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Talisman Energy Inc. (NYSE:TLM)

2012 Investor Open House

May 10, 2012 8:30 am ET

Executives

Lyle McLeod - Vice President of Investor Relations

John A. Manzoni - Chief Executive Officer, President, Non-Independent Director, Member of Health, Safety, Environment & Corporate Responsibility Committee and Member of Executive Committee

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

Tony Meggs - Executive Vice-President of Special Projects

A. Paul Blakeley - Executive Vice President of International Operations for East Region

Richard Herbert - Executive Vice-President of Exploration

Chris Spaulding

Lyle McLeod

Good morning, ladies and gentlemen. It looks like everybody has taken their seats, and we're ready to go here.

So welcome to Talisman's 2012 Investor Open House. My name is Lyle McLeod, the Vice President of Investor Relations. I've had an opportunity to meet many of the people in the room, but to some that I haven't and hopefully over the course of the day, I'll get a chance to meet more of you.

We have all the senior executive with us here today to give update and presentations on the company. But before I get started, a couple of -- just a couple of logistical things here. First off, washrooms. You'll find the men's washroom out the doors to the right, and the ladies' are off to the left. And also -- and very important, but hopefully it doesn't come to pass, in the event of an emergency, the emergency exits would be the -- follow the red signs and would be down, the stairwells to the left or the main stairwells to the right, down into the lobby and then exit the building to the main doors -- main doors in the main lobby.

So with that, the last sort of business -- bit of process, I have to do a little bit of legal stuff here. So wait till you see today. The presentations you're going to see contain 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.

And now with the legal stuff out of way the way, I can turn it over to much more entertaining John Manzoni, and over to you.

John A. Manzoni

Okay, then good morning. Nice to see you. If you notice we've a new, we saw lots of formats for this over the years. We've had people sat behind tables up here. We're now going for a salon-style approach. So we'll see if we can keep you entertained. I hope -- nice to see, all, anyway. Thanks for coming. I hope you've had little chance to interact at least with some of those posters outside because we've all -- today, we've got some of our senior leadership from the regions.

The guys who actually do the real work out there in Papua New Guinea and in the North Sea and places, and there are some process out there, which just gives them an opportunity to talk to you about their business. So I would encourage you -- and we're going to break it up a bit. We're going to have a break. We have some time to do that, and I hope over lunch, we will also find some time for you to chat and get the real scoop, so to speak, from the guys who are at the frontline. So I'd encourage you to take the opportunity to do that because I think that's a good thing to do, and I hope that, that will give you a little deeper insight into some aspects of our business straight from their mouths as opposed to our mouths, and that's the purpose. So I hope you take that opportunity.

The stuff this morning is for the EVPs to talk to you about the different parts of the business. In addition to those who you'll see up here presenting, we have 2 other members of my executive team here today. I'm desperately looking around for them. Bob Rooney, who's here. He won't be speaking and neither will Helen Wesley, who's at the back. Both on my team, but won't be up here this morning, so -- but they'll be very happy, of course, to chat with you about anything you like as well during the breaks.

I'm also delighted today to introduce Paul Warwick [ph]. Where are you, Paul? Could you stand? Thank you. Who's joined us today, and he's about to join us full time as an EVP in the very -- in the next week or 2 to look after our international operation West division, and that means Paul's initial focus, of course, will be on our North Sea operations, and I'm particularly excited to welcome Paul because he has extensive and deep experience of both the North Sea and of operations. And I think will bring a huge benefit to Talisman with his joining, and we're very much looking forward to that. I'll leave him to tell you himself about -- how will I say this, rather long experience in operations. But many of you may know him already or if you don't, he's from ConocoPhillips, and I'm delighted that he's joining us imminently.

So what I'm going to do this morning is give you an overview. Scott will then run over the financials and balance sheet very briefly, and then we'll hear from Tony Meggs who's been running the Western operations division on an interim basis since December in addition to his main responsibility, which, of course, has been gas monetization in North America, which includes our relationship with Sasol [ph]. After Tony, we'll hear from Paul Blakeley on Southeast Asia. Lots of exciting things to tell you about there. And at that point, we're going to stop. We'll take break. Actually, we'll take some questions first on Tony's presentation on Asia. We'll have those questions, then we'll take a break, interact with the guys in the posters, then we'll come back, and we'll hear from Paul Smith on North America, and we'll hear from Richard Herbert on exploration. And then we'll take some more questions, and then we'll have all earned lunch I think by the end of that.

So I hope you're going to find this a fascinating morning, and there's [ph] certainly a lot of opportunity in our businesses, which we hope we will convey to you over the course of the next few hours. So let me begin by framing the portfolio for you. The headline I supposed is that we have a balanced portfolio, which will provide material liquids growth. And I'll show you that over the next few years, but also holds exploration promise and a high-quality gas option in North America for the time when gas prices actually do increase a little bit from where we are today, and there are 4 pieces to that portfolio.

We have a growing and strengthening Southeast Asia business, which I'm bound to say in our view today is not properly recognized yet by the market. The business is growing sustainably and is also generating increasing amounts of free cash flow at the same time. We have an evolving exploration portfolio, which is now starting to see material success in several places. And you'll hear all about those places this morning.

We have a tremendous unconventional business here in North America, which offers both liquid growth as we direct capital into the liquids-rich parts, but also includes an advantage dry gas portfolio, which today could be seen as I suppose as an option for the future. And we have our legacy assets, which are our North Sea business and our conventional North American business where our objective really is to maximize value through a combination of good operations, some divestments and dilutions.

But those businesses, in addition to that, also have a very rich opportunity set of their own investments, and you're going to hear, all of which have fantastic economics, and you will hear about those this morning as well. What I will say is that I recognize the tension between a diverse portfolio and the need to focus. And you can be sure -- we are to be sure that we're not spread too thinly across our operations that we don't manage them all properly.

And part of our forward plans certainly do include a drive to continue to focus our portfolio, and I'm determined that over the course -- we have done a lot, and I'm quite certain that over the course of the next period, we will do some more. But on the other hand, it's also true that the diversity of our portfolio has been a strength in the most recent period when North American gas prices have been particularly low.

Our balance sheet is -- remained very strong, and it's partly because we focus the portfolio over a number of years to the tune of about $6 billion. And most relevant to today's gas price environment, the portfolio today can deliver liquids growth, and I'll show you. But it can deliver liquids growth between 5% and 10% between now and 2015 off of very strong liquids base already.

So just before we look into the future, it's useful I think to step back and remind you of the original objectives of the strategic moves that we took over the course of the last few years because in the end, that's what underpinned the quality of portfolio as we go forward into the next period.

Our first objective was what I call extending the legs of the portfolio for growth. The reserve replacement ratio between 2009 and 2011 was 144%, and that compares with a reserve replacement ratio of less than 100% in the 3 preceding years. We now have a resource base, which can support growth in this company for a decade with plenty of running room we'll show you. And those resources aren't only found here in North America.

We have a best-in-class acreage position in Southeast Asia, which, in fact, is 99% undeveloped. Apart from that, we can grow very strongly over a long period of time. And if I look back 3 years ago, that just wasn't the case for Talisman. We did not have those sort of legs in the portfolio to underpin long-term growth.

The second objective was to reposition the company in terms of profitability. Replacement costs have been reduced over the last 3 years by about 40%, and the balance of our portfolio has allowed our netbacks to rise over the same period by more than 50%. And that is a result of increasing oil prices, increasing Asian gas prices offsetting decreasing North American gas prices.

The third objective was to create an exploration portfolio to help renew the firm in the long run. I said at the time 3 years ago, that it will take between 3 and 5 years to do that. And I believe we're on track. And I'll show you in a moment why I say we're on track, but we are confident today that we are building a good track record in our exploration portfolio with several of our areas now starting to work. And if we can evolve that portfolio through an even more competitive position as we go forward, and I'll describe how we're going to do that too.

There's one more perspective about what's happening -- what's been happening in the last 3 years that I want to show you. For our operating teams in the business, this is the most important aspect, and for the financial market, I would simply encourage you to make the link that a company cannot be good in operations if it is not looking after the safety of its people.

We've made dramatic improvements to the personnel safety moving from the fourth quartile 3 years ago to the second quartile today, and we've made similar improvements in process safety. The indicator, which is on here, which is sort of hydrocarbon releases is simply a leading indicator of the process safety. And you can see from this chart that we're improving there as well.

In addition to that, Talisman's playing a leading role in promoting responsible shale development. We publish our own shale operating principles, which I think are on your table in front of you and you'll see. And I think as you look over those, have a look inside and make your own judgment about the passion of our teams in operating that Shale business. And I think you'll conclude that this is an important part of what Talisman is and how we intend to forward.

These operational and safety aspects are very important indicator of how we're improving our operations because they are, in fact, of course at the heart of our business. So we've made some pretty big changes in the portfolio over the last few years. And in so doing, I think we've made ourselves fitter for the future. We've got longer legs, we're more profitable, we have better safety, and we have a higher quality opportunity set for renewal.

But to some extent, the world's change pretty radically over the last 12 months at least as it relates to North American gas prices. But our portfolio's exposed to more than just the North American gas price. Oil prices look underpinned into the future, perhaps not at today's level. That's come off a bit recently, but it's still close to some degree by geopolitics. But the fundamentals remain tight in our view despite relatively moderate global GDP growth.

Overall, we believe that about $90 to $100 Brent is a sensible medium-term view, and our portfolio is 55% weighted to oil prices. About 1/3 of our gas production is in Asia, and Asian gas prices are high and getting stronger. Power demand in GDP growth in the region points a strengthening prices, and we're certainly seeing that same trend in our own portfolio realizations, and Paul Blakeley will talk to you at some length about that.

And of course, North American gas prices are at decade lows. They certainly won’t return to the highs you can see on the chart and we've seen in 2008, but we do believe they will return to levels, which will allow the North American market, which is showing strong and sustained demand growth, to be supplied profitably at least by those with the best blocks. And we believe we have a portfolio of the very best blocks here in North America for when that price does rise just a little bit.

But today's NYMEX prices certainly, of course, require some adjustment, and we've moved very fast to respond. And we've done that in 2 major ways. First of all, our capital budget. We've reduced expenditure in 2012 to $3.6 billion, which is down from $4.5 billion last year. Within that total, we've minimized the allocation to dry gas spending in North America. Looking forward, we can predict only about $200 million of dry gas spending, which is intended to essentially maintain our dry gas portfolio in good standing and maintain that option for the future. And at the same time, we're reducing our exploration expenditure. I'll show you the moment that as we continue to evolve our exploration portfolio, we believe we can deliver the same resources as we have been delivering but at a lower cost.

So looking forward from today, about more than, in fact, 90% of our capital this year will be directed towards liquids rich or liquids linked opportunities. And the second adjustment we made is to focus our portfolio. So far this year, we delivered $1 billion of our $1 billion to $2 billion target, and we're continuing to look at opportunities for more.

These adjustments that I've just described will do several things for us. First, they'll continue to focus the portfolio. I've pointed to the North Sea and certain areas of our exploration portfolio is future disposal or dilution options. And those areas remain valid through the course of this year.

Second, they'll drive strong liquids linked growth over the next few years, which I'm going to show you in a second. And finally, at the same time, they'll also allow us to continue to strengthen our underlying business in our key areas of operation, which I want to turn to just now.

Starting first with our legacy portfolio. That's the North Sea and our conventional North American business. As you know, we invest a little over $1 billion annually into the North Sea business, but we've also taken about $2 billion of free cash flow after investment out of that business over the course of the last 3 years. It's performing a very powerful role in that sense within the portfolio.

The agenda in the North Sea is very clear. We'll improve our operating capability. We'll invest in very high quality opportunities to maintain the health of that business, and we'll continue to both focus it and take free cash flow from it. The investment options include medium-term redevelopment projects, which over the next few years increase the capital investment slightly as you can see from the middle bar on this chart, but then deliver more cash in the post 2016 period.

But they also include a large portfolio of infill wells, which as Tony Meggs is going to describe later, have really very attractive economic returns. In our North America conventional portfolio, we're very close now to completing our technical assessment of its potential. We have a very powerful legacy position with over 1,900 well locations and 700,000 acres of liquids-rich opportunities in place such as the Cardium and the Wilrich.

The question for us, of course, is how to exploit that potential best. And as we finalize our technical work, we're looking at options to do that. And Paul Smith will talk a little bit about where we're getting to and when we will complete that decent work when he speaks a bit later.

Turning next to Southeast Asia. The portfolio here is of tremendous quality. It's growing, and it's playing in a strengthening gas prices in the region. In part that's because of some of our gas realizations are linked directly to oil price, but it's also true the domestic gas prices in Asia are increasing strongly.

Production in Asia for Talisman is growing at about 8% per annum with a range of development opportunities you can see on the slide between now and 2015 or '16. And it's now starting also to generate increasing amounts of free cash flow, which, of course, provides options to grow in the region itself or to redeploy that cash into other opportunities elsewhere in the portfolio. So in Asia, very high quality portfolio, which is growing and strengthening all the time.

Our exploration portfolio has been evolving over the last few years and is now framed into 2 major opportunity sets. First is near-term oil, including Colombia, Kurdistan and Malaysia. And second is Asian gas, which today includes Papua New Guinea and Vietnam. As we think about the next set of opportunities in our exploration portfolio, we're focusing on leveraging our unconventional skills where we're being asked to help in many countries across the world. The question is, which ones of those we pick up and act on, and so far, we've entered Poland as a first step.

We're also starting to focus into deepwater where opportunities exists to explore for material oil prospects. Our first move here is in the West African margin in Sierra Leone, which we'll drill later this year. Standing back from the last 3 years, our exploration portfolio is starting to create what I call a pretty good track record, and I'd characterize it for you as follows.

Two of the areas we've tested haven't worked. That's Peru and Makassar, and we need to determine our future plans in both those places, and we will do that over the course of the next few months. Three areas have worked. Colombia, where we're finding material oil resources; P&G, where we're aggregating gas successfully for subsequent export; and now Kurdistan, where we found a significant oil column in the Kurdamir well. And 2 areas we have yet to test. That's Vietnam and the Sabah blocks in Malaysia. We'll test both of those places over the course of the next 12 months. And once we've drilled those 2 basins, we'll have tested all the areas of our original portfolio.

So overall with 7 areas in that portfolio and 3 working, 2 not working and 2 yet to test, that is a relatively strong emerging track record. And I mentioned that as we evolve that portfolio, we believe it can drive to a lower finding cost. Over the last few years, we've targeted 600 million to 700 million barrels over a 5-year period at a finding cost of $5 a barrel. And we're on track as you can see from this chart to achieve that over the 2009 to 2013 period.

We're evolving now to a position where we can target the same 600 million to 700 million barrels over a 5-year period but now at a finding cost of $3 a barrel. And this is largely a result of targeting our resource renewal opportunities into unconventional resource resources and higher-value deepwater oil opportunities and reducing our drilling and legacy decisions, which tend to contain smaller hydrocarbon pools.

