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Executives

Harold N. Kvisle - Chief Executive Officer, President, Independent Director and Member of Executive Committee

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

A. Paul Blakeley - Executive Vice-President of Asia-Pacific

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

Paul C. Warwick - Executive Vice-President of Europe-Atlantic

Analysts

Brian C. Dutton - Crédit Suisse AG, Research Division

Bob Brackett - Sanford C. Bernstein & Co., LLC., Research Division

Mark Polak - Scotiabank Global Banking and Markets, Research Division

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

Brian Singer - Goldman Sachs Group Inc., Research Division

George Toriola - UBS Investment Bank, Research Division

Matthew Portillo - Tudor, Pickering, Holt & Co. Securities, Inc., Research Division

Talisman Energy (TLM) Q1 2013 Earnings Call May 1, 2013 3:00 PM ET

Operator

Good morning. My name is Martina, and I'll be your conference operator today. At this time, I'd like to welcome everyone to the Talisman Energy Inc. 2013 First Quarter Results Conference Call. [Operator Instructions]

This call contains forward-looking information. Certain material factors and assumptions were applied in making the forecast and projections to be discussed in this call, and 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 1, 2013, 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, this conference call is being recorded on Wednesday, May 1 at 1:00 p.m. Mountain Time.

I will now turn the conference over to Mr. Hal Kvisle. You may begin your conference.

Harold N. Kvisle

Okay. Thank you, operator, and welcome everyone to our first quarter conference call. The Talisman executive team is with me here today and we'd be happy to answer questions once Scott Thomson and I go through our first quarter results.

As you know, we held our Annual General Meeting this morning, and that's the reason our conference call is being held later in the day. Thanks for bearing with us on that.

I emphasized 3 aspects of our first quarter results. First of all, because of new accounting rules, we have changed the way we report our U.K. and Colombia joint ventures, and Scott Thomson will provide more details on that. But in summary, we've tried to provide historically comparable figures in our press release and reconciliations in our financial statements to make it as easy as possible to understand the numbers.

Secondly, in March, at investor open house, we announced the production capital and cash flow guidance for 2013. And we've reviewed those full year numbers in light of our first quarter performance, and we fully expect we will meet that guidance for the full year.

And finally, in October of last year, we set all 4 strategic priorities to drive value creation, and we're making steady progress on all 4 of those priorities. Today, I'd like to discuss our first quarter results in the context of those 4 priorities, which we believe will lead to a more profitable and sustainable company and generate significant shareholder value.

Our first priority, as I've discussed before, is to live within our means. This means setting investment budgets that can be funded by operating cash flow with less reliance on asset sales to fund capital spending in future years and maintaining a strong balance sheet at all times.

Our 2013 guidance was for capital spending of approximately $3 billion compared to $4 billion in 2012, against the cash flow forecast of approximately $2.5 billion. Investing $3 billion with cash flow of $2.5 billion is obviously not quite living within our means. In 2013, we're working our way through a number of projects that were initiated in prior years in addition to our 2013 program, and it will take time to get capital in line with cash flow, but we're committed to doing that.

Consistent with our full year guidance, we invested $775 million during the first quarter, including our share of investments within the U.K. and Colombia joint ventures. That would be down roughly 25% from both 1 year ago and from the run rate in the fourth quarter of 2012. I'm comfortable that we will deliver our 2013 capital programs within our target of $3 billion for the full year.

Our press release cash flow of $517 million was down relative to the fourth quarter of last year, largely the result of selling 49% of our U.K. business in December, as well as lower netbacks and higher natural gas production in North America. Our 2012 cash flow forecast assumes growth in higher-margin production volumes in the second half of this year, and we remain committed to our full year target of $2.5 billion. Scott will provide more details on this.

Production for the quarter, adjusting for the U.K. transaction, was essentially flat compared to the fourth quarter of 2012. North American natural gas volumes declined relative to the previous quarter, but did exceed our expectations as a result of successful production optimization, notably in the Marcellus. We continue to defer North American gas development drilling. We see stronger NYMEX prices in the years ahead driven by power generation and industrial demand, and we will direct capital to gas development drilling when all of the markets support a good rate of return from those investments.

Looking forward, we don't see a lot of production growth in the second quarter with the exception of increasing volumes in the Eagle Ford, but we do expect a significant ramp in volumes in the third quarter and again in the fourth quarter.

In the first quarter, Eagle Ford production was only up slightly relative to the fourth quarter of last year. However, we have a large inventory of drilled wells that are being completed right now and tied in for production. We then increased our full-time completion crews from 1 crew to 3, and we expect to tie in about 50 wells in the second quarter compared to 18 during the first quarter.

Eagle Ford production averaged 21,000 barrels equivalent per day during the quarter. We expect to exit the second quarter with approximately 30,000 barrels equivalent per day and thereafter remain on track to meet our target of approximately 30,000 barrels equivalent for the full year.

In Asia Pacific, we're currently producing 4,000 boe a day from Kinabalu, which we expect will increase substantially as we continue with platform upgrades and a planned workover program. The Kinabalu property and our large adjacent Sabah acreage position holds significant potential for increased production over an extended life in a variety of ways: through production optimization, through infill and step-out drilling, through exploration and longer-term development. We're very pleased to be moving forward with Kinabalu redevelopment and adjacent exploration on the Sabah blocks.

