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Talisman Energy (NYSE:TLM)

Q1 2012 Earnings Call

May 01, 2012 10:30 am ET

Executives

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

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

Tony Meggs - Executive Vice-President of Special Projects

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

Richard Herbert - Executive Vice-President of Exploration

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

Analysts

Andrew Potter - CIBC World Markets Inc., Research Division

Robert Bellinski - Morningstar Inc., Research Division

George Toriola - UBS Investment Bank, Research Division

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

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

Brian Singer - Goldman Sachs Group Inc., Research Division

Brian C. Dutton - Crédit Suisse AG, Research Division

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

Menno Hulshof - TD Securities Equity Research

Mark Polak - Scotiabank Global Banking and Market, Research Division

Operator

Good morning. My name is Michelle, and I will be your conference operator today. At this time, I would like to welcome everyone to the Talisman Energy Inc. 2012 First Quarter Results Conference Call. [Operator Instructions]

This call contains forward-looking information. Certain material factors and assumptions were applied in making the forecasts and projections to be discussed in this call, and actual results could differ materially from those anticipated by Talisman and described in the forward-looking information.

Please refer to the cautionary advisories in the May 1, 2012, news release and Talisman's most recent Annual Information Form, which contain additional information about the applicable risk factors and assumptions.

I would like to remind everyone that this conference call is being recorded on Tuesday, May 1, at 8:30 a.m. Mountain Time.

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

John A. Manzoni

Thank you, Michelle. Ladies and gentlemen, good morning. And thank you for joining our call today. As usual, I'm joined by the management team here in Calgary, who will help to answer your questions after Scott and I have given you the main points on the quarter.

A word about the commodity price outlook is context to what I shall talk about in terms of our capital program for the year. Gas prices here in North America continue to reflect the combination of oversupply and an unusually warm winter and have remained below what we believe to be a necessary long term equilibrium price. However, with the injection season now upon us, it's quite possible that this gets even worse before it gets better, and we've adjusted our capital plans accordingly.

There are some early voices of optimism that the coal switching, which has occurred over the last quarter, will play a role in accelerating the recovery, but I don't think anyone is expecting positive news until at least the end of this year. And we need to be ready for this to last well into 2013.

Oil prices have been strong, and we believe Brent will continue to be underpinned at the $90 to $100 a barrel range. We should expect some volatility around that just as we're seeing today on the upside as a result of geopolitics, but as a base projection, we remain comfortable in the $90 to $100 range.

Turning to the first quarter. We had a strong quarter in terms of operating results. Production was very strong with 462,000 barrels a day, 4% above the equivalent quarter last year, and underpinned by a very strong quarter in both North America, which was driven by the shale being about 50% higher than a year ago and by Southeast Asia, which had a record gas production quarter delivering 136,000 barrels a day.

Cash flow was up 5% over the first quarter last year. Prices and volumes were up but were offset to some extent by higher taxes and higher costs. Earnings from operations were $167 million for the quarter, reflecting higher prices, but also higher costs than a year ago and a higher DD&A rate, which Scott will explain in a moment. Costs were down from the fourth quarter last year when you may recall we had significant shutdown activity, particularly in the North Sea, but they're up on the equivalent quarter a year ago. This reflects, in part, increased activity since that time. For instance, we've now got operations in Kitan in Australia, Jambi in Indonesia and Equion in Colombia.

In North America, we've also flowed through the new Pennsylvania impact fee, which this quarter includes a historical component. If we exclude the historical part of the impact fee, we continue to see a trend of reducing unit cost in the Shale business.

In the exploration portfolio, we found a significant oil leg in the Kurdamir-2 well in Kurdistan, which is sufficiently encouraging for us to plan an appraisal program on the structure. It's early days, but we are very encouraged by what we see so far. And in Papua New Guinea, our exploration wells continue to turn up what we expected, which is that the structures we are drilling tend to be full to spill. The latest well, Ketu-2, was another very positive result and is building on our gas resource exactly according to plan.

In Colombia, it's a little slow as we wait for the authorities to grant the relevant operating permits, but we're making progress, and I expect through this year we will see increasing news flow. In Vietnam, we started drilling the Ngoc Thach exploration well in Block 5.2 in the Nam Con Son Basin. We wrote off the unsuccessful Situche Norte well in Peru. We hope that well would more or less double the commercial reserves we all already have in Peru, but it didn't work. We are reviewing now how to proceed in Peru in light of that result, and we'll finalize our plans in the next quarter.

We've had a good start to the year with disposals and have secured about $1 billion so far. This is about focusing our portfolio. We continue to examine options in the North Sea, including the dilution of some of our big redevelopment projects there, and I've also said we'll look at our exploration portfolio.

As I've just mentioned, we've recently drilled a dry hole in Peru, and we also drilled dry hole in South Makassar. And we're in the final stages of determining our forward plans for both places. I'm confident we'll achieve our original objective of $1 billion to $2 billion as we go through the rest of the year.

Another highlight for the first quarter is the provisional award of 60% equity and operatorship for the producing Kinabalu field offshore Malaysia. We've agreed all commercial terms with PETRONAS for the award of a new PSC at Kinabalu, which is offshore Sabah, subject to formal signing, which is expected within the next few weeks.

The PSC covers the redevelopment of an existing producing oilfield, which will transfer to Talisman with 60% equity and operatorship at the end of this year. It brings immediate production of around 8,000 to 10,000 barrels a day in 2013 and will build on our existing business in Malaysia. This is an asset which allows us to do what we do well, and we'll invest in a number of capital programs to increase reserves and production over time.

I indicated at the start of the call that we've taken further steps to reduce capital in light of the depressed gas price. I see no reason to continue spending money in dry gas shales when it doesn't remunerate. So in our fourth quarter call, we said we would reduce spending on exploration and development to just above $4 billion, and that corresponded to running 3 rigs for instance in the Marcellus.

We've now reduced that further to a single rig program in the Marcellus, and in fact, we're at that level today. We're now projecting capital expenditure on E&D activities for this year at around $3.6 billion.

Dry gas spending in that figure is at a minimum and looking forward, will only be a couple of hundred million dollars. We're holding land where we need to because it makes sense to retain our position in the best dry gas plays for another day. In the Montney, we're running a 4 rig program to continue to delineate the play, and we've agreed a sensible program there with our partner Sasol who are currently paying most of the capital.

We're continuing to build operational momentum in the Eagle Ford and are currently running 12 rigs and 2 dedicated frac crews. Drilling performance is improving all the time, and we expect to hold 12 rigs through the rest of this year. And we've not changed our plans in the Duvernay, where we'll complete a 6-well pilot program through the remainder of this year.

