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Talisman Energy (NYSE:TLM)

Q2 2010 Earnings Call

July 27, 2010 11:00 am ET

Executives

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

Richard Herbert - Executive Vice President of Exploration

Paul Smith - Executive Vice-President of North American Operations

Nicholas Walker - Executive Vice President of International Operations - West

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

Analysts

Brian Singer - Goldman Sachs Group Inc.

Greg Pardy - RBC Capital Markets Corporation

Mark Polak - Scotia Capital Inc.

Paul Andriessen

Markus Ermisch - Calgary Sun

George Toriola - UBS Investment Bank

Michael P. Dunn - FirstEnergy Capital Corp.

Christopher Theal - Macquarie Research

John Herrlin - Merrill Lynch

Carrie Tait - National Post

Andrew Potter

Operator

Good morning, ladies and gentlemen. Thank you for standing. Welcome to Talisman Energy Inc. Second 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 July 27, 2010, news release and Talisman's most recent annual information form, which contains additional information about the applicable risk factors and assumptions. [Operator Instructions] I will now turn the conference over to Mr. John Manzoni. Please go ahead.

John Manzoni

Thank you very much, Ron. Ladies and gentlemen, good morning, and thank you for joining our second quarter conference call. I'm joined here in Calgary as usual by the management team, and after Scott Thomson and I have run through the results for you, we will be happy to help answer your questions.

In terms of commodity prices, I think the year's turning out pretty much as we've expected and perhaps even a little stronger in terms of gas price. Oil prices look to be trading at a relatively stable band around $75, which is, I think, fairly well supported. Prices lately seemed to be influenced as much by the general appetite for risk as the fundamentals of supply and demand, but there is broad consensus that global demand will remain robust over the second half and into next year. Future direction of non-OpEx supply will likely have some influences on prices in the medium-term, but we continue to believe that the oil price at current levels look secure, and in fact, has gentle upward pressure.

North American gas prices have been slightly stronger than we thought they might be, robust industrial demand, coal substitution and some recent hot weather seem to have supported prices in the $4 to $5 range. But we remain cautious in our short-term outlook here since supply in North America continues to be very strong. I think there remains potential at least, for the fundamentals to erode price levels a bit from here in the second half of the year with weather, of course, also being an important factor as always.

We're well-positioned if the gas prices do weaken a little from here. And I would say in a stronger position now than we were even in the first quarter, with a very strong balance sheet, flexibility in our capital programs and great momentum in our key areas.

I'd characterized our second quarter as a strong quarter in which we've done exactly what we said we'll do, with the portfolio now increasingly set for sustainable profitable growth. I mentioned at our recent Investor Open House, that we would demonstrate underlying growth in the second half of this year. This quarter's results reaffirm that view, and we're confident we're well-positioned to begin to see sequential growth over the second half.

Turning to some of the highlights for the quarter. We're producing more than 190 million cubic feet a day from the Marcellus today, which gives us more confidence in reiterating our target year-end exit rate of between 250 million and 300 million cubic feet a day. The trend I noted last time we talked of unconventional growth outstripping conventional decline has been consolidated this quarter, and is contributing to the underlying growth of the overall Talisman level. This will continue and will set us up for 5% to 10% absolute growth into next year.

Our asset transition is continuing and as you saw from our release so far this year, we've completed $1.5 billion of the $1.9 billion of asset sales in our North American conventional portfolio, and we'll deliver the remainder through the second half of the year. That's contributed to $2.6 billion of cash on the balance sheet which is clearly a very strong position, although Scott will explain, we will spend some of that through the second half.

We strengthened our exploration portfolio further over the quarter. In June, we were awarded three exploration blocks in the Sub-Andean oil trend of the Putumayo basin in Columbia, and we have some encouraging signs from our first test well in the heavy oil blocks we already holed. Although it's early days, this is all moving in the right direction.

We've been awarded additional acreage around our Sageri block in Indonesia, which we'll drill next year. And we completed a good appraisal well on Grevling in Norway although with more work to do to establish a development program for that discovery.

Our Asian portfolio has hit 125,000 barrels a day this quarter, the underlying trend is positive and we'll also benefited from a one-off adjustment as we completed a favorable utilization agreement on South Angsi. So our strategic actions are all moving in the right direction, and we're delivering what we promised.

I must say a word about our response to the Gulf of Mexico incident. We are, of course, deeply saddened by the tragedy which is both personal and environmental, and we are, along with the rest of industry, taking all the precautionary steps we can to learn, and to make sure our processes minimize the risk of such an incident happening again.

We've examined and revisited all our well designs, procedures and well control equipment, and we've discussed the event at length with all our operations and drilling teams to learn as much as we can and reinforce our procedures and accountabilities to minimize risk. We've discussed the incident and our responses with our board, and we're satisfied that we have taken all possible steps to learn and minimize our risks.

It's of course important because we're drilling wells offshore all the time, and we're about to begin a non-operated deep water well in Pasangkayu in Indonesia. All the procedures have been checked multiple times, and I'm confident that we can progress our operations safely and without incidents.

Going through the financials, the quarter was strong. Net income was $603 million for the quarter, and there are really three main items to draw your attention to in that number. First, we benefited from a stronger oil price than a year ago, although gas prices reduced our netback slightly versus the first quarter of this year. In both cases, the stronger Canadian dollars was a negative in terms of realizations. Second, we booked modest mark-to-market gains from our hedging program this quarter. But this time a year ago, we booked substantial losses, which depressed our reported income a year ago, and hence, flat as the year-on-year comparison.

