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Executives

Nicholas J.R Walker - Executive Vice President of International Operations - West

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

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

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

Richard Herbert - Executive Vice President of International Exploration

Unknown Executive -

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

Helen J. Wesley - Executive Vice President of Corporate Services

Analysts

Katherine Lucas Minyard - JP Morgan Chase & Co, Research Division

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

Brian Singer - Goldman Sachs Group Inc., Research Division

John P. Herrlin - Societe Generale Cross Asset Research

Menno Hulshof - TD Newcrest Capital Inc., Research Division

Michael P. P. Dunn - FirstEnergy Capital Corp., Research Division

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

Brian C. Dutton - Crédit Suisse AG, Research Division

George Toriola - UBS Investment Bank, Research Division

Mark Polak - Scotia Capital Inc., Research Division

Pawel Rajszel - Veritas Investment Research Corporation

Robert Brackett

Talisman Energy (TLM) Q3 2011 Earnings Call November 2, 2011 1:00 PM ET

Operator

Good morning, my name is Chrissy and I will be your conference operator today. At this time, I would like to welcome everyone to the Talisman Energy Inc. 2011 Third Quarter Results Conference Call. [Operator Instructions]

This conference contains forward-looking information. Certain material factors and assumptions were applied in making the forecasts and projections to be discussed in this call as 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 November 2, 2011, news release and Talisman's most recent annual information form, which contains additional information about the applicable risk factors and assumptions.

I would like to remind everyone that this conference is being recorded on Wednesday, November 2, at 11:00 a.m. Mountain Time.

I would now like to turn the conference over to Mr. John Manzoni. You may begin your conference.

John A. Manzoni

Thank you, Chrissy. Ladies and gentlemen, good morning from Calgary and thank you for joining our third quarter call today. As usual, I have the management team with me here in Calgary, and they'll be happy to help answer your questions after Scott and I have given you an overview of our results.

First, a word about commodity prices and our outlook. In terms of gas prices, I think we're seeing the prices we expected and, frankly, expect for a while yet. Under most circumstances we see as likely, prices will remain more or less as they are to date through this year and well into next. It's still all about supply, and it'll take some time for activity to reduce efficiently to have an impact. Perhaps in our flatter forward curve will help a little, and I think we're starting to see signs of reduced capital allocations into the more marginal plays, so we can expect a gradual move upwards over time. But we believe that this would be well into next year. The wild card, of course, as always is weather this winter, which impacts storage levels. In the event of a mild winter, we could see prices getting worse before they get better. So as always, we have to take a cautious stance on that.

Oil prices, on the other hand, held up as we expected, despite the concerns over the macro picture. In some senses, the fundamental support to current prices whereas the fears over a more serious economic slowdown driven either from Europe, the U.S. or a slowdown in China or some combination of all 3, continues to make the market nervous. Provided we don't have a discontinuity or a shock in any of the areas I've mentioned, we believe the fundamentals will support prices more or less as they are today. There are obviously risks to the downside, and perceptions or market nervousness may even push prices temporarily down. But barring a significant slowdown in global growth, fundamentals will be supportive. We use a price base of about $85 brand as a floor under our expected conditions going forward.

Turning to the numbers for the quarter itself, we saw both cash flow and underlying earnings from operations increasing substantially from this time a year ago. Cash flow at $902 million was 29% up on a year ago, and more or less equal to last quarter. From a year ago, it was driven largely by higher realizations with slightly lower volumes in an absolute sense. Earnings from operations, which as you know, strips out the various one-off items, was up about 38% from a year ago to $165 million, with largely the same drivers as the cash picture. Operating costs were higher this quarter than a year ago, but more or less the same as the second quarter. Versus a year ago, they were higher in Asia, where some work to manage downhaul scale in PM3 caused an increase, and in the North Sea, where fuel gas was more expensive than a year ago. Unit cost in the North Sea were particularly impacted this quarter by the lower production there during the quarter.

We spent about $1.2 billion of capital during the quarter, bringing the total exploration development spending, year-to-date, to around $3.3 billion, and we expect to spend $4.5 billion for the full year as we've previously guided. Production for the quarter was 400,000 barrels a day, as we indicated in our operations update last month.

Looking at continuing operations, year-to-date production has increased by 10% over last year and quarter-on-quarter, has increased 3% despite the very low outcome from the North Sea in the current quarter. The growth has been driven by both the increasing shale production and, of course, the purchase of the Colombia assets earlier this year.

In the U.K., the Claymore platform turnaround was extended to complete work to meet the requirements of a prohibition notice. The platform began startup around the middle of October and is building to full production capacity now. We also took the proactive step to shut down Tartan to perform some safety-related work, primarily on the emergency refuge, which includes the control room. And that's the main reason we had to shut down the platform. The works related to the air pressure in the control room not meeting the current standards, and for such an old platform, we need to undertake considerable work to retrofit to the more recent standards.

For the year as a whole, we expect production to average 425,000 barrels a day, which is a 6% underlying production increase over last year, or 9% including Colombia. That outcome is driven in part by a significant step up in production from our shale plays in North America during the fourth quarter. Production from several of the plays has always been loaded toward the last quarter of the year, and we're seeing the ramp up that we expected. Overall in the third quarter, we averaged around 485 million cubic feet a day from our shale portfolio, with a total of 29 rigs operating. We still have 2 additional -- we'll have 2 additional rigs running during the fourth quarter in the Eagle Ford, and we expect the shale production to continue to build over the coming months, so that we'll average about 490 million cubic feet a day for the year as a whole.

The Kitan field in Australia was also successfully commissioned during the quarter and is now producing around 10,000 barrels a day next to Talisman. Overall in our Asian business, we averaged 121,000 barrels a day during the third quarter, and achieved a record level for gas sales.

As you saw in the press release, it's helpful sometimes to remember that we sold our gas in Asia during the quarter for around $9.40 per mcf.

North Sea production is expected to increase to around 100,000 barrels a day in the fourth quarter, as we complete the various turnarounds which were underway during the third quarter, with Claymore, Rev, Blake, Buchan and Ross now back online.

In Colombia, we're seeing good performance from the Equion-operated Piedemonte field, and recent field -- wells on the field have given very encouraging results, which bodes very well for the future. In Block CPO-9, the operator, Ecopetrol, has restarted appraisal drilling around the Akacias discovery. The first appraisal well in a 4-well program was spudded last month, and we plan to complete at least 2 wells before the end of this year and apply for commerciality early next year. And in Block 6, the operator will shortly begin drilling the next set of 6 appraisal wells, with the block now having been granted an exploration and production license. And in the Niscota Block, the Huron-2 appraisal well is drilling today toward its objective.

A number of other wells in the exploration portfolio are currently drilling, including Topkhana in Kurdistan and our first shale well in Poland, which is now coring in the upper Silurian shale target. The drilling program in Papua New Guinea is continuing, and although the last well found gas in a tight reservoir, we are confident we will aggregate 2 to 4 tcf of gas as planned. The deepwater Lempuk well in the South Makassar Straits of Indonesia has recently spudded. And later this month, we'll commence drilling with Situche Norte well in Peru.

