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Executives

John Manzoni – CEO

L. Scott Thomson – CFO and EVP - Finance

Paul Smith – EVP, North American Operations

Richard Herbert – EVP, Exploration

Paul Blakeley – President, Operations

Analysts

Greg Pardy – RBC Capital Markets Toronto

Brian Singer – Goldman Sachs New York

Mark Polak – Scotia Capital Markets Calgary

George Toriola – UBS Securities Canada Calgary

Andrew Potter – CIBC World Markets Calgary

John Herrlin – Societe Generale

Andrew Fairbanks – Bank of America

Brian Dutton – Credit Suisse

Minu Hulsa (ph) – TE Securities

Mike Dunn – FirstEnergy Capital

Scott Haggett – Reuters

Palo Rasvel (ph) – Veritas Investment Research

Scott Polster – Calgary Herald

Cam Sandhar – Peters & Company

Talisman Energy, Inc. (TLM) Q3 2010 Earnings Conference Call November 2, 2010 1:00 PM ET

Operator

Good morning ladies and gentlemen, thank you for standing by. Welcome to the Talisman Energy Inc. Q3 results conference call. (Operator Instructions.)

This call contains forward-looking information. Certain material factors and assumptions were applied in making the forecast and projections to be discussed in this call and actually results could differ materially from those anticipated by Talisman and described in the forward looking information. Please refer to the cautionary advisories in the November 2, 2010 news release in Talisman’s most recent annual information form which contain official information about the applicable risk factors and assumptions.

I would like to remind everyone that this conference call is being recorded on Tuesday, November 2nd at 11 am Mountain Time. I will not turn the conference over to Mr. John Manzoni. Please go ahead.

John Manzoni

Thank you Ron. Ladies and gentlemen, good morning and thank you for joining our Q3 conference call. As usual I’m joined here in Calgary by the management team who will be very happy to help answer your questions after Scott and I have run through the highlights of the quarter for you.

The quarter turned out very much as expected in terms of commodity prices; with gas prices in North America now reflecting the underlying fundamentals of very strong supply. We remain relatively cautious on North American gas prices for the remainder of this year and indeed into next year since it could take through next year for the market to rebalance. Gas prices today, we believe, are below marginal cost and therefore in the long term we do see them being slightly stronger.

Oil prices have also reflected more or less what we believed, which is basically underlying stability with a gentle upward pressure. The most recent move above $80 may not yet represent a sustained rally and could be impacted by economic sentiment as Q4 progresses. Although there does seem to be building evidence that demand continues to be robust even in OECD economies. But even if we do see a slight cooling, we think oil prices above $75 are well supported and will continue to have upward momentum over time.

We had quite a busy summer and I’ll outline a few highlights for you before turning to the financials. (Inaudible) of course, we made several acquisitions. We moved very quickly on these, used our balance sheet which had been strengthened over the last 12 months and targeted liquids rich opportunities.

First we made two relatively small acquisitions in Norway for a total of around $200 million dollars and bought into two licenses containing the (inaudible) discoveries. One of those deals was closed, the other is waiting on regulatory approval.

Next we purchased BP Columbia’s assets with (inaudible) patrol. This provides a fabulous under pitting to our explorations program in Columbia, which itself is looking very promising with several successful wells over the last few months. The transaction includes about $12,000 barrels of oil equivalent per day of production which we expect to grow over the next two years towards about 20,000 BOE a day and, of course, will establish a cash flow base for us in Columbia. We can now being to see a path towards a material business in Columbia.

And then recently we deepened our position in the (inaudible) in South Texas and at the same time created a joint venture with Stratoil including our existing landholdings in the play. That transaction both deepened our overall land position; so we now own about 70,000 net acres and enhanced the overall quality of the land in terms of liquid content.

Each of these transactions offers significant value going forward and strengthens our portfolio in line with strategy. And as I mentioned, they’re all liquids, which of course gives us more liquids options for capital deployment next year.

We also continued to execute our disposal program in North America, closing three small deals over the quarter and reaching agreement on a forth. I’ll explain the production for the quarter in a bit more detail for you in a moment. But it’s reflecting what I said last time we talked, which is under lying growth from the previous quarter is up about 4% on 2Q and about 12% on the prior year on a continuing operations basis. This gives us confidence to raise our guidance for the year to 415,000 barrels a day.

I think the fact that the production is now growing quarter on quarter is an important point in our portfolio transition. And of course an important contributor to the production goals is the Marcellus, which continues to move forward as we’ve promised. Today we’re producing about 270 million cubic feet a day and we’re confident to reiterate our outlook for the end of the year to be at the upper end of the 250 to 300 million cubic feet a day range we’ve held all year.

The continuing good results from these wells have also given us confidence to increase our EUR assumptions in the Marcellus, which will now move to 5 BCF a well from our previous assumption of three and a half BCF per well.

We’ve also initiated a process to look for a partner in the Ferrell Creek area of our (inaudible) asset. This is not focused on drilling to hold land since the lease terms are about ten years in the (inaudible) but we believe the overall value of the assets will be higher if we develop it with a partner since we have so much contingent resource in the area. We’re very pleased with the level of interest in the process and will progress the conversations over the next few months.

In terms of expiration, as always, some good news and some disappointments. Our more recent Peru well, called Runsastaffer (ph) which drilled a small structure in block 101 was not successful. Although we were carried for a large part of it. And we drilled one of the Halley Terraces in the North Sea which was also dry. But on the other hand, we’ve drilled two stratographic (ph) wells with our partner Pacific Rubiales in block six in Columbia, which have been very encouraging in terms of showing oil and are currently drilling a third. Of course we’ll have to test them, which will be done next year, but so far the signs are very encouraging.

And also in Columbia we drilled a structure in block nine, which has been successful in finding an oil-bearing formation in that block. So our exploration program in Columbia is looking very positive. In (inaudible) we’re testing the lower elligiscene (ph) in the block 44 well, but it’s a little early yet to assess the results.

So a very busy Q3 for us which has strengthened our portfolio in some key areas and builds more confidence for the future in terms of our objective of safe, profitable growth.

Turning now to the financials. Net income at $121 million dollars was down on the last quarter but up from a year ago. Prices and realizations were broadly similar to last quarter but the second quarter result was particularly helped by a number of positive factors going our way, including a particularly large gain on the North American assets we sold during the last quarter.

