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Executives

Kevin Reinhart - EVP & CFO

Marvin Romanow - President & CEO

Analysts

Andrew Potter - CIBC World Markets

Bob Morris - Citigroup/Smith Barney

Greg Pardy - RBC Capital Markets

Mark Polak - Scotia Capital

George Tunula – UBS

Tom Mockler - GE Asset Management

Chris Damas - BCMI Research

Michael Dunn - FirstEnergy Capital Corp.

Nexen Inc. (NXY) Q2 2010 Earnings Conference Call July 15, 2010 9:00 AM ET

Operator

Good morning ladies and gentlemen, welcome to the Nexen second quarter 2010 conference call. I’d now like to turn the meeting over to Mr. Kevin Reinhart, Executive Vice President and CFO. Please go ahead Mr. Reinhart.

Kevin Reinhart

Thank you, good morning and thanks everybody for joining us today. This is Kevin Reinhart, Chief Financial Officer and joining me today is Marvin Romanow, President, CEO; and Gary Nieuwenburg, Executive Vice President of our Canadian operations.

Just to advise you to comments I make today are forward-looking statements. I’ll refer to our press release, for more information regarding such statements and also refer you to our 10-K for a description of the various risk factors. So following in my comments this morning, there will be some time for some questions.

So we continue to make significant progress executing all of our strategies. My plan this morning is to highlight some of the success that we are having at Long Lake, at our Shale gas operation, through the drill bit, and with our disposition program. I’ll then touch on our production volumes and then significant production adds, we have coming from our various initiatives.

Before I get into all the programs we are making on our strategies, I’d like to make a few comments on the Gulf of Mexico. The current drilling moratorium there does not have any real impact on us. Our production has not been affected. We don’t have any rigs working for us at this time, so we’re not paying for any idle rigs.

We do have two deepwater rigs under contract; these are scheduled to arrive later this year. We’re assessing our options now including news from the rigs or other activities in the Gulf possibly subletting these outside of the Gulf. But we will continue to watch the situation and respond accordingly. The moratorium will delay our exploration program a little bit and the delineation of our discoveries as well. How long will depend on obviously the length of the moratorium and how broad based it continues to remain through the period.

These projects have long cycle time, so the impact is not immediate on us. We are obviously watching thing very closely in the Gulf, though we remain very confident that the deep-water Gulf will continue to be an attractive basin for us going forward.

Turning to Long Lake, we are now generating more steam than we ever have before and in response the bitumen volumes continue to rise month after month, our upgrader is processing substantially all of our bitumen production and some of the third party volumes and we are consistently producing the highest quality synthetic crude in North America.

Since the turnaround last fall, our bitumen production is increasing quite nicely, wells are ramping up and SORs are improving. We now have 20 wells that are collectively meeting our average design bitumen and SOR rates, this is up from only two prior to the turnaround. We continue to optimize remaining wells and heat up those that are early in their life. Long Lake is currently producing 28,500 barrels per day growth and we are on track to meet our yearend exit target of between 40,000 and 60,000 barrels per day.

With improving bitumen volumes, we are seeing substantial improvements in unit operating costs, these have decreased by 43% from the first quarter. They averaged about $88 per barrel in the second quarter and this will continue to decline as we ramp up production in this largely fixed cost operation. We are on track to meet our expected operating cost of approximately $25 per barrel when we are at full capacity.

And we are approaching cash flow breakeven here. Our quarter two cash outflow was $19 million, a substantial improvement from an outflow of $58 million from the first quarter. And we expect to generate positive cash flow here later this year even with the upgrader operating at less than a 50% capacity. With a lot more volumes coming as the ramp up continues, we are excited about the project’s strong cash generation power.

When fully ramped up, our share of annual cash flow is over $600 million in the $70 price environment. At the same time that we are making steady progress on the ramp up, we continue to pursue inexpensive ways to add bitumen capacity. This makes a bunch of sense. It ensures that we keep the upgrader full and the bitumen production in excess of upgrader capacity can be sold for fairly attractive returns.

As a result we are positioning ourselves to be long bitumen by optimizing or producing wells and continuing with the development of two additional wells and we are starting engineering work on two more once-through steam generators. These will increase our steam capacity by 10% to 15% and that can be done at a modest capital investment of about $150 million gross or a $100 million net cost over the next 18 to 24 months.

