Nexen CEO Discusses Q3 2010 Results - Earnings Call Transcript

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Nexen, Inc (NXY) Q3 2010 Earnings Call October 28, 2010 9:00 AM ET


Kevin Reinhart - EVP & CFO

Marvin Romanow - President & CEO


Andrew Potter - CIBC World Markets

Greg Pardy – RBC Capital Markets

Bob Morris - Citigroup/Smith Barney

Mark Polak - Scotia Capital

Arjun Murti – Goldman Sachs

George Tunula – UBS

Brian Dutton– Credit Suisse

Brandon Biago – Treaty Oak

Menno Hulshof – TD Securities

Chip Rewey – CRM


Good morning, ladies and gentlemen. Welcome to the Nexen Third Quarter 2010 Conference Call.

I would now like to turn the meeting over to Mr. Kevin Reinhart, Executive Vice President and Chief Financial Officer. Please go ahead, Mr. Reinhart.

Kevin Reinhart

Good morning and thanks for joining us today. With me today is Marvin Romanow, President and CEO, and Gary Nieuwenburg, Executive Vice President of Canadian Operations.

Before I get started, just to caution that certain statements that I make this morning are forward-looking statements. I refer you to our press release of today for more information regarding those statements. And also refer you to our 10-K and 10-Q for a description of the risk factors.

Following my comments this morning, there will be some time for questions.

We continue to make significant progress across all of our areas in our

portfolio. My plan this morning is to go over the highlights of this progress, and then I'll touch on our production volumes and the significant production adds we have coming over the next 24 months.

Let me start with Long Lake. The bitumen production volumes continued to rise following the turnaround that we undertook last fall. We're pleased with how quickly we got back on the ramp-up curve once we completed the changes to the water softening system last year.

Following the steady ramp up that we've had throughout this year, our pace temporarily slowed during August and September as we took down some of our best-producing wells for ESP upsizes, and to complete asset jobs on other ones. In addition, the steam generation was temporarily interrupted by upgrader shutdowns and power outages.

Now that these are behind us, we're producing record levels of steam and in response,

bitumen production is over 31,500 barrels per day; and that's gross. This is double the levels of the start of the year.

In addition, the number of wells producing at average design rates has increased from ten at the beginning of the year to 24 today. In light of the lost time from the recent disruptions, our ramp-up progress has been delayed by a few months.

As we've described before, we continue to pursue inexpensive ways to add bitumen. These initiatives include bringing on the remaining 13 wells to SAGD production, optimizing all producing wells, developing two additional well pads, and adding two more once-through steam generators that can use the available water treating capacity that we have there.

These actions require little incremental capital and the economics are quite compelling.

Operating costs here continue to trend as we expect, and we're on track to be in the $25- to-$30 range per barrel once we are at full capacity.

As production volumes grow and yields improve we are approaching cash flow break even and we expect Long Lake to generate positive cash flow here shortly.

Oil sands is a key part of our future and we are moving forward to capture the value of the billions of barrels of bitumen resource that we own.

Earlier this year we described our plans to sequence the development of Phase 2 differently than Phase 1.

We'll start with smaller SAGD stages of about 40,000 barrels per day each. And then we'll follow with upgrading at some time after we get those SAGD projects ramped up.

This approach has many benefits; it simplifies the SAGD ramp-up process, there's less stress on material, equipment and labor markets during the construction, it improves our capital efficiency since 2/3s of the capital is in the upgrader. And it provides flexibility on when to move to upgrading based on the economic conditions.

The front-end engineering work is advancing on Phase 2 as we speak.

Turning to shale gas, we're making great progress on our Horn River acreage. We're executing very well, and costs continue to drop.

This past winter, we successfully drilled an eight-well pad. Compared to our previous program, these wells were drilled in 35% fewer days and they were almost twice as long.

We recently completed fracing these wells, and we did this at an industry-leading pace of 3 1/2 fracs per day with 100% frac success rate.

We're currently production testing these wells and expect to reach peak rates of 50 million cubic feet a day this winter. We plan to follow up this successful progress with a nine-well pad that would start drilling this winter. The wells would be fraced and completed next summer with

first production in the fourth quarter of 2011.

This program allows us to advance our Horn River play while we progress our plans for an 18-well pad to be drilled next winter with first production to follow in late 2012.

Compared to other North American shale gas plays, Horn River is top quartile. It has a long land-tenure system with no need to drill and produce to hold the land. It has low royalties and excellent resource density and fracability. So we expect to be able to earn a 10% rate of return with gas prices at above $4 per MCF.

Given the success we've been having in this area, we more than doubled our acreage position in North East British Columbia earlier in the summer, and we are now one of the top acreage holders in the area.

We estimate that the 90,000 acres we have in the Horn River Basin contain three to six TCF of recoverable contingent resource.

With a total acreage position, that is now more than three times that size, the resource potential of our shale gas lands is even more significant now.

Given the progress that we're making here, and the additional land we have acquired at Cordova and Liard, we are in the process of updating our total resource estimates and expect to disclose them in the next month or so.

Turning to the conventional side, we're also having excellent success here with the drill bit. Now, some of our recent drilling highlights include a number of successes in the North Sea that can be quickly tied back to existing infrastructure. We have the Golden Eagle Hobby discoveries in the

North Sea. We have the Appomattox and Knotty Head discoveries in the Gulf of Mexico, and the Owowo discovery offshore West Africa. And we're well positioned for even more success with an active drilling program and numerous exciting prospects over the next little while.

Now, in the Gulf of Mexico, we're quite pleased that the drilling moratorium has been lifted. This moratorium did not impact on our production at all. Rig’s standby costs for the two deepwater rigs that we have under contract are expected to be minimal.

