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Talisman Energy (NYSE:TLM)

2011 Earnings Call

February 15, 2012 1:00 pm ET

Executives

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

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

Richard Herbert - Executive Vice President of International Exploration

Tony Meggs - Senior Advisor

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

Analysts

Bob Brackett - Sanford C. Bernstein & Co., LLC., Research Division

Brian Singer - Goldman Sachs Group Inc., Research Division

Andrew Potter - CIBC World Markets Inc., Research Division

George Toriola - UBS Investment Bank, Research Division

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

Menno Hulshof - TD Securities Equity Research

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

Brian C. Dutton - Crédit Suisse AG, Research Division

Operator

Good morning. My name is Kyle, and I'll be your conference operator today. At this time, I'd like welcome everyone to the Talisman Energy Inc. 2011 Year-end Results Conference Call. [Operator Instructions]

This call contains forward-looking information. Certain material factors and assumptions were applied in making the forecasts and projections to be discussed in this call, and actual results could differ materially from those anticipated by Talisman and described in the forward-looking information. Please refer to the cautionary advisories in the February 15, 2012, news release and Talisman's most recent Annual Information Form, which contains additional information about the applicable risk factors and assumptions.

I'd like to remind everyone that this conference call is being recorded on Wednesday, February 15 at 11:00 a.m. Mountain Time.

I'll now turn the conference over to Mr. John Manzoni. You may begin your conference.

John A. Manzoni

Thank you very much, Kyle. Ladies and gentlemen, good morning, and thanks for joining our fourth quarter call today. I'm joined here by the management team in Calgary. And we'll be happy to answer your questions after Scott and I have given you the main points.

First, a word about gas prices. Gas in North America is clearly now reflecting the oversupply condition, which has existed through last year. Prices fell steadily through the fourth quarter toward the levels we're seeing today. We believe this condition is unlikely to correct itself for some time, although actions are now being taken across the industry to cut back dry gas activity. Today's prices are unsustainable in the medium term, but we think they may last for 12 months anyway. We've set our expenditure plans for this year, which I'll review in a moment, in the context of a continued low gas price in North America.

In Asia, gas prices continue to be firm and in the medium term, are showing upward pressure. Our Corridor field in Indonesia realized a price of over $10 an mcf over the course of last year. We think oil prices are underpinned at or around current levels, although the pace of economic recovery in OECD on the one hand and political events on the other, have the potential, of course, to create volatility. But our plans are based on an assumption of about $85 WTI, which might be a little on the conservative side.

Moving now to a summary of the fourth quarter last year. I'll give you a few main points and then ask Scott to fill in a bit more detail. I'll then briefly remind you of our main areas of focus during this year and then, we will turn to your questions.

Starting with production. As I said out in our third quarter call, our average production over the year was 426,000 barrels a day, having regained operational momentum in the fourth quarter when production was 442,000 barrels a day. For the year, this is an underlying increase of 9%, and about 8% over the same quarter a year ago.

We saw excellent momentum in the shale business through the end of the year and averaged nearly 600 million cubic feet a day in the final quarter and about 500 million cubic feet a day over the year. The Kitan oil field in Australia was successfully commissioned in the fourth quarter, and we also benefited from the commissioning of Jambi Merang in Indonesia and the Equión production in Colombia through the course of the year.

We spent about $4.7 billion of cash capital overall last year, of which just over $4.5 billion was on exploration and development activities. As I'll describe a bit later, this will be reduced in the current year.

Cash flow for the fourth quarter was $824 million, and for the year as a whole, it was about $3.4 billion. Both were up substantially from the prior year, benefiting from higher liquids prices.

Earnings from operations for the year were $604 million, up over the prior year, benefiting, again, from the higher prices. But the fourth quarter was lower than the same quarter a year ago, and this reflects increased DD&A and increased costs. Operating costs were a little higher during the fourth quarter, which reflect mostly the substantial amount of maintenance work, which was undertaken in the U.K. during the quarter.

Unit costs in North America continued to trend downwards as we increased the proportion of shale production in the mix. During the fourth quarter, we drilled an encouraging well on the Elevala structure in Papua New Guinea, which continues to build our confidence in our gas aggregation plans, and we're making very good progress in discussions to find a strategic partner for our PNG activity.

Wells in Peru, Kurdistan, Poland and Colombia were all actively drilling through the year-end, so we should expect results over the next few months. We wrote off the unsuccessful exploration well in South Makassar during the quarter, although we're still assessing the implications of that well result for the basin as a whole.

Over the year, reserve replacement was 157% before the impact of price provisions and 162% after price provisions. During the final quarter of last year, we agreed that the reunitization of the Suban field in Indonesia, which reduced reserves net to Talisman in that field.

Replacement costs for the company last year were between $18 and $19 a boe, which is up from the prior year due to the Suban reunitization I just mentioned and the normal volatility in annual F&D cost in the international portfolio. Three-year replacement costs continue to trend downwards, and the replacement cost in our North American shale portfolio were close to $8 a barrel equivalent.