The economics are compelling whether we sell the bitumen or upgrade it through our facility, and this also adds incremental steam capacity which increases our safety reliability and allows for higher SOR if that's where we ultimately get to. We are committed to developing our vast oil sands resource.

As we described in the press release, we are working on plans to sequence the development of Phase 2, a little different than we did Phase 1. Here we started with smaller SAGD stages of about 40,000 barrels per day each. And then we will follow with upgrading sometime after we ramp up the SAGD operation. This approach has many benefits. It improves the management of capital as we are constructing the facilities. It places less stress on the material, equipments and labor markets. It simplifies the SAGD ramp up process and it provides flexibility on when we move to upgrading based on economic conditions. Oil sands is the key part of our future and we are moving forward to capture the value with the 6.5 billion barrels of resource that we own.

Turning to shale gas, we are making substantial progress on our Horn River acreage. We are executing very well and our costs continue to drop. This past winter we successfully drilled an eight well pad. We did this 35% faster than our previous pace and these wells were twice as long. We are currently fracing those eight wells and very early on the programs, but the first 40 fracs were 100% successful. And they were done at a frac pace of 3.5 fracs per day. This compares to previous industry pacesetter activity of 2.4 fracs per say.

Compared to other North American Shale gas plays, Horn River is top quartile. It has an excellent land and long land tenor system. It has low royalties and it's got an excellent resource density and fracability. We expect to be able to earn a 10% rate of return here with gas prices at $4 an mcf. And given the success that we and others are having we more than doubled our acreage position in Northeast BC at the recent land sale.

As we previously disclosed, we estimated that the original 98,000 acres we have in the Horn River basin contains 3 to 6 tcf of recoverable contingent resource. And that 6 tcf equates to about a billion barrels of oil equivalent and that is equal to our total crude reserves. That gives you a sense how significant those first 90,000 acres were to the company. And with the total acreage position that is now more than three times the size, the resource potential of our lands now is even more significant.

Turning to the conventional side, it had great success with the drill bit. We’ve had recent successes at Appomattox in the Gulf and Golden Eagle Hobby in the North Sea and Owowo, offshore, West Africa.

We are well positioned for more with an active drilling program on numerous exciting prospects over the next several years. In the Gulf, we have a major discovery at Appomattox. This has the potential to be our best discovery in the Gulf. Plans are underway to commence an active program to delineate the discovery and further explore the surrounding area. Drilling is delayed by the moratorium but we are well positioned to move quickly once we get the go ahead. In the North Sea, we’re on track to sanction Golden Eagle Hobby next year with the first oil planned for 2014. At Buzzard, we have a number of opportunities to add to our proved reserves. The northern panel contains more recoverable oil. We plan to drill Bluebell later this year to extend to the field to the South. And we plan to drill an appraisal well at Polecat, which is a potential tieback to the Buzzard facility.

Elsewhere in the North Sea, we are finalizing plans to drill the North US well later this year. This is west of the Shetland and it is targeting a size much larger than we typically go after in the North Sea.

Offshore West Africa, this kind of growing factors started out in 2012 of growing factors started up in 2012, this will add 36,000 barrels a day net to our interest once we are fully ramped up. And at peak rates, I am assuming $70 oil price, this of January ‘10 about $750 of annual cash flow.

Recently we announced successful exploration at Owowo. Success here makes people more optimistic about other exploration prospects in the area. And we are working on plans for additional explorations, drilling to support both extending the plateau at Usan and stand-alone development elsewhere.

On the disposition front, we made excellent progress in generating significant value and have already met their proceeds targets with our investment in Canexus yet to sell. Most significant was the sale of our heavy oil properties in Western Canada for approximately $975 million. We achieved excellent value for these assets.

Net sale was expected to close shortly. The sale of our North American natural gas business is expected to close next month. We recently received a regulatory approval to proceed and now we are in the process of assigning the key contract over to the buyer. These two dispositions are expected to generate net book gains of over $500 million for us.