The first rig may remain with the co-contractor for the time being, or we may use it to start drilling the upper part of the holes on our prospects until we get permits to enter the hydrocarbon zones. As a result, we face very little financial exposure for non-productive drilling time.

On the second rig, we are close to completing discussions with a rig provider regarding our contract. And we're also pursuing opportunities to sublet this rig for the first drilling slot.


We have submitted drilling permit applications for our exciting Kakuna and Angel Fire prospects, and we are responding to changes made to the rules and regulations so we are ready to drill when the permits are in hand. We expect to be drilling here as early as yearend, and no later than the second quarter of next year.

We continue to be confident that the deepwater Gulf is an attractive hydrocarbon basin, and that we have the right standards of behavior and financial capacity to pursue the strong value proposition this area offers.

At Appomattox, we announced a few weeks ago that our discovery there was over 250 million-barrels gross with significant upside potential.

We believe this has the potential to be our best discovery ever in the Gulf, and we plan to start delineating this discovery with appraisal drilling and to conduct further exploration drilling in the area. We are well positioned to start this program once the permits are received.

At Knotty Head, a Letter of Intent has been signed by the Knotty Head partners and by Hess to commence with the data exchange on the Knotty Head and Pony discoveries, and to work toward a joint development plan. We expect to have an integrated project team in place in six to nine

months to start working on that joint development plan.

In the North Sea we're on track to sanction Golden Eagle Hobby next year. We're currently reviewing the development plans with our partners, and first oil is expected in 2014.

At Buzzard we have a number of opportunities to add to our reserves here. The northern panel contains more recoverable oil. We're awaiting the results of the Polecat well which is a potential tie back to the Buzzard platform. And we plan to drill Bluebell later this year to extend the field to the South. We've also made very good progress on the hookup and commissioning of the fourth platform at Buzzard. Start-up activities have been accelerated to take advantage of cost efficiencies.

As a result, fourth quarter production volumes at Buzzard are expected to be 70% to 90% of normal. Production is expected to return to full rates around year end.

Our Ettrick field is performing very well, and Scott/Telford is back on line following the unplanned shut in of production here for eight weeks to allow the Forties pipeline operator to repair a valve failure.

Our North Sea Exploration and Appraisal Programs to take advantage of our existing infrastructure are working very well. We drilled the Rochelle and West Rochelle prospects, and these are tiebacks to the Scott platform. Blackbird discovery is a tieback to the Ettrick FPSO. Polecat is a potential tieback to the Buzzard platform. And we have additional Telford development opportunities that will also be quickly tied into the Scott Platform.

We expect these to add at least 10,000 barrels a day of new production over the next 18 to 24 months. Now to support the success we are having with the drill bit in the North Sea, we are growing our acreage position here.

Earlier this week the UK government announced that we were the successful applicant for ten licenses covering 18 blocks in the recent North Sea offshore licensing round. Most of these blocks are near our existing acreage and infrastructure and will enhance our ongoing exploration program where we're having a great deal of success.

Offshore West Africa, our Usan Project, is on track to start up in 2012. This will add 36,000 BOE per day net to us once it's fully ramped up. And at peak rates and at a $70 WTI price, we expect to generate about $750 million of annual pretax cash flow. Once on stream, this will represent a significant swing in our financing needs as our capital investment today turns into a significant cash inflow soon.

In West Africa, we've also announced successful exploration at Owowo. We're working on plans for additional exploration drilling to support both extending the plateau at the Usan Platform and potential standalone developments elsewhere.

On the disposition front, we've completed the sales of our western Canadian heavy oil properties and our North American natural gas business during the quarter. We're very pleased with the value generated through these asset sales. The dispositions generated proceeds of over $1 billion, allowing us to reduce our net debt by a similar amount.

It's worth noting that even with the asset sales, our production volumes today are at similar levels to our annual volumes last year. We are now targeting proceeds from the disposition of our non-core assets at approximately $1.5 billion with our investment in Canexus to be sold over the next 12 months. The proceeds will be used to develop exciting successes being generated

throughout our portfolio.

We're in great shape to close out the year and are on track to be well within our annual production guidance range of 230,000 to 280,000 BOE per day. The low end of this range, as you'll recall, assumed that downtime for an accelerated startup of the Buzzard platform, that Telford TAC would be deferred until 2011, and that the Long Lake production would be at the low end of our estimates.

Now, each of those temporary events have actually occurred, and in addition our guidance did not contemplate the sale of 15,000 BOE per day of heavy oil assets, or the eight-week shutdown of the Scott Platform for the valve failure on the Forties pipeline.

So despite all of these events occurring, our annual production volumes are still expected to be well within our original guidance range of that 230,000 to 280,000.

This reflects strong contributions from Yemen, the Gulf of Mexico, and the ramp up of Ettrick. We are currently producing in the 245,000 to 255,000 BOE per day range, even though Syncrude is not yet at full rates and we no longer have 15,000 BOE per day of heavy oil volumes.

This is the same level of production we generated last year before we sold the heavy oil properties.

As mentioned earlier, we'll come off these levels a little bit in the fourth quarter as we start up the new platform at Buzzard. Over the course of the next 24 months, we are well positioned to add about 70,000 BOE per day of new volumes as we continue to ramp up production at Long Lake, and at Horn River, and we start up the Usan Platform in West Africa.

We'll also see near-term production upside from the tie ins from the recent drilling success that I reviewed in our U.K. area, and the possible contract extension in Yemen, which we are currently actively working on.

