Good morning. My name is Christie, and I'll be your conference operator today. At this time, I would like to welcome everyone to the Talisman Energy Inc. 2011 First Quarter Results Conference Call. [Operator Instructions]
This call contains forward-looking information. Certain material factors and assumptions were applied in making the forecasts and projections to be discussed in this call, and actual results could differ materially from those anticipated by Talisman and described in the forward-looking information. Please refer to the cautionary advisories in the May 4, 2011, news release and Talisman's most recent annual information form, which contain additional information about the applicable risk factors and assumptions.
I would like to remind everyone that this conference call is being recorded on Wednesday, May 4 at 8:30 a.m. Mountain Time. I will now turn the conference over to Mr. John Manzoni. You may begin your conference.
Thank you, Christie. Ladies and gentlemen, thank you for joining our first quarter conference call. I'm joined here today, as usual, by the management team who will help answer your questions after Scott and I run through the main aspects of the results for you.
The first quarter certainly saw some volatility in the oil price, of course, driven by the political uncertainty in North Africa and in some parts of the Middle East. Those events I think have pushed prices above where fundamentals would otherwise suggest, but there is still some element of security premium in the price. Quite how long the situation lasts is subject to events, of course, but in the long run, we look through it to the fundamental supply-demand balances and continue to believe that prices in the $80 to $95 range makes sense.
One aspect of this quarter's results is that the hedges we put in place at the end of last year did not contemplate those events. And thus, the income for the quarter is subject to mark-to-market losses as a result, and we'll come to that in a moment.
Gas prices have rallied a bit most recently, as storage balances are in the normal range. But we're still in an oversupply situation and therefore, we're not banking on much strength in prices above where we are today throughout this year. We continue to believe that in the medium term, the market will settle the marginal cost pricing, which is modestly above today's prices. And that just emphasizes that we need to be in only the best place, and we believe that we are.
Moving now to the activities of the quarter and the numbers. I'm very sad to report that we had a fatality in our operations this quarter. Our highest priority is to continue to build systems into our operations which improve safety. We're making good progress on those systems and the metrics which demonstrate that are improving all the time, but it is nonetheless very sad to have to report a fatality.
In terms of the numbers, it's quite a complicated quarter because there are several things happening all at once. First, we reported in IFRS for the first time, which has changed quite a lot in terms of how we report, although its cause has not changed any of the underlying activities.
Second, we've reported in U.S. dollars for the first time. Given the approximate parity of the Canadian dollar to the U.S. dollar, it's a pretty good time to make that change. It's a better reflection of the underlying business drivers for the company, and that's why we've changed.
Also in the numbers this quarter, we've reflected the recent tax change in the U.K., which was announced rather suddenly in March. Scott and I will draw your attention to the relevant aspects of these changes as we go through, but let me spend a moment on the main activities of the quarter.
In terms of the underlying operations, production was 444,000 barrels a day for the quarter, which is about 14% higher than a year ago on a continuing operations basis. So we're starting to see the growth that we've been talking about for a while, mainly from the inclusion of our new Colombia operation, which closed this quarter and from the shale plays.
You may recall that I mentioned the Yme project when we gave guidance for the year, which we were hoping to get sold by the end of April from Stavanger. Unfortunately, there's been no weather window to allow load-out, and it's still in there in Stavanger. This project continues to cause problems, and I'm frustrated by the quality of the work undertaken by our contractor, which is requiring considerable rework in the yard.
The good news, I suppose, is that we can take advantage of the platform being in the yard to complete the work faster than we would be able to do offshore. But I'm now anticipating that the field will be on stream by the end of the fourth quarter rather than July, as we had previously hoped. The project was one of the last ones before we introduced our new project management system into the company, which we started in early 2009. And I have to say, it's a poster child for why that was so important.
Right now, I'm not going to change our guidance despite the platform being late. I'm specifically holding my initial guidance for you today at 5% to 10% underlying growth, excluding Colombia, although the Yme issues are pushing us toward the bottom of that range right now.
In parting, I should remind you that during the second and third quarter, our production drops as we undertake scheduled maintenance in particular, across the North Sea.
In North America, we completed the Farrell Creek transaction with our partner Sasol for $1.05 billion at the beginning of March and came to agreement on a second transaction in our Cyprus A assets for exactly the same price. We'll move forward with the development of those resources, utilizing the carry provisions in these two deals both together.
We've ramped up to 8 rigs in the Farrell area, and I expect to exit the year with 10 rigs. In parallel, the feasibility study for the gas-to-liquids project is ramping up quickly, and I'm very excited about seeing how that unfolds over the course of the next 15 to 18 months.
We're ramping up operations in the Eagle Ford. We currently have 5 rigs operating, converting 2 dedicated completion crews and have begun completion operations on the inventory backlog that we built up. We expect to exit the year with 8 rigs operating in the Eagle Ford.
In the Marcellus, operations continue as planned. Average production for the quarter was 350 million cubic feet a day, an increase of about 30% over the fourth quarter last year. And as we've said before, this activity continues to be economic in particular, as the gas prices have recently been slightly stronger.
It's worth mentioning Québec since there's been quite a lot of press commentary on this over the last quarter. As you know, the government responded to the back report by setting up a commission, which is now in the process of being appointed and whose remit is to study the shale business and determine the conditions under which it should proceed. In addition, they outlined some principles on which the tax and royalty structure in the province would be set.
