At this time I would like to welcome everyone to the Talisman Energy Inc. 2011 guidance 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 January 11, 2011 news release in Talisman’s most recent annual information form, which contain official information about the applicable risk factors and assumptions.
I would like to remind everyone that this conference call is being recorded on Tuesday, January 11 at 11 am Mountain Time. I will not turn the conference over to Mr. John Manzoni. You may begin your conference.
Thank you operator. Ladies and gentlemen, good morning. This is John Manzoni and thank you for joining our conference call today, where we'll run through the main components of our activities for 2011. I'm joined here in Calgary by the management team, who will of course be happy to answer your questions after Scott and I have run over the key points.
I want to draw your attention to the fact that everything I say today will be in U.S. dollars, because from the first of this year we will be reporting in U.S. dollars. We've made that decision because our functional currency is predominantly U.S. dollars, and many of our peer companies report that way.
We'll report fourth quarter 2010 results next month in Canadian dollars, and then for our 1Q results, we'll be in U.S. dollars. I hope it's not too confusing for you, because I will talk about the 2010 cap ex number, for instance, in U.S. dollars in this call, just to make the comparables easier as we discuss 2011. But given the fact that for 2010 anyway, the Canadian and U.S. dollar numbers are very similar, I hope you'll be able to follow.
Before looking forward, I think it's helpful to recap the key achievements of 2010, because that sets the context for what we'll set out to do this year. Of course, the numbers aren't finalized yet, and won't be until we release our year-end results in mid-February, but we can certainly give you a sense.
So to recap 2010, first and most importantly, we continued to improve our safety record. I think we'll have improved our injury rate by about 10-15% over 2009 on top of the 40% improvement we saw the previous year. So we're building a safer business, and we've set ourselves some ambitious targets again this year to continue that journey.
We successfully sold $2.2 billion of assets through last year, all with very good metrics, and that allowed us to reposition the portfolio substantially through the year, with about $2 billion of acquisitions including some discoveries in Norway, the BP Colombia acquisition with our partner Ecopetrol, and our deepening in the Eagle Ford jointly with Statoil.
And of course, just before Christmas, we came to an agreement with Sasol, who will become our partner in the Farrell Creek Area of the Montney. In addition to jointly developing the area, we'll commence a joint feasibility study to investigate the possibility of a gas-to-liquids option for Farrell Creek gas, which I think is a very interesting option for the future.
We've built from a small base to become the largest Marcellus producer, exiting the year at 315 million cubic feet a day, above the top end of the range we had previously outlined. And in 2010 we saw further progress in repositioning our expiration program.
We added promising new licenses in Latin America and Southeast Asia in our core exploration areas, and entered Poland to explore its shale gas potential. And we had expiration success in Colombia in the exciting heavy oil trend in the southeast of the country, with an oil discovery in Block 9, and encouragement from stratigraphic drilling in Block 6.
We successfully appraised the Situche Central discovery in Peru, and we encountered an oil lake below the previously tested [gas cap] in the Kurdamir 1 well in Kurdistan. We also participated in successful appraisal of the Beta discovery in Norway, which flowed and more than 10,000 barrels a day on test.
We're currently drilling the TR1 well in the U.K., which will complete operations in the next few weeks, and early results are encouraging. In Indonesia, the Pasangkayu Bravo well was disappointing and failed to find hydrocarbons, but we're a little more excited about the prospects for South Makassar, which we'll drill this year.
Our capital costs have been well managed through the last year, with projects largely being delivered on time and on budget, and we expect to end up having spent just under $4 billion cash capital on exploration and development activities in 2010.
F&D costs came down more than 45% from 2008-2009 and as we projected all through last year, I anticipate we'll be able to report a further reduction of between 25% and 30% in total F&D and around 45% to 50% in drill bit F&D when we announce our results in a month's time, and production has now started to grow.
As I mentioned in our third quarter conference call, we can look forward to increasing production into next year. We expect to deliver around 415,000 barrels a day for 2010, which is substantially higher than I had indicated to you at the beginning of the year and reflects good performance across the business.
Overall, we've repositioned the portfolio for sustainable, profitable growth into the future, and most recently we've used our flexibility to adjust spending toward liquid opportunities while gas prices remain relatively low.
So now turning to this year, 2011, the gas prices in North America are behaving pretty much as expected, and we don't think that will change much through this year. It's all about supply, and for all the reasons everyone is now familiar with, we see this situation continuing more or less through 2011, although the most recent cold weather has supported prices above $4.00.
I hope that by 2012 we might see some slowdown in drilling, but it's possible that the oversupply situation could push into 2012 as well. We need to be ready for that, and we'll keep a close eye on it as we go through this year. We're planning this year on a base price of about $4.00, and we're adjusting our investment plans accordingly, which I'll describe for you in a moment.
Internationally, the gas prices look firmer, both in Europe and in Asia. The market is starting to look forward now in Asia, to a supply and demand balance which is tightening into the medium term, and the oil price linkage appears to be holding firm.
