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Talisman Energy Inc. (NYSE:TLM)

2012 Guidance/Update Call

January 10, 2012 1:00 pm ET

Executives

Tony Meggs -

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

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

Analysts

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

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

Andrew Potter - CIBC World Markets Inc., Research Division

George Toriola - UBS Investment Bank, Research Division

Brian C. Dutton - Crédit Suisse AG, Research Division

Alex R. Comer - JP Morgan Chase & Co, Research Division

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

Menno Hulshof - TD Securities Equity Research

Operator

Good afternoon. My name is Tracy, and I will be your conference operator today. At this time, I would like to welcome everyone to the Talisman Energy Inc. 2012 Guidance 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 January 10, 2012 news release and Talisman's most recent Annual Information Form, which contain additional information about the applicable risk factors and assumptions.

I would now like to remind everyone that this conference call is being recorded on Tuesday, January 10, at 11 a.m. Mountain Time. I will now turn the conference over to Mr. John Manzoni. You may begin your conference.

John A. Manzoni

Tracy, thank you very much. Ladies and gentlemen, thank you for joining our guidance call this morning. I am joined here in Calgary by the management team, except for Paul Blakeley, who's in Asia and is on the telephone. And they will be happy to answer your questions after Scott and I have run through the main points we want to get across for you today.

I'd like to begin by looking at what was achieved last year and then look forward to our plans for the current year. Despite being a difficult year in some respects for Talisman, a great deal was achieved over the last 12 months. Most importantly, our safety record continues to improve. In 2011, we improved our personal safety statistics again by more than 40%. So we're now moving the company very close to the second quartile, having been at the bottom of the fourth quartile just 3 years ago. In fact, some of our businesses are now firmly in top quartile, which is a tremendous achievement, and is, of course, our first and most important responsibility.

Over the course of the last year or 2, we've transitioned the portfolio to secure long-term growth potential. I'm confident today that the company has established an asset base to secure growth in the medium and long term. When we announce our results in a month's time, we will have produced around 425,000 barrels a day in 2011, which is 9% above the 2010 outcome on a continuing-operations basis.

Growth in the medium term is founded primarily in our shale portfolio here in North America. We produced over 400 million cubic feet a day in the Marcellus last year and about 485 million cubic feet a day in the fourth quarter and secured some of the highest margins in that region. We consolidated our Montney joint venture with Sasol and began the development of the Farrell Creek area, as well as making good progress understanding long-term monetization options for the gas from that area. In the fourth quarter last year, we produced about 55 million cubic feet a day from the Montney as a whole and about 35 million cubic feet a day from Farrell Creek.

In the Eagle Ford, after a slightly slower start than planned, we produced around 30 million cubic feet a day last year, but we've now established a fully functioning organization and we'll more than double that production this year. And we took a substantial position in the liquids-rich Duvernay shale here in Alberta, which we will learn a lot more about in the next 12 months as we continue to pilot. And of course, we also began drilling in Poland. It's very early days, and again, we'll learn more about that during this year. So our shale portfolio is now underpinning long-term sustainability for the company.

The other source of confidence in our medium-term growth is Asia, where we saw successful commissioning of both the Jambi Merang and the Kitan fields during 2011. We produced about 120,000 barrels a day in the region during the fourth quarter, and it's good to remind you that our average sales price for gas in Asia for the year was above $9 an mcf. We'll sanction new projects this year to secure growth into the future.

We made further progress in evolving our exploration portfolio, and we drilled several wells in the existing portfolio. In Colombia, I think we have lots to be excited about. We started drilling an appraisal well on the Huron discovery in the foothills and drilled a successful appraisal well on the Akacias discovery in Block 9. The discovery well on that structure continues to show promising results from the long-term test, and it's flowing about 1,600 barrels a day today. In Block 6, we began a program of 6 more stratigraphic wells to appraise the discovery in that block. Activity will accelerate across our portfolio in Colombia this year, which I'll describe for you in a moment.

In Papua New Guinea, we drilled several successful wells as we began aggregating gas in that country. We had success in both the Stanley and the Ubuntu wells, and right at the end of the year drilled another encouraging well in the Elevala structure. These wells continue to give us confidence that we can secure sufficient gas to create monetization options over the medium term.

At the very end of last year, we had a disappointing result in our deep water Lempuk well in the South Makassar Straits in Indonesia, which did have gas shows, but has been plugged and abandoned. And we were drilling a number wells over the year end which will reach their objectives in the next few months, including the Situche Norte well in Peru, the Kurdamir-2 well in Kurdistan, and of course, our Poland and Duvernay shale pilot wells.

And finally, in the North Sea, despite it not being an easy year in many respects, I think we can look forward with increased confidence. It starts with the people, and I believe we now have a high-quality team on the ground to run that business. We improved our operating efficiency in the U.K., which is a measure of how well the basics are being performed, from 69% in 2010 to 72% in 2011. In Norway, our operational efficiency is already very high at 98%. And in terms of its role as a provider of cash to the business, the North Sea delivered more than $600 million last year, so its fundamental role in the portfolio is certainly being fulfilled.

Perhaps our biggest disappointment of 2011 was the Yme project, which of course is not get on stream and continues to be problematic. I'll talk more about this a bit later.

While we haven't completed our analysis yet and won't do so until we announce our year-end results, just a word about F&D. Our 3-year F&D is likely to continue to show an improving trend as the underlying efficiency of our capital spending improves over time. On a one-year basis, I'm expecting F&D to increase a little versus last year when we release our final results for 2011 as a result of 2 main factors:

First, at the end of last year, we agreed a redetermination of the Suban field, which is part of the Corridor asset in Indonesia. That means we'll make a retrospective downward adjustment to reserves in our year-end reporting.

Second, the one year F&D numbers are very volatile, in particular in the international portfolio, and it looks like they're going to increase in 2011. North America, which is more stable given the unconventional business model, is likely to remain in the $8- to $10-a-barrel range. The increase even on a one-year basis is not particularly significant.