Talisman's position on this is all quite clear. We believe we can make sufficient progress under the commission, although we recognize that we'll need to move carefully and deliberately and work in close cooperation with them as we plan and execute our activity. I'm hopeful that, in fact, we will be able to undertake some completion activity this year, and we're in discussions with the government of Québec right now today to see whether that will be possible.
We also believe that with careful discussion and collaboration, the tax and royalty regime can be conducive to progress. It's important to remember that right now, there is no commercial viability in the Québec gas industry, and it will take time and care and, of course, good test results to move it to a place where it can progress. We're going to work through the association in Québec to move this forward over the course of the year.
Elsewhere in the world, we're making good progress in our drilling. In Papua New Guinea, we drilled 2 successful wells at the end of last year, one of which proved significant upside in the Stanley field. We're now drilling a development well in the field for an early condensate stripping scheme, which we're engineering right now.
In Colombia, we're now drilling our sixth stratigraphic well in Block CPE-6 and have defined a program of up to 8 more wells to be drilled this year, together with 3D seismic acquisition as we appraise that block further.
Following the promising Akacias discovery late last year in Block CPE-09 with Ecopetrol, we're preparing for a 3D seismic program and at least 2 appraisal wells this year. And we'll also drill another prospect in the same block this year.
In Block CPE-8, several of our seismic contractor employees were taken hostage in early March. One worker is still in the hands of the abductors, operations have restarted in that block under a much enhanced security regime to complete a reduced seismic program.
Finally, in Colombia, 2 rigs are working on development drilling in the Piedemonte block, which we bought from BP jointly with Ecopetrol.
Turning to the numbers. As I've mentioned, underlying production has grown 14% from the prior year and 9% from the prior quarter. Relative to the equivalent quarter a year ago, we've sold about 46,000 barrels a day of production.
Cash flow for the quarter was $811 million, which was higher than both the prior quarter and the previous year. This reflects higher prices, offset by a significant under lift during the quarter and the impact of the tax situation in the U.K.
The impact of the under lift, which coincidentally occurred in a number of places all at once this quarter, was about $80 million. In fact, the situation has already been normalized, so that should come back during the current quarter.
Capital spending on exploration and development activities remains on track for what we've told you, that is about $4 billion of cash spending this year. I sense we may see a little upward pressure on this over the course of the year, but it's too early to make any predictions on that today.
We reported a net loss of $326 million for the quarter, which was lower than the equivalent quarter last year, but slightly higher than the fourth quarter. There were 3 main influences on this number. First was the under lift, which I've already mentioned. Second was the unrealized mark-to-market losses on our hedges. Scott will detail where we sit on these. But against the first quarter of last year, the unrealized losses reduced income in the current quarter by more than $400 million. The third impact is the U.K. tax change. Scott will outline the detail but first quarter income has been impacted directly by about $250 million.
The tax change also created some impairments in the U.K. Going forward, I think it's important to remember that under IFRS, we're likely to see more volatility, as assets get written down and back again, as price forecast or other circumstances change.
The U.K. tax change also, of course, has an influence on future projects. We're in the process of revealing our development plans carefully right now, and I believe we may reconsider some of them. But I don't want to rush into that. We'll consider them carefully, and I plan to discuss them with the U.K. government before taking any action.
We did write off 3 exploration wells this quarter, TR1 in the U.K. was disappointing. The main Triassic reservoir flowed oil on tests, but not at sustainable commercial rates. There's a shallower section, which is actually a future tieback candidate.
Gnatcatcher in Norway, which we referenced I think in our fourth quarter call, was also taken this quarter. And we also wrote off the Romeo well in Pasangkayu, which was wet.
Costs were broadly flat this quarter to some extent, benefiting from the underlift despite the springing on the Auk North project in the U.K., which otherwise would have raised costs slightly in that business.
As a general comment on cost levels, we are anticipating a gradual tightening of capacity across the industry in service crews in North America, in offshore rigs in the U.K. and Norway and also, in steel availability as a result of the Japanese tsunami impacts.
We're largely insulated against these impacts because we've contracted ahead. And in the case of steel, we have ample stocks. So we're not currently seeing this general cost trend impacting our cost base significantly. As an example, we've contracted dedicated completion crews in both the Marcellus and the Eagle Ford, both at very good prices.
So now let me turn to Scott to talk about the balance sheet hedges and give you a little more flavor to some of the things I have mentioned. Scott?
Thanks, John. I'll review our financial results, balance sheet, acquisitions and disposal activity in the quarter and our hedging position. As John mentioned in his remarks, our results for the period were impacted significantly by three factors: the timing of oil liftings, the impact of commodity derivatives and the U.K. tax changes announced in March 2011.
I thought it would be useful to explain the impact of these items on the numbers before reviewing the numbers themselves. First, with the exception of the North American business, all of our operations are impacted to some extent by the timing of oil liftings, which caused oil inventories to increase or decrease from quarter-to-quarter. This quarter was unusual in that 1.9 million barrels where produced into inventory, taking the total in inventory to 3.5 million barrels.
Put that into context, in the same quarter of 2010, 400,000 barrels were produced into inventory. This buildup of inventory reduced income by $45 million and cash flow by $80 million in the quarter.
The second major impact resulted from our commodity derivative. Towards the end of 2010, we entered into contract, hedging 70,000 barrels per day of oil in collars with ceilings of between $92 per barrel and $98 per barrel, with the objective of securing cash flow. However, the unexpected rise in oil prices, which caused Brent to end the period at $117 per barrel, resulted in a loss from the financial derivatives, which negatively impacted net income by approximately $320 million during the quarter.