Oil prices have firmed, with some unexpectedly strong underlying fundamentals. Demand has been continuously revised upwards through the last year, and inventories have been drawn down, even in the OECD economies, reflecting the strong economic rebound.
We had felt that there was a chance that the oil price might pull back a little in the first half of this year, as that economic rebound normalized, but the most recent actions, in particular by the U.S. government, to maintain the momentum in the U.S. economy might make that less likely. Overall, the oil price seems to be influenced by macroeconomic sentiment as much as fundamentals, but the underlying fundamentals do seem to be good.
So it's in that context that we set our 2011 activities. The main implication is that we have to maintain flexibility and adjust our investment to reflect a weaker gas price, which could be here for a while. I want to begin by giving you the 2011 headlines, and then I'll go back and provide some of the detail and color behind those headlines.
So first, we'll growth business off our expected 2010 outcome of 415,000 barrels a day, by between 5% and 10% organically, approximately 50% of which will be liquids. Our recent acquisition of BP Colombia, which happens also to be approximately 50% liquids, comes on top of that, and adds between 12,000 and 15,000 barrels a day this year. That growth rate, of course, is considerably higher on a continuing operations basis, because of the disposals we made last year.
We'll do this by spending about $4 billion cash capital on exploration and development activities in 2011. In other words, more or less the same as we spent last year. We think that this is likely to be slightly more than cash flow at consensus prices, but of course the outcome will depend on the commodity prices through the year, and as you know, we're particularly leveraged to the oil price.
Our balance sheet is certainly strong enough to handle a slight draw through the year. We don't plan any major disposals this year, which is not to say there won't be any, as we're always looking to high grade the portfolio, but we're not entering the year with a big plan for disposals like we did 12 months ago.
Our profitability has improved each year since 2008, and I think it will continue to strengthen through 2010 and through 2011 as we bring down drill bit and total F&D costs. We should look to a further improvement of PDP F&Ds this year of maybe 10-20% as it converges toward total F&D. And we have some very exciting exploration wells to drill this year in Colombia, deep water Makassar, Kurdistan, and the North Sea.
Internally, we'll continue to build capability and capacity in our organization. I'm delighted with the progress so far, but there is more to do, whether it's safety standards, IT systems, or project management skills, and we'll concentrate in 2011 on building development processes for Talisman employees, which I see as a critical next step.
Underpinning all of this, of course, is continued world-class execution. We have a large agenda, and it remains the highest priority to deliver what we say and to deliver it safely and well.
So there are the headlines. Before I go into each area, a word about the overall capital and its allocation. I've mentioned our [ENP] cash capital will be around $4 billion. Our reported capital will be higher than the cash capital because it will include a capitalized lease of about $400 million associated with the EMA field in Norway.
Most of our capital flexibility lies in North America as you know, because that's where we have options to dial up or down in a 12-month period. Given the gas price, we're obviously focusing our expenditure on activities other than dry gas, and we've therefore reduced our dry gas capital expenditure in North America by 35% from 2010 levels, and refocused much of that into liquids options within North America.
The exception to that reduced activity is in the Montney, where because of our new partnership, we'll pay 12.5% of the capital program and at the same time get ourselves down the learning curve. In North America, we'll increase our investment into liquids-rich opportunities to the maximum extent. There are obviously operational limits to this, but we have to balance operational requirements with capital allocation, and I think we have a program which gets the right focus.
Overall, in North America, we'll spend around $1.7 billion this year, with just under 40% being focused towards liquids-rich opportunities. In the Marcellus, we exited last year with 12 rigs producing 315 million cubic feet a day. This year, we've already taken steps to move to 9 rigs, and we're actively considering reducing this further, to 7 rigs, although that's a decision for later given that our wells are economic below $4 gas.
Assuming we maintain a 9-rig program, we expect production from the Marcellus to average 350 to 400 million cubic feet a day this year, so a substantially slower ramp than last year. We expect to drill a little over 100 net wells during the year, and our EUR assumption remains at about 5 BCF a well. Overall in the Marcellus, including infrastructure capital, we expect to spend about $800 million.
In the Montney, we'll continue the development of the Farrell Creek with our partner Sasol. They will contribute 87.5% of development capital, and we'll ramp up from 4 rigs as we enter the year to average 8 rigs over the full year in order to benefit from the learning curve and economies of scale.
We exited last year at about 50 million cubic feet a day, with an average production over the year of 20 million cubic feet a day. We expect net production to average 50 to 60 million cubic feet a day over 2011, because of course we now have a 50% interest.
Overall, we expect to spend about 100 million in Farrell Creek this year, drilling around 35 net wells. Our EUR assumption in the Montney remains at 7 BCF a well, and reflects the good results we've seen from our drilling up to now. During the first half of this year, we'll begin a feasibility study for a gas-to-liquids facility in western Canada, which will be led by our partner Sasol.
