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Executives

Nicholas J.R Walker - Executive Vice President of International Operations - West

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

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

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

Richard Herbert - Executive Vice President of International Exploration

Unknown Executive -

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

Analysts

John Malone - Ticonderoga Securities LLC, Research Division

Brian Singer - Goldman Sachs Group Inc., Research Division

John P. Herrlin - Societe Generale Cross Asset Research

Menno Hulshof - TD Newcrest Capital Inc., Research Division

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

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

Andrew Potter - CIBC World Markets Inc., Research Division

Brian C. Dutton - Crédit Suisse AG, Research Division

George Toriola - UBS Investment Bank, Research Division

Pawel Rajszel - Veritas Investment Research Corporation

Robert Brackett

Talisman Energy, (TLM) Q2 2011 Earnings Call, Jul 28, 2011 July 28, 2011 1:00 PM ET

Operator

Good morning. My name is Sean, and I will be your conference operator today. At this time, I would like to welcome everyone to the Talisman Energy Inc. 2011 Second Quarter Results Conference Call. [Operator Instructions]

This call contains forward-looking information. Certain material factors and assumptions were applied in making the forecasts and projections to be discussed in this call, and actual results could differ materially from those anticipated by Talisman and described in the forward-looking information. Please refer to the cautionary advisories in the July 28, 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 Thursday, July 28, at 11:00 a.m. Mountain Time. I will now turn the conference call over to Mr. John Manzoni. You may begin your conference.

John A. Manzoni

Thank you, Sean. Ladies and gentlemen, thank you for joining our 2Q conference call this morning. As usual, I'm joined here by the management team, who will help to answer your questions after Scott and I have given you the main highlights for the quarter. And today, I'd like to welcome Tony Meggs to his first quarterly call with Talisman as part of the leadership team. Tony has joined the team as a Senior Adviser, and he'll focus initially on helping us consider the options associated with North American gas monetization, in particular, our gas to liquids study around the Montney. But he's already broadening out from that initial remit to make contributions more generally to our overall strategic progress. So welcome Tony.

And I have another announcement to make. In it, Chris LeGallais, who's been doing a fabulous job at running our Investor Relations team for 7 years, has, I hope, with some reluctance, decided to make a change in the new phase for him and his family. This conference call today is the 31st consecutive quarter end Chris has been managing and is also the last one he'll do with Talisman. We shall certainly miss him, and I'm sure you'll join me in wishing Chris all the best for the future.

Let me say a word or 2 about the overall trading environment first, which is playing out pretty much as we had expected. Oil prices are holding up, maybe just a little higher than fundamentals would suggest, although the world is concerned about tightening supply/demand balances going in the second half of the year. Price levels seem to be particularly uncertain currently because on the one hand, there's the prospect of tightening balances, evidenced by the recent SPR release, but on the other hand there's also a significant uncertainty about the overall state of the major economies. Together, these opposing forces make it particularly difficult to predict the future direction of price movement. Overall, we believe the balance of factors seems likely to maintain prices at or above their current levels, rather than being subject to any lasting downward shift.

North American gas prices remain depressed, and it's still all about supply. During the second half of this year, we're expecting that most of the lease-driven activity will probably be completed, but the supply/demand picture will still take some time to normalize even after that's done. And storage could come under some pressure later this year depending among other things on the weather between now and then. We're planning on weak prices well into next year. Having said that, we still believe that today's prices are below what will be seen ultimately as marginal cost. So that in the medium term, we're expecting modest improvement underpinned by robust demand. And that's why we continue to believe that the best shale plays will still be good business.

It's worth noting that our Asian gas prices are quite a different picture. This quarter we saw prices of about $9.80 per million cubic foot in Asia. And as I've mentioned to you before, the pressures on gas prices in that region are all upwards. In fact, this quarter's prices are around 50% higher than they were a year ago. So the prices have been as expected. And now let me turn to our own quarter.

Overall in terms of the numbers, I think we have had a strong quarter. Cash flows and underlying earnings are up about 14% versus a year ago. Underlying production growth is strong, and we're continuing to implement the actions in line with our strategy to build the foundations for sustainable growth at improving profitability. Here in North America, we continue to build our shale portfolio and in fact, we added to it this quarter by securing a material position in the Duvernay shale here in Alberta. We have about 360,000 acres in the play now, acquired at an average of around $2,000 an acre. We believe this will prove to be a liquids rich shale play, and some of the industry activity in the area so far has been encouraging in that regard. We'll begin derisking the play with 2 rigs in the second half of this year. It's very early days, but we're optimistic that we'll see the Duvernay emerge as another successful liquids rich play, this time right here in Canada. If we see success in this year's activity, we will of course, build on that success going into next year. So we're continuing to strengthen our shale portfolio in North America, and we're looking forward to the early results of the wells in the Duvernay.

In terms of production this quarter, we're seeing strong underlying growth. As you saw, we produced 420,000 barrels a day in the quarter, which is 13% ahead of this time last year when we account for the disposals we've made in the interim. The growth is driven by North America where we continue to build production in the shale. In the Eagle Ford, we're continuing to ramp up activity, and we'll exit with 10 rigs operating there. We now have 2 completion crews fully up and running, and they have a continuous program as we build production from the area. We were a little slower than we had hoped in getting the completion activity started this year because we wanted to use our own dedicated crews rather than utilize existing crews at the very high spot rates earlier in the year. This will reduce our average production from the play for this year because we can't make up for the period we delayed, but the crews at least are now fully up and running.

In the Montney, we already have 10 rigs running, and as you know, we closed our second transaction with Sasol in the Cypress area. And in the Marcellus, we're drilling with 11 rigs and we're continuing to see encouraging well results. In light of these results, we're now projecting we'll be right at the top of our guidance range of 350 to 400 million cubic feet a day for the year.