And from a cash flow perspective, our oil collars had a negative impact of approximately $65 million. Although we continue to have the same oil hedges in place for Q2, in the second half of the year, 20,000 barrels per day of $80 by $92 collars are replaced by puts and therefore, our upside to oil prices will increase.
The third major impact was the increase in the U.K. tax rate from 50% to 62%. While this change will undoubtedly impact investment decisions in the medium and longer term, the most significant short-term impact was on taxes and impairments. As a result of the changes, the company recorded approximately $25 million of additional current tax expense during the quarter as well as the $225 million deferred tax expense and impairments in the North Sea of approximately of $100 million.
So taken together, these three factors adversely impacted our net income during the quarter by approximately $650 million. From a cash flow perspective, the inventory buildup out of the money oil hedges and the U.K. tax changes had an impact of $170 million on cash flow in the quarter.
Now to the results themselves. Cash flow of $811 million was consistent with the first quarter of 2010 despite the sale of 46,000 barrels per day of production, as higher commodity prices and lower operating expenses were offset by higher cash taxes and the impact of the timing of liftings.
Compared to the fourth quarter of 2010, cash flow increased by approximately $150 million since revenues were higher yet cash taxes were essentially flat because of lower production contribution from Norway in Q1 relative to Q4.
Non-GAAP earnings from operations of $157 million were slightly higher than the first and fourth quarter of 2010, as higher dry hole expense, higher taxes and the impact of the timing of liftings offset higher commodity prices.
DD&A decreased by $12 million compared to the first quarter of 2010, mainly due to the impact of the timing of liftings, lower production in the North Sea and lower DD&A rates on some North Sea assets as a result of higher reserves. This was partially offset by increased production volumes in North America, although the assets in the shale business have a lower DD&A rate than the conventional activities.
Operating expenses decreased by approximately $50 million relative to first quarter of 2010, mostly due to the impact of the timing of liftings, but also the result of lower well intervention costs at Tweedsmuir, which were significant in the first quarter of last year.
Unit operating costs continue to decline in North America as a result of the transition to shale. The first quarter 2011 rate of $7.15 per BOE compared to $8.52 per BOE in the immediately preceding quarter.
Lastly, from a cash tax perspective, it's also important to note that this quarter, with the transition to U.S. dollars and IFRS, we have taken the opportunity to combine current tax and current PRT into one line item called current income tax on the income statement. Although at first glance, it may appear that current tax is up from Q4, in reality, the total current tax when you include the PRT impact, was $443 million in Q1 relative to $438 million in Q4, so broadly flat.
On the acquisition and disposition front, we closed 2 significant transactions during the quarter. In January, the purchase of a 49% interest in BP's Colombian operation was completed for a final cash payment of approximately $200 million, taking the final consideration to $800 million.
As we indicated in our 2011 guidance, Equion is contributing approximately 12,000 barrels per day of production, but since the transaction closed at the end of January, the full year contribution is likely to be 11,000 barrels per day.
In March, we closed the transaction to sell a 50% interest in our Farrell Creek assets to Sasol for total consideration of approximately $1 billion, comprising cash of $250 million and the remainder as a future capital carry. A second similar transaction with Sasol related to the Cypress A assets is due to complete in the third quarter of 2011. Importantly, we will be able to apply the carry from both of the transactions against the Farrell development, which will be on a faster timeline than Cypress.
At March 31, we had $1.3 billion of cash in the balance sheet compared to $1.7 billion at December 31, 2010. The reduction was due largely to a $350 million repayment of Canadian medium-term notes and the final payment on the Equion transaction of approximately $200 million, partially offset by the cash proceeds from the Farrell Creek transaction with Sasol.
Net debt was relatively unchanged, $2.5 billion. Capital expenditures, including exploration expenditure, which now under IFRS is expensed as incurred, was approximately $1 billion during the quarter, with $200 million spent on international exploration; $245 million on North Sea development, the largest items being Auk South and Yme; and $460 million in North America. Approximately 3/4 quarters of the North America spend was directed towards shale activity.
During the remainder of the year, we continue to expect that capital expenditures will modestly exceed cash flow from operations, but that of course depends on commodity prices.
Turning to our hedging program for 2011. On the oil side, we have 70,000 barrels per day hedged in the first half of 2011 in collars and 70,000 barrels per day hedged in the back half of 2011 in a combination of collars and puts. The first half program consists of approximately 41,000 barrels per day of Brent hedged in $80 by $92 collars and 20,000 barrels per day of Brent hedged in $84 by $97.50 collars.
The second half program consists of approximately 21,000 barrels per day of Brent hedged in $80 by $92 collars, 20,000 barrels per day of Brent hedged in $84 by $97.50 collars and 20,000 barrels per day of puts at $90.
For the second quarter, our economic exposure to oil prices above $97.50 is limited, especially in light of the recent U.K. tax changes. However, given put options replaced collars on 20,000 barrels per day of production in the second half of the year, our exposure to higher oil prices increases as we move throughout 2011.
In 2012, we have entered into collars for 20,000 barrels per day of oil production at a floor of $90 and a ceiling of $148 Brent.
On the gas side, we have approximately 200 Mmcf per day of physical and financial hedges in place for the first half of 2011 and 100 Mmcf per day, primarily in tight collars, with a floor of approximately $6 NYMEX for the second half of the year. This represents approximately 15% to 20% of full year North America production, and slightly more on an economic exposure basis. And we currently have no gas hedges in place for 2012.