In our fourth quarter call in February, I gave you guidance that as a result of our reduction in spending on currently uneconomic dry gas, we would grow like-for-like production during 2012 somewhere between 0% and 5% of the 2011 outcome, which was 425,000 barrels a day. Since then, we've reduced dry gas spending even further, and while I don’t believe we need to change our guidance, we're now clearly at the bottom of the 0% to 5% range in underlying growth.

The actual outcome for the year will depend on the asset sales we make and their particular timing through the year. For the assets we've sold so far, we've probably sold about 5,000 barrels a day for the year. Liquids or liquids-linked production will be little over 50% of the total for the year as a whole, and we'll see year-on-year liquids growth in our North American business from the Eagle Ford and in Southeast Asia as a result of contributions from Jambi and Kitan. I should just mention that despite a very strong start to the year in terms of production, the middle 2 quarters will be lower due to the normal planned turnaround activity. So hence, we're maintaining our original guidance for the year.

Now turning to the Yme project in Norway. At the last call, I noted I would have more information at the end of the first quarter. What's been happening on the project is that we've been completing our own independent studies to assess what is required to complete the platform. These studies are part of the normal handover process between the contractor who built the platform and us, as the operator of the license. I have to say it's been something of an evolving story because we've been progressively understanding the shortfalls of the platform as constructed against Norwegian standards.

A majority of those studies have now been completed and the main conclusions shared with both our partners in the project and SBM, who built and incidentally owns the platform. They indicate a substantial amount of work is needed to put the platform in a state of compliance. Up until now, we've been trying to assist SBM within the constraints of the EPC contract. We've had considerable numbers of engineers and technical teams present and working alongside SBM. In light of the conclusions of the studies I've mentioned, we believe the best route now is to allow SBM to complete the work independently as per the original contract.

We'll reduce our own presence alongside their teams, both onshore and offshore, of course, maintaining sufficient manpower in both places to discharge our proper responsibilities as license owner. We'll also remain available to assist them as they detail the work program, which delivers a compliant platform, which is ready to be handed over to us as operator.

Last quarter, I took Yme production out of 2012. Until such a time as a plan to complete the platform, which meets specifications, is defined and agreed as workable, I've decided to completely remove Yme from our forward projections. In parallel, we're examining all options to get the development completed.

I fully expect our medium-term growth guidance of 5% to 10% will remain valid despite removing Yme. We've also decided it's prudent to take some write-down on the project, mainly because it will now be later than we originally projected and the costs will increase. The project was on our books for just under $900 million, and we've included in our first quarter results a write-down of $250 million after-tax, to reflect a delay and our best judgment today of a range of outcomes. So progressively over the last 2 quarters, we've removed Yme completely from the forward projections and insulated our balance sheet to the extent we believe prudent. We will now move forward with Yme being fixed on the side so to speak. There's obviously considerable complexity in this, including the performance of the contractor and compensation for what has happened. I suspect that will take considerable time and will be quite separate from our continued intent to get the platform working and producing oil.

Now ladies and gentlemen, let me ask Scott to provide some more details on the first quarter before we go to your questions.

L. Scott Thomson

Thanks, John. I'll review our results, balance sheet, disposal activity during the quarter and our hedging position. Cash flow in the first quarter was approximately $850 million, which was 5% higher than the same period last year and 3% higher than the immediately preceding quarter, as higher oil prices and a smaller realized loss on held for trading financial instruments were partially offset by higher operating expenses and lower North American gas prices.

Cash taxes were higher than in the fourth quarter of 2011 as a result of higher taxable income in the U.K. and Southeast Asia, but were relatively unchanged compared to the first quarter of 2011. Non-GAAP earnings from operations of $167 million were approximately the same as the first quarter of 2011, and $50 million higher than the previous quarter and were impacted by the lower dry hole expense, lower exploration expense and higher DD&A.

Similar to a year ago, both cash flow and earnings from operations in the quarter were impacted by the timing of liftings. You will recall that in the company's international operations, the results are influenced by the timing of crude oil liftings, which cause inventories to increase or decrease from quarter-to-quarter. During the first quarter, we experienced an inventory increase of 550,000 barrels, arising mainly in Norway, Algeria and Australia. Had this inventory been lifted before the quarter end, cash flow and earnings from operations would have been an estimated $46 million and $31 million higher, respectively.

Net income in the period was approximately $290 million compared to losses in both the first and fourth quarters of 2011. In addition to the items noted previously, the principal factors contributing to this result were the gain on disposal arising from the sale of noncore coal assets, offset by the write-down taken on the Yme project. As John noted, the completion during the first quarter of various studies of the Yme project and the knowledge that it will now be delivered later than projected and likely at an increased cost has led us to conclude that a write-down of its carrying value is appropriate. Accordingly, we recorded an impairment expense of approximately $980 million in respect to the Yme during the quarter, which at the prevailing Norwegian tax rate is approximately $250 million after-tax.

The remaining carrying value associated with the company's investment in Yme is approximately $650 million.

The realized price in the quarter of approximately $65 per boe was relatively unchanged from the first quarter of 2011. While the realized oil and liquids price increased by 11%, the realized natural gas price decreased by 12%. Netbacks were 9% lower than in the first quarter of 2011 due principally to increased production in royalty paying jurisdictions and higher OpEx per boe. Although netbacks were lower in North America as a result of lower gas prices and higher operating costs, they were higher in all other areas of the business.

I'd like to take a moment to provide some color regarding the operating expenses and DD&A trends. Operating expenses of approximately $580 million were $125 million higher than the first quarter of 2011. There were 4 broad reasons for this. First, increased activity in Colombia and Southeast Asia, with new operations at Kitan and Jambi Merang. Second, the Pennsylvania impact fee came into effect, which resulted in a charge for the quarter of $21 million, of which $18 million was a onetime impact resulting from the retrospective application of the legislation to wells drilled pre-2012.

Third, the movement in unlifted oil volumes added approximately $35 million relative to last year, since the inventory increase in the period was less than in the corresponding period in 2011. The remainder of the increase arose from an increase in maintenance activity in the North Sea. Unit operating expenses increased by 10% over the same period last year reflecting increases in North America and the North Sea. North America unit OpEx was down $0.40 per boe after normalizing for the onetime retrospect development of the Pennsylvania impact fee, which added $1 per boe to the unit rate in the quarter. The underlying trend is a continuing decrease in the North America rate. The increase in the North Sea rate relative to the first quarter of 2011 was the result of higher maintenance and lower production. Operating expenses decreased by $54 million relative to the immediately preceding quarter as the reduction of maintenance cost in the North Sea and Southeast Asia exceeded the impact of the Pennsylvania impact fee and increased activity in the Eagle Ford. Unit operating expenses benefited additionally from increased production.

