Welcome to the Talisman Energy, Inc. third quarter results conference call. At this time all participants are in a listen only mode. Following the presentation we will conduct a question and answer session. Instructions will be provided at that time for the queue up for questions. (Operator Instructions) This call contains forward-looking statements. Certain material factors and assumptions were applied in making the forecast and projections to be discussed on 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 November 3, 2009 news release and Talisman’s most recent annual information form which contains additional information about the applicable risks factors and assumptions. I’d like to remind everyone that this conference call is being recorded on Tuesday, November 3 at 11 am Mountain time. I’ll now turn the conference over to Mr. John Manzoni.
Welcome and thank you for joining our third quarter conference call. With me today in Calgary is Scott Thomson, Paul Smith, Nick Walker, Bob Rooney and Phil Dolan and joining today by telephone are Paul Blakeley and Richard Herbert. After Scott and I have made some comments about the results and the outlook we’ll be very happy to answer your questions.
Let me begin my giving an overview of the results and pick up some points I think might be helpful for you. The results of this quarter reflect a lower pricing environment from a year ago and a relatively lower production level which represents a low point during the year but doesn’t materially change our outlook for the full year.
Our realized prices during the quarter were up from the prior quarter by just under $2.50 a barrel equivalent at $50.29 a barrel. But, our net backs were down about $0.25 to $27.16 a barrel. The reason the net backs were down was higher royalties arising from higher production in Asia where the royalties are a little bit higher and a very slight increase in unit operating costs which is due to the lower production rates rather than the absolute level of costs.
Cash from operations during the quarter was $838 million compared to $900 million last quarter which reflects the reduction in net backs and the lower production levels in this quarter. Reported net income for the quarter was $30 million and earnings from continuing operations which strips out certain non-operating items was $155 million for the quarter up from $125 million last quarter.
Free cash flow for the quarter was -$183 million reflecting our normal capital expenditure program and the small acquisitions we made in Papua New Guinea which amounted to about $220 million. This compares to the nearly $1.4 billion in flow last quarter which reflected of course our disposition program during Q2. Although capital spending year-to-date has been broadly in line with our guidance, as Scott will explain in a moment we will spend more than $3.6 billion capital this year by the time the year is complete.
We continue to retain cash on the balance sheet although this is now reducing slightly from last quarter and currently sits at about $2 billion. Scott will give you some indication on how we see that moving for the rest of the year.
Turning to our operations, I’m pleased by our continuing performance in safety. Year-to-date we have a loss time injury frequency 48% below last year despite substantial changes in our business which can sometimes distract people from this very important priority. Production for the quarter was 401,000 barrels a day. This is down from the second quarter mainly in the UK which produces 74,000 barrels a day in 3Q. The UK production was impacted by plant shut down activity which effectively took about 14,000 barrels a day out of service during the quarter.
There were also some operational issues which are now fixed but which impacted our UK production by about 6,000 barrels a day for the quarter. The other operational issue of note during 3Q was here in Canada where our Sukunka gas plant was down for a while which reduced production by about 3,000 barrels a day equivalent for the quarter. That’s now fixed and back up in operation.
Looking forward for the year, I’ve said on previous calls that I expected to be at about 430,000 barrels a day for the year with down side limited to 5%. The reason I’ve maintained the down side is because we’ve been selling assets through the year and the final outcome of that was uncertain. We now have a clearer picture of how much disposal activity we’re likely to complete this year and we expect to complete about 8,000 barrels a day annualized over and above the Netherlands and Trinidad disposals which were in our plans from the start.
Through the year we’ve sold several western Canadian properties including the Bakken. We’re still completing deals this year but I think we can now estimate the final impact. So now accounting for the sales that we have made and plan to make, I believe our overall production for the year will be between 423,000 and 426,000 barrels a day.
Turning to costs, it’s always complex to analysis quarter-on-quarter changes because of course the activity levels change and in particular with all the shut down activity this last quarter. You’ll see from the numbers our operating costs are more or less flat both with last quarter and the year ago despite the increased activity levels. Unit costs have increased marginally this quarter more to do with the production levels than the absolute cost levels.
Looking through different lenders we’ve set targets for reductions in various categories of operating and capital costs of around 10% and I believe we’re seeing 50% to 60% of that achieved so far. We’re taking a range of actions to achieve those reductions including negotiations with our largest suppliers, reductions in contractor rates, general overhead reductions and process improvements in our operating areas.
A general comment on the cost base is that in certain areas we’re starting to see a leveling off in rate reductions. This is becoming clear in chemicals prices as an example where it looks like they’ve reached a bottom with reductions ranging, depending on the product, between 2% and 15%. Our operating areas are focused hard on costs and I’ll mention later the progress we’re making in reducing well costs in our unconventional activity.
