Earnings Transcript for 0883.HK - Q1 Fiscal Year 2010

Executives: Kevin Reinhart – SVP and CFO Marvin Romanow – President and CEO

Analysts: Greg Pardy – RBC Capital Markets Mark Polak – Scotia Capital Arjun Murti – Goldman Sachs Bob Morris – Citigroup Brian Dutton – Credit Suisse Terry Peters – Canaccord Adams

Operator: All participants thank you for standing by, your conference is about to begin. Good morning ladies and gentlemen. Welcome to the Nexen First Quarter 2010 Conference Call. I would now like to turn the meeting over to Mr. Kevin Reinhart, Senior Vice President and CFO. Please go ahead Mr. Reinhart.

Kevin Reinhart: Thank you and good morning and thanks everyone for joining us today. This is Kevin Reinhart. Joining me today is Marvin Romanow, President and CEO and Gary Nieuwenburg, Executive Vice President of our Canadian Operations. Certain comments that we make today are forward-looking statements. I refer you to our press release for more information regarding forward-looking statements and also to the 10-K that we filed earlier this year for description of the risk factors. So following our comments today, there will be some time for questions. I’ll start off with some comments and our first quarter results then I’ll hand it to Marvin to highlight some of the exciting success that we’re having executing on our strategies. During the first quarter, we had continued success in each of our three core growth strategies. Our exploration program is working well. We announced an oil discovery at Appomattox earlier in the quarter and together with Golden Eagle Hobby discovery in the UK and a well in Nigeria, we now have significant discoveries in all of our basins. We’ve also had successful appraisal drilling at (Nottihead) in the US. This was 15% ahead of schedule and 20% under budget. Long Lake continues to steadily climb the growth curve. And Horn River Shale gas is getting better all the times. And we’re making good progress on our asset disposition program. So cash flow during the quarter was $538 million. This was down from the previous quarter as production volumes were temporarily lower. We’re no longer capitalizing start up results at Long Lake and our marketing results swung from a large profit last quarter to a lost this quarter. The impact of these items was partially offset by increasing oil prices. Quarterly production was 252,000 BOE per day as compared to 265,000 in the fourth quarter when everything was on stream. The first quarter was temporarily impacted by the downtime of Buzzard to repair the separator unit but we got back to full rates quick quickly. It was also impacted by ongoing commissioning activities at Ettrick and a two week shutdown for drilling rig moves on that FPSO. It was also down due to an acceleration of the turnaround of the LC500 (inaudible). So currently productions backup to around 270,000 barrels a day. Our second quarter will be impacted by the shutdown at Buzzard for about the equivalent of the two week period. This is to do the installation of the topsides on the fourth platform to handle the addition inch to us and we’ll also take the opportunity to complete the repairs on the separator. So following this we’re very well positioned for a strong second half with the maintenance behind us and volumes growing at Long Lake, Ettrick and Horn River, all should contribute to some pretty strong production in the second half of the year. So with that production growing in our 85% win into crude oil, we’re well positioned to take advantage of strong oil prices relative to gas. As a result we continued to generate the highest cash net backs and recycle ratios in this business. We’re also no longer capitalizing startup results at Long Lake as I mentioned earlier. We expensed the operating loss in the first quarter and in previous quarters we have been capitalizing that cost. We expect to get the positive cash flow later this year as production continues to rise. Marketing as you will have seen reported a loss in the quarter. The abundance of gas supply particularly near consuming markets is making the transportation services less valuable. And also in the prior quarter, rising gas prices contributed to a profit of a $112 million whereas declining gas prices in the first quarter caused us to get some of those gained profits to be given back. So as you would have seen in the news release this morning, we indicated that we have substantially completed the negotiations to sell our North American Natural gas marketing business. We expect to sign an agreement in the next few weeks, once we finalize the documentation. The transaction is expected to close in August and its subject only to regulatory approvals and assignment to some of the various key contracts. We were able to sell the business on a cash neutral basis as inventory and growing concern value offset the negative value of the gas transport storage contracts. These contracts became less valuable in time with the growth in gas supply in North America particularly in those markets where consumption is high. With – while its cash neutral we expect to take a non-cash loss between $250 and $290 million recognizing the negative value of the transportation contracts. And just as a reminder, we’ve had very good success with this business over the last decade and we’ve generated over $800 million of positive cash flow. We’re also making good progress in our other disposition initiatives. The data room for a heavy oil asset package is open. We’ve had a lot of interest and this is a very strong price environment particularly with now heavy differentials. And we expect to sell this business this year – by midyear. Together with the possible sale of our interest in Canexus, we expect to generate over $1 billion from these dispositions over the next 12 to 18 months and we expect these two dispositions to generate gains significantly larger than the marketing loss that were recognized on closing. We’re also exploring the possibility of taking on a joint venture partner for a sizable exploration program in the Gulf of Mexico. Over the last several years we’ve built up our inventory, we’ve hired some world class talent and we’ve matured the prospects to a drill ready stage. At this point we typically farm down our working interest on a prospect-by-prospect basis. So with equipment and drilling locations now available we have the opportunity to extract more value by offering an area wide exploration program. So at this point, I’ll turn it over to Marvin to talk about the strategy and the progress that we’re making in various parts of our business.