DD&A expense of approximately $600 million was $130 million higher than the first quarter of 2011. The increase in activity in Colombia and Southeast Asia again contributed to the increase, as did the movement in unlifted oil volumes, which added $25 million to the DD&A in the quarter. The remainder of the increase was the result of rate increases resulting from reserve revisions in the fourth quarter of 2011. Compared to the fourth quarter of 2011, the $57 million increase in DD&A was due to increased production, a full quarter of Kitan and rate increases.

Total capital expenditure for the quarter, including exploration expense was $1.1 billion, of which $1 billion was associated with exploration and development activity. Approximately $600 million of this amount was spent in North America, $230 million on North Sea development, $70 million on Southeast Asia development and $70 million on international exploration. For the rest of the year, we expect the run rate in North America to reduce quite dramatically given the decreased activity in the Marcellus.

As John noted, we have made good progress towards our disposal target of $1 billion to $2 billion. We completed the sale of a noncore coal asset in the first quarter for proceeds of $500 million and expect to complete the sales of our noncore Shaunavon and Whitecourt assets during the second quarter for a further $450 million.

At March 31, we had net debt of $4 billion compared to $4.5 billion at December 31, 2011, reflecting the disposal proceeds received in the quarter. Available borrowing capacity at March 31 was $3.2 billion.

And turning to our hedging program. During the first quarter, we had $9 million of cash outflows associated with our hedging program, compared to $47 million in the first quarter of 2011 and $39 million in the immediately preceding quarter since our out of the money hedges rolled off at the end of 2011. In 2012, we have 50,000 barrels per day of Brent oil hedged in the second quarter, 30,000 barrels per day are hedged in $90 by $150 collars and 20,000 barrels per day are hedged in $90 by $125 collars. In the third and fourth quarters, we have 30,000 barrels per day of Brent hedged, 20,000 barrels per day in $90 by $150 collars and 10,000 barrels per day in $90 by $120 collars.

We have no gas hedges in place for 2012 and no hedges in 2013. Those are my highlights. I'll turn the call back over to you, John.

John A. Manzoni

Thanks, Scott. Ladies and gentlemen, just before your questions, let's just summarize the quarter. We had a very strong operating quarter with great production, which sets us up well for the year. We have reduced our capital plans further with only a very small proportion drilling dry gas in the current environment and despite that, we will hold our production guidance for the year, although clearly we expect to be at the bottom end.

We've made great progress in terms of focusing the portfolio, with $1 billion already sold this year and more to go. We've discovered oil in Kurdistan, and our PNG program is going well. Still to come this year will be more results from Colombia and some interesting wells offshore Vietnam.

In Malaysia, we've been awarded the operatorship of the Kinabalu field at the end of the existing PSC toward the end of this year. The field is producing today. It will create a hub around our Sabah exploration activities, and we're looking forward to increasing recovery and value from the field. And we put the Yme project to one side, and we'll build our forward plans to exclude it until such a time as we decide how to progress.

I think that's enough from us. Ladies and gentlemen, now I'd like to turn, if I may, to your questions.

Question-and-Answer Session

Operator

[Operator Instructions] Your first question comes from Andrew Potter from CIBC.

Andrew Potter - CIBC World Markets Inc., Research Division

Sort of a question on Yme. First thing is, can you remind me just what's on the books in terms of 2Q reserves for Yme? And then second just to clarify, I think there's some concern out there that you guys may have to put up some cash to get Yme over the finish line, but just based your comments, that doesn't seem like it's the case. That in fact you may be looking for a compensation as opposed to actually having to put something up, is that correct?

John A. Manzoni

Andrew, let me just deal -- see I'm looking at Tony, but 2P reserves about 40 million or 50 million barrels. We haven't made a change to the 2P reserves primarily because we believe we'll get the project over the line. We'll develop the field. It's just a question of exactly when. With regard to the cash out, obviously that will be subject to some discussions. What I've said is that we're pulling back, we're reducing costs to some degree that we have been having in the past 12 months as we've been trying to assist the contractor. We'll be pulling that back somewhat as we allow them now to figure out how they're going to get the platform into a good shape so that it can be delivered. So the costs from here reduce going forward, I think relatively substantially as a run rate if that sort of answers the question. Does that get it for you?

Andrew Potter - CIBC World Markets Inc., Research Division

Yes, more or less. Okay. And then one other question, I guess, just on the U.K. John, I think in previous conversations, you had mentioned pretty wide range of options in terms of deemphasizing North Sea. I think at one point you mentioned, pretty much everything was on the table from selling 0 to up to 50% of the North Sea production. With the U.K. budget change coming in I think as you're expecting, how are you thinking about that wide range? I mean, are you guys thinking of getting more aggressive in terms of monetizing some North Sea?

John A. Manzoni

I mean, I think those range of options still exist. Let me see if Tony Meggs, who's been running that part of business pro tem, would like to offer you any perspective, Andrew.

Tony Meggs

Yes, well I think a couple of things. One is, we are, let me just say, actively pursuing options to dilute our interests in the North Sea. And we have discussions ongoing. Secondly, we are looking at the 2 major projects that we have in the North Sea, the Auk area redevelopment and the Montrose/Arbroath redevelopment. These are both good projects with good economics helped by recent changes in taxation changes from the government. But nevertheless, given the capital size, we are still actively looking at ways of reducing our exposure to those projects. So I can say it's as often a work in progress, but nevertheless, good progress is being made.

Andrew Potter - CIBC World Markets Inc., Research Division

And is there any time line from when we should expect kind of the next data points?

Tony Meggs

I really don’t like to give time lines, but it will be this year for sure.

John A. Manzoni

I think we'll give you some clarity, Andrew, this year. And as Tony's indicated, there's a range of options. These things are always very difficult. You have to do it before you talk about it, and we have those options that he's described actively under consideration.

Andrew Potter - CIBC World Markets Inc., Research Division

Right, okay. And very last question, I promise. Obviously, a big land position in Marcellus which you're deemphasizing, huge opportunity at Duvernay, still a big position in Montney, with such low activity levels, I mean, are you starting to think of more joint venture type deals, is that on the table?

John A. Manzoni

Let me see if Paul Smith wants to offer a comment on that. Paul, in light of our reduced activity?