In the Eagle Ford, we're aligned with our partner Statoil in ramping up as quickly as possible. We're currently operating 4 rigs, and we'll build to 8 rigs by the end of the year. We'll spend around $300 million as we ramp up activity, and we'll be accelerating right through the year end.
We expect to drill approximately 35 net wells this year, with annualized production of between 55 and 65 million cubic feet a day net to Talisman, just under half of which will be liquids. For now, we're continuing to maintain our EUR assumption at about 4 BCF per well, or just under 0.7 million barrels equivalent.
We'll also complete the two outstanding wells in Quebec, with the timing dependent on the availability and cost of completion equipment. In our conventional portfolio in North America we'll also focus on liquids opportunities.
Overall, we expect to spend around $380 million, with nearly 70% of the capital focused on expanded oil development programs in our Chauvin and Shaunavon properties as well as the continuation of our pilot programs in the Cardium oil and wet gas windows. Our conventional portfolio in North America produces at around 90,000 barrels a day equivalent, and is pretty constant at that rate.
Turning to our Asian business, we expect to spend between $700 million and $800 million this year. Production will remain largely flat with last year at about 120,000 barrels a day, because of the timing of project delivery, although we still expect to maintain about 8% per annum growth over a five-year period.
New production will come from compression projects in the corridor field in Indonesia, and we'll bring on Jambi Merang, also in Indonesia, around mid-year. We're also hoping to see first oil from the Kitan development in Australia before year end.
In terms of engineering work, I'm expecting to sanction the HSD development this year in Vietnam, which you will recall we had hoped to sanction in 2010 but delayed to improve the project. The development looks good now, and I think we'll have a robust development plan which will come forward during this year.
We'll also, of course, be progressing our Papua New Guinea activity. We began drilling at the end of last year and will continue that program through this year. We'll spend somewhere between $200 million and $250 million on the program this year, which will be a mix of expiration, appraisal, and some early development wells on a condensate stripping scheme we hope to progress for early cash flow.
In the North Sea, we'll spend around $1.2 billion of cash capital, with about two-thirds in the U.K. and one-third in Norway. Production from the region will be between 130,000 and 135,000 barrels a day, with a little over 80,000 from the U.K. and we expect about 50,000 from Norway.
The main focus for the year in Norway will be commissioning EMA. We have assumed in our projections that we bring the field on in July, which means it has to sail from Stavanger by early April. As you know, we're just waiting for a clear weather window to move it offshore, but it comes on at a high rate, and so delays beyond July will start to impact our production outlook.
As usual, we have a large in-field drilling program in Norway this year, including wells on Gyda, Brage, Veslefrikk, and Varg, all of which represent very high return activity. And finally, we'll be progressing the appraisal of the Grosbeak discovery, which we acquired last year, and Grevling, where we'll progress a development plan through this year.
In the U.K., we're ramping up the Auk North project, which came on stream at the very end of last year. The early signs look very encouraging, and the three wells in the development were flowing at more than 25,000 barrels a day as we ended last year. We're also starting platform drilling on Claymore.
There are a number of major projects in the early stages of engineering in the U.K., including the redevelopment of the Montrose/Arbroath platform, which extends the life of the existing fields and also incorporates the development of the Cayley, Godwin, and Shaw discoveries. We're currently expecting this to come forward for sanction in 2012, and we're completing the engineering for the Auk South redevelopment and have started construction on the new accommodation module in the drilling rig. We're targeting first oil from this project, which is really a reengineering of the Auk platform, in 2012 as well.
And to complete the picture of activity this year, our exploration program is also fairly active. As you know, we spend around $700 million per year exploring, and this year is no different. There are several areas of focus for the year.
In Colombia, we'll appraise the Huron discovery in the foothills, and we'll also continue the exploration program around last year's successful drilling in Block 6 with Pacific Rubiales. This year, we'll confirm the hydrocarbons will flow. In Block 9, with Ecopetrol, we'll continue to appraise the discovery we made last year, and we'll consider how best to achieve early production.
In Indonesia, we'll begin drilling our Lempuk well in South Makassar, and we'll also [inaudible] a well into Block 39 in Kurdistan called Topkhana. And as I've mentioned already, we'll continue our program of drilling in PNG with the wells being a mix of pure exploration and some appraisal.
In Poland, we'll commence our program of three vertical wells, which will give us some early information about the potential of the shales there, and we'll have a fairly active program in the U.K. on the TR1 well and in Norway comprising both exploration and appraisal.
So, that's an overview of our focus and activity for this year. I'm now going to ask Scott to run through how we're seeing our hedging program and the balance sheet for you. So over to Scott.
L. Scott Thomson
Thanks John. Talisman continues to be in a strong financial position. We will end the year with total debt of approximately $4.2 billion, post our $600 million fourth quarter debt issuance, but that includes a $350 million Canadian bond, which is maturing this month.
At the last quarterly call, I had indicated cash on hand at the end of 2010 would be in the range of approximately $500 million. A slight delay in the closing of the BP Colombia transaction from Q4 to January, stronger than forecasted commodity prices, lower than projected capital expenditures, and the fourth quarter debt issuance, will actually result in a 2010 year-end cash position of approximately $1.5 billion and a year-end net debt position of approximately $2.7 billion.
