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Talisman Energy, Inc. (NYSE:TLM)

Q2 2009 Earnings Call

July 29, 2009 1:00 pm ET

Executives

John Manzoni – President & Chief Executive Officer

Phil Dolan – Senor Vice President of Finance

Hollie Castro – SVP, Corporate Services

Scott Thomson – Executive Vice President, Finance & Chief Financial Officer

Paul Blakeley – Executive Vice President, International Operations (East)

Ronald J. Eckhardt – Executive Vice President, North American Operations

Paul Smith – Executive Vice President, International Operations (West)

Richard Herbert – Executive Vice President, Exploration

Analysts

Brian Singer – Goldman Sachs

Mark Polak – Scotia Capital

Andrew Fairbanks – Banc of America-Merrill Lynch

Martin Molyneaux – FirstEnergy Capital Corp.

Benjamin Dell – Bernstein

Andrew Potter – UBS Securities

Chris Theal – Tristone Capital

Brian Dutton – Credit Suisse

Carrie Tait – National Post

Operator

Welcome to the Talisman Energy, Inc. second quarter results conference call. At this time all participants are in a listen-only mode. Following the presentation, we will conduct a question-and-answer session. (Operator Instructions).

This call contains forward-looking information. Material factors and assumptions were applied in making the forecast 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 29, 2009, news release and Talisman’s most recent annual information form which contains additional information about applicable risk factors and assumptions.

I would like to remind everyone that this conference call is being recorded on Wednesday, July 29, 2009, at 11 AM Mountain Time.

I will now like to turn the conference over to Mr. John Manzoni, President and Chief Executive Officer of Talisman Energy, Inc.

John A. Manzoni

Ladies and gentlemen, welcome and thank you for joining our second quarter conference call. With me today in Calgary are the management team, Scott Thomson, Phil Dolan, Ron Eckhardt, Paul Blakely, Paul Smith, Richard Herbert, Bob Rooney, and Bob Redgate, and Hollie Castro who is taking up the role of SVP Corporate Services when Bob Redgate retires in mid August, so welcome to Hollie. You may also have seen that Ron Eckhardt has decided to retire from the company, and he will also be leaving us in early September.

Since this is the last quarterly conference call for both Ron and Bob, I’d like to thank them both today for everything they’ve done for the company over many years. We will miss them, and we wish them the very best for the future. In light of Ron’s retirement, I’ve appointed Paul Smith to take over Ron’s responsibilities in North America, and Nick Walker who currently runs our UK operations will step up and run Paul Smith’s existing portfolio of International Operations – West. Both of these appointments will be effective in early September, and I know that both Paul and Nick are very excited about their new roles.

Now turning to second quarter results, I think we’ve delivered a very solid set of results, and I continue to be encouraged by the progress we’re making in moving our strategy forward and establishing a firm base for the future. Net income for the quarter was $63 million, although we benefited to the tune of $477 million from gains on the asset sales we made during the quarter. The net income excluding the sales gains reflect of course the negative mark to market impact of our hedging programs.

Earnings from continuing operations, which strips out both the gains from sales and the unrealized components of the hedging programs, were $135 million this quarter, down from $294 million last quarter. This mainly reflects the rolling off of some of our oil hedges which reduced the earnings from operations by about $300 million after tax quarter over quarter. These hedges were the $90 puts we had in place on some of our oil production which rolled off at the end of the first quarter, but we offset a large amount of this reduction with lower dry hole costs, lower depreciation charges, and lower operating costs.

Cash flow for the quarter was $900 million, also down from the previous quarter by about $400 million largely due to those same oil hedges not being in place. Free cash flow for the second quarter after investing activity was about $1.4 billion, benefiting from the sales we closed during the quarter and giving us a very strong balance sheet position which Scott will discuss in detail in a moment.

In total for the first half, we have seen positive free cash flow of just over $1.8 billion, helped of course by dispositions. We’ll continue to take actions to focus our portfolio, but are not expecting the same level of dispositions during the second half. Based on our current projections and of course excluding any inorganic actions we might take, we see positive cash balances at year end, although not quite to the extent that we have today.

Turning to operations, I’m delighted with our safety performance so far this year which is nearly 50% better than last year in terms of lost time and injury frequency. This is important because it signifies the real focus on operations which of course underpins everything that we do. Production for the quarter was 424,000 barrels a day, down from the 450,000 we reported for the first quarter, although production from continuing operations was up 2% from this time last year and is up 6% year to date.