And Richard is going to describe some of this in a little bit more detail when he speaks later. And finally, our North American Conventional portfolio. In a very short time, we've constructed a portfolio of shale plays, which extends to about 40 Tcf of contingent resource. Like everybody else today, we're focusing on the liquids growth in North America for right now. And as I'll tell you in a moment over the next few years, we can drive to at least 65,000 barrels a day from our Eagle Ford and Wild River positions in Liquids.

But gas prices won't stay where they are today forever. We don't see them moving much above $4 or $5. But they don't need move much about $4 or $5. Our portfolio, as you can see, has been assembled to contain what I have called just enough of the best. The bottom of this slide shows just 1/3 parking perspective of the relative breakeven prices for the various North American shale plays. We've consistently held a view that we need to be in only the best plays, and we believe the Marcellus has full cycle breakeven economics between $3.5 and $4, and we believe that the Montney can achieve about $4.

We'll find out more about the Duvernay as we go through this year, but we remain optimistic that we have a very material position in the next liquids-rich shale play. And while we can drive liquids growth in the short-term and medium-term, which, of course, is good for all seasons anyway we also, therefore, have an advantage dry gas portfolio, which, by the way, as I've mentioned we can maintain in good standing with minimal capital expenditure.

Now pulling together the components of the portfolio I've talked about in terms of Liquids production over the next few years. Of course, we're also driving gas production especially in Asia. And as I've mentioned, the domestic gas prices in Asia continue to increase, but this chart focuses on liquids and liquids-linked gas contracts. We'll build strong momentum through 2015 as you can see from that picture. We then go off a little bit frankly, in 2012, just to be conservative, but we do see some decline in Liquids from the 2011 out-turn. This relates to the fact that we've sold some Liquids in North America this year and also as I think we talked about in our first quarter call, increased water cut in some walls in the North Sea.

We have actually plans to drill up dip wells to mitigate those water cut issues, but we've learned over time that to be somewhat cautious in our North Sea forecasts. As we focus our investment during this year onto Liquids opportunities around the portfolio, it drives substantial growth as you can see starting in 2013. We anticipate investments during this year to build new Liquids production of around 40,000 barrels a day, which leads to at least 20,000 to 30,000 barrels a day of net increase in 2013.

That includes the buildup of our Eagle Ford position, increased Liquids production from Colombia in both Akacias and in Piedemonte. We also benefited from the new PSE at Kinabalu in Malaysia, as well as substantial liquids-linked growth in the Corridor field in Indonesia.

We bring the HST/HSD field on in Vietnam in the second half of 2013, and we continue to drill infill wells in the U.K. and Norway as high quality new Liquids opportunities. At the end of 2013, our peak plant comes on stream at Wild River bringing about 10,000 barrels a day, and we're expecting to be able to build production at Kinabalu as well. And we continue to add incremental production through the period in both Eagle Ford and in Colombia.

Looking toward to 2015, therefore, we anticipate at least 120,000 barrels a day of new Liquids production coming on stream resulting in a net increase in Liquids of at least 70,000 barrels a day over the end of 2011. And at the end of 2011, we were producing around 230,000 barrels a day liquids. So that says we're at about at least 300,000 barrels a day of Liquids by 2015.

Within this total, North America itself will be producing at least 65,000 barrels a day, driven primarily from the Eagle Ford and Wild River along with some contributions from our emerging Conventional portfolio. Overall our Liquids and liquids-linked production will grow at somewhere between 5% and 10% per annum between the end of 2011 and 2015, which, of course, gives me additional confidence in our overall target of 5% to 10% growth in the medium term.

These projections are necessarily approximates because things change. For instance, I've excluded any contribution from our recent oil discovery in Kurdistan, which we hope we can develop with some early production. And also I've excluded any success we see as we pilot the Duvernay play in Alberta, which we hope also will be a liquids-rich opportunity. And I further completely excluded any contribution from the Eva [ph] development in Norway until such time as we're clear on the time frame for that project.

Beyond this time frame, there are significant contributions in our North Sea business from the major redevelopment projects on the Auk field and the Montrose Arbroath field, both of which are projected to come on stream just after the end of this chart in 2016 and 2017.

So just to conclude, I've given you an overview of the reasons we're confident in the underpinnings of the business and the potential we have to grow profitably, including our Liquids potential. In 2012, we're focused on building operational momentum and executing what we said. And this chart shows you some of the short-term milestones we're focused on during the course of this year. We've made a significant shift to our capital allocation within the unconventional portfolio or away from dry gas and into Liquids. We can retain all the optionality of our dry gas portfolio while at the same time, growing the liquids-rich part of the portfolio.

We've made great progress in Asia with Kinabalu, which of course gives us more Liquids and also with PNG where Mitsubishi are turning out to be a very strong partner. We sold $1 billion of assets, and we found some oil in Kurdistan. But there's lots more to come in 2012. We'll see more visibility on liquids growth as we go through 2012 and 2013. That includes growing the Eagle Ford and getting more visibility on the Duvernay play as we go through the year.

And we're continuing to seek opportunities to strengthen the Asian portfolio. We're drilling exploration prospects in Vietnam and expect we'll make progress in Colombia and in Kurdistan over the remainder of the year. And we'll continue to find opportunities to focus the portfolios through the course of this year. So this is the deliberately short-term focus slide to emphasize that we're maintaining a sharp focus on the very near term, and we have lots more to come in 2012.

Each step this year is strengthening the portfolio towards what I outlined at the beginning. That is that we have a balanced portfolio, which we will continue to focus, which deliver strong Liquids growth over the next few years, has upside from the successes we're starting to see in the exploration portfolio and still retains an option for dry gas in North America by virtue of the quality of that part of the portfolio.

So that's all I have to say in overview, ladies gentlemen. Just before we go into the detail of each of the areas, I'll ask Scott to talk about the financing and the balance sheet. So over to you, Scott.

L. Scott Thomson

Thanks, John. Good morning, everyone. Good to see some familiar faces. Few of us joined us yesterday as well, so hopefully there was enough compelling tidbits there that made you want to come back.

I'll spend a few minutes, as John mentioned, discussing the balance sheet and the financial position, run through a few slides and then hand over to the operational VPs. But hopefully gives you a little bit of context on the strength of our financial position.

We continue to have a strong balance sheet and liquidity position. As you heard John said, we're responding to the macro environment by reducing capital from $4.5 billion last year to $3.6 billion this year. The combination of operating cash flows and disposition proceeds will plug the gap, which -- there's a slight gap in terms of operating cash flow and the CapEx this year, but we'll plug that gap and allow us to enter 2013 with a significant liquidity position. As John mentioned, we've sold $500 million of dispositions that closed in the first quarter. We expect to close another $500 million in the second quarter, and then throughout the year, we'll continue to explore disposition opportunities in the North Sea business, the North American conventional business and the exploration portfolio. We have no near-term maturities, and in fact, approximately 45% of our debt matures post 2020.

We've taken advantage of a number of different and innovative financing instruments to lower our cost of capital and expand our investor base over the last few years. The diversification of our fixed income portfolio has enabled us to significantly reduce our financing cost. In 2009 and 2010, our fixed income portfolio was 100% term debt. In 2011, we started the U.S. commercial paper program where we pay approximately 60 basis points in interest. In addition, we issued preferred shares and an attractive funding cost of 4.2% during the year. Our overall cost of debt is approximately 5.3%.

Our overall debt levels are reasonable relative to peers based on 2 metrics that we look at when assessing our leverage position. At the end of 2011, our debt to cash flow on a trailing 12-month basis was approximately 1.4x, below the peer average of 1.5x. At the end of the first quarter, our debt to cash would have fallen to about 1.3x trailing the cash flow.

Debt to average daily production at the end of the year was about 14,000 per flowing barrel, again below the peer average of 16,600. At the end of the first quarter, this metric had dropped to approximately 13,000 per flowing barrel. From when we first entered our transition to now, we've remained a strong mid-investment grade company. Our diverse portfolio both in a geographic and hydrocarbon sense has been beneficial especially to this trade of lower North American gas prices.

When we began the transition in May 2008, our net debt was $4.2 billion, approximately same level as our $4 billion in net debt at the end of the first quarter of 2012. I believe the debt capacity of the firm has increased quite significantly over this 4-year period because operationally, the business is strong and more profitable as evidenced by the recycle ratio and F&D improvements that John referenced in his earlier comments.

The rating agencies also recognize this and this is one of the reasons we are removed from negative watch in Moody's in April 2010. Finally, a word on hedges. In order to protect the balance sheet, we do enter in commodity hedges from time to time. This year, we have 50,000 barrels a day of Brent collars in the first half of the year, approximately 30,000 are hedged in 90 by 150 collars and 20,000 are hedged in 90 by 125 collars. In the second half of the year, we have 30,000 barrels per day of Brent hedged, 20,000 of which are 90 by 150 collars and 10,000 of which are 90 by 120 collars.

So we protected approximately 60% of our economic exposure to oil in the first of the year, and 35% to 40% of our economic exposure to oil in the back half of the year. When I say economic exposure, I mean our exposure to oil post taxes and royalties. We currently have no hedges in place for past 2012. However, we are looking at potentially entering into some oil hedges going forward, given the current oil features curve.

So with that, hopefully it's given you a little bit of context on the soundness of the balance sheet. And, Tony, I'll pass it over to you to talk about the North Sea business.

Tony Meggs

Good morning, everybody. Am I on? Yes, my name is Tony Meggs, Executive Vice President of Special Projects. As John said, I've been acting as the EVP for our International Operations West since the middle of December last year, and I have to say that I am delighted that the cavalry is now arriving in the form of the highly experienced Paul Warwick. So having said that, while I welcome Paul, I should also take this opportunity to say what a pleasure and a privilege it has been to work with my colleagues in IOW, and it's given me the opportunity to understand the firsthand the real nature and value, underlying value of our North Sea businesses.

So let's take this little clip off here. I'm going to focus today on our North Sea operations in the U.K. and Norway. But before I get down to business, I'd like to introduce 3 of my North Sea colleagues John, [ph] Managing Director of our Norwegian operations, please stand, the very distinguished; Jeff Holmes, who holds an equivalent position in the U.K. even perhaps more distinguished; and Roy Bucket, [ph] our most senior and most distinguished Operations Vice President from the U.K. North Sea. I'm pleased they're here, and they will be happy to speak with you during the breaks.

Jeff and Roy have a poster. It serves as a backdrop because they can really demonstrate to you and explain how we're maximizing value from our assets in the U.K. And I know they will look forward to sharing with you, and I encourage you to visit them. So over the next 15 to 20 minutes, I will describe the nature of our business in the North Sea. In a nutshell, this is a mature business and a business that has definitely challenged us over recent years. But one that continues to provide strong cash flow for the company, one that contains many attractive investment opportunities going forwards and one that remains an important strategic part of the Talisman portfolio.

First, let me spend a moment on safety, both personal safety and process safety, which is our highest priority. As you can see, we're making progress on all fronts. Personal safety has improved strongly. We've reduced our lost time injury frequency by 75% over the last 4 years. And so far in 2012, we've had no lost time injuries at all. This is the result of sustained effort and commitment throughout our operation. And if you were to visit our facilities in the North Sea, this effort would be very apparent.

Still the unintentional hydrocarbon releases are 2 measures of our process safety. As you can see on the chart here, we've made huge progress in reducing the number of spills. We haven't done quite as well around unintentional hydrocarbon releases. Apart from continuous improvements to our operations management system, we have a number of programs underway specifically designed to address the issues of unintentional hydrocarbon releases. Through the first quarter of 2012, we've seen improving performance in this vital area.

Before describing our North Sea strategy, let's pause for a quick look at an overview of our business in the region. Our operations are comprised of multiple fields and reservoirs, some of which are subsea developments, tied back to central processing platforms, which, in turn, are interconnected to form the hub shown on this map.

We have 5 major hubs in the North Sea; 3 in the U.K.: Flotta, MonArb and Greater Fulmar; and 2 in Norway: Varg and Gyda. Altogether in our North Sea operations, we have interest in 52 separate fields, the majority of which we operate. The North Sea generates substantial cash flow around $5 billion over the past 3 years. We have a large resource base of over 0.5 billion barrels and stable, ongoing production over the next several years. We have considerable growth potential beyond that from some major projects that I will describe later on in my talk.

Our North Sea business is expensive and material, but also focused with a high average working interest and high levels of Talisman operatorship and control. The sharper eyed among you, which I suspect is all of you, will have noticed that I have not included EMA on this map or on in the forward projection -- production shown later in this presentation.

We use a simple framework in thinking about this business. There are, in essence, 4 components to our North Sea strategy. First and foremost, we need to maintain and optimize our base production. This is about maintaining the safety and integrity of our plant and equipment, including our extensive stock of more than 400 productive wells. We spend around $400 million per annum on the base. And experience indicates that little level of continuous investment is required to maintain the integrity of our plant and equipment.

Second, we optimize and improve the recovery process in our existing fields and reservoirs through a thoughtful program of infill drilling, wells drilled within the boundaries of our existing fields. The relatively wide well spacing in the North Sea combined with an ever improved, ever improving understanding of reservoir complexity means that we're continuously assessing areas of the reservoirs where we can improve recovery by drilling additional wells.

We currently have an inventory of 60 or so such infill targets generally with very attractive economics as I'll show on a later slide. We continuously refresh this inventory as we deplete the Hopper through drilling. We -- as we deplete the Hopper through drilling, we also replenish it with additional targets identified as the result of ongoing reservoir studies.

Next come major projects, which help revitalize the portfolio. We have 2 particularly large redevelopment projects moving through our project development system in the North Sea at the moment: the Montrose area redevelopment and the Auk area redevelopment. I'll give you some more color around those shortly.

Flyndre/Cawdor is a subsea project that will develop around 7 million barrels of additional resources, and also extend the economic life of the host platform pride by 11 years. Such tiebacks are highly synergistic. By extending economic life of the, platform additional reserves can be produced. And this extended lifetime can also create opportunities for additional drilling from the host platform. And finally, infrastructure led exploration provides the opportunity to refill the development Hopper. The focus here is on closing exploration to discover accumulations, which can be tied back to existing assets, hence the term infrastructure led. We have reasonable track record of this type established discovery. For example, Godwin, Haley and Shore in recent years.

I'll come back to each of the components of our strategy shortly, but first I want to provide a picture of the strong positive cash flow characteristics of our North Sea business. On the left-hand bar of the chart on the left, we show cash flow. Historically, around $1.6 billion a year over the last 3 years, higher going forward, given our current oil price expectations. We compared that to CapEx spend, which has a strong positive free cash flow that we have achieved historically. Over the past 3 years, our cash flow has averaged more than $550 million a year, and we can continue to anticipate strong positive free cash flow in the future.