And third, depreciation charges were lower than a year ago by about $100 million, and down also against last quarter. This is due to a combination of lower production in the U.K. because of the turnaround scheduling this quarter, the foreign exchange benefits and increased reserve bookings at the end of last year.

We also realized the gain on disposables of around $160 million which is included in the net income number. Earnings from continuing operations take out the impact of the mark-to-market adjustment and other non-operating items, and we're up from both last quarter and a year ago.

Dry holes this quarter, we're again relatively low, and in fact, benefited a little from a tax rebate in Alaska. Costs as you would have seen were low at this quarter, a weaker pound helped, which reduces the U.K. costs when reported in Canadian dollars. The U.K. had quite an extensive shutdown program this quarter, and the work over on the Tweedsmuir well, which is now back online after being cleaned up and descaled added to operating costs in the first half. But the reported costs were down despite these pressures which is good news.

In a general sense, cost pressures are building across our operations as economic momentum builds. In many places, we've put in place longer-term contracts, which mitigate these pressures. This is true for rigs and stimulation services in North America where perhaps the pressure is at greatest. And also for supply vessels in the North Sea, where we're also seeing substantial market pressures.

Our cash flow position of just over $800 million was down from last year, but the prior year benefited substantially from the hedges which we had in place at that time. Whereas this year, we realized the small cash loss from our hedging programs. Excluding these effects, cash flow was up about 20% from last year. Free cash flow after capital expenditures was around $680 million, which of course, benefited from the disposal proceeds of about $1.2 billion from our North American sales. We've completed about $1.5 billion of sales, but some of them came after the books closed, and so it will be reported in next quarter's cash flow.

Capital expenditure was about $960 million in the quarter, bringing the total year-to-date to $1.7 billion. I mentioned in May when we met, that we were maintaining the activity forecast, which at that time, we estimated the costs about $4.6 billion for the year. Looking at the year-to-date spend and even accounting for the fact that we will spend more in the second half, I think our annual spend may turnout closer to $4.4 billion to $4.5 billion, although this absolutely doesn't represent any strategic shift or change. But we'll need to keep an eye on it over the next quarter, and we'll adjust guidance properly for you as it becomes clearer in the second half.

The strong cash flow, disposal proceeds and capital broadly on plan have contributed to a very strong balance sheet position at the quarter end. This is a good place to be, and we're projecting to use some of that cash on organic spending going forward. Production for the quarter was 411,000 barrels a day, which was impacted by around 38,000 barrels a day of planned shutdowns. As you read in our release, 27,000 barrels a day, this was in the North Sea, and in fact, 18,000 barrels a day was in the U.K. Although we've completed the majority of the planned shutdown activity during the second quarter, we do still have some shutdowns in the third quarter. These shutdowns, combined with the impact of disposals, will result in absolute production levels in 3Q being lower than they were in 2Q.

Production from continuing operations, taking out those assets either sold or held for sale, was 387,000 barrels a day, which is up 2% from the same quarter last year. This underlying growth trend is set to continue through the second half, and as I've mentioned, will deliver absolute growth into next year.

I'm holding production guidance for the year, the same as I outlined for you last quarter. Our latest estimate of the impact of disposals for the year is about 18,000 to 20,000 barrels a day. And I've said, we'll remain broadly flat with last year, excluding disposals. Production last year was about 424,000 barrels a day. And thus, we're expecting to be a little over 400,000 barrels a day after disposals this year, no change to what I've said previously.

Let me now ask Scott to run over the balance sheet, cash flows and hedging programs in a little more detail for you. So over to you, Scott.

L. Thomson

Thanks, John. I'll review our financial results, balance sheet, progress on focusing the portfolio and hedging position. Cash flow in the quarter was $812 million compared to $837 million in the immediately preceding quarter, with lower production volume and commodity prices, partially offset by lower cash taxes.

Cash flow of $897 million in the second quarter of 2009, included approximately $200 million of hedging proceeds. Earnings from continuing operations, which includes certain non-operational items were $137 million in the quarter compared to $121 million in the immediately preceding quarter. Lower production volumes and commodity prices were more than offset by lower operating expenses, DD&A and lower realized losses from hedges. Earnings from continuing operations of $132 million in the second quarter of 2009, included the approximately $200 million of hedging proceeds referenced earlier, partially offset by lower commodity prices.

Current income taxes were $161 million in the quarter, lower than both the immediately preceding quarter and the second quarter of 2009, due principally to lower production in the North Sea as a result of turnarounds. Last quarter, we indicated current income taxes would likely be in the $700 million to $850 million range, and that is still the case. However, given strong production in Norway and potentially lower capital expenditures relatively to plan in the North Sea, 2010 current income taxes are likely to be towards the high end of that range.

Exploration and development expenditure during the quarter was $934 million, of which $338 million was directed towards North American Shale activity, with the majority spent on progressing development of the Pennsylvania, Marcellus and Montney Shale programs.

$250 million was spent on development activity in the North Sea, a significant portion of which related to the Auk North and EMA development. $141 million was spent on development activity in Southeast Asia and the rest of the world and $156 million on international exploration.

Year-to-date, we have spent $1.7 billion on capital expenditures. Although capital expenditures accelerate in the second half of the year, as John mentioned, it is unlikely that we'll spend up the $4.6 billion that we forecasted at our Investor Meeting in May.

On the disposition front, we closed three North American conventional assets sale during the quarter for proceeds of $1.3 billion, and another since the quarter end for $200 million. We'll close the remaining sales in the second half of the year to complete the $1.9 billion in conventional sales announced in Q1. We also closed our acquisition of assets in the Eagle Ford during the second quarter, and have started running our first rig.

