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Executives

Charlie Fischer - President and CEO

Marvin Romanow - EVP and CFO

Analysts

Brian Dutton - Credit Suisse

Amir Arif - FBR Capital Market

Martin Molyneaux - FirstEnergy Capital

Steven Calderwood - Raymond James

Bob Canty - TIAA-CREF

Al Sebastian - Irin Bank

Gil Yang - Citigroup

Peter Best - Indus Capital

Terry Peters - Canaccord Adams

Robert Plexman - CIBC World Markets

Kenneth Pounds - Nutmeg Securities

Kam Sandhar - Peters and Co.

Michael Young - Chatham Bay Advisors

Nexen Inc. (NXY) Q2 2008 Earnings Call July 17, 2008 9:00 AM ET

Operator

Welcome to the Nexen 2008 second quarter conference call. I would now like to turn the meeting over to Mr. Marvin Romanow, Executive Vice President and CFO, who is accompanied by Mr. Charlie Fischer, President and CEO. Please go ahead Mr. Romanow.

Marvin Romanow

Good morning and welcome to our second quarter conference call. This is Marvin Romanow, Chief Financial Officer and with me today is Charlie Fischer, President and CEO.

Certain statements that are made today are forward-looking statements. Actual results may differ from expected results because of various risk factors. Please review our 10-K and 10-Q for a complete description of these risks. More information with respect to forward-looking statements and other cautionary notes maybe found in today's press release. All numbers in my comments today are in Canadian dollars unless I specify otherwise.

Moving to the quarter; we have solid financial and operating results, generating C$946 million of cash flow and C$380 million of earnings. We also generated the highest quarterly cash netbacks in our history, at over C$72 per BOE.

Production volumes for the second quarter amounted to 254,000 BOEs per day and were impacted by the shut down of the Forties Pipeline following that two day strike of the Grangemouth refinery in Scotland, requiring the temporary shut down in our North Sea production.

With Long Lake volumes ramping up and improved reliability at Syncrude, we remain on track to meet our annual production guidance.

Our financial results for the quarter were impacted by three items. Firstly, we were holding 850,000 barrels of crude oil inventory from our North Sea operations at quarter end. This moves approximately C$50 million of cash flow into early July when this inventory was sold.

Secondly; our stock price increased by more then a third, since the first quarter. As a result we have recorded approximately C$330 million and that's C$240 million after tax of stock-based compensation expense.

Thirdly our marketing division reported a cash flow loss of a C$164 million in the second quarter, compared to a contribution of C$13 million in the first quarter. This loss primarily relates to widening locations spread, driven by significant increases in North American natural gas prices. This occurred at a time when we were positioned to take advantage of traditional seasonal narrowing.

By way of offset, we have c$207 million of unrecognized gains in our storage and transportation assets that have increased in value. Due to accounting rules these gains can only be booked when these assets are used. We expect to be able to report a large part of these gains this coming winter in the last quarter of 2008 and the first quarter of 2009.

Comparing to our second quarter results in 2007, additional current taxes in the UK and the impact of a weaker US dollar reduced our cash flow in 2008 by more than C$500 million. For the full year we expect to generate approximately C$4 billion of cash flow assuming as WTI price of US$90 for the rest of the year and NYMEX gas prices of C$8.50. This will provide us with surplus cash, which we can use to reduce net debt, repurchase shares and fund additional capital investment.

Earlier today we announced our intention to seek approval from the Toronto Stock Exchange for a Normal Course Issuer Bid. This will allow us to repurchase for cancellation up to 10% of our common shares. We have also increased our capital investment program by between C$600 million and C$800 million. This will allow us to accelerate shale gas, coalbed methane and shallow gas projects in Western Canada along with development drilling in Yemen and the development of Usan in Offshore West Africa. We expect this additional investment will add between 4,000 and 6,000 BOEs per day to our 2008 exit volumes and bring our total capital investment program for 2008 to between 3 billion and 3.2 billion.

Turning to operations, Buzzard continues to outperform and contributed 86,500 BOEs a day and that’s just over 200,000 BOEs a day gross to our quarterly production volumes despite the Grangemouth interruption.

In early July, Buzzard was shut down for two days to move our rig off-location for scheduled maintenance. We expect to shutdown Buzzard again for a week in August to move the rig back on the location.

Elsewhere in the North Sea, first of the metric is expected in the fourth quarter and we drilled exploration wells at Pink and Blackbird. We have sidetracked the Pink well and are currently evaluating results.

This discovery is a candidate for core development with Golden Eagle. We are evaluating Blackbird and upon success, it could be fast tracked for development given its close proximity to the Ettrick FPSO.

At the Long Lake, commissioning of the upgrader is progressing well and is approximately 80% complete. We remain on track for start-up in late in the third quarter. We continue to inject steam into the reservoir and currently have 35 of 81 well pairs converted to SAGD operation. While the reservoirs is performing well, we have been limited by surface facility start up issues such as power outages, heat exchangers down time we have restricted steam generator. These issues have been resolved and our steam capacity is ramping up.