The second quarter is usually a big turnaround quarter in the North Sea, and this year is no difference. In fact, that activity extends into the third quarter, and we're expecting the North Sea as a whole to have slightly lower production in 3Q than in 2Q. The Yme project is now finally installed on location offshore. This is a major milestone although there remains considerable work to do before we can commission the facility. Much of that work is rework, which turns out to be necessary due to the poor initial fabrication. Getting clear on the total scope of rework required has made it difficult to project the first oil date. But we're now getting very close to finalizing that work scope. I don't like the answer, but we now believe we need to push Yme first oil into the first half of next year. And in setting frankly our own expectations, and hence yours, I'm pushing it right to the end of the first half, because although we are close, we've not yet completely defined the work scope. I said before that I'm very frustrated with this project, and the root cause is a poorly executed fabrication contract. As you know, we've taken a number of steps to improve our project execution, and I'm determined that we will do better in the future. Not least, because we -- as you've seen in the press release, we've adjusted downwards our expectations for production growth for this year and this project is a large part of that move. We now believe that our total production will be between 430,000 and 440,000 barrels a day this year.

There are several factors, which have contributed to this move. You'll recall that in our last call, I held to our original guidance despite moving Yme to the end of the year. At the time, we had anticipated Yme might come on a bit earlier than year end and that other areas of the portfolio would make up some of the loss. Having now firmly moved Yme into next year, and also had another quarter to watch, it's clear we need to adjust guidance for the year downwards. We deliberate in deferring our Eagle Ford ramp-up during the first quarter as I've described, and recently we've seen a very slight delay to Kitan in Australia, which we still believe will come on before year end, but maybe a month or 2 slower than we had expected.

In the North Sea, as a whole, we believe this year will be toward the bottom of the 110,000 to 140,000 barrel a day range we have set. This relates obviously, mainly to Yme, but we've also seen some reduction in both Rev in Norway and Tweedsmuir in the U.K. In both cases, we have infill wells planned for next year which we believe will restore performance, but we can't do them this year.

Looking forward, we still have some shutdowns planned in the U.K., which always carry some uncertainty, and hence we've aimed off a little to account for those. So putting all that together and given the first half production to 432,000 barrels a day, we cannot meet our initial guidance of 5% to 10% underlying growth for the year. The revised range of 430,000 to 440,000 barrels a day represents only modest absolute growth when I exclude the 11,000 barrels a day we purchased this year with our Colombia acquisition. In an organic sense, accounting for the disposals, and still excluding Colombia, it's between 7% and 10% above last year's outcome, which shows the portfolio is growing. The factors which led us to reducing the guidance for this year are quite specific and defined, and therefore, I'm confident in reaffirming that our target of 5% to 10% growth in the medium term remains firmly in place. However, for this year, it's a missed target. This is the first target we've missed and as a leadership team, we'll resolve to do everything in our power to make it the last.

Raising our eyes a little to the slightly longer term. The quarter has been a busy one for the exploration team. In Vietnam, we were formerly awarded the 135, 136 licenses in the Nam Con Son Basin and we completed the seismic survey in those blocks during the quarter. Drilling activity will begin in the adjacent 5 to 10 block next year. We're drilling the Topkhana well in Block K39 in Kurdistan, which is now close to reaching its first objective. We're also drilling another well in Papua New Guinea, but we've now started to aggregate gas in line with our plans there. We drilled one well in the southern part of our acreage in PNG, which was dry this quarter, although this was a commitment well which did not form part of our gas aggregation strategy. We're in the final stages of preparing to drill the Lempuk deepwater well in the south Makassar Straits of Indonesia, which we expect to spot in August.

In Colombia, the 2010 Akacias discovery in Block 9 is now on long-term test with very encouraging flow rates. And we're preparing to drill several appraisal wells on this discovery in the second half of this year. We're drilling the Huron-2 appraisal well in the foothills Niscota Block and have taken the next steps in Block 6, where we're transitioning the block from a technical evaluation license to an exploration license. This now allows us to move forward with our next wells in that block.

In terms of development activity in Colombia, Equion have 2 development wells planned for the second half of this year into the Piedemonte block and the full development planned for Piedemonte is being worked for sanction next year. And finally, in Norway, we drilled a successful appraisal to the Grosbeak discovery.

Turning now to the financials for the quarter, which as I mentioned, was strong. As you recall last quarter, inventory was built quite strongly across the business. Some of that was reversed during the second quarter as we predicted, and that release of inventory helped the comparatives for cash flow and earnings a bit this quarter. Cash flow at $897 million was up about 14% from a year ago, reflecting stronger prices and net backs. Capital spending for the quarter was about $1.1 billion, and for the 6 months around $2.2 billion. We still anticipate spending between $4 billion and $4.5 billion cash capital on exploration and development activities this year. During the quarter, we had free cash flow outflow of nearly $460 million, bringing net debt at the end of the quarter to about $3 billion. In addition to the cash capital, we also spend just over $500 million on the Duvernay land acquisition. We also agreed to a small tuck-in acquisition in the Eagle Ford for a little over $100 million, which will close in the next quarter.

Net income was $698 million, a very strong result, especially compared to last quarter's loss of $326 million. Much of that swing has to do with the change in unrealized hedging gains and losses, which were a positive impact on the comparatives this quarter due to the forward strip coming down. We also benefit from lower charges for stock-based compensation. Underlying earnings from operations, which as you know strips out the various one-off impacts, was $168 million, higher than the previous quarter and a year ago.

Operating costs were about $100 million higher than last quarter. About half of which is due to the release of inventory and half due to the turnaround activity in the North Sea.

Taking a slightly longer view of costs. Year-to-date, we're up about $50 million, which can be pretty much explained by the addition of our operations in Colombia and the Eagle Ford and the commissioning of Auk North in the U.K. Cost pressures generally remained high in line with activity. Here in North America, we're seeing spot rates continuing to increase in both onshore rigs and stimulation services. As I've mentioned before, in large part, we're mitigating these pressures by our contracting strategies.

We wrote off the dry hole in PNG this quarter, which as I mentioned was a commitment well in the southern part of our licenses and wasn't part of our aggregation strategy.

So now let me turn to Scott to give you a little bit more detail on those numbers. So Scott?