So our exploration program is now moving to a higher operational phase as we predicted, and we're of course eager to see the results as the various wells reach their objectives. Together with the ramp-up in production I've outlined, the final quarter promises to be very busy.

I want to talk a little more about our outlook for 2012 in a moment, but first let me ask Scott to give you some more detail on the current quarter. Over to Scott.

L. Scott Thomson

Thanks, John. I'll review our financial results, balance sheet, acquisitions and disposal activity in the quarter, and our hedging position.

Cash flow and non-GAAP earnings from operations of $902 million and $165 million, respectively, were flat compared to the immediately preceding quarter, and lower production volumes and slightly lower commodity prices were offset by the fact that we had more exposure to oil prices, given a lower hedge position on our oil production.

Cash flow increased by $202 million relative to the third quarter of 2010 as a result of higher commodity prices. The full impact of price increases was partially offset by higher operating costs.

Non-GAAP earnings from operations increased by $45 million to $165 million, as a result of the same factors, offset by higher deferred taxes.

Netbacks were 18% higher than the corresponding quarter in 2010, with higher prices being partially offset by higher operating expenses and higher royalties. Operating expenses of $550 million were relatively consistent with the immediately preceding quarter, as lower operating costs at Claymore during the shutdown for safety upgrades and lower processing tariffs at Rev due to the shutdown of the host platform were offset by higher maintenance costs in Southeast Asia and the startup of Jambi Merang.

Unit operating expenses increased due principally to higher maintenance activity and lower North Sea production. This was offset by lower unit cost in North America, which decreased by 5% relative to the third quarter of 2010, and by 17% year-to-date as a result of the transition to unconventional shale development and the sale of high-cost conventional assets in 2010.

Depreciation expense of $455 million was flat compared to the third quarter of 2010, as the addition of Equion was offset by lower volumes. Lower volumes accounted for the $25 million decrease relative to the immediately preceding period.

Current income taxes were $270 million in the third quarter, down $165 million from the preceding quarter due to lower North Sea revenues resulting from lower production. Current taxes this quarter were in line with the third quarter of 2010, as the impact of higher oil prices and the U.K. tax rate change was offset by lower production in the North Sea.

You will recall we had a significant buildup of inventory during the first quarter of 2011, which had a negative $80 million impact on cash flow. Following an inventory reduction of 600,000 barrels in the third quarter, the negative cash flow impact has largely reversed in the year-to-date numbers.

Capital expenditure, including exploration expense was $1.2 billion during the quarter, with $190 million spent on international exploration, $300 million on North Sea development, and $630 million in North America, approximately 80% of which, related to shale activity. Year-to-date, we have incurred exploration and development capital expenditure of $3.3 billion, and continue to expect a full year total of approximately $4.5 billion.

During the quarter, we closed 2 transactions for additional undeveloped land in the Eagle Ford shale play for approximately $130 million. And year-to-date, North America undeveloped land acquisitions total $640 million.

At September 30, there was $420 million of cash on the balance sheet, and total debt at $4.1 billion was slightly lower than the $4.2 billion of total debt at the end of 2010.

Turning to our hedging program. In the third quarter, we had $65 million of cash outflows associated with our financial hedges. This was a significant reduction from the $120 million of cash outflows in the second quarter, as 20,000 barrels per day of out-of-the-money collars were replaced by $90 puts. In addition to the puts, we continue to have 50,000 barrels per day of oil hedged in 80 x 95 collars for the remainder of 2011. In 2012, we have 40,000 barrels per day of oil hedged in the first half of the year in 90 x 145 collars, and 20,000 barrels per day hedged in the second half of the year in 90 x 148 collars. On the gas side, we have approximately 100 mmcf per day hedged in collars and swaps at $6 NYMEX for the remainder of 2011, and no gas hedges in place for 2012.

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

John A. Manzoni

Thank you, Scott. So a word about our 2012 outlook. As we look toward 2012, we're still formulating our plans and capital allocation, but I want to give you some pointers as to how we're thinking.

As I outlined earlier, we have a great deal of activity building in the final quarter of this year, as we continue to execute the strategy and build the business for the long-term. And our capital plans next year will reflect that business build, but will also reflect some degree of additional focus as we move into the year.

Capital is likely to be reduced into the dry gas plays and redirected toward our liquids-rich Eagle Ford play and also to Colombia, where we're seeing success with the drill bit. And we're also planning to take steps to focus our portfolio some more in a number of areas. First, our North American conventional portfolio, where we have considerable potential, which we believe we are not maximizing, because we're concentrating on building the shale portfolio. Therefore, we're considering options to maximize value from the conventional business. In some cases, these assets may be more valuable in other's hands, but we're also considering some more creative ways of leveraging other people's resources to mutual benefit in that portfolio.

In addition, we've been disappointed with the volatility in the North Sea over this year, and we're considering options as to how we take steps to reduce our exposure to that part of the portfolio. Perhaps via some farmouts or dilution in certain assets, just as some examples. I'm not signaling radical change, but I am signaling that we're looking at various options to reduce the impact of the volatility within our portfolio over time.

And finally, we'll examine our exploration portfolio as we complete the drillout of the various plays. If the exploration is successful, it's not necessary for Talisman to develop all these areas ourselves, and we'll examine the portfolio in that light, to find the natural moment to maximize value via an exit of certain areas.

I've not given you any specific actions today and nor frankly do I plan to, because we haven't defined them yet. But I do want to signal that we're working to define a set of actions which will, over time, evolve the portfolio to a greater focus. We'll continue to update you on the progress, and I'm expecting that early in the new year, I'll be able to give you a little more specifics in some of the areas that I've mentioned.

So ladies and gentlemen, that's all we wanted to say. And now, we'd be very happy to answer any questions you may have.

Question-and-Answer Session

Operator

[Operator Instructions] Your first question comes from George Toriola from UBS.

George Toriola - UBS Investment Bank, Research Division

The question I have pertains to your portfolio outside of the North American shale gas business and the North Sea, and clearly the producing assets in Indonesia. Outside of those, do you sort of talk through how you would rank that portfolio? Kurdistan, Papua New Guinea, Peru, those types of places? How would you would rank them? How much -- what metric you would use to rank them? And in terms of cycle time from entering into a certain play or certain type of asset, your cycle time to production?

John A. Manzoni

George, let me -- I think you're talking about the exploration portfolio, would I be right?