At this stage of start-up with some of the well pairs on SAGD operation for these in bitumen and other still circulating steam, the overall SOR is currently ranging from 5% to 6%.

The well pairs that have been converted to SAGD operation are currently producing at 13,000 BOEs a day or 6,500 net to us at an average steam-oil-ratio of about 3, which is better than we expected in this phase of the ramp up cycle. We expect to have sufficient bitumen feedstock to start up the upgrade later this summer.

SAGD volumes are expected to continue ramping up through the remainder of 2008 and reach the full design rates of 72,000 barrels a day in late 2009. Phase 1 of Long Lake will develop approximately 10% of our oil sands resource inventory. Work continues on Phase 2 and our goal is to sanction by late this year.

Ultimate timing depends on accumulating sufficient operating history from Phase 1, receiving clarity on proposed regulatory changes such as climate change and receiving regulatory approval for the Phase 2 SAGD portion.

Our strategy focuses on identifying resource opportunities and moving early to build an asset base. A great example of this is our Horn River shale gas position. Our Horn River basin in northeast British Columbia has the potential to become one of the most significant shale gas plays in North America and has been frequently compared to the Barnett Shale in Texas.

As previously announced, we estimate our Dilly Creek lands in the Horn River basin to contain between 3 trillion and 6 trillion cubic feet and that’s roughly 0.5 to 1.0 billion barrels of oil equivalent of recoverable contingent resource. This could double our total proved reserves of the company. Further appraisal activity is required before these estimates can be finalized and commerciality established. Following the success of last winter's drilling program, we have accelerated the drilling of two horizontal wells which will be fraced and tested this summer. This winter, we are planning an 8 to 16 well drilling and completion program. We have secured access to 70 mmcf/d of pipeline and processing capacity in the area. And this winter, we are planning an 8 to 16 well drilling and completion program and this will comprise either one or two paths.

Turning to Usan, offshore Nigeria. The field development has commenced and all major contracts for deep-water facilities have been awarded. The field is expected to come on stream in early 2012 with our capital investments expected to range from US$1.6 billion to US$2.0 billion. At full production rates, we expect Usan to generate approximately US$1 billion of annual cash flow assuming all price of US$100 a barrel. Usan is clearly an exciting project that will only develop a small portion of the resource potential here and we expect to resume exploratory drilling in 2009.

Offshore Nigeria, the size of our acreage is about equivalent to 100 deep-water blocks in the Gulf of Mexico. In the Gulf of Mexico we had interest in discoveries at Vicksburg and Shiloh and we recently spud an exploration well at Fredericksburg, with results expected late in the third quarter. When we combined the discoveries at Vicksburg and Shiloh with the prospects we see in our rank holdings, this area has the potential to become a very significant asset in the Gulf of Mexico.

We have two new deep-water drilling rigs coming in mid 2009 and mid 2010 which will allow us to kick start our deep-water appraisal and exploration program in the Gulf. We plan to use the first rig to drill an appraisal well at Knotty Head to asses this potential world-class discovery.

To conclude, let me summaries the value proposition of investing in Nexen. All of our assets are performing well and we are on track to meet our annual production guidance. We expect significant cash flow and earnings this year as we have not hedged commodity prices and low operating costs and low royalties on almost all of our production. This is generating cash net backs that are amongst the highest in the industry.

As Long Lake the project remains on schedule and we look forward to first premium synthetic crude later this year. We have several identified projects such as Ettrick, Longhorn, Usan, Knotty Head and a number of discoveries in the UK North Sea that will generate future production growth and value creation.

Our Horn River shale gas play complements these attractive long cycle-time projects riding us with short cycle-time, visible near-term growth. In addition to these defined projects, we have a rich portfolio of exploration opportunities in the North Sea, the deep-water Gulf of Mexico and offshore West Africa.

That concludes my prepared comments; I will now open the call to questions.

Question-and-Answer Session

Operator

 

Thank you. (Operator Instructions). Our first is from Brian Dutton from Credit Suisse. Please go ahead.

Brian Dutton - Credit Suisse

Yes. Good morning, Marvin. You mentioned part of the increase capital which you planned for this year, will be directed towards Yemen. Does this imply that you’ve come to a resolution now on the extension of the PSA?

Charles Fischer

Brian, this Charlie. We haven’t got a formal extension in place, but we see a lot of opportunities to drill additional wells. They have very gassy shale. Given the commodity prices that we are seeing and it just makes good sense to do it. So we’ve agreed with partners to go ahead with that.

Brian Dutton - Credit Suisse

And second question, just in terms of the increase production at the exit rate, but you’re now looking at where would that be coming. Can you split that up?

Charles Fischer

Some coming from the Yemen obviously with the additional wells. The dollars will be in Canada and it’s a combination of CPM and largely CPM – it's all gas.

Marvin Romanow

And that is, in that program we’ll have volumes as well.

Brian Dutton - Credit Suisse

Okay thanks a lot.

Operator

Thank you. The next question is from Amir Arif from FBR Capital Market. Please go ahead.