L. Scott Thomson

Thanks, John. I'll review our financial results, balance sheet, acquisitions and disposal activity in the quarter and our hedging position. Cash flow in the quarter was $897 million compared to $811 million in the immediately preceding quarter. Its higher commodity prices and increased liftings were partially offset by realized hedging losses, lower production volumes and higher operating costs.

Non-GAAP earnings from operations increased to $168 million from $157 million in the immediately preceding quarter as a result of the same factors.

You'll recall that we had a buildup of inventory in all locations during the first quarter of 2011, which had a negative $80 million impact on cash flow in the first quarter. In the second quarter, the situation partially reversed and the net inventory reduction of 600,000 barrels contributed $40 million in cash flow during the quarter. Cash flow increased by $107 million relative to the second quarter of 2010. Its higher commodity prices and increased liftings were partially offset by higher operating costs, higher cash taxes, and a realized hedging loss.

Non-GAAP earnings increased by $20 million to $168 million as a result of the same factors and were additionally impacted by higher exploration expense and DD&A.

The incremental DD&A arose primarily from the additional of Equion and the start-up of Auk North. Current income taxes were $436 million in the quarter, in line with the $443 million of taxes in Q1, but significantly higher than current taxes in the second quarter of 2010 because of higher oil prices and the high tax rate North Sea jurisdiction.

In the recently completed quarter, the impact of the U.K. tax change was approximately $40 million, which was higher than the $25 million reported in the first quarter of 2011 because of the higher average Brent prices during 2Q.

Operating expenses increased over the immediately preceding quarter and the second quarter of 2010, mostly due to the costs associated with annual turnarounds and the reduction of inventory in the North Sea. We expect operating expenses in the third quarter to be similar to the most recently completed quarter because of continued turnarounds in the North Sea and Asia.

On the acquisition and disposition front, we completed 2 significant transactions in June. First, we closed the transaction to sell a 50% interest relating to the Cypress-A assets to Sasol for total consideration of approximately $1.1 billion comprising $250 million in cash and the remainder as a future capital carry. Second, we acquired additional undeveloped land in the Alberta Duvernay shale for approximately $510 million. We also acquired additional acreage in the retrograde window of the Eagle Ford from SM energy in the second quarter. This acreage is adjacent to existing acreage and the transaction is expected to close in the third quarter.

At June 30, there was $860 million of cash on the balance sheet compared to $1.7 billion at December 31, 2010. The reduction reflects a $350 million repayment of Canadian medium-term notes, $200 million final payment on the Equion transaction and the acquisition of Duvernay undeveloped land for approximately $510 million, partially offset by the cash proceeds of approximately $500 million from the sale of interest in Farrell Creek and Cypress-A to Sasol. Net debt was at $3 billion at June 30.

Capital expenditure, including the exploration expenditure, was $1.1 billion during the quarter, with $280 million spent on international exploration, $310 million on North Sea development and $440 million in North America, approximately 90% of which related to shale activity. Year-to-date, we have spent $2.2 billion on capital expenditures, and we continue to expect cash capital expenditure for the full year of between $4 billion and $4.5 billion.

Now turning to our hedging program. In the second quarter, we had $120 million of cash outflows associated with our hedging program. $140 million of realized oil hedging losses were partially offset by $20 million of cash inflows from our gas hedges. On the oil side, 20,000 barrels per day of $80 x $92 Brent collars have been replaced by $90 put for the back half of the year. The program for the second half of 2011 consists of 21,000 barrels per day of Brent hedged in $80 x $92 collars; 20,000 barrels per day of Brent hedged in $84 x $98 collars; 9,000 barrels per day of WTI hedged in $80 x $92 collars; and 20,000 barrels per day of Brent puts at $90. In 2012, we've entered into Brent collars for 20,000 barrels per day of oil production at a floor of $90 and a ceiling of $148.

On the gas side, we have approximately 100 mmcf per day primarily in tight collars with a floor of $6 NYMEX for the second half of 2011. And we have no gas hedges in place for 2012. Those are my highlights.

I'll turn the call back over to you, John.

John A. Manzoni

Thanks, Scott. Ladies and gentlemen, just before your questions, the key points. We had a strong quarter financially with both cash flow and underlying earnings, strong and showing improvement both from last quarter and from a year ago. We're continuing to build our portfolio to deliver long-term, sustainable and profitable growth. We added a substantial position to Duvernay this quarter, which we'll begin to test in the second half of the year. I've lowered our production guidance for this year to between 430,000 and 440,000 barrels per day. This reflects the delay in Yme, a slower ramp-up in the Eagle Ford and the North Sea likely to be toward the bottom of the range for this year.

While these impacts are all explainable and temporary, I regret having to move off our own projection for the first time and of course, we're taking actions internally to strengthen our project execution and delivery. Notwithstanding this year's reduction, we remain very confident in our medium-term outlook for production growth, which we're maintaining at 5% to 10%.

So with that, ladies and gentlemen, I will be very happy to take any of your questions.

Question-and-Answer Session

Operator

[Operator Instructions] Your first question comes from the line of Bob Brackett with Sanford Bernstain.

Robert Brackett

I saw the 4% rise in North America shale gas quarter-on-quarter but I saw the Marcellus, which is the lion's share of that, up 16%. Is that delta just the impact of the JV in the Montney?

John A. Manzoni

Thank you, Bob. Let's see if Paul can shed some light on what's happening outside of the Marcellus port.

Paul R. Smith

You're absolutely right. The Marcellus was up 15% and the overall share portfolio, up 4%. The Eagle Ford, we delayed the first quarter start-up by roughly a quarter, that means that we've got a back-end loaded quarter in the Eagle Ford. In the Montney, we didn't really start our completion activity until May this year. So we had a very back-end loaded program for both the Eagle Ford and the Montney. And the Marcellus taking the lion's share of the growth, 1Q over 2Q. So I think that probably sort of slower in the Eagle Ford and starting completions in the back end of the year in the Montney part. Does that get at your question?