Paul R. Smith

Yes, I mean, as you know, we've already got a partnership with Sasol in our Montney assets. In the Duvernay, I think it's early days, Andrew, and we're 2 wells into our 6-well program. Just about every week, you see another well coming in, in the Duvernay, and I think there's momentum building in the Duvernay for all of us in terms of encouraging results that confirm or starting to confirm the Duvernay as a really exciting emerging liquid-rich play, with all of the characteristics that we would expect for a long-term play. We've got substantial position in the Duvernay, but now is not the right time for us to be considering bringing in a partner into the Duvernay. And then the Marcellus, I think we've just -- we've always said we've got just enough of the best. Once we slow down our activity in the Marcellus temporarily, the rocks remain world-class rocks, and I'm confident that as gas prices recover in the medium-term, that, that will continue to be a core part of our business. And so there's no intent to dilute our position in the Marcellus.

Operator

Your next question comes from Robert Bellinski from Morningstar.

Robert Bellinski - Morningstar Inc., Research Division

I was wondering if you could give a little bit more color as to the -- some of the bottlenecks you're seeing in Colombia with the permitting issues.

John A. Manzoni

Yes, Robert, let's see -- let me just ask Richard Herbert if he'd like just to comment on what's happening in Colombia. Actually perhaps in a general sense, so that you can get a bit of a picture of what our position is. Richard?

Richard Herbert

Yes, Robert. John mentioned in his speech that the permitting delays have slowed it down a little bit there this year. In fact, it's slowing down the whole industry in Colombia at the moment, and it's really an issue with the environmental permits that are required to drill wells, to test wells and to build facilities. And it's just causing a certain amount of delay in projects. We've been in very active discussions with the government, and they're well aware of the problem, and they're trying to work to bring in additional resources and try and speed things up. And just a few weeks ago, our joint venture company, Equion, received its environmental permits to begin the construction of upgraded facilities to expand its facilities at the Piedemonte site. So that was a very big milestone for us. A permit that we've been waiting for, for about 6 months. I mean, in the meantime, we do have drilling activity. We just drilled another stratigraphic well in Block CPO-9, which is where our Akacias discovery is. And that well is some way down deep from the Akacias-1 discovery well, and we've logged oil in that well down to the base of the reservoir, but of course, we'll have to wait for the permits before we're actually allowed to flow test it. But we do expect those permits to be delivered shortly. So I think on balance, it's slowing us down, but we still got some activity. And one of the positive things coming out of Colombia this year is our production, which thanks to the last few wells that were drilled by Equion in the Piedemonte fields and some debottlenecking of the facilities, we're now able to produce at up to -- over 18,000 barrels a day net to Talisman as opposed to 14,000 to 15,000 last year. So we are seeing some good progress on that.

John A. Manzoni

So pretty -- overall, quite a positive thing, a bit frustrating when you can see the oil and can't flow it because you're not allowed to, but as I said, I think, Robert, some increasing news flow through the course of this year, which hopefully I think will put us on a good track.

Robert Bellinski - Morningstar Inc., Research Division

That's helpful. And then my second question, John, you kind of -- if I heard you right, you mentioned Makassar in Peru in kind of relation to the disposals for the remainder of the year. Are you thinking of pulling back working interest in those plays? Or is there a consideration of a complete divestiture?

John A. Manzoni

I think the answer to your question is sort of considering all options, Robert. We have drilled 2 dry holes, that doesn't necessarily write off, for instance, Makassar. I think it writes off South Makassar basin completely, but I think we're certainly considering our own options from dilution through to total exit, and we'll be making those final calls again in the course of the next few months.

Operator

Your next question comes from George Toriola from UBS.

George Toriola - UBS Investment Bank, Research Division

I have 2 questions. The first is on North American natural gas, particularly Canada. Just based on your cash costs and the economics of your current production, are you considering shutting in production right now?

John A. Manzoni

George, thank you. Let me ask Paul Smith of what he's thinking about in terms of the natural gas, in particular in Canada or shut-ins.

Paul R. Smith

Yes, I mean George, clearly with AECO hovering around $1.50 right now, assets that only a few months ago were well above water in terms of their marginal costs are now starting to approach their marginal costs. Let's say that the assets that we're exploring most closely are our Monkman assets, and that's linked mainly to a negotiation that needs to happen with Spectra where we process most of the gas. And we're looking at all options for Monkman. If we don't get an equitable outcome in a low-gas price environment to keep some of that gas flowing, we have different options there to mothball parts of the field, all of the field, and I'd say that's the only asset today even at these low gas prices that are starting to approach the marginal cost of production.

John A. Manzoni

Sounds like that was a message for Spectra there, George, thank you for that.

George Toriola - UBS Investment Bank, Research Division

Okay, just a follow up, this is for the North Sea now. You talk about the options in the North Sea. But I guess the changes -- the recent changes in taxation, particularly around the commissioning, liabilities and things. Has that changed your view at all as to what to do with your North Sea assets? Sounds like it hasn't. And just wondering how you're thinking about it in light of at least some clarity on the decommissioning side.

John A. Manzoni

Yes, sure. So let me ask Tony how that's -- positive moves from the U.K. government, whether that's changed our view or not.

Tony Meggs

Well, I think the positive news we should be pleased about I mean, it improves the overall value of our business. It provides some certainty around future decommissioning tax treatment. And therefore, actually makes the assets essentially more tradeable. It really doesn't change our plans. Our plans are to first of all, run a good safe business. We still have lots of opportunities in the North Sea, lots of wells to drill and some good projects to do, but nevertheless, we plan to, as we have said, manage the volatility of the business by a reduction in our overall interest, either through some combination of a reduction in our interest in the 2 major projects and/or a sharing of our interest in the U.K. and North Sea business overall. So plans are unchanged, but the news from the government is really good. And it helps the economics of some very interesting projects.

George Toriola - UBS Investment Bank, Research Division

Okay, that's helpful. I guess just one last question for John now. So let's just fast forward 6 months assuming that you're able to do what you want to do in the U.K. You're able to potentially divest some of your exploration portfolio. Where do you put all of that? Where do you reinvest? How would you think about reinvestment once these things cleared?