Amir Arif - FBR Capital Market

Hi good morning. Couple of quick questions for you. First of all on the to start the upgrade, what’s the minimum amount of bitumen feed stock you do need to get that going and I understand that you’re already at 13,000, still ramping up or where do you want that to be before you really start the upgrade?

Charles Fischer

We’ve all selected this, but we need be say 25,000 to 35,000 barrels a day of supply. We have contracts in place for third party as supplies for about 10,000 a day to give us some flexibility as we come up. So, when we look at our ramp-up schedule and we see how all the reservoirs performing, we’re pretty confident that there won’t be a problem, particularly with the back stock that we put in place that gives effects of some additional bitumen in the short-term if we need it.

Amir Arif - FBR Capital Market

I apologize as I missed the start of the call. But on the marketing loss, are you taking position just on the gas spreads?

Charles Fischer

We don’t bet on the absolute price. We usually look at basis differential and then historically that’s been a very good play for us. Typically what we look at is seasonal differences and basis differential on gas, and we’ve got a lot of experience typically in terms of how those move and what we’ve seen is some variation in that, largely I think related to the run up at oil prices, and with rigs coming on and more LNG landing, we’re seeing some changes. So, we have backed off significantly on those positions and we’ll wait and see how the market stabilizes before we get back to the normal.

Amir Arif - FBR Capital Market

Sure. So those have been widening even more since the end of the quarter. So are these positions still open or are these ones that you have closed, or I’m just trying to figure out what’s the implication for the coming order?

Marvin Romanow

Yes, now since the end of the quarter, our book has actually…

Charles Fischer

We are along those positions in the second quarter.

Amir Arif - FBR Capital Market

Okay. And just final question, I mean you have generally free cash flow at year end. You’ve got everything based on a $4 billion cash flow projection for your increased CapEx. If both stays higher the way it is, what would you do with incremental cash flow above 4, are your good inventories as well as potential buybacks. So where would you put the incremental cash flow?

Charles Fischer

I think the incremental is going on in two places. We talked about the buybacks. If the buybacks is full, the amount of the buybacks will depend on how much free cash is coming. We would also build some cash, there is still of lot of people, we have a BBB negative rating from one of the rating agencies, which I always find the best pricing because we got about one time spent cash flow, in terms of our debt-to-cash flow ratios. So we’d like to see that improve and one of the ways is to do that, is built some cash and what is the net debt position in the short-term, that gives us more flexibility as we go forward.

Amir Arif - FBR Capital Markets

And actually one final question, on the increased CapEx of 600 to 800, 150 is going to the shale gas, can you breakout roughly where, the rest is going on the increment?

Charlie Fischer

Yeah, if you look at it broadly, well Mark has got those charges.

Marvin Romanow

Yeah we’ll invest about another roughly 150 in shale gas, coalbed methane will be another 50, conventional gas will be another 50. Nigeria is going faster, so that will be almost an additional US $100 million.

Charlie Fischer

Not just timing, we got approval earlier than we had much of there did and so. It doesn’t change the cost of the project. It’s just timing issue, we spent more dollars earlier.

Marvin Romanow

In Yemen we’ll invest another 50, Long Lake we budgeted at the lower end of our total cost range, and we are seeing cost creep towards the higher end. And that would really make up the entire 600 to 800.

Amir Arif - FBR Capital Markets

Okay, sounds great. Thanks, guys.

Operator

Thank you. The next question is from Martin Molyneaux - FirstEnergy Capital. Please go ahead.

Martin Molyneaux - FirstEnergy Capital

Two questions, gentleman. While I guess, first Blackbeard or Blackbird in the North Sea, can, are we testing that now, or where do we sit there? The second one is can you flesh out a bit more the situation that you are in with bidding around in Iraq?

Charlie Fischer

So Martin, Blackbird is being tested and once we get a sense as to what it's doing and get little bit more information, analyzing our date to start well, we’ll come back and describe that but it does look good, it looks promising, with what we see today. The issue in Iraq for us is something we’ve looked at for a long time. You have some of the work effectively going out there and so short-term access is unlikely, but there’s a lot of well in Iraq and ultimately the issues that we see there today above ground, are going to get resolved. So we were pleased to be included in the early round as being, sanctioned or authorized by these Iraqis to participate and I think we are well positioned do that, so we’ve gained a lot of knowledge about operating in the region and have done a great job again and over the years and I think they’ve recognized that and that’s why we were included in that early round of companies that were approved.

Martin Molyneaux - FirstEnergy Capital

Great, thank you.

Operator

Thank you the next question is from Steven Calderwood from Raymond James. Please go ahead.

Steven Calderwood - Raymond James

Yes good morning, thanks for taking my question. On the shale gas you say you’re spending your $150 million, is it really $150 million in 2008 comprising the 8 to 16 well program that you’ve added or is there some of that drilling program your mark for 2000, I’m trying to a get a handle on capital spending, in the incremental capital spending on the company?