Beyond this, we have possible upside at the Buzzard, extending production plateau there from the things that I described earlier. We have continued development of our shale gas properties.

and we have new production adds coming from major discoveries to be developed at Golden Eagle, Appomattox, Knotty Head and Owowo, as well as future phases of oil sands.

So with current and future production over 85% weighted to crude oil, we are well positioned to take advantage of strong oil prices relative to gas. We generate the highest cash netbacks in this business, and our investments are generating superior returns.

We are executing well, and the momentum is building in all areas of our portfolio.

So, I'll now turn the call back to the operator and we'll open it up to questions. As always, I ask you to once again focus your questions on the business activities and strategies. Feel free to call our investor relations group and they'll be happy to answer any detailed modeling questions you

might have.

So with that, I'll turn it back to the operator.

Question-and-Answer Session


Thank you, Mr. Reinhart. (Operator Instructions). Our first question is from Andrew Potter from CIBC. Please go ahead.

Andrew Potter – CIBC World Markets

Hi, guys. Just wondering if you could elaborate a little bit on the early results from the Horn River. Maybe if you could talk about rates or relative to what kind of rates competitors are showing in the area. And also wondering if there are any other thoughts on the Bakken and Exshaw that I believe it started last quarter.

Marvin Romanow

Sure. This is Marvin here. We've only had our wells on stream for less than a week so it would be early to quote rates. We typically quote average for the first 30 days. That's becoming now closer to an industry standard, although there's still a wide variety of those. What I will say about the program though is that we had 100% success placing sand, and we had 100% success in terms of the kind of frac rates that we expected. So that really does bode well. The first two wells that were on stream are flowing at stronger rates than our previous wells, but with a week I think it's just a little too early.

We're getting very good water returns, so that's another good sign. You want to get all your frac water back. And so I think that in the next month or so we'll be able to provide a bit more clarity on that, but I would say we have encouraging signs.

On the Bakken, we're still looking at the evaluation of some of the core data that we've acquired and we'll look to see what that implies for us going forward.

Andrew Potter – CIBC World Markets

Okay, perfect. And then one other question. Just a follow up on the Gulf of Mexico, I believe that last quarter you said you were evaluating monetizing some of the exploration prospects. Maybe if you could update us on where that process is.

Marvin Romanow

Sure. Maybe a more general observation there is, you know, we are seeing now well licenses starting to be granted. We've seen I think at least two to be granted, those are for drilling injectors. We expect producers to be forthcoming shortly. I think it's pretty tough to exactly predict the timing, but kind of our P50 estimate is that we should be drilling our prospects some place in the first quarter. The earliest we would expect to be drilling on either an Appomattox appraisal or some of our exploration projects would be yearend, and the latest would be some time in the second quarter.

In terms of industry interest, by and large everything we found was that during the moratorium people were quite cautious on trying to understand what the new rule set was going to be, to understand what the potential impacts would be before they move forward. So there was a lot of strong signals we got on the technical evaluation of our prospects, but people wanted the rule changes to be more clear before they would move forward.

Since some of those rule changes have been made clear, we've had specific proposals on our portfolio and we're in the process of just putting together the groups. But we're starting to see the kinds of terms that are approaching the kind of terms we saw pre-Macondo in terms of interest and levels of commitment and carry the companies are willing to commit to.

Andrew Potter – CIBC World Markets

Okay. And as far as the process goes, is it likely – maybe it's premature to talk about it, but is it more likely this gets done as one big package for all the prospects or a bunch of smaller one-off deals?

Marvin Romanow

I think that we're fairly flexible in how to approach that. And I think people are still evaluating exactly what their strategies are going to be a bit tactically in the Gulf of Mexico.

What I do see very consistently though, is a strong focus and a strong recognition of the hydrocarbon potential of that basis. And we see that from both the regulatory side and the commercial side.

It's like I think every investment strategy, people do not like to make investments where there still is some uncertainty remaining, and especially where that uncertainty is going to be clarified, I believe. in the next few months.

So the environment here is, I believe, going to undertake a fairly major shift once we start seeing people drilling and licenses being issued. And from everything we see on the regulatory front, they're moving forward to cause that to happen. So I think with respect to your specific

question on exactly what form this is going to take, that's something in evolution and what I do like is that we have created several styles of options and we're getting interest in all of those so we'll look to what serves the portfolio best.

Andrew Potter – CIBC World Markets

Perfect. Thanks a lot.


Thank you. Our next question is from Greg Pardy from RBC Capital Markets. Please go ahead.

Greg Pardy – RBC Capital Markets

Hi. Good morning. I'm going to ask just a couple of strategic questions. Colombia has been an area, Marv, that's been in the portfolio for a long time. You got in there relatively early, but obviously we've seen declines generally. Does it still fit with the portfolio? What do you do with Colombia longer term?

And then second question is just in terms of contract extensions in Yemen, we're currently showing that production is coming to an end in 2011. If you had to put a probability of success that you'll remain in Yemen post ’11 what might that be? Thanks very


Marvin Romanow

Sure. So let me address the Columbia question first. The discovery we have at Boqueron is one of our highest-rated return assets in the company when you look at capital deployed and margins that we generate and full cycle returns.

We also have close to a million acres of shale gas potential there. We're going to be drilling four to eight core holes and grinding up the rocks to see what kind of potential that represents. It's acreage that's close to Bogota so it represents a ready gas market. I was in the country in May, and we had a great deal of interest from folks on that shale gas acreage. We hold it 100% and we would look to see if it has any potential before we would look to potentially taking on a partner to extract some value out of that.