John A. Manzoni

Now of course, an interesting question, George. I mean, the continued evolution of the company, the continued evolution of the strategy remains, of course -- we've made some big shifts, we've made some bets on unconventional. Momentarily, gas prices have made that a complex issue, which is why we -- we're not panicking about that, it's not going to be there forever. We have a fabulous dry gas portfolio here in North America, which will come back, we don't need much, and it will come back. We are building liquids opportunities in our unconventional activity. We can see -- so the opportunities for investment range from today, we're looking at many options for liquids-rich unconventional opportunities, both in North America and outside. There are plenty of people asking us to help them outside North America, and we're one of the few companies who can do that. We have a building business in Asia, which actually as I mentioned, the Kinabalu field, for instance, wasn't in the press release. It was in the remarks that I made. There are other opportunities in Asia to continue to build that business, growing strongly, great realizations. And as we look forward into our exploration portfolio, we're beginning to see success in Colombia. We'll follow investment into Colombia. Papua New Guinea is seeing success. Kurdistan now is interesting and seeing success. That'll take a little while to clarify, but is potentially very, very interesting indeed. So there are many opportunities consistent with today's strategy to continue to build out our portfolio. And you know, the world keeps changing, one's got to keep dynamic, and so those are the sorts of things that will attract additional investments. All the time, we think about how do we accelerate a transition from the old Talisman to the new Talisman as we release cash out of certain parts of the business and redeploy it into new parts of the business. So we are active. This is one of those things that one, as I say, one can't talk about too much until it's done. I can assure you, the team is thinking about many, many options, both on the release of cash and on the investment of cash as we think about how we steer the company through a momentary difficulty bit in the dry gas shales. That's the sort of general answer to your question.

Operator

Your next question comes from Greg Pardy from RBC Capital Markets.

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

John, looking forward with North Sea playing less of an emphasis and dry gas playing less of a role, and the Eagle Ford becomes a bigger piece of the puzzle. Just thoughts around that, I mean, you've mentioned a dozen rigs. It looks as though you're going to be comfortably blowing through the conservative estimate you have this year on the production side, and you're bringing lots of people down there later this month. What are the expectations for how big the Eagle Ford could become?

John A. Manzoni

Yes, let me -- you sort of given out, now I haven't got any choice now Greg, but to ask Paul to answer the question about Eagle Ford.

Paul R. Smith

Thank you, Greg. I've been waiting for this one.

John A. Manzoni

For the near term, Paul, and then let's talk a bit about how big it can get for us.

Paul R. Smith

Yes, I mean, let me sort of start with some context. I mean, we've continued to build operational momentum, and we've moved a long, long way in the last 6 to 9 months, Greg, in the Eagle Ford. We're running with 12 rigs now, and we previously said that we'd go up to 14 rigs. That's actually no longer necessary as we continue to come down the D&C learning curve, and our drilling cycle times are showing some pretty remarkable improvements over the last 6 months. We're actually going to be able to execute the same activity set and indeed, actually slightly more with a 12-rig activity set than we originally thought we'd need to do with 14. So that's the first point. Operational momentum is now sort of at full speed and for those of you coming, you'll see that in action next week. The second thing I've messaged for the last few months is that, actually the biggest concern around being able to be more precise around where we're going to end up in 2012 in the Eagle Ford is around egress. The good news is that we've had a very strong first quarter, and you've seen that from the results where we produced 75 million standard cubic feet a day equivalent, which about half was liquids. And that was because we were able to that every single molecule away through interruptible transportation. With 300 rigs up and running in the Eagle Ford, at some point, the interruptible transportation may start to close in on us. But we have light at the end of the tunnel with the buildout of our egress position, which we'll talk about more next week at the IOH. And because of all of that together, Greg, I'm now comfortable to reset our expectations for the Eagle Ford this year from the 60 million cubic feet a day equivalent that I've been signaling up until now to a range of 70 million to 100 million cubic feet a day, and the big determiner of where we end up in that range is going to be our ability to access interruptible transportation for the next 3 to 4 months.

John A. Manzoni

So positive news, Greg, in the near term. And I think the Eagle Ford position as a whole builds to sort of to the 40,000 and 50,000 barrel a day equivalent over time as all of our positions do, and I think we continue to look frankly to optimize our position, to build our position because one's got to be with a mind on value. And the prices get pretty toppy out there as the world moves toward it. So -- but I think it's all positive. In the near term, as Paul has described, and in the medium-term, where we're looking at a 40,000, 50,000-barrel a day type position as we build that position as everything that we do needs to achieve. Does that help?

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

Okay, and maybe just one follow-up on that. As you mentioned, I mean, you've got $1 billion done in dispositions. So in terms of going from $1 billion to $2 billion then, is it most likely that the asset sales would be in North America or could that encompass other parts of the world?

John A. Manzoni

Well, we've signaled various options, Greg. One is in North America. Second is in the North Sea, which we spent a little time this morning talking about, and the third is certain aspects of the portfolio, the exploration portfolio as we evolve that. So I think we could -- steps from here could come from any of those places.

Operator

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

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

Just a couple quick questions for me. One bookkeeping question on guidance for the full year. Just wanted to clarify when discussing kind of the lower end of the 0% to 5%. Does that include the asset sales that you have held for sale at the moment?

John A. Manzoni

No, what I said was that organically, Matt, we'll be at 0% to 5% because we've brought gas spending from over 4 -- most of that change from over $4 billion down to $3.6 billion, is coming out of the dry gas. So we've brought that down. We've pushed Yme out. So we're at the bottom of 0% to 5% organically and then what I said is depending on when we sell assets across, will depend on how much production comes out. But right now, I would imagine 5,000-ish barrels a day of that number to sort of accommodate an inorganic outcome.

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

Great. And then just on the asset sales in particular. Can you provide any update, I think you had mentioned previously you were looking at potentially monetizing some of the noncore Montney assets or some of the nonproducing Montney assets. And then also in the Marcellus, on the midstream side, if there's any intention to potentially monetize your midstream assets given the deemphasis on growth in the Marcellus in the near to medium term.

John A. Manzoni

Let me deal with the first and then look to Paul, just to tell us where we are in some of the Montney. The midstream in the Marcellus, clearly an opportunity. We sit on -- and it's not the only opportunity. We sit on quite a lot of pipes, quite a lot of infrastructure, quite a lot of things like that in the portfolio. And the question is, how do we move forward in the most value adding way for those assets, if at all? So that is part of consideration. I'm not saying there's any firm plans, but we are reflecting on whether those assets are best in our hands, in partnership with others, in someone else's hands, the whole range of things that we are thinking about and of course, I mean, just to give a little color to that, one wouldn't want to have stepped into a partnership for instance, which required continuously building gas throughput, just at the moment when the gas price fell out of bed. So I think caution here, reflection and thoughtfulness is important. But that does not mean to say that there isn't opportunity within our portfolio of the infrastructure that we have. So that is being thought about, being considered, but today no firm plans, but it is in our minds. That's the answer to the second part of your question. And then on the Montney, Paul?

Paul R. Smith

Yes, I mean, Matt, we've got, as you know a very large position in the Montney, roughly 30 tcf of contingent resources. We've struck a partnership, as you know, with Sasol for 2 of those areas, Farrell Creek and Cypress A, and we'll continue to look at options to potentially monetize parts of that position, but we'll only do so for value. And so I don't think there's anything definitive on the horizon today. But we'll continue to look to high grade our portfolio in the Montney like we do anywhere else within the portfolio.