At June 30, we had $2.6 billion of cash on the balance sheet. Our net debt decreased from $2.1 billion at December 31, 2009, to $1.3 billion at the end of the quarter, reflecting approximately $680 million of free cash flow in the quarter, which includes the proceeds from the assets dispositions that closed and the dividend of $0.125 per share.

We continue to expect capital expenditures to exceed cash flow for the rest of 2010, and we'll fund the capital program with cash on hand and proceeds from dispositions. In the last quarterly call, I indicated our ending cash position would be approximately $1.5 billion. If we take into account a modest underspending capital expenditures relative to plan in the second half of the year, I believe our ending cash position would be slightly higher than the $1.5 billion referenced earlier. This balance sheet strength will allow us to continue to pursue organic growth or take advantage of acquisition opportunities that may arise.

Turning to our hedging program. We have hedged approximately 40% of estimated remaining 2010 crude oil production in four different programs. 25,000 barrels per day are hedged in 70 x 90 collars, 23,000 barrels per day in 55 x 85 collars, 22,000 barrels in 50 x 60 collars and 5,000 barrels, again, in 50 x 60 collars. Approximately 60% of our 2010 production is oil or oil linked, and therefore, we have significant upside exposure to higher oil prices.

For North American gas, we protected approximately 335 million cubic feet per day or approximately 50% of estimated remaining 2010 production through physical and financial hedges, with approximately 95 million cubic feet per day in NYMEX collars with a $6 floor and $7 ceiling, and the majority of the remainder in AECO collars, with a $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. 2011, we have hedged approximately 150 million cubic feet per day of gas at approximately NYMEX $6, weighted to the first half of the year. And currently, we have no 2011 oil hedges in place. Those are my highlights, John, I will turn the call back over to you.

John Manzoni

Thanks, Scott. So ladies and gentlemen, I think it has been a strong quarter, both in terms of financial results and in terms of delivery against what we so we'd do. I feel confident about the second half of the year as the company moves to consolidate into profitable growth, and we continue to execute against our promises.

We'll maintain flexibility in our capital program because it is still not clear which direction gas prices will move to the back half of this year and into next. But our growth track and improving profitability are robust to any environment, and I'm looking forward to building on a very strong first half. And with that, ladies and gentlemen, we'll be very happy to answer any questions you may have.

Question-and-Answer Session

Operator

[Operator Instructions] Your first question comes from Mark Polak from Scotia Capital.

Mark Polak - Scotia Capital Inc.

I just wonder if we can get a bit of an update on the Montney drilling program progress to date in terms of how many wells you've drilled and completion and how that unfolds over the second half of the year?

John Manzoni

I'm going to ask Paul Smith who wants to tell us how we're doing in the Montney.

Paul Smith

As you know, we got a combination of development drilling and pilot activity going on with the Montney as we speak. We've drilled nine wells to date in the first and second quarters of this year, and we're in the middle of starting our completion program as we speak. So in the second half of this year, we should start to see a large increase in the number of completions. On the pilot side, we've now drilled seven net wells in what we call Cypress - A, and we've got another six wells that are being drilled in the Cameron area as we speak. So we should end the year, having drilled roughly 14 gross pilot wells in Cypress. So a lot of data coming as we go forward. There will be no new wells brought online since the wells that we had last year. I will say that although we continue to make good progress on the efficiencies, in particular, on the drilling side, in Farrell, we plan the beginning initiate to have wells drilled at about $5.5 million. We're currently averaging well below $4.5 million and are approaching $4 million a well after early six months of activity. And to sort of translate that into days for you, we had a 60-day per well plan, and we just have steady pace [ph] of well just under 40 days for the well. So the program is going well, but because we don't same oaks [ph] between drilling and completions, we have to wait for the rigs to move up with path [ph] drilling, obviously. And so you'll start to see sort of an exponential amount of completions coming on in all three zones of the Montney, Lower, Upper and the Doig as we go forward. Have said, we'd bring 17 wells online this year, and we're on track to do that in Farrell.

Mark Polak - Scotia Capital Inc.

And my other question was on PM-3 and just with the response you're seeing on IOR project so far. Is that any change you have used on a Phase 2 of that, is that still looking like a 2014 start-up?

John Manzoni

I hope Paul doesn't commit as to more capital on that. But, Paul, PM-3 Phase 2, how are we saving about Phase I?

Paul Smith

Yes. The drilling on Phase 1 is just coming to completion and we are very happy with the progress we've made. The well results at least as good as planned, if not better, so that's a great start. And the team has been working on identifying a large number of new infill well opportunities. But the next stage will require placement of additional platforms and other facilities. It will be larger program. We're working our way through that and our expectation and hope is that we'll come up with sufficient opportunity to work through something for sanctioning sometime in next year, perhaps in the latter part of next year.

John Manzoni

Smallest platforms, Paul?

Paul Smith

Yes, this would be very small unmanned facilities just supporting wells tied back to main infrastructure.

Operator

Your next question comes from Brian Singer from Goldman Sachs.

Brian Singer - Goldman Sachs Group Inc.

First question on the capital budget, even if you under spend the $4.6 billion by $100 million to $200 million as I think you highlighted, I think that would apply a very substantial ramp up in the second half. Could you add more color on where we'll see that, geographically, and extent to which service costs increases maybe a contributing factor relative to potentially you're under spending the budget by a greater amount?

