&A run rate by $100 million to $150 million per year. That would get us from the high end of the spectrum into the middle of the pack as far as G&A cost per barrel or G&A cost by any measure of activity.

If we can achieve that $100 million to $150 million reduction in G&A run rate, we'll be well on our way in the right direction. How do we do that? Well, one element of Talisman that has struck me as being a strong -- a big contributor to high G&A costs are these far-flung programs in many different parts of the world. It takes a large corporate effort, a lot of legal support, a lot of government affairs support, financial support. It just takes a lot of background work to be operating from offices in places like Kurdistan, like Sierra Leone, Peru, Poland, places like that.

So we need to pull back and get ourselves focused. If we're going to be in places like that, we need to focus on only the very best ones. Today, that would be Kurdistan. Kurdistan is a really attractive opportunity, I think, for the company. We'll focus our international exploration efforts on places like Kurdistan and in our Asia-Pacific region, Papua New Guinea, and reduce and pull back from very expensive programs in some of these other locations.

In addition to that, Calgary head office offers many opportunities for cost reduction. We were building an organization aimed at sort of an 800,000 boe a day company. As we recognize that, that's not going to happen as quickly as was planned, we can pull back, and there are a number of areas at the corporate center where we have greater capability than we need. In our Canadian operations, you would have seen roughly 100 people exited our organization last week. We have similar reductions going on in the corporate side of our Canadian locations, and that will continue.

The whole focus is on reducing activities, stopping doing things that we don't need to do, increasing the efficiency of things that we do need to do and focus our efforts on value creation.

As we look to unlock the value of the portfolio, through divestments primarily, you can see on the left-hand side of the chart that our 6 major assets constitute 60% of our cash flow. And they're interesting. If you look in Asia, 3 out of the 6 are the Corridor block, which I think is the single most valuable asset that Talisman has; PM-3, our largest physical operation; and then HST/HSD in Vietnam. Those 3 assets are 3 out of the 6 that are most important to the company.

The other 3 are the Marcellus in North America, our Colombian oil business and the Eagle Ford in Texas. So those 6 assets would constitute 60% of our cash flow and roughly 60% of the producing property value of the company.

On the right-hand side of this chart, we show the assets that we are looking at as to what we might do with them to divest them, to joint venture them, to develop them. What's next? The biggest one obviously is the Montney, where the range of value is somewhere between $2 billion and $4 billion. Very big position. We don't need all of it, and we're examining different ways that we might proceed to either bring in partners or divest a portion or all of the Montney in British Columbia.

The Duvernay, 2 parts to it, North Duvernay and South. Paul Smith will talk a little bit about the successes we're having in the South Duvernay, and we're very excited about that. In the North, we've got a great land position, but it may be an asset that we can divest for a very good value to somebody else and focus our efforts on the south and on other assets within our portfolio.

Kurdistan. I think the width of the bar here could exceed the width of the chart. Kurdistan is one of the most exciting oil structures that I've seen in my career. We're very enthused about the next couple of wells that we're drilling there. They will tell us a lot about both the Kurdamir structure and the Topkhana structure. Richard Herbert will talk more about that a little later this morning.

And finally, Papua New Guinea, where if we can aggregate a large enough gas position to underpin an LNG project, that would be of interest to LNG players who would either acquire it from us or join with us to develop that into a legitimate LNG project.

OCENSA is a pipeline in Colombia that we're looking at our options. We can either keep OCENSA to move our own oil production to market, or we can divest it to a pipeline company that would pay a relatively high EBITDA multiple, certainly a higher multiple than we trade at, to take that over from us and we'd just become a shipper on that system.

I want to, though, address the question of what we do more broadly with the company. I think we -- obviously, as some of our analyst coverage has written about, we do have broad options that we can look at in Talisman. And there have been -- I've been asked many times whether or not Talisman is for sale. Rather than working through these individual assets, would we consider a sale of the whole company? And the message from our board is we at all times have to consider those things, that if legitimate offers from credible players come forward, Talisman has to deal with them and consider them, and there's no restriction or negative reaction to that. This is just part of business, a part of the business that we're in.

Another suggestion that has been made in the second category is really that of splitting the company or spinning off one part of it. People frequently ask me, "Why don't we spin off Asia?" Well, Asia is not a small peripheral part of this company. It's one of our 2 core areas. It's really in many ways the heart and soul of what we've been successful at in the last few years. And we've done quite a bit of analysis with financial advisors on different ways of separating Talisman into different companies. And in every case, the answer is the same. It doesn't actually make sense for us to do that. It's a -- there's a lot of friction to go through that kind of process. There's a lot of increased overhead as we establish 2 companies. And that's a lot, I think, of risk for our shareholders. And as a shareholder, I would not want to see Talisman split into 2 companies. I don't think it's a particularly creative solution where we're at.

The third is really the opportunity that's presented on this slide, and that's part of the bigger picture that I talk about, developing our assets, joint venturing them with someone else or divesting them. If we can't see a clear path to develop an asset for cash flow, if we can't see a practical way to form a joint venture that works for both parties, then I think our option is to divest that property. We can't sit on this stuff. We need to pursue one of those three: to develop them, to joint venture them or to divest them.

When you consider North America and the very large resource base that we have, we have characterized this as being 6 specific plays or opportunities for us within North America. But as you drill down through those, there's literally dozens of specific plays. In our heritage heads and core region, we have so many opportunities in a lot of different formations, some of them dependent on stronger gas price, but many of them quite attractive and economic today and wanting for capital.

We have in total 1.3 million acres of mineral rights here in North America, a very big position. We would see 5 tcf equivalent of proved and probable reserves, half of that really being related to the Marcellus; 36 tcf of contingent, the bulk of which is in the Montney; 13 tcf of prospective, most of which is in the Duvernay; 13,000 drilling opportunities. The magnitude of these numbers are staggering. 40% of our drilling opportunity is in the Montney and 1/4 of it in the Duvernay.

But I think one thing we're realizing is that the number of tcfs of gas resource you have really doesn't matter anymore. In North America, we now have such an enormous resource base, thanks to the shale developments. What does matter is production. What does matter is cash flow. And as we look at our assets in North America, we have to consider how much capital are they going to take, how many wells do we need to drill, which of them should we keep and which should we divest and pass on to someone else.

If you look at it from a funding point of view, this is the capital required to develop our Marcellus position. I would say that the Marcellus is something we can manage and manage very well over the longer term. The Eagle Ford, equally, there's good liquids potential there. We're getting quite good at our operations in the Eagle Ford. The team has come a long ways, and Eagle Ford seems to be something that should fit well with the company long term.

The Montney, obviously, from this chart, you can see the enormity of the capital challenge there and the obvious need not just to do the Sasol deal that the company did a great job of putting together a couple of years ago, but also to move forward with additional joint ventures or divestments in the Montney. It's simply too big a position for us to economically develop on our own. And in the Duvernay, we have 2 very clear properties, the North and the South. At this point, we think the best opportunities for Talisman lie in the South Duvernay, so we will look at options in the North.

Turning to those 2, in the Montney, the chart on the left really breaks down into 3 distinct areas. In the south, Groundbirch and Saturn where companies like Shell are very active. In the middle, shown in the red circle, Farrell Creek and Cyprus A. These are the properties that we formed the joint venture with Sasol and where they continue to provide the bulk of funding for our developments going forward. And then up at the north end, some of the best Montney assets, best land acreage that we have in an area that we call Greater Cypress.

The map on the right shows here the current situation in the North Duvernay, and it looks like a bit of a scatter diagram. But what we've tried to show here are the positions of the different major players that you would have heard about. Now you'll see down on the lower left in the dark red is the dry gas part of the play. Talisman's land, shown in yellow, is primarily in the rich gas part of the play, shown in a lighter red through the middle. And then up to the north, you'll see the oil window. We are not active in the oil window of the north Duvernay, but we have a very significant position in the rich gas part.

Some of the other companies that are shown there: the Exxon Celtic transaction are the purple lands, which are adjacent to ours in many locations; Encana's big position, a little further to the northwest of us, shown in brown; and the Chevron land, shown in green. Quite interesting, I think that Chevron has returned to Canada to get into this, but no surprise that they're doing it here. This is adjacent to Kaybob, an area where Chevron was one of the pioneers 50 years ago. They've obviously retained geological knowledge and come back here after a significant period being away.

So that's the situation in the North Duvernay. We think Talisman's position has not been well appreciated, just how significant our land holdings in the North Duvernay are and what a great location they're in. And obviously, we have significant interest from people in what we might do there, either in a divestment or a joint venture.

So I'd like to just take a moment and talk about some of the other international assets that we have that don't fit within either our North American core or within our Asia Pacific core. When you look at the rest of the world, in the North Sea, the Sinopec joint venture, 49% of our assets going to Sinopec, that has reduced our North Sea production to 26,000 barrels a day.

In Norway, we've had 2 problems. We've suffered some decline. We think that could have been avoided with a little more investment in some of those properties. But more notably, the Yme situation has not gone well. The team is working hard to bring the Yme arrangements to a conclusion so that we can move forward with that asset under a different arrangement.

Between Norway and the U.K., our production is around 50,000 boe a day. That's 10% or 15% of Talisman's total production, still a very valuable cash flow to us.

If you look in Colombia, the OCENSA pipeline. Now if there's $50 million a year in cash flow as an owner and you put a 10x multiple on that, that would have a value of around $500 million. If that can be raised to $60 million with a 12x multiple, some of the pipes created at that level in Colombia, that would be $700 million. So that's the range. We think the OCENSA asset as a divestment opportunity for us is in that $500 million to $700 million range.

Algeria, a little dot on the map in North Africa and often raised by people as something we ought to get rid of. There are a couple of interesting issues there. First of all, strong production and valuable production. Strong cash flow, significant reserve life and considerable upside in where the developments in Algeria may go. We're not the operator. The operator, ConocoPhillips, has just done a transaction to sell to a company that we're very close to, Pertamina of Indonesia. And we look forward to being a good partner of Pertamina and strengthening the relationship that we have with that company, not just in Algeria but notably in Indonesia. So there are some strategic reasons in addition to the strong production reserves and cash flow that we enjoy in Algeria. I would see that as an asset that we're likely to keep at least for the medium term.

In Australia, Kitan is a property that continues to surprise us in terms of strong production, but the reserves would appear to be relatively limited. And that would be one, at some point, I think you'd see us look to get out of.

Kurdistan, a huge resource base, no production obviously today, but more opportunity than I first thought at what we might be able to do to get it on. And Richard will talk about that a little later. And finally, a very small property in the grand scheme of things, Tangguh, operated by BP and Indonesia, an LNG project, one that I like being involved in, firstly because of the insight it gives us on how the LNG business is developing in that part of the world. And secondly, there's a third phase to Tangguh that we would like to be an investor in. The rates of return are very attractive.

Now if you look at our total portfolio of what I call the non-core, non-operated assets, this is our Australia position, Tangguh and Algeria. Taken together, these assets produce about 25,000 barrels a day of high-value production, about $250 million a year of cash flow and very low capital expenditure. This is an interesting non-core, non-operated portfolio. These are assets that for value we would certainly divest, but I don't see a particular pressing need to do that, a significant upside in value in those assets.

Kurdistan, I've mentioned. Really, I'll leave this to Richard. I just want to draw your attention to -- on the slide. Our blocks are shown in yellow. And not too far away to the left and above to the northwest is the Kirkuk Field. And Kirkuk is a field that -- 25 billion barrels of recoverable oil. And you compare that to the 175 billion barrels of the Canadian oil sands, which I'm sure will grow over time, but the Kirkuk recoverable volumes may also grow over time. Now that is a field that's owned by the Iraqis. It's not owned or operated by any private sector company, but it does give you some sense of the enormity of reservoir volumes in this part of the world. You can see, shown in green, are a number of the other legacy fields in that part of the world. And our assets that Richard will talk about on the yellow blocks, generally on trend with that -- with those big fields.

We have provided this morning a capital guidance and production cash flow guidance for 2013, and I've -- this is just summarized on this page. I won't take you through it. But in terms of total production, between 375,000 and 395,000 barrels a day. CapEx, approximately $3 billion, plus or minus a little bit. Of the total CapEx program, about $1.3 billion of that in the Americas, about $700 million of it in Asia-Pacific. Those 2 taken together would constitute $2 billion out of the $3 billion total. Of the other $1 billion, the bulk of it is through our joint venture in the North Sea with Sinopec, where, by forming the joint venture, we're able to invest a lot more money in the assets and get them back on track. And our share of it, of course, would be half of the total. So less investment for us, more going into the assets overall.

In terms of our 2013 cash flow guidance, in 2012, we looked at -- we did generate around $3 billion of total capital through -- of total cash flow through divestments. That cash flow went down to $2.5 billion being the run rate at the end of the year. We would see decline in different properties that would have reduced our cash flow down to approximately $2 billion, much of that restored through development of the liquids and then other activities and investments in Asia-Pacific. So we would see adjusted cash flow being flat at around the $2.5 billion over the course of 2013.

In terms of our balance sheet, we're aiming for a debt-to-cash-flow ratio of about 1.5. This for me is very important, to have the resilience, to be able to withstand downturns in the cycle that can always come at unexpected times. But secondly, optionality throughout this cycle, the ability to make moves on opportunities when they present themselves, the opportunity or the capability to invest additional money in larger developments when those come along. Our target, as I said, is to maintain it through the end of this year at 1.5x cash flow. We need to do $1 billion of divestments to maintain the balance sheet strength that I want to see. As I said earlier, we have a $2 billion to $3 billion overall divestment target, and that's what we're working to this year.

The excess proceeds after we've kept our balance sheet in shape would be to fund some highly attractive incremental CapEx, to do share repurchases and to hold some dry powder for good things that might come along.

As we look forward for the next 3 to 5 years, our plan calls for flat production today. I think in terms of changing the approach to business at Talisman, we've got to get very good at capital investment and investing at a level that will maintain flat production. Flat cash flow will give us the opportunity to do that. But as we look forward into the years ahead, first of all, volume growth obviously is what we all want to do in this business. It's got to be volume growth, though, that's profitable, and that will be our focus. Secondly, margin enhancement. In virtually every part of our business, I believe there is another 10% or 15% margin available on the barrels that we have, either by optimizing revenue, for example, improving liquids recovery here in North America and getting those liquids to market at more attractive prices. But also, on the cost side, reducing costs in both the field operations, in our capital programs and in corporate overhead.

Oil and liquids have been a significant part of our focus in recent months and will continue to be going forward. You can see here in North American oil and liquids primarily, but also Colombia and Asia-Pacific, how we intend to drive our production of oil and liquids up by more than 10% per annum.

In 2012, we did about 136,000 barrels a day of liquids. We did have the normal decline, and then we built that back up as we go into 2013 through investments in Eagle Ford, what we're doing at Kinabalu in Sabah of Malaysia and the HST/HSD projects in Vietnam. In 2013, we would look to be at about 140,000 to 144,000 barrels a day by the end of the year. There will be a decline and then, again, further investment in Eagle Ford, the liquids recovery project at Wild River, our drilling in Colombia and again, Kinabalu and Vietnam such that we would go into 2014 or be in 2014 at around 160,000 barrels a day. I think this is a significant move in the right direction on liquids for us in Talisman.

And just a few more slides, and then I'll turn it over to Paul Smith to talk about North America, but I did want to mention one of our most significant assets here in North America, the Marcellus. And what I've laid out in these charts is 2 different scenarios for you to consider. The one on the left is the kind of thing that I like to see, and that's sustained production at a profitable level, in this case, 400 million cubic feet a day of gas. You'll see the cash flow shown in red, the capital it takes each year to sustain that flat production, and then the free cash flow in orange.

And if we're comfortable sustaining flat production at the 400 million cubic foot level, you can see that we can grow our free cash flow and generate it in every year here, 2013, '14 and 2015.

Now this is all based on our gas price forecast. In 2013, we're looking at $3.60 NYMEX; 2014, $4; and then in 2015, going up to $5. And you can see the impact that, that has at a flat production rate of $400 million a day.

On the right is the scenario where we want -- where we will be, in 2013, stay flat. But then in 2014 and '15, we will grow to 500 million cubic feet a day based on the funding available within the Marcellus.

We can grow that business to 500 million a day without importing capital from elsewhere in Talisman. But through that period, there's really no net free cash flow. So based on the gas price, it may be appropriate to maintain that as a 400 million a day property, or it may be appropriate to ramp it up to 500 million in the stronger price environment. And of course, this is normal activity that anybody in the gas business would be looking at. I just thought it was particularly interesting in the case of Marcellus, the options that we have available to us there.