Our HST/HSD developments offshore Vietnam are progressing on schedule and budget. All drilling and completion activities have now been completed, and first oil is expected around midyear with our share of near-term peak production expected to be about 12,000 barrels equivalent per day. We are projecting fourth quarter volume increases in both Colombia and Indonesia, as result of field development and incremental deliveries to market. In aggregate, we see incremental volume growth later this year and our production guidance remains in the range of 375,000 to 395,000 barrels equivalent per day.

Our second priority is to focus our capital program. We're investing in projects with better netbacks and fast recycle times, as evidenced by our near-term liquids growth. Approximately 90% of our capital spending this year will be directed at growing near-term, high-margin production.

As I mentioned, we have lingering obligations to complete prior-year projects that we would not necessarily initiate today. New capital has been carefully allocated to near-term, high-margin production.

Our third priority is to improve operational performance on all fronts. For example, we've reduced Eagle Ford drilling cycle times to less than 25 days in the first quarter and lowered our average drilling and completion costs in the Eagle Ford to around $8 million. We've accelerated new well tie-ins, we're working to optimize Eagle Ford well performance, and we expect to bring 3 new processing facilities online during the second quarter.

A number of our Eagle Ford wells are producing more liquids and less gas than expected, and while this has posed production challenges, having higher liquids content is a good problem to have.

The first quarter showed a noticeable reduction in G&A expenses relative to Q4. Some of this was simply the timing of various payments, but we also saw real cost reductions in Q1 and we will see more during the rest of the year.

During the quarter, we announced approximately 175 staff reductions as part of our plan to reduce G&A run rate by $100 million to $150 million by the end of this calendar year.

Our fourth priority is to unlock value within our portfolio through sales or joint ventures and to realize value from our long-dated exploration projects. Our target is to realize $2 billion to $3 billion in proceeds through the sale or joint venture of non-core assets over the next 12 to 18 months. This is an ongoing process, and we are making progress both in North America and internationally.

In Kurdistan, following the exciting Kurdamir-2 oil discovery in 2012, our objective this year is to understand the extent of the resource that we are on in the Kurdamir and Topkhana blocks and move forward from there. In the first quarter, we began drilling Kurdamir-3, which is expected to reach target depth in the third quarter.

In Colombia, after regulatory delays, we have resumed drilling in Block 9. We are now testing the first of 7 planned appraisal wells. We have 2 rigs on location drilling the second and third wells, and we plan to bring a 3rd rig to Block 9 later this year to drill an exploration well.

I'd now like to turn the call over to Scott Thomson. Scott will discuss commodity prices, our hedging program and our financial results. Scott?

L. Scott Thomson

Thanks, Hal. Q1 is a difficult quarter for comparative purposes because of the requirements in January 2013 under IFRS to move to equity accounting for both our U.K. and Equión joint ventures. In our press release, we've included the impact of both the U.K. and Equión in our non-GAAP cash flow for comparative purposes or you will see in the financial statements some of the GAAP comparisons around items like operating costs and DD&A are tricky because of both sale of 49% of the U.K. in the fourth quarter and also because the U.K. and Equión are now treated as one line in the financial statements as opposed to being included on a proportionate consolidation basis as in prior quarters.

I suspect some of you will have some questions as you readjust your models and our Investor Relations Department is equipped to assist you in this regard.

Non-GAAP cash flow in the quarter was $517 million compared to $675 million in the immediately preceding quarter. $100 million of the impact was simply due to the sale of the 49% stake in our U.K. business and the impact of ceasing the capitalization of interest on EMA and Auk South effective January 1, 2013, as a result of both of these assets moving back into the evaluation stage. The impact of the U.K. sale was approximately $70 million.

Excluding this one-time impact, cash flow was down approximately $60 million, primarily resulting from higher costs and lower production in North America and higher royalties in Southeast Asia. Southeast Asia royalties increased partly because of lower capital spend in Malaysia and partly because of the impact of an investment credit settlement that has reflected an increase in royalty rates in the quarter.

Taxes were also a bit higher than anticipated, primarily because of lower current tax recoveries in the U.K. as a result of lower capital spend, and in Asia, where losses generated in certain regions cannot be used to offset income and others.

The realized prices in the quarter were $59 per barrel, which was consistent with the fourth quarter. In the first quarter, the benefits of the amended pricing agreement in Indonesia was offset by the investment credit settlement. But for the rest of the year, we expect to benefit in the order of $10 million to $15 million per quarter from the revised pricing agreement.

In Southeast Asia, we continue to get a significant premium to Brent pricing. For example, Vietnam and Malaysia are seeing premiums of $5 to $6 over Brent. Although our first quarter production and cash flow results are low relative to full year projections, we are maintaining our full year guidance of 375,000 to 395,000 barrels per day, with cash flow of $2.5 billion. Our production and cash flow profiles are weighted to the second half of the year.

Looking forward to the remaining quarters, we are projecting the following: Continued quarter-on-quarter growth of Eagle Ford volumes and cash flow, with an expectation that Eagle Ford will meet its full year target of 30,000 barrels per day of production despite a relatively modest increase in Q1 2013; the full benefit of Kinabalu production and cash flow, despite 4,000 barrels per day of production, we didn't complete the lifting in Kinabalu in Q1 and, therefore, did not realize any cash flow in the quarter; significant production in cash flow from HST/HSD starting midyear; the full benefit of the higher quarter PGN gas prices. The first quarter impact was offset by the settlement of a historic credit dispute; reduced royalty rates in Malaysia as capital spend ramps in the latter half of the year; and continued benefits of operating and G&A cost reductions. The majority of these cash flow benefits will be seen in the third and fourth quarters.