So now turning to 2012. I believe we can expect gas prices to remain depressed through this year. At least, that's the basis on which we set our capital plans. We're seeing signs of activity reduction in the dry gas plays, including ourselves, which I'll describe in a moment, and this will of course act to mitigate supply over time. But even the liquids-rich gas drilling will continue to provide gas supply, and hence, we take a fairly conservative view of prices.

On the other hand, we believe oil prices are more or less underpinned at current levels, perhaps a little lower, provided the world maintains roughly its current state. That state feels slightly precarious and certainly within the OECD, doesn't hold exciting growth prospects. Over the last month or 2, general forecasts of growth have been softening, but even accounting for that, supply and demand appear to be balanced to tighter going forward. There are, of course, downside risks and events which could push prices upwards, but we believe ultimately, the world needs the oil price to be somewhere in the $85- to $95-a-barrel range to maintain equilibrium.

So in that context, I'll give you the main messages related to how we're thinking about this year and then give you a bit more detail on each region. First, our exploration and development capital plans for 2012 are around $500 million lower than in 2011, at just a little over $4 billion. In addition, within that lower capital budget, we've prioritized profitability over headline growth in the current gas price environment and reduced dry gas expenditure and activity, primarily in the Marcellus and the Montney, by between $500 million and $600 million. At the same time, we've increased spending on identified liquids projects by about $350 million. The impact of this is to reduce the headline production growth, but increase the profitability going forward.

The capital program is setting in place long-term liquids growth in North America. In 2012, we'll produce about 25,000 barrels a day of liquids, which we expect will grow to over 60,000 barrels a day by 2015. Second, our organic production growth in 2012 will be between 0% and 5%. Medium-term guidance between 2011 and 2015 remains at 5% to 10%, but the switch to liquids-focused investment in 2012 will reduce growth this year. We calculate that reducing the gas directed capital by $500 million and increasing the allocation to liquids-rich opportunities reduces headline production by about 25,000 barrels a day of oil equivalent, which represents about 5% from our current base. The 0% to 5% range for the current year also accommodates some residual uncertainty around the Yme project.

Third, we will actively focus our portfolio during 2012, and I've already signaled 3 areas where we'll concentrate. First is the North Sea. We'll continue to invest in this business to ensure the integrity of our installations and secure the very important cash flow which it generates. But over time, we'll also seek to reduce our exposure somewhat to this mature and relatively volatile business. I'm not in a position today to describe exactly how we'll achieve that, although we are investigating several options. The combination of some sales, some farm-outs and some dilutions will, over time, result in the North Sea being a smaller part of the portfolio.

Second, we'll continue to actively focus on North America conventional portfolio. Some assets are non-core to Talisman and should be sold. In other areas, we'll seek to use other expertise or resources to accelerate activity and optimize value in areas where we would not otherwise direct capital. I'm optimistic that this will drive increased value for shareholders in our conventional portfolio, and I expect to see evidence of that during 2012.

And finally, we'll seek to exit some of our -- some areas in our exploration portfolio as part of the natural evolution of that portfolio. Some areas, we'll appraise and develop, but others, we will choose to exit for value at an earlier stage in the cycle. Overall, we're targeting between $1 billion and $2 billion of disposal proceeds through 2012 as we continue to high-grade and reposition the portfolio.

And the fourth headline message is that we have a lot of exploration wells currently drilling, so 2012 is a big year for exploration results for Talisman.

So those are the headlines. Now I'll give you a little bit more flavor by area. First in North America, we've refocused our shale investment into liquids-rich opportunities, and we'll grow liquids from about 25,000 barrels a day this year to over 60,000 barrels a day by 2015. Our shale portfolio will produce between 105,000 and 110,000 barrels of oil equivalent in 2012. That's between about 630 and 660 million cubic feet a day. In our conventional portfolio, we'll produce at around 80,000 barrels a day of oil equivalent per day during this year.

We'll spend around $1.8 billion in total, about $400 million lower than in 2011, with a little over 40% directed to the liquids-rich areas. In the Eagle Ford, we ended last year with 10 rigs, and we'll exit this year with 14 rigs operating, spending around $500 million, up from about $350 million last year. Egress build out in the Eagle Ford is a challenge, but we're confident that we're very close to securing sufficient egress both for gas and liquids to allow relatively unconstrained production through 2013.

We'll also be directing just over $100 million into Wild River, a low-risk resource-type play in Alberta which is also liquids-rich. There's lots of running room in this play, and we expect to build towards about 10,000 barrels a day of liquids over the next 2 to 3 years.

In the Marcellus, we'll reduce activity substantially in the light of current gas prices. We exited the year with 11 rigs, but will plan to reduce to an average of 7 rigs for this year and are actively considering reducing further to 5 rigs in the play. Even with 5 rigs operating, we expect to be able to hold production around 500 million cubic feet a day. Capital will be between $600 million and $800 million in total, with up to $250 million spent on building out infrastructure as we move east towards Susquehanna County.

In Farrell Creek in the Montney, we'll also reduce activity substantially, moving to a full rig program for this year. Talisman capital spend is low since we only pay 12.5% of the total, but we'll reduce the pace of development, both in light of gas prices and to ensure we optimize capital efficiency as we build understanding of the different zones which make up the very thick Montney shale. We've been encouraged by the early results in terms of liquids yields from a step-out pad in the east of the play, which came online in the last few weeks.

We'll continue our paced program of pilot wells in the Duvernay, drilling a total of 6 wells, and we'll also drill around 20 wells with 2 rigs in the Cardium play. Capital investments into our conventional portfolio will be between $300 million and $350 million, and production will be around 80,000 barrels a day, about 25% of which will be liquids.

Our Asian business is continuing to grow at an average of 8% per annum over the next few years and uses its own funds to achieve that. This year, we'll spend about $600 million to $700 million, including exploration expenditure, slightly lower than 2011 investment. The main feature will be the ramp up of activity in the HSD/HST development project in Vietnam, which we sanctioned late last year. We'll also spud 2 exploration wells in Block 5-2/10 in the Nam Con Son Basin in Vietnam during this year.