Now as I've talked a little bit this morning, I feel very strongly, the volume growth is not the only route to value creation for shareholders. If we can sustain flat production, as you saw in the previous Marcellus slide, and enhance our margins, we can increase our cash flow of every barrel. Some of the big opportunities, we've just summarized on this slide, is here in North America, an increasing focus on redirecting our cash flow into investments that produce liquids rather than dry gas. Secondly, getting better investment results. This is the whole key to the business, obviously. How can we get more production, better reserves and lower operating costs out of every investment we make. That's getting a lot of focus in our company today. Third, cost reduction and the continual high grading of assets. How can we exit properties, like some of what we're seeing in the North Sea, and redirect our efforts into assets that have better long life, better cost characteristics, better revenue, better product mix. And finally, G&A cost reduction that I've talked about this morning.

Looking to the longer-term future of Talisman, if you think about the future asset base upside that we have, on the left is shown our proved and probable resources and our job today is to maximize the value of every barrel and every MCF in those 2P reserves. Then moving on, you can see assets like Kurdistan, Papua New Guinea, our contingent reserves in North America, the prospective lands in places like Duvernay and finally the big land position that we have in Edson. And this gives you -- you can see there's a break. I need to draw your attention to the break in the vertical axis, that from slightly less than 2 billion barrels of oil equivalent all the way up to north of 11 billion, this is the size of the resource base and the things that we can work on. Our objectives here are to prove up Kurdistan and either commence production or enter into some kind of joint venture transaction with somebody else that would accelerate the development of our Kurdistan assets. Papua New Guinea, bringing that on in a series of stages. First of all, the Stanley liquids project that we're pursuing with our partners now, and that project is in progress, but also the much larger volumes of dry gas that are obviously ideally suited for an LNG project.

In the Montney and the very large contingent resource base that we have there, where it's ideally located from an LNG export point of view and big parts of that, I think, have more interest to players in that game than they would be to us in the Marcellus, which we think is located about as well as it could be to serve the North American market and relatively attractive cost structure compared to other assets in North America. This is a prime opportunity to develop in the event of strengthening in North American gas prices. And of course Duvernay and the Edson prospective assets, looking to the longer-term. So our -- this big resource base, how do we convert it to reserves and production at an attractive cost and bring on both gas and oil from this.

So to conclude, that's a long-winded overview of what we're doing at Talisman, but I wanted to give you the sense of the things we've been focused on. As we look about unlocking net asset value, our 2013 goals for the company: firstly, to increase the net back on every barrel and every Mcf that we produce; driving for higher margin production, substituting out some of the low value stuff that we have and redirecting our efforts into properties and assets and volumes that deliver higher cash flow per barrel; third, one of the biggest challenges we've had, and some of the big progress that we're making, is on astute capital allocation. Where do we direct our money? What kind of things can we invest in that will bring results more quickly. And secondly, improving the execution of our drilling programs in Eagle Ford and Montney, improving the execution of getting things onstream more quickly, getting greater value out of our capital programs. Our fourth objective is to divest $2 billion to $3 billion worth of assets, some of them in North America, many of them in the North Sea, over the next 12 to 18 months. Number 5, to unlock the value of our big positions in Kurdistan and Papua New Guinea, and then to look at reinvestment of the proceeds from all of that. Firstly, keeping our balance sheet strength, getting it better and maintaining it; looking at augmenting our 2013 and 2014 capital programs; accelerating some of the investment opportunities that we would see in our asset base; and finally, share repurchases as a clear option for us going forward.

So that's the overview that I wanted to take you through. Right now, I'd like to ask Paul Smith to join me on -- at the podium. And Paul will take you through and describe some of the more specific things that we're doing here in North America. Paul?

Paul R. Smith

Thank you, Hal. Thank you very much, everybody. I'm cognizant that I'm mic-ed up here. So for Phil Skolnick in the audience, I'll make sure that I don't mutter any obscenities under my breath today. Sorry, Phil. It's gone viral everywhere. Even my children know you now, Phil.

For those of you that don't know me, I'm Paul Smith and I look after our business in North America. And over the next what was 45 minutes, that'll be now strictly tailored to 35 minutes, I'd like to take you on a tour of our North American business with specific emphasis on the clear plans that we have for each of our assets, the progress we're making in various parts of the portfolio and how we intend to unlock shareholder value within this part of our business.

I hope at the end of this presentation to leave you with 4 key messages: Firstly, that we're positioned in some of the best plays in North America. We have material positions in 3 leading liquids-rich plays and upside exposure in 2 of the best dry gas plays in North America. Collectively, our North American business continues to provide a solid foundation for long-term growth.

Secondly, increased confidence around capital efficiency and cost control within the North American business. This year, we will execute on a $1.1 billion capital program in North America, half the level that we were investing in only 2 years ago, albeit in a very different gas price environment. Our near-term capital program is focused primarily on high-margin, short payback, liquid-rich development.

Thirdly, throughout this presentation, you'll note the continued improvement trend in key operational metrics such as drilling cycle times, completion performance and EUR enhancements. These improvements, combined with a purposeful shift to increasing liquid production, will improve cash flow margins and accelerate short-term cash flow generation.

And finally, we have a portfolio in North America with an enormous high-quality resource base. The reality is that our position's more than we can develop on our own and there is a need to rationalize the portfolio to match our capital funding capability. As such, as Hal has already said, we've commenced the process of high grading our portfolio, focusing on properties that produced little to no cash flow in the short-to-medium term. Our target is to deliver $1 billion to $1.5 billion of proceeds in the next 12 to 18 months. We will start with the dilution of our current positions in the Montney and North Duvernay. Both are large resource plays, but produce little to no cash flow in the near to medium term.

Most of you -- I'm not going to go through this map in detail because I think most of you are very familiar with our position in North America, and I don't intend to spend a lot of time going through this. But suffice it to say that we have a good mix between liquids opportunities in our portfolio, with the Eagle Ford and Edson in development, and the Duvernay in appraisal, as well as significant leverage as and when gas prices recover through our material position in both the Marcellus and the Montney. We operate a large land base, covering over 6 million acres across North America, providing us with a long-term resource base from which to continue to develop our business.

I firmly believe there's a direct correlation between health, safety and environmental performance in the underlying performance of the business. I've yet to see a great business that had poor HSE performance. Since 2010, we have reduced our recordable injury frequency rate by approximately 25% per year and had a 15% reduction in spills. The improvement in our HSE performance, in some respects, mirrors our improvement in operational performance. And I do believe that these improvements are related.

Not only are we positioned in most of the leading shale plays in North America, we've done so in a material way that allows us to feel confident about the long-term growth of the business. At the end of 2012, we've only booked 2P reserves of 5 tcfe, representing less than 15% of our net contingent resource estimate of 38 tcfe. Our 2P bookings alone represent the reserve life index of 14 years based on our 2013 production.

Our contingent resources continue to be dominated by the Montney, underpinning our belief that this is a world-class resource, well positioned for accessing premium Asian LNG markets. Also, we have a great deal of running room in the best dry gas play in North America, the Marcellus. If we chose to plateau this business at half a Bcf a day as an example, we estimate we'll be able to sustain this plateau rate for over 13 years, based on our 2P reserves alone, or over 40 years when we include our contingent resource estimate. That gives you a feel for the size and scale and running room of this great play within our portfolio.

In addition, you'll note for the first time that we've estimated prospective resources, totaling just under 10 tcfe in the rapidly emerging Duvernay play, as well as our legacy position within the multi-stacked Deep Basin in Canada. We expect a significant shift in contingent resources this year as we continue to appraise these plays. And I'll talk more about the Duvernay later on in my presentation.

And on to capital discipline. We're consistent with the corporate priority of living within our means in North America. We set ourselves a 2013 capital frame of $1.1 billion. This represents a 30% reduction on year-on-year capital spending, and a 50% reduction based on the levels that we were spending at in 2011. As mentioned in my opening remarks, we intend to aggressively pursue liquids in the short term. The portion of our total capital directed towards liquids has increased from 30% in 2011 to over 80% this year. Capital is being prioritized to the highest-quality opportunities. Over 60% will be allocated to the Eagle Ford, where we plan to double production in 2013. We will focus on the high liquids, volatile oil and retrograde windows of the play. In Canada, we will invest in our liquid rich Wild River position, which will benefit from the Deep Cut plant, which we expect to come online towards the end of this year.

Our investment in dry gas plays has been minimized. to a land retention of core acreage in the Marcellus, where we're now operating with just a single rig, and the continued development and de-risking of our Montney JV position, where the majority of the capital program is funded by our joint venture partner, Sasol.

The impact of directing the vast majority of our capital towards liquids-rich opportunities can be seen on this slide. You will note that we've set out to grow liquids by 30% per annum, primarily driven by the Eagle Ford, and to a lesser extent, Wild River, nearly doubling liquids to an expected 55 to 60 mbd by 2015. Overall, North American production growth to 2015 is almost exclusively the result of liquids growth. As a result, we'll be replacing lower-margin dry gas production with higher-margin liquids production. Given the increased liquids production, combined with an assumed modest recovery in gas prices, which Hal talked about earlier, we expect the North America business to be self-funding from next year and subsequently will become an increasingly important source of free cash flow for the wider corporation from 2015 onwards.

I'd now like to take a little bit of time to delve a little deeper into each of our major plays, starting with the Marcellus. As most of you know, in response to the challenging gas price environment, we have significantly curtailed our investment to the minimum level required to honor lease obligations and protect core acreage. This works out to be about $150 million per annum. This year, we will allow approximately 10,000 non-core acres to expire and will end the year with around 200,000 net acres in the Marcellus.

We expect to bring on only 18 net wells in 2013. As a result, base decline management and optimization are key performance drivers for us this year. Last year, we saw an average annual base decline of 31%. This year, we expect it to be lower at approximately 27%. Given this, we expect full year Marcellus production to be guiding towards 410 million and 420 million standard cubic feet a day. Our solid execution and operating track record in the Marcellus has allowed us to drive down the half-cycle breakeven costs in the play, which is now below $3 an Mcf. We have an uncompleted well inventory in the Marcellus of more than 50 wells with a half-cycle breakeven in those wells of less than $2.50 an Mcf. As a result, we're very well positioned to take advantage of a recovery in gas prices to a level of around $4 an Mcf when the Marcellus can effectively compete for capital within the Talisman portfolio.

This slide demonstrates the continued progress that we're making in a number of key dimensions in the Marcellus despite the slowdown in activity. Our drilling cycle times, measured by spud-to-rig release, have decreased from 27 days in 2010 to just 17 days in 2012. Whilst at the same time, we're drilling longer laterals which have increased from an average of 3,700 feet to over 5,000 feet. Our completions performance shows similar improvements, with completed stages per day having doubled to 4 stages a day last year. And finally, over the last 3 years, we've increased the EUR per well by over 20% to an average of around 6 Bcf today. All 3 of these operational metrics have been instrumental in positioning the Marcellus as a sub-$3 breakeven play within our portfolio.

Hal has already been through this slide, but I just want to sort of go through it once more to drive home the point. We continue to enjoy a great deal of flexibility that we've created in the Marcellus. Depending on the gas price environment, we have a number of choices ahead of us. You can see at the bottom of the slide just how sensitive moderate changes in gas prices impact the quality of the Marcellus wells, with single well IRRs more than doubling in response to $1 increase in gas price. It doesn't take a lot for the Marcellus, as I said, to be effective and compete for capital within the Talisman portfolio.

On the left-hand side of the chart, shows a world of a sustained low gas price. We're under this scenario. We'd look to sort of sustain production in the Marcellus at about 400 million cubic feet a day, spending about $200 million per annum in CapEx over the next 3 years. And as we do so, grow the average operating cash flow to about $300 million per annum, an average free cash flow of about $100 million per annum over the same period. On the right-hand side sees us returning to moderate incremental activity levels and a self-funded development profile that grows the business back to 500 million standard cubic feet a day by the end of next year. With attractive incremental returns, this scenario of self-funded growth would increase average operating cash flow to approximately $400 million per annum over the period to 2015.

And on to the Eagle Ford, where we have assembled an attractive position of approximately 75,000 net acres in the heart of the liquid-rich window of the play. To date, we've brought approximately 117 wells online, and for the last 2 years, we've been primarily drilling to hold our core liquids-rich positions and today, have over 50% of our acreage held by production. This now allows us to increasingly focus on prioritizing the development of our highest value retrograde and volatile oil acreage.

In the early years of developing the play, we've had to invest heavily into infrastructure. We now expect to see significant efficiency gains as volumes ramp up with onstream cost coming down from $36,000 a flowing barrel in 2013 to $24,000 a barrel -- per flowing barrel in the next 2 years.

We secured a total of 7 major deals with third-party service providers and no longer rely on interruptible transportation and I don't foresee us having to layer in any additional egress capacity until 2015, 2016. Last year, we completed the deal for a 50,000-barrel-a-day gross JV condensate capacity as the anchor shipper on the Double Eagle line into Corpus Christi. We expect to be 50% reserve connected to this line when it's commissioned in June this year, rising to 85% by the end of this year as we continue to build out our infrastructure. Currently, we're managing over 2,000 condensate trucks per month -- loads per month, at an average cost of $5.50 a barrel and hence, the condensate pipe connection at a tariff of around $2 a barrel will be a welcome relief on many fronts.

And of course, we're very focused on a smooth transition of operator-ship -- partial operator-ship, of our Eagle Ford to Statoil. We've had a full-time transition team working since the middle of last year and we expect to hand over our first rig to Statoil in the east, which is where they'll be operating next month.

In 2012, the Eagle Ford made a major production milestone, achieving an annualized gross rate of 30,000 barrels of oil equivalent a day gross and exited the year with momentum of approximately 40,000 barrels of oil equivalent a day of gross production. We brought over 50 uncompleted wells into 2013, and with a 7 rig base program for this year, we expect to double our annualized production to approximately 60,000 barrels a day gross, or 30,000 barrels a day net to Talisman. We expect over 60% of our total production to be liquids this year, as we prioritize our program into the volatile oil and retrograde windows of the play. Over the next 3 years, we expect to grow liquids production at over 40% per annum, culminating in just under 40 mbd of net liquids production to Talisman by 2015. As a result, we expect to see significant operating cash flow growth in the years ahead and be in a position where the play is free-cash-flow positive by 2015.

Hal referenced this slide in his opening remarks and whilst it's still early days or relatively early days in our D&C learning curve in Eagle Ford, like in many of our other plays like the Marcellus, we see tremendous progress in both our drilling cycle times and our overall D&C costs. Our acreage position is in some of the deepest parts of the basin, with an average well depth of 17,000 feet. Our measured depth is substantially higher than many of our competitors drilling in shallower, lower pressured parts of the play. We're still in the early stages of understanding the optimal well and completion design for different parts of the play. This year, we'll be piloting a number of new technologies, including ceramic proppants, sliding sleeves and alternative completion fluids to name but a few. In addition, we've completed our first 40-acre down spacing pilot in our Solera [ph] black oil block and are in the process of evaluating results and intend to complete another 4 down spacing pilots at similar 40-acre down spacing in other parts of the play, including in our retrograde and volatile oil windows.

Demonstrating repeatable and improved well productivity and top quartile D&C performance can have a large impact on cash flow. Let's start with drilling cycle time. Having achieved the cycle time of 25 days per well, we're now targeting less than 20 days per well in the next 1 to 2 years. Achieving this target would accelerate about 5,000 barrels a day of production and result in $40 million per annum of incremental net operating cash flow. In a similar story on the D&C cost front, as we move towards full pad drilling, and full pad drilling for us is 6 to 8 wells per pad which we'll really do in earnest from 2014 onwards, we expect to see D&C cost come down to a level of about $7 million or less per well. Assuming a constant capital funding program, achieving this target of $7 million a well would allow us to invest in an incremental 14 net wells, resulting in about $60 million per annum of incremental net operating cash flow, which is just an example of how continuous improvement can flow straight through to the bottom line.

I'd now like to move on to our Canadian business where we have a material business, which stretches from Fort St. John in northeast B.C. to Edson in Alberta. Here, we have a large contiguous land base providing extensive running room, which is supported by a large company-operated midstream infrastructure. One core area within our Canadian business is our legacy position in the Greater Edson area. We estimate that the liquid-rich gas inventory in this area, where we hold over 500,000 acres of land, has an unrisked resource potential of over 600 million barrels of oil equivalent. We will be able to leverage the development of these emerging plays by utilizing the extensive pipeline and processing network of 9 Talisman-owned facilities and over 1,000 kilometers of pipeline we operate in the area.