GAAP operating expenses and DD&A are hard to compare at a quarter-to-quarter basis because of the impact of equity accounting and the sales in the U.K., but the trends are both positive. Operating expenses were $330 million for the quarter compared to $580 million in the immediately preceding quarter. In the non-U.K. portion of our business, we saw operating cost reduced primarily in Norway, which had higher maintenance in the fourth quarter of 2012. Excluding the U.K., our operating expenses were lower than Q4 2012 by approximately $45 million.

DD&A expense was down from $700 million in Q4 2012 to $420 million for the quarter. Aside from the impacts of equity accounting and the U.K. sale, we also experienced underlying reductions in DD&A because of the fourth quarter 2012 impact of de-booking proved reserves in North America.

G&A was $25 million lower than the immediately preceding quarter and down $16 million compared to the same quarter 1 year ago, due to phasing of certain costs, cost reduction activities and equity in non-core countries. We are making progress on the G&A side and we expect to reach our run rate target of $100 million to $150 million in G&A reduction by the end of the year.

Non-GAAP capital expenditures for the quarter, including exploration expense, was $775 million. Approximately $320 million was spent in North America, with the majority spent on the development of the Eagle Ford, and $250 million on North Sea development. In Southeast Asia, we spent approximately $125 million, with the majority spent on HST/HSD development and Corridor. HST/HSD is scheduled to come on midyear, with peak production profiles of approximately 10,000 barrels per day. The balance of our spend was primarily in Colombia, Kurdistan and Algeria. We reduced our capital spending from the prior year and we expect to be within the $3 billion range we've communicated in March.

At March 31, net debt was $4.1 billion from $3.7 billion at December 31, 2012. As expected, we had a free cash outflow during the quarter. In addition to the cash flow-CapEx gap in the quarter, the $50 million Kinabalu payment was made in the first quarter and is reflected in the movements in working capital. We primarily funded the free cash outflow with cash on hand and, therefore, did not see a significant increase in gross debt. The planned dispositions in the second half of the year will enable us to keep our balance sheet in good shape. It is also worth noting that we renewed our credit facility in the quarter and now have a $3 billion facility that is in place for the next 5 years.

Turning to our hedging program. During the first quarter, we had $32 million of cash outflow associated with our hedging program compared to $16 million in the immediately preceding quarter. In 2013, we have 70,000 barrels per day of oil hedged; 26,000 barrels of Brent collars with an average floor of $90 and an average ceiling of $108; WTI collars for 10,000 barrels with an average floor of $85 and an average ceiling of $104; and Brent swaps for 34,000 barrels at an average price of just over $105.

For 2014, we have 50,000 barrels per day of oil hedged; 20,000 barrels of Brent collars with an average floor of $92 and an average ceiling of $108; WTI collars for 5,000 barrels with an average floor of $80 and an average ceiling of $95; Brent swaps for 22,000 barrels at an average swap price of just over $101; and WTI swaps for 2,500 barrels at an average swap price just over $104. On the gas side, we have approximately 330 MMcf per day hedged in $3.50 by $4.75 collars in 2013.

In the first quarter, we significantly increased our 2014 GAAP hedges. We now have approximately 430 MMcf per day hedged, 190 MMcf per day of NYMEX collars with an average floor of $4.20 and an average ceiling of $4.75; and 240 MMcf per day in NYMEX swaps with an average price of $4.35.

We've also started to enter into some hedges on the gas side in 2015 given the attractive prices and our drilling aspirations in the Marcellus. We currently have approximately 125 MMcf per day hedged for 2015.

Those are my highlights. I'll turn the call back over to you, Hal.

Harold N. Kvisle

Okay. Thank you, Scott. So to summarize, we've achieved a lot and changed the company quite significantly in the past 6 months, and we continue to make steady progress.

We're already a more focused and disciplined company, focused on our 2 core regions and we are working to deliver value from our focused and disciplined activities. With the sale of roughly half our U.K. business in December, the North Sea now accounts for just over 10% of our production. And with the proceeds of that divestment, we've strengthened our balance sheet and regained our financial flexibility.

We significantly cut capital spending and refocused our investments on short-term, high-value production opportunities. We'll start to see the results of these changes in the second half of 2013, with an increase in liquids volumes and corresponding growth in cash flow.

We're taking steps to cut costs in all parts of our company and improve our operating performance. And we knew it would take time, but we're progressing the sale of between $2 billion and $3 billion in non-core assets, all of this for the singular purpose to significantly increase the value of your investment in Talisman.

Thanks for joining us today. We'd now be happy to take questions, and I'll turn it back to the conference call operator.

Question-and-Answer Session

Operator

[Operator Instructions] Your first question comes from the line of Brian Dutton from Crédit Suisse.

Brian C. Dutton - Crédit Suisse AG, Research Division

I have 2 questions on Southeast Asia. The first question's on Kinabalu. Could you give us some insight on the production ramp to date and how you see production building over the balance of the year?

Harold N. Kvisle

Brian, it's Hal Kvisle. I'm going to ask Paul Blakeley to give you a little bit of background on Kinabalu. Over to you, Paul.