Drilling will continue in Papua New Guinea, although at a reduced pace as we shoot more seismic to prepare the next prospects. We're also actively seeking a partner in PNG and licenses where we have a very high working interest, and where we'll benefit from a strategic relationship to help monetization. The Corridor field will see the normal flow of continued projects for capacity expansions and compression, and we'll also continue drilling infill wells in the PM-3 CAA commercial area in the northern field. I'm hoping we'll be able to secure an extension to the PM-3 PSC during 2012, which will unlock substantial new investment opportunities in the field for increased recovery.

We produced about 120,000 barrels a day in 2011, which will increase slightly in 2012 as we have a full year of the Kitan and Jambi Merang developments. In the North Sea, we'll spend around $1.2 billion of cash capital, which is about the same as last year. Around $800 million of the total will be in the U.K., where a big focus will be on the MonArb and Auk South field redevelopments, although the pace at which we spend on these projects will depend to some degree on ongoing discussions with the U.K. government following the tax increase last year. We'll also be investing in Claymore as we continue the compressor replacement program on the platform, aimed at increasing operating efficiency for that field.

In Norway, the main focus will be bringing on the Yme project. It's been clear for some time that the competence of the contractor is stretched, and we continue to manage a difficult balance to get the platform onstream as soon as possible. The current plans project midyear, but last year's experience persuades me to take a cautious stance in setting Talisman's growth targets for this year. Productivity in the last few months has not been satisfactory, although it has been negatively impacted by a very bad weather in the North Sea. We're very active with the contractor to find ways of improving the current unsatisfactory rate of progress.

The remaining expenditures across the North Sea is mainly on infill wells.

Overall, we expect the North Sea to produce between 95,000 and 110,000 barrels a day in 2012, with the timing of Yme first production having a significant impact within this range. The U.K. will produce between 65,000 and 70,000 barrels a day, not 80,000 barrels a day, which I've stated previously. This lower production is a result of 2 main factors:

First, in light of experience in 2011, we've taken significantly more conservative assumptions with regard to projected improvements in operating efficiency and also in terms of planned turnaround days. We believe this to be prudent until we get under the maintenance issues which were the cause of some of the unplanned downtime last year.

Second, we've seen increased water cut on Auk North and also on Tweedsmuir. We hope to rectify some of this production decline by drilling an uplift producer in Tweedsmuir this year, but it isn't scheduled to be on production until early next year.

So overall, we should now consider 65,000 to 70,000 barrels a day a new normal for the U.K. It will vary around this level of bit depending on the timing of projects and individual wells, but I consider this a re-based number for our U.K. business. I should note that we don't anticipate any reduction in proved reserves as a result of this range.

And finally, exploration, where we've historically spent around $700 million per year. This year, we reduced that slightly to closer to $600 million as we trimmed our overall capital for the year. Our major focus will be in Colombia, where we have a very active program during the year. We'll complete the Huron-2 appraisal well and spud Huron-3. We have 2 rigs actively drilling development wells in the Piedemonte block, the most recent of which have been very successful. We expect to sanction the Piedemonte expansion by the middle of this year. In Block 9, we'll continue to appraise the Akacias discovery to confirm its size and potential. Our objective is to seek a declaration of commerciality for the field and target some early production by the end of this year. We'll complete the 6-well stratigraphic appraisal program in Block 6 with Pacific Rubiales, which will include flowing some of the wells on short-term test. We remain confident that we'll be able to move this program quickly.

Overall, we expect production from Colombia to average around 16,000 barrels a day this year as we expand the Piedemonte field, and I expect we'll define the future steps more clearly from the heavy oil appraisal that I've described.

In Peru, we're drilling Situche Norte, which we hope will increase the reserves we've already found nearby in Situche Central. We'll sanction a development project for this discovery this year, which can handle a successful well in the north as well. We'll complete the current Kurdamir-2 well in Kurdistan and spud another in the Baranan Block. We've already found large accumulations of gas condensate and these 2 wells are targeting liquids. We'll complete the drilling of the 3 vertical wells in Poland and determine next steps based on the results of those wells. In Vietnam, as I mentioned earlier, we'll drill 2 wells in Block 5-2/10 and are planning our first exploration wells in the Sabah blocks in Malaysia. We also have continued exploration and appraisal activity in PNG and in the North Sea.

So that's an outline of our activity for the year and I'd like to turn now to Scott to run over the balance sheet, hedging plans and cash balances. Scott?

L. Scott Thomson

Thanks, John. Talisman continues to be in a strong financial position. We will end the year with net debt of approximately $4.5 billion. At 2011 analyst consensus cash flow forecast, our net debt to cash flow will be below 1.4x. Liquidity remains strong. We have no material maturities until 2015 and approximately 85% of our debt matures post 2016. We have approximately $3 billion of room on our credit facility, which is committed until 2014 and priced at LIBOR plus 2%. In November 2011, we launched a U.S. commercial paper program which we started to utilize to lower our weighted average cost of capital. Currently, we have $400 million placed in the commercial paper market at an attractive funding cost of less than 1%. Finally, just before the Christmas break, we completed a $200-million preferred share offering at an attractive rate of 4.2%.

As we move throughout 2012, we continue to be focused on maintaining a healthy balance sheet. Significantly reduced capital expenditures, combined with additional dispositions in both our North American conventional and exploration businesses, should result in a free cash flow positive position for 2012. The exact timing of the dispositions will be determined as we move throughout the year, but we are currently in the process of marketing 2 North American assets which have generated significant interest from both North American and international counterparties. Successful conclusion of these 2 asset sales will give us some early momentum to achieving the $1 billion to $2 billion of disposition estimate that John referenced earlier.