As I mentioned, our disposition programs already exceeded our proceeds target of $1 billion. We now expect to generate $1.5 billion of total proceeds from all the sales once we complete the program. These proceeds will be used to develop exciting successes being generated throughout the rest of our business. We are in great shape as we move into second half of this year. Even with asset sales we expect to meet our annual production guidance of 230 to 280,000 barrels a day.

We are recently producing between 250 to 260,000 barrels per day and that’s after the sale of the heavy oil properties. Earlier this week however, the Scott/Telford field was shut in when the operator advised us of a valve failure on the pipeline leading into the Forties productions system. The operator is detecting the root cause and they’re planning their repair work, we are taking this opportunity to accelerate the plant and maintenance that we had scheduled for later this third quarter.

As we noted in our press release we expect to have 70,000 barrels a day of new volumes over the course of the next 18 to 24 months. This comes from the ramp up at Long Lake, the startup Usan and from continued progress at Ettrick and our Horn River shale gas play. We could also see near term production outside beyond that from a potential contract extension at Yemen, further exploitation drilling in the UK and accelerated development of our shale gas properties.

Little longer term, we have upside at Buzzard, extending the production plateau. We have new production adds coming from major discoveries we have to develop at Golden Eagle, Appomattox, Knotty Head and Owowo as well as future phases for oil sands.

For the current future production over 85% weighted to oil. We are well positioned to take advantage of the strong oil prices relative to gas. We continue to generate the highest cash netbacks in the business and we continue to generate superior returns from the money we invest. We are delivering execution success and building momentum with all of our strategies. Our future is bright and our value of proposition is highly compelling.

I’ll now open the call to questions. But as always we’d ask you to focus your questions on our business activities and strategies and if there is any detail or add-on questions, our IR here is more than happy to deal with you offline.

With that I’ll turn it back over to the moderator.

Question-and-Answer Session

Operator

We will now take questions from the telephone line. (Operators Instructions) Our first question is from Andrew Potter of CIBC World Markets. Please go ahead.

Andrew Potter - CIBC World Markets

Just a question on the shale gas land acquisition, where specifically were the land; is it Horn River or Cordova Embayment?

Kevin Reinhart

Hello?

Andrew Potter - CIBC World Markets

Hi, can you hear me?

Kevin Reinhart

Hello?

Andrew Potter - CIBC World Markets

Just a quick question on the shale gas land acquisition, were the land acquired in the Horn River or Cordova Embayment?

Kevin Reinhart

Shouldn’t you think we should cut it out?

Operator

I do apologize. Mr. Potter, could you repeat your question please?

Andrew Potter - CIBC World Markets

The land acquired, were they in the Horn River or the Cordova Embayment, in sort of the shale gas land?

Operator

I do apologize for this difficulty. The conference will resume momentarily.

Kevin Reinhart

Hello?

Operator

Please proceed with your question Mr. Patter.

Andrew Potter - CIBC World Markets

We will try one more time. So the shale gas land acquisition was that in the Horn River or the Cordova Embayment or elsewhere I guess, I wasn’t totaling clear on that?

Marvin Romanow

Good morning, this is Marvin here. We purchased acreage in the Cordova area and we also purchased acreage in the Liard area.

Andrew Potter - CIBC World Markets

What sort of results have you had from the Cordova or have you even drilled there yet?

Marvin Romanow

We have had both vertical and horizontal test there and we are very encouraged by what we see there. I think if we wanted to compare that to Dilly Creek, the way we’d frame that is well costs are going to be a bit cheaper because the formations are a bit shallower. Resource density from the activity that we see today is roughly 80% of what we see in the Dilly area. So in fact with the lower cost and slightly lower resource density, our economics are probably are going to look a little better than the Dilly area.

Andrew Potter - CIBC World Markets

That’s interesting, and then one last question just on the Horn River. One operator was yesterday talking about an oils owner, oil resource play kind of over-line the Horn River shale, is that something you guys have looked at yet or what is your thoughts on that I guess?

Marvin Romanow

Yeah, we quote some of that area, we do see oil staining, we are evaluating what the possibilities are there and we maybe pursuing some activities on that.

Andrew Potter - CIBC World Markets

What is the zone; is this the Bakken or Bakken/Exshaw?

Marvin Romanow

It’s the Exshaw.

Operator

Our next question is from Bob Morris of Citigroup, please go ahead.