John Manzoni

Brian, let me just give you a general answer. I mean, I think actually, in almost everywhere, we're seeing, in almost areas of our business, you'll see particularly, as the rigs ramp in North America and also in Asia, we're actually projecting larger higher activity levels in the second half of the year. So the projection of that increase is actually all to do at the moment with activity ramp up. And we're not building into that projection, any service cost increases or inflation in those projections. So this is about -- I think where we stand at the half year, it's really just about the pace, the natural pace of activity. We have actually sort of gone back to the organization, we confirm, reject and it's come back, saying now we're still on the activity level that we set, which represent a significant ramp up in the second half of the year. So that's why I'm not officially changing $4.6 billion just yet, but I expect it would be a little lower. But we will confirm as we go forward. But there is no build, there is no inclusion in that or expectation of any inflation due to service costs. This is all about activity.

Brian Singer - Goldman Sachs Group Inc.

And should we assume you're not seeing any of that at the moment even in the Marcellus or you starting to see some of that?

John Manzoni

Well, we are seeing across our operations, as I've mentioned, a general increase in economic activity, which brings with it a general increase in cost pressures. In certain places, and I mention two, one in the North Sea, where we've got longer-term contracts going in on supply vessels and second in the Marcellus, in particular, in the Marcellus where there is pressure on stimulation crews, well service crews and rigs. We've actually put in place long-term contracts for all of those which have essentially locked in a lower level of the cost base. So we've mitigated what is a general cost pressure across the business, and we mitigated in other places. Well, but those are two main ones, where I think the pressures were highest and we acted earliest to mitigate those pressures.

Brian Singer - Goldman Sachs Group Inc.

And then, I guess, lastly, can you give us an update on Colombia and resource potential on how you're thinking about the program following the completion of the Guairuro [Guairuro-1] Well?

John Manzoni

I'm going to ask Richard Herbert just to talk in a general sense about what we're doing, Richard, in Colombia and acreage acquisitions and such things and resource potential perhaps.

Richard Herbert

Yes, certainly. I mean, Brian, a couple of things that we've said a pull out in Columbia. One is we've drilled a successful exploration well in the first part of this year in Chiriguaro [indiscernible] number one well, and that is going to put on a long-term test during the second half of the year. Secondly, as you mentioned, the operator, Pacific Rubiales, has just drilled the first stratigraphic test in Block 6 that we're partnering in that well the Guairuro-1, had a 28-foot net pay zone, which was very encouraging. It's still really early days there. We have a program of six stratigraphic wells we're going to drill in total. This is just the first well. Now it's too early to start putting sort of resource estimates on it. But it's certainly, a positive step. And I think once we've been able to complete the stratigraphic well program, we'll have a better understanding of sort of resource potential in that part of the trend. The other thing that's happened during the last quarter was the 2010 Columbia bid round. And in that, we were successful, again, with the Pacific Rubiales in acquiring three new blocks in the Putumayo basin, which is the next basin south of our Llanos basin position, but is an extension of the same geology and the same prospectivity. So we've done a lot of work we believe to strengthen the portfolio, got encouraging results, being in the right direction.

Operator

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

Greg Pardy - RBC Capital Markets Corporation

A couple of questions just on the Marcellus, John. The first one is, I think you mentioned on your last call, that you're moving into new areas and you were not inclined to upgrade the EOR IP rates that you were seeing. So just curious as to how the program has continued to unfold? And also, interested just in the number of stage fracs that you're now running in the Marcellus. And then the second question is it relates somewhat to the DD&A rate, just curious as to how much in the Marcellus you now have in the proven category.

John Manzoni

Well, I figure out we're going to answer the second part of your question. Let's get to Paul to answer the first part.

Paul Smith

So let me answer it, Greg, let's go with the generals of the statement in terms where we are in the Marcellus, and I'll answer your question specifically around the new areas, so we entered the year, this year with 60 million standard cubic feet of production as you know. We've drilled and completed since the beginning of this year an additional 61 wells in the Marcellus. And so year-to-date, we're now running at as you saw from the press release, at around just over 190 million standard cubic feet a day. We remain on track, as we've signaled all the way through the year and since the beginning of the year, the drilling complete 145 wells this year. So that means there are 84 wells also to come from this point forward. And we continue to be sort of cautious in terms of our forecast going forward. Firstly, because as you know, we've got 65% decline rates in all of the wells that we have coming on in that first year. And secondly, to now get to your question, we're now drilling into new areas in the second half of this year. The first is in Colombia County and the second one is in the Susquehanna County. We're actually, this week, starting to bring on the first wells in Colombia. And so I think it's just too early to say, we don't have a single well in Colombia on production. We don't have a single well in Susquehanna on production at this moment in time. And so what I will say is that we are smart back on track to remain to deliver an exit rate of 250 to 300. In terms of the stage fracs that you asked for, it depends on the wells, Greg, and sort of geometry of the leases. We have a bias, as I said in our Investor Open House to go as long as possible now. We're doing up to 15 stage fracs, and we will continue to where the geometry of the lease. So we're go as long as we can. And we're also continuing now to optimize the fracs with more pounds of sand per foot going in. So we're moving from what we have at about 500 pounds before, we're moving up to the 1,000 to 1,500 pounds before, super frac its ranges it's called, and anticipate that will have a positive impact.