The closing of the BP Colombia transaction in mid-January will result in an additional payment of approximately $250 million over and above the deposit we've already paid to BP. This outflow, combined with cash outflows in Q1 related to tax payments in the U.K. and Norway and the maturity of our Canadian debt issue, will reduce our cash balance as we move through Q1. For the rest of the year, we will likely see an additional draw on the cash balances of the company, as capital expenditures will modestly exceed cash flow at consensus price forecasts.
It is important to recognize that Talisman's cash generation profile will change significantly over the next few years. Since the beginning of the strategic transition, we have been using proceeds from the sale of conventional gas assets to finance the development of our North American shale business, which increases the profitability of Talisman as a whole.
As you know, any shale play moves into a cash generating position after the first few years, and our investment track record in the Marcellus, combined with our partnering in the Montney, will move Talisman toward a free cash flow positive position.
Of course, the exact timing of this tipping point depends on commodity prices, but it is fair to say that the cash generation capabilities of Talisman have changed and will increase significantly as we move through 2011 and into 2012.
Talisman will continue to maintain a strong liquidity position. In the fourth quarter we raised $600 million at an attractive rate of 3.75%, in anticipation of refinancing our January maturity, and we also renewed and upsized our revolving facility to $4 billion. This revolver is priced at LIBOR plus 2%, is unutilized, and doesn't mature until 2014. Excluding the January maturity, we have no debt maturing in 2012 or 2013, $50 million in 2014, and in fact 80% of our debt matures post-2016.
Our disposition program allowed us to maintain a strong balance sheet while at the same time executing on our 2010 capital plan and acquiring approximately $2 billion in assets. Since we embarked on the strategic transition, we have sold approximately $5 billion of assets at metrics in excess of $60,000 per flowing barrel. In 2010 we sold approximately $2.2 billion of assets, primarily consisting of North American conventional gas properties.
We also announced a joint venture of our Ferrell Creek Montney assets for a value in excess of $1 billion. These dispositions enabled us to accelerate our strategic transition with the acquisition of common resources and enduring resources in the Eagle Ford, BP Colombia, Jambi Merang in Southeast Asia, and two exploration opportunities in Norway. As John mentioned, we don't have any major dispositions planned as we enter 2011, but we may continue to high-grade to some extent.
It is worth spending a few moments on current tax projections for 2011. As previously mentioned, we expect 2010 current tax to exceed our $850 million target given at the beginning of the year, primarily because of higher commodity prices and lower than projected capital expenditures, particularly impacted by a $150 million to $200 million reduction in spending in the North Sea. The difference between 2010 and 2011 current taxes will be primarily dependent on the 2011 realized oil price, as we expect our regional capital spend profile to be similar in 2011 to 2010.
In order to protect cash flow going forward, we layered in hedges throughout 2010 for the 2011 calendar year. We feel that $4 billion is the ideal capital expenditure budget for the firm, and in order to ensure execution of this program it was prudent to lock in some price protection.
We focused on oil, as opposed to gas, for two reasons. First, at current prices Talisman's cash flow is primarily linked to the price of oil, and second, hedging opportunities at reasonable prices were more attractive in oil relative to gas given the futures curve of each commodity.
On the oil side, we have 70,000 barrels per day hedged in the first half of 2011, and 50,000 barrels per day hedged in the back half of 2011 in collars of approximately $80 by $93 dollars. And on the gas side, we have approximately 200 million cubic feet per day of physical and financial hedges in place for the first half of 2011 and 100 million cubic feet per day for the second half of 2011, primarily in tight collars with a floor of approximately $6 9x. This represents approximately 15% of North American production and slightly more on an economic exposure basis.
For 2012, we currently do not have any material hedges in place. Given the volatility in the commodity markets and the lack of attractive prices for the gas futures curve, we've been hesitant to hedge too far into the future, but we will revisit this on an ongoing basis.
Lastly, it is worth reiterating John's initial statement regarding our conversion to U.S. dollar reporting. As we transition to IFRS, we also thought it was an opportune time to convert our reporting currency to U.S. dollars. U.S. dollars is a more reflective currency for Talisman given our exposure to oil, which is denominated in U.S. dollars, and given our geographical diversity.
We will begin U.S. dollar reporting for the 2011 fiscal year. Our 2010 results will be released on February 16 and will continue to be in Canadian GAAP and in Canadian dollars. Our Q1 results will released in May, and will be in IFRS and in U.S. dollars.
Back to you John.
Thanks Scott. Just before your questions ladies and gentlemen, let me recap the key points for you. We'll use the flexibility we have in our North American portfolio to concentrate on liquids-rich activity and reduce our gas shale cap ex by 35% from 2010. We'll spend around $4 billion of cash capital, which is about the same as 2010, and we'll likely be just a little bit above our cash flows, although that depends on the oil price. Our balance sheet is strong and easily capable of handling a small draw in 2011.