So that's, I would consider, in the class of an exploration opportunity. We've been in the country for 15 years. We understand the landscape well, both from a regulatory, political and a security side. So I think that our capacities in the country can increase and we're looking at the way to do that. Historically we've been explorers of these high-risk thrusted plays and I think that we'll be looking to migrate from that to other kinds of opportunities in Colombia.

So although it's small, it still represents a strong strategic footprint for us, and again, it is a high rate of return business.

In Yemen, I met with the President of the Country twice in the last quarter. We've had good discussions on what Nexen has brought to the country; our strong operating capacities there. And it's clear that that's well recognized across the entire spectrum of industry participants in the

countries, competitors, the regulator there, and government folks as well. So there's a strong desire to have our presence continue there.

The discussions are getting more detailed and they're getting more thorough in terms of the details of our extension, but I would also say that, you know, I can't really provide any sort of complete and 100% guarantees, but we wouldn't be having, I believe, these consistent and detailed discussions if we both weren't working towards having Nexen and its partners continue to be in the country.

Greg Pardy – RBC Capital Markets

Okay. Thanks for that, Marvin. And maybe just a last one for me, obviously a difficult quarter at Long Lake but you're ramping back up now. How comfortable do you feel about hitting the lower end of your exit of 40,000 to 60,000 this year?

Marvin Romanow

Well, let me provide a bit of perspective on some of the things that have happened at Long Lake this year.

So things like having the reservoir respond to consistent steam, you know, between January and October we went from having ten wells that were operating at our average production rate, to expectations to 24 wells. Steam has to lead that, so we've moved from having 11 wells at the beginning of the year operate at our target steam rates, to having 48 operating at our target steam rates today.

And consistent with that number of well pairs where the SORs are coming down to average with in our target rate has gone from 25 to 40 wells. So what we're seeing through that whole piece is that when we provide consistent steam the reservoir is responding. I mean, we have a handful of

wells here that are producing over 1,500 barrels a day each and those wells are still growing. This is a thick reservoir so the steam chambers continue to grow. So we've seen some positive signals.

We had some upgrader interruptions in August and into September, and those affected our average rates for the third quarter. And I think what those highlighted to us is, if you look at our ramp-up profile in quarter one – or sorry quarter one, quarter two, and where we were in quarter three is really how crucial it is to have consistent steam, and consistent steam means consistent on a daily basis. It doesn't mean consistent on a monthly basis.

So one of the things that we've identified that is important for the long-term success of this project is to provide more isolation between the SAGD and the upgrader. And this is while keeping all of the benefits of integration.

So for example, we do not have enough inlet capacity to fire the burners on 100% natural gas. That's not a complicated fix. Natural gas prices are low. That's an important piece of flexibility we're looking at and adding.

We also because of the amount of break-up storage that we have, and the amount of – and the way we inlet treat, it's not very easy for us to switch quickly from producing a pure stream of PSC to producing a diluted bitumen. Those two pieces of flexibility will offer us much more capacity to have these upgrader bumps. And some of them are only a matter of days, some of them take a bit longer to ensure that we continue to ramp up and be on that steady profile that we've seen from our wells.

And if you look at the data that we show on our website, you know, we show how each individual well is performing. And that kind of granularity, I think, is not found in others' disclosures, but what it really represents is the confidence we have in the reservoir. So we're looking at this important idea of isolating the SAGD from the upgrader. And our back-of-the-envelope estimate that this is going to be a project that's going to be under $100 million.

So in terms of the importance of this, I think that we've – we continue to make progress on having more upgrader reliability. But I still have to say well, I look at every plant in the area. They do go down from time to time and you want to provide the isolation in your components so you can still make economic progress.

Greg Pardy – RBC Capital Markets

Okay. So I mean, generally comfortable or not comfortable with exit rates?

Marvin Romanow

Well, I think it really depends on how things go over the next two months. And I think we have to also share that we aren't focused on hitting a particular number at a particular date. We gave a target range, if we didn't have the upgrader bumps this summer we would have been well within

that range. I think that that's, you know, with the bumps we took that summer, that's going to make that target a bit more challenging. But more importantly, I think when we see how our wells are responding when we provide them the constant steam and, you know, look at the evidence for that, we'll get back on the right ramp-up curve as we can offer that steady steam.

Greg Pardy – RBC Capital Markets

Okay. And the last one for me, so that additional $100 million of capital is going to go into 2011 predominantly?

Marvin Romanow

I think we want to still look at exactly what's going to be required there. So some of it might be 2011, some of it might spill into 2012.

Greg Pardy – RBC Capital Markets

Okay. Thanks very much.


Thank you. Our next question from Mark Polak from Scotia Capital. Please go ahead.

Mark Polak – Scotia Capital

A couple questions on Horn River and Long Lake. At Horn River have you sort of settled in on 18 fracs per well being the right configuration, or would you sort of wait and see how these eight wells do and maybe experiment with something different on next year's nine wells? And I’m just curious if you could give some color on the cost structure you were seeing on this year's program there.

Marvin Romanow

Yes. Our expectation is that this next nine-well pad, and really what it is, it's a half of an 18-well pad, is going to cost us $115 million for the nine wells. So I think the economics of that are very strong. We've seen very good execution on our drilling side and on our frac side as well. We're planning to use the same rigs that we've used before with the same crews, with the same or similar service companies. So that continuous execution capacity is forming quite nicely and I’m sorry, I forgot your first question was again?