John Manzoni

Greg, Paul managed to fill the bus long enough, but we still don't have the exact answer to your question. DD&A rate, lower this quarter primarily for the reasons that we discussed. It's about lower U.K. production. It's about a benefit from ForEx in this case. And about the reserves having been written up at the end of last year in the U.K. because of the pricing affect. There hasn't been a substantial impact because of Marcellus DD&A and Canada implementation in the lower number this quarter. And the reserves, 1P, if you like, that we've got in there are the same as we had at the end of last year in the Marcellus, no change to that. So the reduction you're seeing is for those reasons that I've mentioned and it's not an impact as a result of the sort of shale coming into that program. That's not an exact answer, I think to your question, but it's good at it.

Greg Pardy - RBC Capital Markets Corporation

One follow up, there has been some talk now about producing, just producing wells that at restricted rates, higher pressure and not necessarily -- not filling the well with a 65% decline in year one. Would you continue, especially with further gas prices down, do you see altering your strategy at all in terms of how you would produce the wells or...

John Manzoni

Yes, let me just see if I can answer in general, and then I'm going to ask Paul to see what we're doing. In a general sense, I mean, you're referring to the sort of debate going on about whether or not in certain shales. EURs are ultimately higher or lower if you blast the well early. I would say, in the general sense, that we, before I ask Paul to do what -- fairly what we are doing in our wells. Our capital is -- you'll notice we are not stealing forward and accelerating capital and accelerating growth in all of those things, we're really very comfortable with the level of capital that we're deploying into the shales in particular. In the Marcellus, they're making money because the break-even price is lower than today's gas price, and that's an important aspect. We're getting it straight into sales. In the Montney, we're driving down on track to build the program, which is going to be economic very, very soon in that sense. We sort of at the level of capital that I think is not pedal to the metal, so to speak. But is well judged in the light of today's fixed price, with options up or down as we go through the second half and into next year. And that's what I was trying to signal with the capital program. Now the 65%, the absolute choke levels, Paul, on the Marcellus earning?

Paul Smith

Yes, I mean, Greg, we make decisions based on clearly the value contributions of the well, full cycle, not just point forward. And with our Marcellus program, sitting well below $4 in mcf full cycle, with gas prices well above anything about $4 means that we're making the right value judgments to not choke those wells and in this moment in time, we're not choking wells or restricting wells in the Marcellus.

Operator

Your next question comes from Andrew Potter from CIBC World Markets.

Andrew Potter

Just two quick questions on the strategy in the shale gas. I mean, it seems like we're seeing a bit of a trend where -- we're seeing more joint venture and activity in some of the Canadian shales. Just wondering, how you guys think about that? And if that sits in with your strategy and in particular, I guess for the Montney Shale and potentially the Utica. What stage of drilling do you have to get up to before you would entertain that type of transaction, I guess, if at all?

John Manzoni

Let me ask Paul to describe how he's thinking about the Montney.

Paul Smith

I mean, as you saw at the Investor Open House, the Montney is -- and our position in the Montney is a fairly chunky resource at 44 tcf of contingent resource. That's probably too large in the long term for Talisman alone, and so we continue to look at all options to maximize value. I'd say that, at this moment in time, we haven't decided on any particular route, but we will continue to look at all options and decide at some point going forward, which option allows us to unlock and maximize value in the Montney with a 44 tcf contingent resource position that's becoming more and more de-risk by the day.

John Manzoni

I think value is the operative word, Andrew. I mean, in general, the faster you can develop these things, the better. Except when the gas price is low, so there's a trade-off there and there's also a trade-off as between pace with one zone capital and pace sharing somebody else's capital. So those trade-offs are being assessed. We know where we stand on them, so that's the considerations in Paul's mind. And I would say exactly the same considerations apply to the Utica as well in due course.

Andrew Potter

And just to finish off on the Utica, I mean, how many more wells do you need before you get in sort of hazard contingent resource estimates on the play?

Paul Smith

Let me tell you what we're doing, Andrew, in the Utica this year and I don't think I'll be able to answer your question specifically around the 700,000 acre position, but we've decided -- since the last time that we spoke, based on the success of the first well, the St. Edouard well, to increase our program this year from four horizontal wells to five horizontal wells. Four of those have been drilled and we're sort of drilling the fifth one as we speak. We're in the process of completing two of those wells and by the end of the third quarter, we should have a total of three wells producing or at least testing, I should say, in the Utica. And then we should have the other two, i.e. wells four and five, onstream testing by the year end. And at that point, we'll have a lot more data than we do today. I mean remember today, we still didn't have a single data point, the St. Edouard well and we'll have 5x as many data points by the end of this year in which to make decisions on how we move that play forward.

John Manzoni

About 100,000 acres?

Paul Smith

Yes, I think we roughly think this will de-risk five wells that we're drilling this year, we'll probably de-risk 100,000 to 150,000 net acres of the 700,000 acre position that we hold in the Utica.

Operator

Your next question comes from John Herrlin from Société Générale.

John Herrlin - Merrill Lynch

A couple on the Marcellus, when will you be HBP on all of your acreage? Do you have any exploration limits with respect to the leases themselves?

John Manzoni

Two questions, did you say or just the one?

John Herrlin - Merrill Lynch

The other one is on frac costs as a percentage of your total well costs, how much are the fracs running?

John Manzoni

How much are the fracs running? So let's do with the whole by production first. Paul?

Paul Smith

As you know, last year, we doubled our acreage position in the Marcellus, which gave us roughly half our acreage completely unincumbent with three- to five-year lease terms. In general, I'd say that -- so that sort of gives you an indication of the amount of years it's going to take before we have everything held by production...

John Manzoni

You're talking Pennsylvania?