George Toriola - UBS Investment Bank, Research Division

That's right. That [indiscernible]

John A. Manzoni

So let me just see if I could make a couple of general comments without being sort of too specific for you at this stage. Clearly, our exploration portfolio, always good to find oil if you can. Although gas, in Asia, being linked to oil prices, is a good thing as well. And as I mentioned, the realizations there are really quite healthy. In a general sense, we look for both -- so we look for hydrocarbon phase, and hence, realization. We look for materiality in scale. So in Talisman's portfolio, we want some area to be able to build to around 50,000 barrels a day if it's going to be in the portfolio. And then we look at, as you say, the sort of time to development. And those things do vary. So just as an example, PNG, actually a proven basin, we're drilling out and we're finding gas. And clearly, we have to work in parallel with how that gas can be monetized, but the basin risk is low and we're proving and aggregating gas. Makassar, actually, much longer time frame. If we find gas there, it's likely to be offshore Indonesia LNG scheme. So we have to think about that in the context of length of time. But it, again, even if we're successful, that may be something that we say that's more valuable to somebody else, because Talisman has a shorter time frame. For example, no decisions made yet: Peru, we've had a very successful well, we're drilling another well, we found the only light oil in Peru. The question for that one is materiality. What can we do? Can we get that to materiality? And what are our options to do that? So these are the sort of questions that we're examining our exploration portfolio through, and that's what I really mean by through those various lenses. Over the course of the next few months, there may be points in time at which it's natural for Talisman to -- let's hope they're all successful. We couldn't do them all if they all were successful, and therefore, we could make some decisions about various exit routes along -- at various points as in that portfolio. I haven't answered your question directly, because it's a sort of qualitative answer and a qualitative question. But does that help?

George Toriola - UBS Investment Bank, Research Division

It certainly does. And in terms of -- does it get to a point where you sort of say to yourself, we've been in country for 5 years, 10 years, whatever. And you haven't got in the materiality, and you start to then reduce your footprint. Is that something that you worry about? Or you just sort of say, well, we'll keep it in the portfolio and we'll progress as we can.

John A. Manzoni

I think we've got to show some discipline. If we're hanging around there not finding any hydrocarbons, let it develop over within a timescale that we would like to see and that we can see can get material, then I think we have to be disciplined in our decision-making process and find a way to back out and concentrate our limited resources on something that can meet those criteria.

George Toriola - UBS Investment Bank, Research Division

Okay, great. Just one more quick question for me. When you say that you're going to sort of reduce your capital spend on dry gas and focus on liquids-rich and other opportunities like Colombia, does that mean that the Marcellus and Montney would see reduced capital expenditure?

John A. Manzoni

I think -- I'm just looking at Paul, who is sort of indicating I might as well answer this. I think the answer to that question is likely yes, George, as we think about our capital allocations into next year. I think where we've got other things to spend money on, then I think you can expect that we -- and we haven't finalized these plans yet -- but you can expect that the allocations into both the Marcellus and the Montney are likely to be less than they are this year.

Operator

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

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

Maybe just to focus a bit on 2 bigger liquids growth areas. Just wondering if maybe Richard could give us an idea of what we should expect in Colombia over 2012? And if we can maybe just do same with the Eagle Ford?

John A. Manzoni

Okay. Why don't we go to Richard for Colombia, and then we'll come to Paul for the Eagle Ford. Richard? Ladies and gentlemen -- oh, there he is. Great, thanks, Richard.

Richard Herbert

I'm actually in Colombia at the moment while answering this question. So let me just give you an update on what's coming up here. I mean in 2011, we've had a little bit of a hiatus in drilling activity, partly driven by in Block 6, converting the land [ph] to an EMP license, and also through a number of permitting processes to allow us to drill the next set of wells. But we're now sort of getting back into sort of quite busy operations again. So in Block 6, with Pacific as operator, we are shortly going to start drilling the next suite of stratigraphic wells. I think 6 are planned at the moment. Also some 3D seismic. And the attention in 2012 will be to flow test some of those wells. And I think that program will give us a good indication of the resources that we plan with the initial stratigraphic drilling program in that block. Turning in to sort of heavy oil wells, and moving to Block 9, in Block 9 we made the Akacias discovery late last year, and that was still on long-term tests producing nearly 1,600 barrels a day gross, with a very stable water cuff [ph] of around 10%. So we've had good results from that test and we're now drilling the first of several stratigraphic sort of follow-up wells to appraise the size of the discovery. And there's the second well, which was spudded last month, is now at the top of the reservoir. And we should shortly know how sort of whether we can extend the oil column down deep on the structure. And this well will be followed up with 3 further stratigraphic wells late this year and into early next year, and also some 3D seismic. So we're going to acquire a lot of data on our Block 9 discovery during the next few months. Turning to the Talisman-operated block, Block 8, this is the large block further to the east of the Rubiales field. We're going to start stratigraphic drilling there during this month and drill our first 2 stratigraphic wells in that block. And we are also, turning to the foothills acreage, we're currently drilling the Huron-2 appraisal well on the Huron discovery that was made in 2009. And that well is down to about 8,000 feet. It's quite a long well. So we've got some way to go, but we'll get results from that in the first half of next year. And also in 2012, we'll spud an additional appraisal well, Huron-3, on the same field. So I think those are the main highlights. There's certainly going to be a lot of news and results coming in from Colombia during the next 6 to 12 months.

John A. Manzoni

Thank you, Richard. Maybe Paul can talk a bit about what we're going to do in the Eagle Ford going forward -- ?

Paul R. Smith

Yes, sure. Greg, as you know, at the beginning of the year, we ramped up a little bit slower than we had anticipated, really building organizational capability from scratch, building the supply chains that were needed to run an operation at the scale that we're now running at. And thirdly, underpinning sort of the egress in midstream out of the Eagle Ford, which as you know, with nearly 300 rigs up and running, has probably been more complicated than we imagined. We're in great shape on all 3 of those dimensions now. We are now up and running, and the machine is starting to really gain momentum. And then just to sort of illustrate that to you, we're running with 9 rigs today. As John said, we'll add a 10th rig in next month. We've only completed, year-to-date, in the Eagle Ford about 14 wells to the end of the third quarter, and we've got over 30 wells coming on in the fourth quarter, and that sort of gives you a sense of the momentum that's now building with the machine. In terms of results, limited set of results from 14 wells. Let's say that everything we're seeing is in line with the 660,000-barrel EURs that we externalized to you at the beginning of the year. So everything is going good, and we expect to sort of go into next year with real momentum, which is the key.

Operator

Our next question comes from the line of Bob Brackett from Bernstein Research.

Robert Brackett

Any size and probability of success on Lempuk? What should we expect there?

John A. Manzoni

I'm sorry, can you maybe -- on Lempuk? Oh. Richard, what would you say about Lempuk at this early stage?

Richard Herbert

Well, the Lempuk well is drilling in the South Makassar basin, which is a very frontier basin. It's very hard to predict exactly how big it's going to be because we call this a sort of new play set. And the well is drilling down to a target which is a kind of reservoir target sitting on a big [indiscernible] block. So it's potentially a large structure, but what we don't know at this stage is the extent of reservoir development on it, nor if there are hydrocarbons in it. What will be the sort of vertical height of the columns? So to make any estimate of volume at this stage will be speculation. But by early December, if all goes well, we should be down at the reservoir level and testing it. And if it works, not only could this be quite a significant discovery, but it sits in a basin which is almost totally undrilled and has a large number of other undrilled structures in it. So it's a very interesting well. .