Mark Polak – Scotia Capital

Just if you were going to continue with like under that program next year for $115 million, is that 18 fracs per well or would you look at sort of playing with different –

Marvin Romanow

Right. What we've had is we've had just excellent success with putting in these 18 wells per frac. Although it's very early, we're seeing some positive signals on what that means for rates. We've drilled some of the horizontals into the Evie and some into the Muskwa. We have some particular strategies with respect to evaluating each of those two. So the first thing we're going to do is see how these production rates hold in and see what that implies for any of the components of well design.

I don't believe we've completely finished the learning curve in terms of the way we perforate these wells. I think our frac design is industry leading because of the success rates that we have. But I believe there's still room to optimize it. I'm not sure that longer wells are the only trick in

the book here that we'll be looking at. There are still a few other areas where we're looking at improvement. Our current well design is to continue with 1,800-meter laterals and I think the most number of fracs we did on one of our horizontals was 20 or 21.

Mark Polak – Scotia Capital

Okay. Thank you. And then on Long Lake, just curious, the 24 wells that are producing at design rates, I just wonder if you could talk about what sort of steam-oil ratio you're seeing on those wells. And in terms of you mentioned cash flow breakeven shortly, what’s – at current prices, what sort of production number do you believe you need to get to that level?

Marvin Romanow

So the first question on the big wells and their target steam oil rate; so we have 24 wells that are producing at or better on their average production design rate. But 41 wells are at their target or better SOR rate. So I don't have it exactly in front of me, but my guess is that those 41 wells are at 3.3 average. So the 24 wells would be in the mid-to-high twos is my guess, but I don't have that in front of me.

The breakeven, we're getting very, very close at kind of 30,000 to 35,000 barrels a day and current prices, and keeping the upgrader running. We're getting into the zone, so assuming that the third quarter or the fourth quarter will be on that ramp-up curve without any interruption, I think our probabilities are very high of producing positive cash at current prices.

Mark Polak – Scotia Capital

Great. Thank you very much.


Thank you. Our next question is from Arjun Murti from Goldman Sachs. Please go ahead.

Arjun Murti – Goldman Sachs

Thank you. Just a follow up question on Long Lake. I think in your prepared remarks you mentioned sanctioning future phases, they might be smaller than this initial phase. I'm just curious in terms of the timing of that. Do you feel you need to see the phase one get to your plateau rates or kind of be running at a good rate for some period of time, or do you think you've just learned enough lessons, and I know these are complicated projects, but you've learned enough from the first phase that you'd be comfortable moving forward even if phase one didn't quite get to your expected plateau rates? Thank you.

Marvin Romanow

Yes. I think the answer to the question is a little bit of both. We've spent much more time delineating and evaluating some of the other geological areas, and we have a very high-quality reservoir to develop in [inaudible] and in future phases. So that represents a good opportunity.

When we took on the task of ramping up 91 well pairs and an upgrader that was highly integrated, that proved to be a large task. And although we're knocking off each of the issues we face issue, by issue, by issue, I think when I look at what more – perhaps a more rational way to do this from just a pure operational perspective, I think we would have – the better approach is to do the two 40s followed by the upgrader. That's consistent with the economics. It's also consistent with recognizing that these projects take a little bit of time to ramp up.

So to have an upgrader, which in our case represents – in all cases represents about two-thirds of your capital, to have it being partially full as you ramp up is not delivering high economic efficiency.

So you do your ramp up first and then you start up your upgrader, allowing you to phase the capital.

I'll go back to my earlier comments on the importance of having some isolation between the upgrader and the SAGD. So when you look at doing two 40s in an upgrader that happens naturally. You're going to need 100% capacity to fire with these with natural gas until you get your syngas going from an upgrader so it kind of all fits together with what we're doing with phase one and the kind of thinking for phase two.

Arjun Murti – Goldman Sachs

Marvin, thank you. In terms of the first part of your answer there, you mentioned you have done some test wells to examine the geology of the next areas. Is it your sense it's "better" geology than this first area, or am I over focusing on that statement and it's really the upgrader and not building it initially, that will be the delta?

Marvin Romanow

You know, we have areas that represent better geology on future phases. We also have some areas of very good geology on phase one. I think that going back to my earlier comments, when you have a handful of wells that are producing 1,500 barrels a day per well pair or better, the reservoir quality has got to be excellent in those regions to do it.

So what we've primarily done is continued to ramp up the density of our core holes so we understand the bits and pieces of the reservoir better. And what that does, it allows you for making just very good and selective decisions on where to place your horizontal well pairs. The comments I've made I think on the upgrader and the importance of having some degree of independence while you keep the benefits of integration from the SAGD, I think those are components that we're moving forward on phase one and would look to keep those on phase two as well.

Arjun Murti – Goldman Sachs

Thank you. And then just on Knotty Head, I think you mentioned you have a letter of understanding with the Pony Partners and that team would be in place in six to nine months, which kind of gets us to mid-‘11 or thereabouts. Could that actually be sanctioned by the end of ‘11 or is that too optimistic of a time frame and we should think of 2012 as to when some Knotty Head/Pony development could be sanctioned?

Marvin Romanow

You know, I think there are a couple of things in the background there. It was tough to make progress to do a lot in the Gulf of Mexico when there was so much rule uncertainty and so much focus and intensity on BP's blowout and the cleanup that followed afterwards.

I think by 2011, we're going to be moving for that basin to be much more into a routine normal set of activities. I think countries around the world, and UK we're particularly familiar with, have looked at all of their rules and it's clear that all of the decisions they're making are to continue to develop accumulations in both the shelf areas in the UK but also in the deep water. They have not taken a drilling break whatsoever. So I think those are very good indicators for the environment to be returning to a more normal commercial environment in the U.S. And as a result, I think we have a very good chance of making some excellent progress as all the partners are motivated to move that project forward. We have the equipment to drill appraisal wells. We have the knowledge with all the partners on the reservoir to make that dialogue and move forward. So I think that 2011 is a realistic time frame for that project.

