Earnings Transcript for 0883.HK - Q3 Fiscal Year 2010

Executives: Kevin Reinhart - EVP & CFO Marvin Romanow - President & CEO

Analysts: 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

Operator: 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. f 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.

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

Andrew Potter – CIBC World Markets:

Marvin Romanow :

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:

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:

Andrew Potter – CIBC World Markets: Perfect. Thanks a lot.

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

Greg Pardy – RBC Capital Markets:

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:

Greg Pardy – RBC Capital Markets: Okay. So I mean, generally comfortable or not comfortable with exit rates?

Marvin Romanow:

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:

Greg Pardy – RBC Capital Markets: Okay. Thanks very much.

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

Mark Polak – Scotia Capital:

Marvin Romanow:

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.

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

Arjun Murti – Goldman Sachs:

Marvin Romanow:

Arjun Murti – Goldman Sachs:

Marvin Romanow:

Arjun Murti – Goldman Sachs:

Marvin Romanow:

Arjun Murti – Goldman Sachs:

Operator: 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:

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:

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:

George Toriola – UBS: Okay. Thanks a lot.

Operator: 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:

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:

Brian Dutton– Credit Suisse: Thanks, Marvin. That was very helpful.

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

Brandon Biago – Treaty Oak:

Marvin Romanow:

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:

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:

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:

Brandon Biago – Treaty Oak: All right. Great. Well, thanks a lot.

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

Menno Hulshof – TD Securities:

Marvin Romanow:

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:

Menno Hulshof – TD Securities: Perfect. Thank you.

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

Chip Rewey – CRM:

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:

Operator: 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:

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