Robert Brackett

I guess, the question was if North America is about 470 million a day and the Marcellus is 406 million, the growth in the Marcellus -- you've lost some mcf a day as a function of closing the JV. I guess that's the question.

Paul R. Smith

It's a function of 2 things. I mean, the JV -- we did have the second transaction closed on the Cypress-A property, Bob, as you know, which should have an impact too, but we've also got underlying decline because we came in to this year in Farrell Creek with a run rate above 50 million standard cubic feet a day. We've clearly got base declines on that production. And as planned, we're not actually starting to frac -- we didn't start to frac into the Montney. We are now running with 2 full crews until May this year. So what you're seeing in 2Q is essentially -- and one in 2Q is no new wells coming on in the Montney, a very back-end loaded program by design post-breakup. And yes, there is a small impact from the second disposition to Sasol in there too.

Robert Brackett

Great. So it's really that natural decline from 50 to 22?

John A. Manzoni

Correct. That's right.

Operator

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

Andrew Potter - CIBC World Markets Inc., Research Division

Two questions. I guess, first, maybe if you could just talk a little bit about your interest in other shale opportunities in North America and globally. I mean, I guess, the Duvernay is sort of the last play we're going to see you guys get into or should we be expecting that there's more in the cards? And then the second question, just in Colombia, I mean, it seems like things on the CPE-6 and CPE-09 are going very well. But when will you be in position that you can actually kind of firm up development plans or release a contingent resource estimate? I guess, when we get more definition on where this is going to go?

John A. Manzoni

Sure. Let me make a general statement, Andrew, if I may, and then hand to Richard, who could -- well, Richard, really to talk about our interest in international. We've obviously got to balance, you know our activities and be thoughtful about how we spread, so to speak, our focus. Having said that, we are looking generally at international shales outside of North America because we're one of the few companies who have both done it and are international. And that therefore conveys a level of competitive advantage for us. So we are relatively active in that. Maybe Richard can describe -- because the other thing we've done is we've just centralized our new plays, teams underneath Richard Herbert so that we can leverage our North American experience internationally when looking and assessing different shale plays. So let me ask Richard to give another comment on that if you want and then perhaps to talk a little bit about how quickly we can get firm on Colombia activity. Richard?

Richard Herbert

Yes, thank you, John. So Andrew, we -- as John mentioned, we are looking to leverage the experience we're getting in North America and internationally. And obviously, we don't talk about the specifics of particular deals that we're looking at. But I mean, I think it's fair to say that sort of around the world now that there's a lot of focus and interest on international unconventional plays. We are using the experience we've got from North America to make sure that we focus on the most attractive ones. And we are looking -- in some places, we're looking at potential gas as in Poland, where we now have an active exploration project and we will be drilling wells in the second half of this year. And in other places, we are looking for other plays like the Eagle Ford for the Duvernay, which look like they could have quite significant value in the liquid part as well. So I think you will see as we go forward, there will be announcements. We will be looking at other plays to go into, but we don't have any specific projects to talk about today. If I move onto the second -- your second question on Colombia. I mean, clearly we're excited by the early results in the 2 blocks that you mentioned. Block 6 and Block 9 of course, these are exploration results and we have to wait a little while and completed an appraisal program before we can really start to talk in detail about levels of resource or specifics of development. But I mean, just to address this very briefly, I mean in Block 9, where we've made the Akacias discovery, that well was put on long-term test during the quarter. We've already produced about 75,000 barrels from that test. It's producing at about 1,600 barrels a day gross oil, which is very encouraging. And we are making the plans now to go and to acquire more 3D seismic and drill some appraisal wells later this year. There are some current delays in Colombia with permitting and award of licenses for drilling activity, which we have to take into account. But we are confident we'll be drilling in the second half of the year. And on Block 6, we have an additional step there we've been going through which is, as John mentioned in his text, we have to convert that block into an exploration license before we can move forward with the program. And we are confident we're going to receive that approval to do that very, very shortly.

John A. Manzoni

Do that get at your questions, Andrew?

Andrew Potter - CIBC World Markets Inc., Research Division

Absolutely. Great.

Operator

Your next question comes from the line of George Toriola with UBS Securities.

George Toriola - UBS Investment Bank, Research Division

Two questions. The first is, looking at your North American gas business, could you just project -- assuming flat natural gas prices from here, could you project when you think that business could be free cash flow positive, just looking for when you think that business could be self-sustaining? That's on one hand. And then the second question, really the follow-on to Colombia, could you sort of speak to what type of growth trajectory will -- I mean you've talked about looking to build out the 50,000 barrels a day type of core area? Now are you still thinking that this would be organic? If so, is it 5 years away or is it 3 years away? Can you speak to what sort of trajectory we expect to see down there?

John A. Manzoni

Okay, thank you. George, let me try and address the first because it's an interesting underlying dynamic in the company of course, as you know, shale plays move over time into a cash -- well, potentially, a cash flow positive situation if one doesn't need to reinvest the full amount of cash into the shale play to at least maintain production in that shale play. Where the company actually moves into cash flow -- sustaining free cash flow generation of course, depends on the choices that we make with the cash that is generated from the shales. What I have said in the past is that within 2 or 3 years, the underlying dynamic of the company will move to that condition. But of course, it will depend on the choices that we make with that capital, with that free cash and the investment choices that we make. So the fact is, we have some choices, but we don't have them until we're in a condition which the company could generate free cash. And that condition will happen sometime between 2 and 3 years from now. And then, we will have some choices about -- and of course, the amount of capital, the amount of -- the different choices that we make for investment both between now and then and after that. So I think, if that -- does that help you in thinking about that?

George Toriola - UBS Investment Bank, Research Division

Yes, John. But if you could just clarify that, is that on the assumption of future gas prices that are higher from here? Is it flat gas prices?

John A. Manzoni

I'm sorry, yes. I'm sorry. That's our current planning assumptions, which actually are broadly today's gas pricing.

George Toriola - UBS Investment Bank, Research Division

Okay. So 3 years or so from...