Marvin Romanow

That’s not all, it's not all just drilling though, we’ve got to build some infrastructure so we’ve got some road cost, we got some pipeline cost and we got to line up equipment for the winter program and we’ll start that winter program thoroughly. One of things we are trying to do here is accelerate our knowledge. We have participated in northeastern road, which gives us access so that’s why we go in the summer and drill a couple of wells and we want to extend that capability. So, the costs here are not only the summer cost, additional cost through the winter program and then getting ready for next winter and carrying forward. The winter program that we are going into this coming winter, we are planning to drill as many as 16 wells to change a little bit upward or downward based on what we see through the summer program but we see real opportunities here, and we are going to go as fast as we can to define the opportunity and move towards commerciality.

Steven Calderwood - Raymond James

 

Okay. And if I may, I didn’t catch what you said the production capacity you were contracted at in near future but can you just take us through what your current production is, what your production will be in the summer and what this processing capacity is? Is that without any spending anymore capital and what would you be able to expand it to by spending more capital in Horn River?

Charlie Fisher

Okay. You are talking strictly on shale gas.

Steven Calderwood - Raymond James

You bet.

Charlie Fisher

Sure. We only have one horizontal, one vertical tied in right now and we are producing them for lower than 2 million a day, and that’s in line with what our expectations were. The horizontal is a well that we had completed using two frac segments and what we are seeing is about that when we look across the industry results, we’ve got 1 million a day capacity on initial production from a frac segment. So, it lines up with that. And when we look this summer with the two wells, we will be looking at significantly more frac segments to try and confirm that work.

We have physical capacity on pipeline and processing that ramps up over the next year basically to 70 million a day in terms of pipelining capacity which we have matched up with processing capability at Ft. Nelson. So if we drill couple of wells this summer and tie them back, we could see if we use half a dozen fracs in each of those wells we could see 6 million a day coming in the early stages from those wells. If we drill as many as 16 this winter, we’ll have a lot of gas coming from that. So we think with the takeaway capacity that we have matched up with the processing capability at Ft. Nelson, it will get us through all of these early stages of evaluation, allow us to complete the wells, put them on long-term test where we are selling the gas, that it gives us the sense of to what those decline curves are going to look like so that it will be easier for us to determine commerciality with some history.

Steven Calderwood - Raymond James

Okay. Thanks, Charlie. Now if I could may just ask one more question here on the capital spending. If I added up what you just said on your capital spending in different, various projects, the incremental $600 million to $800 million, and only get somewhere around 400 of defined project spending; does that mean that Long Lake is the swing factor here and the extra $200 million to $400 million in within that $800 million number?

Charlie Fisher

Those costs are up at the Long Lake, but they are not 200 to 400. They are about 200.

Steven Calderwood - Raymond James

Well maybe I got it wrong here, because shale gas is at 150, CBM 50, shallow gas 50, Yemen 50 and Usan a 100. Unless we’re forgetting to include the 150 from Usan earlier this year, is that’s it?

Marvin Romanow

No there’s a bit more, there is another 50 in the North Sea, another 50 in the US, another 25 in Norway. So I didn’t cover absolutely every dollar when I went through my list. So…

Charlie Fisher

Just had the major ones.

Marvin Romanow

It just had the major ones.

Steven Calderwood - Raymond James

The rest is Long Lake?

Marvin Romanow

And the rest would be Long Lake.

Steven Calderwood - Raymond James

Thanks a lot.

Operator

Thank you. (Operator Instructions) The next question is from [Bob Canty] from TIAA-CREF. Please go ahead.

Bob Canty - TIAA-CREF

Good morning. Earlier you touched upon your BBB minus rating. You said you wanted to go to mid BB from S&P. You mentioned you might do this through your net cash, accumulating a cash balance. Is just having cash enough or would you think the S&P might want to see you actually pay down additional debt and further more when you said you wanted to get the mid BB is that something you’re looking to do in 2008 or you just going to next 18 months or so? Thank you.

Charlie Fisher

Well we would like to affirm this quickly as we can. So when you look at our debt, our debt is typically long-term public debt and it's priced very well and so it allows us to look at buying back a budget debt that’s priced well and gives us great value over the long-term and I think our plan is in the short-term to build some cash and be would be able to net that cash off. We are also looking at other things that would help the rating agencies improve that rating at the same time.

Bob Canty - TIAA-CREF

What other things you are looking at for the agencies?

Marvin Romanow

Well, one of the primary things that S&P has written about was that Long Lake is a very important project to the future of the company and so they are looking to see the operating performance from that as it’s a very significant investment. So with the success we have on wrap up and are about to start the upgrader, some of the movement in penetrating here will come as a due natural course and just as our operating events unfold in the company.

Bob Canty - TIAA-CREF

Okay, thank you.

Operator

Thank you. The next question is Al Sebastian from Irin Bank. Please go ahead.

Al Sebastian - Irin Bank

Good morning gentlemen, just one question that concerns with marketing. In the past you’ve indicated you saw that sort of a normalized level of cash flow from marketing was 200 million per year. Has that changed at all?

Marvin Romanow

I would say in the long-term that’s still a reasonable assumption for us to be a operating from. This year is not going to be quite that good. This year we’ll be in the range of $50 million to $100 million of income from that and we primarily manage against criteria of economic end and from what we can refer to is ROE is a bit different because we can’t mark-to-market our physical storage assets and our transportation assets.