Those are my highlights. I'll turn the call back over to you, John.
Thanks, Scott. Ladies and gentlemen, just before your questions, a reminder of the key points.
Big changes to our reporting this quarter, including IFRS, U.S. dollars, and a change to simplify by aggregating the North Sea. While all the numbers move around, nothing changes to the underlying business or cash flows as a result. Our production guidance holds for today, and we'll keep it under review depending on where we get to with the Yme project.
The quarter has been impacted by a number of quite big swings in terms of income, including unrealized losses on our hedging program, the change to the U.K. tax regime and an underlift, which is likely to have been corrected already by the second quarter. But underlying earnings are up on the fourth quarter and flat on a year ago.
The business is growing, and we're starting to see success in our exploration program especially in Papua New Guinea and Colombia, with some other big wells to come later in the year in other parts of the portfolio.
So ladies and gentlemen, that's the review of our first quarter results. Now I'd like to turn it over to your questions.
[Operator Instructions] Your first question comes from the line of Greg Pardy with RBC Capital Markets.
Greg Pardy - RBC Capital Markets, LLC
3 questions for me or for you rather. First is, Scott, could you touch on just your cash tax expectations for 2011, all in? Secondly, just wondering what is top of mind exploration now? And third, could you add maybe just a little bit of color around how the Eagle Ford program is going to unfold this year? Thanks very much.
Great. Thank you. So first is cash tax for 2011. We'll go to Scott for that. We'll go to Richard for the exploration excitement to come in the year. And we'll go to Paul to describe the Eagle Ford activities. Scott, cash tax for 2011?
Great. So on the cash tax. Just recap Q4 versus Q1, and I think that's important. Essentially, cash tax was similar between Q4 and Q1. So despite higher prices, we had somewhat lower production in Norway. In Norway, the tax is 78%, and so we have a benefit there. So that was why cash tax basically stayed flat quarter-over-quarter. As we think about full year 2011, not much different messaging than what we told you last quarter, which capital -- taxes are dependent on prices, capital and production. Our biggest exposure to taxes are in the North Sea, U.K. and Norway. We're expecting relatively flat production and relatively flat capital. So the impact on taxes will be dependent on prices. And if you look at consensus prices, $80 prices in 2010, I think the analyst consensus right now is about $105. You can take that increase and divide it by the average tax rate, it's probably to a pretty close 2011 tax estimate.
There you go, Greg. As helpful as ever. Let's move to Richard and the excitement for this year. What's going on this year in exploration program, Richard?
Yes. Greg, let me just focus on sort of 4 countries where we've got some big, sort of big activity this year. First of all, in Kurdistan, last year we drilled the Kurdamir well in Block 44, and we found a lot of hydrocarbons in that well. But due to various problems, we were unable to fully evaluate it. So we've now moved to the adjacent Block K39, and we're drilling the Topkhana well, which spudded at the end of January. And that's on a very big structure, and we should have results for that in the third quarter. And then we'll move back into K44 and re-drill the Kurdamir well. So that's Kurdistan. In Latin America, our major focus for drilling this year will be in Colombia. And we've got as I think -- as I'm sure you know, we've got sort of 2 major trends there. One is in the heavy oil trend in the south of the Llanos basin. And this year, we will be starting up an appraisal program on our Akacias discovery that John mentioned in Block 9. And we're now doing the permitting before we go back and drill at least 2 appraisal wells there at the back end of the year. And we're also going to drill some more exploration prospects. We're continuing to work in Block 6 with our operator, Pacific. And we're just completing the final stratigraphic well in the current program. We've put in an application to turn that block into a true E&P contract, so we can go back in the future and drill some real exploration wells and flow test them. And that activity should also be starting in around the fourth quarter once permitting is in place. And finally in Colombia, in the Niscota Block, we made the Huron discovery in 2009. And we are shortly going to spud an appraisal well on that, Huron #2 will spud in June and will be followed a third appraisal well. And then moving into Southeast Asia, in Indonesia, we've recently completed drilling the Romeo well in the Pasangkayu block. Since we've picked that block up in 2006, our excitement in it has diminished as we would see the seismic data and saw that it had limited prospectivity. But we're much excited about the South Makassar, where we have a number of production sharing contracts. And in July, we will be spudding the Lempuk-1 deepwater well, which will be our first exploration test in that basin. And finally, PNG, a good start to our drilling program there, with 2 discoveries. And we'll have 2 rigs running this year and a number of wells drilling there.
Thanks. Now finally, let's just get a bit of color on the Eagle Ford. Paul, a little bit of test on what's going on in the Eagle Ford right now?
Thanks, Greg. We spent most of the quarter, Greg, making good progress on building our organizational capacity in the underlying operational foundations to really ramp up in the Eagle Ford. We've increased our rigs from one rig, which is what we were running with at the beginning of December, to 5 rigs currently. We expect to sort of exit the year in the Eagle Ford at sort of 8 to 10 rigs towards the end of this year. Crucially, we've secured 2 dedicated completion crews. We've always said that we were not willing to use spot crews, given the very high rates. And so we've started to commence activities on the backlog of 16 wells that we've built up prior to commencing with our dedicated crews. We had some slight delays to starting up with those crews. One of those crews was a new build crew, and we actually didn't commence our frac-ing operations until the end of March. We've just done, as I sit here, our first 3 wells. And those are all well in line with expectations that we've set in terms of the tight curves that we're expecting, particularly within the liquids-rich window where we're concentrating this year. And so our guidance this year, Greg, remains at the 55% to 65% net Talisman guidance annualized that we externalized at the beginning of this year.