The ratio of proved undeveloped to total proved reserves continues to be managed conservatively and is 43% for North America and 37% for the company as a whole.

Now let me turn to Scott to give you a few more details about what I said and also, to talk a bit about the balance sheet.

L. Scott Thomson

Thanks, John. I will review our results, balance sheet, acquisition and disposal activity during 2011 and our hedging position. As John noted, production was 442,000 barrels per day in the fourth quarter and 426,000 barrels per day for the full year.

North America shale volumes more than doubled to 500 million cubic feet equivalent per day for the full year, and Southeast Asia gas volumes exceeded 500 million cubic feet per day for the first time. You will recall that approximately 65% of our gas production in Asia is linked to the price of oil, which resulted in a realized price of $9.30 per 1,000 cubic feet over the course of the year.

North Sea production decreased significantly from 2010, primarily driven by lower volumes in Norway. Fourth quarter North Sea volumes of 100,000 barrels per day were in line with guidance we gave in October.

For the full year 2011, cash flow increased by $500 million to $3.4 billion as higher commodity prices were partially offset by higher operating costs, higher cash taxes and the higher realized loss from derivatives. Non-GAAP earnings from operations increased by $50 million to approximately $600 million and was impacted by higher DD&A, higher dry hole expense and higher deferred taxes.

Relative to the fourth quarter of last year, cash flow increased by 25% and non-GAAP earnings were essentially flat. Higher commodity prices drove the cash flow increase. And in the case of earnings, the benefits of a higher commodity price were offset by increased DD&A year-over-year.

Netbacks in 2011 of $37 per boe were 19% higher than in 2010, due principally to higher oil prices. Despite increased maintenance activity, North Sea netbacks were approximately 40% higher than 2010. And Southeast Asia netbacks increased by 30% driven by the higher oil price year-over-year.

Operating expenses of $2.2 billion were $300 million higher than 2010. The increase was primarily the result of the addition of Equión, the startup of Jambi Merang and Kitan in Southeast Asia and increased maintenance in the North Sea.

Unit operating expenses increased due principally to higher maintenance activity and lower North Sea production. This was offset by lower unit costs in North America, which decreased by 18% year-over-year, as a result of the transition into unconventional shale development and the sale of high-cost conventional assets in 2010.

Depreciation expense of $1.95 billion was 9% higher than 2010, due principally to the startup of Auk North, Jambi Merang and Kitan, the addition of Equión and rate increases resulting from reserve revisions in the fourth quarter. For the full year, current income taxes were $1.4 billion compared to $1.1 billion in 2010. The U.K. rate change accounted for $100 million of this variance with the remainder due primarily to increased commodity prices.

Total capital expenditures for the year, including exploration expense, was $4.7 billion, of which approximately $4.5 billion or just slightly over $4.5 billion was associated with E&D spend. $2.2 billion was spent in North America, of which $1.8 billion related to shale activity.

During the year, we acquired undeveloped land in the Duvernay and Eagle Ford shale plays for approximately $650 million and completed the acquisition of a 49% interest in Equión, with a final payment of approximately $170 million.

Disposals in 2011 were limited to the transactions with Sasol and the Montney, which generated cash of approximately $500 million and a future carry of $1.6 billion. But as John noted, we expect considerably more disposition activity in 2012 and are in the process of marketing North American non-core assets.

At December 31, 2011, we had net debt of $4.5 billion. As I noted in our guidance call, we issued $200 million of 4.2% preferred shares towards the end of 2011 and launched the U.S. commercial paper program with $400 million outstanding at December 31 at a rate of 0.6%. Other than renewables associated with our commercial paper program, we have no significant maturities until 2015. At the end of the year, our revolving credit facility, which matures in 2014, had $3 billion of unused capacity. During the year, we paid a common share dividend of $0.27 per share, an increase of 11% over 2010.

And just briefly on our hedging program. During 2011, we had approximately $270 million of cash outflows associated with our hedging program. The fourth quarter outflow of $40 million was significantly lower than the $65 million in the preceding quarter. Our out-of-the-money hedges rolled off at the end of 2011.

In 2012, we have 50,000 barrels per day of oil hedged in the first half of the year and 30,000 barrels per day hedged in the second half of the year in approximately $90 x $140 collars. We have no gas hedges in place for 2012.

Those are my highlights. John, I'll turn the call back over to you.

John A. Manzoni

Thank you, Scott. Ladies and gentlemen, just before your questions, I want to say a word or 2 about our focus for this year. In terms of capital expenditure, we've set our plans in the context of continued low gas price here in North America. When we issued our guidance last month, I said we would reduce the overall level of capital and direct more of it into liquids opportunities. We plan to spend around $4 billion of cash capital on exploration and development activities this year.