We'll growth the business between 5% and 10% off a 2010 base of around 415,000 barrels a day, and I've given you the regional components of that production for this year. There are a couple of things worth noting about that. First, the base of 415 is higher than when I first talked of a growth rate of 5% to 10%. Second, that growth rate excludes Colombia, which will be additive and add another 12,000-15,000 barrels a day to the organic growth. And third, we believe that growth rate to be sustainable because of the shape of the portfolio which underlies it.
Our profitability will continue to improve, driven by another year of substantially improved F&D costs in 2010, which we see continuing into 2011 although not at the same rate. And finally, we have some very exciting exploration wells to drill this year in Colombia, deep water Makassar, Kurdistan, and the North Sea.
So that's the program for 2011, ladies and gentlemen. Now we'd be very happy to answer your questions.
[Operator Instructions.] Your first question comes from the line of Andrew Fairbanks from Merrill Lynch. Your line is now open.
Andrew Fairbanks - Merrill Lynch
John, I was curious how you might see Colombia evolving in terms of volumes and scale post-BP. And if you do have incremental success in developing some of the prospects you have, is there any concern around having sufficient pipeline capacity as you execute those plans?
Let me turn to Richard, who is running our Colombia business and the exploration. Richard?
Clearly it's still early days for us in Colombia. The BP Colombia deal actually closes next Tuesday and as John said, our predicted production for this year will be between 12,000 and 15,000 barrels a day from that. Clearly during 2010 we've had a number of interesting wells drilled. We've had a discovery in Block 9 with Ecopetrol in the Acacias well, which we'll be appraising this year, and we've also had some encouragement from the stratigraphic drilling in Block 6 and we continue to be very encouraged by the potential of the Huron complex in the foothills, which we'll be appraising during 2011.
It's still early days to actually roll all this up into definitive forecasts of production, but we do expect to see the business growing there strongly and we will be developing our plans as the appraisal wells get drilled this year. I think in terms of capacity, a key component of the BP Colombia acquisition for us was to acquire an interest in the Ocensa pipeline, and we currently believe that our interest in that will be sufficient to deal with the production that we're forecasting.
So just to round that off, we are increasingly of the view that the potential of that area meets our criteria, which is 50,000 barrels a day in the medium term. So we're actually pretty excited. Richard's described some early exciting opportunities, I would say, and none of those opportunities, as he said, are constrained at the moment by egress out of the main basin.
Your next question comes from the line of Juan Pineros of InterBolsa. Your line is now open.
Juan Pineros - InterBolsa
I just have two questions following up on the exploration in Colombia. Can you provide more information on the results you had in the stratigraphic wells in Block 6 and do you have any looking for plans? Second question would be given your increased exposure to Colombia have you considered listing the stock in the Colombian stock exchange?
Let me answer the second one and then turn to Richard to answer the first one. The answer at the moment is we haven't at the moment considered listing on the Colombian stock exchange. We're a little early in our phase, I think, for that for the moment. But as I say, we continue to be encouraged. Richard, anything further you'd like to say on Block 6?
Yes, in Block 6 we partner with Pacific Rubiales and I think that company, the operator, has said quite a lot about the results that we've had to date and like the operator we're very encouraged by the results. We're now in the process of drilling the fifth stratigraphic well in the block. The first two wells both encountered oil lakes of around 30 feet and we then drilled two further wells which have demonstrated an extension of the play. They didn't encounter as much reservoir as we'd found in the first two wells, but they were drilled right on the edge of the play system. And we're now drilling the fifth well and that will be followed by the final sixth well which will be drilled in February. So I think at this stage clearly stratigraphic well drilling doesn't give us any flowing data. It gives us indication of the presence of oil and reservoirs. We're very encouraged by the scale of this accumulation, but we won't really know any more until we've drilled some proper appraisal wells, which we plan to do later this year, and actually have a chance to do some testing and get some flow data as well. So it's still early days but we're encouraged.
[Operator Instructions.] Your next question comes from the line of Greg Lynch, a private investor. Your line is now open.
I have a question regarding the Utica shale. I understand that you'll be completing two wells this year when - with regards to cost and all that. I'm just wondering what your commitment was to that area going on.
Let me ask Paul Smith, who runs that business, to talk a bit about how we think about the Utica shale in Quebec.
As you know, we've always portrayed the de-risking of the Utica as something that will take place in a measured fashion. We've said the first step of that is the completion of five horizontal wells, testing five different structures within the fairway. Three of those wells were drilled and completed last year. The other two were drilled and we will hopefully be completing those two final wells this year as market conditions for completion equipment allow it to make sense for us to complete those wells this year as we expect to do. And at that point we'll have completed the five wells that we've committed to and we will see what the data tells us in terms of our path forward at that point.
We see nothing that is at odds with our original expectations, Paul, so far? Would that be fair to say?
I think it's early days, three wells and a fairway of 750,000 acres, and we sort of need to let the rocks speak to us and we need another two wells to decide how we move this play forward. But nothing unusual to date.