A. Paul Blakeley

Sure. Well, the asset was safely transferred at year end, and we spent the first quarter really working on what were planned safety critical repairs and upgrades to the facilities. So nothing really that impacts production in the first quarter, hence, the production range at around 4,000 barrels. As we move in the second quarter, we have a work barge now alongside and we're starting to access some of the existing wells, doing some workovers and so on. And so we will start to see some impact from that activity in this quarter. And then later in the year, drilling rig, probably later in the third quarter, will arrive, and we have 3 wells planned for that operation. So towards the end of the year, again, significant increases in production would be planned. Those wells are now all targeted. We are very happy with what we see. It's exactly our view from the evaluation stage. So we're just now methodically working through it.

Brian C. Dutton - Crédit Suisse AG, Research Division

That's helpful. The second question is also on Southeast Asia, and there is some discussion in the opening comments about the Indonesian gas pricing. Could you give us some more insight in terms of the pricing you saw the quarter, the $11.7 -- I think it was $11.17 number, how should we be looking at pricing for the rest of the year in Indonesia?

Harold N. Kvisle

Well, as you heard in the introductory remarks, Brian, we see a benefit quarter-on-quarter about $10 million to $15 million coming from the renegotiated price this year at Corridor. There are further gas price adjustments in the future, which are still awaiting government approval and I'd rather not talk in any detail about them. Suffice to say that the renegotiation of these contracts is all about supporting further investment in the Corridor field in the future for the benefit of all stakeholders. But the first step, the price went up in September of last year, that will continue through this year. And then there'll be further increases in the future. But as we articulated, this year, $10 million to $15 million a quarter. And that's all I'd like to say.

Operator

Your next question comes from the line of Bob Brackett from Bernstein.

Bob Brackett - Sanford C. Bernstein & Co., LLC., Research Division

Yes, one question on those Eagle Ford wells. You're quoting a target of $8 million-well. Some of the competitors are closer to that $6, $6.5. Do you know -- is that something you target ultimately? Or is there something driving that cost differential?

Harold N. Kvisle

Well, I'd say, first of all, it depends on what kind of a well and at what depths you're in and how long the lateral is and all of that, and how many frac stages. So they're not all the same. I'll ask Paul Smith to comment through that. Paul, any thoughts?

Paul R. Smith

Yes, Bob, on average, in March, well costs have come down significantly, drilling and completion costs, on an average across the play, to about $8 million drilling and complete. But the range around that is -- I mean, we're drilling wells at 6 million or less in the Western part of our play, which is shallower. So you've got to be very careful and make sure that you have a like-for-like comparison as you look at drilling completion data. The most expensive wells are in the KDP area, which is deeper in the eastern part of the play. But there again, we're making great progress there, too. So we're very happy, I think, both with: A, where we are relative to competitors, and B, progress the progress that we're continuing to make. I mean, we don't know, as Hal said in his introductory remarks, down to cycle times across the play of less than 25 days, whereas 4 months ago, we were at 40 days. And I'm hoping that we should be able to see that come down to below 20 days as we progress through the year.

Bob Brackett - Sanford C. Bernstein & Co., LLC., Research Division

Great. And then a follow-up, could you give us some clarity around where you are in the HST/HSD sort of first oil, what are the steps that need to get done before we can get the first oil? And also, on the disposals process as well, what are some of the steps we should be watching for?

Harold N. Kvisle

As you heard, we are planning around midyear. As we sit here today, the facility installation has gone very well, everything is in place, all the wells are drilled, tied in. We're now commissioning the facilities offshore. And if things go according to our current plan, I believe we will see production ahead of our plan, our original plan, and we'll wait and see.

Harold N. Kvisle

And I'll ask Scott Thomson to comment on the divestments.

L. Scott Thomson

So on the disposals, Bob, or joint venture and partnering our disposals, the North Duvernay, we will have a data room open this month and we've made great progress on that. And you can see results around this are pretty encouraging on the Kaybob area. And on the Montney, that process continues. I mean, we're talking to a number of people about a number of different alternatives. So I suspect both of those will be a second half of 2013 situations. And then the other one that we're making a lot of progress on is the evaluation of the OCENSA pipeline. And as you know, we have a 12.1% stake there. And we are coming to the conclusion on selling the equity in the OCENSA pipeline, which has significant value. And again, that will be a 2013 activity, I suspect.

Bob Brackett - Sanford C. Bernstein & Co., LLC., Research Division

And those make up what bulk of the $2 billion to $3 billion?

Harold N. Kvisle

We have some other options that we're looking at as well. But Bob, those are the ones that we've announced so far. And I'll just add to what Scott said that something like the OCENSA pipeline equity, it's pretty clear to us that's a good candidate for sale. There is also a capacity right that comes with that pipeline, and that capacity is worth a lot of money to other people who do not have ways to get their production to market, the alternative being a very long haul trucking route. And so we're looking carefully at that and whether we're better to sell part of that capacity to producers who are short or whether we should keep it and be involved in commercial business around that, quite an existing opportunity, which would give us options for the future. On our Montney and North Duvernay, our base case has been to offer these properties for sale in a cash transaction. But we also are entertaining and looking closely at proposals for joint venture because if the net present value for our shareholders would be significantly higher by doing something like we did with Sasol in the first part of the Montney, we're certainly not averse to that. But the base case that we're pursuing is the sale for cash.

Operator

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

Mark Polak - Scotiabank Global Banking and Markets, Research Division

Actually all my questions have been answered.

Operator

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

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

Let me just start with a question for how you've been through turnarounds before. Just want to get your perspective on the results for the first quarter. Is that more or less lining up with what you expected? And then secondly is, when do you think Talisman will begin to turn the corner when it comes to restored operating momentum? Is that a 2013 event?