Greg Pardy - RBC Capital Markets, LLC
Okay. And just a last one for me. How much of that would be liquid, Paul?
So -- I mean, as I said, the majority of our drilling program this year is going to be in the liquids window. We'll have a handful of wells in the dry gas window, which is really just to hold land, 2 to 3 wells this year. And as I've said before, we've got 14 different type tiers depending on where we drilling in the liquids window. But roughly, roughly, roughly, I've always said, expect roughly half gas, roughly half liquids, and the liquid is clearly a combination of both the condensate and the NGL that are in the liquids.
Your next question comes from the line of Mark Polak with Scotia Capital.
Mark Polak - Scotia Capital Inc.
First question for me is on the Marcellus. There's been a few big wells drilled there of late. I'm just curious what you guys are seeing with your wells, if you're still sort of comfortable with that 5 bcf range, or if you think there's some upside to that? And what you're seeing for cost-wise there?
Very good, Mark. Thank you. Marcellus wells, Paul, how are we seeing Marcellus?
Yes. Mark, I mean we're sort of seeing things very similar to the way that were articulated at the beginning of January. We continue to see tight curves in line with the 5 bcf EUR that we've indicated. Clearly, as always, there's variability around that. And we've seen some big wells, we've seen some below, but on average, we're seeing 5 bcf type curves. We have seen some cost pressure in the Marcellus, as I'm sure everybody has. Most of our completion activity is jilted as a result of the long-term contracts that we have in place. But clearly, material costs, diesel, sand, all of those sorts of things have seen some quite significant pressure between the fourth quarter and the first quarter. We're working hard to absorb most of that, and I'm confident that we'll continue to be able to make operational gains this year to see our drilling and completion costs come in line with what we articulated at the beginning of this year.
So I think overall, Mark, we continue to be encouraged, gas price going up a bit. We're sort of looking at it and sort of enjoying it, I think, at the moment.
Mark Polak - Scotia Capital Inc.
Great. And as you've mentioned, gas price is going up, and in particular oil. When you guys laid out your budget for this year, I think it was $4 NYMEX and $75 WTI. Given the strength in crude, just curious what your thoughts are on the capital program, if there's potential to increase that, and if you were looking at that, where that might be.
Well, let me just make a general comment on the capital program. I mean, in general sense, our oily projects tend -- most of them, at least outside of North America, tend to be on a sort of longer timeframe, okay? So the big projects are on a schedule and then are immediately turned up-able or turned down-able. So one's not -- tweaking capital in that context, on the big projects outside of North America. Now here in North America, where we have liquids-focused activity in our North American business, we're obviously focusing as hard as we can and looking for opportunities to accelerate where we can, which is one of the reasons I'm suggesting that we may see some upward pressure on the $4 billion of cash capital as we go through the remainder of this year. So in the general sense, Mark, obviously, oil prices are higher. I think you're right, we always like to plan on the slightly pessimistic side. $75 is what we used. I think you'll see as we go to through year, I mean, even we're going to increase that a little bit. It's now embarrassing to hold it that low, so we're upping, I think, our base perspective on oil price going forward, although it's not going to move -- as I said in my remarks, in some senses, there is a premium in the price today. So we're not going to move up to where we're seeing it today. And we got to look through all of that to some sort of level of fundamentals. I think I said $80 to $95-ish. So I think you're going to see -- we're obviously actively looking. We're actually quite happy with the basic distribution of our capital program. We've still got quite a substantial proportion of our incremental production this year coming from liquids. Actually, probably back-end loaded, in fact. I mean in particular, of course, I've discussed the Yme project. As that moves backward -- this is a huge project when it comes on, and as that moves backwards, it moves the incremental liquids production in the year to the back end of the year. So a lot of our liquids increments are coming in at the back end of the year, and so we're not seeing that yet. But we're basically happy with it subject to sort of tweaks and minor adjustments. Does that help?
Your next question comes from the line of Brian Singer with Goldman Sachs.
Brian Singer - Goldman Sachs Group Inc.
Following up on that exact question on capital allocation, I think you mentioned in your comments that you would consider pulling back on capital activity in the U.K., North Sea, to a degree, in light of the taxation. So in that context and in the context of how you think about the excess capital, if there's not that much opportunity for reinvestment in the big, long lead-time projects, that would seem to leave North American natural gas, North American liquids exploration debt paydown and acquisitions. Can you kind of talk to where you would reallocate capital here or if I missed some other options?
Well, near term and long term, Brian -- first of all, let me deal with the U.K. tax, perhaps, a bit. I mean I think what I have indicated is that we're going to look at it. I mean that, obviously, it was a surprise and clearly, it has impacted future projects to some degree. And I think that's all clear for everybody in the market place. I'm merely suggesting there that we've got to look quite hard. It's obviously -- if there's a marginal project, it will push it underneath the line. But I think there's a conversation to be had with the U.K. government, I think we fully intend to have that conversation to spell out for them the implications of that. That doesn't mean to say there's going to be substantial reallocations of capital away from that problems. Although, I think in a sort of strategic sense in the long term, it clearly has an impact on one's attitude toward the predictability of that place as an investment place. So I think in the short term, it's not going to have a huge impact in that regard. Near term, we're clearly in the business of looking for incremental investment opportunities which are liquids-focused, not uniquely liquids-focused because we've still got -- as I said, we're still making good money in the Marcellus, actually. So it's not uniquely liquids-focused, but we are clearly looking at options. And it's not only in shale plays, it's also in the conventional portfolio in North America where we have a number of options. We're examining a number of plays, some of which have liquids content. There are a number of options in some of those liquids plays to increase the liquids content. So these are the sort of things that we're looking at. And I think that would be the first call on incremental capital. We're quite comfortable at the moment, I think. Scott is sort of nodding. We're quite comfortable in terms of the balance sheet, the debt paydown scheduling, all of the management of our balance sheet. So I think our first focus is on, can we find profitable incremental investments in the places that we can to increase our spending pattern slightly in the context of today's commodity prices? Does that get it clear for you?