As indicated, base capital expenditures of the order of $400 million a year are necessary to keep our plant and wells in good order. The remainder on the capital side is discretionary. For planning purposes, we're showing here around $250 million to $300 million a year in infill drilling, and then of the order of $600 million to $800 million a year for major projects in the medium term. It's, again, a discretionary investments that may change as a result of business circumstances and individual project economics.

Some of these project economics, in turn, will be impacted by ongoing discussions with the U.K. government about the brownfield allowances promised in the recent U.K. budget.

Across on the right gives an indication of the significant incremental production of certain natural field declines, which would result from that pattern of expenditures. The production show over the next 4 years comes from infill drilling and some of our smaller projects. Production from the major projects, as John mentioned earlier, comes later in the decade. From 2016 to the end of the decade, we'll see incremental production increase to between 40,000 and 70,000 barrels a day as production from MonArb and Auk along with the continued infill drilling program hits our bottom line. Given that strong cash flow picture, let me now go into a little more detail on each element of our 4-part strategy to show you what we're doing to deliver long-term value from these mature assets.

The first element is optimizing the base. We are focused on continuous improvement of our base operations and production -- I'm sorry, the focus on continuous improvement of our base operations and production through investment in people, process, by which I mean the way we work and plant.

This is a busy slide. I'll say that again. This is a busy slide, and various improvements never sound very exciting. But this is really an incredibly important piece of work to Talisman. The price is enormous as each percentage point of efficiency improvement adds around 1,000 barrels a day to our production.

I should stress the importance of people in maximizing the value of our assets. Over the past year or so, we have been able to attract some of the best operational leadership from across the North Sea. And they, in turn, can attract the best people and have attracted the best people to work within their organizations. The quality of these people underpins our continuous improvement plans.

We took a substantial step in 2011 by bringing around 170 offshore supervisory staff from contract positions into the company as full-time employees. That has allowed us to increase their training and ensure that they're fully in line with the objectives and values of the company. Running mature offshore assets is a challenging business. First-class people working together in a well-planned and highly disciplined manner are the critical ingredients, and we also have to continuously upgrade and refresh critical elements of our plants to improve reliability.

The 2 charts here show a couple of examples of the sort of relatively minor, but highly cost-effective investments that we can make -- we are making on a regular basis through our facility improvement activities. The chart on the left demonstrates how a relatively minor investment in new pumps, in motors at Auk has allowed us to increase production from the field. The other chart shows an example of upgraded pump capacity, allowing us to maintain higher reservoir pressure and enhanced production from the Claymore field, and those are just examples from many.

The overall objective is to improve our operating efficiency, which rose to 72% in 2011 in the U.K. and which we plan to increase to more than 80% in the coming years. Our Norwegian operations I have to say generally operates at very high efficiency already. As I have said, it's difficult to convey the nature of this base activity in a short presentation or even, probably for me, in a long presentation, which is why we've asked Jeff and Roy to add some texture with their poster sessions later on.

Second element of our strategy is infill drilling. As I said, we currently have an inventory of more than 60 wells to be drilled. This chart provides our view of the wells we expect to drill over the next few years. These are all discretionary investments. So we can vary the pace of our drilling activity as a function of our investment appetite at any point in time.

As you can see infill activity reduced a few years ago largely due to prevailing market conditions, but we're stepping this up going forwards. At current oil prices, these represent very attractive investment opportunities. The chart at the bottom shows the economic indicators for several wells from the 2012 drilling program. The wells have excellent economics, generally come on to production with high initial rates creating rapid paybacks and excellent returns.

Infill drilling is the bread and butter of maximizing the value from our legacy assets. These opportunities require rigor and discipline to ensure that we invest in the right targets. The importance of impact of infill drilling to our business in the U.K., we recently created a new resource renewal organization staffed with experience subservice pressures. This will allow us to pick up the pace in drilling out our program and create further targets to add to the Hopper.

Now let me turn to the third element of our strategy, major development projects. Strategically, major projects are quite different in character to the infill drilling activity I described earlier. Infill drilling is characterized by multiple relatively small-scale individual well decisions. Risk can be managed through good technical work and through the portfolio effect where good and less good outcomes can balance out over time.

Major contract -- major projects in contrast enlarge discrete investments with a different risk profile. Risk is managed through appropriate amounts of front-end engineering and meticulous planning. Our current intention is to reduce the risk in large capital of these -- exposure of these projects further by diluting our high equity positions over time.

Before I talk about the specifics of the Montrose area redevelopment project, let me mention the considerable improvements that we've made in project capability across the company in the last couple of years. Having appointed a global head of projects since 2010, we have improved project processes and assurance through fully implementing a project development in system across the company.

In addition, we've attracted over 20 very high quality senior project managers to lead our major projects. Project leadership is critically important. Good project leaders create successful projects.

Turning to the specifics of Montrose. This project has a number of components. Firstly, we'll be developing and tying back 2 undeveloped fields, Kayleigh and Shaw, to the Montrose field. Secondly, in order to accommodate these new fields, we'll be building a new Bridge Linked Platform adjacent to and linked to our existing Montrose platform. This allows us to create new processing facilities while at the same time, using some of the services and accommodations from the existing structure.

The objective here is in part to minimize brownfield activity, the cost of which can be difficult to control in old facilities. Thirdly, we will install a new modular rig on the Montrose platform to drill a number of exciting infill well opportunities that have been identified through advanced seismic imaging. The project will develop around 50 million barrels of new reserves, it's expected to start production in around 2016 and peak 20,000 to 25,000 barrels a day and will also lead to a substantial improvement in operating efficiency as we'll have new processing facilities. This project illustrates a number of the points I made earlier. Development of the tieback projects extends the life of the field from 2017 to 2030, incidentally deferring our abandonment liabilities by at least 13 years. This then creates additional base production and reserves. Furthermore, the extended field life provides the time and the incentive to pursue an infill drilling campaign that otherwise would not have been possible. In technical terms, this is known as a triple whammy.

No, it's never going to work. It's not going to work. In technical terms, this is known as a triple whammy. This is a major project by any standards, particularly in a mature basin. Sorry, particularly in a mature basin such as the North Sea. I should emphasize that while this project has attracted characteristics. It has not yet been sanctioned within Talisman. The project does not yet quite meet our internal capital efficiency hurdle, very, very close. We will be seeking some additional relief in the form of the recently announced brownfield allowance to tip the project to the hurdle.

Another U.K. project with similar scale, but a little behind in the development process -- behind the Montrose project is the Auk area redevelopment project. This project is designed to drill up to 12 extended reach wells into the hitherto undeveloped flanks of the Auk field to develop 46 million barrels of new reserves. In the interest of time and not to try your patience, I don't plan to go over the details of project other than to say that we expect production start up again around 2016 with peak rates in the range of 20,000 to 25,000 barrels a day. We also expect significant improvements in operating efficiency as the result of this new equipment.

Next slide. Let me finally give you an example from our Norwegian business where we also have strategies in place to extend the life of our existing assets. The Varg field, it's currently producing around 8,000 barrels a day net through a wellhead platform tie back to the floating production storage system where oil is processed and stored before being offloaded to tankers for transportation to market.

We have a number of opportunities to create additional resources and extend the productive field life. We have firm plans for a number of infill wells and a gas export project. Over much of the field life, gas has been reinjected into the reservoir for pressure support and for storage as there are no gas export facilities.

My colleagues are having a conversation [indiscernible]. The gas export project will allow us to produce this gas through a subsea pipeline over to Rev, which does not have export capability. Beyond that, we have a significant undeveloped resource in the nearby Grevling discovery, although this tie back project is still at an early stage of development with considerable uncertainty attached. We then have additional exploration drilling in the area, which may add further tieback opportunities in the future.

So in summary, I'd like to leave you with these 5 key points about our North Sea business. First, the North Sea has generated strong cash flow for the company and can continue to do so for the foreseeable future. Second, we are focused on improving plant integrity and operating efficiency through sustained investment in people, process and plant. Thirdly, we have a Hopper of attractive infill drilling opportunities with excellent economics, and we will continue to replenish that Hopper as we identify additional opportunities in the future.

Fourthly, we have a number of major projects that have the potential to revitalize the portfolio and provide a further platform for growth down the road. And finally, we'll continue our program of infrastructure-led exploration to replenish the development Hopper and extend the productive life of our existing infrastructure. The North Sea remains an important part of the Talisman portfolio and can continue to make positive cash flow contributions to the company for many years to come.

Thank you for your attention. I now hand you over to Mr. Blakely to talk about Southeast Asia.

A. Paul Blakeley

Thanks a lot, Tony. I'll try to be as quick as possible because I know you're desperate for cigarettes.

Good morning, ladies and gentlemen. I'm Paul Blakeley, and I'm Executive Vice President for our international operations in Asia IOE. And I'll now describe our Southeast Asia portfolio, take the next 20 minutes or so to review the business environment and our key activities in the region. I'll touch on 4 things. First, I'll briefly describe how we've continued to deliver on our strategic promises of the objectives safe, profitable growth and pretty much as we described 12 months ago. Second, I'll spend a few minutes giving some new context to the gas markets in which we operate and why I still say gas in Asia is good. And third, I'll walk through how we're doing on some of the key projects and activities that we're carrying out. And finally, explain why we believe Talisman is still in a very strong position to continue to grow our business in Asia.

Before all this, some introductions I think. Here today from international operations east is Ron Aston, the General Manager in Malaysia; Ron at the back there; Paul Atkinson, General Manager for Papua New Guinea and Australia; and finally, Paul [indiscernible], who's our Commercial Vice President in our business. And obviously, they'll be delighted as well at the break or over lunch to talk more about their particular areas of the business.

Now since we launched our strategy in 2008, production in Asia is up 9% per annum over the last 3 years with cash flows up 14% per annum, boosted in part by improving prices.

Well, I will say we'll likely achieve 5% or so production growth in this current year, the growth steps are lumpy. We do remain absolutely clear that in the longer term as we look out for 2016, we expect to maintain our average of around $0.08 to $0.10 production growth per annum from the Asia business.

Our activities in the region have generated cash flow beyond our reinvestment needs every year even while the business has grown, and this pattern looks set to continue with free cash flows increasing significantly as production and potentially prices continue to rise. I'm also very pleased that this growth has been achieved alongside an improved safety performance where we've seen a 70% reduction in lost time injury frequencies since 2008.

This is top quartile performance, and we are very focused on maintaining a safe working environment for all our people across all our work sites. So overall, our Asia business is on track to deliver its promises. The gas story in Asia continues to evolve as economic growth in all the economies in the region maintain their momentum.

From -- data, GDP growth across Asia is expected to remain in the 5% range per annum out to 2020. In order to meet this growth, together with the underlying primary energy demand that goes with it, gas prices, which have risen over the last 5 years at an average of 10% per annum across the region, might be expected to maintain similar momentum in the medium term.

So let's wind the clock forward to 2020 under the business environment of rising GDP across the region. Both Sierra [ph] and Wood Mac, for example, project the supply-demand gap for gas as being likely to exceed 25 BCF a day in the Asia-Pacific region as a whole or 8 BCF a day in our 4 main domestic markets in Southeast Asia as we show you on the right-hand chart there.

In response to this, we're currently witnessing a variety of incentives by host governments to encourage upstream investment in order to boost domestic gas supply. It may well be that this is actually too little too late with gas production peaking in Malaysia and in Indonesia. And evidence of growing reliance on LNG imports to make up the supply gap with regas facilities being built in Singapore in Indonesia and in Malaysia. Singapore represents an interesting conundrum in the market with no domestic supply of its own, willing to pay premium prices for secure piped gas from Indonesia. Singapore, in some ways, sets the benchmark in the region. Talisman benefit very specifically from this with around 300 million cubic feet of Corridor gas feeding the premium market of Singapore at prices currently running at $19.50 per mcf.

At the other end of the spectrum, all of the legacy, fixed-price gas contracts generally set over 10 years ago, for example in Indonesia and in Vietnam, are still in the range of $2 to $3 per mcf. There's a huge arbitrage here which we now see being unwound, and I'll explain a bit more of this in a moment.

But in the meantime, with demand increasing and concerns for security of supply growing across the whole region, coupled with LNG pricing and the mix as I've explained, there's a lot of upward pressure on existing gas contract prices, pressure on new contract prices and also pressure to maintain oil price linkage in gas contracts.

Though coal is also predicted to gain more share of the market in power in Asia, reliability in supply, environmental issues and the cost of new build all favor gas. And therefore, price in the region may well increasingly be set by LNG.

Now for those of you who are regular readers of The Jakarta Post, you'll be well aware of the push by the Government of Indonesia through its regulator, BPMIGAS, to force significant price increases in all domestic legacy gas contracts. Under the headline, No higher prices, no additional supply, the government expresses the concern that uncompetitive pricing is stifling investments and contributing to a shortage in domestic gas supply. This is coincident to the first LNG shipment being offloaded at Pertamina's new regas facility at Jakarta with a price believed to be around $12 per mcf.

So it's under this prevailing sentiment that Talisman was able to successfully renegotiate the anchor gas contract with Jambi Merang, when we bought the undeveloped asset in June 2010. As a result, and inclusive of some volumes that we do sell at a premium to Caltex in the north, we currently enjoy an average price at Jambi of $6 per mcf compared with the original fixed-price contract of $2.65.

So as The Post goes on to report, both Pertamina and ConocoPhillips have been negotiating with the support of the regulator with the same outcome for their Pagar Dewa and Corridor assets, respectively. And today, we have announced that these negotiations have reached their conclusion. And in a press release, the Chairman of BPMIGAS, Raden Priyono, explained that the signing of these agreements will be a milestone for the gas industry. The press release quotes the Corridor PGN price increasing from $1.85 per mcf under that contract to $5.60 per mcf immediately, and then rising to $6.50 per mcf by 2014, 3% per annum thereafter. The benefit this year to Talisman will be relatively small because we're going to unwind some take or pay gas within that contract but, thereafter, will be worth an incremental $80 million to $100 million per annum in free cash for the remainder of the PSC. The value of this to Talisman is in excess of $600 million in MPV.

In 2011, Talisman benefited from production weighted almost 3 quarters to oil or oil-linked gas. As we look forward, this reduces over time to just under 2/3 in the portfolio, though as I’ve described fixed-price contracts seem to be enjoying significant price increases, too.

In 2011, our Asian business contributed around 1/3 of the total gas produced by Talisman. And their current prices helped offset what we're seeing in North America. The record prices and netback last year in Asia have already been exceeded by first quarter realizations with the average price today running at almost $10 per mcf and netbacks up to $5.80.

Just to give you a sense of liquids pricing, too. With most of our Asian crudes receiving premiums to Brent, last year our average price realization was $116 per barrel and, in the first quarter this year, has increased to $125 per barrel with a netback of over $58.