In terms of absolute levels of production in Q2, we expected a drop as we entered the shutdown season in the North Sea although two aspects of our production disappointed us this quarter. First was that in April we had an unplanned shutdown on the Claymore field in the UK which I think I mentioned in our last call and which reduced our production for the quarter by about 4000 barrels a day, although this issue is now resolved. And the second was the operational performance of the Rev Field in Norway which is an issue both on Rev itself and on the Armada platform which we don’t operate. Both of these aspects are being worked to improve the overall efficiency going forward.

Third quarter production levels will be below the second quarter levels, again because of planned shutdown activity, but looking forward with what we see today, I see no reason to change our guidance for the year, which as you will recall centers around 430,000 barrels a day.

Just before handing to Scott, a couple of other aspects of the results I want to draw your attention to. First is dry hole costs, which you’ll see this quarter are relatively low at $51 million certainly compared to the last quarter. We benefited from the sale of some credits in Alaska this quarter which offset the dry hole costs by around $35 million in the number we’ve reported. Dry hole costs in the quarter include the Canon well in Norway as well as some wells in North America.

You’ll also see that our absolute operating costs are down both from last quarter and the equivalent quarter last year. Unit costs are up slightly from last quarter, but this has to do with the production levels rather than the cost levels. We continue our internal focus on actions to reduce costs, and we’re starting to see results in particular in the UK cost base, but also in North America, we’re good making good progress on our lean programs across the business which are leading to efficiencies in many areas. We’ll continue to put high priority on these cost initiatives, and I’m expecting continued progress through the rest of the year.

Now, I’d like to turn to Scott to say a few words about our balance sheet, cash position, and hedging programs.

Scott Thomson

I’d like to make some comments about our results and cash flows, our debt position, progress we’ve made in focusing the portfolio, and finally our hedging position. While the environment continues to prove challenging, our results and cash flows for the period were solid. Earnings from continuing operations, which exclude the after-tax impact of unrealized mark-to-market movements from commodity derivatives, were $135 million in the quarter, compared to $294 million in the first quarter of 2009, primarily because after tax realized gains from our hedging program were $300 million more in the first quarter of 2009 relative to the latest quarter. The reduction in hedging proceeds was partially offset by higher realized prices and lower dry hole expense.

Compared to the second quarter of 2008, earnings from continuing operations has decreased by approximately $650 million, reflecting the 49% year over year decline in realized commodity prices, partially offset by realized gains from our hedging program and lower royalties and taxes.

Cash flow from continuing operations was approximately $900 million in the quarter compared to $1.3 billion in the immediately preceding quarter due principally to the lower hedging proceeds noted above. Year to date, we’ve generated $2.2 billion of cash flow fro continuing operations compared to $2.7 billion in 2008. As John mentioned, we’re seeing positive results from our initiatives to reduce costs with both absolute and unit operating expenses showing a reduction relative to the second quarter of 2008.

While a stronger Canadian dollar against the British pound also contributed to lower operating costs, all regions have prioritized cost reduction initiatives and have shown results. We expect to continue to realize savings throughout the second half of 2009 with initiatives including reduced rates from suppliers, lower discretionary expenditures, and improved operational efficiencies.

Exploration and development spending year to date was $1.8 billion, of which approximately $550 million was spent in North America, $300 million on development activity in South East Asia, and approximately $450 million on exploration excluding North America. A significant majority of our North American spend was on unconventional activity and given our encouraging results, we now expect to allocate more capital for the Marcellus in 2009.

Net debt declined from $3.9 billion at year-end to $2 billion at June 30th, due principally to $1.3 billion of proceeds from asset sales that closed during the quarter. In June, we further enhanced our liquidity position with the issuance of US $700 million, and ended the quarter with debt to cash flow of approximately 0.8 to 1, and debt to debt plus equity of 27%. We have no current draws on our approximately $2.8 billion of bank lines and have few near-term maturities, so our balance sheet is solid.

Excluding any acquisitions we might need to fund, we expect to end the year with a positive cash balance, although not at the $2.3 billion level. We always knew that cash coming into the company in the first half of year would be greater than the second half of the year as a result of our hedging program and the timing of the closing of our after sales. We have successfully positioned Talisman to continue to fund our 2009 capital program and provide the flexibility to pursue additional organic or inorganic growth opportunities in 2009 and 2010 even if commodity prices remain depressed.