When I talked to you in January, I indicated that we would move from 10 rigs we had running in the Marcellus at year-end to around 7 or even 5 over the current year. In light of the gas prices, we plan now to go further than that, and we'll bring our activities in the Marcellus down to as few as 3 rigs during this year. As a result, total capital expenditure in the Marcellus will reduce from the $1.2 billion we spent last year to around $600 million this year, which includes significant infrastructure build-out as we move east. At this level of spend, we can maintain production broadly at today's levels of 500 million cubic feet a day with no land expiry issues. We'll continue to ramp up our activity in the liquids-rich plays in North America, including the Eagle Ford, the Wild River and the Cardium play.

In the Eagle Ford, we'll ramp up to 14 rigs by year-end and expect to at least double production this year. We'll also increase spending in Colombia as we continue to appraise the discoveries in Blocks 6 and 9 and also begin the development of the Piedemonte field.

I outlined our guidance for this year's production range in January. Moving our focus to liquids rather than drilling less-economic gas will result in underlying production growth between 0% and 5% for the current year, although our medium-term target of 5% to 10% remains in place. I really see no value in chasing unprofitable growth while gas prices remains so low. The range for 2012 also accommodates the uncertainties around the Yme project in Norway.

And with regard to that project, I want to give you a little more context. I've deliberately taken it out of our production projections for 2012. As you know, the work is being undertaken by a contractor, who has a turnkey contract to provide the Yme owners a complete working production facility. As it stands today, while the design accommodated the Norwegian regulatory standards, in a number of respects, the platform does not. The rework that's being undertaken is essentially to meet those standards and the contract specifications. And it has to be complete before hookup and commissioning.

The work scope is broadly defined, but the pace of work today is not meeting the schedule which have been agreed between the owners and the contractor. We're in very active discussions with the contractor to agree on the most effective way to improve productivity and complete the work. Until those discussions are complete, I don't want to be explicit for you about how we will improve the situation, but I can say that we can see a path forward. I anticipate being able to be more explicit about that part over the course of the next few months.

We do need to allow the teams on the ground the time and space to resolve what has clearly been an unsatisfactory and complex state of affairs. And so both internally and now, externally, I've taken the project out of our projections for 2012.

We've also stated that we'll seek to dispose of between $1 billion and $2 billion of non-core assets this year, including potential dilutions, farm-downs or sales. We're in action in the North Sea and in our North America conventional portfolio. We'll also be evaluating the options to focus our exploration portfolio as we complete our drilling program through this year.

Our guidance call in January gave you quite a lot of detail on the allocation of our capital and production targets and more detail of our plans for this year. My intent today was only to recap that very briefly. So with that summary, I think it now best to move straight to your questions.

Question-and-Answer Session

Operator

[Operator Instructions] Your first question comes from Bob Brackett from Bernstein Research.

Bob Brackett - Sanford C. Bernstein & Co., LLC., Research Division

I had a question on the Eagle Ford. With getting the 14 rigs running, your production guidance of, say, 30 million cubic feet a day seems awfully low. Is that the drilling side? Or is that the access to additional egress? How do you think about that?

John A. Manzoni

Let me ask Paul. You may have misunderstood, but Paul will clarify for you. Paul Smith?

Paul R. Smith

Bob, the production guidance is more -- that we said more than double, which means that it's going to go from 30 to more than double that this year.

Bob Brackett - Sanford C. Bernstein & Co., LLC., Research Division

So 14 rigs will add a net of 30?

Paul R. Smith

So we've -- I've said last year, we averaged about 30 net. So remember this is our net position, which is about 40% working interest in the Eagle Ford. Last year, we averaged about 30 million cubic feet a day, 50% of which was liquids. And I'm confident that we will more than double that, Bob, this year. So I mean, we've got momentum, clear operational momentum now exiting last year, coming into this year. We have a few challenges ahead of us. All of us who operate in the Eagle Ford, I think, have challenges ahead of us, in particular, in terms of the midstream build-out this year. But I would reconfirm, again, I am more than confident we will more than double our production in the Eagle Ford this year.

Operator

Your next question comes from Brian Singer from Goldman Sachs.

Brian Singer - Goldman Sachs Group Inc., Research Division

Can you give us the latest on how you're thinking about the monetization of various assets? On the exploration portfolio, you've had a couple of data points here between Kurdistan, Peru and Papua New Guinea, which you referenced in your comments, and then Poland as well. How are you thinking about the strategic importance of those assets to Talisman versus potentially finding partners or selling? And then maybe you could also address the North Sea in that context as well.

John A. Manzoni

Yes. It's quite a sweeping set of things, but let me see if I could just give you sort of an overall context, and then perhaps Richard can update on, particularly, Peru, PNG wells and Poland wells, and Kurdistan wells, we can deal with that. But here's what -- here's how we're thinking about the exploration portfolio, which is why I'm not being particularly explicit right now. Over the course of the sort of 12-month period, we're actually finding ourselves drilling almost all of our basins that we have deepened our position in. Even if all of those work, Brian, we won't choose to take all of those to the next step, and therefore, we will choose to exit some of them for value, if they're successful. And the lenders would push for that frankly, materiality and probably time frame. So we'll take a view on whether or not we can get it very material, and we'll also take a view on how quickly it might take to monetize. So those are the sort of general lenses that we're using on our exploration portfolio. I think this is sort of natural process of evolution across our exploration portfolio. With regard to the North Sea, what I've said for the moment is that we will reduce our exposure to that part of our business. Now you will understand, we are in various deliberations about how best to do that. And frankly, until those deliberations are complete, and we're in sort of in action, it's a little difficult to be more explicit than that, except for me to say that I'm confident that we will execute against that plan during the course of 2012, one way or another. And we're in various discussions and deliberations about how best to achieve that. But that is our intent and that is what will be delivered. Now perhaps going back to the exploration portfolio, I could just turn to Richard to give a little bit of an update on some of those exploration areas that you mentioned. Richard?