Al Sebastian - Irin Bank

Well, I guess when you take a look at it last year; I think last year was in the $50 million to $100 million range as well. And you know this year it looks like probably $50 million to $100 million, but do you feel there is anything that’s fundamentally changed that would cause you to lower your expectations from the 200 million per year for marketing?

Marvin Romanow

Yes, 2006 was a record year for us. We had over $400 million of income from marketing. 2007 I don’t have in front of me with my records, that was about a 135 or 140 million and this year is going to be a bit short of that. It is quite dependent on what the weather unfolds we have 42 BCF in gas and storage. It’s all priced hedge but we haven’t touched the summer winter differential. So if there is a strong need for natural gas during peak demand periods, during the winter that could make that singular difference could make a huge difference on how much marketing in-term we have in 2008.

Al Sebastian - Irin Bank

Thank you.

Operator

Thank you. The next question is from Faisal Asghar from Citigroup. Please go ahead.

Gil Yang - Citigroup

Hi this is Gil Yang. Could you just remind us when you talked about 1 million cubic feet per day per product stage in the Horn River how sustainable is that or the 24 hour test is long month sustainable rate?

Charlie Fisher

That would be an initial rates and I guess when we look at what all of our competitors have disclosed along with our own experience when we were looking at it we were looking at it as sort of the first month average. We don’t know whether everybody has done that, but it’s certainly not just the first 24 hours. We get some very high rates in that first about first little period you have to let some time go by and get a more stabilized IP.

Gil Yang - Citigroup

Okay, so it’s over, something like your first two weeks of production.

Charlie Fisher

Yeah.

Gil Yang - Citigroup

Second question I have is in the North Sea you said you had 850,000 barrels of inventory carried over. Are those barrels included in your production volumes in the quarter?

Marvin Romanow

Yes, they are included in the production volumes, but the cash flows are going to be included in the third quarter.

Gil Yang - Citigroup

Okay. How many barrels you typically take from quarter-to-quarter in inventory?

Marvin Romanow

Usually we try to have our inventory at just very nominal levels, but what happened in the second quarter is the folks in the North Sea did an excellent job of minimizing our down time and moving this rig off location.

Charlie Fisher

Rig was shutdown, so

Marvin Romanow

The gas was fixed on the rig so, as a result of that these volumes all came in towards the end of the quarter and it really wasn’t possible for us to physically lift them before the end of the quarter.

Gil Yang - Citigroup

Alright, understood, okay But so they are in the volumes, but are the revenue there?

Charlie Fisher

No,

Marvin Romanow

No. the revenues –

Charlie Fisher

We don’t book the revenues until we physically left them so but the crudes. So, the volumes are there, but the revenues aren’t, and we would normally deplete our inventories on the end of the quarter just to make sure that all of that value flows through and this was a bit anomalous and that significant, so we felt that was important describe it.

Gil Yang - Citigroup

Okay. So how much of that affects your pricing per barrel in the quarter then? Because you had no revenues, but you did have the volumes?

Charlie Fisher

It added I think about a little over 4000 barrel per day, average out of 254. So it would affect that little bit, but not a whole hell of lot.

Marvin Romanow

Yeah, we do also disclose our sales volumes, so what you should really look at when you’re trying to calculate an average price is look at our sales volumes, don’t look at our production volumes to get the price impact.

Gil Yang - Citigroup

Thanks and alright. While I’ll go with that you know offline later on in more detail. Another question I’ve got is FOPS delay, how much does that alone affect the volumes? When had you’d expect to come on line and how much would that affect your volumes in the year?

Charlie Fisher

We are looking at something around late summer. We are going to be into the fourth quarter now and this will lease FOPS up that Blue water are building for us, and they have had just delayed a few trials because we have been electricians largely. Against where we had started the year, probably affects 7,000 or 8,000 barrels a day, because it will be late here when it comes on. Having said that, Buzzard has picked up a lot of that slag. So, that’s why when we look at the volumes, we are still tracking within the range that we had projected.

Gil Yang - Citigroup

 

And just finally, maybe you said this. The additional 46,000 barrel in ’08 from the increased Cape that, if that is additive to the current guidance or that is…?

Charlie Fisher

That’s at year end.

Gil Yang - Citigroup

At the year end, exit volume?

Charlie Fisher

That’s an exit volume and so it won’t have a significant impact on the full year rates because that’s where we will be at year end, and we’ll be gradually ramping up to those between now and then, I think the big impact is what that is that to the volumes next year and give us growth as we go into the next year.

Gil Yang - Citigroup

Alright, thank you very much.

Operator

Thank you. Your next question is from [Peter Best from Indus Capital]. Please go ahead.

Peter Best - Indus Capital

Hi, good morning. I just wanted to ask a question on marketing. Just wondering about the volumes that were being hedged or, in size of the positions relative to your production because, it seems that the dollar volume or the dollar size is fairly high relative to your production. So you're, taking positions larger than what your actual volumes are?