Bob Morris - Citigroup/Smith Barney

Good morning. Last quarter you indicated that you are pursuing or looking at a joint venture in the deep-water Gulf of Mexico on your 250 plus. Given event since last quarter, is that something that you are still looking at or what is the status of that at the moment?

Marvin Romanow

Well I think like a lot of other operators, we are looking at how the regulatory environment is going to unfold and what that actually means for company's abilities to conduct activities and the implication of that. So when an environment becomes a bit uncertain I think everybody waits for the frameworks to unfold and then to move forward. So we've been engaged with discussions with a handful of companies that are interested in our proposal but they like everybody else are waiting to see how some of the specifics in the Gulf will unfold.

As we look to how the Gulf of Mexico progresses, as BP makes more and more progress in containing the well and moving to improving the overall situation in the Gulf, I think we will move the dialogue back into what we need to have a positive and constructive deep-water industry in the Gulf. So in the long term we are very constructive on what the deep-water has to offer and I would say the companies that we are talking to would exhibit a similar framework. But like everybody, we all want to know what the environment is going to be with a little more specificity than what we see today.

Bob Morris - Citigroup/Smith Barney

And then on the North Uist, when is that supposed to spud and given the fact that BP is the partner operator there, has that changed schedule and timing on that at all given the situation with BP?

Marvin Romanow

It hasn't changed the timing and schedule. We are waiting on the rig to arrive and we expect that to be somewhere in the fourth quarter of this year.

Operator

Our next question is from Greg Pardy of RBC Capital Markets.

Greg Pardy - RBC Capital Markets

Maybe just a follow up a little bit on Canexus, what we should be looking at in terms of timing? I think Marvin you mentioned there would be potentially like 40,000 barrel per day phases but what does timing look like?

Marvin Romanow

I think that we are continuing to progress the work on there with core holes and doing preliminary design work. So we really expect to continue to be doing that into 2011, I think the earliest we would be ready for a formal sanction would be late 2011, early 2012, and then you would look at kind of a two, three year investment program to get to first production.

Greg Pardy - RBC Capital Markets

So I just wanted to clarify just the non-cash gains and losses then, I think $260 million to $290 million is a non-cash loss that you will take right in connection with the disassemblage of the gas business. And then did you mention or did Kevin mention that you will take a $500 million gain then on the heavy oil business?

Kevin Reinhart

Yes, the net of the two will be $500 million, so our gain on the heavy oil business is somewhere in the vicinity of $750 million.

Greg Pardy - RBC Capital Markets

And just the last one on the Horn River, the supply cost number that you provided of around $4, can you give us any color around some of the base assumptions that you are loading into that, either in terms of EORs, IPs, what have you and how do you plan to handle the CO2?

Marvin Romanow

So in terms of the assumptions what we are looking at is 18 oil pads with 18 fracs that we expect when you take the drilling and completion costs will be in the $500,000 to $600,000 per frac for drill and complete. We think that the Spectra plant will process the CO2, so they have been doing some pilot work on re-injecting the CO2, so that would require some time and some facilities to complete that project.

In terms of the other parameters, we are using 20% recovery factor for estimated ultimate recovery and then looking at some of the well performance that we are seeing from our current production in Horn River, I think that’s a very conservative assumption. So we are looking for I think to be honest better performance than that. We will have 144 fracs completed on this eight well pad that we are drilling right now. But we have seen very consistent kind of 0.5 to 1 million cubic feet a day deliverability per frac on our previous fracs that we’ve done. So it’s those kinds of parameters that we built into going forward as well.

Greg Pardy - RBC Capital Markets

Is there anything you can say just on the IPs or the EORs?

Marvin Romanow

At 20% recovery factor, we are in the neighborhood of about 10 Bcf per well. So as that improves and some of the shales in the US, where actually rock properties aren’t quite as good as Horn River are seeing up to double that up to 40% recovery factor.

So I think that as we collect more and more production information, we are still actually continuing to advance our frac design, by the way we are doing perforating. And I expect that those will continue to show positive improvements in terms of both recovery factor and production rate per dollar of capital spent.

Greg Pardy - RBC Capital Markets

And just on the IP mark?

Marvin Romanow

The IP mark was half a million to a million cubic feet per day, per frac.