This year, we're executing on the Wild River project to deliver wet gas volumes to a midstream Deep Cut processing plant expected to be onstream by the end of this year. The facility will allow us to increase propane and ethane liquids recovery from the 10 barrels a million cubic feet today through our current refridge [ph] facilities in the area, to over 70 barrels a million cubic feet with a large associated value uplift in today's oil price environment. The ethane stream has been sold under an attractive long-term supply agreement with Dow Chemicals.

In addition, we'll commence a drilling program into the Woolridge [ph] by the middle of this year. Our initial development area has already been largely derisked by our competitors, giving us confidence in the attractive economics associated with this liquids-rich play. The production from this play will flow directly into our Edson facility and its associated refridge [ph] facility able to extract about 40 barrels per million cubic feet of liquids. We continue to build a well inventory for execution into other parts of the basin commencing in 2014. And we intend to make room for potential incremental development activity in this area by continuing to high grade our portfolio around the greater Edson area.

Moving on to the Montney, a play which represents one of the most material and strategic resource positions within our portfolio, and as we all know, is well positioned for accessing premium Asian LNG markets. The primary focus to date has been the early development of our JV position in Farrell Creek and Cypress A. Our partner, Sasol, continues to fund the majority of the build-out until the remaining $1 billion of carry is exhausted. We have slowed down expenditure in the current environment to a 3-week program, allowing us to continue to deepen our understanding of the play, reduce our D&C costs and optimize the ultimate field development plan. This year, we will focus on the liquids-rich eastern portion of Farrell Creek and recommend appraisal activity of the large Cypress A area where we already have 5 highly successful appraisal wells drilled to date. The remaining 2/3 of the contingent resource is split between the Greater Cypress asset to the northwest, the shallower and more liquids-rich part of the fairway, and the shallow-operated Greater Groundbirch asset to the southeast, where activity is ramping up.

Our Montney position provides an enormous amount of flexibility to be able to ramp up at the appropriate time and access a range of gas monetization options, including LNG. With over 50 million tons per annum of LNG plans annexed to date for the West Coast requiring more than 6 Bcf a day of gas supply, we believe our Montney position will be more valuable to those with the ability to access premium Asian markets. As such, as Hal said, we've commenced a process with the intent to further dilute one or more of our parts of our Montney position.

And I don't want to skip over the improvements that are being made in the Montney where demonstrating repeatable operational improvements is paramount to unlocking the long-term value of the Montney. Well, we've made great progress in the last 12 months. Our drilling cycle times have halved over the last 2 years and we're now drilling wells of cycle times of less than 30 days. Our next largest competitor in this part of the Montney play has an average cycle time of 50 days. Similarly, we've made large improvements in our total D&C costs. We expect to be able to drill and compete wells in 2013 for less than $9 million a well.

Moving to the Duvernay, where I know all of you have been impatient with the lack of results that we've been willing to share with you. We will change that today. Moving first of all to the -- well, the Duvernay for us is a, as all of you know, a rapidly emerging liquids-rich play in Alberta where we're extremely well positioned with a material position of 350,000 net acres. Most of the industry activity in the Duvernay has been focused in the northern part of the play. There are over 100 wells drilled to date with encouraging results. We hold approximately 159,000 acres of land in the northern part of this play, the Kaybob area, with an estimated petroleum initially in place of 2.7 billion barrels of oil equivalent and a prospective resource of 800 million barrels of oil equivalent. Our land base here, as Hal has already said, is bordered by Exxon through their acquisition of Celtic, Chevron and Encana and is in close proximity to a very large amount of legacy Talisman infrastructure.

As many of you know, publicly available condensate data could be misleading, with only trucked condensate being reported. This means that those of us who had spiked their condensate into wet gas sell streams for downstream processing would appear to be on the surface to have dry gas wells. This is not the case for the 3 wells we've drilled to date in the north. Each pilot well was completed with an average of only 6 stages per well, much shorter well as we're in pilot phase, and the 3 pilot wells resulted in an average IP30 of 3.2 million standard cubic feet a day of gas and 60 barrels a day of high-quality field condensate. In addition, we would expect to see on average, an additional 290 barrels of per day of NGLs from each of our 3 pilot wells processed through a Deep Cut facility. Put another way, we estimate that an optimized development well in our pilot area drilled with a 5,000-foot lateral and completed with 12 stages will result in a well with approximately 6.5 million standard cubic feet a day of gas and 700 barrels a day of condensate and NGLs. However, as part of our efforts to focus the North American portfolio in the near term, we intend to commence a process to dilute our North Duvernay position, preferably through an outright sale and focus our efforts going forward in the southern part of the play.

So as many of you know, our focus over the last 6 to 9 months has been to start appraisal activities in the relatively under-explored and under-appraised Southern Duvernay near Williston Green. We hold, as a company, the largest single position in this part of the play with 189,000 net acres of land, positioned in what we now firmly believe to be the richest portion of the condensate and volatile oil windows. We've estimated that we have 2.7 billion barrels of oil equivalent of petroleum initially in place. Using recovery factors similar to those experienced in the analogous Eagle Ford for each of the phase windows, we've estimated a prospective resource in this area for us of 600 million barrels of oil equivalent. We have now drilled 3 and completed 2 wells. We're excited by the initial results from both of our wells, and indeed, from our competitor wells. Our first well, the 11-03 well, which you can see in the southern end of the yellow acreage on the map here, mapped on to the fringe of the volatile to black oil transition window and was completed with a relatively short lateral of only 3,500 feet, with only 5 effective stages completed. However, the well came on strong with an IP30 of over 300 barrels a day of condensate of 50 API oil at a yield of just over 1,000 barrels per Mcf.

Our second well, the 02-60 well, which is slightly to the northwest of the first well, was -- has only been tested in the last few weeks. Again, with a relatively short lateral of 3,500 feet and only 7 stages completed. The IP7s for the first week of flow test data produced at the gas rate of 1.1 million standard cubic feet a day with a condensate yield of 110 barrels per million standard cubic feet a day. The well will be shut in for the next few weeks to soak, a method utilized to great effect on our first well, allowing the relative permeabilities to settle down. We'll bring the well back online in Q2 following the construction of a third-party pipeline that will allow the well to flow to cells.

We're currently drilling our fourth well in the play and expect to bring in additional 2 to 3 wells onstream this year. We are excited about the potential of our position in this play and we're learning a lot from each well we drill and complete and are developing plans for phased early development scheme commencing next year.

So I'd like to finish by reiterating our competitive advantage in our major plays in North America. I'll then summarize the key near term value drivers that I believe will drive increased value returns for our shareholders.

In the Marcellus, we have a high-quality land position with extensive running room in what is, without a doubt, the best dry gas play in North America. We have a proven track record of operational excellence and today have a business that is flexible and can deliver self-funded growth.

In the Eagle Ford, we're well positioned in the liquids window and are focused on continuing to improve our execution performance in the play and drive material near-term liquids and cash flow growth. In our Greater Edson area, we're well placed to capitalize on a material, again, liquid-rich resource base and intent to pick up the pace of our activity in this area in 2014.

In the Montney, we have a world-scale resource, which is well positioned for accessing premium Asian LNG markets. And an operational track record that is continuously bringing us down the supply cost curve. It is simply too big an asset to develop for a company our size, and hence we've made the decision to look to further reduce our exposure to this play.

And finally in the Duvernay, we have an extensive 350,000-acre position and are very well positioned in the liquids-rich window of this rapidly emerging Eagle Ford-like play. We will focus our efforts in the south and look to exit or JV our position in the north.

Let me conclude by leaving you with 4 near-term value drivers for our business in North America. Firstly, we will double our Eagle Ford production in 2013 and bring the Wild River Deep Cut plant online by the end of this year. Our liquids volumes will increase unit margins and drive near-term cash flow growth. In addition, we have a great gas price -- we have great gas-price optionality through our low-cost position in the Marcellus.

Secondly, we have significantly curtailed capital expenditure in North America, which this year at $1.1 billion, will be half of what we were spending only 2 years ago, with over 80% being directed towards liquids-rich opportunities. The combined effect will be an North American business that turns free-cash-flow positive next year.

Thirdly, we must continue our operational excellence journey progressing on both the execution and cost-efficiency front in every play we operate. Despite the fact that overall volumes in North America will be coming down this year, we will be targeting cost reductions across the business to maintain flat unit operating costs of around $8.50 a boe. And as Hal has said, we started this journey last month by restructuring our Canadian business, resulting in a 20% reduction in our non-field head count in that part of our business. And finally, we will take firm steps to reduce our North American footprint to deliver $1 billion to $1.5 billion of proceeds in the next 12 to 18 months, commencing with the North Duvernay and Montney large resource plays that produce little cash flow in the near to medium term.

Ladies and gentlemen, thank you very much for your time. I'll briefly hand you back to Hal before you go into a very well deserved break.

Harold N. Kvisle

Thank you, Paul. So just to summarize quickly before we go to the break, over the past 6 months, we've been reviewing our assets in a lot of detail. I'm very interested in what the detailed upside and potential of every asset that we've got in Talisman. We spent a lot of time examining those assets, also though, at the same time, considering our strategic options for how we want to move this company forward. Out of that work, we have committed ourselves to 2 core regions, the Americas and Asia-Pacific, that will be the theaters of operation for Talisman in the years ahead. We've looked and we've identified opportunities to divest or joint venture, further assets in the U.K., in Norway and look at the development plan either independently or through joint ventures in Kurdistan and Papua New Guinea. Outside of our cores, we have a group of excellent, non-core, non-operated assets that generate strong cash flow and upside and take very little of our time and attention. These assets are all operated by good partners that we have good relationships and confidence in.

Paul has talked about the enormity of our North American gas resource base. Today, we're very focused on liquids opportunities, whether it be in the Eagle Ford or in the emerging Duvernay plays. And interestingly, he mentioned the down spacing opportunities in the Eagle Ford. The thickness of these sections is so impressive, and the down spacing to a 40-acre spacing, things we never would've thought possible in earlier years. These are the reality of the opportunity today in places like Eagle Ford and in the future, in South Duvernay, where we have a very large position and huge amounts of liquids in place.

We're looking at joint ventures or divestment opportunities in the Montney and the North Duvernay, and we're always on top of the optionality of our gas positions in the Marcellus and the Edson areas in the event of improvement in North American prices. After the break, we'll have Paul Warwick, a very experienced man who's joined us, operates out of Aberdeen and runs our North Sea business. Paul has recently taken on operational responsibility for Colombia and Kurdistan. He'll give us an update on what's going on in the North Sea. Paul Blakeley, a longtime Talisman executive, currently in Singapore, will speak about our track record and our plans going forward in Asia-Pacific. Richard Herbert, who heads our global exploration and development programs, will speak about Colombia and Kurdistan and the huge oil upside that's there and the appraisal programs that are currently underway, and then I'll wrap up. So if we could take about 15 minutes for break. Thanks for your attention so far, and we'll start again in 15 minutes. Thank you.


Harold N. Kvisle

I'd like to introduce Paul Warwick who joined us, I think almost a year ago -- not quite a year ago, after a long career with ConocoPhillips. Paul is a man with great experience in the North Sea and other parts of the world as well, but particularly, of interest to us in the North Sea. He is currently running our operations in the North Sea, responsible for Norway, our interest in the U.K. joint venture and, as well, now our operations in Colombia and our appraisal activities in Kurdistan, where he works closely with Richard Herbert on evaluating where we go from here.

So without further ado, I'd like to turn it over to Paul, and he'll take us through the current status of activities in the North Sea. Paul?

Paul C. Warwick

Thank you, Hal. Good morning, everybody. What I wanted to do was give you a quick run through from the North -- or concerning the North Sea. This slide is a highly simplified view of our North Sea business. And I like to look at operations in the context of making them simplified.

And Hal mentioned that I've been with the company almost a year. In fact, my first exposure to the company was at this event last year. And part of my observation in the North Sea was that it was a very complicated business, it's a very multifaceted business. That's not gone away. But I think our level of understanding that we need and the approach we need to be able to solve the problems, needs to be done from a perspective of simplicity?

And a bit like Paul Smith was saying, how do we get to that simple future that we want, is that we become efficient, we become reliable, we become good at what we do, and we do things in an economic sense. So there's not any great secret in how you run a business like that, but noticing it is not necessarily going to get you to the end point you want to be in.

So where are we? The U.K, Hal spoke about selling half of the business, 49% of the business to Sinopec, 200 million barrels of reserves. That was I think a very good deal. It's good for Talisman, it was good for Sinopec, it's good for the assets. And the arrangement with Sinopec, I think, is going very well. The people we work with are a pleasure to work with. They're very keen on the business, and the joint venture is taking shape really well. And working within the JV is slightly different than working within a direct operated business. And along with Sinopec, we're learning how to do that. But I'm quite optimistic at the moment how that's going.

And in Norway, the slightest [ph] optimizing value through near-term opportunities. It's a relatively small base in Norway, 40 million barrels of reserves. But we do have opportunities there within the hub areas that we currently operate in, at Gyda and at Varg. And we do have a certainly particularly reasonable size group of for tax synergies, which means that there are opportunities in Norway to lead with those tax synergies in production -- other people's production, if we can get that.

But the real aspects of the North Sea that I hope I can demonstrate to you today is that we are concentrating on delivering value. And why is that, perhaps a strange thing to say. Well, recently, the North Sea has under-delivered. I think you all are very well aware of that. North Sea is being challenged, it's been a problem and it’s -- in recent years, there've been many things that some have been explicable, some we have been inexplicable, some which we have done to ourselves, some which are environmental related to the North Sea. And I think it's in understanding the issues that we've had within the North Sea that enables us to be able to articulate and then deliver what the future should be like for that business.

And there are a number of things on here, which I would refer to. Hal has spoken about limited investment. That's resulted in asset reliability problems. We've had issues with reservoir performance in some of our Norwegian assets. And, of course, we've had the Yme projects, which is -- had a lot of noise around it over the last year or so. And it never seems that you can pick up from any form of industry journal or electronic media without seeing something about Yme.

So I'm not going to concentrate on Yme today, but just to put it into the context, we did demand the platform last year for very good reasons. We have still not manned, there's no technical basis to do so, although we're working through that with the authorities and with our partners and with the contractor, SBM. And we're looking for how we can reach a technical solution, we're looking to how we can reach a commercial solution.

At the quarterly call, I spoke about that we were speaking to SBM about potential deal. I'm somewhat some constrained to talk about that because of confidentiality agreements, for those conversations are ongoing. I would like to have a result there, but there's nothing which I can say today that would say there is going to be result, which is imminent, but working seriously with that.

In parallel, we're pursuing arbitration against SBM, it's the Yme partnership, and the papers for arbitration have been put in place, and that activity is taking shape. Now it's going to take several years for any arbitration activity to come to fruition. And so we're working these parallel paths to try and find a suitable outcome for Yme. But it's most unlikely that the current project will continue as a project and end up delivering in its current form.

Let me go to the strategy, which we're pursuing now. Let me say, again, noticing the issues of the North Sea is good, and it enables us to say well, we need to be doing something about it. But in itself doesn't confer anything on us other than the, I would say, mature recognition that we have to do something different.

There are no quick fixes for the problems, which we have. We started our process to improve the North Sea business. The Sinopec deal was part of that in terms of reducing the volatility to the business. But when it comes to the physical activities, this is a multiyear activity to be able to get this business to be producing in a reliable way. And so we're putting huge amounts of effort, intellectual effort and some capital and operating cost effort in this year, and that will get us someway on the journey. That journey's started, and we're focused on it, and we want to deliver it. But it is not a straightforward activity.

In some areas that we're going to work, and I'll talk a bit about it in a reasonable degree of detail, we have to improve in the areas of projects. We have to improve in the area of drilling infill wells, some of the bread-and-butter things that we do within our business. And we have to be good at making the choices for base investment properly. We also need to make sure that within this context, that whatever the future is going to be like, that we rationalize our portfolio and make sure that the lower end of the portfolio has been churned, and that we're bringing assets into the business, because that's the healthy basis, keeping the business like our North Sea, but -- U.K. and Norway in a healthy and successful future.