So now turning to some of the areas where we're currently very active. I'm going to spend just a couple of minutes describing our investment plans for our existing production base, which on this chart is shown in orange, and our plans for development, which is shown in green.

This year, development capital will be primarily focused on Corridor in Indonesia, on PM-3, which straddles the Malaysia-Vietnam border; on the development of the Hai Su Trang and Hai Su Den fields in Vietnam; and on expansion at Jambi Merang in Indonesia.

Additionally, in Malaysia, we've now added the Kinabalu field to the portfolio, which John mentioned earlier, which will provide additional oil volumes in 2013. These activities provide the solid foundation to layer on future growth opportunities. In Papua New Guinea, we continue to execute on our gas monetization strategy, which is now largely funded by Mitsubishi, and we're also preparing an early liquids production scheme there.

And finally, we're active in the exploration basins in Nam Con Son in Vietnam and offshore Sabah in Malaysia, which I'm sure Richard will touch on later.

So now first, to Corridor, which remains our single largest asset by production and reserves with growth sales gas running at over 1 Bcf a day today. Corridor feeds several key markets, to Caltex in North Sumatra to Singapore and Batam and to the rapidly growing industrial areas around Jakarta in West Java.

As I touched on earlier, we see strong price growth in all these markets, and we aim to capitalize on this with a number of investment programs focused on debottlenecking facilities and increasing overall throughputs. Examples are compression upgrade at Dayung, additional wells in Sudan and the reactivation of Latang [ph], Tangguh and Rawa, which are old fields shut in several years ago and yet with material gas reserves still to be produced and which will benefit from new pricing.

The objective over time will be to increase output significantly through successive activities, all this while Corridor sales price average $10.70 per mcf in the first quarter this year and a netback of $6.16 and set to rise further now that the legacy gas contract negotiation is agreed.

A final point is the growing free cash associated with Corridor, which, at $360 million last year, will again benefit significantly, as I've already explained, from the new gas price.

And now moving to the Malaysia-Vietnam border and focusing in on the PM-3 commercial arrangement area. This asset, which we've operated for over 10 years now, has provided a stable base of flat production with a reliable stream of free cash flow to help fund further growth in the region. 60% of production is gas, drawn in equal volumes both north of Vietnam and southwest to Peninsular Malaysia. The other 40% of production is a high-quality crude premium priced and with upside potential. Once again, through investments in facilities and drilling, we now see growth options both in gas as well as oil, subject to a granting of a license extension by the host governments, which we're currently working on.

We're targeting 75 million barrels of additional oil recovery and over tcf of gas. The large number of infill drilling options will maintain activity for the next several years with an inventory recently boosted by a successful new flank play, which proves a stratigraphic trapping mechanism within the license area. This has resulted in 3 out of 3 new oil discoveries in the last 18 months with many more targets identified on seismic. Here we're doing what we do best: managing utilized assets with complex, multiple reservoirs for maximum recovery and, as this slide shows, generating significant and growing free cash flow.

Now moving further north to Vietnam, where we recently sanctioned the Hai Su Trang and Hai Su Den development in Block 15-02 in the Cuu Long Basin. These are 2 oilfields with reservoir upside, which are being developed by 2 small wellhead platforms tied back to infrastructure. Project progress is on track, 33% complete overall to date, with the jackets due to be loaded out for installation later this year to allow drilling to go ahead during the winter and then placing the topside early next year with first oil by second half of 2013. The development utilizes existing infrastructure close by, resulting in significant capital reduction for this project. And it has access to the gross egress capacity of 15,000 barrels of oil today together with other processing services.

The chart shown here on the right gives a clear picture of how quickly this project pays back. And the asset will throw off a lot of free cash in the medium term.

And now to Kinabalu, the latest addition to our business. I'm delighted with the award of this asset, which sits in shallow water offshore Sabah in Eastern Malaysia. Agreement has just been reached with PETRONAS to relicense this oil-producing asset to Talisman with a view to investing in numerous production enhancement activities, which we expect will add significant reserves and production over the 20-year license period. A transition plan is being prepared for the rest of this year, and we'll take over operations at year end. A number of early investment wins have been identified, and we expect to add up to 8,000 to 10,000 barrels of oil per day, net to Talisman, in 2013 with the potential to increase this significantly in the future.

We've agreed novel PSC terms with PETRONAS, which are similar in structure to all existing contracts in Malaysia, have a new progressive component, which benefits Talisman as the contractor based on add-in production and reserves. This is the perfect commercial alliance for us.

And finally, it's worth noting that the Kinabalu PSC is next to our existing and highly prospective Sabah Block 310. And the synergies here will promote activity, enhancing the value of exploration success, which can be more readily and cost-effectively converted to production. This is a great addition to our business in Malaysia, and it does play very well to the skills and capabilities that we built there.

And so finally, let's take a look at Papua New Guinea, where we've made good progress since we talked to you last year. And we're very pleased with what we see. Two years ago, we laid out a very clear strategy for Papua New Guinea, which we're now following through. We built up a very large base and dominant position in the Western Province with over 14 million acres containing a number of gas discoveries. Since then, we've shot several seismic surveys and, with this data, started to build a picture of the basin and to high grade in the center and relinquish around the edges.

We drilled 3 -- I'm sorry, I think we drilled early successes at Stanley and Ubuntu and this year have followed with Elevala-2 and Ketu-2. Both of these were set out appraisal locations designed to test for the gas-water contact. But both had full gas columns and came in 60 and 30 meters high to prognosis, respectively. The results signal material resource additions.

These wells have also confirmed the condensate-rich part of the basin with consistent testing in the order of 50 barrels per million cubic feet. As a result, and together with partner, Horizon Oil, we're evaluating an early condensate recovery scheme at Stanley, which we hope to follow with a far more material liquids development once our appraisal at Elevala and Ketu is complete. Overall, this could generate material cash flow within the 2016 planning horizon, and we're increasingly excited about this.

The other major element of progress in Papua New Guinea was the announcement of our strategic partnership with Mitsubishi, who will bring to their farm-in agreement a $280 million carry that will underpin our exploration and appraisal expenditure over the next 3 years. Mitsubishi also bring capability in LNG construction through their subsidiary, Tioga, their long-standing global LNG player, most recently with their Donggi-Senoro project in Singapore -- I beg your pardon, in Indonesia, which progresses well. And they will also bring world-class expertise in LNG shipping and in marketing.

The Mitsubishi funding will support drilling of up to 14 wells and the acquisition of around 900 kilometers of additional seismic. And we hope this activity will prove out the threshold resource volumes to allow front-end engineering for a larger-scale development scheme focused on LNG, which we believe can be competitive within the region.

As we assess progress to date, gas resource build is now approaching 1.5 tcf onshore when we include recent well results, and we have 3 more wells still to drill this year. And I know Richard will touch on this a little bit later as well.

So as interest and activity PNG accelerates, we're confident that the timing and strategy adopted by Talisman and the selection of Mitsubishi as a partner will prove pivotal in creating exceptional value in this part of our business.

So as I move to conclude the Asia story, just a quick recap on investments within the portfolio. In total, our capital spend across Southeast Asia will pull for, on average, around $750 million a year out to 2016. Within this total, the developments component increases year-on-year, signaling investment which will underpin short-term production growth, while exploration and activity -- while exploration and appraisal activity averaging around $200 million per annum will also provide a longer-term optionality for us. Exploration spend will focus on the continued activity in PNG, in offshore Sabah and in the Nam Con Son basin in Vietnam.

As for the development expenditure, Corridor, Hai Su Trang and Hai Su Den and PM-3 are all near-term uses of capital, while the PNG liquid development scheme, Kinabalu, expansion at Jambi Merang and further developments at PM-3 will all draw on capital out to 2016.

Just one key point while we're talking about capital investment. Predictable project delivery has also become a key success factor for Talisman in Asia. And this has been critical to us meeting our targets, both capital and production, but interestingly has also had the added benefit of us gaining access to new business opportunities by making us a partner of choice and recognized for our skills by regulators and national oil companies in the region.

And then as for production, our Asia business is delivering around 30% of Talisman's global total. Near-term growth is underpinned by the organic projects I described, and we'll keep looking to find new high-quality, inorganic solutions and options, like at Jambi Merang and Kinabalu, to build out the portfolio further.

Cash flows from operations in Asia business will more than meet the capital requirements for all these activities, as it has in the past, with post-tax free cash set to increase significantly as new production comes on and as regional gas prices maintain their upward momentum.

So by way of wrapping up, let me summarize by saying that our Asia business continues to excite us as we maintain momentum and deliver on our promises. We're finding and producing oil and gas in the most vibrant and rapidly growing region in the world, a region where the demand for primary energy continues to outstrip supply at a pace that gives us access to opportunity, to price upside and to value creation like nowhere else.

We've worked hard over many years to build relationships that have helped us to access new business, such as exploration in the Nam Con Son Basin in Vietnam and such as Jambi Merang in Indonesia and Kinabalu in Malaysia. And in the meantime, our people on the ground carry out their activities with excellence, giving increasing confidence in safe delivery, on time and on budget.

I'm extremely proud of the teams in our Asia offices and the work they do. And I recommend you come visit us so you can also be compelled and feel what's going on in the region and by the value that we're able to create there for Talisman.

Ladies and gentlemen, thank you for your attention. You've been very patient. I'm now going to hand back to John for a question-and-answer session before we break. Thank you very much, indeed.

John A. Manzoni

Ladies and gentlemen, right, we're going to have -- we're going to do questions on IOW, IOE. And we'll save the general questions for the end, unless you insist. But why don't we take any questions that anybody may have right now on what Tony talked about in the North Sea or Asia.

Question-and-Answer Session

Unknown Analyst

A couple questions on the North Sea. A couple of questions on the North Sea. In your slides, you talked about the number of infill wells that you expected to drill per year, which seems to be about even in '12, '13 and picking up again more towards '14 and '15. The production increase from infill wells seems to be more front-end loaded in '12 and '13. Can you talk about if there's any differences in the productivity of some of the earlier infill wells, and then what you're expecting in terms of grow productivity from those infill wells relative to what you've seen in the past?

Tony Meggs

Gosh, yes, a little bit. I mean, first of all, some of these wells in the area, particularly a couple of Norwegian wells, really are quite big. I mean, John then said that it's clear that we have a well that we're about to start drilling in the Red field, which these wells can come on at 10,000 barrels a day easily. So some of the wells are -- identified wells right now are really quite high-potential wells. Some of the other infill wells have maybe 2,000 or 3,000 barrels a day. I don't think you can identify from my chart a gradual degradation of quality over time. I think that would be slightly over-engineering what I have intended here. But yes, the characteristic of North Sea is that some fields just have enormously high rates, which is great. The corollary of that is that when those wells go off production, it's like a big earthquake. So the good news is we've got some great wells, the bad news is sometimes those wells don’t play. But no gradual trends here. It's a hopper [ph].

Unknown Executive

There's no trend. It's in -- implied in the chart, Brian. I think whatever you source, whatever -- and the way it happens, so they won't actually necessarily be drilled in that order either. But there's is a hopper in the pool of wells delivering -- and of course, what they're doing by design is maintaining the North Sea flat, of course. They're filling in the decline, okay?

Unknown Analyst

And then I guess on the projects component of it, you talked specifically about Auk and Montrose, which are big contributors in 2016 and beyond. You did have a nice bump up in project production contribution in 2014 and '15. Is there anything specific we should follow for the -- to monitor that contribution?

Tony Meggs

Well, these are smaller things. I think that there was a contribution, for example, from the development of the graveling field, which is a -- just actually a very extended well from one of our existing platforms. There is also in there later on the Varg gas exports projects. So I mentioned that briefly, but that actually does show up in that time frame. So these are smaller scale. Important contributions but smaller scale the chart that show in that. There's probably something else.

Unknown Executive

When did Splinder [ph] -- when does Splinder [ph] come one?

Tony Meggs

Oh, Splinder [ph]...

John A. Manzoni

Is that -- Jeff?

Unknown Executive

2014.

John A. Manzoni

2014?

Tony Meggs

Thank you.

John A. Manzoni

Then Decodo [ph] comes on in that sort of time frame.

Tony Meggs

Yes, those will probably be the 3 most significant ones.

John A. Manzoni

Any other questions on Asia or the North Sea, please? If you could say your name for everybody and then...

Unknown Analyst

Sure, it's Khan Orrin [ph] from the [indiscernible] Pension Fund. Just regarding Montrose, so the relief that's required from the government, I think it was up [ph] as being a tax relief of roughly $0.5 billion, was it? I'm just curious, what sort of relief are you expecting? And when -- how optimistic are you and when might you expect that relief to be in place?

John A. Manzoni

Let me frame the optimism, please. While either Tony or Jeff talk about the -- so let me just give you a little context because the government, of course, in the U.K. slapped up the tax in a fairly arbitrary way. So we all got bolshie and went back and said, "Well, if you're going to do that, then we're not going to do the following things." In fact, we actually quite deliberately paused [ph] forced on one of these projects to make a point that actually, they had missed the subtlety of what that did to ongoing projects around in the U.K. I think we are actually very confident the work that was done by the industry actually, led by Anaus [ph] who's now -- was then our finance manager in U.K., led to a very successful, I think, understanding by the U.K. Government that they had sort of probably acted a little quickly. So what's happening -- it's not a terribly satisfactory outcome in terms of the tax regime, but what's happening is they put the overall tax up and now they're in a series of bilateral discussions with every operator, talking about how they're going to enable certain projects to move forward. So we're actually, I think, in those discussions and pretty confident that those projects will move forward. And you're hearing us saying subject to because, of course, we're still in a conversation with the government to say, "It ain't moving forward unless there is some help here." Actually, the engineering of the project is making it increasingly robust, both of Auk and Montrose. So that's actually good too. So I think we can be pretty confident this will move forward. I don't actually -- do you know the numbers?

Tony Meggs

About $0.5 billion. I mean, we -- the Montrose project has already benefited from a change in the small fields allowance that has helped the economics. It really looks quite good and that we've -- and we're looking for a little bit more help just to get to a sort of 0.3 GPI [ph]. So -- and by the way, Mr. Warrick [ph] also and Jeff, they've both been deeply engaged in these conversations all in a different context. So they can provide you an infinite amount of detail should you wish later on.

Unknown Analyst

So neither Montrose nor Auk have been sanctioned?

John A. Manzoni

Not yet. No, I think we're expecting a sanction later on this year and quite deliberately holding them up pending finalization of the government discussions. But -- so we're just sort of hedging a bit because we can't blast forward. Well, actually, we don’t want to blast forward with the project, but that can't yet benefit from government relief, okay? Anything else on either Asia or the North Sea?

Unknown Analyst

Just a question on the North Sea operations in general.

John A. Manzoni

How come you're not going to ask a question about Asia? Go on.