John A. Manzoni

Thank you, Paul. Maybe we'll wait for a Christmas present on that one. We'll see how that goes.

Operator

Our next question comes from the line of Brian Singer from Goldman Sachs.

Brian Singer - Goldman Sachs Group Inc., Research Division

Can you talk a little bit more about the Poland shale wells that you're planning on drilling here, including the one that had just spud? Can you kind of define what you're looking for, for those wells, both in terms of reservoir characteristics and, I guess, the rate?

John A. Manzoni

Good. So this is back to Richard, again. Richard, Poland this time.

Richard Herbert

Yes, Brian. Just a quick summary of what we're doing in Poland. We're in the North Baltic basin where there's quite a lot of activity going on. We are operating 3 blocks there. And the current phase of activity, we're going to drill 1 block in each of the 3 wells -- sorry, 1 well in each of the 3 blocks. And then based on the results of that, this is really to collect geological data, and with encouragement, we will then plan the next phase of activity, which would be to drill some horizontal wells starting later next year to then frac them and try to determine some commercial flow rates. So we're still fairly early days. We're drilling the first well right now, and that well has reached the first of the shale units that we're interested in, which is the Silurian age shale and we are collecting core in that. And the plan is to complete this well, and we have 3 -- going for potential interest: The Silurian, the Ordovician and the Cambrian. And then the rig will move on and drill 2 further wells in the other 2 blocks in the program that will finish early next year. And as I've said, based on some success and encouragement from this first stage, we'll move onto the future stages. I mean, what we're looking for here is very similar to our North American shale plays. We're looking for high TOC, we're looking for shale sections that can be frac-ed and that will produce at commercial rates. And we're applying a lot of the technologies we've been using in the Marcellus and Montney and the other plays.

Brian Singer - Goldman Sachs Group Inc., Research Division

And how would you think about lifecycles or timing to development? Maybe going back to the earlier question on kind of prioritization. Is this a play that you think could be developed in a reasonable amount of time, if successful, what time do you think that is?

John A. Manzoni

Maybe I'll -- go ahead, Richard.

Richard Herbert

John, should I go ahead? I mean, we're looking at a number of options for that, Brian. I mean, it's still early days. I think we're still at this stage of proving the play, both as Talisman and as an industry. I mean, there are a number of encouraging potential markets, the domestic Poland market that started the potential to invest into power, and of course, ultimately the potential to export into Western Europe. So all of these things are being looked at. There is existing infrastructure, but it would clearly need to be upgraded. And I think we're still in early days. But from our perspective, Poland would be a very exciting supplier of gas to Europe.

Brian Singer - Goldman Sachs Group Inc., Research Division

And lastly, in Papua New Guinea, can you just put into context the size in one well? Or is that just a one-off well that's on gas, the noncommercial gas? Or how should we think about that well in the context of your program?

John A. Manzoni

So just within our internal accountabilities, Paul Blakeley looks after Papua New Guinea. So I'm going to ask Paul to see if he could answer that question, please, Paul.

A. Paul Blakeley

As per John's discussion earlier, overall, we are excited about the play in the western province of Papua New Guinea. And the context of Siphon-1, which did find hydrocarbons, but a tight reservoir section. We will continue to get occasional surprises. Our early program, essentially, was designed to meet some short-term license commitments. We're out from under that now. Siphon was one of those. And we'll take a more measured view about activity going forward. But this is still a great hydrocarbon province, way more successes than failures in drilling, and we're working hard to increase that success rate.

John A. Manzoni

Doesn't really change our strategic stance on this, Brian. I think one well, in that context. Although as Paul signaled, we are likely as we get forward to be able actually to take a more measured and paced approach in Papua New Guinea because we're through those, the rather complex phase of initial license commitments, which were causing wells to be drilled in order to hold onto various bits of the acreage. So I think we can see -- you're going to see a bit of a change of stance, but it doesn't change the underlying strategic context.

Operator

Our next question comes from the line of Mark Polak from Scotia Capital.

Mark Polak - Scotia Capital Inc., Research Division

John, you mentioned a potential Christmas present from Lempuk. Is that sort of year end that we would expect to possibly hear some results from that well?

John A. Manzoni

I hope I'm right. Richard, when would we be expecting to enter the reservoir in Lempuk or get some sort of indications?

Richard Herbert

Well, Lempuk, it was probably early last week, just over a week ago, and it's a sort of targeted to the 50- to 60-day well. And as I've mentioned earlier, I think -- if all goes well, and of course, it's always difficult to predict in a new basin where we haven't drilled before, but so far, we're on target to reach the reservoir in early December. So we should have -- we should certainly have some results from the well before the end of the year.

Mark Polak - Scotia Capital Inc., Research Division

In terms of the acreage you acquired in the Eagle Ford in the quarter, can you give us a sense relative to your existing position, is it contiguous to that? Or possibly, which counties that's in?

John A. Manzoni

Paul?

Paul R. Smith

We have 2 small bolt-on acquisitions right in the core of La Salle and KDB acreage, 2 transactions, as Scott mentioned, total of $130 million, at what we believe were reasonable prices relative to the benchmarks that were set in the basin in recent months. So highly contiguous so we're [ph] building out to make sure that we have higher land utilization right in the core of our retrograde and volatile oil window in those counties, which is, as you know, is the heart of the play for us and, I think, for most people.

Mark Polak - Scotia Capital Inc., Research Division

Great, and one more for me, if I could. Just in terms of your Marcellus type curves and EUR of 5 bcf, now that given how low you've been at it now, you've had a bit of history of increasing that EUR assumption over time. I think it's still a bit conservative or lower than some of the other operators there. Just curious if you think there's possibly more upside to that 5 bcf for -- or perhaps there's a difference in how those wells are completed relative to some of the other operators.

John A. Manzoni

Just how we like it, Mark. Paul, how does the -- how do you feel about the EURs and the IP?

Paul R. Smith

I think the real results that we're seeing to date, as you know, we're concentrating in the west for most of the program this year. There's no reason to change the assumptions that we've given you, which is 5 bcf EURs and IPs of 4. Clearly, we see variability around those, up and down. But I don't think we're in a place to change those today. As we move east, it's clearly where you indicated sort of larger results from other operators. A lot of those results are coming in towards the east of where we've been drilling, and we haven't been drilling there yet. So we'll find out more about drilling into the east next year, which forms a big part of our program, reduced program in 2012, as moving east and into some of the Susquehanna county type acreage, where we've -- which we accumulated 2 or 3 years ago. So way too early to tell. Guidance remains.

Operator

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

Brian C. Dutton - Crédit Suisse AG, Research Division

John, I was wondering if you could spend a moment talking about capital efficiency. While it's early days for 2011, are you seeing capital efficiency the same or better this year versus last year? And with the kind of program for capital that you're now contemplating for 2012, what are your expectations on the capital efficiency for next year?