Arjun Murti – Goldman Sachs

That's great. Thank you very much.


Thank you. (Operator Instructions) Our next question is from George Toriola from UBS. Please go ahead.

George Toriola – UBS

Thanks. So a couple of questions here. The first is just trying to get a better understanding of the 70,000 barrels a day of production adds you talk about in the next two years. So I just want to be sure that math I'm doing here is the right one. So if we back out Usan, and back out the 50 million a day that you would be producing from Horn River, is the balance there expected from Long Lake?

Marvin Romanow

So there are quite a few bits and pieces that go into that. So you identified accurately the first big piece of 36,000 barrels a day net coming out of West Africa. The next thing to look at, if you look at the plans we have in the shale gas areas, each eight or nine-well pad is adding 50 million to 60 million cubic feet a day. So round numbers that's 10,000 BOEs a day. So this year towards the end of this year we're adding that. Our next nine-well pad, we'll add that towards the end of 2011. And the 18-well pad that we plan to drill in the summer will double that. So that would be about a 20,000 BOE day number late in 2012.

And shale gases have some declines associated with them, especially in the early days. So those would be kind of the start-up rates you would be looking at. We've got three tieback projects to pursue in the UK. This is at Blackbird, Rochelle, and an enhancement of our injection and production capability where we discovered a large accumulation at TAB and TAC. And all of that capital which includes piping, and sub C equipment and tieback would be completed in that time frame. That's going to add another 10,000 to 20,000 barrels a day. And the last piece will be to continue to ramp up Long Lake to its design capacity of 72,000 barrels a day of inlet bitumen.

George Toriola – UBS

Okay, thanks. So essentially, that math then suggests that over the next two years the ramp up of Long Lake would – the range would be somewhere in the 10,000 to 20,000-barrel a day range.

Marvin Romanow

Well, we have to replace some declines as well. So I think that I've given you the important big pieces . I think it would be a bit risky to treat those each as kind of 100% analytically pure. When you add all of those together, I think they should provide you a high degree of confidence that we can achieve that plus more.

George Toriola – UBS

Okay. Thanks. And then the second part of my question, the second question, is so 65 wells on ESP now, and you talk about 51 wells being in sort of the early stage, either in steam circulation or early stage of the growth cycle.

So could you just go through again the timing of when you – I mean, for the 65 wells that are on ESP, I would assume that those would be through sort of the early stage for you to make the decision to put them on ESPs. Or could you just walk through sort of timing of events there and how the 65 wells and 51 wells relate to each other?

Marvin Romanow

Basically our decision criteria on ESP versus gas lift have to do with what the optimal pressure is in our reservoir to lift fluids at, and that varies a bit across the reservoir.

We've also had so much success with some of our early ESP conversions in these big rate wells that I have referred to that we had to take some of them down this summer to upsize the ESPs. Because what you want to do, is you want to inject as much steam as possible at your desired pressure, but when you do that you have to also make sure you lift all of your fluids. That's when you get optimal steam-oil ratios and optimal performance.

So to answer your question, I think it's more done on a regional basis within our Long Lake lease, and it's almost done on a well by well basis. And what does set us back in terms of moving and making progress on that is when we have steam interruptions. So each period where we've had consistent steam we've progressed our entire well set through that chain of gas lift, put in an ESP, watched the well, how it responds, find your optimal operating pressure, make sure the well is pumped off, upsize the ESP, and moving forward.

In addition we still have Pad 11 that isn't completely on stream. There we had to add some surface facilities right at pad site. So we're only starting to ramp up that entire well pad. And we're at 170,000 barrels a day of steam injection, and we have the capacity to go to 230,000 to 240,000. So we're getting towards where that steam is continuing to show its results in the ramp up curve.

George Toriola – UBS

Okay. Thanks. And I think just a follow up; so on all the 65, are you pumping off the fluid levels in those wells? Or do you have – how are those doing right now?

Marvin Romanow

I don't have fluid pump-off charts in front of me on all of the wells. But what I would say is that each of those have a strategy to be managed on a well-by-well basis.

George Toriola – UBS

Okay. Thanks a lot.


Thank you. Our next question is from Brian Dutton from Credit Suisse. Please go ahead.

Brian Dutton– Credit Suisse

Yes. Good morning, Marvin. How do you view the operating performance of each of your business units? So what are you telling the troops internally? Do you think they're living up to your expectation? And if they are, do you think there is then a disconnect between your expectations and the market's?

Marvin Romanow

I think that's a good question, Brian. We have focused enormously in the last little while at continuing to move forward at executing very well in each of our basins. So let me walk through that basin by basin.

So in the North Sea when we bought that in 2004, I think our general strategy there was that we had a pretty good reservoir in Buzzard that would respond. We would take that free cash and invest it in other basins that were less mature.

As we had a clear view of what we actually were able to accomplish, we're finding a lot of oil there. We found it in Hobby/Golden Eagle, we found it in traps that folks didn't think were perhaps possible. And we've got another world-class UK development project there in Hobby/Golden Eagle.

And as I mentioned earlier we're finding these smaller accumulations in sub-sea tieback opportunities to our existing facilities. We've built our land base with the recent acquisition of Crownland that Kevin talked about. And we have an exploration portfolio there that's I think leading edge in terms of the North Sea. We're the only producer I could find that has a growing profile over the next few years.

And Buzzard continues to look better and better with each successive set of wells that we drill and produce. So I think there we're really executing at an excellent level.