It is worth spending a few moments on tax projections for 2012. Current taxes in 2012 will be dependent on production mix, oil prices and capital expenditures in the North Sea. At planned production and assuming 2011 prices, we expect current taxes to be similar to 2011. Lower U.K. tax will be offset by higher Norway tax, although the Norway tax will ultimately be determined by the exact start-up date of Yme.

In order to protect cash flow going forward, we continue to layer in hedges in 2011 for the 2012 calendar year. We feel that $4 billion is the ideal capital expenditure budget for the firm, and in order to ensure execution of this program, it was prudent to lock in some price protection. Hedging our oil production was more effective than entering into gas hedges, primarily because of the futures curve of each commodity.

We've been successful in locking in significant portion of our oil production in wide collars. We have 50,000 barrels per day of Brent hedged in the first half of 2012, 30,000 of which are in $90 by $150 collars and 20,000 of which are in $90 by $125 collars. In the second half of 2012, we have 30,000 barrels per day hedged, of which 20,000 barrels per day are hedged in $90 by $150 collars and 10,000 barrels per day are hedged in $90 by $120 collars.

John, I will now hand it back to you.

John A. Manzoni

Thanks, Scott. So ladies and gentlemen, just before your questions, a quick recap of the key points for the year.

We'll spend about $4 billion cash CapEx this year. Within that, we will reduce spending by a little over $500 million on dry gas versus last year and spend about $350 million more on identified liquids opportunities. The balance sheet will remain strong. The exact cash balances will obviously depend on commodity prices, but we anticipate being slightly cash flow positive during the year, including the proceeds from planned asset sales.

We'll seek to streamline the portfolio in 2012, disposing between $1 billion and $2 billion of non-core assets in the North Sea, our exploration portfolio and our conventional North American portfolio. Production, excluding the sales I just mentioned, will be between 0% and 5% above the 2011 outturn, which will be about 425,000 barrels a day. We've prioritized profitability over growth in the current gas price environment and have consciously allocated capital to liquids opportunities rather than seek the headline production growth. Medium-term production guidance to 2015 remains at 5% to 10%.

Ladies and gentlemen, thank you for listening, and now, we will be very happy to take any questions you may have.

Question-and-Answer Session

Operator

[Operator Instructions] Your first question comes from Brian Dutton.

Brian C. Dutton - Crédit Suisse AG, Research Division

Clarify on your North Sea U.K. sector guidance. Did I hear correctly that you're now looking 65,000 to 70,000? Or is it 75,000 boes a day?

John A. Manzoni

Brian, I said 65,000 to 70,000 for the U.K. and 95,000 to 110,000 for the North Sea as a whole.

Brian C. Dutton - Crédit Suisse AG, Research Division

Right. And so, could you give us some insight then as to why you're taking that down from 80,000 to 90,000 for the U.K.?

John A. Manzoni

Yes, there were a couple of things that I mentioned. The first point, just to reiterate, I don't think that this changes reserves. Proven reserves won't -- we don't expect any change in proven reserves as a result of a reduced production range, Brian. And there are 2 factors which have led to that reduction. The first, of course, is our own assumptions going forward. We certainly planned more planned turnaround in 2012 than we had in 2011 on the basis that we had a substantial amount of unplanned turnarounds in 2011, as you know, including the shutdown of one of our fields. So we've got quite a significantly higher, 50%, 60% higher turnaround assumption in terms of days in 2012 than we did in 2011. And similarly, we've taken a slightly more conservative view of the operational efficiency improvements that we're planning going forward into next year. So that's one set of things which has to do with our assumptions. And the second set of things has to do with the water cuts, which we've seen in Auk North and Tweedsmuir, which are frankly a bit higher than we had anticipated when we set the "80,000 barrel a day" range. Some of this can probably be mitigated, and it's just a question of getting a rig to drill an uplift producer, which is what we're planning to do on Tweedsmuir for sure, but that well is scheduled to be drilled at the end of next year, so the production doesn't come until 2013. So next year, we're seeing the impact of the higher water cut. So those are the 2 things that have caused us to take a lower view of our U.K. production. Now some of that may be our own conservatism, but I think it is actually prudent now to have that range in our U.K. business, still held flat at that range, but it is not 80,000.

Brian C. Dutton - Crédit Suisse AG, Research Division

So just a second question now on that topic. I think if I heard you correctly, you mentioned that you see more turnarounds in 2012. You're concerned here about water cuts. If you look last year, I think it's probably safe to say that North Sea production and the resulting missed production relative to market expectations was a key driver behind Talisman's poor share price performance. So can you give us a road map on how you see production progressing through the year on a quarter-by-quarter basis?

John A. Manzoni

Not offhand, frankly. I do have it; I just don't have it in front of me. I agree with your point that in the end, the North Sea has been -- I mean, historically, for Talisman was very volatile. And in fact, historically, for Talisman was the cause of many of the misses in guidance in the past, and I have to say I was disappointed that last year, it appears that we did not have that behind us and we missed again. So there's no question, I think, that, that disappointment has reflected in the market and has reflected in the share price. And I -- of course, you can imagine, we have no intention of having that repeat itself in 2012. So we have set a lower number. There are the normal turnarounds in the middle 2 quarters of the year and the production will come back in the fourth quarter. I don't have the exact numbers. We can soon get you the exact numbers, if that's -- if it's useful, but I would say that we've got, in total, a planned turnaround schedule of something in excess of 300 days, I think, in our North Sea business -- in our U.K. business, in 2012. And that is in order -- and one hopes that we'll have less unplanned turnarounds as a result of actually spending more time with planned turnarounds and scheduled maintenance. So I think we are -- you've heard me say before -- I mean, it's disappointing to me that the North Sea has been struggling in 2011, and it was clearly struggling. Some surprises, negative surprises, and I reiterate, I think that we now have a good team on the ground in the U.K., who I believe are getting underneath the fundamental issues in that business. I think that needs time. It's a complex business. These are very old platforms. It needs time, but I must say, and I didn't say it lightly, that I think we can look forward with better confidence than we can look backwards, because I think that team are getting their arms around that business and starting to make the underlying improvements which will make this business more reliable. So I think that's where we are, frankly, in the North Sea.