John A. Manzoni

Well, Brian, as you know, we always -- I mean, we essentially run our capital programs by looking essentially at all of the projects on a consistent basis at any point as we formulate plans. And of course, it isn't only done on a spreadsheet, it never is. But all of the projects and the allocations of capital are ranked. We use what we call a DPI measure, which is the present value of our present cost, which is an efficiency metric, a return on capital employed and internal rate in return. So we look through a series of lenses. Clearly, as we -- which is why you're hearing us talk a bit about redirecting capital away from some of the gas plays into the liquids plays. Because our views, I think, along with everybody else's, have evolved over the course of 2011 about how quickly the gas prices may be recovering. I've said, I think, we should plan at least for 2012 will be at very similar levels to this year. So on that basis, and in the mind of operational requirements, you don't turn these things on and off overnight, but we can signal reduced capital, and hence, by which you can interpret, we have more efficient deployment of that capital into other areas in our portfolio. And so, that's what -- I mean, we're always looking at that. I would say to you that, as we go -- as we put the plans together for 2012, that's -- I would say, as I think about the stats, the main shift that we're going to be reflecting as we put the final 2012 plans together, sort of less, less dry gas, mindful of everything else, and all the other constraints that one thinks about. And then the other one, of course, which is always a big question, is the exploration portfolio, which of course piles -- as we put $700 million a year into our exploration drill bit, which of course doesn't return at all for some years. And that's why we're also looking, as I've indicated, at the sort of long end of the exploration portfolio. Because while we might find hydrocarbons, but if it's 10 years away, then we've got to take a different view. If we were a much bigger company, and we had much longer legs and we have many more options, then maybe we can hold that in the portfolio. But for Talisman, we have to be mindful not to be drilling into too much stuff that's very, very long-dated. So that's the other lens which I think -- character which will move us to a greater capital efficiency in terms of returns for dollar invested, as we move the plan in 2012. And I think -- I mean, I don't know if [ph] that gets your question. Does that help?

Brian C. Dutton - Crédit Suisse AG, Research Division

That helps, but I guess looking at 2011, if you exclude the big Duvernay land purchase, do you think you've got more bang for your buck on your dollars spent this year in terms of reserve adds, in terms of the efficiency going up and your cost per unit going down for 2011 over 2010?

John A. Manzoni

Haven't actually -- oh, for 2010, you mean?

Brian C. Dutton - Crédit Suisse AG, Research Division

Yes.

John A. Manzoni

Well, what we've been doing of course -- I mean, one metric on that would be F&D and recycle ratio. Those metrics are moving in the right direction. I haven't actually looked because we haven't quite finished all the numbers for 2011. But in a trend sense, those trends are moving. Both recycle ratio and F&D are moving in the right direction, 2011 over 2010. So I think -- those, I think, we can be relatively confident are reflective at least of long -- medium-term capital efficiency, Brian. I haven't looked at in-year versus in-year, to be honest, that's why I don't know how to answer your question. But in a trend sense, that of course is the intent of the strategic reposition that was done a few years ago. And indeed it's been working. So I think for that, there's a measure, and I think 2011 does move, in a trend sense, in the right direction on those metrics..

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 on Latin America. For Akacias, if your play [ph] is successful, how should we think about the resource potential that you're potentially chasing? And would Chichimene, the structure itself, be a good analog for the size of the structure you may be looking at Akacias?

John A. Manzoni

Let me ask Richard to talk about Akacias and what we know about that.

Richard Herbert

Yes, certainly, Matt. It's early days. So Akacias, we've got one well, which the one I described earlier which has gone test. That well had oil in a tertiary reservoir right down to the base, and so we don't yet know where the oil-water contact on the structure is. And that's the reason why we're now moving into the next phase of drilling several more wells to try and establish. And there's sort of -- there are a series of wells that will step further and further down deep looking for the oil-water contact. And of course, every time we step out and this contact is extended deeper, we'll clearly see larger reserves. So we can't really put any numbers on it today. In terms of Chichimene, the relationship of Akacias to Chichimene is an interesting sort of geological conundrum at the moment. We're sort of down dipped from the Chichimene field, which is a structural closure at a higher level. We are exploring on the flanks of that. And I think it's going to take a few more wells and probably some more seismic data to actually understand how it all fits together. But big range at the moment, but looking very encouraging. And we should have some more results in the next few weeks from the current well.

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

And just a follow-up on that trend, in terms of Humadea, when would you expect to spud the exploration well there? And on the historical well that you do have data on, am I correct in the assumption that you actually did see oil pay in the well, but it just wasn't flow tested?

Richard Herbert

Yes. Humadea is sort of just south of -- to sort of southwest of Chichimene. We have an exploration well planned there. The sort of backlog of permitting that's sort of affecting the industry in Colombia at the moment, it's pushed that well out of the end of this year into 2012, but we're hoping that those permits will come through and allow us to start drilling that well, certainly in the first half of next year. We plan to dig 2 operations on Humadea. One is to drill a new exploration well, which will test some of the deeper stratigraphy. And in addition, we plan to try and go back into the old well that you've just referred to and try and do some tests in it. Because it's clear, from looking at the logs and the history from when that was drilled, that it had some oil in it, but it was never properly tested or evaluated. So we're going to try and get some data from that.

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

And then one last question in Peru. In terms of the Situche north prospect, if that appraisal well is successful or the exploration well is successful, how should we think about the resource potential for that play?

John A. Manzoni

Richard?

Richard Herbert

The Situche complex is -- it's a series of fairly closely linked structures and we've only, so far, drilled one of them, which is the Centrale structure. And we have found an estimated 40 million barrel gross in the Centrale structure. We've now moved to drill -- the well we're about to start drilling this month is on the Norte structure, just to the north of it, and this is the largest structure in the complex. And we think that if this works, it will probably have in the order of around 55 million barrels, again, gross. So that will put the total from those 2 features in excess of 100 million barrels of light oil, which is a significant resource in a country that has limited light oil resources. There are a number of other bumps that we could potentially follow up and drill in the future. We would need to acquire some more seismic data to fully image those. But this next well is really the key one to define the resource in the complex.

Operator

Your next question comes from the line of Pawel Rajszel from Veritas Investment Research.

Pawel Rajszel - Veritas Investment Research Corporation

Wondering if you could give us an update on service costs in your shale plays and where you see that going over the next year or so?

John A. Manzoni

So let me ask Helen to talk generally a bit about service costs in North America, if you could, Helen, and how we mitigate and all that?

Helen J. Wesley

So generally, we try to put some contracts in plays for a minimum of 12 months and shoot for fixed priced contracts wherever possible. We're not seeing a huge amount of volatility in costs currently. In services, we are seeing some inflation in rig costs and we're generally putting in place some mechanisms to keep us roughly flat through into 2012. And I don't know, Paul, if you want to talk more specifically about some of the individual service areas?