Let me now ask Scott to give you a bit more on the quarter results and then I’d like to spend a few minutes on our strategic progress and outlook before answering your questions.
L. Scott Thomson
I will make some comments about our financial results, balance sheet, progress and focus on the portfolio and hedging position. Cash flow in the quarter was approximately $838 million compared to $900 million in the immediately preceding quarter due principally to lower volumes, a reduction in net backs and slightly lower proceeds from our hedges.
Year-to-date we’ve generated $3 billion of cash flow compared to $4.6 billion in 2008. This decrease in cash flow is primarily attributable to the lower commodity prices partially offset by significant cash inflows from our hedging program. Earnings from continuing operations which excludes certain non-operational items were $155 million in the quarter compared to $125 million in Q2 due principally to lower depreciation expense and foreign exchange gains from our significant Canadian cash balances.
Year-to-date earnings from continuing operations have decreased from $1.85 billion in 2008 to $564 million in 2009 reflecting the 43% year-on-year declines in realized commodity prices partially offset by realized gains from our hedging program. Cash taxes of approximately $175 million in Q3 were approximately equivalent to cash taxes in Q2 since the lower production volumes in Q3 were offset by lower exploration tax deductions. In Q4 we expect cash taxes to double relative to Q3 because of expected production volume increases.
Cash, exploration and development spending year-to-date was $2.7 billion of which approximately $950 million was spent in North America, $850 million on development activity in the North Sea, $260 million on development activity in Southeast Asia and $600 million on international exploration. Almost all of our North America spend in the quarter was on unconventional activity.
We now expect cash capital expenditures to increase to approximately $4.5 billion for the year. The increase relative to our prior guidance of $3.6 billion in primarily the result of accelerated drilling in the Marcellus, land acquisitions in the Montney Shale and the Marcellus and successful sidetracks and testing of several exploration wells.
At the end of Q3 we had $2 billion of cash on the balance sheet and $1.9 billion on net debt. Excluding any additional acquisitions we may choose to fund, we expect to end the year with a positive cash balance but clearly not at the level seen at the end of Q3. Our land acquisitions in the Montney Shale and the Marcellus and our accelerated unconventional activity will be funded by cash and this is possible because of the balance sheet flexibility we generated through our asset sales in the first nine months of the year.
On the M&A front we continue to be active. During the quarter we closed two strategic acquisitions of exploration interest in Papua New Guinea for a combined cost of approximately $220 million. The acquisition of Rift Oil in August and the subsidiary of Horizon Oil in September, are a key step in aggregating natural resource potential and provide an expanded exploration position in Papua New Guinea.
On the disposition front, we continue to focus our portfolio. In the third quarter Talisman entered in to agreements to sell conventional assets in Western Canada for proceeds of approximately $300 million. These sales are expected to close in Q4. In addition, we expect to close the sale of 10% of the EMA asset in Norway and the sale of our Tunisia assets in Q4.
Since we introduced our strategy in May 2008 and including announced transactions expected to close later in 2009 we have sold assets for proceeds of approximately $2.8 billion while divesting only 31,000 barrels per day of production. Proceeds received allow us to accelerate the implementation of our strategy in a fashion that maintains balance sheet strength. We will continue to evaluate opportunities to focus the portfolio particularly in North America and we’ll proceed with additional dispositions if the value received and the strategic rational makes sense for Talisman.
Our commodity derivative contracts in 2009 and 2010 protect our cash flow. We have protected 76,000 barrels per day or 35% of our remaining estimated 2009 oil production with collars at a floor of approximately US $74 per barrel and a ceiling of approximate US $101 per barrel. This consists of three programs namely 40,000 barrels per day in $95 by $135 collars, 11,000 barrels per day in $60 by $86 collars and 25,000 barrels per day in $43 by $50 collars. In 2010 we have 75,000 barrels per day hedged in three different programs. 22,000 barrels per day in $50 by $60 collars, 28,000 barrels per day in $52 by $80 collars and 25,000 barrels per day in $71 by $90 collars.
For North American gas we’ve protected approximately 350 million standard cubic feet per day or approximately 45% of our remaining estimated 2009 North American production at a price floor of approximately $6 AECO. In 2010 we have protected approximately 290 million standard cubic feet per day at prices of approximately $6 AECO as well. The 2010 program is weighted a little more to the first half relative to the second half of the year.
Those are my highlights, I’ll turn the call back over to you John.