Brian Singer - Goldman Sachs Group Inc.
Yes, thank you. And then secondly on Colombia, can you add any color on what you've seen out of the first 5 stratigraphic wells on Block 6 so far?
First signs of -- yes, Richard, any -- are you prepared to divulge any detail of what we're seeing in Block 6, or the -- yes, the first 5 and maybe the current stratigraphic well?
Well, so Block 6 stratigraphic wells, we still only have a 2 dimensional seismic over Block 6. So it's still sort of relatively far data set to be able to determine exactly what we found. I mean we would sort of endorse what the operator has said in the sense that a number of these wells have encountered oil. And we've seen varying amounts of pay, which is indicating that the reservoir system is not ubiquitous, it sort of thins and thickens. And until we have got more seismic imaging and got some more wells down, it will be quite hard to put any sort any volume numbers on this. Nevertheless, I think the scale of the system that we're looking at here in Block 6 implies we've got oil over quite an extensive area and therefore, it looks very promising. So going forward, we're just getting results from the final well. It's being logged as we speak. And then our intention is to go and drill some more wells across some 3D seismic. And then critically, as we convert this to a proper E&P license, as I described earlier, we'll have a chance to flow test wells and see how this reservoir will perform.
Just a qualitative comment perhaps, Richard, I mean I think the operator sort of seems to be doing a good job there, yes?
Definitely, very much so.
So we're quite happy with the operator there down as well. It seems to be moving it along quite quickly.
Your next question comes from the line of Mike Dunn with FirstEnergy Capital.
Michael P. Dunn - FirstEnergy Capital Corp.
Most of my questions have been answered but in the MD&A, you guys did mentioned -- it sounds like there's some uncertainty over whether or not the increase in the supplementary tax charge in the U.K. will allow increased deductibility of decommissioning costs. That might have been something I missed in the March announcements or is that a new development, and can you talk about what the uncertainties are there? I mean it was kind of my qualitative impression that there might actually be some relaxing of the decommissioning burdens in the U.K. Thanks.
Thank you, Mike. Maybe I'll -- I mean I think as far as we know, I mean I think the point in the MD&A is that it's just not definitively stated at this point. The government suggested in the announcement that they would limit the tax relief on decommissioning and not increase that tax relief in line with the increases in the supplementary tax that they announced in their announcement. So what they've said is that by the time they do the 2012 budget, they'll have defined -- they'll have decided, they'll defined the mechanism by which that will come to pass. Now the industry in the U.K. is clearly up in some arms what the government has done. And so I think there's a conversation going on about whether they really mean that or not. I would say the base case is that they intend to limit that relief, although I think there's room for some discussion. That's why it was reflected in the way that it was reflected in our MD&A. I'm just looking at Nick and Scott to see if they want to add anything to that. Does that help, Mike?
Michael P. Dunn - FirstEnergy Capital Corp.
Yes, that's great. I think I just missed that initially in March, but thanks for clarifying.
Your next question comes from the line of George Toriola with UBS.
George Toriola - UBS Investment Bank
My question is around GTL. So just the feasibility study that you guys have undertaken here, could you speak to broadly what the goals are and what the goalposts are here for -- so specifically, the goals of your feasibility study and broadly, what the goals -- the boundaries of a GTL project will be in terms of oil and gas prices, CapEx and then also, to resource volumes and possible production volumes and the outlook if this was to go ahead?
Just a general comment then by the sound of it, George. Let me see what -- let's just talk a bit about GTL, the feasibility study. Paul, why don't you just give it a go?
So George, you just sort of covered the scope of the GTL study in your questions there. So in all seriousness, the GTL study, led by -- they're clearly led by Sasol in conjunction with ourselves, is up in full swing. The team is now fully resourced and up and running here in Calgary and South Africa. The main purpose of the gas-to-liquids feasibility study is to allow both partners to be able to make a decision in the second half of next year, which we've always indicated, which is when the feasibility study is expected to be completed for both partners to be able to make a decision on whether or not to proceed with the gas-to-liquid study into feed. That's the exact decision point which would come in the second half of next year. Clearly, there are many, many questions that we need to be able to answer for ourselves in terms of the economic viability of the gas-to-liquids plant relative to the alternative gas monetization options that both Sasol and ourselves have with the properties that we're developing in the Montney. So I'll leave it at that.