Richard Herbert

Yes. Brian, just to build on what John is saying there. I mean, I think we're in an active testing phase across the portfolio, and we want to see some wells get drilled and understand the results of those before we take sort of portfolio decisions. In Peru, we are drilling a deep exploration well, Situche Norte-4x, which is on the largest structure that we've identified in our Block 64. It sits just north of the Situche Central discovery. And that well is now down deeper than 15,000 feet, heading for target which is about 18,500 feet. So in the next month or so, we should reach that target, understand what we have in Peru and then be able to take some decisions going forward. In Kurdistan, last year, we drilled a very large gas condensate discovery in the Topkhana well. That followed on from our Kurdamir well, which we previously drilled which also found gas condensate. And we're now back on the Kurdamir structure drilling an appraisal well, which is about to appraise the shallow Oligocene gas condensate reservoir, down dip from the discovery, plus also drill deeper into the Cretaceous. While we encountered a lot of encouraging liquid indications in the original Kurdamir well, but we were unable to log or test. So there's no doubt that our blocks in Kurdistan are sitting in an area of very rich hydrocarbons. And again, we want to just complete the drilling of the Kurdamir well, and we're also looking to drill one further well on the barren end structure just behind, which is another very large structure, before we take any decisions around where Kurdistan is in the portfolio. And I think, finally, the other country that you mentioned was Poland. And again, we're in the process of drilling an initial set of 3 wells in Poland on 3 different blocks. We've now completed 2 of those wells. We've collected a lot of geological data. We've seen some encouraging indications of gas shows and even some liquid shows in the second well. But it's early days to be able to define what the flow potential or the commercial importance of this area could be until we've completed the analysis of these wells and drilled the third well. And so that will emerge during this year.

Brian Singer - Goldman Sachs Group Inc., Research Division

Great. That's a very helpful update. And just very quickly a follow-up. As you drop the rigs in the Marcellus as a result of the gas prices, what gas price would you look for to go back to a double-digit rig count there?

John A. Manzoni

So I'm just looking at Paul who's indicating $4. $4 used to feel really low. From $2.50, it feels like a great price. If gas price moves towards $4, I think we'd start ramping it back, Brian.

Operator

Your next question comes from the line of Andrew Potter from CIBC.

Andrew Potter - CIBC World Markets Inc., Research Division

First, just a question on Yme. I'm not sure if you'll be willing to answer it or not, I guess. But I mean, you mentioned that obviously you've taken it out of the 2012 guidance and a lot depends on workforce productivity improvements to get this thing on. But I mean, at current pace of workforce productivity, what is sort of the range of outcomes in terms of when this could come on? I mean, is it -- are we really looking at a risk if this pushes deep into 2013? Or is that really a worst-case scenario?

John A. Manzoni

So let me ask Tony Meggs, who is now looking after IOW for us to answer. He's been deeply involved in the Yme project since he's taken over. Tony?

Tony Meggs

Yes. Andrew, it is correct that productivity has been significantly lower than we would like. And we are in action now, developing a plan with our partners, with our contractors to dramatically or radically adjust the situation, to turn the page on the performance to date and move into a new status. I don't think it would be helpful for me to speculate on how the new -- on a new date at this point in time until we have a new plan clearly in place, new activities going on, on the platform, and we can demonstrate clear progress against the new plan. So I can say with confidence that we are taking on a new approach to this project, but I don't want to, at this stage, give any indication of when the first production might be.

Andrew Potter - CIBC World Markets Inc., Research Division

Sure. Fair enough. And then just one other question just on PNG. I mean, the tone around that sounded reasonably positive in terms of either bringing in a partner or doing some sort of structure there. Maybe if you can just elaborate a little bit on kind of what the endgame is there. I mean, are you -- is it an LNG player, you're hoping to bring in as a partner? And I guess, if that's the case, what could be a plausible development time frame for LNG in Papua New Guinea?

John A. Manzoni

Very good, Andrew. Let me ask Paul Blakely who's here from Singapore to join us today, and he'll answer your question on PNG. What are we going to do, Paul?