I want to update you on our progress in strategic implementation before taking questions. We’re gaining momentum in our implementation along a number of dimensions. First, in our shale gas activity, so far this year we’ve drilled 31 wells in the Marcellus and 30 wells in the Montney between the core and the shale areas. As we’ve said before, we’re satisfied that our Pennsylvania Marcellus acreage is ready for development and we’re stepping up our pace.
We’re drilling wells now for $4.3 million US with breakeven economics below $4 a 1,000 cubic feet. Our EURs are increasing as we drill and we’re currently holding 3.5 bcf per well in our internal plans although many of our recent wells look closer to 5 or 6 bcf per well. We’ve defined Tier I acreage has having full cycle breakeven economics at about $4 per mcf.
We started the year with 90,000 Tier I acres in the Marcellus and we’ve now doubled that Tier I acreage at an average price of $3,250 US per acre. So, we now hold 180,000 Tier I acres which gives us about 1,800 net well locations in the area. We’ve been accelerating investment over the last quarter. Right now we have three rigs running and we’ll be ramping up to six rigs by year end. Plans for next year are still being finalized but we’re ready to go up to 10 rigs depending on our final capital decisions.
In the Montney we’ve been piloting several areas of the Montney shale in BC and as you know we’ve also been drilling what we call the Montney core in Alberta. We’re ready to move some of the pilot areas in the shale towards development in to next year. Within the Montney shale area in BC we’ve added about 80,000 Tier I acres to our land base which brings the total Tier I land within the Montney shale to about 166,000 acres which we think is about 3,000 net locations. We believe the economics of this acreage will be very similar to our Tier I Marcellus.
So you can see we’re accelerating our shale gas development activity as we gain confidence in the highest quality land positions. Our Montney position was considerably enhanced in the recent land sale and we’re delighted with the results and this is being reflected in our increased guidance for capital spending through the remainder of the year. We’re now confident we have sufficient running room for Talisman in the highest quality acreage for an extended drilling campaign to drive sustainable growth over multiple years.
Exactly how we play in to that growth will depend on the price outlook, our balance sheet management and a range of factors and is still under discussion internally. But, the important point is we have the resource in what we believe to be two of the best unconventional shale gas plays in North America.
Turning to Asia, the other piece of strategic implementation during the quarter was a series of acquisition in PNG which Scott outlined. The intent here is to aggregate onshore gas in PNG and although we’re not quite complete we believe we can see access somewhere between 3 and 5 tcf of gas. It will take some follow on exploration which we think is relatively low risk but a substantial amount of that gas is already discovered. That amount of gas is easily sufficient for a standalone small modular LNG scheme and we’re in discussions with various parties about how best to monetize that resources.
This represents a clear step forward for our Asia strategy and builds out a new area for us in a region which is hungry for gas. I’m excited about how this develops over the next year or two. We’ve also seen some success as we continue to build out our exploration portfolio. Richard will be happy to answer questions on this later but during the quarter we’ve successfully appraised the shortest discovery in the UK to firm up our estimate of about 100 million barrels in place and we’ve been granted additional acreage in both Malaysia and Indonesia. We’ve also been successful in our appraisal of the Situche discovery in Peru.
As we go forward in to 2010 we’ll be further accelerating certain aspects of our North American portfolio transition. Of course, the final shape of that transition will depend on many factors, not lease the market conditions in 2010 as we contemplate further disposition in our conventional business. But, we’re confident as we high grade our conventional portfolio and accelerate the transition in to shales, our returns will increase. We will be prepared if the market conditions are right in to next year to sell substantial existing production to cycle the capital in to the shale gas land base we’ve now secured.
Final decisions on this will come later but I want to signal now that our production levels next year will be determined as much by the pace of those disposition as anything else. The quality of our portfolio is increasing all the time and one example of this will be reduced finding and development costs. I said that I’m expecting a 30% to 50% reduction versus 2008 this year and I remain confident that this can be achieved. I remain equally confident that we will be able to continue to reduce F&D in to the future.
Ladies and gentlemen I’ve talked for a little longer than usual this time because I wanted to update you on those strategic actions but now we’d be delighted to answer your questions.
(Operator Instructions) Your first question comes from Andrew Fairbanks – Bank of America Merrill Lynch.
Andrew Fairbanks – Bank of America Merrill Lynch
I wanted to ask you about the capital spending on the shale gas program. Obviously, you don’t have a number for next year but as you think about how aggressive you could be, are there levels or parameters you would be concerned going above? Could you see something as aggressive as say a $2 billion program, is there some percentage of capital that you’d be nervous about spending in North America as a percentage of total capital worldwide?
Let me ask Paul to give you a perspective on how we’re thinking on our capital expenditures this year in that part of our business.