During the quarter, we entered into an agreement to purchase for approximately $200 million the outstanding shares of Rift Oil which is highly prospective exploration licenses Papua New Guinea. In addition, we have agreed to acquire an interest in block 9 in the Kurdistan region of northern Iraq which offers access to additional plays in the region.

Our objective of focusing the portfolio continues. During the second quarter, we closed three transactions—our Southeast Saskatchewan assets, our Trinidad assets, and a portion of our midstream assets for aggregate proceeds of $1.3 billion. Since we introduced our new strategy in May 2008, we sold assets for proceeds of $2.5 billion while divesting only 27,000 barrels per day of production. These proceeds will allow us to continue to accelerate the implementation of our strategy in a fashion that maintains balance sheet strength. We will continue to evaluate additional opportunities to focus the portfolio; however, we will only proceed with additional dispositions if the value received and the strategic rationale makes sense for Talisman.

Our commodity derivative contracts in 2009 and 2010 will continue to protect our cash flow. We’ve protected 76,000 barrels per day or 35% of our remaining estimated 2009 oil production with collars at a floor of approximately $74 per barrel and a ceiling of approximately US $101 per barrel. In 2010, we have 50,000 barrels per day hedged with collars at a floor of approximately $52 per barrel and a sealing of approximately $72 per barrel.

For North American gas, we protected approximately 400 million standard cubic feet per day or approximately 50% of our remaining estimated 2009 North American production at a price floor of approximately $6 ACO. In 2010, we protected approximately 300 million standard cubic feet per day at prices again at approximately $6 ACO.

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

John A. Manzoni

Before your questions ladies and gentlemen, let me say a few words about the outlook. Oil prices although a little volatile appear to be settled at the $60 to $70 level for now. This is in line with our medium term projections and forms the basis for our investment plans which we will finalize later this year. Gas prices continues to be depressed, and it’s possible that they will remain that way well into next year. Our projections assume these prices in the medium term, and we’re taking steps to ensure we continue to have a healthy business in the current business while retaining options should it prove to be better than that.

Our balance sheet is strong as Scott said, and while we are looking for opportunities to strength the portfolio in both Asia and in North America, we’ll continue to maintain discipline as we assess them, and we won’t act unless we see real value. Meanwhile, we continue to great results in our shale plays here in North America. In the Marcellus, we have drilled and completed four wells which continue the improving trend. The wells all look to be above our type curve assumptions and showed initial flow rates of around 5 million cubic feet per day. We’re now producing and selling more than 30 million cubic feet per day from the Marcellus from 10 wells and plan to increase our activity through the rest of the year to drill a total of 50 wells by year end.

In the Montney shale, our recent wells in the Farrell Creek and Cypress areas are encouraging. We drilled a total of 5 wells in the quarter, and we will continue to build our activity over the rest of the year. In Quebec, we’re encouraged by the results of our vertical wells and plan to start our horizontal well later this year.

Turning to Asia, production from the Corridor field in Indonesia is above our projections for the first half of the year and continues to build. In the northern fields, in the PM3 Malaysia-Vietnam commercial area, we’ve ramped up oil productions since we commissioned the oil stream in March this year. We commissioned a dry gas stream just a few days ago which will allow us to ramp up gas production from the PM3 complex.

As Scott mentioned, in June we entered into an agreement to acquire Rift Oil, a small company focused on gas in Papua New Guinea. We see the opportunity to create a very low cost gas aggregation strategy in PNG which will allow us to create export options for that gas.

Our exploration program continues to make progress. We are close to target on a number of important wells, and we have seen early success in some of them. Huron in Columbia has found hydrocarbons, and we are just completing testing it now. In the North Sea, the Shore well in the UK has found hydrocarbons and is in a similar geology to the Godwin discovery and the Kaley discovery before that. Revling in Norway also a commercial discovery, and we’re currently establishing the next appraisal location. During this quarter, we can look forward to more news from wells in Peru and Kurdamir in Kurdistan both of which are close to important milestones.

In summary, I think second quarter has been a valuable period for us to consolidate our strategic direction. We’ve secured the financial capacity to improve the portfolio if the opportunity arises. We continue to make progress on proving up and moving to development our sale portfolio, and we’re building production in Asia. We’re seeing success in our exploration program with some important results due in the next month or so. All of these actions are moving our business in the right direction, and internally we continue to focus on cost and performance to strengthen the foundations of the business.