There is opportunity for the production base within the North Sea to grow. In 2013 and '14, that growth, the fuzzy edges on here, but that is going to be moderate, it's not going to be particularly ambitious. But we are going to see an increased cost from an operating cost point of view. Let me tell you, there is no immediate -- we are going to reduce operating costs in this business available to us. One of the problems that we had, which has led us to the situation we have with the North Sea business is that we reduced operating cost too much, and therefore, didn't make the investments that we needed to do. So putting that right is going to cost money, but once we get things fixed, then we have an adage for -- that we picked up in the U.K., which is we will fix forever. Rather than forever fixing, this business will become much more reliable and much more predictable.

But to make this business work, we do need to do the right things right, and we will then be able to be delivering a reliable production business. Now can we do this? It's a reasonable question that you should ask. And I think in our North Sea business, I think very impressed with this particular example, which is at the Gyda field in Norway. And Gyda is sort of getting on for 20 years old facility. It's towards the end of its life, and it has all of the challenges of an old asset; declining production, high cost per barrel, some safety performance issues.

And this slide illustrates what has been done at Gyda in terms of the McKinsey company to this North Sea benchmarking exercise that compares all of the operators who contribute to it. Not everybody does, but most companies do and using the McKinsey data to be able to say, where does Gyda fit. And so what we've been able to do in a very focused and successful way is take Gyda from being towards the bottom end of the path at the end of 2009 to the time 2008.

In 2011 and now, being in position when -- where there is no gap between the Gyda operation and the top quartile. And the Gyda production is very small, so some -- McKinsey normalized some of this information. But being able to have an asset like Gyda in the top quartile of North Sea operations, I think demonstrates that we can do that across other areas of our business. So the question, well, can you do this? Can you put this right? I think Gyda is a good example of that.

Let me move to the next slide in terms of operating efficiency. I think this is really quite interesting in demonstrating what we do within Norway, which is Gyda and Varg predominantly and the operating efficiency that we've seen within our U.K. assets and the prize that's available for us by actually getting after this business and doing the right things.

And there are a number of things, which I've listed there of what we can do and the benefits that we get. Unfortunately, there's no linear relationships that I can find, which says if you spend this amount of money, you'll get this improvement with an operating efficiency. It's -- to me, and I think Hal spoke earlier about the culture within the company and the culture of do it in the way of operating efficiency, safer, faster, cheaper type approach. It's a way of being. It's a culture, the operators and operations have to have to be successful.

And one of the drivers, which I think -- and we have this in places in our North Sea business. One of the drivers to improve operating efficiency is to create an environment where people live within that world of high operating efficiency. The Gyda example shows that you can create that, and our intent is to deliver that across our business.

Now in the last year, we've also announced that we'll be doing what we call the Mar or the MonArb project, which is a large capital investment. And part of the history, of course, I mentioned Yme, is capital excellence or capital efficiency within the North Sea across the U.K. and Norway. And the question, I think, one should be asking is, well, again, can you do this? Given your recent performance, can you spend this money wisely? And I think Mar is a good example of where we have learnt from our lessons.

We're still learning from some of them and doing things and putting things in place to be successful, but is actually applying best techniques in the industry to be able to do a large capital project and building the capacity within our organization to be able to make that happen. So things which are relatively simple to observe like a stage gate process, we've implemented that for Mar, providing functional assurance that the project is actually doing what it says it’s going to do, we've implemented for Mar.

And part of the way that you get the good capital excellence is to have people who know what they're doing. We've recruited very good people from across the industry for doing this. And then, one of the other ingredients is an intense management overview to ensure that at every stage, the project is working properly, and the capital is being well spent. And those are the activities that we've been pursuing at Mar.

Now we have a few opportunities in our U.K. business, and some which we're generating within Norway that have some similar context to this. Extending field life, bringing in new fields, that then mean that we can push the abandonment of the assets back. It's creating really quite substantial value within an area that if we operate properly, we can actually -- as Hal showed in one of his earlier slides, really give very good cash flow because of the position we hold within those operating regimes.

Another simple area is the drilling program doing the infill wells. And again, it's not difficult to observe but if you don't drill the infill wells, well, you have a 12% decline, which is being, if you look at the chart from 2008 through to '10, really, you end up with production which declines at 12%, possibly more in some areas. And so creating an approach where we have high-quality investment opportunities that we can then deliver from an infill point of view across the portfolio in the U.K. and Norway is important.

And so over the last month, we've been up to identifying these opportunities in a number of areas in the U.K., Fulmar, Clyde and Claymore, Blane, et cetera. And in Norway, it's -- some partner operate -- partner operates the areas like Brage and Veslefrikk. Let's say, yes, we actually do have a portfolio of infill wells that we can deliver. And if you think that the earlier slide with the production increases, which actually enable us along with operating efficiency increases to be able to deliver additional production.

As I started off with not particularly sort of great science to observe these things, but if one does the work properly then you can get the prize and within the assets that we have, if we're not operating in this as well as we should be, you're sitting on a gold mine and our intent, our process, our activity today is to be operating these assets in a better way than we have done previously. And we're seeing some of the benefits of that already. But as I say, it doesn't happen overnight, and there's no quick fix.

So in summary, I've spoken about most of these issues. We're working across a wide front in our North Sea business to get improvements within the business. We're focused on it, notwithstanding the strategic issues that Hal's spoken about affecting this business. It doesn't divert our attention from making sure that these businesses work. And our view is that whatever the outcome is, whether it's to invest, to JV or to divest, operating these businesses properly works in all of those potential outcomes. And it's my intent that over this reasonable period, and I can't promise that by the 16th of March next year or whenever, it's all going to be solved, but over a reasonable period, we will focus on all of these areas and move up the curve where we want to be to improve the business. And it's -- that we have a team of people also, both in the U.K. and Norway, who are focused upon doing this, who understand the realities of what it takes to operate these businesses. So hopefully, I will have a chance to talk to you next year and talk about progress that we've made. But there's a lot to do, plenty of work, but our journey has started, and we're well on our way.

Now in a more successful part of our business, I will be handing over to Paul Blakeley, who will be talking about Southeast Asia, which I find quite exciting myself, given that I used to work there in one of my previous evolutions. Paul?

A. Paul Blakeley

Thanks, Paul. Good morning, ladies and gentlemen. So it's good to be here to share details of Talisman's business, and I'm going to spend 30 minutes or so just talking about Asia Pacific.

To set context, I'll try to give you a sense of how the markets in Asia are expanding and creating value for upstream investment through both product price upside, as well as through access to incremental opportunity. I'll lay out some details of our portfolio and how we've continued to improve our performance even while we grow, increasing both margins and cash flow.

And finally, I'd like to outline what I think is Talisman's competitive advantage in the region and some of the things that perhaps differentiate us from that many of the other players. But to begin with, if there are just 3 key messages about our Asia business that I'd like you to take away, these are the ones: The first is about the Asia economy. We see the economic growth continuing to expand faster in Asia than anywhere else in the world and the demand for energy running at an extraordinary pace. This has encouraged governments in the region to develop fiscal pricing and investment conditions that incentivize the upstream sector in the development of domestic resources to meet the growth.

IHS CERA and Herold, through their annual upstream performance review, reconfirm this competitive positioning, commenting that Asia Pacific year-over-year continues to deliver the best returns in income per BOE when compared with all other regions around the world.

The second thing is about Talisman's portfolio. As a company, Talisman is well positioned among its peers to capture and deliver value in Asia through a set of core assets and an extensive acreage position with both running room and identified upside.

We've demonstrated our operating capability and have become a partner of choice with many NOCs and other key regional players. Our size, our Canadian flag, our cooperative partnering style, together with long-standing relationships have allowed access opportunities not widely available.

And the third thing is about our track record. Talisman, over the years, and it does take years, just as Paul has highlighted in the North Sea, has built strong operating teams in each country, where we're active with a blend of global and local skills that are now delivering great performance. Operational excellence, good capital discipline and project delivery have all contributed to the reliable 8% running growth in production and the increasing free cash flow that -- growing with it and is being returned to the corporation.

To put a little bit more context to this, the in-country teams work from an operating model where each element of the production system is monitored and losses are recorded. Equipment downtime is minimized through risk analysis investigation and remedial actions. People skills are assessed, and we use the leadership development model to strengthen capabilities and teamwork, and we have extensive competency schemes in place as well. The outcomes are facilities with improved reliability and the workforce that's delivering higher performance.

A good example is at PM-3 where we have now achieved over 97% up time. We also record and work hard to improve safety outcomes. And I argue, as Paul Smith did earlier, that these go hand-in-hand. So higher uptime and fewer incidents equals more production and lower cost. And this will contribute to the bottom line.

The asset portfolio that underlies this is focused around 4 core areas in Asia. In the Malay Basin, centered on PM-3 and recently bolstered by new adjacent acreage, in South Sumatra, where Corridor and Jambi Merang are located. Offshore Sabah, with the newly acquired Kinabalu field, which anchors great near-term exploration opportunity. And finally, onshore Papua New Guinea, where our position contains large gas potential and with early production and cash flow from liquids developments at Stanley and potentially Elevala and Ketu.

In addition, we have one longer-term exploration play in Vietnam, which holds great promise. And the small number of free cash-flow-generating assets resulting from successful exploration, but with no broader potential right now. And I'll provide a little more detail in all of these and the key attributes over the next few minutes.

But first, I wanted to the layout a more detail rationale for Asia in our portfolio. The simple conclusion is that Asia is the global economic powerhouse today. It's definitely open for business as we see it, and among other things is offering great opportunity in upstream investment. World Bank data shows that Asia GDP growth was in the 6% to 10% range over the last 10 years and is likely to continue in the future at around 5% to 7% per annum.

To give some context, average Asian GDP is currently only $2,000 per capita compared to $20,000 to $30,000 in specific developed economies like Taiwan and Korea and increasing to $50,000 to $60,000 per capita here in North America. So with a rising affluence among a growing middle class and with such significant headroom for growth, coupled with the underlying population growth, industrialization, urbanization, there is a strong basis for economic development in Asia continuing to drive global growth going forward.

You only have to travel to any one of dozens of major cities in Asia to see and feel this for yourself. In some respect, it's even part of the answer to the gas surplus in North America, and Paul touched on this earlier with West Coast LNG here in Canada and export from the U.S. Gulf all targeting Asian markets.

Under this backdrop, local energy suppliers across Asia can't keep up with the demand growth. Both IHS CERA and Wood Mac project that the growing supply-demand gap for gas is likely to exceed 25 Bcf a day in the Asia-Pacific region as a whole by 2025 or around 9 Bcf a day in the 4 main domestic markets in Southeast Asia, where Talisman is active.

In order to meet this growing energy demand, the inevitable outcome will be for an increasing reliance on expensive imports, the bulk of which will likely be LNG. And to counter this, we're witnessing more incentivization for the development of the remaining domestic resource with wider net economic benefit that it brings, but we're also seeing significant upward pressures on domestic gas prices. And this is manifesting itself even as we speak.

So with all this in mind, and you want us to look briefly, country by country, in the key areas where we're active and start at Malaysia. Here, PETRONAS' regulator are pushing for increased investment domestically. They're offering up many new offshore licenses for exploration and are being flexible in the fiscal terms on offer and through infrastructure expansion, supporting the rapid development of discoveries. The net impact has resulted in 24 discoveries last year in Malaysia, up from 6 the year before. In fact, to my recollection, I've never seen the environment in Malaysia busier than it is in the past 12 months.

However, all these activities only delays LNG imports slated to start later this year. Though where domestic gas discoveries are successful, this will just result in substitution of import volumes which can then be diverted. Early integration of LNG imports into the domestic market, however, has already forced the government of Malaysia to establish a formal plan for gas price reform, and we see this as the political solution in defending a new and higher domestic pricing environment. If LNG imports are a catalyst for price reform, it's interesting that this, in turn, will encourage more domestic exploration activity and provide new business opportunity for well-positioned companies like Talisman.

Much the same-store is evident in Indonesia, where more critical energy shortage has resulted in regasification's facilities already in place and operating. With early diverted cargoes, entering the domestic market at over $14 per million BTU. The days of low-cost subsidized domestic supply in Indonesia are over. And throughout 2012, we are seen sweeping gas price renegotiations for domestic contracts as prices move up to meet the cost of imported gas.

And finally, the same sort of trend in Vietnam is playing out as subsidies unwind and new sources of domestic gas are developed from even more expensive offshore locations. Vietnam, once a highly controlled price environment, is calling for more energy and the latest contract price negotiations for new supply are signaling significant increases from the past. From our -- up from around $3 per million BTUs to $6 to $8 per million BTU and higher today. Talisman already benefits from this new price range in Vietnam and is increasingly moving as it increasingly moves to a level that's consistent with broader Asia price setting.

So widening this theme across all Asia-Pacific, you can see the significant supply challenge emerging. At least 3 quarters of the supply gap is likely to be filled by LNG, and as result, most commentators anticipate LNG demand in Asia to rise at about 5% per annum going forward. This is not just to satisfy the traditional markets of Japan, Korea and Taiwan, but also new entrants like China, Thailand, Singapore, Malaysia and Indonesia. However, despite this huge increase, there's also a view prevailing that we will see softening LNG prices over the longer term, thanks to significant greenfield LNG supply coming onto market in the next 5 to 10 years and balancing -- at least balancing, the increasing demand.

Now one perspective to this, and I noted a recent Goldman Sachs paper supporting this, suggests that new LNG, though in large supply, is going to be very expensive and that current prices, which may soften briefly in the 2017 to '20 timeframe will easily return to current levels in the longer run.

To put this in context, the cost environment for LNG projects has dramatically shifted upwards, and per unit liquefaction build costs have risen by a factor of 2 or 3x over the last decade. Other complexities and challenges as well as project resource shortage such as you're seeing in Australia today have reduced confidence in LNG project delivery. This is reinforced by recent performance, where 7 of the last 10 sanctioned LNG projects are now running at a combined projected $46 billion of capital overruns and are up to 2 years delayed. Goldman's report is generally more pessimistic on final breakeven costs than we show here, and it just reinforces the headroom available for domestic product pricing going forward.

Across a broad range of future LNG pricing, we conclude that though likely to be the primary source of new supply to Asia, LNG will not result in significant price break down and certainly not provide any competition to much cheaper domestic gas supply. This means that the headroom for domestic gas pricing will remain or even increase in our view into the $10 to $12 per million BTU range, providing very healthy returns in investment going forward. And since this is at the heart of Talisman's Asia strategy, we continue to say that gas in Asia is good.

And this sets the context now for our Asia portfolio today, where we see investment plans as we look into 2013 and beyond, and also, why we're very happy to chase gas in the region, of course, we do like to find oil as well if we can. We've increased capital expenditure by $150 million this year versus last year. And we focused on activity that'll result in production and cash flow in the near term.

The exploration spend is targeting low to medium risk prospects, and where possible, located close to infrastructure for early tieback. This includes the Malay Basin, Sabah and South Sumatra, for example. And our development spend will bring Hai Su Trang and Hai Su Den, 2 fields in Vietnam, to first production this year. We'll expand to Jambi Merang and add more capacity at PM-3, Corridor and Kinabalu. We'll also move to early production of liquids in Papa New Guinea.

So just to give a little color to this, I'm turning first to South Sumatra. This is a low-cost onshore operating environment, where we enjoyed premium pricing from oil linked contracts, delivering high netbacks and value to Talisman. It's also an area of extensive existing infrastructure with pipeline egress to the Caltex Duri steam flood project in the north, to Singapore and Batam in the Northwest and to the high-growth markets around Jakarta in Java to the south.

Our knowledge here gives us a deep understanding of the gas markets, as well as strong relationships with the buyer groups, and we look to take full advantage of this with future investments. As an example, all last year, we have been diverting a significant proportion of Jambi Merang gas to Caltex Duri at premium prices, an opportunity not envisaged when we acquired the license a couple of years ago.

The key asset in South Sumatra is, of course, Corridor. And as our largest producer with gross gas sales running at around 1 Bcf a day, it remains at the heart of our business. Facility upgrades in various parts of the license at Dayung, Sumpal, Letang Tengah Rawa and Suban are all nearing completion, and at various times during 2013 will come onstream. These activities underpin the existing sales profiles, as well as deliver modest growth in the midterm. We'll also boost production potential by adding 2 new Suban wells later this year, in addition to current drilling at the Sumpal field, where the latest well is just coming onstream and tested at 150 million cubic feet a day. I can also confirm that the first 2 steps in the PGN gas price renegotiation have been agreed, signed and are already being implemented with further price steps undergoing final approvals.

And now to the Malay Basin, where we operate the PM-3 commercial arrangement area between Malaysia and Vietnam. We built a level of operating expertise and capability here, which has resulted in uptime performance reaching top quartile as I've already discussed. Our reliable and consistent delivery has earned us a great reputation, and we no doubt benefited from this during the relicensing process that led to the award the Kinabalu.