I think from the press release you’ll have seen – let me deal with the Marcellus and Montney separately and then let’s talk generically about what’s actually probably going to be the choke on expenditures in both of those plays. In the Marcellus we’re going to be going from three to six rigs by the end of this year and as John has already indicated, depending on our final capital choices for 2010 we could go up to about 10 rigs in 2010.
In the Montney we will be starting commercial development of two segments of the Montney next year. We’ll probably start with three rigs next year and we will increase those rigs as we continue to derisk the Montney next year. I think the biggest constraint on our growth is not actually the capital it’s the organizational capability to grow at the rates that I’ve just outlined Andrew and we’re confident we can do that with the organizational capability that we’ve built.
Your next question comes from Brian Singer – Goldman Sachs.
Brian Singer – Goldman Sachs
Following the acquisitions of additional acreage in the Marcellus and Montney, what are your thoughts on further expansion to potentially include another shale gas area? Is that something that is still a focus or following these acquisitions and drilling results is that less of a focus.
I think firstly Brian we’re delighted with clearly having doubled our position in both the Marcellus Pennsylvania and the Montney Shale which we believe to be two of the leading shale plays in North America. I think we’ve always said that we will continue to look for the potential to enter an additional Tier I play within North America. There’s nothing specific at this moment in time but we’ll continue to look for opportunities and should the right opportunity present itself at the right value at the right time I think that’s something that we’ve consistently signaled that we would consider.
Back to Paul’s answer Brian, if you think to 2009 we came in to 2009 with a balance sheet that had the capacity to purchase positions but I think what we’ve been learning is you’ve got to be in the best spots you’ve got to be in the best rocks and all the stuff that came available in 2009 was frankly in an inorganic since may have not been the best rocks. We’re increasingly discerning, therefore the funds were diverted on to organic expansion, to what we do think is now the best rocks, the Tier I that we’ve been describing. I think we’ll continue to be looking but we will also continue to be fairly discerning about where we deploy the capital.
Your next question comes from Greg Pardy – RBC Capital Markets.
Greg Pardy – RBC Capital Markets
Just a couple of questions, I know the focus has been on the Marcellus in Pennsylvania but any thoughts on the [inaudible] just on the back of the environmental impact statement?
As you’re probably aware the comment period closes at the end of this month. We’re going to be well placed to provide our comments by the end of this month as well with the rest of the industry. It’s likely I think there are some calls for an extension for this initial comment period and that might be granted and so that might be a 30 day extension that may be granted in the coming weeks.
What I’d tell you is that everything that we’ve seen from the proposals that have come forward from the DEC, many of the things are actually just formalizing practices that we already do as a company and I think we’re confident that we could see progress in the first half of next year in New York.
Greg Pardy – RBC Capital Markets
I’ll shift gears a little bit just as it relates to the restructuring of Western Canada in to the conventional in the shale so John when you’re thinking about getting value for the conventional assets I know you’d be likely looking at just traditional sales, would you ever think about spinning out a portion of those assets to your shareholder base or is that not on the table?
Greg, the way we look at it is as follows, when we think about the capital deployment and capital allocations within the company what’s clear is the conventional business will not subtract capital in our system versus the alternatives that we have to put the capital in, at least not all of it will. Some of it by the way, is really exceptionally good high returns, growth opportunities so some of it will attract that capital but not all of it will. For the stuff that won’t then we have a number of options of course, one is the traditional sale.
There are structured arrangements we could make in to the market, there are joint venture arrangements, other people’s money, all of those things I think are on the table. As Paul is going through his considerations of how to restructure that business, how to think about those assets, we’re considering all of those. That work is underway right now and I’m hopeful that as we enter next year we’ll be clear about how we want to proceed but all of those things are on the table.
Your next question comes from [Chris Steel] – Macquarie Securities.
[Chris Steel] – Macquarie Securities
The question is on the Montney, when you look at your Tier I acreage and the number of locations that you put out this morning, it implies about 11.5 sections on average for a development scenario. I’m just wondering if you can give some context on that degree of spacing on a per section basis number one. Then secondly, with respect to moving forward with commercial development in the Montney Shale can you give us a sense of what’s on the table for this winter?
The Montney, as you’re probably well aware is three times as thick as the Marcellus so you actually need more than a single well currently in to each section so think of it as kind of to get to the 3,000 well locations you sort of have 100 acre spacing and you need three wells per unit to actually drain the Montney as we go forward. That’s how you get to the 3,000.