Your next question comes from the line of Katherine Minyard of JP Morgan. Your line is now open.
Katherine Minyard - JP Morgan
Just a quick question on the Marcellus. Actually, as you think about your longer-term position in the Marcellus, have your objectives in terms of the target production levels changed, or is the curtailment in rigs in 2011 just more of a short-term impact as you eventually progress towards the same objective?
Let me ask Paul to answer that as well for you.
No, I'd say our position long-term hasn't changed. We still have 220,000 acres, which we believe are sitting in what is emerging, clearly, as the sweet spot of the Marcellus play. What we've chosen to do this year in response to the external environment is to turn down and use the flexibility that we've always said we've had within our portfolio in the Marcellus, and we've turned the play down about $200 million this year. As John has already said, we will take the activity levels down from the 12 rigs which we operated last year, down to nine, and we'll make a decision on whether to move that further down to seven this year. But the potential of the rocks has not changed. We continue to see better and better results with every well that we drill and it will turn out to be a play in the long-term that will be producing for us at over a BCF a day. When that will be will be a function of the external environment and the pace at which we choose to put capital into this play.
Your next question comes from the line of John Malone of Ticonderoga Securities. Your line is now open.
John Malone - Ticonderoga Securities
Your release refers to your spending about $200 million to $250 million in Papua New Guinea. I think it was six wells you referred to. Can you expand a bit on your plans there and how you expect to monetize any gas you might prove up?
Let me first turn to Richard to describe the program and where we are in the program and then to Paul Blakely to describe where we are in our considerations of commercializing that gas.
As I'm sure you're aware, over the last 18 months or so we've acquired a large acreage position in the Fallen Basin in PNG. This is a very underexplored area. It's a very prospective area for gas, and as part of the acquisitions we've made we've taken an interest in a number of discoveries which total more than one TCF of gas and we have a lot of exploration prospectivity as well.
So our current plans are to first of all illuminate this prospectivity by shooting seismic. We've been very active during 2010 continuing into 2011 with a seismic program and we've now just started up in December of last year our drilling program, which will comprise two rigs.
We're currently drilling the first two wells. One of them is an appraisal well on the Stanley discovery, and the other one is a nearby exploration well. So our plans for this year are to drill six wells and to start to aggregate together sufficient gas to look at potential export solutions. And those wells will be a mixture of exploration drilling and appraisal of the discoveries that are there.
I'll turn back to John or to my colleague Paul to talk about the monetization options.
Paul, how are we doing in various options to monetize?
So following the expiration story, we'll look at a number of monetization options of aggregated gas. And in the short-term we're also planning, and perhaps by the end of this year, to sanction an condensate recovery scheme which will start some monetization of the assets in Papua New Guinea and also to allow us to more fully understand reservoir performance and so on. But you know, still early days really, and we'll see how things progress during the year.
John, does that get at your question?
John Malone - Ticonderoga Securities
It does. I guess it leaves one more quick question, which is your JV with Sasol. Are there other parts of the world you would look to kind of apply the same technology if you were working closely with Sasol? Or is it too early days to start expanding on that?
I think you've answered your own question really. It's a little early. We are [inaudible] and I'm very excited about our relationship and our partnership with Sasol. We think they're a great company. We get on extremely well and therefore I think we can look forward with some optimism to opportunities in the future, but for now we're concentrating on the one that we've just signed, which I think is quite strategic and quite interesting for us. So I think very optimistic, but very early too.
Your next question comes from the line of Brad Marcotte of UBS. Your line is now open.
George Toriola - UBS
This is actually George Toriola from UBS. A question on Eagle Ford. So you're going to be spending some more money on your Eagle Ford assets and hoping to grow that production volume from there. The question is do you see that program as continuing to de-risk the asset or are you in the development phase for that asset?
Let me ask Paul to answer that question. Are we still de-risking, Paul? Or are we in sort of full development?
I'd say that we're in the early stages of full development would be the fairest way to characterize it. The acquisitions that we did, purposely acquired assets where a lot of the de-risking on the acreage had already occurred. Clearly the total acreage position which within the JV is now about 140,000 acres, hasn't all been de-risked, but there is activity going on around us, which gives us great confidence that we have our hands around the productivity that we will expect to see within the various windows of the Eagle Ford play, which is clearly more complex than a simple dry gas play. So to answer your question, yes, it is in full development mode and as a result of that we'll be ramping up this year from four to eight rigs as we build the organizational capability and supply chains to underpin that ramp up. And most of those pieces are falling into place as we speak and we're confident that we will ramp up as John has described and deliver 55-65 million standard cubic feet a day this year from a standing start, 10 million scfs last year in the Eagle Ford, half of which will be liquids.
George Toriola - UBS
And just to clarify, on a [DOE] basis, the production volumes that you expect out of the Eagle Ford are sort of 50% liquids? Is that right?
55-65, of which 50% is liquids. Correct.