The result this quarter also included a higher DD&A charge which results from both increased production but also a drawdown of inventory during the quarter. Earnings from continuing operations, which as you know strips out most of the non-operating items was down this quarter at $22 million dollars. The DD&A I’ve just mentioned had an impact but the main difference between this quarter and the quarter a year ago was foreign exchange adjustments on working capital balances. These are not stripped out of the continuing operations result and impacted this quarter negatively by about $70 million dollars versus a year ago and by about $100 million dollars versus the second quarter.

Operating costs were held pretty flat against last quarter and against a year ago. Versus this time a year ago, the stronger Canadian dollar helped a little bit but since Q2 it went the other way.

Unit costs came down mainly because production increased. Cost pressures in the business generally are most acute here in North America where the service industry is relatively tight in the Marcellus and particularly tight in the Eagle Ford. But through our contacting strategies in both places, we think we can offset most of that pressure, all though we’re keeping a close eye on it.

Cash flow in this quarter was $727 million dollars, down from the last quarter and a year ago. Although realizations were up reflecting increased volumes and higher prices than a year ago, our hedges a year ago also realized about $150 million dollars which of course helped the cash flow. We also saw higher taxes this quarter, which Scott is going to explain in a moment.

Our cash capital expenditure year to date is about $2.8 billion dollars. You’ll recall last quarter I maintained our outlook at around $4.5 billion to $4.6 billion total capital expenditure. Which was actually the same activity set as we entered the year with although we’ve benefited from a substantial foreign exchange gain in Canadian dollar terms.

The $4.5 billion dollar figure includes the capitalized lease associated with the EMA platform in Norway, which I’ll talk about in a moment. But excluding that lease, the cash capital number I indicated last quarter is about $4.2 billion dollars.

I now think our cash capital outcome this year will be somewhere between $4 billion dollars and $4.2 billion dollars. A slight reduction in terms of actual spend versus our plan is not strategic; it’s just about what actually gets spent this year and what gets pushed into next. And we’ve seen this impact before. I’ll provide you more guidance for next year’s capital program early in the New Year, as we haven’t yet finished putting the program together. But we’re obviously thinking carefully about how to allocate spending in the current environment.

I should mention the EMA project which, as you know, has not been an easy project to bring to completion. The good news is that the wells that we predrilled for the project look good and we’re confident that the subsurface will work very well. We can also claim victory on the fact that the topsides are now sitting in (inaudible) ready to be towed out to location for commissioning. All that is good, but because we’ve been late, we’re now at the mercy of the weather. We need five days of good weather to get the top sides towed out and located. And at this time of year, we could be waiting a long time for those five clear days.

Following that, we need three months of commissioning work to first oil. Given that timeline, EMA will now certainly not be on stream this year. And whether it’s 1Q or 2Q next year will frankly depend on how long we have to wait to begin towing it out. We’re all set to go as soon as there’s a weather window, so it’s just a matter of waiting.

You will be reassured though that the projections I’ve been giving you consistently over the course of the last few quarters, including next year’s growth can accommodate a delay in EMA until mid-next year if we have to. Although I am hopeful that we will see progress before that.

Finally, let me say a word about production. Production for the quarter was 404,000 barrels a day less than last quarter as I signaled to you the last time we talked because of the shut downs in Q3 and the sales we made during the quarter. At our last call I reaffirmed my initial guidance that we would be a little over 400,000 barrels a day after sales this year. Q4 will produce in the UK as we bring on Burley and several planned shutdown activities come to an end. And I’m confident that the Marcellus will continue to perform strongly.

So now looking to the year as a whole, I think we can be confident in production being closer to 415,000 barrels a day after sales. That, of course, still excludes our Eagle Ford and Columbia acquisitions. Neither of which we expect to impact this current year.

This is a great performance given we expect to have sold somewhere between 15,000 and 20,000 barrels a day by the end of the year. Now I’m going to turn to Scott to give you a few more details.

L. Scott Thomson

Thanks John. I’ll review our financial results, balance sheet, acquisitions and disposals in Q3, our hedging position and say a few words about the adoption of IFRS.

Cash flow in the quarter was $727 million compared to $812 million in the immediately preceding quarter. With higher cash taxes and foreign exchange loses partially offset by higher production volumes. Cash flow of $838 million in Q3 of 2009 included approximately $150 million of hedging proceeds.

In Q3 we had foreign exchange losses which we not backed out of our non-GAAP earnings for continuing operations and also negatively impacted our cash flow from operations. In the quarter, the Norwegian krone and the Canadian dollar strengthened relative the US dollar by 10% and 3% respectively. This strengthening created a working capital foreign exchange loss in the quarter of approximately $60 million dollars.

We have exposure to currency fluctuations on a quarterly basis and do not usually highlight these movements on the quarterly call, but I thought this was worth mentioning because last quarter we actually experienced the exact opposite impact with a weakening Norwegian Krone and a weakening Canadian dollar, creating a $40 million dollar working capital foreign exchange gain.

As a result, when comparing Q2 with Q3, the impact of a hundred million dollars is quite large. As a consequence, earnings from continuing operations, which exclude certain non-operational items, were $22 million in the quarter compared to $137 million in the immediately preceding quarter.

Higher production volumes were offset by higher DD&A, higher taxes and the just mentioned foreign exchange loss. Earnings from continuing operations of $95 million in Q3 of 2009 included the $150 million of hedging proceeds referenced earlier.

Current income taxes were $235 million in the quarter, higher than both the immediately preceding quarter and Q3 of 2009 due principally to higher production in the high tax rate North Sea jurisdiction following the completion of turnaround. Through the first three quarters of the year, current income taxes were $631 million dollars. In the last quarterly call I indicated that current income taxes for the full year 2010 would come in at the top end of the $700 million to $850 million dollar range I gave at the start of the year. I now expect current taxes to modestly exceed the $850 million target because of Talisman’s higher production forecast, which incorporates better than expected production in Norway, lower capital expenditures in the North Sea relative to forecast and higher draw down of inventory relative to plan.

Year to date, exploration and development expenditure was $2.8 billion of which a little over $1 billion dollars was spent in Q3. The most significant expenditures in the quarter were they $517 million directed towards North American shale activity and the $282 million spent on development activity in the North Sea. A significant portion of which related to the off North and the EMA development.

Year to date capital expenditures of $2.8 billion exclude the acquisitions that I will discuss momentarily. As John noted, we do not believe full year capital expenditures will exceed $4.2 billion.