Unknown Analyst

You do talk a lot about improving reliability, but the fact is that the quarter-to-quarter variability in production has been one of the most unpredictable parts of the business. And I just wonder if you can point to sort of the major causes of the unpredictability. And what are these bumps along the road? I guess can we, going forward, expect these bumps to continue? Or is there really some progress that can be made? Or is it just a standard part of the nature of the North Sea business?

John A. Manzoni

Let me give a high level and ask Tony to talk about what the bumps are that we're seeing right now. But at a high -- I mean, I think it is quite important for -- so the general context on this. I think that the North Sea business continues to be for us a -- I mean, when you put incremental investment into the North Sea, it is a fabulously remunetory [ph] business. So this thing is worth persevering to some degree. It's not worth -- and you heard me say a year ago that the variability of the North Sea, as Tony just said, you get a well that falls over and it might be 20,000 barrels a day, knocks the company. That variability is an issue for Talisman and has been an issue for Talisman. We had it in a nice, tidy box for 2 years, and it popped out again. And here it is again. I have said that as a result of that, this company's total production is -- can't tolerate that sort of variability. So we intend to reduce our exposure to the North Sea for that reason. We're in various conversations. We can do it through dilutions. We can do it through various ways. Some of the projects we just talked about are super opportunities for investment into the classic sort of project for people. So we said we will reduce that. Now one of the issues, frankly, is that we have been slower than we might have hoped in really getting underneath what I would call the -- both the surface and the subsurface complexities of running in a mature field and mature profits. This company for years and years and years operated in the North Sea by virtue of acquisition and acquiring the next projects and acquiring the next project. It did not historically spend a great deal of time and attention really concentrating on the excellent operations of the projects that it then bought. And it was very successful. It grew. And there's no statement about success or otherwise of history, but history was one of acquisition. What we did 3 years ago is we turned that into a concentration and a focus on a stable production as opposed to growing production and a focus on operational excellence, both surface and subsurface. I would have to say to you that we were probably slower than we would, in retrospect, have wished to get the right people to concentrate on that transition. I will say to you I believe now, but only in the last 6 to 12 months, that we actually have put now -- we do have a team both on the surface and the subsurface who can actually improve that business and its fundamentals. And I believe we're beginning to see that improvement. It takes time, and I think it'll take some more time. But the underlying operations, the underlying reliability, the underlying forecast ability of the maintenance, the -- all the things that go to running that mature business are now improved, some of them here, complemented now by Paul who brings his enormous experience, which I think can only be beneficial. So in a macro sense, I think we turned the corner in that. That doesn't say we're not going to reduce our exposure to that. This is -- now, we still have ups and downs in the North Sea. And maybe Tony could describe some of the things that have caused this year or most recent wells or whatever it is...

Tony Meggs

I mean, I don't -- I think you've answered the question, John. I don't really want to go into to any detail other than sort of add a couple of things. One is that when you have, let's say, 80% operational efficiency, that doesn't mean that 20% of the time something is happening. So one has to sort of -- there is always a balance between how much money you spend and how much reliability you try and build in. You have to find the right balance. So there will be variability both -- from the wells. We had -- on New Year's Eve, we had a well go down, the Auk North #3, 3,000-barrel-a-day well. That's the kind of presents we got around Christmas time here. So even one little thing can make a difference that registers at this level. That -- those variabilities will stay. What we can do is we can drive up the underlying operating efficiency. It's all about getting the right people and doing things in a systematic way. We have some of the best people now in the North Sea. It's not overnight, and I would really encourage you to get real answer -- real -- to go and see these guys in the break, if you possibly can, and understand really what they're up to. It is impressive. But like all sustainable change, it -- sometimes, things gets a little worse before they get better.

John A. Manzoni

Thank you. Any other questions on -- somebody ask a question on Asia because -- yes, please. Now I'm putting you on the spot. Now it has to be about Asia.

Unknown Analyst

I actually wasn't going to ask a question on Asia all along. So my question is just on the gas price environment on Asia. And given it's been quite constructive recently, what sort of activity levels -- we went through this in North America, frankly, where gas prices had a bit of a blow-off and then technology, supply activity really caught up. So what are the sort of differences, opportunities, challenges just from a long-term sort of macro standpoint on Asian energy prices?

John A. Manzoni

Paul, do you want to have a go at that? Macro -- on what's going to stop Asia doing a North America on us, I assume?

A. Paul Blakeley

Well, I mean, there are many factors, which play into this whole principle of where ultimately prices will go. And, I mean, the first and fundamental point is that the supply-demand gap is there and is growing. And the Asia region growth story is unquestioned. And I think for them, a bad year is -- growth is down to 4% or something. So this underlying principle -- and you have to go to Asia to understand fully the energy and the drive of the growth that there -- is there. And once you understand that, that's the first fundamental that says the risk of something happening in Asia like in North America is probably a lot less. The second point is you have to understand that the choices for energy supply are -- it's not like North America with incredible infrastructure that can move gas around the whole region. And there is also a national component where security of supply country by country is protected quite fiercely and increasingly so. And so -- and then overlay the fact that increasingly, the energy gap is going to be filled by way more expensive gas LNG. The net effect is -- what I talk about principally is domestic gas, which sits in the $5 to $6 range and its nearest competitor is at twice the price. You feel that there's a lot of cushion that will ensure great comfort that pricing typically in the domestic area will continue to grow. And we feel all the time that it's just reinforced. And this latest renegotiation of the Corridor contract, it's just confirmation of that. Actually, on the day, BPMIGAS signed 6 new agreements for price adjustments. Corridor was the largest. Pagar Dewa was -- Pertamina was the second largest. But there were 4 others. And it's almost a bcf a day of gas that was renegotiated upwards by a huge margin. And yet the government is still delighted because even after that, there is seething [ph] domestic gas, which is still half the price of the alternative. So I think we feel pretty confident that gas pricing in Asia maintains that momentum, and the alternatives from a long way away, LNG, can be the only option. You don't seem likely to undercut that price.

John A. Manzoni

Okay, very good. Anymore, please?

Unknown Analyst

Another Asian question. You historically have funded internally in Asia. Clearly, we've been waiting for price improvement for a long time. We're now seeing it. I bet the gas rigs' return in Asia are going to become spectacular. Should you be accelerating your investment in Asia? A question on the U.K. Really, externally, outside of production, the biggest issue has been operating cost has been increasing. Can you talk about is there anything you can do to address that?

John A. Manzoni

I think I'll answer the question about accelerating investment in Asia because I know what Paul will say. I mean, the answer is actually of course. I do think there is an issue for us here in North America that, that business is not particularly valued inside Talisman's portfolio, in fact in the way that it probably can be, I think that is an issue. It's a sort of long-term issue. And I've always said provided the business is getting stronger and stronger, we can sort that issue out at the right time. And it is getting stronger and stronger. And I think so if we can find more things to invest in Asia, then I think we shall do so because it's a strengthening environment, it's a strengthening price, it's a good business and it's now increasing cash flow. The -- and you're seeing us do it. Well, Jambi Merang, Kinabalu and such things we're exploring in Asia. The opportunities, though, need a little bit of -- they don't fall -- just fall on a plate in Asia. They need some digging out. They often rely on good relationships, and I think, for instance, Kinabalu and actually Jambi Merang came as a result of the relationships that Talisman has built in-region with incumbent national oil companies. And I've said before, being Canadian is an advantage, being our scale and our size is an advantage. And having people who have good relationships at the top of those companies is a huge advantage. And the people in-region do that, and I think we do it well. And I think we're beginning to see the -- interesting that Kinabalu opportunity comes as a result of Malaysia Inc. suddenly realizing the thing that Paul has just been talking about. Actually, we're short of energy, and we're starting to import expensive energy we need. And we're sitting in not-so-terribly-effective way on all sorts of unexploited resource. They need some help. And the question is, who do they turn to for help? And that's happening across the region. So I think the answer to the first question is, if we can find the right opportunities, and it isn't -- we got to be selective, but if we can find the right opportunities, that will continue to attract investment because the returns are high. Costs in the North Sea, do you want to deal with that?

Tony Meggs

Yes, well, I'll have an initial go. First of all, I should say that in Norway, as John will be happy to elaborate, we actually benchmarked -- I can't see the question here, I apologize. We actually benchmark as -- it's certainly in the top quartile. It's not the best operating or operator with respect to operating cost. So we do have the ability to really do a good job here within the company. I'd say in the North Sea, actually operating cost is an absolute number, has risen slightly, 2012 on 2011, in our projections. Usually, because production is lower, and therefore a barrel is higher. Right now, I mean, of course, they're always a concern. I don't personally -- it's up to the new boss to figure this out, but I personally don't think this is the time for us to push too hard on that lever because we want to -- we're in a very difficult period. We're spending money to save money. That's where we are. That reflects in both capital and operating costs. And without giving any guidance to my colleague, new colleague at all, I hope that we can sustain that, live through that period so that ultimately, we can drive operating costs down a lot. Best way of getting operating cost down is by having fixed the problems. And many now fix the problems for the future. So that's where it is.

John A. Manzoni

Good answer. Any other questions anybody would like to raise? In which case I suggest we have a cup of coffee and Lyle is going to tell us -- when do you want us back?

Lyle McLeod

Yes, we're just on schedule, a little bit of behind. But I think, well, 15 minutes. We can be back in about...

John A. Manzoni

15 minutes. I'd encourage you to go and chat with the guys in the posters and talk to some -- in some more detail and be back in 15 minutes. Thank you. One moment.

[Break]

Lyle McLeod

Yes, can you hear me? Hello? All right, if we can all try to take our seats, please. That includes my boss. It's not often I get to tell my boss to sit down, and only once, I suspect.

Good morning, ladies and gentlemen. It's clear that the halftime festivities were keeping people very occupied and engaged, which is great actually. That's actually what we wanted, lots of dialogue out there. And after we finish this session, we'll have more Q&A, and we'll have the opportunity to do more question sessions outside. And hopefully, you'll be getting good answers from the people that we brought out.

So, well, before I start today, I would like to introduce some of the senior members of my cosmopolitan and debonair leadership team. Rob Broen, if you could stand up first? Rob up until recently headed up our U.S. business and has recently taken over our Shale business across North America. Ed LaFehr? Where are you, Ed? Ed at the back there heads up our Conventional business, primarily in Canada. And Tim Peper. Where's Tim? Tim's is our Commercial VP for North America.

Okay, we'll make a start with North America. 2011 was a year of tremendous delivery for our North American business. In the Marcellus where we had little to no production only 4 years ago, we're currently producing over half a Bcf a day. We've continued to look to deepen our liquids portfolio throughout last year. We added 8,000 net acres into our Eagle Ford business, not an insignificant task given that prices that Eagle Ford's acreage has been going for over the last 12 months. And we drove a land sale into the emerging Duvernay play in North -- in Alberta where we acquired an additional 180,000 acres to add to our existing 180,000-acre position in the play.

And of course, against the backdrop of a challenging near-term gas price environment, the focus this year has been to take decisive and rapid action to reallocate capital away from our dry gas shale plays and into liquids-rich opportunities across our portfolio. We've utilized the capital flexibility we've always said we've had to significantly reduce our activity levels in both the Marcellus and the Montney.

And at the same time, we've continued to build operating momentum into the Eagle Ford, and we've commenced de-risking our liquids-rich positions in the Duvernay and in the Greater Edson area of Alberta.

And finally, in the first quarter we've made a great start to meeting our $1 billion to $2 billion corporate disposition target with the disposal of $1 billion of nonstrategic assets in North America through the sale of our highly strategic coal mine in the first quarter, dry gas assets in West Whitecourt and a fairly nonmaterial but nice position in Shaunavon, all of which will close during the second quarter. The first one closed in the first quarter.

So moving on to safety. In North America, like the other businesses that you heard about today, we've made great strides forward in our health and safety performance and, indeed, our operational integrity performance last year. On the personal safety front, we were able to reduce our lost time injury frequency rate by nearly 60%. And for the first time in our business, we were able to approach the OGP top quartile benchmark for performance in this area. However, our performance in the first quarter this year, as you can see from the chart, highlights that ramping down is as challenging, if not more challenging, than ramping up operations.

And we're continuing to make strong progress in the environmental front. One of the most significant developments has been the publication of our shale operating principles, which John spoke about earlier, which has now publicly set out our position around responsible shale development, mutual benefits and indeed transparency throughout our business.

This slide is intended to represent where each of our major shale plays sits within the development life cycle. Our primary focus in the near term is the build-out of our liquids-rich positions in the Eagle Ford and Wild River whilst temporarily slowing down our activity in the Marcellus and Montney, 2 world-class shale plays with some of the lowest break-even costs in North America. And of course, we continue to look to de-risk the material positions we've established in liquids-rich issue areas like the Duvernay, Cardium and, indeed, our legacy position around our Greater Edson area.

Not only are we positioned in most of the leading shale plays in North America, we have done so in a material way that allows us to feel confident about the long-term growth of the business. At the end of 2011, our net contingent resource estimates were at around 40 tcf. This resource estimate does not include our last position in Québec nor estimates for the Duvernay and the Greater Edson area. We're at the very early stages of piloting and de-risking our position.

The running room in this part of our business is best illustrated by the chart on the right-hand side of the slide. To date, we've drilled only 4% of the circa 8,000 wells required to develop our material resource position across North America. And I'm pleased to say that we'll be more efficiently layering capital into our resource plays last year. Last year, our North American F&D cost was just under $10 a barrel, nearly half the level we were investing into the same business only 3 years ago.

We were able to do so whilst remaining relatively conservative in our PUD bookings. And at the same time, we've increased the underlying profitability of the business, doubling our recycle ratio between 2009 and 2011, a period when gas prices were relatively constant at $4 to $5 an mcf. And those were the days.

Furthermore, we've continued to drive down the structural cost base of our North American business, reducing your unit direct operating cost by nearly 40% over the last 3 years. This has been primarily achieved through the rationalization of our higher-cost conventional assets as we rationalized those whilst at the same time transitioning into low-cost shale plays. The current challenging external environment provides an ideal opportunity for us to continue to make progress in this area throughout our North American portfolio.

We've purposely built a business with minimum land retention requirements, providing us with a great deal of capital flexibility. The primary intervention has been to drastically slow down activity in our 2 dry gas plays, the Marcellus and the Montney, both of which require break-even gas price of around $4 an mcf.

In the Marcellus, we entered the year with 11 rigs, and in the first quarter took decisive action to reduce our activity set to a single rig. And similarly in the Montney, where, with the majority of our expenditure is covered by the carry arrangements we have in place with our JV partner, Sasol, we entered the year with indeed again 11 rigs but have quickly slowed down our activity set to 4 rigs and indeed intend to take further action to reduce our activity set down in the Montney down to 3 rigs in the third quarter. We anticipate spending only $200 million for the remainder of this year in these 2 dry gas plays.