Paul Smith

In Pennsylvania, the Marcellus in Pennsylvania. The pace at which we could turn down the drill bid in Marcellus and the flexibility that we said we theoretically have is to turn the drill a bit in Pennsylvania down to circa $300 million. We're putting $1 billion in this year without losing a single acre of land. So I think we're in a strong position to manage our land expiry profile in the Marcellus, consistent with the external environment that we find ourselves in. Second question, in terms of sort of frac costs, well costs, we're sort of on average, continuing to as we go longer, we're sort of drilling and completing wells for about $4.3 million at the moment, and about $2.6 million of that, $2.5 million, $2.6 million, depending on how many stages we're doing, the frac costs. So that's sort of the rough numbers for the Marcellus.

John Herrlin - Merrill Lynch

On acquisitions, John, you said the balance sheet is in good shape and you might look at things, we're talking complementary-type acquisitions. And what's your disposition or predisposition? Would you look more in the North Sea or onshore North America or elsewhere?

John Manzoni

We've always said, with regard to acquisitions that if we make them, they'll be in line with our strategic orientation, which essentially says, we look in Asia because we're building in Asia. We'll look for the right opportunities, come to deepen or strengthen our existing land base in North America and/or will look behind the distinction behind our exploration drill date in certain places where we're trying to build the business, which is exploration lead. So actually, the North Sea doesn't feature, particularly the U.K. doesn't feature in that set of priorities. But anything that we do have to be consistent with what we've set our strategy to be. And it also has to be a sort of value accretive to us. It's very easy to swap dollars for barrels and that's not a particularly productive occupation. So I think we looked through those two lenses and see if any opportunities arise, which is consistent with that.

Operator

Your next question comes from Chris Theal from Macquarie Securities.

Christopher Theal - Macquarie Research

Question on water permits in the Marcellus. You mentioned you have those in place for 2010. What's the visibility there for 2011? And what sort of process do you go through here?

John Manzoni

Let me see if Paul wants to answer that one.

Paul Smith

Sure. So yes, I mean the 2010 program is pretty well underpinned. The permitting process to drill a well in Pennsylvania is essentially three types of permit, one of which includes a water permit. As I mentioned last time, the program for this year is well underpinned. We've started to get ahead of the curve for the 2011 program, and I think that's key because as industry continues to pick up activity in the Marcellus Pennsylvania, there's clearly a larger and larger strain on the administrative resources within the DEP. I think we're well positioned and we'll make sure that we continue to be well positioned, but this isn't a choke on our delivery.

Christopher Theal - Macquarie Research

And part two to that with the Marcellus, there's been a few industry blowouts. Any response from the regulators in terms of reviewing company drilling and completion operations? And I mean changing on the regulatory front as a result of those last few events?

Paul Smith

I would say that the regulator in Pennsylvania is taking all of these events extremely seriously as they clearly should. Only a few weeks ago, an instruction went out to all operators in Pennsylvania with a list of incremental requirements that the DEP was expecting operators to implement. The good news is we had already been operating to those standards, so there's nothing new in there for us in the way that we operate and the standards that we hold ourselves accountable to. But clearly, I think all of these incidents are extremely unfortunate. They don't help the public perception, which is an issue in any event, but I think we're a long way off from seeing any signs or threats of a growing support for a drilling moratorium in Pennsylvania. I think both Governor Rendell and the two leading candidates to replace him during the elections at the end of this year, all three have come out publicly and stated that they fully oppose a drilling moratorium seeing the benefits. But increased regulation is clearly, local regulation is clearly on the cards. And I think the DEP are doing a good job to staff up to make sure that they can handle the increased activity levels in Pennsylvania.

Operator

Your next question comes from Mike Dunn from FirstEnergy Capital.

Michael P. Dunn - FirstEnergy Capital Corp.

With respect to your positioning in Vietnam, I know you've recently acquired a couple more blocks there. I think BP, this morning, confirmed they were looking at options for its -- or maybe divesting its Nam Con Son assets. So I guess my question to you would be, do you feel like you have your hands full with what you have in the Nam Con Son basin right now? Or are you open to additional acquisitions there? And I guess second question is, maybe if you guys can walk through your North Sea exploration program for the year?

John Manzoni

As I said in acquisitions, we look in all areas where it would be strategically consistent with what we are doing. That's the first point. We're of course aware of the BP processes and you're right, I'm not going to confirm or otherwise any particular or individual discussions going on. Are our hands full? I think we've got a great team. I think we've got lots of capacity. There's lots of things should the right things emerge. I think I'd leave it at that. But there's an ongoing process, we're always looking at all sorts of things and I'll just repeat what I said. It's got to be consistent and it's got to be more than swapping dollars for barrels. So I think that's -- but we're very happy with our position in Nam Con Son basin. It's actually a very prospective part of the basin. And we've deepened, as you mentioned, so we're very excited about that as an opportunity going forward actually which is great. North Sea exploration program, let me see if Richard would like to comment on where we are with that.