The closing of North American conventional asset sales contributed proceeds of approximately $350 million in the quarter. We anticipate closing one for the sale in Q4 for an additional $340 million dollars. By the end of the year, we’ll have received proceeds of approximately $2 billion dollars from our North American disposals.

As John noted, this was a busy quarter for acquisition activity. In August we announced an agreement to acquire a 49% interest in BP’s Columbian assets for consideration of approximately US $850 million and have painted a positive $613 million in connection with this transaction. The timing of the closing of the acquisition is subject to regulatory approval but we’re excited about the way in which the assets being acquired from BP will complement our existing Columbian business.

In October we announced an agreement with Stratoil where by we’ll partner together in the Eagle Ford (inaudible) in both our existing interest and in the acquisition of further liquid rich opportunities. As a result of this agreement, Talisman will increase its interest to approximately 70,000 net acres at a cost of approximately US $485 million dollars.

Lastly we have completed, or are close to completing two exploration license acquisitions in Norway for a combined cost of approximately $200 million dollars. At September 30th, we had $2.1 billion of cash on the balance sheet after paying the deposit in connection with the Columbia acquisition. Our net debt decreased from $2.1 billion at December 31st, 2009 to $1.6 billion at the end of the quarter reflecting year to date free cash flow of approximately $400 million which includes the proceeds from (inaudible) dispositions.

We continue to expect capital expenditures to exceed cash flow in Q4 of 2010 and will fund the capital program with cash on hand. In the last quarterly call, I indicated that our year-end tax position could exceed $1.5 billion dollars. However, clearly much has changed since then and should the BP Columbia and Eagle Ford transactions close in Q4, we are projecting a year-end cash balance somewhere in the range of $500 million dollars.

From an overall liquidity perspective, we have significant flexibility because we continue to be undrawn on our $2.8 billion dollar revolving credit facility.

Turning to our hedging program, we have hedged 75,000 barrels per day of oil in three different programs for the remainder of 2010. $25,000 barrels per day are hedged and (inaudible). 23,000 barrels per day and 55 by 85 collars and 27,000 in 50 by 60 collars. Approximately 60% of our 2010 production is oil linked and therefore we have significant upside exposure to higher oil prices.

For North American gas we have protected approximately 335 MMCF per day for the rest of 2010 through physical and financial hedges with approximately 95 MMCF per day in (inaudible) collars with a $6 floor and $7 ceiling and the majority of the remainder in (inaudible) collars with $6.20 floor and a $7.50 ceiling. After taking into consideration royalty payments, a significant proportion of our economic exposure throughout the rest of 2010 is hedged.

For 2011 we have hedged approximately 150 MMCF per day of gas at approximately (inaudible) to the first half of the year and 30,000 barrels per day of oil in 80 by 90 collars.

Finally, I’d like to make a comment concerning the IFRS disposure in our MD&A this quarter. It is important to note that the adoption of IFRS does not impact Talisman’s underlying economics cash generation characteristics or the company’s long term potential. While income may become more volatile in the future as a result of an increase in the use of fair value accounting under IFRS, the impact on our net income in our first two quarters of 2010 was insignificant when we round the numbers using the new accounting standard. The adjustments made in resetting the opening balance sheet arise from the application of a new set of rules, are mechanical in nature and will not impact future profitability and cash flows. We will run through all of the detail with you at the end of the Q1 next year, but we have basically flagged the impact of a new set of rules for you in the MD&A.

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

John Manzoni

Thank you Scott. So ladies and gentleman, a very active quarter in terms of transactions which have each strengthened a piece of our portfolio in line with strategy. The Q3 production reflects the start of a new phase for the company because it shows growth from the last quarter in continuing operations and we can look forward to that trend continuing from here. We have options in turns of capital allocations into next year and we’ll finalize that over the next couple of months.

We’ve increased our production guidance a bit for the end of this year and I’m very confident we can maintain our momentum of safe profitable growth into next year.

So now ladies and gentleman we’ve talked enough and now I think it’s over to you for any questions you may have which we’ll be happy to answer.

Question-and-Answer Session

Operator

Thank you. Ladies and gentleman, we’ll not conduct the question and answer session. (Operator Instructions). Your first question comes from Greg Pardy from RBC Capital Markets. Please go ahead.

Greg Pardy – RBC Capital Markets Toronto

Hi, good morning. I wanted to dig in a little bit more into the Marcellus. John, you mentioned that you boosted EURs to 5 Bcfe per well, could you talk maybe just a little bit about what you’re seeing in IP rates and then just based upon the well count and what you’ve tied in thus far. I mean you certainly already achieved your objectives, but would you still be on track to tie in 147 wells this year or will some of those extend into next year?

John Manzoni

Greg, thank you for your question. Let me ask Paul to talk a little about AVIP rate via the number of wells. Let me make on comment just in overview to start. You’re pushing on the Marcellus. I think in some senses, you know, we’re signaling actually in the light of current environment. We’re not pushing as fast as we have stated that we’ve been our original target at the beginning of the year. So Paul is going to describe a little bit of an easing off of that in terms of the number of wells completed during the course of the year.

Paul Smith

Okay, Greg, let me start with the IPs which go along with the increase in the EURs which you signaled from three and a half to five. We’ve at the same time increased our IP assumptions from three, which we’ve been signaling for most of this year to four. I’d like to say that both are still on the right end of where we should be, i.e. behind where the actually performance in the rocks is showing us to be this year.

In terms of your question around wells completed this year, you’re absolutely right and John sort of provided the context. We said at the beginning of this year that we would complete and bring on to production (inaudible) or 145 wells this year. I can now say we expect that to be closer to 105 to 110 net wells online this year. And that’s mainly the result of drilling much longer wells this year. And many more stages than we’d originally planned. We had planned this year for most of our wells to be eight stage average. We actually, this year, deliver twelve average stages with wells ranging from 18 to 16 stages but longer and more stages is kind of the key and that’s clearly as we continue to look to drive productivity into the Marcellus.

As John has also said, you know, as were sitting here today we’re producing circa 270 million standard cubic feet a day and we’ve brought 90 wells online as of this morning. And so we expect another 15 to 20 to come online between now and the end of the year. So one of the questions you may ask is why so few in the last two months of this year. Two reasons for that. Firstly, as you know, we’re exclusively pad drilling in the Marcellus and so there’s, just by the nature of the program, actually quite a lot of carryover from Q4 into Q1 next year. And just as importantly, we are actually starting to slow down activity in the Marcellus in anticipation of reducing our rig and well count in 2011 which we’ll speak more about when we speak to you in January with our update.