Operator

Our next question is from Mark Polak of Scotia Capital. Please go ahead.

Mark Polak - Scotia Capital

Just a follow-up on the Long Lake, with the incremental steam capacity, just wanted to know how much spare capacity you have in terms of oil treating and the emotion [ph] and water treating, then what the potential uplift of bitumen production is there?

Marvin Romanow

I think the way to look at the two components of our capital program, there are the two extra well pads and the additional steam generation. The steam generation is very capital efficient because we have enough water processing and handling capacity that we don’t have to duplicate all of that infrastructure and that really points to the success of the turnaround that we completed last September.

So both of those projects although they are independent really get us to the same place of putting us in a position to be bitumen long beyond 72,000 barrels of bitumen supply that we have targeted for, but it also gives us more flexibility with respect to maintenance because the steam generators have to be taken down to be maintained periodically. It also gives us the opportunity to handle higher SORs during ramp-up periods. So it provides a lot of positive benefits and has very good economic returns.

Mark Polak - Scotia Capital

Thank you and then are you able to comment on how much you spent on the Shell gas acquisitions?

Marvin Romanow

What I would say is that bidding for acreage here is across the world is pretty competitive strategy. So, we are thrilled with the amount of acreage we acquired, we acquired about half of what we bid on Cordova side of the equation we acquired a slightly higher proportion of that on the [lockliard] side of our strategy and we really look forward to moving that both of those areas forward.

Mark Polak - Scotia Capital

Would that be included in the cash flow statement for Q2 or would that show up in the third quarter?

Marvin Romanow

No, it’s incorporated in our capital investment program in quarter two.

Operator

(Operator Instructions) Our next question is George Tunula of UBS. Please go ahead.

George Tunula - UBS

A quick question on Long Lake. Could you provide some clarity on the metric you look for in terms of installation of ESPs on the wells and the difference in productivity you have seen pre and post installation of ESPs?

Kevin Reinhart

Yes, typically the converted wells from gas lift to ESP is in the order of $1 million, we have actually found that as we have gone through this program started or I think its almost a year what we are actually doing now our second generation of upgrades where we have seen such positive results from some of this programs that we are now actually upsizing the ESPs on some of the wells, we originally converted from gas lift to electric submersible pumping.

So, the primary benefit we get here is to be able to manage our injection pressures to optimize [scene] and to optimize our production. When you go with gas lift, there is a minimum injection pressure that you require to lift the fluids and in some situations that injection pressure is too high for the ultimate utilization of steam and the ultimate production performance of the well.

So some of the best cases we’ve seen productivities go up by a factor of two or three times from the kind of optimization we were able to achieve with gas lift. So it varies and overall, my kind of back of the envelope gas is that the results of this programs is we’re paying up the investment in ESPs in a matter of weeks or months.

George Tunula - UBS

What about -- your press release talks about converting or installing incremental ESPs at the appropriate time. I’m just wondering what performance metric for each well you look at to trigger that installation?

Kevin Reinhart

What we have generally found is in the early period when we soak the wells and we soaked the wells with -- soaking both injector and the producer with steam for about 90 days. During the very initial production phase and kind of the first three to six months, it’s easier to manage and operate those wells in the gas lift mode. So it’s typically been as soon as we get through that initial stage production operations with gas lift that we move to installing ESPs.

Operator

Our next question is from Tom Mockler of GE Asset Management, please go ahead.

Tom Mockler - GE Asset Management

Good morning. Should we be thinking that you wouldn’t contemplate any leveraged acquisitions that might jeopardize your investment grade bond rating?

Marvin Romanow

When we look at our overall balance sheet and the asset streamlining we’ve undertaken with primarily exiting gas marketing and disposing of our conventional heavy oil business, that really was an asset optimization driven strategy. And when I look at kind of the opportunity set we have in front of us, we have five conventional discoveries to develop in, two in Gulf of Mexico, one in the North Sea and two in West Africa, one of which is going to be on stream here in 2012. We have additional phases of Long Lake, we’ve enhanced our Shale Gas acreage position in an area that’s industry leading in North America. So what we are going to be using those funds for is to move those projects forward.

Tom Mockler - GE Asset Management

So we should interpret that as you are committed to investment grade bond ratings.