At the same time, we've greatly increased the capital allocated towards our liquids-rich plays from 30% in 2011 to 65% this year. The majority of our liquids expenditure this year is focused on the Eagle Ford where this year, we anticipate spending around $1.2 billion gross, or $600 million net, to Talisman to continue to build out this business. And as a result of this underlying shift in capital towards liquids-rich opportunities, we expect to significantly grow this business over the next 3 years from around 20 mbd today to at least 65 mbd by 2015.

The primary drivers for this growth are the expected ramp up of production in the Eagle Ford, which I will discuss in a little bit more detail later on, as well as the completion of our turbo plant, our turbo [indiscernible] plant in the Wild River area, which is due to come on stream at the end of next year.

We have an extensive land position in the liquids-rich Wild River area with around 1,000 undeveloped well locations on our 90,000 net acre position. And we're at the early stages of a feasibility study to expand our Deep Cut presence in this area to maximize value from this opportunity.

The most -- probably the most dramatic example of exercising our capital flexibility, which I've already discussed, has been the reduction of our activity in the Marcellus down to a single rig. In the event of a sustained low gas price environment throughout 2013, we will probably curtail our activity in the Marcellus in a range of $200 million to $300 million per annum. And at these levels, we would be able to maintain all of our near-term expiries and minimize our PUD expiries. In doing so, as we minimize capital in the play potentially through as long as the end of 2015 and perhaps beyond, we'll be temporarily plateauing our business in the Marcellus at around 350 million to 400 million cubic million feet a day whilst retaining the flexibility to ramp up activity as and when gas prices recover.

So on to the Eagle Ford. In the Eagle Ford, we've assembled an attractive position of approximately 80,000 net acres in the heart of the liquids-rich window of the play. Whilst it's still relatively early days, we are highly encouraged by the results we're seeing across our position.

Last year, we established an office in Houston and built out our staffing levels to around 360 people, no mean feat in 18 months as I spoke in the office and indeed in the field. And we're now fully staffed to accommodate our current activity set of 12 rigs and 2 dedicated frac crews. As a result of continued improvements in our drilling cycle time, we now expect to drill approximately 100 gross wells this year without the need to ramp up to the 14 rigs we had originally envisaged. Put another way, we expect to do exactly the same activity but with 12 rigs this year.

One of the biggest challenges we face in 2012 is the build-out of our egress and indeed our midstream facilities, most of which are provided by third parties. I will discuss egress in a bit more detail in a moment, but it is the primary reason why we've maintained a relatively conservative stance in our estimates of 2012 production.

However, with the first quarter and a very good first quarter in the Eagle Ford now behind us, where we benefited greatly from being able to get just about every molecule away through interruptible transportation and with good progress in the build-out of our third-party plans for our white gas production, I'm now confident in resetting our full year 2012 expectations in the Eagle Ford to a range of 12 to 70 mbd.

Exactly where we end up in this range will be a function of both our continued access to interruptible transportation capacity and the timely completion of third-party processing infrastructure. And of course, we fully expect to carry a great deal of production momentum into 2015, en route to a business that we ultimately believe will be producing at 70,000 to 80,000 barrels of oil equivalent a day net to Talisman and become a free cash flow-positive business as early as 2014 when we can expect to enjoy self-funded growth for this important part of our business.

The Eagle Ford has proven to be one of the most attractive plays in North America. We know this not only from our own type peers, but also from the 600 competitor wells that have now become publicly available within the basin. However, this play is a highly complex play, spanning 150 miles just across our Talisman position from end to end across 5 face windows. For now, we have chosen to retain the previously disclosed average tight curve for our position in the play, an EUR of around 660,000 barrels of oil equivalent and a 30-day IP of 1,200 thousand barrels a day. By the end of this year, approximately 75% of our acreage will be held by production, allowing us to focus on prioritizing the development of our highest-value retrograde and volatile oil acreage positions from 2013 onwards.

Whilst it's early days in our D&C learning journey in the Eagle Ford, we have seen tremendous progress over the last 6 months. We've improved our drilling cycle time by nearly 30%, allowing us to bring wells on earlier and accelerate value whilst at the same time improving our D&C costs by nearly 20%. Last year, the best well we drilled, we call it a pacesetter well, we drilled in 53 days. This year, 5 months into the year, our current pacesetter well in the same basin is 24 days. So you can see the step changes that are being made within our business on the D&C side. And indeed, we expect to see much further improvements as we optimize our development of the play.

Our acreage position is some of the deepest parts of the basin. And hence, our average well depth this year of 17,000 feet measured depth is substantially higher than most of our competitors drilling in the shallower, lower-pressured parts of the play.

We're currently drilling wells from around $4.5 million, and we're completing wells for around $4.2 million. And we expect to exit this year with a total D&C cost exit rate in the range of $8 million to $8.5 million a well.

One of the biggest improvement levers we see as we look forward to next year will be our increased ability to utilize pad drilling, increasing from, say, 1/3 of our wells drilled this year, as we've been focused in on single-well drilling to hold land, to next year where, as I've said before, we've got 75% of our land held, and we'll be able to drill approximately 2/3 of our wells off pad drilling, which creates a huge amount of drilling efficiencies for us as we look forward.

We continue to be at the very early stages of understanding the optimum well and indeed completion design for the different parts of the play. This year, we'll be piloting a number of technologies, including highway, foam fluid stimulation and cemented sleeve completion technologies, to name but a few. In addition, we'll commence the down basing pilot, aiming to test bringing our current well spacing of 80 acres a well back to 40 acres a well in the volatile and black oil windows of the play.

Finally, we continue to look at opportunities to leverage the supply chain and are currently looking at options to replicate the successful direct sourcing of pulpit [ph] model that we've established in our Canadian business for our U.S. business.

And so a little bit on midstream and egress. We've been active in developing a range of egress and processing solutions to ensure long-term flow assurance from our extensive position across the Eagle Ford. A total of 7 major deals have now been completed with third-party service providers, and we're looking forward to a major step change for our wet gas egress by September this year, eliminating our current reliance on interruptible transportation. We will continue to layer in committed egress contracts in 2013, and we do not expect to be constrained by midstream nor egress from the third quarter this year.

In addition, we've completed a deal for 50,000 barrels a day of gross JV condensate capacity as the anchor shipper on the Magellan-Copano and Double Eagle line into Corpus Christi. In addition, we have the option to increase this bin capacity by further 20,000 barrels a day for the JV and the ability to flow 25% of our volumes over capacity at the same totals that we've agreed.

We'll move up to Canada into the Duvernay, where we're well positioned now with a material 360,000 net acre position within the emerging liquids-rich Duvernay play in Alberta. Most of the industry activity to date has been focused in the north, the northern part of the play, indeed the first 3 of our 6 wells planned for this year will be drilled and completed in the north.

Industry results to date have been encouraging, we've 12 wells released to date, another 2 wells released this week make it 14. The average liquids yields have been in the range of 50 to 300 barrels of condensate per million cubic feet with further upside likely through the processing of the wet gas stream. Our first 2 wells, which we've drilled and indeed, completed in the north have been very encouraging and we'll be completing our third well post-breakup before moving to the southern end of the play to drill and complete a further 3 wells.

The Montney represents one of the most material and indeed, strategic resource positions within our North American portfolio. The primary focus to date has been the early evolvement of our JV position in the Farrell Creek and Cypress A areas with our partner, Sasol, who will continue to fund the majority of the buildout until such time as the remaining $1.2 billion of carry is exhausted.

We've decided collectively to slow down expenditure in the current environment to a 3-rig program, allowing us to continue to deepen our understanding of the play, reduce our D&C costs and optimize the ultimate field development plan. We will continue this year to delineate the area for liquids-rich gas. As we move east in the area, we've observed liquid yields of up to 35 barrels per million cubic feet, in terms of condensate. In order to accommodate the early development of this liquids-rich part of the play, we've built out and increased our processing capacity in the area to 320 million cubic feet a day of gas, including a brand-new 140 million cubic feet a day refresh plant, which will be online later this month.

Our Montney position provides an enormous amount of flexibility to be able to ramp up at the appropriate time to underpin a range of gas monetization options, including Gas to Liquids, LNG and indeed, gas to power.

The massive resource base waiting to be developed in our Montney shale play is geographically disadvantaged by being at the end of the pipeline. Therefore, pursuing alternative gas monetization options has become a strategic priority for the company. Last year, we entered into a joint venture with a world leader in detail technology in Sasol when they joined us in the Farrell Creek area of the Montney. Together, we're in the final stages of completing a feasibility study, and we will make the decision on moving forward into FEED before the end of the third quarter this year.

Another option is LNG. We're in active discussions with a number of parties regarding potential LNG export schemes from the West Coast of Canada. Now we've also started to investigate gas to power options, where regional dislocation of gas prices to power prices can allow creativity through various arrangements to receive additional rent.

All 3 panels on this slide demonstrate the potential uplift in the market that could be available for pursuing one or indeed, more of these options. Capital costs are potentially high, so creative arrangements will be needed to ensure that Talisman capital exposure does not become prohibitive. We will continue to develop and evaluate all options until we are completely clear on the right path forward for the company.

We've already initiated a shift to liquids-rich gas and oil plays in our legacy positions in Canada. We are executing the Wild River project to deliver up to 150 million cubic feet a day to a midstream deep-cut processing plant expected to be onstream by the end of 2013. This plant will allow us to take our average liquids yield from 10 barrels a million cubic feet a day to over 70 barrels per million cubic feet a day when that plant comes online at the end of next year and will allow us -- as John has earlier said, to enjoy the benefits of over 10 mbtu of the liquid stream by the end of next year from our Wild River assets.

The ethane stream, which comes as part of the product clearly comes from deep-cut facility has been sold under an attractive long-term supply agreement with Dow Chemicals in the industrial heartland of Alberta. Our recent strategy work shows that our liquids-rich gas inventory in the Greater Edson area has an unrisked exposure of potentially up to 900 million barrels of oil equivalent with nearly 2,000 drilling locations already identified and providing a platform for significant liquids growth.

We will be able to leverage the development of these emerging plays right in our backyard by utilizing the extensive pipeline and processing network we operate and indeed own in the area. Much of this opportunity set has been substantially de-risked by industry activity around us in the area. And realized on new drilling and completion technologies such as multistage fracturing and horizontal wells or limited entry, multizone fracs and vertical wells to rejuvenate a legacy asset. We will continue to evaluate different technical and commercial options to accelerate value from these assets, and I expect to have clarity on the preferred way forward before the end of this year.

So I'd like to summarize and leave you with 4 key messages around our North American business. Firstly, our point on capital flexibility. We have moved quickly to reduce our activity in the Marcellus and Montney, which are now set at a level where we can minimize our expenditure going forward at $300 million to $400 million per annum in these plays without losing any acreage. We strongly believe these are 2 of the leading gas plays in North America, and we will retain the flexibility to increase activity as and when prices recover.

Secondly, we continue to direct capital towards liquids-rich opportunities within our portfolio. Near term, the primary focus is to build our operating momentum in the Eagle Ford, where we expect to see a rapid growth of production. For North America as a whole, we expect to see liquids growth from just under 20 mbd today to at least 65 mbd by 2015.

And thirdly, we will continue to de-risk liquids-rich positions we've established within our portfolio. At the Duvernay, we will complete our 6 well, planned 6-well program and depending on results, increase our activity levels in 2015. And in our conventional portfolio, we will evaluate a range of options to accelerate value from the 700,000 or so liquids-rich acres we've identified in our legacy heartland.

And finally, we've continued to high grade our North American portfolio, focusing in on the core assets we want to grow and have made a great start at the disposition of $1 billion of nonstrategic assets.

Ladies and gentlemen, thank you very much for your attention and time. And I'm now going to pass you over to my colleague, Richard Herbert, who's going to give you an insight into poetry and exploration.

Richard Herbert

So ladies and gentlemen, good morning. Welcome to this final presentation today. I'm going to talk about exploration and, of course, as the explorer, I always get to go last.

The good news for you is that I -- there's so much exciting news coming out of our exploration portfolio that I'll leave you all buzzing when you go in for lunch. I'm joined this morning by 2 of my colleagues. First of all, Colombia. Colombia is a very exciting part of our portfolio and I'm very pleased to have our Country Manager for Colombia here today with us, Chris Spaulding, sitting over there in the quarter.

Chris is always complaining to me that Bogota is a hardship posting, which is something of a mystery to me. Any of you that have ever been to Bogota will know that that's not really true, but we thought we'd be kind to Chris and bring him up to Toronto for the meeting.

The other colleague of mine that's here is relatively new to Talisman, Greg Hebertson, sitting here is our Vice President for Exploration and New Ventures. And Greg joined us last year from Anadarko where he's found a lot of oil. And I'm hoping he's going to find a lot of oil for Talisman in the future.

Paul mentioned poetry. Yesterday in New York, I quoted a verse from Rubáiyát of Omar Khayyám, one the sort of frailties of hope. And people also said, that guy who's been sitting is rather depressed, and he didn't really -- it wasn't really appropriate for the excitement in our exploration portfolio. So I couldn't think of a good poem. And as Oscar Wilde remarked, all bad poetry springs from genuine feeling. So I didn't want to share a bad poem with you. So I just thought I'd get on with it. So off we go.

Now I have got -- here we go. I'm going backwards, I do apologize. Let me start with some key messages about our exploration portfolio. We've spent the last 3 years really reshaping what we're doing with exploration. We've taken exploration spending away from the areas traditionally where we were exploring, like the North Sea and in Western Canada. And we put it into places that have more impact, more potential for large discoveries.

As a result, we have now built a portfolio, which we think is very prospective. If we add up all of the opportunities in it, we think we get to about 9 billion barrels of profitability on an unrisked basis.

Secondly, as John mentioned in his introduction, we are now about 3.5 years into a 5-year journey of trying to add 600 million to 700 million barrels of new resources at a finding cost of about $5 a barrel. So we are on track to deliver that promise that was made in 2009.

And in fact, as we look at the quality of the opportunities that we have and the opportunities that we want to move into, we're confident that we can bring our finding cost down even further towards something closer to $3 a barrel in the next phase of our exploration program.

Thirdly, we're starting to see the emergence of a track record of discovery. First of all, in Colombia, in South America, which I'll be talking about; secondly, in Papua New Guinea, where we're aggregating gas for export; and now thirdly, with the discovery of oil in our latest dwelling in the Kurdistan region of Iraq, and I'll be talking about that too. And finally, looking forward we have a number of other areas where we're conducting exciting exploration tests such as Vietnam, Poland and Malaysia.

I just want to remind you of the frame in which we put our exploration assets, and again John talked about this in his introduction. We have a number of assets that fit into a category that we call near-term oil. These are conventional assets that, in our view, have the potential to be in production within the next 5 years or so. And in this grouping, we put Colombia, we put Kurdistan, and we put Malaysia. We have our offshore blocks in Sabah.