Harold N. Kvisle

Sure. Well, Greg, first, I'd note that it's somewhat observed that our results are something like $150 million of cash flow less than might have been expected. And when we would look at that, about half of that amount is the result of the divestment in the U.K. And some of the other shortfalls are things like ongoing difficult operating circumstances in the U.K., considering the helicopter groundings that have occurred there, the difficulty getting things done and the delay of some of our different projects and optimizations in the U.K., that has been part of the problem. At Kinabalu, where we've actually produced about 4,000 barrels a day for most of the quarter, but we did not ship any of that to market and so that did not get booked as cash flow. And then we had a couple of royalty and tax issues, notably in Southeast Asia, but in a couple of the other areas as well, that some of them just due to the pace of capital investment and the tax shelter that comes with that. So we would have like to have seen a better first quarter but as we look at the reasons for it, they're not fundamental, they're more circumstances that we had to deal with in the quarter. I think as we went through from October through December, we were fortunate that the operating teams in the company kept things going pretty well and our capital programs continued on track. I and my management team colleagues were very focused on thinking through the various strategies available to the company and putting those into a business plan, most of which you would have seen at the shareholder conference in Toronto in March, investor open house. So we have set out a course as conveyed in the investor open house and we're now on that. I tend to think of the first quarter of 2013 as the first quarter, the baseline, if you will, from the new direction for Talisman. And we're optimistic, as you can see, that we're going to meet our full year guidance for cash flow and production. And in order to do that, we have to see improved results in the second, third and fourth quarter, and those have all been part of the plan. So I think, Greg, that I would argue in some ways, we have turned the corner. But I don't, for a minute, diminish the amount of work that had to be done. We've got to get these divestments completed. We're on a drive to reduce the cost structure of everything we do, capital costs, operating costs, G&A, overhead, all of those things have to come down. We've really got to play to our competitive strengths. I think we have to focus on the Americas and on Asia Pacific and build our capabilities and our track record there. So I would just throw out the notion that this quarter was the first of the new era at Talisman.

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

Okay now, I mean, that's helpful. And just maybe to -- just to remind me or to go back in the fall thought processes, you're coming in for a couple of years at which point I think you mentioned this on a weekend, but you'd really like to hand over the reins to someone else coming in. So is the likelihood then that we'd still see a new CEO sometime in 2014, is that still the plan?

Harold N. Kvisle

Well, the plan, as I've said, is the board and I have agreed on 2 big objectives. The first one is to reposition the company, tighten things down and get it going in a new direction, and that's going to take a lot of time here yet ahead of us in 2013. And the second objective was for me to assist the board in appointing a new CEO. So those 2 things have to be done and I don't know, Greg, about particular dates. I don't have a particular date in mind, but I'm committed to sticking with it and getting those 2 things done. And once we're there, I'll think about what next.

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

Okay, no, no, that's good. Maybe just as a follow-up. Scott, what would the impact -- I mean, just wondering if you have it, the impact of Kinabalu. So we're going to model, we're going to stick that in the second quarter, I'm just curious if you know what the cash flow impact on the underliftings would have been?

L. Scott Thomson

Probably around $10 million to $15 million. And the reason that, that's a little bit lower than the full year impact at Kinabalu is because you hadn't spent capital money yet, the royalty rates were very high. So as we go through the rest of the year, capital will be spent, royalty rates will come down, and you'll see a pretty significant contribution for Kinabalu for the year. Actually, it is quite significant.

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

Okay, very good. And then $700 million, give or take, still a pretty reasonable number for cash tax this year?

L. Scott Thomson

That feels a little bit high actually. I mean, as you think about first quarter cash tax, I think it's pretty reflective of where we'll be for the remaining quarters. And Southeast Asia is where we're paying the majority of our tax. So $700 million feels a little bit high.

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

And then last question for me. Just in terms of the facility's expansion in the Eagle Ford in the second quarter, I know you've provided the gross number. What's the net uplift in your facility's capacity? In other words, if you completely open things up at the 4 stages, then, how much would you be able to produce in the Eagle Ford on a boe basis?

A. Paul Blakeley

Greg, it's Paul here. From a facility's perspective or from a wells perspective?

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

Well, why not both, Paul, because it sounds like there's a lot of wells you need to tie in.

Paul R. Smith

I mean, the underlying story, let me take you through the story, Greg, which I think will answer your questions, hopefully. We started -- if you remember last year, we had a single crew running in the Eagle Ford. We took 50 wells uncompleted into this year. We slowly brought on during the first quarter an additional crew a month. So by the time we got to March, we were running with 3 crews. But those 3 crews are now running, and I've had -- I've got a vast majority of the carryover from last year now behind them. And now the infrastructure was becoming the bottleneck. We've got 3 major new facilities coming onstream during the second quarter, which I think we mentioned in the press release. And collectively, between both the operational momentum from the first quarter in terms of getting completion behind us and now being able to tie those mostly into the facility, 3 major facilities going onstream, we're going to see a pretty rapid ramp in the second quarter, which we've always envisaged. So it was never going to be a linear ramp during the year. So we did 21 mbd in the first quarter. We'll exit the second quarter around 30 mbd, and we're, as we sit here today, we're sort of at about 24 to 25 mbd. So the ramp is already happening as we speak, commissioning end of April, beginning of May, to be precise.

Operator

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

Brian Singer - Goldman Sachs Group Inc., Research Division

I wanted to touch base on Colombia. Could you just put on perspective the Akacias-18 well and what that means for resource growth and the development plan for CPO-9?