Greg Pardy – RBC Capital Markets Toronto

Thank you Paul.

John Manzoni

Greg, does that answer your question?

Greg Pardy – RBC Capital Markets Toronto

Oh it does, yeah it does. Thanks very much.

John Manzoni

Great, thank you.

Paul Smith

By the way just to reiterate the target that we set of course in light of all of those things we aforementioned.

John Manzoni

Yes, the target remains unchanged. 250 to 300 and confidant we’ll end up at the upper end of that range, Greg.

Operator

Your next question comes from Brian Singer from Goldman Sachs. Please go ahead.

Brian Singer – Goldman Sachs New York

Thank you. Good morning.

John Manzoni

Brian, good morning.

Brian Singer – Goldman Sachs New York

Following up a little bit on that to the extent that you do move a bit more slowly in terms of the recount in the Marcellus, can you talk about where capital and other wise what has been spent there would be deployed to, does that go into ramping up the Eagle Ford specifically? Does that go into new North American plays? Does that go into the exploration portfolio internationally?

John Manzoni

Brian, maybe I’ll do that in the general sense. The answer to your questions, certainly outside of North America, the capital programs are in some sense more fixed. They’re more programmed, they’re more sort of steady and therefore we can see those programs clearly for some way in advance. So the optionality essentially as you suggested is either in the exploration program or in North America.

We’ve set and we remain consistent in about $700 million dollars per year of expiration expenditure and that won’t change into next year. The flexibility there for lies between the gas shales and the liquid shales and activities going on in North America. So, essentially what will happen if the environment remains constant as it is today, we will be looking to move, to the extent that it’s feasible and sensible in an operational sense, we’d be looking to emphasize the liquids options that we have and de-emphasize the dry gas options that we have.

In addition to that we’ve of course made some acquisitions which are also liquids focused in Columbia in particular, which will draw some capital into next year. So there’s our sort of overview of where we’re headed and as I said, we’ll tell you all about that probably in early January as we finalize our plan. But that’s directionally where we’re going.

And I suppose the overview comment is in the current environment. I think we’re probably on the side of more disciplined rather than less disciplined, you know, overall. And I’ve described the allocation biases for you. Does that help?

Brian Singer – Goldman Sachs New York

That does. Thanks. And as a bit of a follow up to the extent that you do find a partner to provide some capital in the (inaudible) and also given the comments he just made, would you look to do additional acquisitions to build your oil shale or liquid shale position in North American or do you feel that, and maybe this includes South American as well with the Columbia piece and the Eagle Ford piece that you’re there.

John Manzoni

I don’t think I’ll start the changes in terms of acquisitions. We’ve always said we look at everything, we will act if we believe there is value to be achieved, but acquisitions will only be in the context of our existing strategic positioning. In other words, it will be in North America, it will be in Asia or it will be behind the exploration drill bit.

So I think that that stance continues consistent. We did act in those ways over the summer and to the extent that there are other opportunities and we feel it’s the right thing to do, you know, we’re always on the lookout.

Brian Singer – Goldman Sachs New York

Great, thank you.

Operator

Your next question comes from Mark Polak from Scotia Capital. Please go ahead.

Mark Polak – Scotia Capital Markets Calgary

Good morning.

Operator

Mr. Polak your line is fully interactive.

Mark Polak – Scotia Capital Markets Calgary

Sorry about that. Question for you on the increased gas production at Corridor. I believe the extent of the Sudan plant back in the six to $700 million a day, I just wanted to confirm that’s sort of the number you’re running at or above right now. And is this testing it at above those levels sort of part of the decision making process? I think you were looking at expanding it to 1.1 Bcf a day down the road?

John Manzoni

Thank you mark. So let me just ask Paul to describe what’s happening in Sudan and whether we’re going to expand some more.

Paul Smith

Sure, thanks. Thanks Mark. The story really around Corridor is the reservoir has capability to deliver more gas than the facilities right now and so we have been looking at an expansion project of existing facilities as well as the potential for further expansion beyond that.

The current project that we’ve been engaged in, as you actually suggested the first was to test existing facilities above what we’ll call name plate rates and Sudan’s specifically has been flowing for extended periods at above 750 million cubic feet a day. Our preference is to run that plant at around 700. Certainly the market is strong and there’s no difficulty there and that’s continuing today. And we’ll look to expand overall corridor facilities currently around 1 Bcf a day to about 1.1 through existing de-bottlenecking projects.

Mark Polak – Scotia Capital Markets Calgary

Very helpful, thank you. And another one from me is in Columbia; I saw you guys had done a small deal with Petro America. In a very small, is that just sort of rationalizing assets there? Are you looking so we can expect to see further deals down there or what was the strategy behind that deal?

John Manzoni

Thanks Mark. Let me ask Richard who’s looking after our exploration program in Columbia, both the ups and downs and that to talk about Petro America.

Richard Herbert

Yeah, the Petro America deal is a fairly small deal. We’ve obviously built quite a big portfolio in Columbia. Now we’re in 14 exploration blocks as Talisman and of course we’ve got the BP Columbia deal which will bring an additional five blocks.

The four blocks that we’re involved in this deal are relatively small blocks with limited prospectivity that hit a sort of non-material play in the fall. And for us this was just a little bit of tidying up. We remain in the blocks with the 25% interest but we’re being carried on a lot of activity.

Mark Polak – Scotia Capital Markets Calgary

Great. Thank you very much.

John Manzoni

Thank you Mark.

Operator

Your next question comes from George Toriola from UBS. Please go ahead.

George Toriola – UBS Securities Canada Calgary

Thanks. Two questions here; the first is on the (inaudible), could you talk to what you’re seeing in terms of well productivity there to the extent that that’s much in the type (inaudible) from (inaudible). And just looking at your, I mean because this is the lines that you’ve had for a while, wondering, I mean that’s where I would imagine that your cost of ownership is relatively low, so wondering why those are the assets that you want to attract third party capital on.

John Manzoni

George, let me see if I’ve got your questions right. The first is how is the drilling doing with regards to in Farrell Creek and into Montney with regard to assumptions. And the second is, I think if I’ve understood it, why would we be joint venturing in a part of the land where the cost of ownership was low. Did I get the second one right?