Paul R. Smith

Yes, I mean, in terms of -- as you know, we've positioned ourselves a few years ago with long-term contracts, in particular on the completion side, which we saw as the most scarce commodity, as pumping services were going to see greater and greater demand. We feel pretty good about the long-term contracts that we have in place across our shale portfolio that underpin the majority of our completions activity in all of our plays going forward. And we have -- that provides a certain level of protection for us. I will say that within the Eagle Ford, it has been particularly challenging. Clearly, there is an unusually large ramp up in the Eagle Ford happening very, very quickly as all operators are drilling into this high-quality play. And we have seen some pressure on rig costs. But again, we've underpinned about 2/3 of our rig portfolio with long-term contracted new build rigs coming in that provide the sort of efficiencies that we're going to be looking for, albeit at slightly higher day rates, which we are already seeing will be more than offset by operating efficiencies. So I think it's something we need to absolutely keep our eye on, day-in, day-out. And are looking to creatively look to make sure that the rent distribution remains in a fair place.

Pawel Rajszel - Veritas Investment Research Corporation

So if those long-term contracts were in place, roughly what kind of inflation do you think you'd see?

Paul R. Smith

I mean, in the Eagle Ford, you guys can go and see for yourselves. But if you wanted to pick up a spot frac crew today, you're going to be paying close to $350,000 a stage. We're significantly lower than that.

Pawel Rajszel - Veritas Investment Research Corporation

Okay, and Paul, in your presentation material, you've got a 2015 breakeven target, probably about $0.50 per mcf lower than what it is now. What are the driving factors behind the improvements you think that will help you hit that 2015 target?

Paul R. Smith

I mean in simple terms, Pawel, it's 2 things. Every -- we're early into the play. And 2 things tend to happen as we move into sort of full factory mode in a play. Firstly, we learn a lot more about the reservoirs and the way to complete the wells. Like I said, with 14 wells in today and we have limited data. We're still experimenting a lot with completion designs and technology. Over the next few years, we will be refining that. And one would expect, as we've seen in every other shale play, that EURs come up correspondingly, as you'd expect, as we learn more about how to optimize completion techniques and indeed drilling techniques into a shale. And then secondly, concurrently with that, we fully expect to see the efficiency gains of coming down the drilling and completions curve, as we move at scale into a play. And I think we'll start to see the first signs of that in the Eagle Ford next year. This was a building year, and next year will be a year of learning and delivery. So those are the 2 dimensions, Pawel, that would have the biggest impact on bringing those breakeven costs down.

Pawel Rajszel - Veritas Investment Research Corporation

I guess it's fair to say you're expecting EURs to still keep going up over the next few years, as well as drilling and completion costs and the scale and efficiency of that, working its way through the capital for the well?

Paul R. Smith

I think it's too early. Like I said, 14 wells in. 660,000 barrel EURs is sort of a good number that we've given you, and there's no reason to change that. Drilling and completion cost, we should see -- we are seeing coming down, and they will come down next year.

Pawel Rajszel - Veritas Investment Research Corporation

Okay, that's helpful. And then you've got JVs that your other shale plays, except for Marcellus. What are your thoughts about getting a JV on Marcellus?

John A. Manzoni

Maybe I'll answer that one, Pawel, if you don't mind. Because it's all part of the -- thinking about the cash balances as we go forward next year, clearly, it's JV-able, should we choose to do it. It's a very popular place. Lots of people want to be there. We're actually one of the leading operators in the play. We understand what we're doing. We have all sorts of -- we have the egress, we have the rigs, we have the operational capability. So if somebody wanted to come in, we could easily put that into a JV, if that's what we chose to do. But I think what we have to think through for ourselves is how the totality of the firm in terms of cash in and cash out works next year. And frankly, that's one of the decisions that we have not yet made, but it's one of the decisions that forms part of the whole balancing act as we go into 2012. So could I leave it at that for you?

Pawel Rajszel - Veritas Investment Research Corporation

Yes, sure. And then -- so, I guess, you kind of mentioned the potential for decelerating the CapEx going towards Montney and Marcellus. Does that in anyway impact your 5% to 10% growth rate that you kind of expect going forward?

John A. Manzoni

Well, I think -- I mean, the answer to that question is, it could, because we could choose to -- because those are the ones that are up and running. They're obviously building. They're the fastest. If we chose to put it into less mature liquids plays, then that would be a different character of growth. So I think, maybe it could. But again, too early. And again, as we think about 2012, we're obviously mindful of the macro environment, we're mindful of a cautious stance on our balance sheet as we go into 2012, or we're mindful of an number of factors. So again, to be determined, frankly, and we'll tell you in January when we've determined. But the answer to the question directly is, if we chose to significantly reduce capital into those plays, which are currently driving hard and growing, then it could have an impact of course on the growth rate of the company. And that's why we've got to be reflective of all of that balance going forward. I mean, we can always grow. We can more or less put the growth where we want to. We can always grow, if everybody likes lots of millions of cubic feet of gas per day of growth, the issue is whether that's wise and sensible in the current gas price environment. So that's the sort of balancing act and the thinking that we've got to do between now and January.

Pawel Rajszel - Veritas Investment Research Corporation

Fair enough. And just one last question. You've kind of told us over the last little while that the portfolio transformation has been largely complete. The conventional North American assets, you've kind of reduced to more of an oilier exposure and North Sea has always been pretty volatile. I'm just wondering, what caused this kind of change of heart or this investigation into some of these thoughts you're having about changing the portfolio?

John A. Manzoni

Well, I think that's quite a good question. The world -- 2 things, the world continues to be dynamic, and one never wants to be caught in a fixed place if the world conditions change. And actually, the world conditions have changed, frankly, since we -- gas prices are now very low, much lower than they were when we set out on that original strategy and such things. And we had anticipated, for instance in our conventional North American portfolio, we'd said, well, gas prices suddenly went low. We said, we might pause here, because they might come back. We might -- the dynamics of the gas market might be changing. Now I think if we look at it, and generally, people would say maybe they're changing so fast. Maybe this is it. Maybe we are here or hereabouts for a while. And in that context, we can reexamine some of that stuff. And it turns out, a year later or 2 years later, when we reexamine our conventional portfolio, that we actually we've directed resources into our shale portfolio and we're actually under-leveraging, in our view, many parts of our conventional portfolio which hold huge potential. So the question becomes, okay, how could we get at some of that potential in our conventional portfolio? So that's one set of things which changes. Second set of things that changes are about internal. The North Sea has always been volatile, but if you recall, in 2008, we said that the North Sea, for us, was a sort of high-quality cash generation machine. And for a number of years prior to that, it had actually been volatile and it had, in some senses, been -- it had missed some targets, that have caused the company to miss some targets. And for 2 or 3 years now, we haven't done that. We haven't missed our targets. We hit our targets, except for this year. And this year, we've missed our target and we had to downgrade the guidance and it put a -- in some sense, it put a power [ph] across the company. There's so many good things going on in the company. There's so many good things being built for the future. And the fact that guidance was missed has been interpreted by the market as -- there's been a huge reaction. It's a very difficult thing to deal with. And it's all because, for the first year in a number of years, the North Sea actually surprised us again. And that's why I keep talking about the volatility and the reduction of exposure to that volatility. So that's the reason. It's about our capacity to execute at the level at which we've set it. Our capacity to be consistent, and consistently execute and execute well at the levels that we've set. And therefore, if we can't do that, that part of the portfolio is no longer playing the role that we wanted it to play. And therefore, we have to reconsider. So there's an internal reason why we think about going back to that portfolio again. I don't -- again, I think this is a continuous evolution. I think any management team that just sits there and says, well, we determined the strategy 3 years ago and that's what we're going to continue to blindly implement. That would be wrong. So we are really reflecting a dynamism here that says we're reacting to both internal and external complexed [ph] and continuing to evolve the portfolio in order to position the company best we can for the future. There's a bit of an answer for you, if that helps.