Richard Herbert

Yes, certainly. Yes, 2010 drilling in the North Sea, both in the U.K. sector and Norway, if I start with Norway. First of all, we're pretty much finished our exploration and appraisal drilling for this year there. We've drilled an appraisal well on the Grevling discovery, which was made in 2009 and that was a successful well included another well test and also a sidetrack to gain as much data as we could. We also drilled an exploration well in Norway called Optimus, which we will partially carried on. This was a commitment well that -- one very enthusiastic about, from a technical point of view and sure enough, it was unsuccessful, but it did complete the commitment in that block and allow us to then relinquish it. In the U.K. sector, we drilled an exploration well on the edge of the Tweedsmuir field, earlier in the year, a well called TP2, and that well felt in kind of the reservoir. Believe we can reuse some of the borehole in a future well on the Tweedsmuir field, but the full compartment we drilled into was not successful. And we're currently drilling an appraisal well near our southern hubs in the U.K. sector, which is called the Halley Delta well. And that well switched to about 6,000 feet and is running casing as we speak. And once we've completed that appraisal well, we'll be going on later this year to drill an exploration well, exposed to that called the TR1 well, which will be drilled in block 3013 near our southern hub in the U.K. sector. We've also, this year, participated in the 26th licensing round in the U.K. We've applied for a number of blocks there. We won't find out the results of that for some months yet, and we're evaluating opportunities coming up in the Norwegian licensing round.

Operator

Your next question comes from George Toriola from UBS Securities.

George Toriola - UBS Investment Bank

First, with the Marcellus, can you sort of talk about the liquids content of the Marcellus as you're seeing it currently?

John Manzoni

Liquids content in the Marcellus. Yes, Paul?

Paul Smith

We're in the dry gas window of the Marcellus, so zero.

George Toriola - UBS Investment Bank

And what about in the sort of new areas, sort of your expectations? I know you said, you don't have any wells on stream yet, but do you have any expectations on that front?

Paul Smith

On the new areas, same. I mean we've taken a conscious strategic decision, George, in the Marcellus to stay in the dry gas window. We have technical reasons for that, and so you won't see any liquids contribution in the Marcellus program from the acreage that we have today.

John Manzoni

Speaks to the pace that which you bring them on, Paul.

Paul Smith

Speaks the pace in the -- and yes, because the complexity that comes along with liquids and some of the technical uncertainties that are out there with liquids in tight shales. I've meant that we strategically decided in the Marcellus to stay within the dry gas window. Unlike the Eagle Ford, where we're clearly targeting the transition window for different reason.

George Toriola - UBS Investment Bank

And then secondly, how much ability do you have to shift capital? John, you had talked about sort of gas prices being in a place that's if it's stronger than you had expected. To the extent to that, we have a supply lead sort of downward pressure on non-gas prices here. How much flexibility do you have to shift capital to liquids?

John Manzoni

Well, George, I mean as we said before, one of the advantages really and I think perhaps it'll turn out to be competitive advantage, we'll have to wait and see. The answer to your question is a lot. Paul has mentioned that in our shale operations, we would have to spend somewhere between $300 million and $350 million per a year or next year, for instance, in order to maintain the land base exactly as it is today. That's substantially less than I think many others who are even today, drilling in order to hold land. So I think we -- and that's why we're being, if you like, sort of steady handed around capital for the remainder of this year, as we watch the direction of gas prices and the supply and demand fundamentals and see which way they move. All of it is going to be guided. Our capital program and its distribution will be guided in the shales by the maximization of value of the total resource. On the one hand, if you accelerate and spend and bring the production forward, you maximize value, but not if it's a low gas prices. So that's a trade-off that we have. And then we compare the returns in the shales versus the returns of any other opportunity that we have. And in some ways, in a good position. I mean internationally, the capital is much more structured and it comes through in a more routine and a predictable fashion. But we look at returns across our portfolio and in fact, as we come up in the September, October, we'll be looking at every project and every incremental capital spend, ranking them on returns. And so we'll be looking through the returns lens and the value lens in order to determine the level of capital that we should deploy into next year. So I think that -- the answer is we have a lot of flexibility to do that, and that's quite a good position to be in.

George Toriola - UBS Investment Bank

Let me just ask the question slightly differently. If you -- to the extent that based on natural gas prices, you chose to do something else, would that mean that you shift capital within your shale plays or you would shift capital outside of your shale plays?

John Manzoni

Well, we have some shale plays which in liquids. Eagle Ford is a great example. So that's an opportunity to distribute the capital within the shale plays in a relatively different way, and we have that flexibility and we will be considering the flexibility in light of the gas prices. That's lever one. And lever two, is the absolute capital into the shales versus into our other projects, explorations and other things, liquids-rich activity elsewhere in the world. So we have both those two levers and both will be deployed as we go into the second half of this year if we think that the gas price situation merits it.

George Toriola - UBS Investment Bank

Just in looking at your international portfolio, where do you see the most leverage to drive sort of the next core area?

John Manzoni

Well, today, we have three core areas, North America, Europe and Asia. We're building Asia, and we continue to build Asia and our exploration activity focused first in Asia where we have a fabulous, I think great quality of exploration portfolio. But also in South America, in Colombia and Peru. And as Richard has described, I think the Colombian portfolio is looking increasingly sort of optimistic. So I think that's got a chance over time to build. I mean we will only be exploring over a period of time in an area which has the potential to become a core area, and Latin America certainly does as the next core area from our portfolio today, I think.

Operator

Your next question comes from Carrie Tait from the National Post.

Carrie Tait - National Post

Can you expand a little bit more on your plans for Poland?

John Manzoni

Carrie, give us the two questions and that will give us time to think about the second one, while we answer the first one.

Carrie Tait - National Post

And the second one is just -- I'm hoping that you can explain one more time why you expect to spend less money this year than your original projection?

John Manzoni

So that one is definitely worth thinking about. So let me ask Nick and that mix voice in the room. Nick, to talk about what we're expecting or thinking of doing in Poland.

Nicholas Walker

So early in the year, we found into some acreage in Poland in the Siberian, which is a shale play. And at the present time, we're gearing up to do some seismic through the latter part of this year, and we expect to drill some wells next year and on three wells in the middle of next year. So building the office and preparing for operations at the present time.