George Toriola – UBS Securities Canada Calgary

That’s right John.

John Manzoni

Okay, so let me just turn to Paul and see if we can get Paul Smith to give you an answer on those.

Paul Smith

Okay, thank you George. In the Montney we’re active in two areas, as you know, this year in early development in Farrell Creek where we’ve had four rigs up and running and we said we would bring on stream this year, drill 25 and bring on stream about 15 wells. So far we’ve brought six wells online that are flowing. Crucially we are targeting not just the upper Montney, which is where last year’s program was focused, but we’re targeting both the lower Montney and the doigs. So all three zones of the Montney are being targeted this year. The good news is that we’re seeing extremely strong results underpinning last year’s wells in the wells that have been brought on in all three of these formations now this year in Farrell and indeed we have- are in the process of upgrading our EURs in the Montney to seven Bcf which again is underpinned with everything that we see this year and from the wells last year. And IPs 30 day IPs are about five and a half.

So we’re seeing very, very strong results. And the secondary which is in the greater Cyprus area, which is more in pilot mode this year. We’ve brought online nine wells to date and we’ve got three more to bring on in the remainder of this year and I can again say that we’ve seen very, very similar encouraging results to what we’ve seen in Farrell; the rocks are very similar and again, all three zones are working. So we continue to be encouraged by the Montney.

And the final piece before I answer your second question is that last week we expanded and brought online our expanded Farrell creek facility which takes our capacity in the area to 120 million standard cubic feet a day. And that gives us the confidence to reconfirm that we will exit the sharitt 40 million to 60 million standard cubic feet a day from the Montney.

In terms of why look to JV, we’ve announced that we’re in a process to look for a strategic partner for the Farrell Creek position, a 40% to 50% strategic partner. Farrell creek is about 9 tcf of a 44 tcf resource base that we have. So it represents a fairly modest part of our overall Montney position and we continue to believe that doing this on our own would be a $35 billion to $45 billion dollar capital program. It’s probably not the way to go and we believe that we can enhance value by accelerating the development of the area by bringing in the strategic partner which in the process of doing for Farrell Creek.

George Toriola – UBS Securities Canada Calgary

Okay, thanks a lot. Then just to confirm the EURs as you talked about from the three zones, they are collectively.

John Manzoni

We’re seeing similar results in all three of the zones and we’re raising our EURs to 7 Bcf for all three zones and IPs to five and a half.

George Toriola – UBS Securities Canada Calgary

Okay, thanks a lot.

Operator

Your next question comes from Andrew Potter from CIBC. Please go ahead.

Andrew Potter – CIBC World Markets Calgary

Yeah, hi guys. I was wondering if you can get a little bit more color on the Eagle Ford and then the plans going into 2011 in terms of the rig count. I guess what I’m getting at is you say four rigs going into the year but could this be a similar progression as we saw in the Marcellus where you very quickly run up to ten rigs or something of that magnitude?

And second question, as you guys and everybody else in the industry seems to double down on liquids rich gas, maybe you can provide us some thoughts in terms of how you’re thinking about NGL pricing going forward.

John Manzoni

In a general sense, let me deal with it first and maybe, you know, we haven’t yet finalized plans for the Eagle Ford or for anything else next year and that’s why I’m really just saying to you that we’ll tell you all about that in January when we tell you the guidance.

Answer is, as you say, we’ll exit the year with four and the direction; we’ll be looking to increase that. But the final values of that I think are probably something that we can define for you in much more detail in January.

I suppose the- in a general sense, NGL’s pricing, obviously there’s some concern. Lots of NGL’s come into the market place. NGL pricing will reduce. Of course there’s a flaw in that because it essentially the ethane can be kept in the gas and the BTU equivalent in the gas essentially represents a flaw. The rest of the NGL components look all very strong and aren’t in oversupply.

So the floor, except by the ethane base on the BTU equivalence; point one. Point two; if you’re going to have NGL, frankly, you might as well have them in the Eagle Ford because that part of the country is still NGL short so the price, essentially, is being set by imported NGL from somewhere else.

So I think our assumptions are, if I could say, typically conservative in our forward planning on NGL pricing but we’re not unduly concerned given A- that we’ve planned on that basis and B- the fact is that I’ve described. Does that help?

Andrew Potter – CIBC World Markets Calgary

Yeah that does, that’s perfect. Thanks a lot guys.

Operator

Your next question comes from John Herrlin from Societe Generale. Please go ahead.

John Herrlin – Societe Generale

Yeah, hi. Some quick ones. It didn’t sound like you have that many lease expiration issues upcoming in the Marcellus (inaudible), how about the Eagle Ford?

John Manzoni

John, let me ask Paul Smith to talk about Eagle Ford expiration and maybe Marcellus expiration.

Paul Smith

Yeah, good. Well let me start with the Eagle Ford. We, in one of the attractive components of the enduring transition that we expect to close by the end of this year is that of the 97,000 acres, about 50% is already held by production through conventional production in the Austin Shore (ph) so that puts us on a very manageable expiry profile in the Eagle Ford going forward with only, it’s like 50% of the acreage under the gun, so to speak. But you know, two to three year expiry and actually quite a lot of the acreage have expansion options, or extension options I should say, on top of that. So I think we remain very much in control of our destiny purposely so in the Eagle Ford.

And the Marcellus, we’ve continued to day we’ve built a portfolio there when we doubled down last year in the Marcellus and had new three to five year leases. Again we continue to be very much in control of the pace at which we have land expiry not being an issue for us. We don’t expect any land in the Pennsylvania side of the Marcellus to walk away from us next year or at any time going forward.

John Manzoni

Did that answer your question John?

John Herrlin – Societe Generale

Yes it does. A couple more; got to ask the IFRS question since nobody else did. It looks like you’re getting a 12%…

John Manzoni

(Inaudible)

John Herrlin – Societe Generale

It looks like you’re going to have about a 12% PP&E hit, I was wondering whether you could specify geographically if some areas were more prone to these charges than other and also since your successful efforts, how come it was so high on a percentage basis? You said it was mechanical, I haven’t seen that IFRS methodology.

L. Scott Thomson

John, so a couple things. If you look at the impact of IFRS; one, again it’s not going to impact the cash flow characteristics confirmed so the non-GAAP cash flow as we go into the 2011 will be the same and in fact on the net income will actually increase slightly. I think we said, in the MD&A about a $200 million dollar impact or increase from that income.