Charlie Fisher

Well first when you think about marketing, we not only move our volumes but we move a lot of third-party volumes as well and we get paid for moving those third-party volumes and we have physical presence. So we have capacity on pipelines and we have storage. So I think you have to put it in that perspective, but Marv maybe you want to speak to the actual size.

Marvin Romanow

Yes. And so I think the way your question was framed that implied that we actually hedge our own equity production and further hedge other peoples’ production. In this particular situation we manage transportations for us and other people. We use that base of physical transportation and trade spread positions against those, and it was those spread positions that we had losses on, that we crystallized in the second quarter. So it really isn’t hedging our or other peoples’ production.

Peter Best - Indus Capital

We are just trying to workout whether it’s a speculative element to it or whether it was some other activity. And what’s your risk management process for this? Do you monitor the positions or can you describe how you can tell?

Marvin Romanow

Yes. We know our positions on a daily basis and we manage them on a daily basis as well.

Peter Best - Indus Capital

Okay, thank you.

Operator

Thank you. The next question is from Terry Peters from Canaccord Adams. Please go ahead.

Terry Peters - Canaccord Adams

 

Thank you, my questions have been answered.

Operator

Thank you. The next question is from Robert Plexman from CIBC World Markets. Please go ahead.

Robert Plexman - CIBC World Markets

 

Good morning. Marvin you mentioned that thing could be developed with Golden Eye, is that gong to affect the overall timing of the development for Golden Eye, which I think you’ve been talking about late 2009 early 2010?

Charlie Fischer

Well Robert. We have been looking at alternatives to develop Golden Eagle. And if you would remember, the quality of oil and Golden Eagle was similar quality of oil that we have.

Robert Plexman - CIBC World Markets

So Golden Eagle, right.

Charlie Fischer

It has a little bit of H2S in it. So we have looked at what facilities around us would have capacity to see whether we can do a buyback. We looked at standalone we’ve talked to the Buzzard and its interesting because at Buzzard the reservoir is performing so well, that the Buzzard partners would not consider, bringing new production into Buzzard before 2014.

So standalone looks to be, probably the most likely development and with the success of Pink going back into Golden Eagle. I think, when put the two together, that’s probably the likely outcome and our guys will be working through that, as they finish Pink and a little bit more information. On a standalone, you are probably looking at two to three years, the first production.

Robert Plexman - CIBC World Markets

And so Pink would that be a sub seed pay back into the Golden Eagle platform or is that an FPSO or how would you produce ahead of Golden Eagle at this point?

Charlie Fischer

Whether we do, as standalone platform or a FPSO, is something the guys have been working on. As we speak, to try and determine which is the most economic and we’d be looking at fast tracking, if you look at Ettrick, for instance. We were able to do that a lot faster because we used to lease FPSO and couple of leasing companies have spaced in the yard. So they are going to have wholes, so you can take that whole and build the facilities to lot faster so those are things that we’ll be working on and we’ll be working with our partners to see what the best solution of this is but, it's good to see the successes and we’ll be making decisions as quickly as we can as to how best to develop this

Robert Plexman - CIBC World Markets

Okay.

Charlie Fischer

And as quickly as we can.

Robert Plexman - CIBC World Markets

Thanks, Charlie.

Operator

 

Thank you. Your next question is from Kenneth Pounds from Nutmeg Securities. Please go ahead.

Kenneth Pounds - Nutmeg Securities

Nutmeg Securities, thank you, gentlemen. I had two questions. One regarding the compensation expense, that’s something, could we get a little bit color on that going forward? Is this a one time thing for this quarter and second question was more strategic, the company seems to have a lot of a very nice off-shore projects and also shale projects, I am wondering what more of the CapEx will head toward in the next five years more towards shale or shale in the United States or perhaps because of your expertise obviously oil sands as well. Thank you.

Marvin Romanow

Your first question on stock based compensation. The way we expense our stock-base compensation is we essentially mark-to-mark entire portfolio of outstanding options on a quarter end basis so when our share price goes up we have an expense and it's directly related to how much our share price goes up and if our share price goes down between a quarter end we would have recovery, so if you look in our 10 Q disclosure and announced with the G&A expense we separate out what is ongoing cash G&A and the dollar amount related to stock based compensations. So you can see that quarter-to-quarter for the last few years.

Charlie Fisher

On the other as we go forward, Usan will take us four years to build and we’ll spend somewhere between US$1.6 and US$2 billion in doing that. Oil sands our plan has always been to sequentially develop so when we finish Phase 1, we are looking to sanction Phase 2 as quickly there after as we can and hopefully as early as late this year because what we see is the continuous development of oil sands. As we go forward; on shale gas we have a terrific land position up in Horn River basin and we intend to grow that. We really haven’t focused that much on shale gas opportunities in the US our sense is that a lot of bad opportunity has been captured and what we are trying to do is to look for opportunities to be earlier into the place where we can gain access without having to pay as higher premium to get in. When you look at shale gas the one thing that we really like about shale gas is that it's a relatively short cycle time, so once we can establish commerciality with a large land position behind that we can optimize and accelerate that growth depending on what our financial capability is. So I think huge opportunities on the shale gas side.