George, if I may just put an overlay on this, which is sort of a strategic comment. I think it's increasingly important for Canada that options for the development of alternative gas markets other than just shipping it down to the main markets in the United States become reality. And whether it's exporting it off the coast or whether it's contemplating, turning it into liquids, whatever it is, we have a lot of -- we have huge resources of gas. We have -- and it's all at the end of the pipe. So these inquiries are, I think, strategic and important for Canada and for Canada's gas. So I'm actually delighted that we're in it. I think there's a lot to understand. There's a lot to determine in terms of the fine points of the economics. I'll just add one point to what Paul said, we've always said that if you think of NYMEX at about $5 and WTI at sort of $80 or $85, or above, then you're into a set of economics which are equivalent really between shipping the gas south, sending it off the West Coast or turning it into liquids. And that's the sort of point and of course, it varies, gas price, oil prices. And actually, we're going to show you a little bit about this next week when we do our investor open house. So we're on -- we're at the point of interest, I think, with all of these options. And I just think it's very important that we're in that study with Sasol, with the main players in the world who can do this. And I think that's important for Canada.
George Toriola - UBS Investment Bank
Thanks, That's helpful. And are you able to speak to the resource base that -- I mean just broadly, what source of resource base would -- you have certain estimates of your resource base right now. What -- do you need to validate that? Do you need to do things on the resource base side to support this or [indiscernible] to date?
So I think -- let's just -- let me ask Paul to describe for you the 2 deals that were done which is in the public domain, which essentially, both what they are and what our confidence in the resource base is. Paul?
Yes. So collectively, the 2 transactions which cover Farrell Creek and Cypress A, the contingent resource numbers that we've publicly declared on these 2 plays is circa 20 tcf of contingent resource. So think of 10 tcf each between ourselves and Sasol in the new 50-50 joint venture. Farrell Creek is largely de-risked. We've now been drilling into Farrell Creek for 3 years now. And Cypress A last year, we de-risked to a large extent but has far fewer wells into it today. I would sort of characterize both of these areas as being ready to go into full development when the partnership chooses to. And clearly, 20 tcf of contingent resources is more than sufficient to underpin any imaginable scale of the gas to liquids plant for a very, very long time.
So lots of resource, George, into the -- I mean, have we released how much gas goes into produce, how many liquids, Paul?
We will talk about this a little bit next week. But essentially, we are putting 2 gas plant sizes into feasibility study. One is a 48,000 barrel a day, gas to liquids plant, and the other is a 96,000 barrel a day gas to liquids plant. And roughly, roughly, there's about half a bcf a day required for the 48,000 plant, but a bcf a day or just under that for the 98,000 plant. So you can do your maps from there, but you'll see the 20 tcf of resources underpins, even the larger plant, for a very, very long time.
I think that gets it, George, for you?
George Toriola - UBS Investment Bank
Yes, thanks a lot. And one last question, the balance of the price from -- that you received from Sasol here, over what time period do you expect those drilling carries to occur?
So the 2 transactions, as you know were each for $1.05 billion. Roughly, $275 million in each transaction is a cash payment, which we will receive this year, so x 2. First transaction is closed and so we've received that. The second transaction is due to close in the coming month or months. The drilling carry, which is clearly the balance, is applied across either of the assets and does not have a time limitation to it. So we will collectively use the carry going forward. And in fact, we're using it as we speak today, as we've ramped up to 9 rigs in Farrell Creek, today and we'll be using that carry until it's exhausted across both of the plays.
We'll make sensible decisions, George, on the pace and timing of development, and we'll use the carry accordingly.
Your next question comes from Menno Hulshof with TD Securities.
Menno Hulshof - TD Newcrest Capital Inc.
I've got a couple of questions. I'm going to start with a question on the proposed Marcellus severance tax. Is this still an outstanding issue in your mind? And if so, what are your current thoughts in terms of how this could play out?
Do you want to give us the second one as well, Menno, and then we'll deal with them both?
Menno Hulshof - TD Newcrest Capital Inc.
Sure, yes. The second one is for Richard on the Lempuk-1 well in South Makassar. And I was just wondering if you could give us any sense of the size of the prospect, cost and I guess most importantly, how it differs from Romeo to the -- which clearly was a disappointment?
Very good questions. So let's deal with the severance tax first, Paul, and then to Richard on Lempuk.
I mean -- as you know, Menno, the issue of the severance tax in Pennsylvania has been on and off agenda for several years now. It is back in the political swirl as we speak. It's being positioned as an impact tax. But in the sense -- in essence, it's a severance tax disguised as an impact fee tax. I think in principle, we need to see the details. There have been no details released by Senator Scarnati in terms of what he is proposing to put forward in terms of the Bill. And it's far from clear right now what -- how the politics will play out. The governor has publicly come out as recently as last week and said he is against the severance tax but is willing to consider an impact fee tax. And we, as an industry, or we, as Talisman -- and I think the Marcellus Shale Coalition has put out a statement to say that we would be supportive of a transparent impact fee that would be mainly directed to those areas in which we are carrying out our activities by the impact fee in the revenues of that impact fee flow to the areas where each of us are operating. So we'll see how it plays out, Menno. We're clearly in the dialogues along with the rest of our industry competitors. I would say the same thing as we said last year which is that with gas prices where they are today, one needs to be very careful about the imposition of a severance tax with capital mobility being very mobile. And I think that's the message that Governor of Pennsylvania is fully aware of.
I think you've just had a public message there, Menno, at the end. Does that help?
Menno Hulshof - TD Newcrest Capital Inc.
Yes, that's very helpful.
Thanks very much. Let's go to Richard's excitement about the Lempuk well.