Our second category is Asian gas, which Paul talked about. We have some large volume gas up opportunities in a region, which as Paul showed us, have some very attractive gas markets. Here, we have Papua New Guinea. We have our untested licenses in the Nam Con Son Basin of Vietnam, and also for the future, we have the deep potential of our Sabah blocks in Malaysia where we see some very interesting structures on trends with some large gas discoveries in adjacent Brunei waters.

And thirdly, for the future, we are now taking steps to position Talisman in some new plays. We have a bias for liquids, and we also have a bias for finding discoveries. And this really directs us into 2 main areas of focus. One is unconventional plays, taking the experience that we've gained in North America and leveraging that to build out our portfolio, both in North America and internationally.

And secondly, in deepwater. We already had deepwater assets in Southeast Asia, in Indonesia or in Vietnam. And now we have a deepwater block on the very prospective West African Transform Margin in Sierra Leone. And we're screening opportunities to add to this portfolio.

Clearly, we still have other exploration assets that are in our portfolio. And for many of these, they don't fit within the categories that I've just described, Peru, Indonesia, some of our North Sea positions. We have some attractive investment opportunities in this part of the portfolio and where it's appropriate, we will collectively invest. But I think there's a very clear message that we're going to high grade the portfolio, we're going to focus it, and this will include exit from a number of areas, which we don't think are core to our future prospects.

Just like to talk about the portfolio now on this plot, which shows finding cost on one axis, which is really a measure of our exploration efficiency against value on the other axis. A number of interesting observations that we can make.

Within the current portfolio, we have a number of really material exploration options that have attractive finding costs in the region of $2 to $4 a barrel. Three of these have been tested, and we now know that they're working, Colombia, Papua New Guinea and now Kurdistan. And 2 are being tested both this year and next year in Vietnam and Malaysia.

As I mentioned on the previous slide, we have a number of areas in our current portfolios, which are shown in gray on this plot, which aren't particularly exciting from a finding cost or value perspective. Indeed, they're not competing for capital, and so we're looking to exit from a number of these areas.

And finally, the new opportunities that I've talked about, the unconventionals and the deepwater, really have quite different characteristics as shown on this graph. Unconventionals tend to have low finding costs and in large volumes. Deepwater, higher finding costs but a high value per barrel. So our intent is to find the right balance for these opportunities to bring into our portfolio.

John showed this slide in his introduction, and it just reinforces the point that we have been spending in the region of $600 million to $700 million a year with the goal of finding 600 million to 700 million barrels in a 5-year period starting in 2009. And now here we are in May 2012, and we found about 500 million barrels of that target. And as we look at the quality of the options that we've got, we believe we can lower our finding costs further, further to $3 a barrel. And the implication of this is that we can consider transitioning our exploration capital to closer to a number of around $400 million per year.

And now I'll just move to talk about some of our exploration results and plans, and I'd like to start with one area that's very important to Talisman, and that is Colombia in South America. I spoke about Colombia in this meeting a year ago, and we remain very excited about the potential there of our business.

We've seen some environmental permit delays, which have impacted our drilling program, but we remain confident that our Colombian assets will be producing around 50,000 barrels a day within 5 years. As shown on this graph, this production will come from a combination of our share of Equion -- our Equion joint venture and 3 discoveries, which Talisman has made in Colombia. The Akacias discovery in Block CPO-9, from Block CPE-6 and from the Huron discovery in Niscota.

Let me start by talking briefly about our Equion joint venture, which we acquired with Ecopetrol in 2010. In January of this year, Equion completed its first year of operations as a new company. Production at the moment is over 15% higher than it was at the time of acquisition. Production comes from the 4 fields, which is shown on this map.

In addition to the upstream assets that we purchased, Equion also gives Talisman access to about 65,000 barrels a day of export pipeline capacity in the OCENSA pipeline. And this we can use, not only for our share of Equion production, but in the future as Talisman's production start to grow. This is the rig that we can use to export that crude.

Equion's main producing assets are the Floreña and Pauto fields in the Piedemonte license. At the end of 2011, these fields had only recovered about 11% of the original liquids in place, and it's our intention to recover roundabout 30% by the time that the licenses expire in 2020.

Pauto and Floreña are now producing at their highest levels since production in the fields have started 12 years ago, and this is largely thanks to 2 wells that were drilled last year in the Floreña field, T7 and T8, which is shown on the cross-section here. And these are producing 12,000 barrels a day between them and are capable of producing a lot more once the gas handling facilities in the field have been expanded.

Equion are now drilling the first of 9 new development wells in these fields, and recently a third rig was added to accelerate the development program. And there is a major facilities expansion at Piedemonte underway. The environmental permit, a key milestone in this project, was received last month, and construction has now started, which will significantly increase the capacity to compress and reinject gas and will allow the exported liquids to be doubled from the field.

This plant start-up of the new facilities is in the 2014, and this will allow Talisman's net share production from Equion to rise over 20,000 barrels a day. Now this map also shows the Niscota exploration license to the north, which Talisman has an interest in and where we made a discovery in 2009 in the Huron field. The Huron-2 appraisal well is currently drilling, and it's very close to reaching its first target. And in August of this year, the Huron-3 appraisal well will start drilling as well. So we're very active in our appraisal program on what looks like a very good extension of the Pauto and Floreña fields into the adjacent block.

As we move on to talk about our discoveries in the Llanos heavy oil trends in the southern part of the Llanos basin, starting with the CPO-9 Block where we've made our Akacias discovery, we've now drilled 3 wells in the block. Akacias-1, which was the first well, has now been on production on a long-term test for a year and has produced over 0.5 million barrels with a low water cut.

We've drilled 2 down taper wells AE-1 and AE-2, which are shown on the map here. Both wells have a very good log responsive oil, but we haven't been able to flow test them yet because we're still waiting for the environmental permits for that operation. We're expecting the permits to be awarded very soon, which will allow us to get on with the testing. These are very important data points for us because these wells are located up to 700 feet down-dip from the discovery well. And if we flow oil from those wells, it clearly has a big implication on the reserves that we have.

In addition, we are planning a pilot development project in the up-dip segment of Akacias, which will start production in 2013, and Talisman's net share of that production capacity will be about 4,500 barrels a day.

Some way to the east of Akacias is our Block CPE-6, and here we have a very shallow sedimentary section. We drill wells here of about 3,500 feet, and they reach basement. And here the stratigraphic drilling that we've been doing with our partner, Pacific Rubiales, has revealed a heavy oil accumulation, which clearly extends to the adjacent Block CPO-12, in which Talisman also has an interest.

We're currently conducting seismic operations, and the plan is to acquire the environmental permit later in the year, which will allow us to drill and test wells and confirm the full extent of this discovery with the intention then to commence pilot production during 2013.

So to close on Colombia, I'd just like to summarize. We've had strong production performance from our joint venture company Equion, which has a very clear root to both production growth in the future. Our Huron discovery is being appraised, and we have had some very positive development drilling results along strike in the Piedemonte license. We've had encouraging appraisal of our heavy oil discoveries in Akacias and CPE-6 and plan to start production from both areas next year. And we have exploration upside, which I haven't talked about this morning in our Llano space and heavy oil blocks, in our blocks in the Putumayo basin in the South and in Equion's offshore Caribbean licenses. Overall, all of this mix is very excited about our possibilities in Colombia.

Let me now turn to another region where we're active, and that is in the Middle East in the Kurdistan region of Iraq where we've had some promising recent drilling results. Here, Talisman operates 3 blocks and here, we've built 2 wells Kurdamir-1 and Topkhana-1. We're currently drilling the Kurdamir-2 well, and we have plans to drill in our third block Baranan later this year.

The Kurdamir-1 well was drilled in 2010, and it's had a large gas condensate accumulation in the shallow and legacy reservoir, which is shown here on a seismic line. In addition, as we drilled deeper, we had good indications of liquid hydrocarbons in this section all the way down to the secondary Cretaceous targets. However, the well had some drilling problems and well-control issues and it is plugged and abandoned before we were able to collect the data to confirm the hydrocarbons in the deeper section.

Last year, we drilled the Topkhana-1 well and discovered another large gas and condensate field in the adjacent structure to Kurdamir. Here, the Oligocene reservoir is even thicker than in Kurdamir, it's over 450 feet thick. So we decided to redrill Kurdamir. So appraised the Oligocene reservoir down-dip from Kurdamir-1 and to check the deeper section. And that well is not drilled for the Oligocene, and it's locked nearly 460 feet of pay, which we interpret to be mostly oil with a bit of gas at the top and no evidence of any water.

We've conducted an open hole drillstem test over the upper 180 feet section of this reservoir, and this flowed at 7.3 million cubic feet a day of gas and 950 barrels a day of oil and condensate. Our prediction is that if we were to flow test the oil curve in our escalation from the gas, we would see significantly better flow rates. And it's our intention to go back and do further testing once we finished drilling the well. Meanwhile, Kurdamir-2 continues to drill down to the Cretaceous targets.

This picture shows the Oligocene reservoir in an expanded form. What we have found is 2 very large domes or structures, which are full of gas condensate and they have oil underneath. And so the question we now have is what is trapped in the oil? Our early exploration focus was on the structure. They appear to be closer still with gas condensate. So we have a different trapping mechanism for the oil, which is underneath.

At this stage, we don't have the seismic resolution to confirm what the trap might be. So we do have an analog, which is a field located along strike the Kirkuk field, which of course, as many of people know, is one of the largest oil fields in the Middle East, 18 billion barrels. And that field is also reservoired in the same Oligocene reservoir, which is stratigraphically trapped with a pinch out on its northeast side.

And our analysis of the Topkhana Kurdamir structure suggests that the same geological conditions could be present. Clearly, we're not dealing with an 18 billion barrel field, but we're dealing with something which could be quite significant. But we need to be cautious. We found oil in the Kurdamir structure. We think it will extend underneath Topkhana. We have not yet found any water, and today we can't map the trap limits. So it's too early to actually make any volume estimates for what this field could contain, but I hope I’ve demonstrated to you that it really could be quite significant.

Given the encouragement that we've seen, we intend to enter the next phase of the Kurdamir license this summer. We will acquire 3D seismic data, and we will conduct some more appraisal drilling in both Kurdamir and Topkhana to try and locate the base of the oil column and really confirm what resources we have in what could be a significant oil discovery. And then we can think about monetization options that we might have.

Let me move on and talk about our third area where we've had some exploration success recently, and that is in Papua New Guinea, which Paul Blakeley introduced earlier. As this map shows, Talisman has a leading land position in the fall and basin of the Western province. Here, we've been appraising various discoveries that we purchased when we entered the province a few years ago with successful appraisal at Stanley, Elevala and now Ketu, we are seeing not only an increase in our reserves, as Paul mentioned, we now think we have about 1.5 tcf gross identified. But we're also seeing very productive wells with individual wells capable of producing in excess of 35 million cubic feet a day. We're now just starting an exploration drilling campaign in the area of the Puk Puk and Douglas discoveries, which are shown on this map. This is an area, which we view to be highly prospective. And our goal remains to aggregate between 2.5 and 4 tcf of gas in this first phase of the project, which can be put into an LNG export scheme.

This slide is a summary of our high-impact exploration drilling during 2012 and 2013. In our near-term oil part of our portfolio, I've spoken about Kurdistan and Colombia. In addition, we have 2 prospective blocks offshore Sabah in Malaysia, which we will start drilling in early 2013.

The acquisition of the Kinabalu asset, an offshore platform, which lies closer to some of our exploration prospects, will clearly allow us to accelerate the tieback of any discoveries we make there and improve their economics. In the Asian gas part of our portfolio, I've talked about PNG, and in Vietnam, we are drilling the first of 2 wells in our Block 5-2 in the Nam Con Son Basin. The first one, Ngoc Thach, is very close to reaching its first objective.

And in our future options category, we're drilling our third shale well in Poland. This is the final well in the initial phase, and then we will pause for a while to evaluate results and plan our next steps. In the first 2 wells drilled in Poland, we have seen gas, and we've had some encouragement from the rocks. But it's still very early days to confirm the future.

And finally, in deepwater, we have found into a very attractive deepwater block at Sierra Leone on the West African Transform Margin, which we will be drilling later this year.

We move to my final slide and just reinforce the 4 key messages in my presentation. First of all, we're starting to build momentum and track record in our exploration programs, and we now see success emerging in Colombia, Papua New Guinea and now in Kurdistan.

Secondly, over the next 12 to 18 months, we will be testing more high-impact opportunities in our portfolio. Thirdly, we're now working to replenish the hopper. Because the hopper of opportunities has to be replaced with some exciting new options with a focus on deepwater and unconventional liquids.

And fourthly, as we look at the portfolio of opportunities we have, the portfolio that we created with new opportunities, we believe we can transition our finding cost to a lower number of around $3 a barrel, and with that, bring our capital down to a number closer to $400 million a year.

Ladies and gentlemen, that concludes my presentation. I now hand over to John for our question-and-answer session. Thank you for your attention.

John A. Manzoni

Okay. Ladies and gentlemen, thank you. Just before we do Q&A on the -- well, on everything actually, you've heard about all the component pieces of the business. What I'd like to do is summarize for you a few key messages that we want you to take away given everything else that you've heard. So like everybody else today in North America with the gas prices where they are, we're concentrating our investments towards liquids opportunities.

We can grow liquids at 5% to 10% per annum from 2011 to 2015, and I've shown you the components of that in that slide. Momentum will build through this year, and it will drive strong growth into 2013 and onwards. And by 2015, we project at least 300,000 barrels a day of liquids for Talisman for liquids and indeed for production. Beyond that there are some more large projects North Sea, as some examples, which are identified and come on in the immediate period after the 2015 period.

We have a very strong business in Southeast Asia, which is growing and providing increasing amounts of cash flow, and it's also playing into an increasingly strong pricing environment in that region. The exploration portfolio as you've just heard is quietly building a strong track record, 3 areas out of 5 so far working and 2 to test in the next 12 to 18 months. And at the same time, we're not targeting a lower finding cost as you've just heard Richard say, which can deliver the same resources with fewer dollars there, $400 million.

And finally, while are favored today, we believe we've assembled an advantaged dry gas portfolio in North America, which we can maintain in good standing with minimum capital expenditure and wait for the day when gas prices do actually increase just a little bit here in North America again. They don't need to increase very much because as we've explained, we believe we have a portfolio, which is at the advantaged end of the cost curve.

So those are the 4 main messages we want you to take away. Now what I'm going to do is I'm going to invite the team back here into the salon-type arrangement, and then we'll pick up any -- that was an invitation, and then we'll pick up any other questions. Welcome to, of course, questions on North America or on exploration or, frankly, on anything else.

Anybody got any more questions? Otherwise, you'll force all these guys to come sit down again without answering anything. Please.