I'll then go to our other conventional basins in West Africa. I think that's a world-class project. We drove the second successful accumulation there. We are looking to delineate and drill more exploration wells. That's a very oily block. Our call on that was excellent. Timing in Nigeria is less certain, so it's not probably the only thing you'd want to have in your portfolio, but in a portfolio like ours it fits very nicely.

I'll then go to the Gulf of Mexico where we've achieved what probably will become our best success ever in the Gulf of Mexico. Appomattox is a minimum 250 million barrels. There's three additional structures to drill, two adjacent and one close by. We need another appraisal well. So by and large we're thinking about four penetrations that are independent of one another to appraise that in both Shell and we are aligned on proceeding with that as soon as the drilling moratorium is off.

So again, when I look at the interest we've had on our [inaudible], acreage of the portfolio that we've put together in the Gulf of Mexico, we're getting good industry interest. I'd call it excellent in the context of the environment we're in. So again, I think we focused on executing well and we've delivered in there. Shale gas we gave you some specifics in the press release on costs per well in terms of frac success. Three and a half fracs a day, that's industry leading. Nobody's come close to that number. And the folks that have come close I think have had to round up to get a three in front of it. So I think there we're doing very well. We'll have more information on that as we see what our early production rates are in that area.

And when I look to Long Lake and I walk through the statistics and the progress we made and what we continue to need to do to get that project in to full capacity, I think we are executing very well in all the areas that we've chosen to continue to be in. We also chose the opportunity to monetize one of our most mature assets and I think at excellent values to redeploy capital back in our business. And we'll continue to focus on this capacity to execute as I've described specifically what we're doing in each of these areas.

Brian Dutton– Credit Suisse

Marvin, if each of the businesses are performing up to your expectations, then what do you think is the disconnect that's going on with the share price?

Marvin Romanow

I think a couple of things. One is people are still waiting to see the production capacity ramp up to capacity at Long Lake The first milestone have to achieve there is getting to positive cash. And we're through that. And I think I've identified all the issues that are there.

I think the other issue is that in the Gulf of Mexico, I think the marketplace has been cautious in how it's approaching the valuation of those assets. That's a phenomenon that will turn to – that's a phenomenon that will deal with itself I think over the next year. We had a question on the

conference call earlier that people understand that the Yemen contract expiry is coming up and it's an important piece of business to us. So I have good progress to report.

But I think people want to wait until the final pins get put into some these issues before it's reflected in your stock price. And I think the last thing is, there are many meetings I'll have with folks that if I didn't bring up West Africa and 36,000 BOEs a day and the positive cash impact on that, it would be lost and forgotten. So we're within an 18-month window of that coming on stream. And I believe in all of these as we move forward through these phases that I described in these four big areas, those will be important elements to improve and deliver the value that we're talking about is there in our asset base.

Brian Dutton– Credit Suisse

Thanks, Marvin. That was very helpful.


Thank you. Our next question is from Brandon Biago from Treaty Oak. Please go ahead.

Brandon Biago – Treaty Oak

Good morning. Thanks, Marvin. Several of my questions have been answered. But I wanted to touch on a couple of things operationally. I guess following up on Arjun's question on the Gulf of Mexico, you said you hope to get back to work at Knotty Head. I understand the unitization

discussions are ongoing. What do you think you need in terms of additional delineation wells before you can really lay out a development scenario? Or are you already at the point where you've kind of got a scenario in mind?

Marvin Romanow

We're pretty close to that. Amerada had a well that they didn't quite get to drill on an adjacent block. So that's a possibility of getting an additional data point. But I think first of all we had to get the group of five producers together to share all of the information to really put together a development plan that made sense for the entire acreage and the entire pool. So that's happened only recently.

The second set of choices focus around whether you choose to do a smaller well development and tie these back to existing producers to get some production history to see what you want to do after that or to make a decision that you've had enough delineation, you have enough information on the wells that you would put together a full field development. It would include a facility and water injection facilities. And you would mobilize a strategy to execute that. So those would be kind of the big picture framing choices that we'll be looking at with our partners over the next little time at Knotty Head.

Brandon Biago – Treaty Oak

When you said little time, can we look for kind of a scenario by mid-‘11 or is it too difficult to say at this point?

Marvin Romanow

Well, I think that question was asked earlier, and I think some time in 2011 is a very reasonable expectation for what we see today.

Brandon Biago – Treaty Oak

Okay. And then I guess to follow up kind of similarly on Appomattox and that group of discoveries, you said you need at least one more delineation well. Is that one more in each discovery? And then when do you think you could move forward with some sort of development plan?

Marvin Romanow

We've discovered sufficient reserves to be highly confident that we've got a developable discovery. So there are some additional structures that are fairly close to the Appomattox well that deserve a penetration. We would like to have another lateral penetration within the structure that we've discovered. And there's another structure between Appomattox group of structures and Vicksburg that deserves a well as well. So those are the four penetrations that we're looking to move forward with over the next year or so. And that's probably close to a year of activity to get all of that done.

Brandon Biago – Treaty Oak

Got it. Thanks . And then one more real quick. Rochelle and these tie back opportunities to Buzzard, or Scott, what kind of size are we thinking about here? And would you like to characterize how many more you may have that are similar?

Marvin Romanow

Well, our program is going very well. We keep finding more oil. So I don't have the specifics in front of me. But those three tie backs will support 10,000 to 20,000 barrels a day, and they're all going to existing facilities. So they're going in with virtually zero marginal operating costs. So they have very attractive economics. These are projects that have break evens on $40 oil prices.