Operator

Your next question comes from the line of Andrew Potter.

Andrew Potter - CIBC World Markets Inc., Research Division

Just a -- first a question on Colombia. I mean, it seems like CPE-6 is moving along well and some encouraging results out of CPO-9. If you do -- if you are in a position where you declare commerciality on both these this year, I mean, where does Colombia go over the next 5 years? I mean, does this leave you in a position where your "50,000 barrel a day" target starts to look very conservative? And I guess if that's the case, what is sort of the upside scenario? And then second, just on the Duvernay, maybe if you can give me a little bit of sense in terms of the drilling program. I mean, if you have good results in the first half of the year, could we expect an expanded program later in the year? Or are you pretty much stuck with the one-rig program? And I guess also on the Duvernay, how many wells will you need to have under your belt before you can come out with a contingent resource estimate on the play?

John A. Manzoni

Thank you, Andrew. Let me turn to Richard Herbert, who looks after our Colombian business in terms of whether he's sandbagging his production target. Richard?

Richard Herbert

Yes, Andrew, good morning. As you say, we're seeing some encouraging data coming out of the heavy oil blocks, Blocks 9 and 6, and we're in the middle of drilling programs. We're going to be acquiring 3-D seismic this year over both of the discoveries there. So it's still early for us to sort of really declare what we think the final outcome will be in terms of reserves and production potential. So for now, we're going to stick with the 50,000 sort of medium-term target for production from Colombia, but clearly recognize that if we have -- that there is upside in there and obviously we'll be looking for that upside. And as we get data and understand it, we can adjust our forecast accordingly.

Andrew Potter - CIBC World Markets Inc., Research Division

Okay. And then so on that -- in terms of timing, in terms of when you'll have enough data, is this kind of a -- I guess, midyear it sounds like the case for CPE-6 and you're saying sort of later year for CPO-9 to have -- be in a position to declare commerciality and change those plans.

Richard Herbert

Yes, certainly -- well, they're both running quite in parallel at the moment. What we're hoping to do in Block 9 is declare early commerciality around the well that we currently have on test and -- so that we can actually count that well as production rather than a long-term test, and then step out and drill some more wells for early data, while we continue to appraise the sort of larger extent of the accumulation with appraisal wells. And that process will take a bit longer because we need to go through the full environmental permitting process to do that. So I think we'll see -- I'm hoping we'll see a declaration of commerciality on Block 9 in the first half of this year and move towards some initial pilot production before the end of this year. In Block 6, I think a lot depends on the outcome of the current wells that we're drilling. We've got 6 stratigraphic wells that are -- 4 are now down and we're waiting for the last 2 and hoping to put some -- to get some flow test results from at least one of those wells. And then dependent on that, I think the operator will declare a timetable for early commerciality, and hopefully, sometime around the middle of the year.

John A. Manzoni

Thank you, Andrew. And Duvernay, Paul, 6 wells this year. And what happens if you get good results?

Paul R. Smith

I mean, Andrew, I think to say, it's clearly very early days in the Duvernay for us and would be for the industry. We've drilled 2 wells now, and we're literally probably a number of days away from completing our first well. It's tied in and we'll be seeing our very first -- our own very first Duvernay results in the next few weeks. As John has said, we'll be drilling an additional 6 wells this year. I'll just remind everybody that we're in a fairly large position, a split between what we call the northern and the southern parts of the Duvernay play, about 350,000 acres, and so those 6 wells are going to make a small dent on de-risking the 350,000 acres within the play. We think that's the natural pace to go, so that we can alternate wells between the north and the south as we de-risk the play this year. And clearly, on the back of the results that we see from the wells at the end of this year, we'll be making decisions around the pace at which we choose to drill into the play in the following year. So I'd just sort of say early days and way too soon to start to be talking about contingent resources and other things. But it's not just our activity that's picking up. You clearly see that industry activity is picking up greatly, too, and that will help us all in the next 12 months.

John A. Manzoni

I think it'd be fair to say, Paul, we won't actually be drilling any more wells than the planned 6 wells. That's our plan and that's what we'll stick to.

Paul R. Smith

Indeed.

Operator

Your next question comes from the line of Bob Brackett.

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

I had a question on the dispositions. It's kind of twofold. One is, what are you thinking up on those international exploration dispositions? Are you ready to talk about what those might be? And then on the North America dispositions, what are you thinking of selling? Are you selling resource? Are you selling acres? Are you selling flowing barrels or flowing gas?

John A. Manzoni

So let me pick up the first, Bob, and then look to Scott and he can just give you a little bit of flavor on the second. In international exploration, I'll just give you a little context on this. I mean, the natural evolution of the exploration portfolio is that if you drill all these things and even if they're all successful, you can't possibly sort of develop them all, so you've got to make some choices. As we've said for some time, we spent the last 2 years evolving the portfolio to today's state, and over the next 8 to 12 months probably, we will have drilled every basin in that portfolio. So the question is, when we've drilled it, what shall we do even if they were all successful? And so, we're in that natural phase where we're now going to be making some choices. And I would -- and it is a little early, and I'm not going to outline the specifics today, but over the course of 2012, I think they will become clear. But I think that some -- we look through 2 lenses primarily. The first lens would be materiality. Can we -- we've always said 50,000 barrels a day in a region is a level of materiality. So the question is, can we can get to that level of materiality? And if we can't, somebody else will be more proud of that and pleased with that discovery than we might. That would be one lens. And the second lens would be sort of time frame. There is a time frame for a company such as Talisman. We don't want to be doing stuff 15 years out. So we'll be having a bias toward those things which can give us earlier production rather than later production. And it's those 2 lenses which we shall likely use as we go through 2012. Drill the wells, see what we have and make a decision. So there's a sort of slightly general answer to the exploration, but there's no question that our exploration portfolio -- we'll make some decisions. We're not just going to sit on stuff. We're going to make decisions through the course of 2012, and you'll see some action in that regard. Scott, North America, the shape and stuff?