Harold N. Kvisle

Well, I'd start out by saying that the first well has performed extremely well, pumping at nearly 2,000 barrels a day gross and relatively little evidence of either water encroachment or production decline, and has now accumulated more than 1 million barrels and continues to produce very well. Beyond that, and I'll ask Paul Warwick, if he would like to add anything to that. But I think the proof has got to be in the drilling of these appraisal wells, the 7-well program that's underway right now. We've seen very encouraging results from the seismic surveys, I should say encouraging indications from the seismic, which together with the first well that we drilled, makes us pretty optimistic. But I don't know, Paul, what else would you think about there?

Paul C. Warwick

I think it's too early to draw any absolute conclusions from Akacias-18. The original test data, we'd be running it on test, it looks pretty good. We have 2 further zones to test within the well before we put on the long-term test. But we're relatively optimistic about it. And as Hal said, you have to see this one well that's produced very well and continues to impress us by its performance. In the rest of the Akacias area, we're going to be spudding Akacias-19 hopefully this coming week. And the Akacias-9, we're drilling ahead and hopefully we'll be in the reservoir later on in the month of May. So I think there's reason to be optimistic. But it's too early to draw any absolute conclusions from it, but we'll see information through the next quarter, which perhaps would give indication.

Brian Singer - Goldman Sachs Group Inc., Research Division

And then in the North Sea, with regards to EMA, post the decommissioning agreement, can you talk about how you think about upstream resource there and whether that is something that you do plan on redeveloping or developing at some point or selling?

Paul C. Warwick

This is Paul Warwick, again. And yes, we have the agreement, but that's the end in terms of what to do with the existing facility. And to remind everybody, that includes removal of the MOPU structure, the top side design that's put into the build. The EMA partnership actually takes ownership of what's called the tank and the case arm. The tank being, what it says, seabed tank, which supports the case arm which is technically like a thin jacket that supports the risers in the subsea wells and sea platform wells. We're in the process of evaluating what the path forward is of project. Part of that is the sub-surface evaluation in which the original project was sanctioned some time ago. And as we go through that process, the EMA partnership, Talisman will determine what path forward will look like. So at this stage, we don't have an absolute plan about what the next phase will be. We have an indicative view that there will be a redevelopment since that particular part of the redevelopment, which will be the top side facility, will go through our standard project process and meet one of the various hurdles that we need to meet for it to be economic for our company.

Brian Singer - Goldman Sachs Group Inc., Research Division

And do you have some sense on the timing of when that planning process and the determination of whether you want to go forward will be complete?

Paul C. Warwick

I think it's unlikely to be before the end of this year. First, second quarter next year is a good timing. What we don't want to do is to just then off the back to our previous experience is just rush straight in and assume you know the answer to the next phase of EMA. So that's my conservative estimate. But we're not just going to jump and go into anything that has -- what looks like fast track associated with it in the next phase of the project.

Operator

Your next question comes from line of George Toriola from UBS.

George Toriola - UBS Investment Bank, Research Division

I have a couple of questions here. The first is on the Marcellus. You talked about the optimization activities that reduced the base decline to 7% from 10%. Can you provide a bit more color or is that a one-off? Is that something that will continue to reduce base decline out of the Marcellus?

Harold N. Kvisle

It's Hal here. I'll just quickly comment and then ask Paul Smith to add to it. First of all, I'm very impressed with what our Marcellus team has been able to do. They rolled up their sleeves and gone about addressing every production bottleneck and optimization opportunity that they can do without a lot of capital. We have not allocated a significant capital to the Marcellus, and they have significantly reduced the decline rate and are -- well, of course, delighted to see the reservoir outperforming in the absence of capital. To me, it's one of the best indicators for the longer term. With respect to specific things we can do, I'll ask Paul to comment. But obviously, things that optimize facilities, reduce back pressure, add wells and achieve better completions, those were all on our list. Paul?

Paul R. Smith

Yes, George, I mean, the overarching result is, as you know, that we're now forecasting for the year a decline of around 2.5% a month, which is 28% annualized, which is significantly less than we saw last year. We're primarily -- and that's on the base. We're primarily doing that with almost no capital expenditures. So it's going into the first in the house buckets, which is, no, really, utilizing a pretty extensive infrastructure position that we've got into both compression, in particular to reduce back pressures, flowing wells around certain facilities and really optimizing every single well as we go forward. Pretty innovative things on the wells as well. But clearly, we've gone after the low-hanging fruit first and it's a trend line that we can't continue forever. We'll continue to work it hard this year, but I don't think you should be assuming that we'll see much more than what I've -- what we forecast now, which is around a 2.5% base decline per month, which, as I said, is a big improvement from what we've seen before and is one of the reasons why the Marcellus is -- was able to produce 440 million [indiscernible] in the first quarter rather than a lower number that we had originally forecasted.

Harold N. Kvisle

And some of these decline figures depend on whether you're looking at relatively new wells that are still in the early stages -- or some of our wells have been onstream for several years now and have not really plateaued but are declining at a lower rate. One of the things we think about are 2 alternative scenarios: One, where production is stabilized to the 400 million a day level. For the very long term, we presented that slide at our investor open house. And when we looked at what kind of capital we have to spend and what kind of cash flow we'd get at $4 Henry Hub price, we can generate free cash flow in the $4 gas environment and sustain production of 400 million a day doing just enough drilling to offset decline and keep the facilities operating smoothly. In the event we saw quite a bit better gas price, we might decide to stabilize production at 500 million a day. It takes extra cash flow reinvestment to do that, but if the price is there, it's a wise thing to do. So we're developing a little bit different way of looking at the Marcellus, how could it be stabilized for the longer term in a profitable way and focused on maximizing margin at different production rates and prices.