At PM-3, our focus in the short-term is on sustaining production through investment into facilities and wells and in negotiating a license extension beyond the current 2017, '18 timeframe. This is vital to ensure ongoing investment, and we're in early negotiation in order to facilitate this.

Most recently, we farmed into 2 adjacent exploration licenses, which leverages our existing knowledge of the subsurface around PM-3, and we anticipate drilling exploration wells here later in the year. PM-3 CAA continues to provide a stable base of flat production and a reliable stream of free cash flow. Over the past 2 years, we've identified further subsurface potential of PM-3 by drilling successful flank wells around the main fields. As a result, we've added capital production and incremental free cash flow from this asset into our plans going forward. The PSC regime makes this type of investment highly profitable, and we see lots of running room here.

We're still pursuing IOR projects as well, the target up to 75 million barrels of oil within the existing fields and gas production is also growing as we de-bottleneck facilities to increase throughputs in response to the growing demand from Peninsular Malaysia. Pricing is already strong, with liquids selling at $4 premium to Brent and gas last year averaging $8.15 per million BTUs with netbacks close to $5.

Extending the PM-3 CAA play into adjacent acreage is a logical expansion of our Malay Basin business. The teams in KL have access to unique seismic data set that gives us an advantage over other regional players, and we've already started exploiting the new stratigraphic play type identified in PM-3 and which has resulted in several successes to date.

A number of locations with clusters of prospects and leads are being worked, and we've mapped the subsurface play extending into Blocks 46/07 and 45 in Vietnam, where we now hold a 35% equity interest and will take over operator-ship in the future, as well as in Block 46/02, which has a number of small discoveries and our own producing Song Doc field. Three wells are planed this year. And though it's still very early, we're quite encouraged by the potential.

Offshore Sabah is now emerging as our newest core area in the Asia portfolio. We originally acquired interest in the 2 explorational licenses, Blocks SP-309 and 310, where there are a number of adjacent discoveries in fields in production and on trend. Prospects are generally located in low-cost, shallow water in this very prolific and proven hydrocarbon basin, which is prone to oil as well as gas. It also leverage our skills and experience at PM-3. We've now completed 3 large 3D seismic surveys, and they're extremely encouraged by the results, illuminating a number of different play types. Two wells are being planned for this year with further wells in 2014.

Early focus will be on an oil prospect close to Kinabalu, which could be a tieback candidate for quick development and early cash flow. And now to Kinabalu. We are delighted to have added this to the portfolio late last year, and it complements our Sabah position perfectly. We see this asset as having significant growth potential, contributing cash flow from day 1. We've transferred a number of key operation staff from PM-3 and deployed their skills for immediate effect, blended with some high-quality recruits from the previous Kinabalu operator.

Our investment plans are already in motion, and this year, we'll perform a number of well re-entries and look to drill 2 new wells to increase production. Significant facilities upgrades are also anticipated over the medium-term, and we've identified cost-saving synergies by working closely with the adjacent operator, Charre Garli [ph]. There's much to do and a lot to be excited about, and it all plays to Talisman's strength.

And now moving to PNG, where we continue to work on aggregation of large volumes of gas for LNG. This is an extensive onshore play in a proven and prolific hydrocarbon basin with potential to create significant value into premium markets. We embarked on 3 strategic steps last year. The first, was the farm down to Mitsubishi, providing significant short-term funding, which underpins our current activities, that well also bringing significant expertise in LNG.

Second, learning from our early activity, we've restructured our operations and are now delivering predictable and reliable outcomes in what is a pretty challenging environment.

And third, we've identified that the liquids-rich northern licenses can deliver early production and cash flow. The Stanley field has now been sanctioned and awaits government approval, and we're confident that 2 more developments at Elevala and Ketu will follow close behind. Together, they have the potential to generate a net $100 million in cash flow per annum midterm and this further underpins our drive to deliver significant value from P&G.

Associated with the early liquids project, there's also growing interest in gas sales for power in the western province. Talisman and its partners are in negotiations with a number of potential buyers for the provision of gas to replace diesel for power generation in a number of local mine projects. In combination with the liquids schemes, this can yield up to $0.5 billion of MPV in addition to the longer-term gas aggregation project, which is progressing as planned.

In Vietnam, the Hai Su Trang and Hai Su Den developments in Block 15-02 in the Cuu Long Basin remain on schedule and under budget. The project currently has about 800 contractors working on final fabrication and commissioning of the 2 topside structures, one of which is shown here, which will be installed early in the second quarter. The rig is drilling and completing the development wells, and all subsea pipeline work is finished. This project, just 17 months from sanction to first oil, takes full advantage of adjacent infrastructure for maximum speed, efficiency and value.

Despite its modest size, accessing a net 24 million barrels of oil, the favorable terms and innovative design result in quick payback and generate very significant cash flow. The HSD field may also yield reserves upside and production history will provide more information about the fractured reservoir here.

As Hal discussed earlier, interests in small but efficient projects like HSD/HST, Kitan, Tangguh, though individually not so material, collectively can add a lot of value. In Asia, a number of discoveries and acquired assets have been cycled through the business and provide a good source of free cash. These assets don't have the potential to grow into core areas, but each has the opportunity for individual upside and the temptation to monetize too early could lose this benefit. For example, having tested Kitan in the market early last year and received a lot of interests and several bids, the reservoir upside that we felt was there and price upside too, made us pause and we've almost doubled the life cycle MPV of this asset as a result. Conversely, we've concluded a sale arrangement on ONWJ in Indonesia that fairly reflects our internal valuation and where the buyer has a specific ability to create extra value, which we can't.

We, therefore, believe that this is an asset class that belongs in our business and rounds out the portfolio in Asia very well. And finally, I just want to point out that we have included Algeria here because stewardship will pass to the team in Asia following ConocoPhillips recently announced sale of their operated interest of Pertamina. Talisman's relationship with Pertamina is best served by us working these asset collaboratively from Jakarta and it just reinforces the importance of relationship management in our business.

So just to pull the whole business together, the production growth and cash generative capacity in this portfolio really speaks to itself. We have a set of high-quality assets that underpin our business with long-life, stable production and upside potential. We've added consistently to this base, with the acquisition of Tangguh, followed by Jambi Merang and most recently, Kinabalu. We also added discoveries at Kitan, Hai Su Trang and Hai Su Den and envisaged further growth from additional activity across the portfolio.

We enjoy exceptional pricing in Asia and operate in a relatively low F&D region, where activity is either in an onshore or low-cost shallow water offshore environment.

And so finally to recap and picking up on the 3 themes I opened with, I want to reiterate that Asia as a region, with all the dynamic growth and opportunity that we see today, continues to put forward on its own energy agenda. In this environment, we expect that high domestic gas prices are set to remain, if not even increase further with the impact of LNG imports. To help offset this, host governments are looking to encourage domestic activity and reward investment with appropriate fiscal and regulatory conditions. And as a result, we can continue to access the best returns in the upstream sector as our teams in the region leverage their relationships with regulators, NLCs and other key players to take on new opportunities and add further to our business.

We've worked diligently over many years to build capability and competency that is now consistently delivering the operating results that we've planned for. Our growth has become predictable and we expect to remain a strong contributor to Talisman in delivering production, operating performance and free cash flow.

Ladies and gentlemen, thanks for your attention. And now, Richard, if you'd like to step forward. He's going to talk us about Colombia and Kurdistan. Thank you very much.

Richard Herbert

Good morning, everybody. For this final presentation this -- now, I'm on, good. Good morning, everyone. For the final presentation this morning, I'm going to provide you with an update on the exploration activity that we've been conducting with a particular focus on 2 areas, 2 exciting areas for us, one is Colombia and the other is Kurdistan. But just to start, I'm just going to talk briefly to this sort of overview slide to just give you a summary of sort of where we are with our overall exploration program. Some of you will remember that back in 2009, we set up sort of 5-year target to add 600 million to 700 million barrels of new reserves over a 5-year period at a cost of less than $5 a barrel. This, of course, was driven by our company that, as Hal mentioned in the overview, was expected to be growing at sort of 5% to 10% per year and it needed that level of resource renewal to underpin that.

When we get to the end of 2013, we will have come to the end of that 5-year period and we will have found 600 million to 700 million barrels of new resource. Thanks to largely to 3 countries which have been successful: Colombia, Papua New Guinea, that Paul just spoke about, and now our new discovery in Iraq in the Kurdistan region, and I'll be talking about Colombia and Kurdistan in a few minutes.

Clearly, if we look forward so, we are now in a different world where we have to sort of fit the exploration strategy to the sort of new priorities for Talisman. And therefore, we are making a number of changes in the way that we explore going forward. And I'll just sort of focus on 3 of those.

First of all, reduce capital spend. So as part of our sort of mantra of living within our means, our capital expenditure on exploration is coming down this year to something of the order of $360 million as opposed to the $600 million to $700 million that we were spending in the past. And this sits in a sort of 10% to 15% of our total capital spend range that is -- that we're targeting.

Secondly, as we define our sort of 2 core regions for the company, obviously, we would like to try and direct as much of our exploration spending to them as possible. So in the Americas, we'll be spending about $75 million on exploration in Colombia this year. And in Asia-Pacific, our other core region, where we're spending about $120 million in our sort of 3 core countries in Asia, which is in Malaysia, Vietnam and Indonesia, and about another $30 million in Papua New Guinea. We still have our important appraisal activity in Kurdistan, which I'll talk about in a minute, which will take about $60 million this year. And we're continuing to spend some exploration money in the North Sea to support our business there as well. But a lot of our spend is now being focused into the core regions and the split is roughly 50% on exploration and the other 50% appraising the discoveries that we've made.

And the second sort of key point about our exploration spend is that we are going to really -- sorry, the third point. I've just made the second point. The third point is that we're going to really try and focus it on opportunities that can generate near-term cash that don't take a long time to develop. So areas like Colombia, where we can develop oil in the near term, the Sabah exploration blocks that Paul just mentioned where if we make a discovery, we can potentially tie it back into platform like Kinabalu in the near term. This will receive sort of prioritization in our activity.

And in fact, only about 30% of our exploration spend is now being diverted towards what we call longer-term options, things like Papua New Guinea, Kurdistan and potentially Vietnam. And even in those countries, we have options to accelerate projects forward. As Paul described in Papua New Guinea, we're looking at -- well, we're developing condensate stripping and we're looking for local gas sales into the mining industry. And in Kurdistan, we're looking for a potential to accelerate in early phase of development. So very much a focus on the near term.

I'm now going to move on and speak to give you an update on our activities in Colombia. Let me just first -- so we'll use this slide to remind you of our asset position in the country. We have sort of 3 major assets. The first one is our Equión joint venture with Ecopetrol, where we produce oil and gas from the Llanos Foothills. We've now had 2 full years of production from the Equión joint venture and it's been going very well. Production in 2012 was up 27% over the prior year. There is a major project underway to expand the facilities in the Piedemonte complex of fields and just recently, the operator-ship and interests that Talisman and Equión had in the adjacent Niscota license, which is just north of the producing fields, has been transferred into Equión and Equión will operate that going forward, which is a, from our perspective, a very satisfactory outcome. The second major sort of group of assets is the heavy oil blocks that Talisman has in both the Llanos Basin and the Putumayo Basin to the south. And these are the blocks that are shown in yellow on the map. After some frustrations with environmental permits and other delays during the last year or 18 months, we're now starting to see some momentum again. We're back to drilling in Block 9. I'll talk about that in a minute. And we hope to be drilling again in Block 6 later this year.

And the third sort of key asset we have in Colombia, which Hal talked about in the introduction, is our ownership in the OCENSA pipeline. Talisman now owns just over 12% of OCENSA directly, having extracted it from Equión and we're now able to use this for our own production or to market the spare capacity to others.

So let me start by talking about Block 9 in the southwestern part of the Llanos Basin. I think most of you are familiar with the Akacias-1 discovery, which we made in 2010 and which is now being on long-term test for nearly 2 years, and production in the next 10 days or so will exceed 1 million barrels gross and we've had a consistent low and stable water cut throughout. The graph on the slide shows you the production profile and you can see that it's recently increased as a result of a work-over that moved the pump and raised the pump frequency, and we're now producing close to 2,100 barrels a day.

In addition to Akacias-1, as is shown on the map, 2 down-dip stratigraphic wells were drilled back in 2011 and both -- one of these is -- the first of these was called AE-2 and the second one mysteriously was called AE-1. They both logged oil in the T2 reservoir but because we didn't have the necessary environmental permits, we were not able to test the wells and we've still not been able to test them. Now that the permit has been obtained, the plan is to test these wells later this year and the flow test from these wells will be critical for establishing the down-dip extent of moveable oil on the structure.

At the beginning of this year, we started a program of stratigraphic -- sorry, of appraisal well drilling and the plan is to drill 7 appraisal wells on the more up-dip part of the Akacias structure and then to put those wells onto long-term tests in a similar way to Akacias-1. The first well is shown on the map. It's called Akacias-18, and that well has, just in the last week, finished drilling and has been logged. The top reservoir is more or less at the same depth as it is in Akacias-1 and we've logged nearly 200 feet of net oil pay in that well, and we've collected some oil samples from it. And testing on Akacias-18 will begin in the next week or so. In total, the plan is to drill the 7 wells, put them on to production and exit this year with production of about 4,000 barrels a day gross.

Clearly, at this stage in the project, we still have quite a lot of uncertainty about the resources. We don't yet know where oil-water contact is and so we have an oil-in-place range that goes from a few hundred million barrels to several billion barrels. We're also not sure yet where the recovery factor will ultimately be in this heavy oilfield. We haven't enough data to constrain that and we've used it -- we've used a recovery factor today of 10% to give us what we think is a relatively conservative 2C contingent resource of 34 million barrels as a result of drilling Akacias-1. Clearly, the significant upside in this discovery, if we can prove of down-dip oil in the stratigraphic wells.

Just moving to the next slide. This shows the activity sets in Block 9. First of all, 3D seismic has been acquired, the 7 wells that I talked about, which will be put on to long-term tests, and our plan to flow test the stratigraphic wells. We also intend to drill an exploration well this year called Loreto-1 and this is being drilled on an adjacent structure to Akacias. It's being drilled up-dip of a 1974 oil discovery called Humadea. And if it's successful, it may prove an extension of the Chichimene-Akacias complex towards the southwest.

Let me now move on and talk about Block CPE-6, which is operated by Pacific Rubiales. We have 50%. In Block 6, we've had slow progress during the last 2 years. Since the 12 stratigraphic wells were drilled, they demonstrated the existence of a large oil accumulation that covers about 40,000 acres and has a net pay of up to 50 feet and looks like it's in part a stratigraphic trap. We've been unable, to date, to test any of the wells because the permits have not been available and we're now hopeful that by the middle of this year, the environmental permits will be awarded that will allow us to get back into action. And the good news is that the permit has been applied for is an exploration and production permit. So once it's received, we'll be able to not only complete the appraisal program on the field, but we'll also be able to move into full-scale development. So that should avoid any further delays.

We have been able to acquire -- while we're currently still in the process of acquiring 3D seismic data, which will be very important for characterizing the stratigraphic trap. And the plan once we have the permits is to drill up to 3 appraisal wells later this year and flow test them with the intent then of declaring commerciality in 2014 and getting on with the development. As in Block 9, we have a large uncertainty today in what the reserves are in Block 6 because we haven't flow tested any wells. We currently carry, as Talisman, a net sort of net 44 million barrels of prospective resource. Now we will convert this into a contingent resource once we have some well tests that demonstrate commercial flow. And we have high confidence that, that will happen. Interestingly, the operator has booked 2P reserves in Block 6, which are not substantially different from the numbers that we have applied to it. So I'm hopeful that in Block 6, we're going to see the pace of activity increase during the remainder of this year.

Moving on, to talk about Equión briefly. I mentioned the 2012 production, 17,000 barrels net to Talisman. This benefited from some de-bottlenecking activity, which took Piedemonte production south into the Cusiana facility because today, the Piedemonte production facilities are operating at capacity. So there is a major project underway to expand those facilities, put in more gas compression and expand the oil export line. And that project should see some results coming through in 2014.

We had some delays in 2012. We had a 6-month delay caused by a delay in the environmental permit to allow the project to move ahead. That's now being -- that's now behind us and we had a few community issues in getting the project up and running, which are also now behind us. So the project is now moving forward.