Ladies and gentlemen that’s enough from me. Now we would be very happy to answer your questions.

Question-and-Answer Session

Operator

Ladies and gentlemen, we’ll now conduct the question and answer session. (Operator Instructions). Your first question comes from the line of Brian Singer from Goldman Sachs.

Brian Singer – Goldman Sachs

I was wondering as you look out from an acquisition perspective whether the Rift deal puts you where you want to be in terms of Southeast Asia gas aggregation or whether that’s an area where you would look more actively for additional transactions.

John A. Manzoni

I think it’s certainly a very good start, Brian, but let me turn to Paul Blakeley to see if he has got any more perspectives to offer.

Paul Blakeley

Rift oil it is an excellent opportunity to acquire low cost gas, but importantly it’s also in a low cost on-shore environment which is one of the features and qualities that we like very much in what is really quite an under-drilled and highly prospective basis, so all of those aspects we like a lot, but it is also fair to say that we continue to look to grow the business in other of our existing areas of activities, so for example of course earlier this year, Vietnam represented another opportunity to get into a very prospective gas basin, so those are all the things that we are looking at, both through exploration, license activity, but also small acquisitions that we can aggregate to and entirely consistent with our overall Asia strategy.

Brian Singer – Goldman Sachs

Do you anticipate further action in Papua New Guinea or not?

Paul Blakeley

It’s certainly possible that that we will be able to build beyond where we are today, but at this point in time, we’re confident to close this deal and to get on with some seismic and drilling activity to confirm there is also potential.

Brian Singer – Goldman Sachs

With regards to the Marcellus, any changes to your updated thoughts and timing of delineating your New York portion of your acreage, and then with the regards to the strong results that you see in terms of well cost and initial production rates from ostensibly the most recent Pennsylvania wells, can you talk about the repeatability of the improved results?

Paul Smith

On New York, we are still waiting for a finalized version of the environmental report and the interpretation of that and what that will mean in terms of regulations around drilling and fracking for shales. We are hoping that that will be done by the end of this year and hoping to be drilling wells early next year, so until then, really no progress on the New York acreage. In Pennsylvania, you’re right. All of the wells have been in Pennsylvania. They’re proving to be very repeatable, no disappointments at all, and in fact, we’re continuing to see improvement in all our well results, and as John said earlier, recent wells have been over 5 million a day, some of them well over that; however, we haven’t got 30-day IP results just yet, but by the end of the year, we’ll have around 15 wells with almost 6 months of production, and we will be in a much better position to reassess our EURs per well.

Operator

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

Mark Polak – Scotia Capital

With the rates that you guys are mentioning on Montney-Marcellus, I’m curious how many stages are being completed in those wells, and also if you can give me a sense what the recent wells have cost in the Montney core area?

Ron Eckhardt

Number of stages in Pennsylvania, we started at around 8 stages per well, and we’ve just pumped a few at 10 and 11 stages which does contribute to the rate. I’ll give you another plug here while we are at it. Just in terms of efficiencies, when we started out, it took us 10 days to pump 16 stages and most recently we pumped 32 stages in 10 days, just showing how drilling on pads and kind of applying our lean velocity is really making a difference in this area, and in the Montney core, costs continued to come down there, and in fact, we’re pushing towards low $3 breakeven gas price in the Montney core area, again through lean initiatives and all of the things that we are putting in place to drive those cost down. Of course, industry is helping us out by lower supply costs.

Mark Polak – Scotia Capital

Now that you have hit your $4 million target in the Marcellus, do you think we’d see a leveling off here or do you think there is further downside potential below that with more efficiencies?

Ron Eckhardt

I believe there are more efficiencies, and they come in all kinds of areas, but water handling for sure over time will drive down cost. The preset rig has made a big difference in well times, and again bit selections continue to get better. We’re experimenting with different ways of cementing up in the Montney core that may be applicable down in Marcellus. I think the minute you stop improving, you go backwards in this game, so yes I do expect continued improvement.

Mark Polak – Scotia Capital

The Kurdamir-1 well in Kurdistan, I was curious on your progress so far and if you’re running into any issues?