From the balance sheet, I think what you’re talking to is the net book value reduction of $1.7 billion dollars. And let me just walk you through that. So, one, $250 million of that is related to moving to a new methodology under IFRS for valuing share based payment. So moving to the black shales methodology that I think probably everyone will have that issue.

Second is a change in the tax treatment for acquisition which resulted in another $100 million dollar impact. And then third, there’s a $100 million dollar impact associated with the change in accounting for ARO. $1.2 billion dollars is associated with the change in methodology for determining the book value of the assets. Of that $1.2 billion dollar impact, approximately $400 million dollars is associated with assets that have already been sold during the year in our North American conventional disposition program.

So there’s about $800 million dollars associated with other assets and, you’re right, there’s primarily, there’s two assets primarily which we’re not going to highlight here, but one’s in the UK and one’s an expiration asset. So not broad-based defined to two assets in particular.

John Herrlin – Societe Generale

Okay, great. Next one for me is on Columbia. You know Columbia got a lot of high light way back when when BP drilled Cusiana Cupiagua with Triton, structurally, can you kind of generalize about your prospect types? I mean are these bids that are up on end like Cusiana was or are they just normal over thrust type structures? Just curios.

John Manzoni

John, you and I interacted as I recall when BP and Triton were doing those as well.

John Herrlin – Societe Generale

Yes.

John Manzoni

Let me tell Richard to describe the different plays that we’re in in Columbia and how they play in the different parts.

John Herrlin – Societe Generale

Thanks.

Richard Herbert

So John, yeah, you make reference at Cusiana and Cupiagua which are two large fields that sit in the over thrust trend as it’s called at the fronts of the mountains. And that is sort of one of our principal plays in Columbia. We were already involved in a bloc called Nuscata (ph), which lies just north of Cupiagua. Talisman has an interest in that bloc, so we’ve now, with the BP acquisition tied up quite a large part of that trend. And you’re right – that’s an area of fairly complicated geology where the beds are actually squeezed and overthrust so that we actually can build some very large hydrocarbon columns and some quite large pools. So that’s one of our principal areas of focus in Columbia. The other area of focus is on the edge of the basin in a rather shallow play in what is called the heavy oil trend. This is heavy oil but it’s not particularly viscous oil, and this is the one that of course is being produced now in the Rubiaditz (ph) field, and we have expression acreage around that field. So those are our two areas of focus in Columbia.

John Herrlin – Societe Generale

Great, thank you very much.

John Manzoni

Thank you, John.

Operator

Your next question comes from Andrew Fairbanks from Bank of America. Please go ahead.

Andrew Fairbanks – Bank of America

Hey, good morning, John. Just another question on Columbia actually. Since you’ve had a lot of activity there I wanted to see what your thoughts were on the scale that Columbia and/or Peru could grow to. Would 20,000 barrels a day be a material position, or is your ambition for something larger?

John Manzoni

Thank you, Andrew. We’ve always said, you know, that in order to be material in our sense we’re looking for 50,000 barrels a day plus out of a region. And I think what we’re seeing now through the combination of acquiring some existing production and the exploration program that Richard’s described in Columbia and also our activities in Peru, we’re now seeing, hence my comment that we can now see a region if you like which we believe has the potential to deliver 50,000 barrels a day plus for Talisman between Columbia and Peru. So that’s our current context, Andrew, and that’s what we’re building toward.

Andrew Fairbanks – Bank of America

And are there a couple of exploration wells you would highlight to people to watch for over the next six months or so in the two regions?

John Manzoni

So, for that I’m looking directly at Richard Herbert to see if there are a couple of things that he gets particularly excited about. So perhaps you could describe a bit of what’s going on, Richard.

Richard Herbert

Well, yes. I mean Andrew, we’re getting quite active in the region now. Starting with Peru, next year we will drill another exploration well in the Situcci (ph) area. You’ll recall we have a discovery there on a structure called Situcci Centrale (ph). We’re going to drill the northern culmination on that trend next year, which is a very interesting prospect adjacent to our discovery. So that’s one to look out for. I think in Columbia, as I think you’re probably aware and John made reference to this, we’re drilling some stratographic wells in our heavy oil bloc six in the Yanos (ph) Basin and that program is going to continue through the rest of this year. We’re drilling six wells in total, and next year, given the encouragement we’re having we’ll be moving to sort of full rig operations so we can test some of these wells. And we’ll also be drilling an appraisal well on our Huron discovery in the overthrust trend during next year as well. So those are the main ones to look out for.

Andrew Fairbanks – Bank of America

That’s excellent, thank you.

John Manzoni

There’s quite a lot going on there, Andrew.

Operator

Your next question comes from Brian Dutton of Credit Suisse. Please go ahead.

Brian Dutton – Credit Suisse

Yes, hi, John. Your strategy’s been focused here on profitable growth and part driven by your transitioning of your North American business from the conventional to the unconventional asset base. So at the outset there of the questions and the call you talked about the well count, the EURs on the growth side of the strategy in the Marcellus. But could you also maybe talk a little bit about the profitability side and what you’re seeing happening in operating costs and F&D costs in 2010?

John Manzoni

Sure, thank you, Brian. Let me, so I’ll ask in a minute Paul Smith to give you a bit of color on all the stuff that’s going on inside North America, but in the general sense you’ll recall we delivered last year a significant reduction in our F&D costs, which of course in terms of total replacement costs, if you can bring those down the profitability in the long run will improve. I mean there’s just no question about that. So we’ve delivered that in the course of last year and I remain confident that we will deliver also what we have said in terms of F&D continuing reductions during the course of this year, both in terms of total F&D and what we might call PDP F&D – drill bit F&D costs. Both of those two things will continue to decline both this year and we believe into the future. So these, in a macro sense, are bringing the replacement costs of the firm down substantially and materially and in a sustainable way. And that, if you like, is the main overall driver of improving profitability into the future. You’ve seen operating costs. The problem with operating costs is it sort of goes up and down in a quarter. This quarter for instance we had some G&A one off costs as we’ve opened some offices in North America and in Australia and places. So the trouble with looking at those quarter to quarter is that there tends to be quite a lot of noise in them. But in the general sense, our operating costs and our D&C costs as we progress into the unconventional activity, are on that steady downward track. Certainly our projected break evens in economics do reflect that steady downward track, but we’re seeing very good evidence of that. So maybe Paul can give you a couple of examples of the sort of reductions we’re seeing or the confidence that we have in a continued track. Paul Smith?