Brandon Biago – Treaty Oak

All right. Great. Well, thanks a lot.


Thank you. Our next question is from Menno Hulshof from TD Securities, please go ahead.

Menno Hulshof – TD Securities

Good morning, gentlemen. I have a couple of other quick questions on the Horn River. First off, I understand that you're currently focused on Dilly Creek. But what are your plans if any for Liard and Cordova over the coming year? And then second, what are your thoughts on joint venturing in the shales at this time?

Marvin Romanow

Yes, those are good questions and I'm glad you raised them. First of all in Cordova and the Liard basin, both of those we'll be planning lease earning wells and we'll also be looking at the kind of seismic and core hole program especially in Liard. So if you look at kind of the maturity of those three areas, Dilly Creek is by far the most mature, Cordova is behind that and Liard is the least mature. Liard offers excellent upside resource potential. It's slightly deeper. It's going to be slightly more expensive to drill. But the resource density there looks very exciting. So what we want to do is plan a program to evaluate that.

It will probably be late 2011 or 2012 before we get our first set of test wells to be able to drill there. And we're just designing that program. We'll have a little more clarity on that as we prepare our budgets and share some of those plans on a couple of investor days that we have coming up in mid-December.

Cordova, its lease-earning activities and seismic, and at Dilly it's nine wells, then an 18 well pad. So we'll have three successive waves of production beginning this year, at the end of this year, at the end of next year and at the end of 2012 that will add volumes. In addition I think it's important to highlight that we're also looking at LNG opportunities there. Because I think it's one of the only areas in North America that represents that exit capacity.

And I think that we as an industry and certainly as a Company have gotten to the point that we have so much confidence in the resource sizes there that you would confidently be willing to commit to multiyear investment programs at costs that you're confident in, to be able to support the capital infrastructure to get to the LNG economics. And there still continues to be a great deal of interest in purchasing that secure supply of gas.

Sorry just to correct myself, our investor day is going to be in mid-November, not mid-December. We are in the process of putting our data together. We did not want to go to the market place with a shale joint venture until we had the history and the execution on our nine well pad and had finalized what our development plans are going forward there.

So I think the timing for us was driven from that particular angle. We've had a lot of unsolicited interest in this area. We have 100% acreage over 300,000 acres. And we've had much more than a handful of folks coming to display their interest in that entire region and all portions of that region.

So what we'll do is we'll take our time and explore what those choices are. I think there are a lot of ways to structure a joint venture. I think there's been something like 23 of them in North America that have generated $20 billion to $25 billion of investment. So it's clear the opportunity is there. But we don't have to do one, so we'll look and see where we can have a relationship where potentially somebody can bring more than just capital to the table.

Menno Hulshof – TD Securities

So given gas prices you're probably thinking it's more likely a late 2011 event at this rate?

Marvin Romanow

Well, I think everyone looks at gas prices, and I think the major impact gas prices are having is on the cash flow that the gas-oriented producers have that allows them to continue to execute their program. What I don't see is some of those folks that have much longer time horizons. They see the resource opportunity. They see that North American gas prices are selling at 25% of the value of oil. They understand that's not sustainable.

They understand the LNG opportunity that represents, and they understand how to think about this asset in ten and 20 year terms. So it's I think those kinds of folks that are thinking about how to make those investment decisions in those areas. So you have to separate the cash flow pressure that low gas prices are producing from the resource opportunity in Horn River.

Menno Hulshof – TD Securities

Perfect. Thank you.


Thank you. Our last question is from Chip Rewey from CRM. Please go ahead.

Chip Rewey – CRM

Hi, quick question. I wanted to follow up on the comment you made on the Gulf of Mexico drilling, specifically that you might be able to drill the top section of some holes without a final permit to enter the hydrocarbon-bearing zones. Can you just talk a little bit more about that? Kind of over what time frame, how much of the well would you be able to drill? And would that really be an effective strategy for maybe accelerating the down hole portion of the well once you do get the hydrocarbon-bearing zone permit?

Marvin Romanow

Well, I think that I mentioned earlier that the first couple of wells that are drilling now, the regulators have continued to improve work-over work, completion work, and drilling of injectors, drilling into existing known reservoirs as well. This was an opportunity if regulators wanted to take more time to figure out exactly the rule set to penetrate new exploratory zones.

One of the options under discussion is that you would be able to drill known up-hole horizons and suspend wells up until the point that you've gotten through all of your known horizons and drill the bottom sections when the rules are more clear and more available. I don't know that we'll have to wait for that. There is a substantial amount of drilling equipment that's not being utilized. It's affecting the whole economic set of activities in the Gulf. Oil industry is their most important activity.

So this is the kind of discussion that's occurring. And what it allows you to do is put rigs to work and allows you to advance your exploration program. And it allows you to do it a bit differently than you would have. But it adds to I think that both the regulator, the drillers and the operators being able to move their plans forward.

Kevin Reinhart

The one thing that I'd add to that, it's Kevin here, Chip, is that's just one of the options that we're looking at right now, is to drill the top holes.

And that would be to avoid the nonproductive drilling time. So clearly from a capital efficiency perspective we'd be getting value for that type of drilling. The other options that we're pursuing are to look for sublets on that rig. And we are in active discussions right now with a potential company looking to take on that rig. So we have those choices available to us here as we see how the permitting process unfolds and the equipment becomes ready.


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

Kevin Reinhart

All right. Thank you. And thank you, everybody, for joining us this morning. I think the questioning was very constructive, and really focused in on the operations. We are having great success here in all areas of our business, and we look forward to continued progress here over the next period of time. Thanks again for your participation this morning.


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

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