- million standards of cubic feet of equivalent a day.
Your next question comes from the line of Alex Shields from Le Devoir newspaper. Your line is now open.
Alex Shields - Le Devoir
First of all, do you think that your project in the Utica shale gas in Quebec could be more important in 2011 and 2012 despite the price of the gas and the big debate that's going on in Quebec about the shale gas exploration?
Let me ask Paul to, I think, reiterate his prior statement about this.
There is a natural pace at which we've said that we will de-risk the Utica. And I've just described that pace to a previous question. That pace is not going to change this year, so the activity set this year will comprise of looking to complete the last two wells and at the same time working with the government, industry working with government, to put in place a regulatory and fiscal regime that may open up the Utica for development as and when the rocks are ready for development. But I think we need to take one step at a time and step one is completing all five wells and we will do the last two of those this year.
Alex, I think as you mentioned, there is, despite the noise, we need to pace this properly. We need to be sure that the fiscal and regulatory regimes are appropriate to ensure that industry behaves in a responsible way, and we're certainly very keen to see that outcome and to make sure that we do. So as Paul has described, we're not going to either pushed or pulled, frankly, in terms of the natural pace of de-risking. And we are early. This is not yet demonstrably commercial. So we have to take our time, and we have to make sure we understand it. But we are, as in all things that we do, determined to progress that to the end and do it properly and do it well.
Alex Shields - Le Devoir
And are you confident that this time with the potential of the shale gas in Quebec, despite that there's only five wells from Talisman? Three wells, excuse me.
We have not yet de-risked the play in Quebec, so the activity that is going on today is about establishing whether or not there is a commercial resource to be excited about in the first place. So I think the answer to the question, frankly, is no. We don't know yet what the potential of the Utica shale is, and that is the purpose of the activity which we're going to go about in a deliberate and careful way over the course of 2011. And then we'll complete these wells and then we'll take stock, we'll have a look, and we'll take the next steps. But I think in truth we don't know yet.
Your next question comes from the line of Jeff Lewis of Alberta Oil Magazine. Your line is now open.
Jeff Lewis - Alberta Oil Magazine
Just had a quick question regarding the joint venture with Sasol in northeastern BC. I'm curious to know just about the production profiles of the Ferrell Creek play. As production ramps up quite quickly on these horizontal wells, are you at all concerned about providing a steady feed stock for any would-be gas or liquids plant that does materialize, notwithstanding that it is early days and you've yet to do the feasibility study?
Let me ask Paul to handle that. The answer, I think, is no. But Paul?
The answer is no, but we're going to be ramping up this year as John has said, from four to eight rigs. That means that production we expect this year to be circa 50-60 million standard cubic feet a day from the area. Of course that's 50%. At the same time, and in parallel, as we're ramping up and coming down the learning curve and the break-even curve, which are crucial and we expect the Montney, as we've always said, to be very similar in its break-even characteristics to the Marcellus. And that's one of the things we'll be proving, or we intend to prove, in the next 12 months with continuing well results which underpin a break-even towards $4.00 in MCF, which is the aspiration that we have line of sight to. At the same time, we'll be starting, as John has said, a feasibility study, which we think will take approximately two years, to investigate the possibility and the conditions under which a gas-to-liquids facility in western Canada makes sense. And clearly if that is a decision which is thankfully a few years away, but if those conditions are the right conditions, then we'll clearly be tailoring the ramp up to the construction of a gas-to-liquids plant. But it's an option. It's very early days, and it's going to take two years just to get a feasibility study done on the project.
I think it's also fair to say that our partners and us are completely aligned with the development plan that we stepped into this in the intervening period. We can sell the gas pro tem while we're studying the option of the gas-to-liquids plant. So it's sort of completely aligned. We've had these full discussions and so there's complete alignment in how we're going to progress this activity.
Your next question comes from the line of Pat Roche from the Daily Oil Bulletin. Your line is now open
Pat Roche - Daily Oil Bulletin
Of the $1.7 billion you plan to spend in North America this year, how much of that will be in western Canada? And can you tell me how much that will increase or decrease from 2010?
Let me see. I'm just looking at Paul to see if he's got the numbers in front of him. Are you ready to answer that Paul?
Yeah, sort of.
Okay, so let's see if we can just do some quick back of the envelope.
The majority of our conventional expenditure this year will be in western Canada, so about $350 million going into mainly liquids or oil plays within our conventional portfolio in both Alberta and Saskatchewan. So that's point one. And then secondly, clearly the circa $100 million that we're putting into the Montney is also going into western Canada, so roughly, roughly $450 million to $500 million going into western Canada this year.
And the activity in Cardium perhaps?
That's included in those numbers. Plus a little bit of piloting. Roughly, roughly? A billion - half a billion of cap ex in western Canada, which is not significantly different from last year with the exception there's a big switch from gas into oil in western Canada within those numbers.
Your next question comes from the line of Jayman Patel from SG America Securities. Your line is now open.