John A. Manzoni

And indeed our planning assumption for oil, which is sort of $85, really $87-ish. So we used some relatively, at least in the oil side relatively conservative assumptions for that. So that's the basis of the statements that I have made. Let me turn to Richard to see if he could shed a little light on how we're thinking about growth in Colombia.

Richard Herbert

Yes, so George, you mentioned the 50,000 barrels a day, and this is a number that we have put out there as our production target for the medium term. And our confidence in that is really based on the current asset base that we've got where of course, we're involved in the Equion joint venture which is currently producing and where we have a development project to grow production. We have the Huron discovery, which is adjacent to the Equion producing fields where we have now started appraisal drilling. And in addition, we have got the Block 6 and Block 9 discoveries that I was talking about a few minutes ago. And beyond that, we have quite extensive exploration acreage. So as we look at that collection of assets and the potentials that come out of those assets, our view is that we can reach 50,000 barrels a day in the sort of medium term. So we're currently this year producing about 11,000. That will go up slightly next year, and then it will ramp towards 50,000 in the medium term.

George Toriola - UBS Investment Bank, Research Division

Thanks. So I guess, the follow on to that is that right now, you're not using the capacity you have in the Ocensa pipeline. So how does that -- how are you thinking about that and is that capacity that just becomes available to other owners of the pipeline or how are you going to liberate your -- or monetize that while you're growing production here?

John A. Manzoni

Sure. So let me ask Scott who oversees our marketing activities to talk a bit about how we're thinking about capacity in this sense of pipeline.

L. Scott Thomson

So, George, as you know, part of BP Colombia transaction, we have an ownership stake in the Ocensa pipeline and there was a good strategic move for us because it allowed us to have exit options for the BP Colombia economy or the Equion volumes, but also it gave us the capacity in the future so that when we ramp up to the level that Richard discussed, we have capacity in a capacity-constraint country. Now clearly, we don't need to use all of that right now and we're aware of the recent transactions that have taken place. And we're in discussions with various people about different ways to utilize that capacity, and I think it's too early to have any further discussions on it. But clearly, between all of the people in the area, there will be other companies that have a demand for that capacity.

George Toriola - UBS Investment Bank, Research Division

And then the longer term, Scott, some general plans for expansion anyway?

L. Scott Thomson

I suspect -- I mean, I think the capacity constraints in Colombia are relatively short term over probably the next 3 or 4 years because there's a lot of pipeline construction going on. So the percent ownership we have in Ocensa will meet the targets that Richard has laid out. And in the future, I suspect there will be options for future pipeline capacity if acquired.

George Toriola - UBS Investment Bank, Research Division

Okay. So in the near term, we might see you look to monetize the old capacity in some shape or form?

L. Scott Thomson

I wouldn't count on a sale though.

George Toriola - UBS Investment Bank, Research Division

No, no. Not the sale, maybe some...

L. Scott Thomson

So I would just say, there are other people that are interested in using them. And frankly, right now as an owner, as it's utilized, we benefit from that utilization. So I don't want you -- to leave you with a thought that we're going to monetize that via a sale.

Operator

Your next question comes from the line of Greg Pardy with RBC Capital.

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

Most of my questions have been answered. But to John, just with Yme now, what are the steps you see, and I know that the complete -- you mentioned that the scope of the work hasn't been completely defined, but at this stage, what kind of a probability would you put on Yme for end of 2Q?

John A. Manzoni

Well, let me -- so let me just frame it in a general sense and then maybe Nick can add some color for you Greg. I have -- as I've said, one of the difficulties we've been having is that frankly, the platform arrived from the yard into Norway. And as we were expecting and looking and preparing that platform, we were uncovering frankly, appalling construction work, which has to be, therefore, redone, which is what we've actually been doing. It's been quite difficult to identify the full scope of that work, which is why we've been, frankly, why the timeframe has now moved backwards because we thought we were close and we've uncovered more that needs to be redone. I do think we are close now to full definition of that work. And so I have high confidence that by the end of the second quarter, next year, Yme will be flowing. And because it doesn't please me in any way of course, to miss our first target as you will know, so I've done everything we have done, everything that we can to get underneath it now to put it back to top on it. So let me just see if Nick can add a little more color for you in terms of some of that. Nick?

Nicholas J.R Walker

Yes, Greg, I mean, I think, first of all, we've made a significant step in testing up the platform safely installed offshore, so it's in the field and we've started hook-up work, and that's ongoing. And as John said, there is a significant amount of remaining the rework to do to commission the topsides, and that's due to poor workmanship in the yard. And as we got into the Norway and have been through the platform, we've uncovered a number of issues. They principally revolve around a weld inspection, which we have to go and redo, because the records weren't in good shape and around the quality of the electrical and instrumentation work. So we've had to go through the whole platform and understand that. And we're a long way through that now. So we have a reasonable understanding of what the scope is, and I think we'll be very shortly be able to quantify the full scope. So based on that, we've pushed out our first oil into towards the end of the second quarter next year.

John A. Manzoni

I hope, Greg, that answers your question.

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

Yes. Just a couple of follow-ups there then. Do you expect to recoup any costs out of this ultimately? And, John, I think you've mentioned before, this was like the last project to go through before you'd implemented that new gating process that you -- so this isn't something you'd ever expect to be even remotely replicated?

John A. Manzoni

I hope not, Greg. I think, in fact, I mean, in terms of sort of cost and things, in fact, the -- curiously, because of the nature of the contract between us and the contractor, the contractor is obliged to pay the work for this. So that's now. Of course that would go -- the contractor may take a few different view. But all of that I think to come and I think, best left to the future, frankly, until we can find out. So today, I'm expecting that the cost will be recouped from the contractor as per the contract.

Operator

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

Brian C. Dutton - Crédit Suisse AG, Research Division

John, I was wondering if you could give us some insight into your farm out to Total on the Sageri block. Is there anything more strategic behind that farm out other than just reducing your economic risk in the well?

John A. Manzoni

Thank you, Brian. Let me ask Richard to chat about the farm out to Total and the rationale behind it.