A. Paul Blakeley

Andrew, so our original game in Papua New Guinea, having identified this very large under-explored basin, was gas aggregation with almost certainly an LNG solution in mind. And that still remains the case. We've shot a lot of seismic. We've started to drill a number of wells. The most recent at Elevala, was a good success, exceeded our expectations. So all of that is on track. But we always had the strategic objective to find a partner who would bring the downstream skills, the LNG capability that we needed for monetization. And we've been working that pretty hard in parallel with the activity in the field. And we're making great progress, and I really hope that we'll be able to say more about that here soon with a view to helping us and supporting us through the next phase of activity, which would see us looking to find the appropriate monetization option. And there are a number of choices around that, including access to existing LNG activity in the area, depending on how well we can get on. We'll see. In those choices, all, I think, still remain open to us.

Andrew Potter - CIBC World Markets Inc., Research Division

Yes. And just to push out a little further. I mean, if you do get access to LNG facilities that are kind of earlier in the planning stage, what -- I guess, what's the soonest we could expect to have some sort of commercial LNG production?

A. Paul Blakeley

I mean, I'm hesitant to give you a date right now. But it would be at least 6 years away, which would be the normal thinking for sanctioning and delivering an LNG project. It wing be that sort of time frame.

John A. Manzoni

For our own greenfield.

A. Paul Blakeley

Yes.

Operator

Your next question comes from the line of George Toriola with UBS.

George Toriola - UBS Investment Bank, Research Division

The question I have is around your return on capital. And when you look at the return on capital across the entire business, I wonder if you can break down the return on capital through your respective geographical regions. And I'm just wondering if that -- if you can speak to that, and secondly, if you can speak to how much capital you think you have tied up in some of the regions, like whether it's South America or Asia, that's not generating adequate returns today.

John A. Manzoni

Yes. So George, I mean I'm not going to give all the details on the phone except to answer it in the most general sense for you and try and get some of your questions. So in a general sense, provided we've got the replacement cost for the company coming down, return on capital will improve over time, sort of point one. It is coming down, it's come down by about 50% in the last 3 years. So what we know is the laid-in capital that's going in every year is being more efficiently laid in than all the prior capital was being when the F&D was much higher. So we know that, that's happening. Now in a general sense, if you look across the regions, incremental capital into U.K. and certainly U.K. actually returns very strongly at high Brent prices. It's got very high costs, but it's got very high prices in netback, so those returns tend to be at the high end. Asia tends to be sort of 15% to 20%-ish in Asia. North America, of course, as we build the shale business, has a very low return because we're putting a lot of capital into a new business with not a lot of return for the moment. Exploration on which we -- and as you heard Scott say, we spent $1.8 billion on that business in 2011. Exploration, we're spending $600 million this year. Return is very low for the moment and of course, emerge later on. And in Colombia, we'll be spending -- or South America, we'll be spending of the order of $350 million, $300 million, $400 million in the course of 2011. And the returns on that won't be immediate. It is returning some. We're producing 13,000 barrels a day today, so lower returns there. But that's the sort of sweep in broad sense of the return characteristics of the portfolio. And the issue, of course, and that's -- and as I say, the U.K. -- Norway, by the way, tends to be relatively low because of the tax. Post tax returns in Norway, you're not going to get above 10%, really. And the temptation, of course, is to keep piling money into the U.K. on those sort of very "high return projects". But the problem is it doesn't replace the reserves and therefore, it's a bit of a trap, but we've had that conversation before. So that's where we are broadly. I mean, I'm sure the guys can follow up with more detail if you need it. But does that help?

George Toriola - UBS Investment Bank, Research Division

Certainly, yes. I guess, maybe if I just followed up quickly. If I use the example of South America, in Colombia, for example, you've got -- if we look at the acquisition you made back in 2010, there's quite a bit of capital there that is not generating returns and specifically, with the capital that has to do with the Ocensa pipeline as well. Just wondering how you -- and I understand what you said in terms of replacement costs. What time frame do you expect some of these things to evolve? And how quickly would you unlock some of these assets that are not making as much today?

John A. Manzoni

That's interesting, you picked Columbia. I would pick that as one of the best. I think that's going to prove to be a highly profitable acquisition. What we bought was producing assets. We did buy -- some of that was allocated to an Ocensa pipeline, of course, on which we're earning a sensible return. But as we build into the Colombia business and the $350 million is going into exploration largely, there'll be a bit of development, the development piece will return very quickly because it's building off existing activity in Piedemonte. The exploration piece in the Huron, Niscota Block and Block 9 and Block 6. All of that will come a little bit later. But I would say what we're expecting is that by 2015, we're going to have a very sensible level of production out of Colombia. At that point, you're going to see the true return of that capital invested.

Operator

Your next question comes from the line of Matt Portillo from Tudor, Pickering, Holt.

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

Just a couple of quick questions here. Could you update us, I guess, on the divestment process within North America, and in particular, on the coal assets and other kind of conventional assets you're looking at monetizing at the moment?

John A. Manzoni

Sure. Let me ask Scott to just give a little update on where we are on that.