Kenneth Pounds - Nutmeg Securities

Right, I was going on with opportunities in shale gas and oil sands at being very capital intensive. Seems like with the cost of offshore drilling just soaring, that your company is maybe one of the few that’s expanding aggressively in offshore North Sea of the Gulf of Mexico etcetera. As the cost, continue to go up, might there be some re-evaluation of some of that spending in the future?

Charlie Fisher

Well, in the North Sea we haven’t seen rates quiet as high on drilling as we have in the Gulf and what we are seeing is good economics so we’ll have facilities on the east side at Scotts and on the West side of where our holding with our Buzzard and we’ve got tie back opportunities and they are good bread and butter things for us to do, and we are looking beyond that. In the US we’ve got two floaters under contract first comes next year middle to next year and because we were looking to support a new build our rates on that rig I think is $335,000 a day where a few were in the competitive markets today probably more like 500,000. The second one is more than the 335 I don’t remember exactly it was around 400,000 but still a lot less than what some of the rigs are today. The first one we have alternating six months slots for a three year period and we have options to extend on the second one that comes in 2010 we have it for two years. So we have limited some of the pressure that will face to be able to conduct our programs.

Kenneth Pounds - Nutmeg Securities

Finally there is a lot of talk about expanded pipeline capacity to the US yesterday DeLauro announced they wanted to participate in one to get to the Gulf of Mexico in Conen’s project. Are you concerned all about having enough pipeline capacity for your oil sands projects?

Charlie Fisher

Well we work pretty closely with pipeline carriers to try and balance that. I would say that the industry generally is paying very close attention to make sure that there will be enough takeaway capacity matching up to how the build and supply is anticipated. There are also pipelines looking to be build through the West Coast that would expand markets. We think that’s a good idea. So we’ll be supporting projects that we think are going to be necessary to move that production. But right now, it looks like generally there is going to be enough takeaway capacity when you look at the various projects that people are looking.

Kenneth Pounds - Nutmeg Securities

Great. Thank you.

Operator

Thank you. The next question is from Amir Arif from FBR Capital Markets. Please go ahead.

Amir Arif - FBR Capital Markets

Good morning guys, just a quick follow-up. On Long Lake, can you give us any color and insight on what the capital costs are looking like for Phase 2?

Charlie Fisher

We haven’t run all of that analysis at this point because to finalize the estimates, we would physically go, and on the major equipment and things and get bids so that we are sure where those are. We know that some of the equipment costs are going to be higher, some of the material costs are going to be higher because we’ve seen escalation in commodity prices not just energy but steel and other things that we use. So we know some of that equipment cost is going to go up.

On the other side, where we suffered our biggest challenges was on field productivity. And we have done a lot of work over the last 18 months to improve that field productivity and we think that there are things that we can do that would substantially improve that. And by implementing some of those changes on the bottleneck project that’s going on now, we are actually seeing significant improvements in that field productivity. So I don’t know how that’s going to shake out. What we’ve done I think in our road shows and would be on our rev as we got a chart in there that shows the cost per daily flowing barrel against what commodity price. And we’ve got a couple of lines there; one of them has had a 10% discount, what commodity price would you need to get a 10% rate of return.

When we go through that, and I don’t have chart in front of me but I know because I have looked. Phase 1 is about 100,000 for daily flowing barrels. So I don’t know exactly what Phase 2 is going to be. Probably somewhere between $120 and may be as high as $160. I think $160 is probably top side. But at $160 per daily flowing barrels we need low 70s, WTI to get a 10% rate of return. So I don’t think that the capital cost given the high commodity prices are going to be the constraining issue, it's going to be the only one, probably the other issues as we go forward.

Amir Arif - FBR Capital Markets

Okay. And if you have to capture the CO2, can you give us a rough estimate of what incremental capital costs or operating costs would be involved with that?

Charlie Fisher

Our plan is, as we go forward to take and replicate Phase 1 when we built Phase 2, so using the same technology. But at Phase 3, we would go to a full shift reactor where we would be able to capture CO2 for the Phases 1, 2 and 3. And the cost of integrating that into Phase 3, if you check out the inflation, would be somewhere to the cost for Phase 3 would be similar to cost of Phase 2 or Phase 1. So the technology works for us when we get to credit critical mass and we go to a full shift reactor. We think there is some logic to doing that because they need to get some infrastructure in place so that from the region so that we can move the CO2 to a place where we can suppress rates.

So, the capital costs don’t look out of line in terms what we are doing right now. And then you have to adjust for inflation for the time delays through the phases, so we feel like we are in pretty good shape actually. When we look at CO2 costs and capture, we also think under the Canadian regulatory framework they provide for projects that are capture-ready, because we are using gasification technology and gasification technology allows you to capture CO2 pre-combustion and will be important not only in oil sands development but also power, when you are looking at power plants, clean coal plants, those sorts of things. We think there’s a good change that we’ll be treated as being capture-ready because of the development of this technology and that will minimize our cost through the development period to the point where we get to stage 3 and we’re capturing. So, we think we are in very good shape here but we need to get some clarity from the governments that we are interpreting that framework in the same way that they are.