Operator

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

Menno Hulshof - TD Newcrest Capital Inc., Research Division

I've got a -- I think I've got a couple of quick ones. The first is on EMA. Could you provide a quick update on the rework that is getting done and as to whether or not you're coming up against any surprises? And then as a follow-up to that, can you comment on your overall level of confidence in the Q2 start date and what we can -- we should expect the ramp-up profile to look like into year end?

John A. Manzoni

Let me turn to Nick Walker and talk a bit about EMA. Nick?

Nicholas J.R Walker

Yes, so the remaining piece of work we have to do on EMA is to -- commission on the top side. They were installed in June, so we've been working on that since then. We've talked in previous conference calls around the issues around EMA. And it principally revolves around the quality of work being completed by our contractor on this and requiring a significant amount of rework. So we've spent with our contractor, SBM, a lot of time getting under the scope of work, and I think we founded it very well. And we've agreed a schedule with SBM to get the project complete, which will see us getting first production towards the end of 2Q 2012. So I feel -- and I've also seen that SBM are much more focused on getting this done. I feel we're in a good place to achieve that. And so I'm feeling pretty confident that we'll get first oil as we've outlined.

Menno Hulshof - TD Newcrest Capital Inc., Research Division

So it's conceivable that we see a ramp-up here to something in the range of something close to capacity towards the end of the year?

Nicholas J.R Walker

Well, actually, the way we see it is once we get first oil, we see ramp up over a couple of months, once we get the facilities stabilized. And so I think...

John A. Manzoni

Before the end of the year, Menno.

Menno Hulshof - TD Newcrest Capital Inc., Research Division

Okay, perfect. And then I've got a really quick follow-up question to Mark's question on your Eagle Ford acquisition. Can you comment on whether those assets were purchased from KKR? And if not, what would the metrics have looked like on a per acre basis or otherwise?

John A. Manzoni

I can -- actually, we're just looking at each other wondering what we can confirm and what we can't. Now, Paul...

Paul R. Smith

One of them was in the public domain, so I can confirm to you that it wasn't KKR that we purchased those assets from. One of them, one of the asset transactions was St. Mary's. It was in the public domain, they've put a press release out. We paid roughly $15,000 an acre for the acres that we bought right in the heart of the retrograde and volatile windows next to our hubs, Menno.

Operator

Your next question comes of the line of John Herrlin from Société Générale.

John P. Herrlin - Societe Generale Cross Asset Research

Quick ones. With the Eagle Ford, could you describe the wells? Whether you were drilling the retrograde ones, as you call them, are they oil wells, was it split? Because you've never given that kind of detail.

John A. Manzoni

Sorry, it doesn't sound --

Unknown Executive

I wouldn't -- which rig are we drilling it?

John A. Manzoni

compensate the old gas, dry gas?

John P. Herrlin - Societe Generale Cross Asset Research

Right.

John A. Manzoni

So John, we've positioned ourselves in -- we sort of have our apron, as we call it, has 4 phases within the Eagle Ford: gas, dry gas, wet gas, volatile oil or volatile condensate -- retrograde condensate, volatile oil and then dry oil. We have positioned ourselves essentially with the majority of our acreage and exclusively what we're drilling into what we call our retrograde condensate and volatile oil windows. That's where the activity has been in this year, that's where the activity will be going forward.

John P. Herrlin - Societe Generale Cross Asset Research

Okay, that's fine. Is this geo-pressurized?

John A. Manzoni

Sorry? Is it -- say that again, John?

John P. Herrlin - Societe Generale Cross Asset Research

Is it geo-pressurized?

John A. Manzoni

Is it overpressured?

John P. Herrlin - Societe Generale Cross Asset Research

Yes, exactly.

John A. Manzoni

It is overpressured. The whole Eagle Ford is overpressured.

John P. Herrlin - Societe Generale Cross Asset Research

Okay, great. When you look at your CapEx, until 2010 historically, in terms of costs incurred, you were spending 20% on exploration. You certainly ratcheted it up acreage expenditures over the last few years. Given your discussion of trying to have a more predictable operating strategy, does this mean that you'll be spending less on rank wildcatting activities and also reduce the amount of acreage aggregation that you've been involved in the last few years?

John A. Manzoni

Well, let me see if I can answer that. I mean, we spend $700 million a year on exploration. That's different from acreage acquisition. So let me deal with the exploration expenditure first. I mean there's a lot to be said for holding a level of exploration expenditure so that the team's can organize underneath that. And Richard and his team can figure out how and where best to spend that, because, as you know, exploration is a long game. So one's allowed to jerk that up and down too much, although I do believe, as we think about 2012, we might want to -- we might be tweaking it a bit, as we think about the options in our portfolio and such things. Again, to be determined, yet to be seen. That, by the way, does include appraisal of any discoveries that we find. So that's exploration and appraisal activity. So I think the exact number for next year is, again, we'll tell you in sort of January, once we figured out exactly how we do that. We've got to decide, as I say, my bias is not to jerk it up and around too much, but there may be some adjustments to be made there. And then the acreage acquisition, which comes on top, I would say we're always looking for new opportunities. We think we understand shale plays, certainly in North America, but also internationally. We have a group who is looking actively internationally and in North America for the next shale play and the next shale play. We're looking focused, certainly in North America in liquids-rich shale plays. In different parts of the world, it rather depends on the price structures and our views of how those things go. So we're looking broadly. And if we believe that there's an opportunity, which is usually early in a sort of shale play game, in that case, then we won't be shy of putting our money behind that. We did it in Duvernay, as an example. So we won't be shy of doing that if we see good value to be had. So I think the answer to that question is, it sort of depends on what we find and the opportunities that we see presenting themselves. All in the context, of course, of not completely burying the company in a huge debt, mounted by overspending on all these things. So we're looking at the long-term cash balances; we're looking at the opportunities set in terms of acreage, shale acreage acquisition; and we are continuously evolving the exploration portfolio at around the $700 million level. Now that may adjust a bit next year as we finalize the plan, but we'll have to wait and see.

John P. Herrlin - Societe Generale Cross Asset Research

Okay, last one for me. In terms of your exploration program, would you try to focus more on onshore opportunities rather than offshore?

John A. Manzoni

Why don't I ask Richard Herbert to talk a little bit about -- Richard, perhaps a little bit about how we've evolved this to this point, and how we plan to evolve going forward?