Unknown Analyst

Just to start off, with regards to international, the reduction in the finding cost, the target going from $5 down to $3, is that -- what is that largely driven by? Because on the one hand, you have the low finding cost that come from unconventional, but on the other hand, you're pursuing or will be pursuing more deepwater oil. So is it the fact there's more unconventional mix all things considered or is it more just to repeat?

Richard Herbert

Well, it's a good question. I think, I mean, we're look at sort of a blend. I mean, we -- in unconventional we think sort of $1 to $2 a barrel is probably sort of the finding cost that we could expect on average. In deepwater, as that plot showed we’re probably more in the region of about $7 a barrel. So the blended mix of those comes out at about $3 a barrel, somewhere in the middle. I mean, clearly some companies have gone for a pure unconventional resource renewal strategy. Our view is that a blend of the 2 brings sort of a better balance and a better sort of management of risk. So that's why we get to the $3 a barrel.

John A. Manzoni

But it's also true, isn't it, that the reduction of spending in legacy areas is helping too.

Richard Herbert

And that helps as well, yes. Because our legacy areas traditionally have probably delivered somewhere between $5 and $10 a barrel. And so by reducing the spending there, that also drives us towards our finding cost as well.

John A. Manzoni

Yes. The microphone is making its way.

Unknown Analyst

Maybe just for Richard as well. On the environmental permitting in Colombia, specifically on CPE-6. I think there already has been some delay in getting those permits to drill the -- test the wells. I wonder what level of -- I guess is there -- do you have an expectation that you will get that permitting in the near future or is there a possibility that it could drag on for a while, maybe be delayed into next year?

Richard Herbert

Okay, well, this is a great opportunity for me to ask Chris, which is why he came to answer difficult questions like that. Chris, can you give us an update on when we -- on the permits...

Chris Spaulding

So the whole environmental permitting process in Colombia is certainly a frustrating thing for everyone involved. Certainly for the industry, for our shareholders, for Richard, for John. But with respect specifically to the Block CPE-6, the -- our plan is that we will have the environmental permit in September. That's what we are planning on now. We hope in Block 9, we will have that imminently, but we shall see on that as well.

John A. Manzoni

And is it -- what is causing the holdup, Chris, just for people's education? Is it because you're slow getting it in or is it...

Chris Spaulding

No, I don't think that's the case, and it's certainly -- it is certainly not an increase in the requirements or the government becoming more restrictive in terms of the standards that we have to meet. What it simply is, is the government and they recognize this, in terms of human resources within the Ministry of the Environment has not kept pace with the increase in activity that has occurred both in the Colombian upstream oil and gas sector and as well as the mining sector. So there's just an increasing amount of demand for the attention or the work that these people have to do. There are also some community issues that get involved and some folks in the local community who complain a little bit and raised a few issues and whatnot. But it's one really just of resources within the government and so to that extent, the industry, both in the mining sector and in the upstream petroleum sector, we are hostages of some of the success that we have been experiencing there.

John A. Manzoni

Thank you. Anything else that anybody would like to probe, please?

Unknown Analyst

It's good to see your success in cleaning up the balance sheet thing in strategic joint venture partners and more focus on exploration and success in Southeast Asia. But there are a couple of things that going forward, a few years ago when the company changed management, gas strategy and North America as opposed the unfortunate part of the change of UN because of the gas price, it looks as though a lot of the disposition proceeds were used to finance the cash strategy and right now, I supposed is in the waiting pattern. And as far as change of management at the top level I think is a way promising side. I'd like to know how the culture is panning out, where they penetrate down to the ground level, right? There were liability in production in the North Sea, would that be fitting you with -- the few operating people have been really changed the culture or what would be the North American strategy going forward as opposed to 65,000 barrels of liquid, what would be the time line for that? And also on the CapEx side, how do the level of production target? I think that was one-off thing in the past and the company has done pretty well for a couple of years, but has the culture changed enough to adapt to the new strategies and the new management?

John A. Manzoni

That's a pretty damn good question. Has the culture changed? So I will give you a couple of observations. First of all, it isn't just the people sitting here who have actually changed. We actually have -- one of the great things that always gives one satisfaction is that is that a company can continue to attract great people all the way through. There are several people sitting in this room, not just here, who have fairly recently joined the company. Roy, [ph] who runs one of the -- he knows the big sort of operations, most senior operations person in the North Sea. Yes, Ed, where's Ed? Ed Lefer [ph] running our Conventional business in North America, Greg running our exploration new ventures. So and actually each of those people have also attracted fantastic quality of people below them. In the end, the culture of a company -- one can't really proscribe a priori, the culture of the company emerges as a result of the values and the culture of the leadership ultimately of the company. I will say to you that, that is a continuously evolving process. What I would say to you today, in fact, I had this conversation is that right now, having just changed as you said a strategy on toward a gas-driven growth strategy, which took 2 years really to effect. We've got a wonderful gas portfolio in North America. The 6 months ago, the gas price completely fell out of bed. Now that is a challenge. That's a challenge for morale. It's a challenge for all the people who are working so hard to do what they did inside the company and move the company forward. And for those people who don't have the benefit across our company of being in conversations, which give them access to how we're thinking about the portfolio, its direction, the next steps. They don't see actually, they will now, but they haven't the sort of liquids growth that we've just shown you, which actually is a very positive story. About when the external environment changes so much, I will say to you now that the culture will be morale of the company having just set off on this is a challenge for us, for this leadership team. We have to put our arms around people, we have to reassure them, we have to demonstrate that we can be nimble. I think we have. At the same time, for instance, Robert Broen, where are you Rob? Who built up the Marcellus from 0 to 11 rigs in 12 months, just taken it back down again to one rig, having built an office in Pittsburgh. People moving back out of Pittsburgh into Houston. So this is not without challenge. What I would say to you is that, though, having said all of that, the activity with which we have actually moved, we will continue to claim that we were the first to start reducing dry gas rigs out of the Marcellus, the first and most public. We moved very, very quickly $200 million from here and the rest of the year on dry gas spending. So what is really encouraging and reassuring is that we have a leadership and it isn't just here. It's throughout the organization who are nimble, who are alert and who are reacting to the situation, and that's a fantastic thing to do and to see. So I find -- it's quite a difficult question to say, has the culture changed enough? One can only observe. Do I believe that last year's experience, where actually as you recall, we came off for the first time in 3 years, we came off a promise to the market. Do I -- and that had an impact, and this organization, I believe, really started to understand the implications of not living up to its promises because this company was doing very well relative to competitors up until that point. And at the end of last year, it did very badly relative to competitors. And that was the moment when everybody in the company said, "Whoa, that matters." And whatever you do and how you communicate those things and say that matters, people experienced it for themselves. The company did not, throughout the company, have a good remuneration structure, even a remuneration year last year as a result of what happened at the end of last year. That hits everybody, and it -- and I believe that the company gets much, much stronger going through experiences like that. So personally, I think that in challenging times, it is when you can really see the mettle and the culture of a company, and I think we have had challenging times. I'm actually really confident as look forward, you can see some of these projections. It's taken 6 or 8 months in response to a dramatic fall in the gas price to redirect some of the things and to rebuild and move it forward again, it's taken a little time. And that's been what has happening since the fourth quarter last year into the first quarter this year. I think now the company can move forward, we can look forward to those sort of growth things and I think people can increase confidence again. But I won't deny that it knocked confidence when we missed the target and the gas price goes to $1.40 an acre. That's a big deal. I would and whether my colleagues want to say anything else in answer to the question. It's quite a hard -- I'm not quite sure how to answer directly your question. Anything to add, Dan? John? He's well-trained too. Please in here. Let's do -- can I go here, please?

Unknown Analyst

With respect on the funding cost again. Can you give us a sense on what that same transition looks like on the $5 to $3 on a more of full cycle basis? So finding and development cost? How that transition is changing also?

John A. Manzoni

F&D, probably -- I don't know. F&D in unconventional $10, $12.

L. Scott Thomson

Yes, a bit more than that, John. About $15 to $18, maybe.

John A. Manzoni

So we're probably in the $20, $15, $20 range. It's the deed that's the big piece of the F&D of course. So while we moved the F cost down a bit but the D is the majority of that. So $15 to $20, something like that, probably long term.

Unknown Analyst

Just had a question on the dividend. So the dividend at Talisman's been increased quite regularly for more than a decade, and I've got a question of culture earlier. I mean obviously, the American gas price environment given the shift the company made has a huge impact on that. But going forward with finding costs and capital or expenditures forward cycling going down, how do you see the dividend going forward, and is it an important part of the corporate culture?

John A. Manzoni

Let me talk to the culture piece, and then we can talk to -- get Scott to talk about the balances. Once you -- I come from a culture that once you start a dividend, you don't stop it. It's not something to be treated lightly. As a company, as you say, has increased consistently over 10 years, it's not a huge dividend. It's $200 million or $300 million.

L. Scott Thomson

$200 million.

John A. Manzoni

As we gave through, but it is nonetheless an important part and an important signal of the management's perspective on the future. My own, and I think our own philosophy on this is that it does contain signaling content and therefore, it must be treated as a not as something to be changed and moved around at will. It's not sort of discretionary in that sense. There are particular reasons that we paused in today's gas price, but it is something which is actually a part, a very important part, very important use of cash. And it's not something which is discretionary.

L. Scott Thomson

Yes, I mean -- the only thing I'd add is as John said for 10 years, we've increased it every year and not by a loss but signaling. And this year we think the view that given $2.50 gas, it wasn't the right time to increase it and the dividend as a percentage of cash flow is getting to an area in $2.50 gas rates where it just felt like that wasn't necessary. Issues, I mean, for the company, is we were sitting here last year we were saying with North American gas prices at $4 or $5, we saw ourselves getting to point we are free cash flow positive a couple of years out. And then you get some very interesting question about would you do with direct cash, you look at share repurchases, do you do increase dividends, do you move total turn or so? Unfortunately, we're not just there today, given the $2.50 gas price, the judgment was that we should just keep it flat for this year.

John A. Manzoni

They will come. Please, Brian [ph].

Unknown Analyst

As you seek to expand your position new venture-wise and unconventional liquids in the deepwater, should we expect you to move into new countries such as Sierra Leone or additional countries that you hadn't historically operated in, and then when we think about some of the areas in the exploration portfolio that may be candidates for divestiture or monetization Peru or costs there, how should we think about potential proceeds and is that baked into your expectations for this year?

John A. Manzoni

I mean, I'm framing this. I mean, it's inevitable, and I will say one of the tensions about having an exploration portfolio, which essentially now we've drilled up. If I look over 3 years, we started by having all sorts of single wells in certain places. We got out of Trinidad and Denmark and Alaska or in Gasso [ph] and Tunisia or in all sort of places, and essentially we honed that portfolio down, and Richard's sort of a strategic intent was to deepen in a few places that he really wanted to be in. And there was only in the end 5 or 7 of them, we deepened in Colombia. We deepened in South Makassar, we actually entered very deep in Papua New Guinea. So we deepened it a few on the philosophy that says you can't just build one well because if the one well works, you want 5 others to drill after that. So we did all that. We're now in a place where we've more or less drilled most of those as you heard. We've drilled 5 out of 7. We'll drill 2 in the next 12 months. And the issue then is, so what do you do at the front end of the hopper? We're bound to enter, therefore, new places. I would have to say we will enter them perhaps in a slightly different way that we might have entered them in the past. I would say that we have quite a lot of people, as it happens in Peru. It's actually an exploration venture. It doesn't need that many people. So you might see new entry, but new entry lights as an exploration probe. So there’s a -- in addition, we're bound to be looking at new places as we go in, but first very differently perhaps to some of the new places that we had entered in the past. In a different way. That, I think, is inevitable as we refill the hopper. And then as we -- and then, of course, it's a matter of time because we don't have to take a successful exploration well through to development appraisal and development. We can choose to exit at any particular time as it happens in Peru, for instance. We believed pretty strongly that the well that we've just drilled, which turned out unsuccessful, would actually find a reservoir, which would double our resources. That's actually why we chose to hold on, drill the well and see what happened after that. It turned out the well was dry. So we will be moving to exit Peru. And the question is, at what point in the cycle do you choose to do that? We have the same discussion -- we're in the same discussion on Makassar, not finalized exactly when yet. Funnily enough, we have the same discussion on Kurdistan, which we've been in for several years. And then we have inconveniently found what might be a very large oilfield. So we have to see what and the decision was taken actually exit now would be the wrong decision. We'll continue to the next phase. These things are continuous, as you know, and recognizing the tension that for Talisman, in particular, people say, too unfocused, can't get it straight, you're in too many places. But for an exploration portfolio, one's got to be bringing new things into the front end of the hopper, and the question is how can we -- can we continue to be disciplined in getting them out the other end in making those decisions. And those are very active discussions in Richard's portfolio. And it's not necessarily the case that even if we're successful, we necessarily take it through to the next phase of the process. So I think it's a continuous process, Graham. Are the proceeds baked in sort of guessing a broad sense, we're looking at cash inflows, cash outflows. We're thinking about what might be possible, have we got specific expectations. We'll have to test the market and see some of these places.

Richard Herbert

Can I just add one thing to that, which is, I mean, we quite often get accused of not having enough focus in our portfolio. We've actually looked at a lot of our competitors and sort of compare the sort of breadth of their portfolio versus ours, and there isn't -- there's nothing particularly different about our portfolio than that of a lot of other people. I think part of the frustration was that we haven't started testing it and demonstrating that we could find things. Now we've got 3 areas that we're talking about that are working, and we've got 2 more that we're testing. And it puts it in a different perspective, I think, and it allows us to take those opportunities and move them sort of into the next phase of appraisal and thinking about development or monetization in some other way. And then as we replenish that hopper, we will be very focused on how we do it. And we said there are 2 areas that we believe we should focus on and again we've looked at the industry and the trends over the last 10, 15 years. Talisman as an independent, was late going into deepwater. Talisman as an independent with a strong unconventional background. Those are the 2 areas we want to focus on because that's where we see 70%, 80% of the resource potential in the future. But we're not going to go running into a lot of different countries to do it. We'll do it in a very focused way with very high quality assets, which sits within a strategic frame.

John A. Manzoni

Thanks, Brian. [ph] Anybody else? My signal that it is -- look at that, bang on 12:00. Must be lunch time. Ladies and gentlemen, thank you for your attention. Thanks for joining us. I hope you found it informative. Thanks for coming twice, Brian, [ph] and please do join us for a bit of lunch and also chat to the leadership who did not stand up here again and ask them all sorts of other questions, if you'd like to. So thanks for your attention.

Lyle McLeod

Just had one thing. The lunch is actually across -- just across the hall. You see the stairs as you walk out. So it's it the next room up the stairs. Just you walk out the doors, straight out and up the stairs, it's the small room off to the side.

John A. Manzoni

Okay.

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