John Manzoni

In terms of geology, Richard, just to round out.

Richard Herbert

Well, I mean we've taken our position in three blocks in the northern area of Poland adjacent to the Baltic Sea. It's an area that's quite a land rush, some other company have moved in there. The first well has just been drilled by another company, Lane Energy, have just drilled the sort of molten well in the basin. And we're still waiting to hear any news from that well, but our understanding is it's going to be tested. Our program is running a little bit behind as Nick said. But our intention is to shoot seismic base to identify drilling locations this year and then doing drills in pilot vertical wells next year to -- drill on core the Silurian Shale interval, which is of interest and looks very similar to the sort of gas shales that we're drilling in North America.

Carrie Tait - National Post

You said the Siberian shales looks similar to which?

Richard Herbert

To the shales in North America like the Montney and the Marcellus. We think technically, they've got a very similar organic richness, that they're much, much thicker. So there's a big upside in the Polish shales if they are, in fact, gas bearing.

Carrie Tait - National Post

How much do you expect that play to become for you?

Richard Herbert

Too early.

John Manzoni

It's very early days. I'm not going to let the explorer answer that question. So to your second question, why we spending less? Look, so we came into the year with a cash capital expenditure expectation of $4.9 billion. Actually, the same activity by the time we got to May was going to cost us $4.6 billion, and that was simply because the foreign exchange movements around the world and where we spend the dollar. So translated into Canadian dollars, it has already gone down to $4.6 billion and that was no change in activity. That was just the impact of foreign exchange changes. Now from here, as I've said, we're still not projecting a change of activity actually and indeed, we will be ramping up activity second half versus the first half. But I think it's just -- for whatever reason, one thing or another little changes here and there are putting a slightly behind the activity curve over time. I say people aren't working hard enough, but I'm assured they are working as hard as they can. So there's no strategic content to the slight reduction as we go into the second half of the year and it may well be that we can't back up to $4.6 billion. But my expectation is to be a little below that. There's nothing -- there's sort of no determined intent to make it lower.

Carrie Tait - National Post

Can I just ask one more question about Poland. You mentioned there was a land rush, are you still participating in that? Or do you think a lot of it has been snapped up already?

John Manzoni

Richard?

Richard Herbert

Carrie, there's very little unlicensed and left in northern Poland now. We're quite happy with the position we've got. We're 60% partner in three large blocks. We've got more than enough real estate to work on.

Operator

Your next question comes from John Herrlin from Société Générale.

John Herrlin - Merrill Lynch

Just on follow up, when will we have more information about IFRS? And what changes that may make to your balance sheet year end?

John Manzoni

This one is for the CFO.

L. Thomson

I think, we saw the disclosure this last period where we started to indicate some of the steps we're taking and we're in a process right now with the auditors and the Audit Committee and with management to start to frame some of those impacts. I suspect third quarter, or fourth quarter of this year, you'll start to see some ranges around some of those numbers and I think we'll have to play it a little bit by year in terms of the internal process and how we engage with our auditors in terms of whether it's the third or the fourth quarter.

Operator

Your next question comes from Markus Ermisch from the Calgary Sun Newspaper.

Markus Ermisch - Calgary Sun

Two quick questions about Poland. First, the regulatory regime in Poland, how suited is that for shale gas exploration? And my second question is, given that Poland is fairly densely populated, how open are people there to drilling in that backyard?

John Manzoni

Let me answer the second one first, and then ask Nick to comment on the regulatory regime. Poland across got a very established gas and oil industry. So I mean people are used to oil activity, not shale activity, but there are all wells and gas wells in Poland today. So it's not as though, this is a completely new experience. Nick, a comment on the regulatory activity that we're finding or the regulatory regime?

Nicholas Walker

Well, as John said in the Oil and Gas business there, and so it's already operating. I think as we've seen in North America, some changes will be required to the regulatory regime. Industries are already engaged on a conversation with the government there and ministries around this. But we see that Poland is open for business and wants to see this business develop. So I think we're confident it will go in the right direction.

Markus Ermisch - Calgary Sun

The reason I was asking because I remember John Manzoni was saying in an earlier media scram that Poland is not Texas. That's his quote. And that's why I asked that question.

John Manzoni

I still stand by that comment.

Operator

Your next question comes from Paul Andriessen from ABN Emerald.

Paul Andriessen

I had a question about the Yme field in Norway. In changes to your expectations with regards to the start-up date of that field to also looking at your statement in your press release about expected load-out of topsides in August?

John Manzoni

Let me ask Nick to comment on where we are with Yme.

Nicholas Walker

So we're making good progress on the field. We're expecting to start up around year end, but that's subject to weather windows for installation. I think it doesn't have much impact on 2010 production, but let me give you a sort of stages on the project. It's completed only subsea installation work, we just finished drilling the last of redevelopment well, the topsides are complete in Abu Dhabi and we're planning to load-out in the next -- in during August. So hopefully, that answers your question.

Operator

Mr. Manzoni, there are no further questions. Please continue.

John Manzoni

That's very good. Well, I think we've answered all the questions. Ladies and gentlemen, thank you for taking the time to listen. I hope that's been helpful to you, and we will look forward to updating you again in the third quarter. And meanwhile, I hope you have a great summer. Thanks very much.

Operator

Ladies and gentlemen, this concludes the conference call for today. Thank you for participating. Please disconnect your lines.

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Source: Talisman Energy Q2 2010 Earnings Call Transcript
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