L. Scott Thomson

Sure. So as we mentioned, Matt, we plan to sell $1 billion to $2 billion of assets this year, a combination of North Sea farm-down or smaller sales exploration, exiting 1 or 2 areas; and then North America conventional. So that will be a major part of it. We're actually in process on 4 assets right now. So the coal mine that we've talked about, we're running a process on that. We've just put Shaunavon, which is a nonmaterial oil-producing asset, into the market, I think, last week; and then 2 gas -- one gas asset, Westlake Corp [ph], which is, again, a very minor producing gas asset; and then some acreage in non-core Montney acreage that is in the market as well. So we're in process on the conventional disposition program. And I suspect through the first half of the year, we'll have some results to talk to you about.

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

Great. And then just one final question on potential divestments. Within the Marcellus, you've spent quite a bit of money on infrastructure and building up that infrastructure piece of the portfolio. Could you give us a little guidance as to potentially how much capital you put to work there over time, and if that is an asset that you may monetize in the future?

L. Scott Thomson

Yes. I don't have a split of actual money put into infrastructure, but it is a good question. I think one of the reasons we've been as successful as we have been to date in the Marcellus is because we've owned the midstream and the gathering. And that, I think, has been a huge competitive advantage and allowed us to ramp pretty significantly. As we go through 2012, I think, there's a legitimate question on whether that's something we think about monetizing or not. But it's not as easy at first sight because I think it plays into how much capital you're putting into the upstream as well. So it's something that's actively being debated internally, but it's not as easy as it might appear on first sight.

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

Great. And then just a final question for me. Could you potentially give us an update on where you are exiting production in the Eagle Ford and the Montney and then kind of any color around the first well results you've seen in the Duvernay and how you guys are thinking about that play over 2012?

John A. Manzoni

Do you mean exit for 2012, Matt?

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

The exit rates you achieved in the Eagle Ford and the Marcellus in 2011. So the kind of rates that you're coming into 2012 with from a production perspective.

John A. Manzoni

So let me ask Paul to see if he can give you a little bit of color on that. I'll try to dissuade him from being too detailed, but let's see what he's going to do.

Paul R. Smith

Matt, I'll use 4Q as a proxy for exit rates. So 4Q, we exited the Marcellus at 485 million standard cubic feet a day, and we exited the Eagle Ford at 55 million standard cubic feet a day. So that was the exit rate in 4Q for those plays. I think there's a question on the Duvernay in there, too. We're early into this play. We've just drilled and completed our first well. It's coming online as we speak. Our second well has been drilled and will come online before the end of the first quarter. And so the program is on track is sort of the first point that I would make in terms of the delivery of the activity sets. The second thing I'd say is you guys probably read in a lot more detail than I do, the wells that are being press released around us. And I have to say it's encouraging to see the results that we're seeing from competitor wells around us. I'm sure all of you saw Yoho's well yesterday, which is not too far away from one of our wells. And so I think encouraged by competitor results. Early days for us, and we'll have 3 more wells -- or first 3 wells behind us in the second quarter. And we'll continue then to move the rig down to the southern part of the play and start to de-risk that part of the play. And we'll look to see whether or not that's the right pace of activity as we progress throughout the year.

Operator

Your next question comes from the line of Menno Hulshof from TD Securities.

Menno Hulshof - TD Securities Equity Research

The first question is on your North American oil and liquids growth profile. You talk about growing volumes to 60,000 barrels per day by 2016. Is the Duvernay reflected in those numbers? And if not, how is that growth broken out among the Eagle Ford and other plays?

John A. Manzoni

Menno, let me ask Paul just to give you a bit of sense of that.

Paul R. Smith

Yes, I mean, Menno, I'll answer it generally. I mean, the Duvernay is at the margins of that growth. So we haven't sort of built our plans one well into the Duvernay, assuming success in the Duvernay. And so clearly, there's upside if the Duvernay turns out to be as good as we think it's going to be. The main sources of growth within that, I mean, the 2 big building blocks within that are the Eagle Ford, which will continue to see the operational momentum coming through year-by-year and generating significant liquids-based growth. We're clearly targeting liquids in the Eagle Ford and prioritizing the volatile oil and the retrograde windows in the Eagle Ford as we drill out this year's program and then the next year and the year after. And then the other big building block actually is within our conventional portfolio, which is our Wild River asset, which we've talked about before, where we've got a deep cut plant, which will come online at the end of next year. And that will generate a fairly significant liquid stream from the wet gas that we're currently producing in our Wild River asset.

John A. Manzoni

Menno, let me just add a thought on this in a general sense for liquids because the whole world is trying to search for liquids and things. We start with a relatively diverse portfolio, a lot of which, 50%-ish, is liquids before we start. As we've shifted capital through 2012 toward liquids, as Paul has mentioned, we're spending more in Eagle Ford. We are spending more in Colombia, which we think will bring more liquids on. We've got liquids coming in next year in Vietnam as we bring on HSD. So I think we can begin to see quite a lot of momentum, certainly, as we go through toward the end of 2012 and into 2013. We're going to really see that liquids momentum from quite a range across the portfolio. We've been a little more specific in North America, but in fact, it's quite broad-based actually as we look across the portfolio.