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

Great, and then just last question for me on the exploration front. Can you, I guess, give us an update on roughly timing for your CPO-9 test and then on Humadea, if you're still planning on drilling that in June and then finally, any interest in the unconventional resource in Colombia?

John A. Manzoni

Yes, good. Let me ask Richard to talk about an update, just timing CPO-9 and Humadea and unconventional. Richard?

Richard Herbert

Yes, well it's a little bit dangerous to predict timing when we are in a sort of environmental permitting process, which is not in our control. We hope the CPO-9 to receive the permits, which would allow us to test these 2 stratigraphic wells we've drilled. And we are hoping we will still -- that we'll obtain those permits by the end of May. That is the date that we've been promised. We'll wait -- we'll have to wait and see whether they actually get delivered then. That would allow us to go ahead and do those tests relatively quickly. And in terms of the future drilling program there, again, we need the permits to come through. But we're really probably looking at third or maybe fourth quarter for any exploration drilling in the block.

John A. Manzoni

Like Humadea, for instance.

Richard Herbert

Like Humadea.

John A. Manzoni

And unconventional, Richard, any thoughts on that?

Richard Herbert

Yes, unconventionals, I mean, obviously we're interested in the unconventional potential in Colombia, and we've been looking at it for some time. We have signed up a study with our partners, Ecopetrol to look at one part of the country, which we think is quite promising. And of course, there are a number of blocks being offered in the bid round later this year, which will have unconventional potential. So this is something that we see as a natural fit for Talisman, so we're taking a good look at it.

Operator

Your next question comes from Brian Singer from Goldman Sachs.

Brian Singer - Goldman Sachs Group Inc., Research Division

Most of my questions were answered. But I just wanted to follow-up once more here on Yme. In your comments and in the release, you mentioned that you would consider all options to get the platform completed. Can you give us a sense of what those options would be beyond what you described as your base case, waiting for the contractor to deliver a compliant platform?

John A. Manzoni

Yes, sure, thanks, Brian. Let me ask Tony to see -- just to see if he can give you a bit of flavor on that. All options, Tony, what do we mean?

Tony Meggs

Well, first I should remind you that we've already completed a lot. We've got wells already in place in subsea or seabed facilities in place. By all options, we mean FPSO, other floating production schemes.

John A. Manzoni

And including fixing the existing...

Tony Meggs

Yes, I think our base case right now is some form of fixing what we have. If I may say, I mean, the engineering studies have revealed problems with fire protection, weight -- and weight of the platform. But I should also say that the platform is perfectly safe right now. People out there working on it and working on completing it. But we have some concerns in the longer term, and we're going to take the next few months to fully evaluate that and have a clear plan forward. As a part of that, we look at all options obviously, but still our base case is to fix the issues that we have and proceed from there.

John A. Manzoni

So Brian, everything's open here. Although as Tony has emphasized, and I think we should consider the main plan, putting some strengthening on the existing platform that what we call the MOPU. So that seems to be the most likely, but we don't want to constrain ourselves as we look forward here to get this thing onstream in the best and most economic way. We still think there's lots of value there, so the question is how do we get it on in the most expeditious way, frankly.

Brian Singer - Goldman Sachs Group Inc., Research Division

And then, you kind of mentioned this in one of the previous questions, but can you put into context or add some color around the Akacias stratigraphic test? The latest one that you, I think, indicated was very encouraging, and what that might do to resource or what level of confidence that gives you in the Akacias area?

John A. Manzoni

Yes, I think you've just got to describe oil down to tests all that stuff, Richard, over to you.

Richard Herbert

Yes, Brian, it's always difficult to -- it's frustrating to talk about these things without all the data. So as you know, we drilled Akacias-1, which is fairly high up on the structure, and that's the well that's been on long term test now for nearly a year, and it's still producing very well, at just under 1,500 barrels a day. And we're now looking at a sort of an early development scheme, which would be positioned around that well and along strike with that well, which we're hoping to sanction sometime during the next few months and bring on production in early 2013. There's clearly some potential upside volumes in the structure, and so we've now drilled 2 stratigraphic wells some way down deep. The first well in up in the north, logged an oil section, but we've been unable to test it because we haven't had the permits. We've now just completed drilling of a second stratigraphic well, which is located in the southwestern part of the structure, and it's also about 500 feet down deep from Akacias-1. And again, we're still in the process of logging that well, but we have logged oil down to the base of the tertiary reservoir. So we're seeing oil on logs, what we don't yet know is the flow characteristics because this is quite a heavy oil. It's something around about 8 API gravity. And as we move into a transition zone with water, we just want to be confident that this will flow at commercial rates. So we're not saying anything about volumes until we've got some flow test. But I'll have to say that it's encouraging and if these oil down twos are confirmed, then Akacias is clearly a very significant discovery.

Operator

Your next question comes from Brian Dutton from Crédit Suisse.

Brian C. Dutton - Crédit Suisse AG, Research Division

Two questions. First is on costs. And in particularly G&A costs. They continued to move upwards on a quarterly basis, and just wondering what's the driver behind that. And is what we're seeing in the first quarter here the new base?

John A. Manzoni

So let me see if I can deal with that one. I mean, I think it's true, Brian, and this is some context, what's been going on in Talisman is that we've been building capability increasingly, and I'm just trying to find the right word, but we're increasing the professionalization of all the decisions we make on a functional axis. So there's no question we've been building capability across the company and to some degree, that's all been improving everything, but it has also been bringing with it increased costs. Because we've been adding people, we've been adding capability across the business. Now we've still got, I would say, today, we still got a relatively active recruitment program filling vacancies in the context of that build. Now that is not -- and I would say to you, that of course we're watching it, we've recognized it. And I would also say to you that I'm pretty clear that in $2.50 gas prices, we need to sort of reverse the trend of that build. We need to change the trajectory of a continuously building G&A because we're in a $2.50 gas price. This is not something that I believe you do sort of arbitrarily. I think one's going to be thoughtful, but there is no question that we must reverse the trajectory of our G&A cost because in today's environment, we can't afford to continue to build as if the gas price was $5-plus. And there are various ways of doing that. The first and most obvious is that we've actually made these interventions already. We're examining every single recruit vacancy to make sure that it's critical and rapidly and quite radically, actually reducing the pace of recruitment. So that would be the first thing, but I don't think it stops there. I think there are other areas clearly as we move from 10 rigs to 1 rig in the Marcellus. We've clearly got an organization which is larger than what it needs to be for the current environment, and we're thinking about the redeployment of some to Houston to the Eagle Ford, but there's obviously some impact. So across the company, you're going to see, I think, a change in the direction of the G&A cost. I think that probably gets at what you're looking for.