Amir Arif - FBR Capital Markets

 

Okay, thanks.

Operator

Thank you. (Operator Instructions).The next question is from Brian Dutton from Credit Suisse. Please go ahead.

Brian Dutton - Credit Suisse

Yes, Marvin just for, or Charlie just for a follow-up. In terms of looking at the reconciliation between production and sales, I can see there that you split the Long Lake bitumen production separately. Where in fact do you report the revenue for that in the quarter and what’s the disclosure going to be on a go-forward basis? Will Long Lake be a separate business unit in terms of financial disclosure?

Marvin Romanow

Yes, I’ll answer the second question first. Yes, in Long Lake we are fighting to disclose it as a separate segment and all pre-operating costs and pre-commercial revenues are capitalized. So neither the revenues nor the costs show up anywhere on our revenue or cost statement today. They all get capitalized until the project becomes commercial when the upgrader starts up. Where we are from an economic basis? Today is roughly around, somewhere around 10,000, 12,000 barrels a day of bitumen at current bitumen prices, we’re breaking even, just selling our bitumen. So, clearly, once our volumes ramp up above that, we’ll be starting to produce positive cash just on bitumen sales alone and then when we upgrade starts up, we’ll be selling premium synthetic crude at that point at higher prices for the bitumen.

Brian Dutton - Credit Suisse

Okay and just a follow-up to that. When you go to that commercialization, declared commercialization, is that the time when you stop capitalizing much of that interest as well?

Marvin Romanow

That’s right.

Brian Dutton - Credit Suisse

Okay. Thank you very much.

Operator

Thank you. The next question is from Kam Sandhar from Peters and Co. Please go ahead.

Kam Sandhar - Peters and Co.

Hi, just a quick question on operating costs. Looks like cost increased about 25% quarter-over-quarter and it’s across most of the business lines, can you talk about specific operational things that might have happened or some more color on if we expect those cost come back down?

Marvin Romanow

Yeah Don I think that is a good observation. The biggest factor contributing to that was actually Syncrude. Syncrude was up $10 a barrel and the way it makes it into the mix makes it high and so Syncrude had lower volumes in the quarter because of the coker turnaround, and they had higher cost because of thanks for the turnaround expense as well. Their second biggest area would have been in the North Sea and there we had lower volumes because of Grangemouth being down and Frigg pipeline being down for a period of time and we had slightly higher transportation tariffs, because our transportation tariffs in Buzzard are related to the price and those get embedded into our operating cost. Other pieces would have been smaller but contributed as well and those include OpEx on a per barrel going up in Masila and Block 51 this is just thus both of those areas are on decline so it is some degrees their unit cost creep up a bit quarter-over-quarter.

Kam Sandhar - Peters and Co.

Okay thank you.

Operator

Thank you. The next question is from [Michael Young with Chatham Bay Advisors]. Please go ahead.

Michael Young - Chatham Bay Advisors

Hi guys good morning everyone. My question here turns to the Horn River in the Dilly Creek acreage and specifically what kind of thought have you given if any to possibly trying to monetize that asset upfront at least the portion there off as some of the competitors have both in Canada and in the US recently.

Charlie Fisher

Well when we look at the relative value of the asset as it moves to commerciality to monetize it up front. I don’t think you get paid nearly what it's worth, when we look around the world the toughest thing that we have to do is to capture new resource. So when you actually have a big resource the last thing you want to do is give it away cheaply. So and just our own experience when we acquired the land at Dilly Creek we were paying about $1500 a hectare as the last sale landed immediately adjacent to what we held went at close to $8600 a hectare. And that just shows you in two years about rapid ramp up. So we think there’s a lot more value to be had to invest some capital and prove commerciality and get some production into things if you sell it too early I think you give away a lot of value and I guess if you look at our experience in buying Buzzard we bought the North Sea assets and Buzzard when it was in development and it's been the best assets that we’ve had in a long time and we’ve created a huge amount of value by picking it up early and then developing it. So I don’t think I’d be in a rush to monetize part of the asset quickly.

Marvin Romanow

You know if you look at what our land acquisition costs are relative to the contingent resource we’ve disclosed of $0.5 billion to a $1 billion boes. Our land acquisition costs are $0.10 to $0.20 at boe. So when you look at the kind of upside this represents that is the success that we’ve had and the success the other operators have had in the area, the well known technologies, that you would apply. If those kind of things, that we’d actually like more of not lesser.

Michael Young - Chatham Bay Advisors

Fair enough and as a follow on to that then, how many potential wells, would we have to drill to fully develop the contingent resource that you identified?

Charlie Fischer

I think if you look at developing all of the lands and probably you’d be looking at something like a thousand wells.

Michael Young - Chatham Bay Advisors

That’s great. Thanks very much.

Operator

Thank you. There are no further questions registered at this time. I’d like to turn the meeting back over to Mr. Romanow.

Marvin Romanow

Well thanks very much for all the questions, this morning. I am delighted we had so many people on the call. Thank you, very much. Have a great day.

Operator

Thank you. The conference has now ended. Please disconnect your lines at time. We thank you for your participation.

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