We have 3 rigs now active in the Piedemonte license and these are big wells that are being drilled. They take 9 to 12 months to drill. And if we look at the 4 last -- the last 4 wells that Equión have drilled during 2011 and 2012, they have significantly exceeded expectations. So production from those 4 wells was between 2,000 and 6,000 barrels a day each. In fact, actual production, initial production was between 5,000 and 12,000 barrels a day each. And we've also seen higher reserves per well than we forecast in the range of 5 million to 7 million barrels per well. As I mentioned in the introduction, Equión is now operating the Niscota license, which lies on trend to the north of Piedemonte. And here, the Huron-2 appraisal well finished drilling in December of last year down to a total depth of 18,500 feet and it found a pay section of about 700 feet of gas condensate, which is a likely extension of the [indiscernible] sheet from the south and the well is being prepared for testing during March and April of this year.

There's another well, Huron-3, appraising the complex, which is still currently drilling. Just a final point I would make on this slide is to show you the barrel bed. It shows that the cash margin from our Equión properties had about $37 a barrel. It's one of the best in the Talisman portfolio. And now moving to talk briefly about the OCENSA pipeline. When we acquired BP Colombia, now Equión, we obtained ownership and capacity rights in the OCENSA pipeline. And this is turning out to be a significant source of value for us. We recently completed a restructuring to take the ownership of the pipeline out of Equión and into Talisman's direct name. So Talisman now owns 12.15% of OCENSA and holds nearly 10% of the capacity rights. We left a few percent inside Equión to transport our share of their production.

In January of this year, OCENSA was restructured from a cost center into a profit center. So now spare capacity can be marketed competitively. Pipeline tariffs have been increased towards regulated prices, which are around $8 a barrel, and this means that a dividend can be paid back to the owners. And our view in the near term is that a combination of tariffs for marketing unused capacity and the dividend payments will lead to a revenue for Talisman of the order of $50 million a year. And as Hal said in his introduction, we have the option now to look at monetizing our ownership of the pipeline, providing, of course, that we can secure capacity for what we expect to be a growing production for Talisman from the basin, but this is an option that we're now looking at.

In the past, we've talked about Colombia providing 50,000 barrels a day of production for Talisman. Clearly, during the last 2 years, we've seen a lot of delays with permitting, et cetera, which have slowed the growth from the original profile that we were hoping for. But we still see some very exciting potential for growth here, which is underpinned first of all by Equión's production from both Piedemonte and in the future from Niscota, and then the heavy oil developments that we have first of all from Block 9 and Block 6, and then beyond that hopefully from some of the exploration properties that we have. And you can see that we still see the potential to get to 50,000 barrels a day.

The right-hand graph shows the amount of capital that we're putting into Colombia at the moment. It's at the order of $200 million to $250 million a year. Of that, about $75 million this year will be on exploration. The graph also shows that Colombia should be free cash flow positive either next year or in 2015.

I'm now going to switch countries and continents and talk to you briefly about our activity in Kurdistan. Kurdistan, region of Iraq, is on the map on the right-hand side of this slide. And in Kurdistan, Talisman holds 2 exploration blocks. In the southeast part of the region of an area known as the Garmian. So Scott McLeod -- sorry, Scott -- what am I saying? Lyle McLeod tells me that the Garmian region is famous for its kulafu [ph] tea. The 2 blocks of Kurdamir with a 40% working interest and Topkhana with a 60% working interest, both operated by Talisman and that is shown in yellow on this map.

As this map shows, most of Kurdistan is now being licensed to oil and gas companies. And 2012 saw the significant arrival of a number of the major international oil and gas companies. As you can see on the left-hand side, Exxon Mobil is now the largest landholder in Kurdistan after the government. Chevron is in Kurdistan. Total arrived last year and Gazprom has expanded its position in the region.

At the same time, we're seeing increasing deal flow in Kurdistan and we've been able to identify 14 transactions during 2012 with a total value of about $1.5 billion, which would value resources somewhere between $1 and $2.50 per barrel. The Kurdistan Regional Government is very positive on the arrival of these bigger companies and is keen to see more consolidation in the sector, which we see is positive for valuation.

Let me move on and talk a little bit about our activity and remind you of the discoveries that we've made. In 2010, we drilled the Kurdamir-1 well, which found a large gas condensate field and a good-quality oligocene carbonate reservoir. The well was drilled deeper into the Cretaceous and it saw evidence of liquids but we were unable to log or test the well because some of well-controlled problems. In 2011, we drilled the Topkhana-1 well, which found another large gas condensate field. Here, the oligocene reservoir was thicker and better quality than in the Kurdamir block. So we had found 2 large gas condensate fields in Kurdistan, both apparently in structural traps, which were filled to spill. So we took the decision to drill a third well, Kurdamir-2, down-dip outside structural closure in order to try and find an oil leg underneath the Kurdamir-1 gas discovery. And the trap that we were looking for was a stratigraphic trap, a stratigraphic pinch-out analogous to the giant Cook field that Paul talked about in his introduction, which lies along depositional strike.

So in 2012, we drilled Kurdamir-2 to a total depth of 4,000 meters in the Cretaceous and we discovered an oil column in the Oligocene, which is at least 140 meters thick and was full of oil to the base. There were deeper zones that were found to be hydrocarbon bearing in the Eocene and the Cretaceous, but we were not able to establish any commercial flow rates when we tested those zones. It may well be that they are potential reservoir in other places on the structure, particularly on the crest or on the more fractured forelimb but in the back limb location where Kurdamir-2 is located, these zones didn't flow very well.

I'm just going to move to the next slide, which shows a cross section I'm just going to talk about the testing results from Kurdamir-2, which is shown on the right-hand side of the cross section. We conducted 3 Oligocene well tests. The first one was an open hole tests that was conducted during drilling and which first confirmed the presence of oil in the feature. The second test was the first case whole test, with DST#6 and this tested 20-meter nonporous zone at the base of the main reservoir interval and it flowed at 3,450 barrels of oil a day of 38 API gravity. And therefore, demonstrates the presence of fractures, which is significantly enhancing the permeability of the reservoir. A follow-up test, DST#7 in the main reservoir zone floated nearly 2,200 barrels of oil a day and 10 million cubic feet a day of gas. Again, our interpretation being that the high gas oil ratio in that test was due to gas being pulled down from the gas cap in fractures.

The flow rates that I've quoted were restricted by the equipment that was used. We have 3.5-inch tubing in the well. If we were to use 5.5 inch tubing, we would see flow rates in excess of 10,000 barrels a day with a potential to go even higher if you were to use horizontal wells. While I'm on this cross section, I just want to explain how we've analyzed the resources in this field at the time being. You can see in red the 2 gas caps in Kurdamir and Topkhana. We've established a gas oil contact in Kurdamir and we have an inferred contact in Topkhana, which is 42 meters deeper. Based on the Kurdamir-2 results and the fact that we saw predominantly dry oil all the way to the base of the reservoir, we have interpreted an oil down to at 2,600 meters, and use that as the base of our 2C contingent resource today and that is the zone that's shown in dark green on the Kurdamir structure. We mapped a limit of structural closure on the northwest end of this feature at about 2,300 meters. We don't know if that's going to be the limit of this trap because of its stratigraphic nature. It could go deeper. But for today, we're using 2,300 meters as the limit of 3C contingent resource.

Next, we have the Topkhana structure where we have not yet demonstrated the presence of liquids. We've only found the reservoir there in the gas leg but we can extrapolate laterally from Kurdamir into Topkhana and this, we are currently calling prospective resource. The cross section shows the location of the next 2 wells that are going to be drilled. First of all, Kurdamir-3, which has started drilling, which is testing the continued deeper section in the Kurdamir feature and then the Topkhana-2 well, which we will drill later this year, which will then test for the oil zone in the larger Topkhana structure.

I'm just going to sort of pull this for a minute and show you a little exhibit, which I've got on the table here. I brought a piece of rock with me, which I'm going to actually pass around for those who are interested to look at it. This was nearly confiscated at Calgary Airport by the security, probably, because they thought I was going to hit someone over the head for the quality of the chicken or something. But this is a piece of core from the Topkhana-1 well. A lot of the oil that's being found in Kurdistan is not a particularly good rock. There's a lot of fracturing but there's still a lot of question marks about the long-term productivity, I think, of some of the fields that are being found in Kurdistan. This is, in my view, the best reservoir in Kurdistan. It's the Kirkuk reservoir. It's an Oligocene dolomitized grain stone. It contains 15% to 18% porosity, 100 plus milli-darcies of permeability. And if you look at this, you can actually see, there's a little white splotches of anhydride but you can see the mold, it get in to crystalline porosity in here, which shows that even though fracturing is clearly very important in these reservoirs, the actual reservoir rock itself is also good quality. So I'm just going to pass that around for people to look at if they're interested.

Let me move on to talk a little bit about resources. Clearly, we're at an early stage in our understanding of the resources that Kurdamir and Topkhana could hold. We don't know where the oil water contact is. We don't really know the form of the trap yet and we really rely on the next 2 wells and a very large 3D seismic survey, which is now ongoing to help us narrow the uncertainty and define the resources.

So this table shows a sort of current view with a lot of caveats on it. Let me just try and summarize the numbers that are on here. First of all, in terms of gas and all the numbers I quote and the numbers that are on the table are net Talisman working interest numbers. So first of all, in terms of gas, in the sort of midrange case we have today, Talisman has about 1.5 tcf of gas in the 2 gas discoveries. But depending on how big the oil leg turns out to be and the solution gas with that, we see the potential for that to grow to anything as much as 5 tcf of gas. And secondly, in terms of oil, if we take the oil down to that I quoted for Kurdamir, which is sort of the base of our 2C contingent resource today in the Kurdamir structure only, then we think the Talisman share of that is about 65 million barrels. However, if we have a deeper contact and we know it's a deeper contact, we just don't know where it is but if we had a contact closer to 2,300 meters and we see an extension of the same oil leg underneath Topkhana, then Talisman share of oil in the upside case could exceed 1 billion barrels. And there's further upside beyond that, once we start thinking about condensate volumes and the potential for oil beneath 2,300 meters as well.

So in terms of what the ultimate resource of this field will be, there's still a lot of uncertainty. But I think we can start to say with some confidence, that based on the scale of the structure, the quality of the reservoir, the quality of the oil that's been found, that this is one of the most important discoveries that's been made in Kurdistan.

This slide just briefly summarizes the activity during the remainder of this year. I mentioned that the Kurdamir-3 well was spudded last month and it will take about 90 days to draw down to the Oligocene target, to test the down dip section of the oil leg that we found in Kurdamir-2. The plan is to draw fourth Kurdamir well in 2014. And in Topkhana, we will spud Topkhana-2 later this year to look for the lateral extent of oil into the Topkhana block and follow that up with another appraisal well during 2014. And the large 3D seismic surveys is now being acquired to help us with our appraisal program and development planning.

Can we just talk briefly about monetization? We're still firmly in the mode of appraising this discovery, but we are now starting to think about the implications of it in terms of development and monetization. In this, the development of regional infrastructure will be very critical. As you can see, from this map, the actual connection of Kurdamir Topkhana into the regional infrastructure is a relatively minor pipeline connections needed and the really critical issue is how does the oil get out of Kurdistan. There is an existing oil pipeline that goes from the Khurmala area in Kurdistan to Jahan in Turkey via Kirkuk using the Iraq-Turkey pipeline. There are also advanced plans to build a new pipeline, a 1 million barrel a day oil line entirely within Kurdistan that would go from Khurmala to Fishkabour, which is close to the Turkish border. And this will allow direct exports into Turkey, obviously, with some political agreement being reached between Erbil-Baghdad and Ankara. There's also a gas pipeline, which is in construction from Khurmala to Dohuk with the intent of feeding a converted power station there. And from Dohuk, it wouldn't be much further to extend that gas line to the Turkish border. And the Kurdistan regional government is in conversations with Turkey about supplying gas exports and we are now getting actively involved in those conversations.

So I think in summary, we can say that Kurdistan is starting to look quite promising. We have a significant discovery at Kurdamir with a lot of upside. The large integrated companies are coming into Kurdistan and deal flow in the region is increasing. Clearly, there are still political tensions between Erbil and Baghdad that have to be managed. But Turkey is now accepting direct imports from Kurdistan and it sees Kurdistan as a critical source of oil and gas in the future.

And we're now moving forward with an active appraisal program and starting to review options for our first stage of field development, so that we can start to generate some cash flow from Kurdistan. So before I hand back to Hal for a wrap-up, I'm just going to conclude with a quote. I think appropriately enough from the Colombian author, Gabriel García Márquez, who wrote [Spanish], which we can more or less translate as, "He who awaits much, can expect little."

So I've talked about a lot of exciting opportunities today but there's clearly still a lot of opportunity. And I think it's important we keep our feet on the ground, we collect the data that we need, we make our plans carefully and we build the very important relationships that we require with government and local stakeholders to make these projects a success. Thank you very much.

Harold N. Kvisle

Thanks, Richard. I'm going to jump quite quickly through an overview and we'd like to get on to some -- or a wrap-up, and we'd like get onto some question-and-answer time. And these things always take a little longer than we think to get through but we've covered a lot of ground.

First of all, on this first slide, just to remind you, which you probably don't need reminding, we've identified 2 core areas being the Americas, the very significant gas resource position that we have in North America, the liquids potential that we're focused on today that Paul Smith talked about and what I think of as quite exciting opportunities in Colombia that Richard describe. Colombia has gone from being one producing asset, being Equión, with some potential for discoveries in Block 6 and Block 9, to having one of the best wells I've been involved with in my career, Akacias-1 producing 2,000 barrels a day and making more than 1 million barrels of cumulative production so far and further drilling and development potential in Colombia. And we've covered also Kurdistan, where this is a very large structure that we're dealing with, significant oil, good flow rates. We know there's rich gas and there are good opportunities to move that production to market through Turkey.

You heard from Paul Blakeley, the exciting opportunities driven by strong gas demand in Southeast Asia. It's an interesting region and that it both has very strong and growing demand and significant in-country or in-region opportunities for both oil and gas development. It's a combination of both supply and demand, not unlike what we deal with here in North America and much different from some of the more remote supply parts of the world. And you heard from Paul Warwick the challenges that we face in the North Sea. We acknowledge there are challenges there, but I think we've taken a very professional and technically driven approach to what do we need to do to restore the North Sea, ultimately look at divestment or joint venture options there.

In terms of the themes, the main themes that we're on and addressing the issues, I started with this slide today and I'd like to conclude it. As a number of the speakers mentioned, part of what we're dealing with is the significant culture change in Talisman and much greater emphasis and focus on near-term production cash flow. We built up some significant resource positions in recent years. We now need to move those through to production. We're also much more focused on the opportunities within existing assets. Sometimes, initially, they don't look that attractive but because they're within existing assets where we can bring expertise and existing infrastructure to bear, I believe we can make significant money out of those and I think they are under appreciated parts of our assets portfolio. We'll look at shorter cycle times getting production out of our resource basis more quickly. We'll focus on cash flow margins, increasing the cash flow out of every barrel or Mcf that we produce. In the near term, we've got a very strong bias to liquids in all of our operations, particularly in North America and a very favorable opportunities, I think, in international gas.

I want to acknowledge the broad options that have been mentioned by some analysts with respect to the future. We acknowledge that there could be opportunities to sell the company. That is not the strategy of the board today. We're working on strengthening and improving the performance of Talisman as a growing concern. But when you speculate about the value of the company, there is somewhere between $12 and $15 a share in cash flow value. Value that would be supported by future cash flow forecast. In addition to that, we see somewhere between $5 and $10 a share in resource base value in these very significant positions that we're sitting on. So taken together $12 to $15 per share in cash flow value and $5 to $10 per share in resource base value, this is a significant asset base that we have.

As we look to the second option of developing, joint venturing or divesting assets and really focusing our company and our resources, capabilities and finances on the very best options, we will rationalize our asset base to unlock the value of some of the underappreciated parts of what we have in different parts of the world.

The third option that people talked about is split call. Splitting the company into 2. We've analyze that in some detail and with a fair bit of rigor. It does not appear attractive from a going concern perspective for the company to split into 2 and we don't think it's attractive from a shareholder value perspective. So the real option of the management team and the board are focused on today is to develop our asset base, look at joint ventures where appropriate and where we have asset that are unlikely to yield shareholder value or cash flow in the near term, to divest those to other people. So that, in a quick summary, is the way we see the company. We'll be the happy to take any questions and even happier to receive any advice that you might have for us. I'd like to ask Scott Thompson and Lyle McLeod to join me on the stage and we'll be happy. Lyle will moderate the Q&A and Scott and I will do our best, then we'll turn to our colleagues in the front row here for additional answers where they are best positioned to do that. So Lyle, over to you.