Menno, when -- the Makassar Straits is still a very unexplored basin, and there was a lot of industry excitement when it sort of opened up after that 2006. In the North Makassar, there's now being a dry hole drilled by ExxonMobil and 2 disappointing wells in our partnership with Marathon, with Bravo and Romeo. Both of those wells found a lot of reservoir, a lot of carbonate reservoir as predicted but they didn't have any hydrocarbons in. So we've got some sort of problem with the plumbing system and the charge, and that was our main concern as we went into this drilling phase. If we look to the South Makassar, it's actually a separate -- it's a separate basin. And it looks -- although it had some similar geological characteristics, it looks more encouraging. We've got a gas field that's located just on the northern rim called the Ruby field, and ExxonMobil made the discovery, Sultan, in 2009. And so we're much more encouraged by the charge system in the South Makassar. In this Sageri PSC, that's where we're going to drill Lempuk starting in July. It's a large total full [ph] block. And on top of it, we expect to find a carbonate reservoir. And in fact, the results from the north actually give us more encouragement about reservoir development. But we think we're in an environment where we're more likely to have received a gas charged into that reservoir. It's very difficult to calibrate it in terms of size at this stage. The basin is completely undrilled. But if it works, it could be quite a significant discovery.
Menno Hulshof - TD Newcrest Capital Inc.
And then what are you thinking in terms of [indiscernible] right now?
I'm sorry, Menno, repeat the question. What are we thinking in terms of...
Menno Hulshof - TD Newcrest Capital Inc.
In terms of your cost and your current working interest?
Cost of our current working...
Menno Hulshof - TD Newcrest Capital Inc.
No, sorry, the total cost of the well and your current working interest?
What is our current working interest?
Our current working interest, Menno, is 100%, but we're just in the process of changing that. And we're bringing in a partner. We'll probably talk about this a little bit more next week. And so our expected working interest when we drill will be 50%. And the well cost on this is somewhere in the order of $60 million, $65 million.
Your last question comes from the line of Pawel Rajszel with Veritas Investment.
Thanks for taking my questions. I've got 2 of them. The first being -- just looking at North American realized prices, noticing that the realized price there for oil and liquids is kind of on par with what we saw last year despite the higher WTI price. Is that reflective of the liquids discount? Do you expect that kind of price to go forward?
Could you give us -- I'm sorry, was it Paul, I didn't get your name?
Pawel Rajszel with Veritas Investment Research.
Pawel, it's Scott. We can go into more detail with you off-line but I mean I think the high-level answer is, in our prior year, so Q1 and Q4, we had physical hedges that were reflected in the netbacks. So when you look at our financial results, the financial derivatives and the physical derivatives are handled differently. We were gaining about I think $0.60 to $0.65 on our physical derivatives in 2010, which is included in the netbacks. And in 2011, we have less hedging, so I think, that's the less physical hedging.
So in fact, the hedging and the accounting for the hedging, Pawel, in your first question.
Okay. And then second question, as you mentioned, you're going to be somewhat protective here from the higher costs due to the contracting you've done in advance. Curious if you can give some more color on how long you've got until those contracts maybe roll over, and then the impact on costs once those contracts roll?
Let me just turn to -- here's a voice you haven't heard on these calls before. Let me turn to Helen Wesley, who is looking after, among other things, our procurements in supply. Helen, any ideas on the sort of the rough, rough contracts sort of timeframe, and what are you expecting about cost pressures?
Yes. Most of our contracts are roughly a year in length at the moment. And so at this point in time, we're working on looking further out and securing longer-term contracts. So we'll see some cost pressure in the intervening time but should be in a position where we're able to manage them, containment of inflation going forward.
We're about 60% of our cost base is covered by these contracts, Pawel, I think in a general sense, as Helen just described and they're well off in a year. Paul, did you want to say something specific?
Yes. I mean within North America, I mean we now have 7 dedicated stimulation crews, and those contracts are all for 2 years, some of them have clearly been going for a year. And most of those, if not all of those, have got an option to extend by a year. So think of sort of 3 years that our option to be able to lock in 7 dedicated crews, which is the majority of the frac-ing activity that will be completely going forward would spot here or there, but it sort of covers 90% of our frac-ing activity. And on the rigs side, we have less exposure. And I think the rig rates are more -- it is less of a bottleneck in the system than completion crews have clearly been. But even in the rig side, we've got roughly 50% of our rigs on long-term contracts, with similar sort of 2-year windows rolling off at different points during the year when we will make decisions.
When you're looking at the cost inflation you've seen from Q4 to Q1, are we basically just looking at regular inflation like CPI or something a little more nasty?
No, it's more than that. So we've seen -- diesel prices, clearly, you can kind of do your own calculations. You know what diesel prices are at going up significantly. And both completion crews and rig crews use a lot of diesel and sand. We use a lot of sand, and sand prices have gone up significantly. So no, it's more than CPI, quite significantly more, I mean a double-digit type inflation. Just on the 40%, let me just turn to Helen, Pawel, if I may. On the 40% that we're exposed, what sort of numbers are we seeing generally?
I mean there's a range of anywhere from sort of 3% to 15%. And I think what's helpful to think about is in the context of the overall CapEx and operating cost profile for the organization, that's roughly $6 billion or so. So it's just -- it's helpful to think of the cost that Paul was telling you about in the content of the North America then which is, obviously, it's not a portion of that, roughly more than those [ph].
Does that get at your question, Pawel?
There are no further questions. I turn the call back over to you, Mr. Manzoni.
Well, ladies and gentlemen, if there are no further questions, thanks very much for participating in our call. And we look forward to delivering the second quarter and reporting it to you in due course, so thanks very much. And with that, we'll end the call. Thank you.
This concludes today's conference call. You may now disconnect.
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