George Toriola - UBS Investment Bank, Research Division

I have 2 more questions. The next one is on the dispositions you plan out of the Duvernay and the Montney. Why the slightly different tact where you have a data room for the Duvernay asset or you plan to open a data room and you have targeted discussions for the Montney? Why that approach?

Harold N. Kvisle

Well, the Montney is a much more enormous asset, enormous resource. We did a very noteworthy deal with Sasol a couple of years ago, that I think has been a great thing for Talisman and we've been able to secure very substantial funding. But that would be focused on less than 1/3 of our total Montney position. What this company sits on in the Montney could constitute something like 25 to 30 tcf of recoverable reserves. It's an enormous number. And when we look at the Montney, I think we're looking at it a little bit differently now, not as a single entity but we really see 3 or 4 distinct parts to the Montney, one of which is in the Sasol joint venture. So as we look at it -- and the reason for the targeted approach is that we really see 2 camps, one, being potential Asian buyers who would want us to be there as a partner and for whom a joint venture would be the right approach versus, say, the super major companies who might like to buy our resource base but they don't need our operating capabilities. So we've decided to talk to a relatively select number of people about it. And it's interesting that as a said earlier, at $3.50 gas price, it's difficult to see any cash flow off the Montney and very much value in it. And at $5.50 or $6, it's by a wide margin, the most valuable property this company has. So it's highly lever to gas price. If we could find a targeted partner that would be taking some portion of that to the LNG market in some way that we shared some of the upside, ideally without us making a multibillion dollar commitment to an LNG value chain, that, of course, would be the very best possible outcome. In North Duvernay, we decided to take a different approach simply because of the number of players there, the size of the play, the general industry excitement today. Very often on these things, the winning bidder is not someone that you would have expected. And so we wanted to open the playing field wide and just see how this thing might unfold. But I would say once again, there are different camps. There are the people who would like to acquire our land position in its entirety. There are people who would be very keen to acquire a portion of our land position in the areas where they operate, and there are the international players who would like to do a joint venture with us similar to what the Chinese company did with Encana. So we're open-minded about all of those options.

George Toriola - UBS Investment Bank, Research Division

And last question for me. Just around your second priority, which you've talked about today, which is focusing your capital program on high-margin opportunities and then the near-term cash flow. What metric do you use internally? Is it payback period? Is it -- I assume that you're hurdle rates within the company have not changed. So when you talk about focusing capital on high-margin production, I'm just wondering what metric are you using to screen those projects such that they actually meet this objective?

Harold N. Kvisle

Sure. Well, we look primarily at the net present value divided by capital, in other words we call it DPI or CPI, capital productivity index, so it's really an MPV calculation and a discount rate, hurdle rate of return, look at things. But I think the question for us is a little different than that. It's strategically, are we going to put a significant amount of money into buying a very large long-term position in a play that looks like it could create enormous value over 20 years? Or at this time, are we going to be more focused on perhaps development drilling in the Marcellus, where the long-term rate of return might not look as good but the risk is not as high, we can hedge in the forward market, we can do more to ramp up near-term cash flow and just live in a little different world of running harder and faster in the near term to maximize near-term cash flow and our outlook over the next 5 years and not as much money as we've done in the past into very long-dated opportunities and some of the very expensive high-risk international wild accounting, you won't see us do as much of that.

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

And so how does your hedge in -- so for example, the hedges that you've laid out for 2014, in natural gas, for example, how does it impact that? Does that sort of provide that price exposure that you need such that you can then pursue some of those projects? Or how does your hedging go into this?

Harold N. Kvisle

I think that's right. I mean, we need -- 3 parts to really come together. We need to have good investment plans in places like the Marcellus and in our Edson core area. And the teams have put those together. And we know when the gas price improves and our capital availability improves, we know where we would want to drill. And the second piece of the puzzle is what is the gas price, and we're actively looking at the forward market. We continue to sell forward. And if we saw that we could drill off significant incremental gas, we, of course, simply hedge more of our production forward and drill into that market. But the third part of it is really capital availability. And into some degree, we're not prepared to run up our bank debt to pay for drilling programs. But if we are successful on divestments, we would earmark a portion of the proceeds to increase activity levels, notably, in places like Marcellus.

Operator

Your next question comes from the line of Matt Portillo from Tudor, Pickering, Holt.

Matthew Portillo - Tudor, Pickering, Holt & Co. Securities, Inc., Research Division

Just a few quick questions for me. In terms of the Marcellus, I think in your press release, you mentioned you have 50 uncompleted wells. With the run up in gas price here, I was curious if we've reached the point where you're interested in starting to blow down that backlog and what sort of pipeline capacity or takeaway capacity do you have to increase production from here?

Harold N. Kvisle

Well, we are interested. It looks pretty good right now and we do have pipe capacity. But Paul, could you comment on that?

Paul R. Smith

I think Matt, Hal has answered the question and it is the previous answer, that previous question, but with current gas prices going above $4, which is sort of starting to hit a zone where it becomes interesting to look at incremental activity. But I don't think we're in a position today to do that without capital constraints. As Hal says, if that changes at some point in the future, then it's going to be fairly easy for us to get after the 50 wells and our egress out of the Marcellus is not going to be constraint in any way, shape, or form. We're pretty well capitalized. In fact, we're actually mitigating a lot of the unused capacity by further design constraint. But if you consider that we were flowing at 600 million late last year, we're now down 440 million, that's not really the constraint, Matt, as we think about incremental activity later this year or early next year in the Marcellus.