In terms of where we will go in terms of the Montney in terms of development this winter we’re going to continue to bring online the remainder of the pilot wells that we’ve drilled and will be completing actually in the coming four to five weeks. Then, our focus in the Montney shale is going to be two things, one is to bring in to commercial development in particular the Greater Farrell area which we’ve now derisked to the extent that we’re comfortable going in to full scale development of the Greater Farrell area.
Secondly, we will continue to pilot next year because the Montney is such a large play, in particular the Cypress area. We’ve picked up now significant acreage as a result of the land sales that have happened this year and we’re excited about that area and that’s the area we’ll be looking to derisk during 2010.
[Chris Steel] – Macquarie Securities
Then just a follow up one question there, one of your competitors announced a well in the Cypress area, can you give us some perspective on Talisman well control in that area?
I know the well that you’re talking about which is up in the northern part of Cypress. We’ve got one vertical well in Cypress A that’s under confidential data. The results there are not significantly different from the publically disclosed Husky well.
Your next question comes from Peter Ogden – National Bank Financial.
Peter Ogden – National Bank Financial
I just had a couple of questions regarding additional color on exploration. You mentioned Columbia you had completed the testing on the Columbian Huron 1 well, can you give maybe additional color on what that testing program entails? As I understand there was a 3,400 barrel a day gas condensate test, was there anything beyond that and where do you go from here?
Peter, in Columbia we completed the exploration on Huron several months ago. What we have there – we tested two reservoir intervals, it’s actually the same reservoir which is repeated in the structure and we tested gas condensate in there at rates up to maybe 3,500 barrels of condensate a day. So, we have quite a significant discovery [inaudible]. We stopped the drilling activities now, we’re acquiring 3D seismic data over the Huron structure and we will be using that during 2010 to plan the appraisal process for this discovery which will involve drilling several more wells. We plan to start the first of those appraisal wells before the end of 2010.
Peter Ogden – National Bank Financial
On the Situche well you mentioned several oil wells in an upper zone and a side track, can you maybe explain what those show? Was there tests already on those oil shows? And, the purpose of the side track right now?
The Situche well in Peru in the Amazon jungle, the discovery well was just in 2005, we have now drilled about 800 feet down dip from the discovery well with the current well which is [inaudible]. That well went to through the lower Vivian reservoir which was the oil sand that we found in the original discovery well and it is [inaudible] and we have completed the evaluation of that and we demonstrated that it looks very active and that is in communication with the oil and the discovery well.
So we’ve conservatively down dip the extension in the main reservoir in Situche, we drilled the well on to total depth which is over 19,000 feet, the deepest well ever drilled in Peru. We had also [inaudible] and we’ve now taking the decision to side tracked the well off dip to test that reservoir enclosure and see whether we have a deeper accumulation. So, that’s the current activity. We’re busy side tracking it for the deeper upside potential.
Having made a discovery or confirmed the discover in the higher zones and we now believe we have reached a threshold somewhere along 30 to 40 million barrels [inaudible] we have to date which is encouraging for much of the development. We think we’ve reached that thresholds and we’re now looking to additional volumes that we can add to that.
Did you hear that clearly enough?
Peter Ogden – National Bank Financial
I didn’t hear the volume at the end but I can check in with you guys later.
Richard was saying in general we believe 30 or 40 million barrels is commercial in that part of the world and we believe in the upper Vivian zone we have now proven that in the Situche well with the appraisal and we’re now looking at the lower zone called [Cushabatie] which we’re sidetracking up dip now having penetrated that lower zone further down dip so we’re now sidetracking that up dip.
Peter Ogden – National Bank Financial
What’s the time line on the up dip sidetrack, when would we see results from that?
On the sidetrack we’ve got very good progress, if we don’t have any drilling problems we will expect to be down within the next month.
Peter Ogden – National Bank Financial
The final question for me is on Marcellus, what’s the current cycle time from spud to on stream and where do you see that going over the next kind of six to eight months? Is that going to improve or how long does it take you to get these wells on stream?
Our average drilling cycle time is down to 20 days. It will be another 14 days to complete and tie in the wells. That’s the kind of average cycle times that we’re down to in the Marcellus.
Improving all the time? Have we flattened out?
We continue to make progress, in particular on the drilling side and expect to see further progress as we finish this year and go in to next year. We expect our drilling and completion cost next year to [inaudible].
Your next question comes from Brian Dutton – Credit Suisse.
Brian Dutton – Credit Suisse
There’s been lots of discussion here on the Marcellus but perhaps taking a different tact and going all the way back down to PNG because I see here in the headline of your quarterly release, you’ve really laid it out here as being really quite prominent giving the position in the headline so I was wondering if you could give us some insight, a little bit more than what you’ve already been talking about as what you see here as the opportunity and the time line?