Paul Smith

Yeah, good. So let me, I think as a whole in NAO we’re going to see F&D costs this year come down below $10 a barrel and on its way down clearly as we substitute in shale growth for conventional production. In the Marcellus, to use that as an example, within the portfolio the F&D that we expect to see this year in the Marcellus is going to be roughly $8 a barrel. We’ve sort of signaled that this is consistent with the numbers we’ve told you before. Well costs are not coming down as fast in terms of this because we’re drilling longer, with more completions, but we are seeing efficiencies per stage coming down. And we expect to see 15% to 20% improvement this year in the CAPEX costs for drilling our wells in the Marcellus. On the operating costs side, clearly the shale business has a significantly lower cost base than the conventional business, just by the nature of the kit that’s required for shale relative to the conventional business, and this year our operating cost per barrel, last year we were just over $10 and this year they should be closer to $9 in North America. And that’s again mainly as a result of the substitution effect of low-cost shale substituting for higher cost conventional production.

John Manzoni

Does that answer your question Brian?

Brian Dutton – Credit Suisse

Yes, thank you.

Operator

Your next question comes from Minu Hulsa from TE Securities. Please go ahead.

Minu Hulsa – TE Securities

Hi, good morning, gentlemen. I have a two part question on P&G. First I was wondering if you could give us some idea of the size of the program for the coming year, and second whether you’ve made any progress in terms of attracting potential strategic partners to ultimately bring that gas to market.

John Manzoni

Thank you. First I’m going to hold the next year question just as I have previously. I mean I’ll look to Paul to describe in general terms what we’re going to do next year, but in terms of the actual numbers I think if you don’t mind we’ll wait until we give you some more detailed guidance in January. And also, Paul, perhaps some comment about where we are in P&G, what our objectives are and a bit of an update.

Paul Smith

Sure, thanks a lot. Actually I was there very recently with Richard. It’s a pretty exciting time. We saw the kickoff of a large seismic program and also construction on two rig sites, where by the end of this year we’ll be participating in two exploration wells. So that’s really the start of the program in P&G for us. And that program will continue into next year, and as John suggests we’ll lay out more details around what that looks like in due course. And the other part of your question around strategic partnering for development solutions, those studies and ongoing work with a number of partners continues, and as we drill through the exploration program next year we’ll start to think about the right development solutions for parts or for the whole of our business.

Minu Hulsa – TE Securities

Terrific, thank you.

John Manzoni

Very good.

Operator

Your next question comes from Mike Dunn from FirstEnergy Capital. Please go ahead.

Mike Dunn – FirstEnergy Capital

Good morning, gentlemen. In your press release you mentioned that had completed two wells in Quebec in the quarter, and I believe one of them was the Chantilly well that I think your partner press released on in September. I think the other one might have been LeClerkville (ph) – just wondering if you’ve tested that and if you’re able to discuss any results.

John Manzoni

I think the simple answer to the second piece is no, but let me first turn to Paul Smith about whether or not we’re going to talk about the second well, LeClerkville (ph).

Paul Smith

Yeah. So Mike, I mean the general context firstly for an answer to your question, we said we would drill and complete five wells this year. We’ve drilled five and we’ve completed three now, and we’ve taken a proactive decision based on market and supply dynamics in particular for stimulation crews to defer the completion of the final two wells into the first half of next year. John’s right – the third well, the LeClerkville well has been completed, it has been tested. But it’s a tight hole and we don’t release individual well results.

Mike Dunn – FirstEnergy Capital

Okay, great. Thanks, guys.

John Manzoni

Thank you, Mike.

Operator

(Operator Instructions.) One moment please. Your next question comes from Scott Haggett of Reuters. Please go ahead.

Scott Haggett – Reuters

Hi. I’m wondering if you can give us a bit of an update on Kurdistan. When do you expect to see production there, and your outlook for a revenue sharing agreement?

John Manzoni

Scott, production from Kurdistan, that’s a- So let me just see if I can turn to Paul Blakeley who can give you a little update on where we are in Kurdistan.

Paul Blakeley

So activity in Kurdistan, I mean we continue to drill on the Kurdame (ph) well in bloc K-44, and that well is now in the testing phase but too early to give any indications at this stage. And after this well is complete we’ll move to bloc K-39 where we’ve elected to take that activity to the next stage and to drill a well there. That well with spud sometime early next year and thereafter we’ll take stock of those results.

Scott Haggett – Reuters

Let me, just to return any sense on when we’ll see an agreement between Kurdistan and Baghdad?

John Manzoni

I think, Scott, we’ve always held in Iraq that, we’ve always said that export from Kurdistan will require political accommodations in Baghdad and (inaudible). We’ve always felt that that would move toward constructive political accommodation in due course but it would be a winding road. I think we’re seeing that winding road. We’re still on it; we still remain confident and optimist that that can and will happen over time. And I think frankly, I think we just hold that optimistic view. The key for us in Kurdistan is not to be committing too much risked capital into that environment ahead of the political process. So that provided we can hold this as an option for us, a long-term option- It’s a super place to find hydrocarbons, and the question is provided we’re not over-committing capital then it’s a great place for us as a long-term option. And that I think continues to be our position and you will know as much as anybody else on the call about the political environment as it moves toward that accommodation that we hope will come about in due course.

Scott Haggett – Reuters

Great, thank you.

Operator

Your next question comes from Palo Rasvel from Veritas Investment Research. Please go ahead.

Palo Rasvel – Veritas Investment Research

Good morning. Just a question on the shale. Given some of the changes in your assumptions, I’m wondering if you have any updates on the supply costs for the Marcellus as well as for the Eagleford.

John Manzoni

Do you mean the service costs, Palo, or are you talking about the break even?

Palo Rasvel – Veritas Investment Research

The break even supply costs that you typically supply in the presentations.

John Manzoni

Sure. So let me just see if, I mean we’re still in a $4 break even full cycle cost area. We certainly haven’t made any detailed adjustments in the like of EURs and IPs and such things. Let me turn to Paul just to give you a little bit more flavor on that in a general sense.