Paul Smith

Clearly, Talisman has been very involved in the planning of this Kurdamir-1 well, and we introduced a number of changes to the program which should help reduce the drilling risk and improve the opportunity to be successful, and that’s bearing out to date. We are now at casing points immediately above the primary targets in the timeframe and costs are what we anticipated, so we’ve made a lot more progress. These are very challenging wells indeed, but so far I think are much better.

Operator

Your next question comes from the line of Andrew Fairbanks with Banc of America-Merrill Lynch.

Andrew Fairbanks – Banc of America-Merrill Lynch

I had a question on Columbia. You’re starting to see some encouraging results there, and while it’s early days, I was just curious to get your thoughts on what you think the shape of that opportunity set is going to be going forward. Do you see the country being predominantly medium larger reservoirs or a mix between light basins that you have as well some of the heavy oil leases required earlier?

Richard Herbert

Andrew, obviously we said a few words on that well, and we are just finishing the testing on that well now, so we don’t have any results to announce this quarter, but I think fairly soon we will have completed the operations in the well, and we will have analyzed results, and we will be able to speak fully about what we have actually found and what it means for that discovery and for that trend. Just addressing a little bit of your question about Columbia, Talisman has taken a very large acreage in Columbia. Part of that trend is in the foothills to the Andes which is where the oil is drilling, and we know from this drilling in that trend that this is primarily a gas because these are very deep type reservoirs, and we won’t be seeing the sort of flow rates we get where we can cycle the gas and recover the condensate and that’s looking very encouraging with the results of Huron. Our other acreage in the basin is in the more conventional oil claves, and this ranges from lighter crude near the mountains out into a zone which is very unexplored, likely to contain heavy oils, but I think we are looking at quite a range of fluid types. Still early days for the exploration out in the heavy oil zone, that will be 2 or 3 years before we really what we are looking out there, but we got some very encouraging learning with some wells.

John Manzoni

To add to Richard’s point, we are exploring with enough running room to create for us a new core area, and I think what Rich described has all of those characteristics for us.

Andrew Fairbanks – Banc of America-Merrill Lynch

I’m curious what your 2010 hedging philosophy is going to be here.

Scott Thomson

For 2009, let’s take gas and oil, and as John said I’m probably not going to give you too much information on what we are thinking going forward, but I know you always ask, but 2009 on the gas side we are about 50% hedged North American gas at around $6 ACO, at 2010, it’s around 40%, and remember when we are at those levels, the economic exposure is around 50-60% so it’s essentially in 2009. In particular, almost 100% economically hedged. On the oil side, we are 35% hedged in 2009 and much less in 2010, about 20%. As we put together the 2010 and 2011 capital plan, we’ll continually assess the hedging position. We’re not going to do anything to speculate, but we would consider doing things to predict the balance and predict cash flow going forward, so I think I’ll leave it at that in terms of our plans for 2010.

Operator

Your next question comes from the line of Martin Molyneaux – FirstEnergy Capital Corp.

Martin Molyneaux – FirstEnergy Capital Corp.

Just coming back to the North American operations, Ron, with the Marcellus, do you think you’ve optimized the horizontal well length and the number of fracts over that horizontal length?

Ronald J. Eckhardt

It’s a really good question, and the simple answer is no. We continue to see improvements by drilling longer and putting more fracts per well, and we will continue to push that envelope and find the other side of the curve. The other thing we need of course is understand more about what the declines are a couple of years out and get more information on drainage areas, fract spacing between wells and inter-well, and all of that will come out in time.

Martin Molyneaux – FirstEnergy Capital Corp.

Can the same thing be said for Canadian Montney?

Ronald J. Eckhardt

There are a lot more wells in the Montney core area, and I think that’s starting to settle into an area people are pretty comfortable with. Montney shales of course is a brand new area, and again because there is that really difficult section above the shale zone, which takes quite a while to drill, that will put favor on drilling longer horizontal sections, so you get more bang for your buck, and I think industry just like in Horn River will be looking to drill very long horizontal wells with a lot of stages in them.

Martin Molyneaux – FirstEnergy Capital Corp.

The horizontals in Quebec, any thoughts on what those things will cost?

Ronald J. Eckhardt

Quebec is a bit like drilling on the moon; however, there is more equipment there than there was two years ago. I hoping we’ll get both of those wells down for around $12 million, and we’ll see how they go. They’re pretty much lined up, so we should be able to do. We know a lot more about drilling in the area than we did.