L. Scott Thomson

Yes, Bob, on the North American side, there's a number of assets that we have in our North American portfolio that are either non-core or, frankly, not being funded. And we will look to dispose of those throughout the year, and the exact timing, we haven't said yet. We do -- are in the market with 2 assets. One is a coal project which, obviously, doesn't have reserves or production associated with it. And then the second is a North American conventional asset, which is relatively minor production. And I think we'll hopefully have success on those in the first part of the year and that will give us good momentum for the $1-billion to $2-billion target that John referenced.

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

Just to clarify, is that a coal project or a coal bed methane project?

L. Scott Thomson

That's a hole project -- coal.

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

Coal.

John A. Manzoni

Very high quality coal, Bob.

Operator

Your next question comes from the line of George Toriola.

George Toriola - UBS Investment Bank, Research Division

My question is around the North Sea and the volatility that, that business has seen over time. So it's a 2-part question. The first is, can you talk about what the root cause of this volatility is? Is it because the assets are maturing? Is it -- does it have to do with other issues around asset integrity? What is the driver behind the volatility? And I guess the second thing is, you talked about it briefly as to the elements of -- the 3 ways that you can sort of reduce the impact. Maybe you can expand a little bit on following on -- what would you then, within that portfolio, look at as less material or overly volatile?

John A. Manzoni

Let me -- Thank you for your question, George. I'm going to ask Tony Meggs, who for the moment is looking after our North Sea business, to see if he can answer the first question.

Tony Meggs

Thank you, George. The root cause of the volatility in the North Sea over the last little while has really been -- has 2 aspects to it. One is that -- is quite honestly rotating equipment primarily, operational efficiency variations as a result of largely gas compression, which has caused significant fluctuations in operating efficiency. And we are -- one of the reasons -- we've got several gas compression projects underway. One of the reasons we've got more downtime or rather, more turnaround time is again to address that. The second has to do with very high rate wells from new developments that come on at significant rates, several thousand barrels a day, and which, quite frankly, have unpredictable -- somewhat unpredictable water cut behavior. And we have been, I have to say, caught in 2011, as John mentioned, by Auk North and Tweedsmuir. So if you were to sort of summarize it, you'd say there are 1 or 2 high rate wells that have been affected by water cut, which we had anticipated. We just got the timing wrong. And secondly, by really unacceptable variability in compression, I'd say primarily compression performance, that we are spending a lot of time addressing now. So we want to calm this down and have a much more stable performance going forward. And that's why we've taken a relatively prudent and cautious view going forward. Now in terms of dispositions, we're looking at all sorts of things and it's really too early to say. John may want to augment that.

John A. Manzoni

Yes, let me add something because Tony's obviously stepped in relatively recently and he's looking after the North Sea. Just for callers' information, Tony's very experienced. He's also running our North American gas monetization project, but has taken an oversight on our North Sea business in it for an interim period. I would say, George, perhaps one addition to Tony's comment on the first part of your question, integrity of the -- these are old platforms. We're not -- I -- actually, I'm pretty confident that we have good maintenance programs with regard to the integrity of the platforms in the main. We also shot Tartan on down on a safety-related issue, but not a plant integrity-related issue. It was actually to do with the air pressure in the accommodation modules. So I think integrity is not an issue for us in the North Sea, but as Tony has mentioned, the gas compression systems are -- and many of them rely on single train compressors because they were built in the 1970s. They don't do that anymore, and of course, if you got a single train compression system, one goes down, you have to bring the whole thing down. And since most of the wells are very old, they rely on gas lift and such things. So that's the nature of the set of problems that one deals with. Some of the more specifics in perhaps how we find ways of reducing our exposure, for instance, we have a couple of very big projects in the North Sea, big investments, multi-billion dollar investments in Auk redevelopment and in Montrose/Arbroath redevelopment. Those are in isolation very attractive projects to somebody. They're growth projects. They're quite capital-intensive, and we may not be the amount of equity that we have in them going forward. So they would be a more -- slightly more tangible example of some of the things that we're in discussion around in terms of how we reduce our exposure. It isn't uniquely those or that's not the total -- totality of what we're talking about, but those are some examples.

George Toriola - UBS Investment Bank, Research Division

Okay. Say, just to follow up quickly and switching gears here, this has to with Eagle Ford. Now we're going to see increased capital spend there. Can you just talk quickly about, based on the level of activity you see there, so potential cost inflation and thing, what is the break-even price that you would need -- natural gas price and what associated liquids content would you be looking for? Because I assume that you still have some degree of -- built in, in the well performance down there. So if you could speak to those 2 things.

John A. Manzoni

Sure. Let me ask Paul Smith to address those 2 questions. Paul?

Paul R. Smith

Eagle Ford, so I mean, at this point to note, it's clearly that -- the machine is gathering momentum. We got off to a slower than expected start in 2011. I think we underestimated the degree of complexity to go and build out an organization in Houston, get the supply chain set up and really get that flywheel turning the way that it's turning in the Marcellus, for example. The good news is that we're sort of exiting the year with all of that momentum very firmly in place. We'll be running -- we are running currently with 11 rigs and we'll be increasing roughly a rig a quarter to take that up to 14 rigs by end of this year, consistent with the organizational capability that we've now put in place. In terms of cost inflation, you are absolutely right. I mean, it is one of the hottest plays in North America in terms of cost of service. We got in early to lock in both -- our major spend is clearly on drilling and completions activity, and we've locked in roughly 90% of our rigs on long-term contracts about a year ago, and 2 full-time completion crews were locked in at the beginning of last year, again, for sort of 2- to 3-year periods. So we're fairly protected from a cost perspective by having locked in early almost 12 months ago. In terms of the break-even gas price that you were asking for, it's very small. Clearly, liquids carry the day. I have previously said that IP and type curves, on average in the Eagle Ford, IP of 6 and a EUR of 4 Bcfe a day. Clearly we're seeing variability as we drill out our positions and with all of us in the industry are understanding the distribution of the phase windows, but there's nothing to suggest that those type curves are often -- roughly half of our production is going to be liquids based in the Eagle Ford. And again, nothing has changed around that.