Marvin Romanow

That’s been very important to us for our whole corporate existence. And with all of the additional volumes we are bringing on stream and being strongly oil weighted, oil seems to have found a floor here in the $70 barrel range. I think maintaining that investment rating is something that’s going to be very straight forward for us to achieve.

Operator

Our next question is from Chris Damas of BCMI Research. Please go ahead.

Chris Damas - BCMI Research

I wondered if you could comment on the timing and process for the sale of your interest in Canexus. Eka Chemicals announced a price hike for their chlorate product. And I wondered if you would see that as a sign to delay your sale process and could you comment on the possible valuation range? I don't expect you to.

Kevin Reinhart

That is the most interesting framing of a question I think I have had in a long time. So I will see if I can work my through that. When we went with our initial partial disposition of Canexus in 2005, we said that eventually we would monetize the entire piece of it. And we had two surprises in the interim, one was a change in the legislation for royalty trust in Canada that changed the tax nature of this asset.

And the second one was the financial crisis and a big recession that had a impact on GDP related business such as Canexus. Canexus has a very strong asset set, it’s a low cost sodium chlorate producer in North America. They are just about to finish and ramping up a very important project at Vancouver that will add about 30% to their EBITDA and the project is largely driven off of reducing operated costs.

So we've had a patient owner in this asset as we've worked through those investment opportunities in those market changes. So having healthy assets since 2005 our real focus here is on ensuring would get maximum value for that. So if that’s going to take you know three months to do or six months to do, that’s how long it will take. If it takes 18 months to do that, we are obviously going to be patient as well. So we don’t have a specific timeframe agenda.

And when I look forward and look at how the market is unfolding, you know we do face some risk of the developed world economies going into a bit of a slowdown. So if that happens we will probably a bit more patient. If that doesn’t seem to have a negative impact, we’ll probably be able to accomplish a bit sooner.

Chris Damas - BCMI Research

Thank you for that, but certainly there are only a handful of possible buyers. I might note that Akzo Nobel recently and now it plans to raise US$1.3 billion. It would seem the pump is fairly well primed over there.

Marvin Romanow

Well, I think that’s a very good observation and what we’ve also been fairly patient for is to ensure that you know as we move this asset into the marketplace that the capacity to finance that activity is strong because that’s just as important as peoples’ assessment of market parameters such as growth and the economy overall.

You know so I think that what we found from a variety of such a transactions that we pursued in the past and in 2005 where we let an IPO Canexus, we had to dual-track process at that time where we explore private equities, strategic buyers and we had a very wholesome process at that time. And what I can say from that is that I believe there will be a decent handful of parties interested in this asset.

And what we found from you know, all of our experience in the conventional oil and gas businesses well is that to predict who or what the successful party might want to pay for an asset like this as really you don’t have to go through a process and as long as you manage the process well you will do very well.

Operator

And our next question is from Mike Dunn of FirstEnergy, please go ahead.

Michael Dunn - FirstEnergy Capital Corp.

Good morning gentleman, just wondering if you could remind me the two well pads that you are working on. What incremental bitumen production capacity are they interested to add and then I guess on the steam generation side what's the incremental steam capacity as well?

Marvin Romanow

So the well pads, we expect the two well pads will add in the neighborhood of 15,000 barrels per day of additional capacity. The steam is roughly targeting about 30,000 barrels a day of incremental steam. So if you look at a 3:1 steam/oil ratio, that's going to support our bitumen production of about 10,000 barrels a day.

As I said earlier in my comments these two projects are independent but what they do achieve is putting us in a position of being bitumen long, they put us in position of adding a lot of asset reliability to have consistent bitumen production, and they put us in a position to handle higher steam/oil ratios in the short term specially and even in the long term if that’s necessary. We still however believe that we have a very good shot at getting to our original target of 3.3 overall.

Operator

There are no further questions registered at this time Mr. Reinhart.

Kevin Reinhart

Great, thank you and thanks for everybody’s participation and patience as we went through some of our technical difficulties. Have a great week and thanks again.

Marvin Romanow

Kevin’s going to go buy a new phone.

Operator

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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Source: Nexen Inc. Q2 2010 Earnings Conference Call
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