Let me ask Paul Blakely, if we can, it’s quite difficult because we’ve got very loud [inaudible] which is where Paul and Richard are sitting. Paul, I wonder if you could give a little bit more perspective and context around Papua New Guinea. If it’s too difficult I will try.
A. Paul Blakeley
In respect to our position, currently Papua New Guinea is a play that we’ve been looking at for a while. We saw an opportunity to access a pretty significant volume of undeveloped resource and capture quite a large and contiguous land base which has a lot of further on exploration potential. Of course, the real advantage of it in the context of economic return is it’s a very low cost on shore environment for us.
So we’ve executed on that strategy, acquired a number of contiguous blocks and it sets us up now for two or three years of follow on exploration and appraisal which we hope and expect will lead to a material reserve volume which we can develop in due course. So, as John alluded to the 3 to 5 bcf is a number that we certainly see is within reach with the existing lands that we’ve already captured.
Brian Dutton – Credit Suisse
Perhaps a second question, Paul if he’s down in Southeast Asia, would be on sanctioning of HSD HST, I’ve seen that that’s moved over in to the first part of next year. Any reason behind that and what would be the implications then for reserve bookings and your target on that 30% to 50% reduction in F&D costs this year?
A. Paul Blakeley
Brian, as we progressed towards sanctioning which we had hoped and thought would come through in the fourth quarter this year, we think now it’s probably going to move in to early next year. That’s just part in parcel of the approval processes that we’re going through. We have already submitted our outline development plan to the government which is the first step in a series of steps that lead to full project sanction. All of the preparatory work, technical work that’s required to be done is on track and the actual sanctioning does not affect project scheduling in any material way and we still expect that we’ll achieve the first oil from the EPS, the Hai Su Den, Hai Su Trang early production scheme around the middle of 2012.
Let me pick up the second part, Brian of course if one doesn’t sanction the product, one doesn’t book the reserves and I think the new Talisman says we’ll get the engineering right, we’ll do the engineering properly so we’ve got a good project and not be pushed in to it by some urgent need to book reserves. Those reserves will be booked when the project is ready to move forward and to sanction it. In this case we’re signaling the first half of next year.
The comment I made about the reduction in F&D costs, of course encompasses that delay it also encompasses the additional graphical spending that we’re putting in our North American business so I’m pretty confident that we’re moving in the right direction here and these swings and round abouts can come and they can go but in general we’re moving down and I repeat that I think we will achieve a 30% to 50% reduction in F&D in 2009 over last year’s outcome. That’s really why I made the comment actually.
Your next question comes from Mark Polak – Scotia Capital Markets.
Mark Polak – Scotia Capital Markets
A couple of questions on two different areas, first in the Utica I was wondering if you could just comment on the approach you’re taking for completing these wells? How long of a horizontal for the first two is planned and how many frac stages and when we might get results on that? Then the second question is on Corridor and just wondering where the increased demand is coming from? Which contracts or markets and whether we can see that going over a bcf a day next year on a gross basis?
In the Utica where we’ve spudded our first horizontal well the well design looks very similar to a Marcellus well so this is about 3,000 to 3,500 feet horizontal/lateral and eight to 10 stages of fracs in the Utica. In terms of timing, we’d expect to have the first well completed by the end of the year and then we go straight on to second well then which should be drilled and completed by the end of the first quarter next year.
A. Paul Blakeley
Well I mean overall and in general gas demand within Indonesia and the various markets continues to be strong and growing. As an overall statement we see that throughout the region actually. If we think very specifically about Corridor essentially we’re supplying three markets, one is up to Caltex for the Duri project, in to Singapore and Batam and the third one is the PGN West Java line in to the greater Jakarta area.
We actually see growing demand in all three. So we have recently signed, and to kind of pick up on each of them, we recently signed ahead for an additional contract in to Caltex that will actually require some capital investment above ground to handle the extra volume but in the meantime we’re continuing to deliver over and above our general current contract quantities. Singapore and Batam both calling for more gas and that line has some minor upgrades associated with it to help improve volume delivery there as well.
Thirdly, just as part of our original contract with PGN to supply gas in to Jakarta we’re seeing steady ramp up as we had planned both through 2009 and through 2010. So, overall very strong demand everywhere and we feel pretty comfortable with that.
Mark Polak – Scotia Capital Markets
That additional capital is that Suban Phase III?
A. Paul Blakeley
No, that’s a separate and further development of additional uncontracted volumes from the Corridor PSC, from the Suban field and that would be a follow on over and above the three areas that I’ve talked about.
Your next question comes from Barbara Betanski – UBS Global Asset Management.