Menno Hulshof - TD Securities Equity Research

Perfect. And then I've got one more quick one on the Marcellus. If so looking at the press release obviously, you could potentially be dropping the rig count to as low as 3. And I was just wondering if the -- I know you mentioned that, that was driven by natural gas prices. But I was wondering if that is in any way related to the Pennsylvania impact fee that was just passed. And if the answer is no, maybe you could just give us your quick thoughts on the fee itself.

John A. Manzoni

Sure. Paul?

Paul R. Smith

Yes, I mean the main decision to go down to as low as 3 rigs, I mean, that was clearly driven by the external environment. I have to say that an impact fee coming in at a time when gas prices are $2.50 clearly, doesn't help, in any way, shape or form, the industry as it's looking to make returns in a very, very difficult environment. So our personal view is, "it's done". And so, the impact is relatively modest. But it does impact, I think, for all of us, producers, in the Marcellus. It couldn't have come at a worse time, I don't think. And hence, it's difficult.

Menno Hulshof - TD Securities Equity Research

Any thoughts on how that would impact your marginal supply cost?

Paul R. Smith

No. Like I said, I mean, you've seen the range. I'm sure you've read it. I mean, the range is anywhere between $150,000 to $350,000 a well depending on gas prices. At today's gas prices, it's roughly $150,000 a well.

John A. Manzoni

Paul, would it be fair to say that philosophically, we were sort of not opposed. I think it's the timing and content that have been disappointing.

Paul R. Smith

Yes. I think the distribution of the impact fee and the mechanism behind it, which prioritizes the revenue streams back down to local municipalities is one we very much supported. The timing and the magnitude of this, we were not supportive of.

Operator

Your next question comes from the line of Greg Pardy from RBC Capital Markets.

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

Just a couple of quick ones. With Colombia, hopefully, it wasn't already covered. But CPE-6, so you've got a bunch of flow test and strat drilling ongoing there. Just curious as to how excited you are on that. And then John, with respect to GTL now, where is that -- where does that stand in the overall mix?

John A. Manzoni

Greg, let me just ask Richard to see how excited he is about CPE-6.

Richard Herbert

Well, Greg, you know that we're measured in our excitement until we actually have data on which to sort of base everything. The operations in CPE-6 have gone well. We've now completed a program of 6 further wells that the operator has drilled. Those have essentially confirmed what we found from the initial set of 6 wells that were drilled. And now what we're waiting for is some environmental permits that will actually allow us to flow some of these wells and move to the next stage of planning some form of development. So until we've see in the flow test data and had a chance to understand what the sort of flow potential is, we're going to be a little bit cautious in our excitement. But we're clearly sitting on a very encouraging and extensive accumulation. What we now need to understand is quite what it's going to deliver for us, and we should have data on that sort of starting in the second quarter. Once some environmental permits are obtained, then we can start to move to the next phase of operations.

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

So Richard, let's just assume that those results come back favorable, you like what you see. How quickly then can you move to commercial order of magnitude in terms of production and so on? Is that more '13?

Richard Herbert

I think it depends on -- I mean, I think everyone understands that in Colombia, there are some quite significant delays that have been taking place with the environmental permitting process. But I mean, we're hopeful both in block CPE-6 and our other discovery in CPO-9 that, with some more encouragement in the next 6 months or so, that we could be moving to some form of pilot development potentially by the end of this year and then certainly ramping up during 2013.

John A. Manzoni

And so that's, that one, Greg. He's obviously -- he's excited and so am I. We'll see where that goes. Now on Tony's, when he's not doing his day job looking after Yme in the North Sea, he's also still overseeing for us the gas monetization options for North America. And so let me ask Tony where we are on GTL. Tony?

Tony Meggs

I think to be boring and repetitive on this, the study is progressing well. Very busy right now, bringing all the results of the web together for a midyear decision on whether or not to proceed into the next phase. By the way, the next phase is not FID, it's a feed study. So we're doing this in a measured way. The work is progressing well, and low gas prices clearly support strongly the economics of this project and also, the decision to evaluate downstream monetization options. And finally, I would add that this is not the only option we are looking at. We're looking at other monetization options, such as LNG, to ensure that we have pursued all possible avenues to realizing the full value for the gas that we're producing.

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

Okay. And maybe this is a follow-up to that then. In terms of investigating the LNG option, what's the process and timeline that you're looking at there?

Tony Meggs

Well, I think because we are in substantial discussions, I'm not actually prepared to say it right now until we have got to a point of more certainty.

John A. Manzoni

If I can just -- yes. I mean, I think, standing back from the Montney, it's a huge resource, very strategic. And this is a big long-term option. So Tony is sort of managing a series of reviews. The gas to liquid is the most public. There are others and I think it's not -- I mean, but you could be sure we're looking at all options in the context of a very large, very strategic project.

Operator

Your next question comes from the line of Brian Dutton from Credit Suisse.

Brian C. Dutton - Crédit Suisse AG, Research Division

John, two questions. I know we kind of flogged Yme here, but I want to go back at it a second time. And the market is always full of rumors and speculation, so what confidence can you give investors that Yme platform situation can be resolved in an economic and timely manner?