Question-and-Answer Session

Lyle McLeod

Okay. I think now we're getting a couple of chairs out, so that we don't have to stand up through all of these. We do have microphones here. I bet you could stand and we're going to have your questions from that or we also have a couple of roving microphone. So you wanted to put your hand up, we got people who can bring the mic around to you. We will be prepared to answer the questions. Hal, Scott and myself will field some of them and then we'll field the rest of the Executive team in the front row here.

[Operator Instructions]

This -- we've been webcasting the procedure so far and we are webcasting the Q&A as well, and we do have some questions that are coming in from the web. And I do have a couple here that I'll put into the room as we move on. So with that, questions from the floor?

Greg M. Pardy - RBC Capital Markets, LLC, Research Division

My name is Greg Pardy from RBC. So just 3 questions for you. One, I just want to be absolutely sure, the guidance numbers that you got out and are prior to dispositions. That's question one. The second one is just with respect to the international assets that you're targeting to sell, that $1.2 billion, $1.5 billion, I'm wondering if you can just clear it up in my mind in terms of which assets are enveloped in that targeted number. Then the last thing is just with respect to the North Sea. Just trying to get a better sense as to what the major issue you need to attack, is it cultural, is it people? Because it has been an area that you've operated in for the better part of 15 years, obviously, with a lot of experience.

Harold N. Kvisle

I will address -- I'll make an introductory comment on the North Sea situation. That -- 2 things have happened there over time: one has been a reduction in capital investment and as you saw in one of Paul Warwick's slides, a real reduction in infill drilling, in particular, but also underinvestment in the facilities and a lack of reliability and operational performance as a result of that. Paul Warwick, you may wish to add to my comments. I think, some of this was driven by a lack of awareness of what would happen if we did not adequately invest and maintain in terms of both infill drilling and production facilities. It's a culture of riding out production from these existing assets and cutting costs, perhaps, with not as much awareness of what could happen in the event of underspending and underinvestment. I think, we're now seeing the results of that. So turning that around is job one in the North Sea. To your question on international divestments, the target for divesting in that area of $1 billion to $1.5 billion. Obviously, the assets in the North Sea, the balance of our joint venture in the U.K. and our positions in Norway, which are significantly valuable other than the problematic asset of EMA. Those would be the bulk of our international target. There are others, the OCENSA pipeline in Colombia, which we think is a near term divestible asset and by near term, I'm thinking sometime in 2013 or early 2014, we could bring that to market. In terms of joint ventures in Kurdistan, much depends on the outcome of the 2 wells that are going to be drilled, Kurdamir-3 and Topkhana-2. We have made the decision that we want to get through the drilling program on those 2, plus the 3D seismic that Richard mentioned before. We would even think about bringing in a joint venture partner to help us carry the cost and risk of the development there. And those are the major ones. I did talk about our non-operated non-core assets, which I actually quite like. I think, these are attractive, profitable and sustainable assets over the longer term, but of course, if the right opportunity to sell one of those for full value came along, we would absolutely look at that. But in the meantime, there is good cash flow to be had by Talisman in holding our position in places like Tangguh, Algeria and Australia. All of which are highly profitable and attractive for us. As to the guidance issue about how we've developed our guidance, then I turn to Scott and have Scott answer that.

L. Scott Thomson

Hey, Greg, it is predisposition. I don't know if this is on. It is predisposition and I remember in North America most of that will be non-cash flow generation and non-production base given the Duvernay and the Montney.

Lyle McLeod

Okay, other questions? Okay.

Curtis Gillis

It's Curtis Gillis with AGF. Just a question on the Marcellus, into the sustaining at 400 million a day. You show free cash flow about $150 million at a $5 NYMEX price. What would that number be like at around $4 NYMEX? Do you guys have a number for that?

Lyle McLeod

Paul Smith.

Paul R. Smith

Yes. $4 NYMEX [indiscernible] rate will continue to come down, as we continue to sort of see older wells that have got less decline coming into the portfolio. So we talked about 37 -- 31% coming down to 27% and I expect, whilst we haven't guided it next year, we will continue base declines coming down. So it's going to be in the $100 million to $150 million at fall.

Lyle McLeod

Okay, another question on this side.

Unknown Analyst

Denise Toya [ph] Tokyo [ph] Securities. I have 3 quick questions about Kurdistan assets that you have. First one is the -- in a time Kurdistan attracted a lot of consolidation and investment in the last 2 years, as you mentioned. You have a 60% interest on the Topkhana block and if I know correctly, the 20% of interest is open for a JV partnership for a while now, like more than a year. So I was wondering why you couldn't find a JV partner for the 20% interest. And is it because that 20% is not attraction -- attracting any attention? People, like companies like Exxon and Total coming in, nobody will be interested in 20% and KRG itself is not interested for the smaller companies to enter now. So will you consider maybe 40-40 JV if there's an interested partner and why there has not been any interested partners so far? The second question, the 3 wells that you drilled so far Topkhana, Kurdamir-1 and 2, they've -- 2 of them had a lot of operational challenges because of the geology mostly, but as we know and you recognize in the past that there has been some operational challenges from the Talisman side, and then the budget and the time for these wells has been overestimated and there has been very -- it was much longer and much expensive basically. So going forward I think that's this year, 2013, is very critical, also these are commitment wells for your PSAs in Kurdistan and you are, I think, I know that in Kurdamir, it's until September for your commitment and I don't know exactly about Topkhana. But -- so as you said, 3 months to drill these wells, do you think -- I think these are little bit very positive optimistic estimates for such wells despite the fact that you will only drill onto Oligocene. And the last question, you mentioned about Turkey and the pipeline. As we know in the last 3 months, there has been no export from Kurdistan and currently, there's 300,000-barrel production in the whole region and 3 months of not exporting this oil created a lot of tension in -- for Kurdistan and for the companies operating there. When do you expect this pipeline, almost -- it's a mess right now. And of course there are a lot of political problems but when do you expect to -- this pipeline to start the construction or even better, if you have any insight for -- to becoming operational?

Richard Herbert

Thank you for your question on Kurdistan. Briefly on the first one, with respect to the Topkhana interest, Talisman has 60%, what's called the third-party interest, which is awarded by the government of 20%, as you pointed out, has not been awarded and then the other 20% is held and carried by the government. I think, the simplest way to answer this is to say that we're in regular communication with the Minister of Natural Resources. When we pointed out the scale of what we think this field could be and the potential, he recognized that just awarding this to somebody at this stage was quite a difficult thing to do because it could be that there's a lot of value for the government in this award, which would be lost if it was done so precipitously. I do know that the minister is talking to a number of companies that are interested to come in. I think your observation is correct that 20% is a small working interest for a major company and they could well be interested in a higher equity position in the block. And in that case, it's something that we would be prepared to consider, but we haven't taken any decision today. So this is something that isn't -- it's not static. Things are happening but they're just not been very clear to date. I think, on the operational challenges, I mean, clearly the first well that was drilled, we did not operate, had a lot of operational challenges. We just drilled Kurdamir-2 to the same reservoir level in much less time, without any of the operational risks or problems that we saw in the first well and we now think that drilling to -- the Oligocene objective as you pointed out is, I wouldn't say it's straightforward but it's something that we have now confidence that we can do within the plans. So when we say 3 months to drill to the Oligocene, we don't see any abnormal pressure zones or anything in that. We believe we now have the experience and technology to do that. And finally, on pipelines and things, I mean, it's very hard for anyone to make predictions on when infrastructure is going to be built. A pipeline was recently completed within Kurdistan, connecting the Taq Taq field with Khurmala, so that the 50,000 barrels a day of truck production coming from Taq Taq can now move by pipeline. Obviously, the flow of oil into Iraq and into the Jahan line is stop start depending on the nature of the disagreements. But there is increasingly amounts of Kurdistan production now being trucked across the border into Turkey. So I think the pressure is building. I think, there is a recognition that Turkey wants Kurdistan oil. Kurdistan wants to export its oil and it all hinges now on some kind of agreement between the 3 parties including Baghdad to make that happen. But I don't think we or anyone else can make a precise prediction about when that's going to happen. Does that answer your questions?

Lyle McLeod

There's a couple from the floor here. But I've actually got one that's coming from the web here. It's a question from Andrew Potter at CIBC. And Andrew's question is first, a very good overview, Hal, but how are you thinking about Marcellus' infrastructure? And is that something that could be monetized and what are the pros and cons of that?

Harold N. Kvisle

We have had a number of queries about our Marcellus infrastructure. We have looked at that. The issue I have with this, and it's one that I've dealt with many times in my career is, if you monetize infrastructures, sell it to a midstream company. In order to sell it for a high price, they will always want a throughput contract or some kind of commitment for a number of years. And so what you're doing is transforming a capital asset into a fixed operating cost obligation and that's not something we'd like to do because that can make life quite difficult in periods of low commodity price. Now if that infrastructure is useful to multiple parties and not just to ourselves, then there is a good and valid economic case for doing that, for rolling that infrastructure to a midstream company who can provide the midstream service to multiple parties. But if it's a case of selling midstream infrastructure to a company that then has offsets [ph], the only customer usually, that is not a good option. There is more drilling and development opportunity in the Marcellus, obviously, on our lands but also on third-party lands that could lead to a demand for the use of our infrastructure. I'd like to see some of that demand before making a decision on what to do with it. There are many midstream companies that have made the case to us that they'd be better owners of that than we would. Similarly, people make that case in the Edson scenario, in Edson in regard our midstream infrastructure as a real competitive advantage that could be -- could give Talisman a leg up as we go to develop both gas and liquids pools in that region. So my own history has been one of keeping field infrastructure that usually, the rates of return, the people in the midstream business are looking for are about the same as what we would be looking for. It's quite different in the case of spec product infrastructure such as OCENSA in Colombia where there's a much longer term outlook for it, where there are big infrastructure players that would be interested in that, where I think they could bring a much lower cost to capital to the table and where I think we could get quite a value uptick by selling something like OCENSA to one of the major pipeline companies. I think that has more interest for me but we'll see where the Marcellus goes. If there's a lot of activity by third parties that would place a demand on our infrastructure systems, we'd be prepared to look at that kind of deal.

Lyle McLeod

Okay. Peter, question over here.

Peter K. Ogden - BofA Merrill Lynch, Research Division

Peter Ogden, BofA Merrill Lynch. Maybe this is a question for Scott, I'm not sure, but could walk you us through the cash flow generation for 2013? I think through 375,000 to 395,000 boes a day is generally in line. Obviously, the $2.5 billion is probably lower than most people were expected. We see G&A coming down, interest cost going up, so maybe those offset higher operating costs in the North Sea tend to be heavily taxed jurisdictions, so what are we missing, generating -- going from production down to the bottom line at the end of the day to get that $2.5 billion?

L. Scott Thomson

Right. So I will take a crack at that. Let's start with the $3 billion, some in the North Sea and selling some of the assets, you start with $2.5 billion. And the reduction in the cash flow is coming from 2 primarily oily assets, Norway and Kitan. And Kitan has started to water out or starting to lose production there, and then Norway, I think Paul Warwick talked about some of the issues there. You're also losing Marcellus gas, although that doesn't contribute a lot of cash flow. Going forward, you do have more oily production. In fact, at the end of the year, through this product substitution, you're ending up with more oil than we had, even with the North Sea sales, and that's coming from HST/HSD, Kinabalu, Colombia and the Eagle Ford in particular. But there higher operating costs and I think some of the analysts have not got the operating cost situation correct in the North Sea in particular. And right now, in the North Sea, with lower production and higher capital, it's not an actual taxable area for us. So when we're looking at the tax payable for the company, Norway and North Sea aren't taxable similar to North America, the tax payables coming from our Southeast Asia businesses or Colombia business and our Algeria business. And as I looked at some of the analysts, I mean, some of the analysts got it right, around $2.5 billion, but some of the analysts hadn't adjusted on the OpEx for the North Sea in particular.

Darren T. Peers - NWQ Investment Management Company, LLC

It's Darren Peers with NWQ Investments. Hal, I appreciate that a lot of thoughts gone into this capital program. My question is regarding North America. And it seems to me that living within your means in North America doesn't maximize the net present value of the assets and that the market values potentially have a higher value than constrained development program. And so I question whether you shouldn't be undertaking either a more aggressive development program in North America or a more aggressive disposition program and so I just like you to give me some color on why in North America living within your means is the best strategy.

Harold N. Kvisle

Darren, I would -- my thinking is somewhat based on my experience in the 1990s where, in North America, we thought that gas prices would always turn around in another 12 to 18 to 24 months. And as a result, producers continued to drill into a weak price market and thus, perpetuated a low price environment for a long time. I think today, the likelihood of a low price environment for an extended period of time is there and we could see that because the resource size is so enormous. What we're finding though is that some parts of the Marcellus, in particular, and our Canadian assets and the Eagle Ford are relatively quite economic, even in a low-priced environment, hopefully a little better than we see today. But if you are selective about which parts you pursue and endeavor to remain the best part of the cost curve, there is a profitable business out there in the next 3 or 4 years. Now so for me, it's not a question of should we develop more aggressively now? For me, it's about keeping our options open and making sure that we're ready to drill our best strategy, would be that -- when we see better gas commodity prices that we can forward sell into and take a forward sold position and then drill into that in a place like the Marcellus where we've got infrastructure and where we understand the geology and where we actually have a number of drill-ready locations ready to go, including well site locations and agreements and permits to do that. That's the way I would like to pursue in that area. Clearly and as I mentioned and when you look at the North Duvernay and the Montney, there is a good case that the economics are going to attractive in both the North Duvernay and South Duvernay, but exactly to your point, we recognize that we are not going to have the funding available to develop them both. And so we've had to make a decision here of the 2, where are we most likely to create shareholder value. We've biased ourselves towards the South Duvernay based on the really excellent liquid results and our knowledge of that area and we have embarked on a process to either divest or find a joint venture that will relieve us of the capital funding in the North. And I think that would be a good example where I agree with you and where we're doing what you would suggest. Similarly, in the Montney, our position is just too vast for us to fund it in any reasonable way. In terms of accelerating capital of -- Paul Smith and I have one major regret this year, it's that we simply don't have the money to continue funding in the Marcellus. The scarce capital that we have available to us right now, we've chosen to direct that to the Eagle Ford where firstly, we want to retain as much of the quality acreage as we can. And secondly, where there are liquids development opportunities that give it an economic edge over the Marcellus right now. But I would say that there are parts of the Marcellus that are economic, even in today's environment and we would like to be developing those to at least maintain that 400 million a day flat production scenario that I've shown on the chart. And in the event that we make good progress on the divestment front and free up some capital there, that would be one of the first places that we go back to. So I don't think we're doing something that's really contrary to what you suggest. It may be a matter of degree and we'll continue to examine that going forward.

Lyle McLeod

I think Brian has question over here.

Brian Singer - Goldman Sachs Group Inc., Research Division

I'm Brian Singer with Goldman Sachs. Three questions each on North America. The first is as we talk about -- as you think about the liquids growth that you have planned, should we expect any change in your average differentials, i.e. any change in production mix in terms of either oil getting heavier or more NGLs working through the mix? The second is that the Duvernay chart that you showed. What's the level of confidence you have in how you've drawn the borders between the oil and the wet gas windows and the level of confidence that you are as firmly in those windows, or do you expect and should we expect that those windows should change? And then the third question, just following up on one of the last responses with regards to the Eagle Ford itself. You seem to be differentiating a little bit between good acreage or the best acreage as your areas of focus. What percent of the 1,000 locations I think you highlighted or what percent of your 79,000 acres would you call as the high-quality locations that will dominate your program, I mean, how long will that last?