Barbara Betanski – UBS Global Asset Management
The question is on the Marcellus and Montney, given that you’ve stated that the full cycle economics work at about the $4 level I’m wondering if you’re going to be going full steam ahead if gas prices are in that $4 to $5 range or is there a chance that you might pull back a bit if we see low gas prices? That’s the first part of my question.
Look, the answer to your question is our view medium term on the gas prices, ultimately it will be set by margin of cost and supply and that margin of cost and supply is certainly reducing. It’s not, I don’t think, in our view medium term in the $7 to $8 range, it might be in the $5 to $6 range point one. Which is why we’re being increasingly discerning about what we’re calling Tier I which is going to be not static, it will be changing and we’ll be high grading the portfolio all the time.
So certainly in a medium term price scenario $5 or $6 we can make good returns on the Tier I acreage today. In the short term of course we can take market actions to hedge some of that to higher prices and then we can take a view going forward as we accelerate in. I’ve said to you I think before that it’s good to be at this end of [wedge] in some senses because we can moderate our pace of investment upward or downward if we take that view.
In the very short term I think the gas prices are still struggling to find the logic. I mean the bearish fundamentals still exist but on the other hand people are worrying about the level and extent of production declines so I think we’re in quite a dynamic moment. But, I don’t think we’re at the levels of capital investment in to our new shale gas business limited as Paul has described by our judgment of capability, internal capability. We’re not at levels yet which are worrying us that we’re over investing in to a gas price which today is sitting between $4 and $5 and we believe medium term may be between $5 and $6. I think that’s sort of contextualizing the question.
Your next question comes from Rafi Khouri – Raymond James.
Rafi Khouri – Raymond James
Just a couple of questions on the exploration side, if you wouldn’t mind touching base a bit on where you are in the well in Kurdistan, sort of level of activity and when you’re expecting TD? Second question is maybe going back to Columbia, could you give if at all possible any indication on sort of percentages of gas you might think are present in the Huron discovery?
First on Kurdistan I think frankly, I’m slightly cautious on this, we’re way less sensitive in terms of Kurdistan than the operator who controls both the operations and subject to our agreement when he chooses to issue press releases so I need to be very, very cautious. It is a tight hole and the well is drilling ahead and I’m not sure that I’m able to say frankly anything else. I think I prefer to leave that to the operator. So, I’m sorry to be uncommunicative about that but I think that’s the right stance for us to take on that I’m afraid.
It is drilling ahead, the operations are going sort of fine and the operator will be proposing news release as and when the operator deems it appropriate to do so subject to our agreement. I think that’s how we have to leave it I’m afraid. I will give you a slightly broader context on Kurdistan for us. The new exploration strategy requires a certain amount of running room in any area that we are and I have to say that right now in Kurdistan we have great acreage in a great hydrocarbon bearing region of the world of course but I’m not sure we’ve yet got enough acreage for Richard’s strategy which requires three or four wells per year for three or four years.
That would be his ideal sort of acreage in order to drill up. We’re not in that place yet in Kurdistan. I think the real question for us, as Talisman is in the context of that strategic position is when and to deepen that acreage position. That I think is as much determined by political and above ground conditions as below ground conditions. So actually the real decisions for us are about when and if we chose to deepen our acreage position in Kurdistan.
That’s again, a more strategic view of how we’re think about this area which is just I think helpful to you and the well will be the well as I’ve described it and I’m not going to say anything else about that. Richard, a comment on Columbia and gas?
Let me just make a few comments on the percentages of gas that you asked about. We’ve issued a number about Huron, it’s in [inaudible] which has a lot of discovered gas condensate to the south, particularly in the Cusiana field. This is a trend which is naturally a gas condensate trend, it needs to be a gas condensate trend in order to get commercial production because we need the high [viscosity] fluid to produce from a very low [inaudible] reservoir.
What we’ve found in Huron is gas condensate with a condensate yield of somewhere between 150 barrels per million cubic feet up to 200 barrels per million cubic feet which is a rich gas condensate and so our interest here is clearly as it is to the south is in gas recycling, shipping out the condensate and marketing that but putting the gas back in to the ground to maintain reservoir pressure and maximize the amount of acreage we can get out.
Your next question comes from William Lee – CIBC World Markets.
William Lee – CIBC World Markets
I just had a quick question, with your new acreage are you guys going to provide some new resource assessments for the Marcellus and the Montney shales?
The answer to your question is I think it’s best to do this sort of annually and we’ll do it as we go through the yearend of indeed as we update strategically in May. So, we haven’t provided additional contingent resource estimates because I think otherwise we’d be sort of chasing our tail. They’re obviously positive and additive but we will be providing that either at the yearend and I’m thinking either at the yearend or in our May update.