Richard Herbert

Yes, Brian, I think the short answer is sort of 2 main reasons. One, as you mentioned, is we have fairly high equity as Talisman in the south Makassar in Indonesia, particularly in the Sageri block where we were, before the farm out, we had 100% of the equity. And it's not a position that Talisman really wants to be and to be having such a high equity. So we were looking for a partner who would take some of the equity. And in terms of Total, of course, one of the attractions is that Total operates the relatively nearby Bontang LNG plant in Kalimantan. And therefore, as an option, and at this stage, it is just an option, but clearly an option that they have identified as being attractive is that if we find large quantities of gas -- and we do believe we're more likely to find gas here than oil. If we do find gas, then we've clearly got an option to tie that back into the Bontang plant, which is quite a mature plant where the nearby gas resources are now somewhat depleted. So those are the 2 main reasons behind it.

John A. Manzoni

So a short answer, Brian, I think is yes. There's a strategic rationale for the partner that we have chosen. And indeed, entering that area with a high equity was a deliberate strategy in order to create the opportunity to subsequently farm down to a strategic partner.

Brian C. Dutton - Crédit Suisse AG, Research Division

Second question, I know there's been a lot of discussion here on Yme, but if we just look at the current production in Norway, can you give us some insight given the maintenance on one hand but also the declines that you're looking at? What should we be expecting for production from Norway over the next few quarters prior to Yme coming on stream?

John A. Manzoni

Well, what I've said Brian, is that North Sea as a whole, which is you acquired between 110,000 and 140,000 barrels a day, constant. And of course, the swing was largely the timing of Yme, is going to be toward the bottom of that range. As you recall, I've also said that we'll be between 80,000 and 90,000 barrels a day in the U.K. I think we'll be at the bottom of that range and we maybe just marginally below that because of the Tweedsmuir issue this year that I've discussed with you. So you can do the sums, and you will end up somewhere between sort of 30 -- I'm doing it in my head -- but 33, 36, something like that, Brian, in the next few quarters in Norway.

Operator

Your next question comes from the line of Brian Singer with Goldman Sachs.

Brian Singer - Goldman Sachs Group Inc., Research Division

I wanted to go back to Colombia. I think you mentioned that Akacias well was producing about 16,000 barrels a day. As point of clarification, I wanted to see if that is apples-to-apples with your 1, 250 barrels a day that you reported I think at the time of your Analyst Day and whether there's been an improvement in performance there. But more broadly, I also wanted to see if you could touch on when we look at how many more successful wells you would need to see between appraisals at Akacias exploration at Humadea to be able to declare commercial analogies on Block 9 with Chichimene and Castilla fields?

John A. Manzoni

Good questions. Always the danger of giving the explorers' numbers, Brian. So let me just see if I could ask Richard to address, first of all, the Akacias is long-term test and secondly, maybe more specifically about the appraisal wells that we actually plan to drill this year and whether or not that will nail it.

Richard Herbert

Brian, the difference in the flow rates is actually a gradual improvement as the well is stabilized. We've actually seen the oil rate go up. Part of this is the amount of sort of drilling fluid and water that's in there has reduced over time. And secondly the well is producing on an ESP, a submersible pump and we've been able to tune the frequency of that up and get the production up. So that's the reason for that. In terms of how much data do we now need, I mean, we have one well at the moment in Block 9 into this discovery. And obviously now we're collecting some dynamic data. We believe -- I mean, the critical issue here is where is the oil-water contact in terms of defining the scale of the field. And we won't know that until we have, first of all, mapped out the structure with more high quality seismic and also drilled a few more wells further down dip to try and find the oil-water contact. So we're expecting to shoot the seismic in the second half of this year and start a drilling program, which will probably end up being about 4 appraisal wells. But I would have thought even partway into that appraisal program, with some success and the right data, we'll be able to declare commerciality and move fairly quickly into a development plan.

John A. Manzoni

Does that help, Brian?

Brian Singer - Goldman Sachs Group Inc., Research Division

Yes, it does. And then as a follow-up or secondly, on the Marcellus, can you just talk to any, if at all, backlog of -- or abnormal backlog of wells drilled, uncompleted or completed and waiting pipe. And then whether you are doing or planning on drilling wells in zones on that acreage beyond the Marcellus?

John A. Manzoni

Very good. Let me ask -- he's just questioning the second part. We have...

Paul R. Smith

We can clarify all your question, Brian, in a moment. But...

Brian Singer - Goldman Sachs Group Inc., Research Division

If you're planning on drilling any of the upper Devonian zones or lower zones beyond the Marcellus shale wells horizontally?

John A. Manzoni

So on your first question, Brian, we continue to be in a place where we have little to no inventory currently, sitting behind you -- the egress oil compression. However, we're just in the process of -- in the second half of this year, our program starts to move east in towards Susquehanna County, which is the acreage that we acquired 2 years ago. That in the second half of the year, we will have wells that will be backlogged as we build out the infrastructure in that area. It's a virgin area for us in terms of infrastructure, and so the second half of this year is going to be a big buildout of infrastructure. So we will see some choking of wells this year behind egress that will become unblocked towards the end of this year and the beginning of next year. But it's an exciting new area moving into and hence, we're moving into it. The answer to your second question is no, we continue to focus today on the development of the main reservoir in the Marcellus, although we continue to look at other shales that clearly are present amongst some of our acreage. But that's not the focus of our development in the near term.

Operator

Your next question comes from the line of John Malone with Ticonderoga Securities.

John Malone - Ticonderoga Securities LLC, Research Division

Two relatively unrelated questions. The first one is, can you just give us sort of a general synopsis on what's happening in the Cardium, what you've been seeing, what you expect to see? And the second question, building on the Marcellus, I know that you assigned a value to the acreage that you have in New York. But given that the possibility of that coming online at some point, do you have sufficient infrastructure to handle it, can you bring it in? I know you've got about 600 million cubic feet of egress capacity, can that be expanded upon?