Jayman Patel - SG America Securities
Just to confirm, you mentioned that your cash number at the end of the year was $1.5 billion and net debt was $2.7? Is that right?
L. Scott Thomson
I guess I'd caution you to a little extent. Our final numbers haven't come in yet, so I'm giving you an approximate approximate. But those were the right numbers. Approximately $1.5 billion in cash, whereas we told you $500 million before, because of the issues I identified. And that results in $2.7 billion in net debt.
Jayman Patel - SG America Securities
Okay, so that would be an increase in total debt of about $500 million and a decline in cash of about $500 million from the Q3 numbers. Is that right? I want to make sure we're looking at the same total debt numbers here.
L. Scott Thomson
Well, the way to think about it is 1) we did increase debt because we raised $600 million in the capital markets in Q4, but keep in mind that we've got our $350 million maturity in January, so that's point one. And then point two, on the cash position, the $1.5 billion is lower than what we saw at the third quarter because of acquisitions we'd done, cap ex we'd spent, etc. etc.
Your next question comes from the line of Mike Dunn from First Energy Capital. Your line is now open.
Mike Dunn – FirstEnergy Capital
Just thought I'd ask you a couple of questions on cash taxes and op costs. I guess maybe start with op costs. Are you foreseeing any material changes to your operating cost structure in any of your regions in 2011?
Let me see if I can get your question. You're either referring to inflationary pressure or you're referring to sort of structural changes. I think it's, and I would start the comment, by talking about the continuous process of cost reduction, which is an incremental process. It's all about what we call lean manufacturing processes within North America, which continuously work to drive down the operating costs, and that's one of the reasons why the break-evens in that business keep coming down. So that is a structural condition.
In a general sense, inflationary pressure is not quite as much as you would imagine, given the state of the economy and all the noise, partly because we're majority contracted and quite a lot of that is fixed-price. So there is, of course, pressure, that you know well about in North America in boat service crews, in rigs, in such things, both of which we anticipate will start to mitigate in the second half of 2011 as activity we think, we hope, reduces and reduces some of that pressure. And then elsewhere in the world, actually, we're controlling much of it.
So, you know, we plan on a sort of 2% number going forward, just as a planning base, and in fact it turns out that when you do the numbers it's about where we sit, probably, given all of the things that I've talked about.
Mike Dunn – FirstEnergy Capital
Great, and next question on cash taxes. I know you haven't nailed down to a specific number for cash taxes, but your cash flow guidance of, I guess, just slightly below cash cap ex. Just remind me, maybe for consensus prices, is that sort of $86 WTI that you're talking about there for 2011?
I think we're slightly below that. We must be looking at a different consensus to you, Mike. We're a bit below that between $83-$84, something like that, in our consensus. But let me ask Scott to see what illumination he can do for cash taxes.
L. Scott Thomson
Yeah, Mike. Couple things. One is we were vague on purpose on the consensus analyst deck because those as you know are changing significantly as we speak, by all the analysts. But broadly, broadly, we're within $500 million up or down of cap ex. That's point one. Point two - on cash taxes, our current tax profile is actually determined a lot by our capital spend, and the capital spend in 2011 broadly, broadly, is going to be very similar to 2010. So what you're going to see from a cash tax perspective is any difference 2011 to 2010 is going to be determined by what the actual realized oil price is.
Mike Dunn – FirstEnergy Capital
Sure guys. I think my model is similarly in line with what you're saying with a little bit higher oil price and a little bit higher cash flow, but just wanted to - thanks for clarifying that. And just on the Marcellus, maybe if you can just sort of frame for me if you do end up going down to seven rigs in 2011, how might that impact your guidance range for the Marcellus production and cap ex and I guess likewise corporately as well?
Well, it's a bit difficult to say Mike, because it depends when we do it, you know? I suppose in a year, $100-150 million, something like that, of capital, but what it does to production who the hell knows? Because it depends on when we choose to ramp it down, frankly. Difficult to answer that one.
Your next question comes from the line of Marcus Ermisch from the Calgary Sun. Your line is now open.
Marcus Ermisch - Calgary Sun
Just a brief follow up question for Paul Smith. Paul, did I understand you correctly that the feasibility study into the gas-to-liquids plant will take two years?
That's right. Approximately two years.
Marcus Ermisch - Calgary Sun
Can you explain to me why that is taking that long? I mean, to me as a layperson that seems like a very long time to study the issue.
Remember you're dealing here with the equivalent of a gas refinery. This is a multi-billion-dollar facility with a lot of complexities to it, that historically two years has shown that in other places, like [Qatar] which has the only two commercial gas plants in the world today, that two years is a reasonable timeline for a feasibility study which will be fully staffed by Sasol here in western Canada with a team of about 30-40 people.
There are no further questions. I turn the call back over to you, Mr. Manzoni.
Thank you very much, and ladies and gentlemen thank you for listening to our 2011 guidance call. We shall look forward to updating you with our fourth quarter results in mid-February. And thank you for your participation this morning. Thanks, and with that we'll sign off.
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