Brian C. Dutton - Crédit Suisse AG, Research Division

And the second question is on a bigger topic, bigger prospective. On the fourth quarter conference call, I asked you how you rated Talisman's performance on implementing the strategy that you unveiled 4 years ago. So reflecting on that, what do you think investors are continuing to miss given Talisman's share price performance over the past 12 months or maybe to put it another way, what's the key message that you think investors better need to understand?

John A. Manzoni

It's an interesting question, Brian. I mean the -- I think over the course of the fourth quarter last year, a couple of things changed a lot. First is the gas price moved down, and we're seeing it at $2.50, and the second is we have some operational stumbles frankly in our North Sea business in particular. I said to you then and I still believe, we shouldn't be panicked by a $2.50 gas price. We have one of the best shale portfolios in North America, I believe. When, and as I believe it will, the world could look quite different, it could look quite different as early as 2013, but we'll see. The question is, how do we maintain that position going forward. And I think that a gas price -- a more optimistic gas price will actually change the complexion of how people see this company, that would be one thing. But that isn't all. There are things that we're doing for ourselves and when you stumble, which I frankly think we did at the end of last year in certain of our operations, it takes time to rebuild credibility. This year is about doing what we said we would do. A series of things happening, whether it's increasing visibility in liquids-rich production, whether it's increasing news flow from our exploration portfolio, Colombia, PNG, Kurdistan, other places. Whether it's continuing building our Asian business, and you've heard 2 or 3 things and by the way, I think you will hear some more things through the course of the year. You will hear some more transactional activity, not all of -- directionally, we've signaled. We are very active thinking about those things and, of course, our objective is to move the needle with some of those things over time. I think this year is about news flow, rebuilding confidence and putting the company back on to what I call the front foot, which I think -- the first quarter was a good start, and I think we can do that. So I would say to you that -- and you don't move a portfolio of this scale, of this spread overnight. You can't just flip a switch and move stuff. But what I would say to you is that, we are not and I know you've written this, but we're not sitting idle fat and happy. We are examining many, many options, which our intent is to do them and then talk about them, rather than talk about them and then do them. And I've sort of indicated and hinted that it'll be -- what we're aiming to do is in the context of the gas price in North America is to accelerate the transition of the portfolio. Anything we do needs to accelerate into the future and accelerate out of the past. And the conversation about the North Sea is an interesting one. How do we reduce our exposure in the North Sea, from little options to big options. All of those are under discussion, and we have to pick a path and then we have to execute. So I'm not frankly a fan of talking about stuff to the market and saying you're missing this, you're missing this. This company needs to demonstrate action, and the market will see it. And I have felt after our end-of-year last year, I have felt that 2012 will be a year where progressively news will be in the market, which I think will rebuild the front-footedness and confident forward moving of this company. And I remain confident that will happen through the course of this year.

Operator

Your next question comes from Mike Dunn from FirstEnergy Capital.

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

A couple of questions. First question, I guess, maybe for John or Paul. You mentioned the project offshore Malaysia, Sabah, I forget how to pronounce it, but could you just clarify what you're expecting there? I believe you said 8,000 to 10,000 barrels a day getting into your hands by around year end. Just wondering what are the fiscal terms there? What does the redevelopment project look like? And did you recently pay for this? Or is this something that's been an agreement from -- that you had in the past?

John A. Manzoni

So Mike, let me ask Paul. It's Kinabalu. Kinabalu. Offshore Sabah. So Paul, why don’t you talk a bit about what you've been busy doing over there?

A. Paul Blakeley

Sure, thanks. Well, first of all, the Kinabalu field or the Kinabalu license, it's an operating producing oilfield. It's been under license for over 20 years, and that license has run out. And so it's not an acquisition. This is a relicensing of the PSC by the government to Talisman. We'll take 60% equity interest and operatorship. As John highlighted, the field is currently producing around 10,000 barrels a day of oil. And we see a number of investment options both in the short term to increase production and also more significant redevelopment options perhaps down the longer term. But we'll talk about those later, I think. In the first instance, we're delighted with this asset because a, it does bring production immediately. And immediate investment opportunities, but also it's located adjacent to our existing Sabah exploration acreage in Sabah Block 310. So there's a lot of synergies with exploration there for tiebacks, for more economic development of exploration success. So in many ways, it fits the portfolio very well, and we are absolutely delighted with it. In terms of short-term activity, we'll transition over the second half of the year to become the operator at the end of this year.

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

Great, Paul. And any -- some thoughts you can share on the fiscal terms there? Typical Malaysia?

A. Paul Blakeley

Yes, good question. I mean, because this is an existing field, we've been working with the government on a different set of terms. This is a progressive volume-based PSC term. It's slightly different to traditional PSCs in that the incentivization is to invest and increase production and reserves. We're delighted about it because that's what we want to do.

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

Great, Paul. And I guess the second question, guys, on Kurdistan. I mean, you talked about drilling another well, I think, later this year on -- not Kurdamir, but the block to the northeast, I believe. Is everything sort of with your other blocks, inside Kurdamir, are those plans sort of on hold a little bit until you make a decision on the payment to KRG at Kurdamir?

John A. Manzoni

Let me ask Richard to talk about -- I think you're talking about Baranan, but maybe Topkhana and Baranan as well. Richard?

Richard Herbert

Sure. So we've got 3 production sharing contracts in Kurdistan: Kurdamir where we're drilling Kurdamir-2, Topkhana which is the adjacent block and then we have the Baranan block, which sits a little bit to the north. And our plans at the moment are to finish drilling at Kurdamir-2. We're now drilling down to the deeper Cretaceous target on that and then to move the rig up to Baranan and drill what is essentially a commitment well to fulfill the work obligations in this phase of the contract. So I mean, that is our plan. That's what we're going to do. I mean, clearly, along the road, we have to make a decision on whether we're going to enter the next phase of the Kurdamir license. And I think based on the very encouraging results we're seeing in Kurdamir-2, it's very likely that we're going to do that. That will commit us to drilling another appraisal well, which we will need to try and chase the oil down deep and understand where the oil, where the contact might be. And as you allude to, there is a capacity building payment that comes due. We're looking at the ways that we might structure that. We're in discussions with the government. It will probably be some form of phased payment that we'll pay as we move into the next phase.

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

Great. And then Topkhana, can you just remind me Richard, the plans for that?

John A. Manzoni

Topkhana.