John A. Manzoni

Okay. So let me -- thank you, John. Let me ask Paul to talk to those 2 questions.

Paul R. Smith

Okay. In the Cardium, we've got, as we've said and as you know, roughly 200,000 acre position in the Cardium. We've got essentially 2 different programs going on. We've got a Talisman-operated program that we said we would drill and complete roughly 6 wells this year and then we've got a nonoperated program over a 50% partner with another large operator within the play. Together, we've drilled roughly 9 gross wells in the first half of this year. And I'd say that we are encouraged by the results that we see from those wells, and that encouragement means that we're going to continue this year drilling into both those parts of the play as we continue to de-risk the Cardium. But results are very much in line with the expectations that we've set, and we continue to be highly encouraged by the oil rates that we're seeing from those wells. Secondly, your question around New York. I mean, you're more -- you're as aware as I am of the SGEIS process. Essentially, we're going to start a 60-day consultation period in August. And the earliest that, I think, any of us could see any potential activity is in the first half of next year. And that, I think, is a stretch given all of the other factors that will no doubt go into play in the coming months as this goes through a public consultation exercise. In the meantime, as you know, our acreage continues to expire and so that by this time next year, we'll be close to 100,000 acres in the New York side of the Marcellus. And of course, not all of that acreage is prospective at current gas prices. So we'll continue to look at all of this, and we are ready to start to drill into the New York side of the Marcellus as and when New York's open for business again.

Operator

Your next question comes from the line of Pawel Rajszel with Veritas Investment.

Pawel Rajszel - Veritas Investment Research Corporation

I've got a few of them. First one is, can you talk a little bit more about the Eagle Ford acreage that you picked up in particular, the county and the amount of acreage?

Paul R. Smith

Yes -- sorry.

John A. Manzoni

Go ahead.

Paul R. Smith

Thank you, John. Yes, as you know, we have an AMI of the whole of the Eagle Ford with Statoil. We together, picked up a 7,000 net to each party block, so gross over -- roughly 15,400 acres. From St. Mary's, they announced that, the deal is due to close this quarter. We paid an average of $14,500 an acre for our 7,700 acres. And it's right next door to our -- it's contiguous with our acreage in La Salle County which, as you know, is in the -- right in the middle of retrograde condensate fairway there. So we like the acreage a lot, we like the deal, and it's a shame it's only 7,700 acres.

Pawel Rajszel - Veritas Investment Research Corporation

And any land expiries coming up in terms of Pennsylvanian Marcelllus or even Eagle Ford?

John A. Manzoni

No, there are no -- we're not -- of course, there are expiries but they're being managed within the program. There are no significant expiries coming up in either play.

Pawel Rajszel - Veritas Investment Research Corporation

And just to go back to earlier question, given your options between international shale/unconventional opportunities and North America, you've clearly picked the $500 million investment into the Duvernay here. Is the choice of going with more North American shale given the low gas price, a vote of confidence that you think the gas price is going to rebound?

John A. Manzoni

Let me see if I can answer that one. With the Duvernay, we anticipate, Pawel, to be liquids rich, so we're targeting liquids rich shales here in North America. Our long-term view of the gas price frankly, is I think I've said, modest rebound. It's going to be set by marginal cost which I don't think is going to be hugely higher than it is today, although it will be a little bit higher, we think. So we're looking at liquids-rich shales and the Duvernay was exactly that. It was targeting a liquids-rich shale. And as Richard has described, we're also looking at liquids-rich shales in other parts of the world. But in some parts of the world, where there are particular reasons to believe that the gas prices won't be structurally as low as North America, we're looking at dry gas as well. That would be Poland, as an example, probably where we think that gas prices will hold higher. So it's sort of horses for courses, but that gives you a little bit of a frame.

Pawel Rajszel - Veritas Investment Research Corporation

Okay. And then lastly, just wondering for your Ocensa pipeline in Colombia. Could you talk about the capacity you currently have on it, as well as any kind of potential capacity expansions that you could put in there in the future?

John A. Manzoni

Okay. So, let's have Scott answer that question.

L. Scott Thomson

Pawel, it's a 560,000 barrels per day pipeline. And we have 12.5% of that. So, as I had mentioned, a lot of -- enough egress to fulfill the plans that Richard had laid out.

Pawel Rajszel - Veritas Investment Research Corporation

And any potential to expand that if required?

L. Scott Thomson

I think that there is potential to expand Ocensa, but there's also potential for other pipelines. I think the current potential expansion of Ocensa is about 100,000 barrels per day, but there's a lot of other pipeline activity in the area.

John A. Manzoni

It's not uniquely Ocensa, Pawel.

Operator

Your next question comes from the line of John Herrlin with Société Générale.

John P. Herrlin - Societe Generale Cross Asset Research

A couple of quick ones. If you find gas in Indonesia, what kind of processing cost would there be for LNG Bontang since Indonesia is going down 10% a year overall?

John A. Manzoni

Do you mean the pricing is going down 10%?

John P. Herrlin - Societe Generale Cross Asset Research

No, no. The volumes are going down from Indonesia pretty dramatically in terms of LNG exports. So clearly, there's a lot of spare capacity. Total has a lot of spare capacity. I was wondering about the processing cost was.

John A. Manzoni

Sure. Thank you, John. Let me see if -- Paul, do you want to see if you can give a bit of flavor on that question? Paul Blakeley?

A. Paul Blakeley

I certainly couldn't speak today to processing costs at Bontang. I mean the principal is the facilities are there, they're underutilized, there is capacity through a number of trains. There is also a lot of other activity in the area looking to take advantage of that capacity. So really it is too early to say.

John P. Herrlin - Societe Generale Cross Asset Research

Okay. That's fine. Is it possible for somebody to tell me what the U.S. gas volumes were in total North America, the U.S. gas volumes sequentially like first quarter to second quarter?

John A. Manzoni

U.S. gas volume? I'll tell you what, John, because we'll be scrambling to try and find that. Can we come back to you...

John P. Herrlin - Societe Generale Cross Asset Research

Have someone call me, that's fine.