John A. Manzoni

So yes, you're right, Brian, I mean there has been some relatively unhelpful, and often times as normal, speculative press comment in this stuff, and it does fly around the market. I don't think it's particularly helpful. But let me see what sort of confidence do you have, Tony, about the discussions we're currently under and that we can bring this forward in a sort of timely and economic way?

Tony Meggs

Yes, clearly, a challenging project. But as we look at it today, we see no reason why the project cannot be brought to completion. The progress of activity offshore, as we've said, is well below what we had anticipated and what we desire. And we plan to move forward on the different basis, which we're currently discussing with our partners and with our contractors in order to accelerate that progress. We're doing a huge amount of work to ensure the integrity of the platform, that the engineering is in good shape. And I might point out that this is being built in Norway, which is the most demanding jurisdiction in the world with respect to the safety and integrity of equipment. So we're all over this project, and coming up with a developing -- well into a development of a new plan as to how to progress it more rapidly. And I have a high level of confidence that we will bring it to closure. Now with respect to the economics, it's still a good project. But that's to be understood that there are discussions between ourselves and our contractors which are not complete yet, which will affect the final economics.

Brian C. Dutton - Crédit Suisse AG, Research Division

Second question, John, is on strategy. And close to 4 years ago, you implemented a strategy to lengthen the stride of the company, improve the profitability of the business with lower F&D costs and position the company for renewals for exploration. So how do you rate the company's performance on implementing the strategy? Do you think the market is being too harsh on judging Talisman's performance? And maybe perhaps more importantly, 4 years later, does the strategy needs to be revisited?

John A. Manzoni

Brian, so here's what I would say. If you stand back 3 years ago, this company couldn't really project much beyond one year. I think in terms of lengthening the stride, we have a resource base now for 3 years or 2 or 3 years in a row, we've replaced the reserves by much more than 100%. We weren't doing that in the prior 3 years. So we have lengthened the stride in terms of the resource base. It is clearly subject to gas price more sustainable than $2.50. I don't think it will be there in the medium term, and I think that we have a resource base in gas, dry gas, which is among the best, at a sensible marginal cost pricing for gas, which we can expect for the medium term. So that's good. We've also got liquids opportunity. So lengthening the stride, I think, actually, medium term, tick. Lowering F&D, tick, more than 50% down over the course of the last 3 years. So we are replacing that at a much better cost than we were. So in that sense, we are making good progress. The third strand that you mentioned was the renewal through exploration. And I think the front end of that is beginning to show us some promise. That's Colombia, it's PNG, it's other areas. They don't all work, and these things take 5 to 7 years, we've always said, for an exploration portfolio, we're in year 4. So we don't want to give up on that. Now having said that, one does not sit there like a big sort of ship and not adjust to external conditions. And I think the 2011 brought 2 or 3 things actually. The first it brought is a $2.50 gas price, which clearly puts a whole different complexion, short term, onto how to respond. We also had quite an unexpected tax rise in the North Sea, which took 25% off the cash flows in the North Sea, which, obviously, has an impact. And we also didn't do ourselves any favors because we didn't execute particularly well, particularly in the area which turned out to matter a lot when the gas price is low and the oil price is high, which was the North Sea. So we had those things happen in 2011. We must respond to that. What we don't do, however, and I know that the market always says, "Well, what are you going to do? What are you going to do?" We have to be measured. We have to be thoughtful, and we have to position the company for the long term. We are in action, as I've described. We've reduced the capital. We've shifted even more capital to liquids, and we will focus the portfolio. Now it's quite difficult if you're at the front end of the year, we're only on the 15th of February, to be completely explicit about exactly how all those actions will take place except that I can reassure you the intent is clear. So I'm much more confident, actually, as I spent with Tony a considerable time in the U.K. just for the last couple of weeks. I'm much more confident that we have underpinned the delivery and execution in that part of our business than we had frankly in 2011. I'm disappointed in the outcome, of course, but nonetheless, looking forward, I think we can be much, much more confident about that. I'm equally confident that we will execute against our intent of focusing the portfolio in the areas that I've said. So my view on this is that we've actually achieved a great deal over the course of the last 3 years. 2011, external circumstances rendered some of that, in the very short term, somewhat problematic so we have to respond. You can't turn these portfolios on a dime anyway and nor do you want to. But I'm pretty clear that we have a team in place around this table that I'm talking around now, but also in the distributed sense, to take some pretty clear actions through the course of 2012. And I believe those actions will become clearer. And as we go through 2012, the buildup of the liquids that we've talked about, the portfolio focus, all of those things, I think, can be responsive to the current environment. And I think we've got to be measured. You've got to look for the medium term, but you've got to respond to the short term. And that's really where we are, and that's what we're doing.

Operator

There are no further questions at this time.

John A. Manzoni

That's the question to end all questions. Ladies and gentlemen, thank you for joining our fourth quarter call, and we'll look forward to updating you next time. And with that, we'll end the call. Thanks very much.

Operator

This concludes today's conference call. You may now disconnect.

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