Richard Herbert

Yes, Topkhana is -- Topkhana, we have the make a decision by December on what to do with that. And again, I think we'll obviously study the full results of the Kurdamir-2 well, but it's very likely in our view that the oil leg that we're seeing under Kurdamir extends into and under the Topkhana structure, and it's probably all part of one very large accumulation. So I think it's very likely -- we haven't made a final decision yet. I think it's very likely we will go into the next phase of the Topkhana license and drill another well there, which would probably be drilled after the Kurdamir-3 well starting sometime middle to late next year.

John A. Manzoni

Mike, if you keep digging, you're going to get the explorer to tell you what he really thinks.

Operator

Your next question comes from Menno Hulshof from TD Securities.

Menno Hulshof - TD Securities Equity Research

I'm going to start with a question for Paul on the Marcellus. Just looking at the volumes, it looks like production was up roughly 9% on a quarter-over-quarter basis. Given the planned spending cuts, when can we expect those volumes to roll over? And then how much of a well inventory do you have to work through before that happens?

Paul R. Smith

So Menno, I mean, just to remind you of the degree to which we've cut back, and then I'll answer your question. As John alluded to, we entered the year actually with 11 rigs, intended to ramp that down to 5 to 7 rigs. We have ramped that down by the beginning of April to a single rig, which is what we will continue to run for the rest of this year and beyond if necessary until we see a recovery in prices that are sufficient to allow us to pick economic activity back up again. As we do that, we have no land expiries, and we'll see minimum PUD expiries. The rollover is starting to happen right now. I mean, so we've brought a huge amount of momentum clearly into the first quarter. As you bring a machine of 11 rigs and a massive well inventory into the first quarter, that's the reason why you saw nearly 550 million standard cubic feet a day in the first quarter. Our spend this year is going to be down from $1.2 billion that we spent last year, down to roughly $350 million, of which most of that $350 million has been spent in the first quarter. And for the remaining 3 quarters, we will only be spending roughly $150 million. I will guide you and say that for this year, I mean, the turning point is happening as we speak, clearly. And we will probably end up this year with the capital that I've just outlined and activities that I've just outlined producing somewhere in the range of 450 million to 500 million cubic feet a day in the Marcellus as we go forward this year.

Menno Hulshof - TD Securities Equity Research

That helps a lot. And then I'm going to move over to the North Sea. Maybe you could just elaborate on some of the water breakthrough issues that were highlighted in the press release for Rev and Tweedsmuir and whether or not that's a serious cause for concern at this point in time.

John A. Manzoni

Let me ask Tony what he thinks about some of those early water breakthroughs, some of which I think we've got some plans to remediate, but Tony?

Tony Meggs

Yes, so in the Rev field in particular, we are drilling the well, as I indicated earlier, I think, which I hope to spud by the end of this month, which will offset -- substantially offset the water breakthrough that we've seen there, and in Tweedsmuir also we're looking at another infill well at Tweedsmuir later in the year. So these types of fields tend to start out at very good production rates due to the high quality of North Sea reservoirs. And then there is always uncertainty about -- and then the production is the same by water, either from water injection or from natural aquifers. There's always uncertainty about when breakthrough occurs. But actually when it does, particularly in the very high-quality Norwegian fields, production tends to decline fairly rapidly. So there's uncertainty around those. But it is a part of this business. These fields come on production at good rates, water breakthrough occurs, we infill where we can, and we make -- and they have overall very good economics.

John A. Manzoni

And I think it's true, Tony, that despite the water breakthrough, I think we've got full infill programs, which hold this production across the North Sea as a whole. Specific plans in Tweedsmuir, Auk North, Rev, Varg, which hold it. Which is how we frankly, Menno, how we hold it flat because we anticipate the water breakthrough. We tend to get it within sort of maybe 6 months on the reservoir models and then we learn and then we come up with the infill well. So sort of the guys are sort of used to this stuff going on, and some of the specifics can be remediated and some of them can't, and they're offset by other things.

Tony Meggs

I should say also that we have an inventory right now in the North Sea in general of about 70 infill wells, and I think we plan to maintain or increase our infill activity over the next few years, that's in addition to major redevelopment projects. So we want to stabilize North Sea production over the next few years through the continuous infill drilling program.

Operator

Your final question comes from Mark Polak from Scotiabank.

Mark Polak - Scotiabank Global Banking and Market, Research Division

A couple questions. First one on Yme. I'm just wondering if you're able to provide me details on the additional cost and schedule assumptions you made in coming up with the write-down. And the other question for me, just in terms of the additional $450 million of dispositions, if you can provide any other details on that. I believe you mentioned about 5,000 barrels a day of production impact for this year. If you could just confirm what's associated with that and any other details would be great.

John A. Manzoni

Mark, thank you. Let me just see what we can do with these. We haven't provided a forward schedule for Yme because as I say, we've taken it out of the forward projections completely. So we've put it on the side. It doesn't affect the 5% to 10% going forward in the medium-term, and we can now rebase, and the intent is for all you lot to put it on the side as well, frankly, so that we don't keep getting tripped up by this. So that we can go and fix it going forward. The write-down that we've taken is a sort of best view of a range of potential outcomes that's potential solutions, potential times, at least $600 million to $700 million of value on the books of the $900 million that it started with. And our view is that's a pretty reasonable and prudent assumption going forward. So we're not -- and I have no intent frankly of falling into a trap of saying we think Yme is going to come on in x because until we finish the work frankly, we just -- we're not going to say anything. So it is sort of that's, that. I think you were then saying, what's the -- what was the second question?

Mark Polak - Scotiabank Global Banking and Market, Research Division

Just if you could provide any more details on -- you're at $1 billion of dispositions now, so it looked like another $450 million on top of the coal assets and wonder if you can provide any details around the most recent disposition.

John A. Manzoni

Yes, sure. So let me ask Scott.

L. Scott Thomson

Mark, so the $450 million as I said in my opening comments, relate to the Shaunavon and Whitecourt assets. And we expect both of those to close in the second quarter. And you're right, the 5,000 barrels that John referenced in his script was associated with those 2 assets. That's the annualized impact of production for the year.

John A. Manzoni

Thank you very much. Was that the final question, Michelle?

Operator

Yes, it was. I turn the call back over to you.

John A. Manzoni

Thank you. Ladies and gentlemen, thank you for joining our call. We continue to be -- to look forward with optimism despite a very low AECO gas price. Lots to do and lots of excitement to come. So thanks very much for your time. And we look forward to the next time. And with that, we'll close the call. Thanks.

Operator

Thank you. And this concludes today's conference call. You may now disconnect.

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