Richard Herbert

Yes, I think -- I mean, the way to characterize this is just sort of say we're in a sort of period of transition with our exploration portfolio. I mean, we started with a legacy portfolio that was in quite a lot of different areas. Talisman had entered over a period of time, so we were in onshore in some areas like in Latin America. We were exploring offshore in the North Sea and in parts of Southeast Asia. We had looked into deepwater in Southeast Asia. And of course, we were starting to look more at shale plays as well. So as we -- and really, what we're doing now is sort of playing out the exploration in the current portfolio, and there's a lot of activities we talked about in this call which is coming up in the next, certainly in the next 12 to 18 months. We will be testing a lot of this portfolio. And coming back to your earlier question, I think more of our spend is going to move to appraisal and to relatively lower risk sort of follow-up exploration, as we test and prove, either successfully or unsuccessfully, some of the sort of more wildcat basins that we're in. So I think the first thing I would say is that risk the profile of our portfolio is going to evolve during the next 12 to 18 months as we test it. Second thing is that, as we renew it, and of course exploration portfolios need to be renewed, because it's always surprising how quickly these sort of play out, the land that we've got. As we look to renew the portfolio, we are I think increasingly we're going to put a focus on 2 areas. One is to build on our experience in unconventional plays. Both looking at new opportunities in North America and also internationally. And then secondly, as we look in other parts of the world, it's clear that the major resource that remains to be found is in deeper water, all in unconventional. And therefore, I think as we go forward, we'll see increasing focus into those 2 areas. But that's going to be a transition that will take several years to happen.

Operator

Your next question comes from the line of Mike Dunn from First Energy Capital.

Michael P. P. Dunn - FirstEnergy Capital Corp., Research Division

Just a question on your committed rigs and completions crews for I guess specifically the Marcellus and the Montney as we think about possibly reduced activities in the Marcellus next year? Just wondering sort of what your commitments are for rigs and completions crews?

John A. Manzoni

So let me ask Paul. I mean I -- obviously, we will make decisions mindful of all of those things, Mike. But Paul, any insights into that?

Paul R. Smith

Yes, I mean, Mike, we had 3 dedicated completion crews in the Marcellus that were on a 2-year contract. We actually terminated 2 of those contracts for safety and integrity reasons, with one particular contract a month ago. And so we're now actually down to a single dedicated crew. And that puts us in a good spot to be able to flexibly decide what the activity set is that we want to have for the Marcellus in 2012. In the Montney, we have 2 dedicated crews, but one is coming off in February of next year, so a couple of nths from now. And so again, that gives us plenty of flexibility in the Montney to, again, decide what is the right pace at which we drill into that play in 2012. So I think we're feeling good about the flexibility that we have to be able to do the right thing here, whatever that may be.

Operator

Our next question comes of the line of Katherine Minyard from JPMorgan.

Katherine Lucas Minyard - JP Morgan Chase & Co, Research Division

Just a quick question on your natural gas exposure for 2012. You don't have any hedges in place currently, and I'm just curious as to whether you're comfortable with that position, or whether it's just that there hasn't been an opportunity to hedge it at prices that you would think would support undertaking the effort to put hedges on in place?

John A. Manzoni

Let me ask Scott to talk a little bit about -- I think he can answer your questions both. But I mean, let's just ask, I mean, Scott to talk a bit about it.

L. Scott Thomson

Well, Katherine, we will feel a lot better if we were hedged at $6 for 2012, that's not the case. There hasn't really been an opportunity over the last 12 to 18 months to put in hedges that balance that fine line between not taking too much exposure and protecting production. So that's the reason why we're not hedged in 2012.

John A. Manzoni

There's something about where the leverage lies, Scott?

L. Scott Thomson

Yes, I mean, if you look at our production, 50% oil-linked this year. Most of our exposure on the cash flow at these prices are to oil. So as you think about how we protected the balance sheet this year, we had oil hedges in place protecting a certain price. And as we look to 2012, and protecting the capital program for 2012, we've also put 40,000 barrels per day and $90 for our collars. In the front half of the year, 20,000 barrels per day; in the back half of the year, again protecting the $90 floor. So that's how we thought about it. If gas prices do move up, for a short period of time, we'll reconsider.

Katherine Lucas Minyard - JP Morgan Chase & Co, Research Division

Okay, great. And then, if I could just squeeze another one in on the North Sea. I realized you've addressed it to great lengths so far in comments. But in your prepared comments, you talk about considering options and not being comfortable with some of the volatility that you've been exposed to in the North Sea. But then in your press release, some of the first comments in the Southeast Asia section, are the Southeast Asia a self-funding growth area? And then of course, in your North Sea comments, you talk about the surplus cash flow that can be reinvested elsewhere. And I'm just curious as to whether the idea of thinking a little bit differently about the North Sea's plays in the portfolio in 2012 is related to the fact that it's kind of losing its niche as a source of funding, as other areas become self-funding? Or whether you're seeing a continued strong appetite in the markets for North Sea assets and that may be a little more weighing into your decision?

John A. Manzoni

That's about 5 questions in 1 there, Katherine. I think -- I mean, I think the answer to the question is, a little of both in some senses. I mean, the North Sea has delivered an enormous amount of cash to this company for the building of the shale plays over the course of the last 3 or 4 years. And it will do again this year, by the way. It's a huge cash generator. Of course, the longer that goes, and the more self-sustaining those shale plays become -- they're not there yet, but one can anticipate, and we have choices in that. I mean, we could turn them into cash generation today, if we chose to stop growing. So we have a set of choices to make. But I think it is true that in the general strategic sense, the North Sea becomes less required to the longer shale plays go on. It's been a huge source of those funds over the last few years. So I think that is true, and that plays into that different strategic stance in the North Sea. Again, I think I should emphasize -- I don't think we're thinking of sort of radical acts here. But on the other hand, we are investing still a lot of money into the North Sea. We've got some very big, multibillion-dollar redevelopments of certain parts of our portfolio, which absorb cash in the near term and deliver cash in the longer-term. And in a portfolio -- in a part of the portfolio which you want to use as a high-quality cash cow, then for instance, those projects might be subject to -- that's the sort of dilution I'm talking about. That might be the opportunity to say somebody else could share some of the long-term, and we'll take some -- we'll absorb less capital in the short-term. So there's a sort of hint as the way we're thinking about this. But I think in the general strategic sense, it is true to say that the North Sea is a -- it's been tremendously successful in its role in the portfolio. It doesn't necessarily -- but as we look forward into the future, do we need as much? Not necessarily. So some of those things that are absorbing capital could be diluted for instance, and somebody might be interested in doing that.

Operator

There are no further questions in the queue at this time. I'll turn the call back over to our presenters for any closing remarks.

John A. Manzoni

Well, I think we don't have any concluding remarks. So thank you, ladies and gentlemen, for both participating and listening, and also, for your questions, I hope that's been helpful for you. Thank you for your attention. And with that, I think we'll end the call. So thank you very much.

Operator

And this concludes today's conference call. You may now disconnect your lines.

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