John A. Manzoni

In terms of your first question sort of the liquid growth, I think as we look into the key driver of our liquids growth in the next 1 to 2 years, I've said that we're going to -- primarily focusing in on the volatile oil and retrograde windows, which means that we're going to see on average more condensate. I think in the past, I've used the analogy where we've sort [ph] of said that average Eagle Ford barrel for us last year had about 50% liquids and of that 50% liquids is about 50% condensate and the rest was gas. I've said today that we expect the yield, the average yield and hence the net backs to go up, will increase to about 60% liquids and I think the condensate yield will go up in a commensurate way. So we'll be increasing the quality of the underlying barrel in the Eagle Ford this year and expect to have it increase even further in 2014 as we will have held the majority of our land by the end of this year. I'll answer your second Eagle Ford question, which was, of the 79,000 acres, what do we feel really good about? Some of those 79,000 acres are sitting in dry gas and we have no intention of holding those dry gas acres this year. So there's probably going to be around about 10,000 acres net expiring over the next 1 to 2 years and we do not have any plans with Statoil to retain that acreage. The rest of the acreage, Brian, would be right in the heart of the liquids window and all good acreage that we intend to fully develop out and may see further upsides as we talk about down-spacing and other things that we've talked about. In terms of the phase windows in the Duvernay, I'd say that phase windows moved continuously. Broadly, I think there's enough well control to sort of -- especially in the North, to feel good, there's 100 wells drilled up in the North. In the South, we've got 12 wells. But if you look at some of the competitor wells, there are clear trends in terms of where, especially where the wet gas to dry gas window transitions. I think there's less control right now over where the retrograde volatile oil or window transitions into black oil and that might change, Brian, as we go along. We're relatively early in, but I think if you look at our acreage, both of those lines may move. We're kind of indifferent right now whether we're still in [ph] retrograde or volatile or in that margins into the black oil window, just want to stay away from the dry gas stuff, so feeling pretty good about the definition in both the North and the South, but they will change.

Lyle McLeod

A question from Matt.

Matthew Portillo - Tudor, Pickering, Holt & Co. Securities, Inc., Research Division

Matt Portillo from Tudor, Pickering. Just one question on the international asset sales. You've outlaid, I guess, the value potential on a sense of $500 million to $700 million in value and you've talked about $1 billion to $1.5 billion of total sales. I just wanted to clarify on the international side. I think you mentioned the North Sea potentially being for sale and I just wanted to clarify that and then maybe the timing around that because previously, that have been an asset that the remaining working interest was not up for sale. And then, beyond that, I just wanted to get some color on the Montney with kind of the $9 million to $10 million well cost. Do you guys have an updated expected EUR for that position and how you think about the relative economics on a breakeven basis for the Montney? And then in the Eagle Ford, just curious about potential for rig acceleration. Obviously, you've highlighted very strong and robust economics and with monetizations is a scenario where you could accelerate upon down-spacing success.

Harold N. Kvisle

So I'll ask Paul Smith to answer the latter 2 questions. On the international divestments, particularly in the North Sea, we do have an arrangement with Sinopec in the U.K. where we will be their partner and where there is -- where there are certain restrictions on our ability to sell or to do things there without their support and involvement. However, there are a number of options that are available to us. We could do a follow-on deal with Sinopec. We could make some different arrangement with respect to ownership levels. I'd note that the people that run the U.K. business, the people that have been long-time Talisman employees, they're not Talisman employees today. They're employees of the joint venture of the partnership we have with Sinopec. So there's not organizational disruption or things like that in progressing through further discussions. The team is there and is able to carry on, notwithstanding things that we and Sinopec might do. On the Norway side, where today, our production is almost as large as it is in the U.K. side, our net production, there's some different issues. One of them, of course, relates to EMA and our desire to achieve a resolution of the current situation with SBM before we look at other opportunities. But whether it be divestment or joint venture, some kind of an arrangement similar to the Sinopec 1 could be an option for us in Norway as well as could -- complete divestment sale exits something along those. In terms of the timeframe, we've said 12 to 18 months. We're trying to allow enough time to work through some of those precedent issues that need to be dealt with before we could go on and do those kind of things, but that would be the outlook, I think, for the North Sea and the way we'd go about it. And Paul, over to you.

Paul R. Smith

Yes, so the Montney. When we went to the well costs -- I went to sort of the well costs today, I mean, we're targeting and actually on track with the first 2 months of this year behind us certainly on the drilling side to be -- starting to come in at that sort of $9 million of well D&C cost. Our first wells that we drilled this year have come in at just over $4 million, which are -- consistently over the last 2 months. So we're continuing to come down that slope. Completions, costs are more of an issue in terms of bringing costs of our completions down at the same rate as drilling costs. The Canadian marketplace is not as competitive as we see in other parts of this continent. We continue to try and be creative around how we bring our completion cost down, but we're targeting $9 million or less and I think our track record is moving us there very quickly. EURs, we're still targeting EURs of 5 to 6 Bcf this year, partially because we're moving towards the more liquids-rich end of the play, which is the eastern end of the Farrell Creek play. And in Cyprus A, where we drilled 5 wells to date, these are vintage wells from 3 years ago, we're going to move a rig back in there to start to delineate part of that play and we've seen EURs from those 5 wells in that play at 7 to 9 Bcf. So that's the sort of range of EURs that we're looking at. In terms of relative economics, clearly, we've always said that the Montney sits at the end of the pipeline and it's got a pick a day, but $0.50 differential to overcome on a good day, and so the rocks have to work $0.50 harder than our Marcellus rocks and you've seen the quality of our Marcellus rocks that we outlined today. So we need to continue to keep coming down the cost curve in the Montney, keep coming up the EUR curve to offset that differential and we're not there today and hence, we speak today -- we've spoken today about the flexibility in the Marcellus where we've got uncompleted wells of less than $2.50 and MCF breakeven and even new wells at $3 and the Montney is not there today. And it's one of the reasons why we think that those that can access premium gas monetization options will be able to make that supply cost curve work in the Montney better than just simply sticking into the pipeline and keeping your fingers crossed. In the Eagle Ford rig acceleration, I'd say that for this year, no. We're running 7 rigs and one of the reasons we're running 7 rigs is, as you -- as always, as we're sort of coming down towards 25 days cycle time, we just need less rigs to drive a consistent capital program. And there are 2 reasons I think why this year is not a year to look to increase our rig activity. We've got over 100 wells coming on this year, which is double what we brought on last year. So we've got -- last year, we've brought on 50 wells. This year, we're bringing on 110 wells. That's a big set of activity to go through this year and that actually what's going to get production into the pipelines. Secondly, we got a transition with Statoil to manage. It's an unusual construct that we negotiated when we first entered the play, and it's really important that we manage that transition in a classy way. As I said, the first rig is going across next month and we need to hand what would be another 2 rigs over before the end of the year and we need to make sure that we support Statoil in doing that so that they can hit the ground running rather than be running into an accelerating rig treadmill. And then the third piece is infrastructure. I mean, the infrastructure complexity in the Eagle Ford, our play -- our position stretch is nearly 150 miles. We've got 22 infrastructure projects to build out this year, 4 of which would be considered sort of large-scale infrastructure projects. And we need to get those behind us because otherwise, we will going to be doing drilling into -- choked production behind infrastructure. So that's why I'm comfortable with the pace at which we're going into the Eagle Ford this year and we'll take stock at the end of this year with our partner, Statoil, and see what next year looks like.

Lyle McLeod

Chris, that's you [ph].

Christopher Feltin - Macquarie Research

Chris Feltin from Macquarie. Maybe just a bit of a chat, and an asset that doesn't get a lot of attention and that Shaunavon, so we've seen you guys get out of the South East Saskatchewan, South West Saskatchewan, pulling up the decline profile on the public data on Shaunavon, it's a nice, late mature project, very low decline. And given the Canadian market an appetite for low decline assets within the yield universe, I'm just curious where this sits within your ranking, like I understand that this is a cash generating asset for you but arguably, you know this could be something where there could be a number of buyers. And is this something that you would look at maybe divesting to accelerate some of the higher growth opportunities within your portfolio?

Harold N. Kvisle

Sure. I have a deep and long-standing interest in oil properties in that part of the world. I've done a lot of the work out there in earlier parts of my career. And Shaunavon is an asset that I've admired for decades as a great puddle of oil or series of reservoirs. And the company had thought about identifying Shaunavon as a divestment candidate, of course. This may not be the best time to do that from oil differential point of view and I continue to harbor faint hope that the Keystone XL pipeline will go ahead soon and that will cause the differential situation to narrow and increase significantly the value of all of those kinds of properties in Western Canada. But beyond that, other than just waiting for something like that to occur, we're also commencing a pretty detailed and very technical review of Shaunavon because even with its excellent performance and relatively flat decline, there's still roughly 2/3 of the oil left behind, left in the ground at the end of ultimate recovery in a pool like that. And people are doing some pretty interesting things in Eastern Alberta and Western Saskatchewan on improving oil recovery from exactly that kind of pool and it's not a low-quality reservoir with a lot of permeability challenges. Shaunavon is a great pool, so we're going to make sure we've done our homework and not sell it at the time of wide differentials, low wellhead prices and uncertainty around what the ultimate recovery could be.

Lyle McLeod

Okay, another question over here, Ryan.

Ryan Bushell - Leon Frazer & Associates Inc.

Ryan Bushell from Leon Frazer & Associates. Just 2 sort of big picture questions, one on the dividend, which doesn't get a lot of attention from you guys, but you had been increasing it pretty regularly up until last year, so just wondering how to think about that near term and longer term. As well, just wondering, with this new outline plan of sort of regearing the company around the 2 core areas, Asia represents roughly sort 1/4 of your production but 1/2 of your cash flow. How are you kind of looking at that a few years out? Sort of bigger picture, how significant will Asia Pacific be, call it 5 years out?

L. Scott Thomson

Sure. I'll take the dividend question. So we spend about or pay about $270 million in dividends per year. And you're right, over the last 4 years, up until this year, we had increased that on a pretty regular basis. This year, given the cash flow, CapEx challenge, we decided not to. And I think it's probably fair to assume that keeping it like at the current level will be the path going forward. I don't think, given it's $270 million, it's something that we should look at cutting or reducing. I think we should continue to pay. I think that's a credibility issue, but I don't think you should count on increases in the near term until we get the free cash flow situation to a better place.

Harold N. Kvisle

And on the Asia Pacific question, we are obviously enthusiastic about the prospects in that region. We think we've got a great suite of assets. We've -- one of the most important things, we've got a strong team of people located, not just in one location, in Singapore, but in Kuala Lumpur, in Ho Chi Minh City, in Jakarta and in the various field operations. I like to think that Talisman has got some significant competitive advantages in that part of the world. We've also built up great currency with the governments and national oil companies in that region and we've done that through a decade of really strong, sustained performance, both bringing capital projects in on time, on budget and delivering quality production and meeting all the expectations that the governments and national oil companies would have for us. And those have led to very strong relationships where, for example, in the Kinabalu assets, we were able to have the confidence of PETRONAS and the Malaysian authorities and take that over. We look forward to getting contract extension at PM-3 and we would look forward to ultimately getting contract extensions at Jambi Merang and Corridor in Indonesia. So I think you could see, as Talisman unfolds, Asia Pacific being 50% of a company that is strongly positioned in 2 core regions. As to whether one of them will be larger or smaller than the other, it's hard to say, it depends on opportunities that come along. And if we were to a get much stronger in North American gas price, of course, that would cause our North American business to grow quite rapidly. But Asia Pacific, we've got a strong starting position. We've got great capability in our people. We got strong relationships. And this is a region that in my mind is like North America, and that it's not like the Middle East where it's generally just a supply region. It is both a supply region and a very strong demand growth region. As Paul Blakeley pointed out, the opportunities to develop domestic gas, pipeline gas, gas that does not go through the LNG cost structure are pretty attractive to the local consumers, to the markets in Vietnam, Malaysia and Indonesia. They're all interested in what we can do to increase domestic gas supply and we think that's a great opportunity and -- in addition to oil. So we're very strongly committed to the region and we could easily see it being 50% of Talisman going forward.

Lyle McLeod

Okay, any other questions from the floor?

Unknown Analyst

[indiscernible] Consulting. The companies offered to sort of refocus on 2 regions, improve balance sheet joint venture, at first, really commendable. I have 3 big picture questions. F&D has been consistently high. Is there any targets in the near to medium term? And with the funding gaps in most regions except Asia Pacific, what's the intent of share buyback potential down the road? And the last one is cultural change. There's been lots of cultural change in the last 5 years and how well do you see is the new wave of change?

Harold N. Kvisle

I think the challenge on finding and development cost and also operating cost and overhead cost is significant, but it represents a real opportunity for us. And part of my recommendation to the board, which the board has embraced that we are to lower our sights and not aim for 8% to 10% growth, but let's try to create significant value with much lower growth ambitions in the near term. Part of that is because in my experience, if we only aim to replace 100% of decline, we can do so in a more predictable way and a lower F&D cost. When we try to not only replace decline but grow production dramatically we just move up that cost curve and that's something we see throughout the industry. There's lots of evidence of that historically. So as we go through the change and trying to embed more cost-effective approaches to finding and development and production operations, pulling back a little bit, making sure we achieve profitable margins on a full cycle basis and then being willing to grow from there. That would be my strategy on that. In terms of culture change, you're right. The organization has been through a number of cultural changes in the last 5 or 6 years and this is yet another one. It is being well received, I would say, by employees. They recognize the practicality and common sense of what we're trying to do. I think the people in Talisman are very committed to maintaining the company as a viable going concern over the longer term and I've had very little negative reaction from people in the company. It is a significant change but people appreciate that it's necessary and we're getting pretty strong support for it. In terms of share buyback, when we did our first quarterly call after I stepped into this role, there was quite negative reaction to my disclosure that we were not planning to use the Sinopec U.K. funds to do a share buyback. And the reason I felt that way is that I had a quite a bit of insight into what 2013 was going to look like that we would still have a cash flow versus capital gap that needed to be dealt with and in my view, we needed to reduce debt. I want to be within that 1x to 1.5x debt to cash flow range. And so at that time, we announced we were not doing to be a share buyback with those proceeds. I am not at all opposed to doing share buybacks and I think that in the event our shares are trading at a discounted level and we have cash availability and that represents a good use of cash and an attractive investment, we would absolutely look at doing a share buyback and that would be one of the options. I mentioned continuing to strengthen the balance sheet, directing some incremental funding to those capital programs that we've been unable to fund in the current circumstance and then share buyback, those are all viable options for us.

Lyle McLeod

Okay. One more, Peter?

Peter K. Ogden - BofA Merrill Lynch, Research Division

It sounds like a very incredible and well-thought of going concern plan for the company going forward, but I'm going to go back to the option of an outright sale of the company and I heard that from you, that the board is actually open to that option. Of course, that's the ultimate unlocking of the value here. So can we understand that there's a parallel process taking place to look at that option? If not, why not? It's obvious that a big portion of your shareholder base would like that option to be further explored.

Harold N. Kvisle

So I think I have to choose my words carefully here, but I would say that the board is not actively pursuing the sale of the company. The board has identified that getting the company back on the right track will lead to the best outcome for shareholders whether we can restore Talisman as a highly attractive going concern company or whether we take the necessary steps to deal with some of the issues and perhaps see that a corporate sale might occur down the road. Either of those would be a better outcome than pursuing a corporate transaction at this time. So the board is not actively pursuing any kind of a corporate transaction. I would like to confirm though that the board is not opposed to that, but if -- and obviously, the board could not be opposed to that. We're here to act in the best interest of the shareholders. And if that kind of a proposal came forward, I think it would be inappropriate for any board to say under no circumstance would we would look at it. And realistically, we would look at it and that's been communicated, I think, pretty clearly. In terms of my statement that I think the best option for the company is to focus on Talisman as a going concern, we see that we're creating, at a reasonable level relative to the cash flow that we generate today and the cash flow that would -- people would expect in the next 2 or 3 years. But we have this very substantial, undeveloped non-producing asset base that's in addition to our cash flowing assets. And in bullish or buoyant times, people tend to place a significant value on those, not just in Talisman, but in many of our peers. People are ascribing pretty low value to the non-producing parts of the asset base and I think we have that issue more than most of our competitors. So our focus really in the next 12 to 18 months is to surface the value of those non-producing portions of the asset base and to the extent that we surface that value through a divestment or the formation of a joint venture, those are options that the board is fully supportive of. So maximizing the value of current production, growing cash flow and achieving a better cash flow multiple by surfacing the value of the non-producing stuff, those, I think, would be the -- that's a good characterization of the board's priorities at this point, but no opposition at the board level to hearing about other opportunities, but we do not have a parallel process going on today and unless we were to see some significant expression of interest from somebody, that's not something that we're pursuing at this time.

Lyle McLeod

Okay, any other questions? If not, there's nothing standing between us and some lunch and an opportunity to have a little more informal conversation with the executives. So with that, I thank you, all, for your attention and your time here. We've gone a little bit over time but hopefully, we got to -- had a chance to answer your questions and we'll have -- go have some lunch and continue our conversations. Thank you.

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