William Lee – CIBC World Markets
If you guys run 10 rigs in the Marcellus, what does it imply in terms of total number of wells drilled in the 2010 time frame?
As I’ve already said we’re going to have six rigs up and running by the end of this year. If we took a theoretical case of adding a rig a quarter during 2010 and ending the year with 10 rigs than we will be drilling, again theoretically approximately 200 wells next year in the Marcellus.
Theoretical in the approximate I think I heard?
William Lee – CIBC World Markets
Then I guess one last question, how does the Montney core now rank when you guys look at the shale plays here you’ve got? There’s a lot of talk about MD&A about Marcellus and also the Montney shale, how does the Montney core rank within all of your plays now?
We like the Montney core a lot, we’ve drilled 27 wells year-to-date, by the end of this year we’ll have put 35 wells in to the Montney core and we should be doing by the end of this year about 50 million standard cubic feet a day coming out of the Montney core. Everything is going well, well costs are coming down, EURs are coming up, IPs are coming up. The only problem we have is we wish we had more of it. We have limited running room in the Montney core relative to the positions that we now have in the Montney shale and in the Marcellus.
Your next question comes from [Carrie Tight] – The National Post.
[Carrie Tight] – The National Post
I just have a question if you can go over something you mentioned earlier, did you outline how many barrels of oil production you’re looking to sell throughout the rest of the year?
No. What I have said is we anticipate that by the end of the year we will have sold 8,000 barrels a day annualized over and above the two assets that were already in our plans as we entered the year which was Trinidad and the Netherlands which together were about 7,000 or 8,000 barrels a day annualized themselves. So we came in to the year with a sort of announced sale of those two assets which were about 7,000 to 8,000 barrels a day and we anticipate now by the end of the year that we will have sold the equivalent of 8,000 barrels a day equivalent when we get to the end of the year.
[Carrie Tight] – The National Post
So how much have you sold already this year out of that 8,000?
Well, it’s not far off, we’re close to the end of the year and by the end of the year we’ll have sold about 8,000 barrels annualized.
[Carrie Tight] – The National Post
My second question, is there any thought to taking a sharp jump in the change of the plan looking at ConocoPhillips Syncrude stake?
No, our own strategic direction does not include heavy oil and we took that view in May 2008 partly because we had a head start if you like, relative to our heavy oil position any way on our shale gas and that actually fitted our bill better than the heavy oil so we actually disposed of our last heavy oil assets and set our course for shale gas which is where we shall concentrate going forward.
Your next question comes from [Mark Freezon – Verson Partners].
[Mark Freezon – Verson Partners]
Just a question follow up on the PNG strategy that you’ve outlined, you mentioned a little bit about a possible supply contract in to an LNG type facility, would an LNG facility be something that you’d be interested in owning yourself or are you looking to partner and just be the supply side of that? And, barring and LNG situation what is the market for natural as currently?
A. Paul Blakeley
It’s very early days to be narrowing in on what the actions may be for development. Suffice to say that we see there are a number of options and obviously most recently in the news has been a lot of talk about the PNG LNG project which is operated by Exxon and there is certainly an opportunity to engage with Exxon Mobil and that partnership with a view to it being one of the potential [inaudible] stake options.
John mentioned in his speech the possibility of a small modular standalone facility, that certainly is also something we look at as being potentially attractive and there are other solutions too that we’re looking at. I think suffice to say it’s early stage in the exploitation and aggregation of the resource but we do see some choices for development and that’s the best place to be.
As to Talisman operating or not again, it really depends on the selected solution. We could go with a third party perspective. We are preparing ourselves to be able to do something as a standalone development but inevitably we look to partner for expertise that doesn’t reside in house and we’ve done that before and I think this is an area where we could successfully deploy that strategy again. As to markets, if it’s LNG of course we’ll be looking out of the PNG area for options and that’s still very early days.
If I could just add, it’s quite interesting when you examine the customer base in that part of the world then of course they don’t want to necessarily be beholden to the big guys with one scheme so they’re actually quite welcoming of a diversified supply base. So provided there’s a constant operator then there is actually room for a smaller different LNG supply source. So, I think all of those options as Paul has described are under consideration. We are in discussion, as I mentioned, with several third parties who bring expertise and market knowledge and all of the things that are required who are keen to participate in that.
We have no further questions at this time. Please continue.
Thank you very much for listening to us and participating in our conference call. I think we’ll close it down with that. Thank you for listening and we’ll talk to you next time.
This concludes the conference call for today. Thank you for your participation. You may now disconnect.
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