Matthew Portillo - Tudor, Pickering, Holt & Co. Securities, Inc., Research Division

And just on the drilling side, obviously, as you guys move into Bradford, Susquehanna, you have acreage that's coming up for expiry here. Could you give us a little color on how many rigs you probably need to, to hold that acreage, the timing of that drilling campaign and with gas at kind of 4.25, 4.50 on the forward strip, should we expect to see in the back end of '13 and heading '14 an acceleration of your drilling campaign in the Marcellus to hold acreage?

Harold N. Kvisle

I mean, you're right, Matt. We are probably the -- a we haven't got a lot of expiries in what we call our current forward Brent but -- and at Chaffee, where we've got continuous lease obligations that are being managed through relatively most programs. We've got a very high-quality position in Susquehanna of about 20,000 acres that does have an expiry profile that peaks next year. And we will be moving the one rig we have operating in the Marcellus, away from Chaffee into that area in September this year to start drilling into that. And we will probably look to pick up a second rig in the of middle of next year to complete our drilling obligation by the end of next year in that area. But it's a relatively modest program to protect 20,000 acres that are just north of what I consider the super sweet spot of the play which is the [indiscernible] super sweet spot which is north of that. So these are some of our best rocks and we don't want to see them walk away from us. And we can protect them relatively modestly and we might do that on our own. And we might look to do that with a partner.

Matthew Portillo - Tudor, Pickering, Holt & Co. Securities, Inc., Research Division

And to that -- a couple as the last point, you have a very sizable acreage positioning here in the Marcellus, very low cost gas and you were at one point running a 10-rig count, which is probably appropriate given the number of locations you have. How do you kind of weigh slowing growth and kind of living within cash flow versus effectively developing this asset from an MPV perspective? And is this something that you should or could look to monetize either through a JV or an outright asset sale or would either monetizations likely fund a re-acceleration of your Marcellus growth going forward?

Harold N. Kvisle

Well, in my experience, the traditional way of looking at this, in other words, ramping production up to 1 Bcf a day and then seeing it decline at 100 million a day per year for the next 20 years, that's not necessarily the most MPV effective way because when you're on the MPV, you don't really know what the future is going to hold. And one of the great advantages of building out to a rate that you can sustain flat production for a long time to keep a whole bunch of options open. And then if the world shifts to an $8 price, we can ramp up production to a higher plateau. And if the world shifts to a lower price, we can ramp down but stabilize at that rate, maintaining some sort of a steady-state operation. I'm always interested in the option value of these different strategies and how we look at the different things that we might do if the world turns out different than the price deck that we're using or the cost structure that we're using in our forecast. So I'm not sure that the old thinking around maximized production in the near term just to maximizing MPV necessarily creates the most value for shareholders. Having said that, that's what I've done with almost every property I've developed in my career. So we just have to -- weigh off and balance here the capital we've got available to us and the sustainable production over a long period of time. We'll, of course, at all times looking at MPV as the primary driver of what we do. It's just that I do worry about the assumptions that go into it.

Matthew Portillo - Tudor, Pickering, Holt & Co. Securities, Inc., Research Division

One last quick question from me, just on the international front. In Colombia, could you give us an update were see the permitting for CPE-6? And then I was curious if you could talk briefly on your Huron-2 test and how that potentially could bring forward some development there if that's been successful?

Harold N. Kvisle

So I'll comment first on the permitting for Block 6. We're in that block, of course, with Pacific Rubiales and we've been waiting on the edge of our chairs for many quarters now for those permits to come through. The latest, I understand, is that we're relatively optimistic we're going to get them soon. I don't have much more for you than that because we've been wrong before, so I hate to go out and be too optimistic here. But I'll ask Paul Warwick, his thoughts to that and also to comment on here on and the broader Equión joint venture.

Paul C. Warwick

I don't have anything in addition to say on the permit as well. I think we have expectations that we've been in that position before. On Huron-2, where testing is underway, that there is a potential frac, which we could take in that well. We're drilling in Huron-3 as well and we're quite optimistic about the results that we're getting there with 3D seismic at this time as well. And the whole context of the Huron area, the Niscota Block in its entirety, is something that we're trying to evaluate. It's still early days, but at the moment, it's looking very positive.

Harold N. Kvisle

So if the Niscota-Huron area unfolds as we hope it will, it's a very significant extension to the business that Equión has been focused on, complex reservoirs, light oil, volatile, really good stuff. And we've got a lot of infrastructure in the area that we could use. I'd point out that on the Huron wells, we also have environmental permitting difficulties, and the team was able to successfully navigate those. We didn't say a lot about that before, but I think the team deserves full credit for what they were able to do and get moving ahead for those Huron wells and we should have some results soon.

Operator

We have ran out of time for questions. I turn the call back over to Mr. Kvisle.

Harold N. Kvisle

Okay. Well, thank you, everyone, for joining us today. We appreciate your interest and look forward to catching up with you soon. If you have any questions or would like any follow-up information, please contact Lyle McLeod and our Investor Relations group, and thanks for calling in. Bye for now.

Operator

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

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Source: Talisman Energy Management Discusses Q1 2013 Results - Earnings Call Transcript
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