Operator

Your next question comes from the line of Ben Dell with Bernstein.

Ben Dell – Bernstein

My first question is around natural gas in Canada. Have you given any thought to the [inaudible] project and whether or not you’ll be interested in committing gas volumes to that?

John Manzoni

It’s predominantly being discussed in the context of Horn River basin, Ben, and we are not in there. We’re looking at it in the background, but we’re not in any advanced discussions.

Ben Dell – Bernstein

Secondly, on the change to reserve accounts at the year end, have you given any thoughts what it would remain in terms of your part bookings, total reserve bookings, and reserved replacement rate?

Ron Eckhardt

We’re looking very closely at the new SEC rules and interpreting them with along industry, and we do believe that there is more opportunity to book PUDs between proven wells, and we will pursue that; however, it is still pretty early days, and a lot of the consulting companies as well as us are looking at what really will be required by the SEC. Having said that though, Talisman has very low PUD percentage overall, and I expect over time that will go up with our unconventional strategy.

John Manzoni

We’re anticipating and indeed have signaled that both through the drill bit and the strategy as Ron said with sensible increase in crude undeveloped, but I expect that our S&D cost will be reduced by 30-50% in 2009. We are not going to be silly in interpreting all of the rules. We’re going to be very sensible doing all of that, both with PUDs and with the new rules, and those discussions are still ongoing, but I still believe that we will be seeing significant improvement in those metrics.

Ben Dell – Bernstein

Do you mind me asking if you can quantify what you mean by sensible increase in PUD?

John Manzoni

We are sitting at about 16 or 18% total today. The range is between 35-70%, and we are not going to go to the top of that range. We are going to be conservative in how we do it, and we will build our way towards some sensible level which allows us to drill out those PUDs in a sensible period of time.

Ron Eckhardt

The only thing to add is if you look at PUDs to your total proven book in the unconventional world, when you start out, they can be significantly higher, but once you get going in a steady state way, you need to be drilling your PUDs up in about 5 years, so your PUD percentage is actually a very strong function of how big your base is and how aggressive your burn rate is.

Ben Dell – Bernstein

Can you give some color on the acquisition market, what you are seeing in terms of pricing? Have seen with the rebound in the commodity prices, fellows become more resistant disposing of assets. Does that change your strategy towards asset deals or corporate deals as you look over the next 12 to 18 months?

John Manzoni

Actually, the level of activity that frankly we anticipated possibly did not materialize because just at the critical moment, markets opened, equity market opened, credit market opened, and everybody sort of refinanced or many people refinanced in that market, so we found that while we were expecting to some degree more activity than I think has been the case, that’s not to say there isn’t any, but there wasn’t quite the level that we expected, I think people have refinanced and have sort of hunkered down. How that plays out in the rest of the year given a gas forecast which I think is now becoming a more consensus view that we may be at these levels for a more extended period of time. How that plays out for the rest of the year, I think we will just have to wait and see. I would say to you that we look at it a lot over time. Scott and his team are looking at almost everything that moves all the time, and we continue to be searching and looking, and we will maintain the discipline that I think we’ve demonstrated so far. We are not just going to leave. We have the capacity, and we’ll act when the value looks right. We’ll have to wait and see. If the end of the year turns out to be what we thought might happen around the middle of the year, then may be more opportunity becomes available, but let’s wait and see and see how that goes.

Ron Eckhardt

We cautiously put ourselves in the position we are today where we have the flexibility to spend either organically or inorganically, so this is a conscious decision. We feel good about where the balance sheet is, and number two from an acquisition perspective, we’re not going to do something just because of financial distress as we are seeing in the Marcellus and Montney. Being the best rocks and low costs are extremely mainly important, so if we do an acquisition, we’re going to do something that makes sense with strategy and the cost perspective.

Operator

Your next question comes from the line of Andrew Potter with UBS Securities.

Andrew Potter – UBS Securities

I have a quick question on Columbia, just following up on an earlier one. Maybe you can give a little bit of context for the discovery on the Niscota block. I know you can’t talk about the actual size yet, but even a little bit of color on what the pre-drill expectations were and second relating to that just on infrastructure, at least from what I can see, it seems like there should be a lot of under-utilized infrastructure from the Cusiana field and other fields in the area, so just wondering if that’s the case and then if that means that the cycle time here could be relatively short or this is really a four to five year development timeframe if it indeed works?