Paul Smith

Yes. So I think in general the Marcellus continues through the improvements that we’re seeing to be well on its way to delivering the $4 or less break even, which is where we want the Marcellus to be. We believe it’s the best dry gas play in North America and we believe we’re in the best part of that play. The (inaudible), we’re confident we’re starting to see signals and signs that it has all of the characteristics. It’s 12 months behind the Marcellus but has all of the characteristics that it will be a $4 break even play in the not too distant future. And then in the Eagleford, the dynamics are clearly different with today a very large differential between gas and liquid prices, and so the break even in the Eagleford today, should those differentials be maintained, is also going to be well within that $4 an MCF break even. And those are all full cycle numbers as we always talk about.

Palo Rasvel – Veritas Investment Research

So with the gas price currently slightly below that break even number, what kind of gas price would make you ratchet down your activity even more, and what kind of gas price maybe would make you ratchet the activity back up?

John Manzoni

Let me see if I can give you a bit of our perspective. I mean the first comment is we won’t be drilling uneconomic wells. Second comment is we actually have flexibility, which I think is a nice play to be of course. We have flexibility to move capital around. As Paul indicated, the Eagleford looks better because of the liquids component and that’s contributed to a much lower break even. And third comment is that today in the Marcellus, the wells that we’re drilling are making money. So we have all of those choices before us and obviously as the price continues to go down we will continue to respond in terms of our capital allocation. And that’s in fact of course what we’re doing between now and the end of the year as we set next year’s activity base, which is why I’m signaling sort of dry shale gas capital activity down, liquid shale gas capital activity up. The exact extent of that is of course a balance between economic factors but you can’t just flip a switch, you know, because you’ve got operational considerations. And that’s the judgment that we’ve got to make but I think directionally that’s where we’re headed.

Palo Rasvel – Veritas Investment Research

Thank you.

Operator

Your next question comes from Shawn Polster from Calgary Herald. Please go ahead.

Scott Polster – Calgary Herald

Thanks for taking my question. I’m just wondering what the threshold is for the number of wells you have to drill in a play like the Marcellus to actually maintain the production and keep it up now that you’ve built it up to a fairly substantial level.

John Manzoni

Yeah. I mean it depends on where you want to put it, Shawn, it depends on what level you want to have it at, of course; and if you’re in a growth mode or a steady state mode and what you choose to do. Paul, do you want to see if you can shed some light on that?

Paul Smith

Yeah. We don’t spend a lot of time focusing in on the amount of wells to plateau the Marcellus today. I think we spend a lot of time sort of focusing in on firstly the flexibility to make sure that we don’t lose land and we’ve talked about that already today. And clearly with the position that we’ve got in the Marcellus with roughly 230,000 net acres, we’ve always said it’s a business that will ultimately support a BCF a day. The pace at which we build to a BCF a day is clearly going to be a function of the external environment, and as John as already clearly signaled on this call, given the current environment that we see this year and the equally challenging environment that we foresee for next year, we’re clearly going to make some choices. And one of the choices we’ve signaled here today is we will be slowing down from where we are today in the Marcellus and looking to reallocate some of that capital towards liquid based production around the Talisman organization.

Scott Polster – Calgary Herald

That was kind of the gist of the question. I was just wondering if you’re scaling back your drilling in that particular play if there’s a point where declines kick in and maybe the production actually starts to fall?

Paul Smith

Well, it would be eventually but we won’t be getting to that place next year, where production goes below where it is this year.

John Manzoni

Yeah, I think the possibilities of decline in the Marcellus we’re not contemplating, Shawn, if that’s any help.

Paul Smith

Okay. Thank you.

Operator

Your next question comes from Cam Sandhar from Peters & Company. Please go ahead.

Cam Sandhar – Peters & Company

Hi. I have three questions. First of all, just wondering if you could give us an update on what you’re all in well costs are looking like in the Mountnie at Ferrell Creek (ph), and second question is just on a high level update on what you’re expecting to do with respect to dispositions in 2011, if it’s going to be to the same scale or size that you’ve been doing in 2010. And then the last question is you’ve obviously signaled some changes in terms of capital allocation for 2011; I’m wondering if you could talk about it at a high level, what sort of implications that might have on your longer-term growth targets of 5% to 10%.

John Manzoni

Let me do them if I may, Cam, in reverse order. First capital allocation in 2011, and the impact on the 5% and 10% growth rates, I think the answer is very little to zero. It won’t change the growth rates. We’ve held- I think a 5% to 10% growth rate is a very sustainable growth to this company and I think we can manage that almost regardless of what we do as I said in my remarks. It won’t have a big impact on next year’s growth rate or in fact the long-term growth rate. Dispositions in 2011 at the macro level, we’ve largely completed $5 billion of dispositions in the last couple of years. We’re in the main through that sort of program or at least through that sort of scale. We’re always looking at parts of our portfolio to high grade and to continue to churn to improve the quality, and that will continue. So while there are no specific plans in 2011, the process of continuously looking to high grade the portfolio will continue and so therefore there may well be activities that we undertake in the market in terms of dispositions, but we don’t have any firm plans today. And they’re just continuously under evaluation. But I think the bulk of our transition, if you like, which is largely focused on North America, but out of conventional and into unconventional, we’ve seen the bulk of that through the course of this year and last year. So it won’t be a program of the same magnitude into next year. And finally your first question which is all in well costs at Ferrell Creek, let me turn to Paul Smith to give you the answer.

Paul Smith

Yeah, Cam, I’ll answer it in terms of general. The Mountnie is 12 to 18 months behind the Marcellus. We continue to see the same sort of improvements that we saw last year in the Marcellus in terms of drilling costs coming down significantly as we apply the leanings that we have made in the Marcellus to our Mountnie operations. Our pace setter well in the Mountaine is sort of just below $4 million. We’re certainly not done at that level – that’s drilling costs – and continue to experiment with the application of all of the learnings from the Marcellus. And we fully expect to see further improvements as we complete this year’s program and as we continue into next year with our planned drilling program.

Cam Sandhar – Peters & Company

Okay, thanks.

John Manzoni

Thank you, Cam.

Operator

Mr. Manzoni, there’s no further questions. Please continue.

John Manzoni

Ladies and gentlemen, thank you for listening to our conference call and thank you for your questions. And I think with that, given that there are no further questions, we’ll sign off and look forward to talking with you again in the next quarter. So thank you very much again for joining. Thank you.

Operator

Ladies and gentlemen, this concludes the conference call for today. Thank you for participating; please disconnect your line.

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