Operator

Your next question comes from the line of Matt Portillo.

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

Just a couple of quick questions for me. First, starting off in the Marcellus, can you talk a little bit about your most recent well results? Obviously you put up a very strong end to the year and really your 2012 guidance was exceedingly strong as well. So could you talk a little bit about your most recent IPs and type curves, and how those compare to kind of previous presentations of 4 million cubic feet a day on the IP side in a 5 bcf well?

John A. Manzoni

Thank you, Matt. Paul, do you want to talk about that?

Paul R. Smith

Yes, I mean, clearly, Matt, I mean, there are a couple of things I'd say here. First, we've started our journey towards the east in the latter half of last year. The acreage in some of the Friendsville, Susquehanna Counties, pike [ph]. So we're moving away from what has been our core that we've developed over the last 3 years in the Bradford, Tioga and state lands, and we started to move east, and we're starting to see some encouraging well results as we move east. You guys have seen some of the results from those that have been there much longer than us. I'd say, on average, though, I'm not here to tell you that our average type curve and IP assumptions have changed. On average last year, an average Marcellus well was doing an IP of around 4 and the average EUR is around 5 on average. Clearly, it changes from area to area. But we did bring on more wells last year than we expected. We had a great run in terms of execution, and we brought on -- last year, we brought onstream nearly 130 wells in the Marcellus, which is a big contributor to the very strong 4Q production that we said, the 485 million cubic feet a day.

John A. Manzoni

I think, if I can add, Matt, it's actually quite good to stay behind the curve on these EURs and IP assumptions, because this is a long game and the world keeps changing. So it's pretty good to have a delivery policy to stay a little behind the curve, and it's always good for us to have an assumption which is behind what we're drilling, and that's our policy a bit.

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

Perfect. And then just a quick question on the Eagle Ford. Could you give us an idea of -- kind of in your guidance, of what you're assuming on a days to drill and complete for those wells, and kind of where the leading edge is on -- from an industry perspective of where you hope to get to over time?

John A. Manzoni

I'm going to Paul to see if he actually knows what the days to drill and complete are.

Paul R. Smith

We're drilling and completing wells now. Our average for -- I mean our first year in the Eagle Ford, we drilled and completed on an average of $10 million a day. That's come down significantly...

John A. Manzoni

$10 million a well?

Paul R. Smith

A well, sorry. Did I say "day?" $10 million a well. That's come down significantly as we've come up the learning curve, and we expect that to be well into the single digits, and we're already seeing wells well into the single digits as we exited last year. I'd say that industry best practice wells, again, you need to be careful because the Eagle Ford has got shallow parts and it's got deep parts, but I think anywhere in the $7-million to $9-million range in the Eagle Ford would currently be considered, I think, exceptional performance for drilling and completing. On a normalized basis. Obviously it depends on many things, not least the length of your well and how many stages your completing with. But on average, that's where I'd sort of guide you, Matt.

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

And then just one last quick question. Could you remind us of the coal assets that you have in your portfolio today and kind of the resource that may be associated with those?

Paul R. Smith

Yes, sure. So I'll take that one. So I mean, this is a legacy asset in its extreme. It's a coal deposit for quite some time ago. It turns out that it's a very high quality, high metallurgical coal deposit. It sits right next door to our Montney properties and has attracted a great deal of international interest because of the high-quality coking nature of the coal and the ability to transport that coal out fairly easily from that area. So unless you want me to sort of -- I can send you -- we're not going to go into sort of details around coal reserves and everything else, but the process is well on its way and as Scott has said, we've had a great deal of international interest in the asset, and we expect to sort of -- towards the end of this quarter be in a position to announce something on that.

Operator

Your next question comes from the line of Alex Comer.

Alex R. Comer - JP Morgan Chase & Co, Research Division

I'm just wondering if you could maybe give some -- a little bit more detail in terms of the number of wells you actually expect to drill on the Montney. And also, you talked about some of the geological issues. Maybe you could elaborate on that. And also, you talked potentially about some liquid-rich plays to these, and I was just wondering maybe if you could -- a bit flavor on that as well.

John A. Manzoni

Alex, thank you for your question. Let me ask Paul just to talk a bit about probably rigs, not wells, and then something about variation on what we're seeing in the Montney.

Paul R. Smith

Sure. I mean, we're -- as a result of sort of $3 NYMEX, $2.50 AECO, we're clearly going to put the brakes on the program in the Montney and preserve our carry that we have in place with Sasol. We'll be reducing, as John has already said, from the 10 rigs that we've been running at last year down to 4 rigs, which I think is the prudent and right thing to do in the current environment as we continue to come up the drilling and completions learning curve, and indeed, continue to develop the play. Not surprisingly, in a 50,000-acre position, as we started our first year of real development, we're going to see some variability. I mean, we still see variability in the Marcellus 3 years in and multiple of hundreds of wells in. And so yes, we have seen some variability. That variability will allow us, as we continue to develop the play, to pick those zones that are giving us higher-than-average EURs and avoid for the time being the zones that are giving us lower-than-average EURs in the play. In terms of liquids, we've always expected liquids as we move east in our Farrell Creek position. And plus it's literally very early days. We brought on our first step-out pad out towards the east of the play only last week. We clearly have indications of condensate and liquids at surface. And we're just generally encouraged by that. It's confirming our suspicions that the play gets increasingly liquids-rich as we move east.

Operator

Your next question comes from the line of Menno Hulshof.

Menno Hulshof - TD Securities Equity Research

I'll start with a question on Lempuk. I thought I heard you say that it was plugged and abandoned. And if so, does that change your view on the prospectivity of that basin? And if not, what are your plans in the area over the coming quarters?