John A. Manzoni

That would be great. Maybe Chris LeGallais can call you after this and give you detail.

John P. Herrlin - Societe Generale Cross Asset Research

Okay. Next one for me. You've cut these deals with Sasol. Gas-to-liquids projects put out a lot of global greenhouse gases. Have you thought about the emission side of things, not just the conversion side?

John A. Manzoni

The answer to that is yes, but this might be an opportunity to ask Tony Meggs to give you a comment on where we are with our gas-to-liquid and greenhouse gas. Tony?

Unknown Executive

Yes, thank you, John. We're in the early stages of our feasibility study right now, which really got ramped up about 3 months ago and will be finished around the middle of next year. Our greenhouse gas emissions are clearly a part of the multi-faceted study. So we're looking at total emissions. We're looking at mitigation opportunities, what they might cost and how they may be constructed. But at the moment, it's too early to tell. We'll be done with the study around the middle of next year, which then brings us to the next decision, which is whether or not to enter into the feed study, which is then another 2-year study or engineering design work before we would move into a full project. So the point I want to make is that it's the early days of our evaluation. We have decision points along the way. And all of these things, including emissions, will be a factor in our decision.

John P. Herrlin - Societe Generale Cross Asset Research

Okay; last one for me. John, you've made a lot of portfolio changes since you've come on board. This quarter's results were kind of reminiscent of other hiccups in the prior administration, so to speak. Do you think you've cleaned up the portfolio enough or assets still a little bit to disparate? Or is this just hiccup-related overall to change in the mix, so to speak, of how you've reconfigured things?

John A. Manzoni

Well, John, let me answer that in a couple of ways for you. Number one, the disparate nature of Talisman, vis-à-vis some of our competitors, I believe, is always a point of discussion and always a point of attention for our leadership team. I do believe fundamentally that the combination of unconventional and conventional activity will prove ultimately to be a winning combination, partly because the -- with the success through the drill bit, the returns available to invest in the development coming from our exploration program, I think, will be superior potentially to some of the -- to the unconventional returns. And we're already seeing that in dry gas. We've yet to see how much liquids-rich shale is available to see if there's enough to go around. So I think, point one, unconventional/conventional structure of portfolio continues to be good, and I think we'll prove over time to be a superior choice. I would say to you that one's never -- we're never idle in examining options in the portfolio. We are constantly looking at whether or not there are better structural conditions for the company. I'm making nothing other than a general statement today, and it's a statement I would make at any point to say that we're always looking, frankly, at parts of the portfolio, big bits, little bits to see if there are optimizations that can be made. I've said we've structured the portfolio, which essentially has the North Sea to date and actually our conventional North American portfolio sitting as a constant. Note the North Sea is still within the range despite all the issues that I gave of 110,000 to 140,000. It's a sort of -- we can hold those levels through 2020. In the North Sea particularly, it's leveraged to the oil price. So those are the pluses. We're clearly seeing some execution issues and we've got to address those and we've got to think about those. So suffice to say, we're always looking, always thinking, never standing still on that issue.

Operator

Your next question comes from the line of Menno Hulshof with TD Securities.

Menno Hulshof - TD Newcrest Capital Inc., Research Division

I just have one question. I was wondering if you could comment on the dispute between Vietnam and China in the South China Sea and as to whether or not that is affecting your activities on Block 133 and 134? And as a follow-up to that, given that the area appears to be contested, is it causing you to reconsider your development strategies for those assets?

John A. Manzoni

Thank you for the question, Menno. Let me ask Paul to talk a bit about whether or not that issue has affected our activities up to now.

A. Paul Blakeley

Okay, thanks. I mean, with respect to activities, in Vietnam, the license awards are all relatively new. So to date, all of our activity in the region has been centered around acquiring seismic. We've just completed a seismic survey, and that survey has gone well. I mean, I won't say it was not without incident but we don't believe it was anything other than an incident associated with a fishing boat being in the area while the seismic activity was being carried out. That aside, we don't see our ability to carry out our activity being restricted. But we're stepping through this very slowly and carefully, and we will commence drilling next year in one of the licenses. Again, we anticipate that, that drilling work will go ahead quite successfully. And beyond that, all I would say is that we hold licenses that are being granted by the Vietnamese government and we're operating under the remit of the Vietnam government.

John A. Manzoni

Does that get at it for you, Menno?

Menno Hulshof - TD Newcrest Capital Inc., Research Division

Yes, that covers it off.

Operator

Your next question comes from the line of Mike Dunn with FirstEnergy Capital.

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

Two quick questions. Your Duvernay acreage, what's your average working interests on that acreage? And second question, just wondering if you can talk about costs today that Yme and -- operating costs, how should we think about op costs at that field, if it does ramp up to the expected rates?

John A. Manzoni

Thank you, Mike. Let me ask Paul, if he knows, to talk about the working interest and then, see if we can shed any light on costs to date and operating costs, which we may or may not be able to do over the telephone here, so Paul.

Paul R. Smith

So Mike, the -- we've acquired our 360,000-acre position over the last 3 years through land sales on our own. So we have 100%% working interest in all of the acreage that we've acquired since 2009 when we led the first sale into the Duvernay.

John A. Manzoni

Thank you. Mike, looks like we don't have the operating cost projections going forward, so would you mind if we come back to you on that for the Yme platform?

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

Certainly and capital costs as well, if you can.

John A. Manzoni

Yes, okay. So why don't we come back on that and just get the numbers to you. It's an issue. We just don't have them in front us. I don't think.

Operator

Unfortunately, we have run out of time for questions. I'd turn the call back over to you, Mr. Manzoni.

John A. Manzoni

Okay. Thank you, Sean. Ladies and gentlemen, that's -- unusually, we've run out of time for questions which is -- so thank you for your interest. Thank you for your questions. And thank you for joining us for our conference call. We look forward to speaking to you again at the end of the next quarter. And with that, I think we'll close the call. Thanks very much.

Operator

This concludes today's conference call. You may now disconnect.

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