Richard Herbert

On your first question of what were the pre-drill expectations, it was clearly the trend of hands in front. The potential of that could go further north [inaudible] I think and of course this well has found gas condensate. He’s put a number of reservoir levels in it, and I won’t say it’s coming exactly as expected. It’s very complex natural geology, and you never quite get what you expected, but it certainly matched our expectation. Clearly there will be a period now of analysis of the results. We need to look at the next steps, go over the structure, and we’ll be planning some further drilling. All of that will need to be worked out. We will be looking with our partners at the opportunity. To me, in terms of an early production, we’re looking something faster than 5 years, but I think we have to be realistic about our full field development.

Operator

Your next question comes from the line of Chris Theal Tristone Capital.

Chris Theal – Tristone Capital

Can you give a little bit more color on the 3X well at HSD in Vietnam? Where was this relative to block B? Your perceptions, how did they change with that well and the results?

Paul Blakeley

In the sense of Hai Su Den development, the drilling that we have been doing and continues to do and starting with 3X. 3X was suspended and not abandoned. It was an exploration step-out well that moved into one of the more distant fault blocks within the overall Hai Su Den feature. You referred to block B, and this was a test of D&D, so the more distant fault blocks. We encountered a long hydrocarbon column in the well, it tested dry oil, but not at that the rate that we had hoped for, and of course we are aware of this from many analog fields in the region that encountering fractures is the key to production rates in these fractured basement rocks. History also shows that there are quite a lot of variability at this point out, so disappointing rates but the encouragement was that demonstrated oil presence throughout the whole of the feature and down to the deeper depths than we had encountered before, so some encouragement, and it has absolutely no impact on the early production scheme, the early development of block B, but it just helps us understand some more about the overall complexity within the basement than we anticipated. Essentially, it has not changed our views.

Chris Theal – Tristone Capital

With respect to Canada, when you look at gas prices in Canada, beyond your physical and financial hedges, do you see shutting in gas through the third quarter? We seems to be on a growing trend of that as we get through Q2 here. What the status on Talisman?

Ron Eckhardt

The simple answer is not at these prices. Now if we see further deterioration and when gas prices get below our variable cost, we would look at shutting in, but we are quite a ways away from that yet. Hopefully we don’t get down there, but if we do, we’ll take the appropriate action.

Operator

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

Brian Dutton – Credit Suisse

It looks like cash taxes were a factor in your second quarter results, so I was wondering if you could give us some color in terms of how we should be looking at cash taxes for the balance of the year from an operating earnings perspective, if the current physical environment continues.

Scott Thomson

The difference between the cash tax in the first quarter and the second quarter was about $50 million, I think. That makes sense given the higher net backs in the UK in particular, I think, our realized net back was $7 higher in the UK and also South East Asia had higher volume and higher net backs as well, so that’s the rationale for the cash tax increase. In North America, we had pretty significant mark to market losses, and that’s why you’re seeing deferred tax impact, but from a cash tax perspective for the last half of the year, I would suspect that we are on a pretty similar path to where we were on the first six months of the year. I don’t expect any big changes. There is a cash tax payable that is going to be due in the third quarter that may impact cash flow a little bit, but from a current tax expense, I wouldn’t suspect anything much different than the first six months.

Operator

Your next question comes from the line of Carrie Tait with National Post.

Carrie Tait – National Post

You mentioned in the formal remarks that you expect to allocate more cash in the Marcellus in 2009. I’m wondering what that’s compared to, about how much, and when you might see that.

John Manzoni

I’m not sure, Carrie, we have actually articulated exactly how much money that we are spending Marcellus. The implication would be that we’d put one more rig in to the Marcellus in the second half of the year. I’m not changing for the moment our overall $3.6 billion capital spend for the year. It may be modestly above that depending upon the actual outcome of the level that we spend in the Marcellus, but we haven’t given any specific numbers. Think in terms of rigs, and we’d probably drop one more rig through the second half of the year.

Operator

There are no further questions at this time. Please continue.

John Manzoni

Ladies and gentlemen, thank you for joining us for our second quarter call and thank you for your questions. I hope we have answered them satisfactorily. We should look forward to updating you again in the third quarter.

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Source: Talisman Energy, Inc. Q2 2009 Earnings Call Transcript
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