John A. Manzoni

Thank you, Menno. Let me ask Richard to talk a bit about Lempuk and what we've learned.

Richard Herbert

We finished drilling the well of the 31st of December. It was our first operated deep water well and the first well to test the basin in the South Makassar, so it was a real wildcat well. Having drilled it, it's obviously going to take a little time to just evaluate the data we've received and understand the implications. We drilled the well without any problems. We had some encouraging gas shows as we drilled the well. But when we reached the main target, and we were very pleased to find the reservoir that we had predicted, but it didn't have the hydrocarbons in that we'd hoped. So I think at this stage -- it's the first well in the basin. We'll spend some time now evaluating what the implications are for the prospectivity. It doesn't mean to say it's the end, but we'll make a fairly thorough-but-rapid evaluation, and on the result of that, we'll decide what we'd do next.

Menno Hulshof - TD Securities Equity Research

So as it stands, there's nothing in the calendar terms of additional drilling activity.

Richard Herbert

For this year, we didn't have any additional activity in that basin, no. We decided after drilling this first commitment well in the Sageri PSC that we would take a break anyway before we did any further drilling. So we've got a bit of time now to work out what this means for the prospectivity before we make any other plans.

John A. Manzoni

[indiscernible] Menno, part of it because of the rig scheduling and things that was shared among many operators in that part of the world.

Menno Hulshof - TD Securities Equity Research

Okay. And then the second question is on Yme. What are you assuming in terms of first production dates for the high end and the low end of your North Sea guidance range of 95,000 to 110,000?

John A. Manzoni

Well, what I said -- let me answer that one. What I said quite carefully, as you will have noted, is that the progress to date is not satisfactory, and frankly it's not satisfactory. If we carried on at the rate we are working today, we would not be at our midyear target. And with relatively carefully chosen words, I think it's -- we're working pretty hard with the contractor to try to encourage better performance. Now some of that has been -- I mean, it has been particularly bad weather in the North Sea in the first month of the year and the last months of last year, which means that although we've got a flotilla alongside, most of the time or a large proportion of the time, the bridge between the flotilla and the platform has actually not been available. So although we've got a lot of people there, we don't actually have much work being done. So some of that has to be corrected as we go forward, and we have to think about what that looks like, but notwithstanding all of that, I think we still got to improve performance on the work fronts in order to meet the original schedule. And what I've also said is that the 0% to 5% range that I have given you for this year's total production incorporates the ranges that we believe to be sensible for Yme. And then you can make your own view, but in some ways, you could push the thing right out at the bottom of that range and not have any production in 2012 at all.

Operator

Your final question comes from the line of Mike Dunn.

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

I guess a couple of questions. Most of mine have been answered, but just wondering, I thought I'd ask if you guys can talk about maybe a range of expectations out of the Eagle Ford for production in 2012 and where you're at currently. And maybe similarly for the Montney, and I'll have another question after that.

John A. Manzoni

Let me see if Paul's prepared to give you a range for Eagle Ford production and where we were this year.

Paul R. Smith

We -- I mean, we've said in the call today that we expected more than double our production from our average of 30 million cubic feet a day this year, and I think that's a pretty safe piece of guidance to you, Mike, to say that it will be at least 60 million standard cubic feet a day equivalent next year. There are -- and the reason I hesitate to sort of be more bullish for you, other than to say that's sort of a very good and conservative floor, is that there are many things that need to fall into place this year, with the drilling and completions side and particularly on the egress side where we have -- we're layering in 6 or 7 deals this year to be able to evacuate all of our production from the Eagle Ford. And then clearly, as we and others are building out in the Eagle Ford, there is chance and potential for some of those projects to be -- some third-party projects to slip from where they are today. So that's what I'd sort of say on the Eagle Ford. On the Montney as a whole, clearly, we exited fairly strongly in the Montney as a whole last year at about 75 million cubic feet a day. And as we think about next year and our production from the Montney as a whole, with only 4 rigs up and running, it would not be unreasonable to sort of use that as a piece of guidance in terms of what we can expect out of the Montney as a whole in 2012.

John A. Manzoni

Does that get it, Mike?

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

Yes, great. I think I must have missed the Eagle Ford comments earlier, trying to type down some other comments of yours. But in the Marcellus, what are the base declines right now, roughly?

John A. Manzoni

Base declines.

Paul R. Smith

I mean, it depends year-to-year depending on how many wells -- new wells you've got coming in, Mike. I mean on average, in our shale portfolio, the average decline in 2012 was 40%, and that's of course the shale portfolio.

John A. Manzoni

But the other way of doing this, Mike, is I actually did say that at 5 rigs we'll hold $500 million.

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

Yes, okay, great. And then one more if I could. Your conventional North American production guidance, 80,000 boes a day, I believe back in May, you were talking about 80,000 to 90,000 boes a day. Is sort of being at the low end of that a function of reduced capital or due to the low gas prices? Or is it something else?

John A. Manzoni

Let me see if Paul can answer that question for you.

Paul R. Smith

No, I think you've answered your own question, Mike. So the answer is, yes. One of the areas where we've cut back quite significantly, about $150 million relative to last year's program, is within our tight gas program -- our conventional tight gas program, which is almost down to nothing for this year. So in places like Ojay and other places where we drilled quite heavily last year in a different price environment are down to nothing. And so the -- I mean, the conventional $300 million to $350 million that John telegraphed in his guidance call is very much liquids directed, mainly into the Cardium area, into our Wild River area where, as John has said, we're drilling into a liquids-rich play. So very much liquids-directed CapEx. So the reason for being at the lower end of that range is because we've cut back capital quite significantly relative to last year.

Operator

I turn the call back over to you, Mr. Manzoni.

John A. Manzoni

Thank you very much. Ladies and gentlemen, thank you for listening. It's -- we've gone 1 hour and 5 minutes, and I think we should end with that. Thank you for your time, and we look forward to delivering what we say in 2012. Thanks very much.

Operator

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

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