Marvin Romanow: Thank you, Kevin. I am excited about the success we are having and executing our various strategies. When you combine our recent major announcement with a major discovery at Appomattox in the Eastern Gulf, our exploration success at Golden Eagle in the North Sea, Owowo in West Africa. We have delivered substantial discoveries at each of our key conventional basins. Much of this exploration success in such a short term is impressive. And we are well positioned for more success with an active exploration and appraisal program for 2010 and 2011. At Long Lake, we’re steadily moving up the growth curve with volume gains in each of the last six months. In Horn River, we have finished drilling our eight-well shale gas program at an industry leading pace of 24 days per 1,800 meter horizontal. All of this success has positioned us well for visible production growth over the next several years from these identified projects. In addition we have a very solid base to grow from, 60% of our current product is not very structural decline for many years. We are currently growing the company with new volumes from Long Lake, Ettrick, and Shale Gas in 2010 and 2011. Going forward, you will see more Horn River Shale gas and new production from Usan, Offshore West Africa in 2012. From Golden Eagle in 2014 and then from Appomattox and future phases of Long Lake. Since our current and future production is over 85% related to crude oil we continued to generate superior returns for every dollar invested. This value creation is magnified when you consider that the market price for energy from oil is three times that of the market price of energy for natural gas. We expect this relationship to continue. I’ll now take a few moments to walk you through our recent successes. So let me start with Long Lake. Since the turnaround last fall, all of our operating metrics have improved significantly. From pre-turnaround averages we have doubled steam production. We have grown detriment volumes by 80% to 25,000 barrels a day. We have doubled the number of well pairs (re-steaming). We have improved our upgrader uptime from about 50% to 80% and our steam all ratios are declining. In addition, we’ve already converted about half of our wells to electric submersible pumping and expect to have about 80% of our wells converted by year end. Electric submersible pumps allow us to optimize our steam injection. The upgrader is producing the highest quality crude in North America and the market is recognizing this. For the quarter we realized over $81 a barrel for Long Lake synthetic crude. This was a premium that WTI one of the highest price realizations in our company were currently on track to meet our exit target of 40 to 60,000 barrels a day. I mentioned at the outset, we’ve achieved excellent success with the drill bit in our key basins. We have discoveries in the North Sea, the Gulf of Mexico and Offshore West Africa. In the North Sea, we are on track to sanction Golden Eagle in 2011, the first of our plan for 2014. In the Gulf of Mexico, we are appraising the drilling results from our recent discovery at Appomattox. Now this discovery has all of the strong characteristics you want in an exploration success. We found light sweet oil, the large structure the six section, a good quality pay, all support attractive well productivities. And we have extensive running room with acreage that we’ve acquired historically along the trend. Our persistence and our patience here has been very important to our success. This is our fifth well in the region. Initial resource estimates for this discovery already support the development of a regional hub. Our plan is in the next few months is to evaluate the results of this well, return to drilling sometime this summer. We plan to drill two adjacent structures and appraise the structure that the discovery was made on. We are also looking at the possibility of using a second rig this year to drill further exploration targets south of the trends. At (Nottihead), we are evaluating the development choices we have after completing our appraisal well. Drilling operations with our new deepwater rig exceeded expectations. We drilled this well below AFE and 60% to 70% of the wells drilled to this depth in the Gulf of Mexico would be more expensive than ours. This is extraordinary performance for the first well for a brand new rig. Offshore West Africa Usan is progressing well towards first oil in 2012 with Owowo lined up after that. We have several more exploration and important exploration wells to drill this year and I am going to go through a brief list. North U.S. (inaudible) is in the UK. That's got a P50 of over half a billion barrels and we have 35% working interest. Bluebell is possibly southern extension to Buzzard and could be tied back easily into Buzzard. Blackbird is the appraisal of discovery that could be tied back into Ettrick and Polecat is another opportunity that's a tieback opportunity to Buzzard. So with even a modest amounts of success here, we can keep our buzzard platform flat for even longer than what I described earlier in my comments. In the Horn River area, we are making substantial progress on our shale gas strategy. Costs continued to drop and we expect overall costs to be below $600,000 per frac for our upcoming 18 well pairs. Our production profiles are also pointing to the higher – to higher recovery factors than what we have traditionally assumed at 20%. As I mentioned earlier, recent drilling results set a pace of 24 days for 1800 meter horizontal. With long tenure, low royalties, excellent resource density and fracability, I am not sure fracability is a word, but we have brittle rocks and crack well. Horn River is a top quartile play where third parties – when third parties compare, the breakevens or the gas price required to earn a return in the Horn River area versus other North American shale plays. We will complete our current eight well pair this summer and we expect to be producing 50 million to 60 million cubic feet by this fall. To conclude, I am very excited about the progress we are making in all of our areas. Long Lake is growing, we have a world class exploration program that is delivering world class results. Our Horn River shale gas program continues to deliver improved outcomes and our future looks very bright.

Kevin McLachlan: We will now open the call for questions. But just before I do that, I just would like to ask you once again that you focus your questions on the business activities and our strategies. Our investor relations group would be happy to answer any detailed modeling questions that you may have later today. With that I will turn it over to questions.

Operator: (Operator Instructions) Our first question is from Greg Pardy from RBC Capital Markets. Please go ahead.

Greg Pardy – RBC Capital Markets: As it relates to Buzzard, what is the earliest that you think Buzzard would start to go into decline? And then when you think about your overall North Sea program, with everything else that you have got, is the idea that you can hold the North Sea flat at on the oil side circa 110,000, 115,000 barrels a day for quite a while?

Marvin Romanow: So, I would separate first of all the question on Buzzard specifically because our North Sea includes Ettrick, Scott/Telford and eventually in 2014, we will have Hobby, Golden Eagle. So when you look at the profile overall in the North Sea, we are the only major producer that I can find that is going to growing production over the next 5 to 10 years when you put all of that together. When you look at Buzzard specifically and this is on a gross basis, when we acquired Buzzard, we expected somewhere around 450 million barrels gross. Just in the direct Buzzard container, we have grown that to over 700 million barrels and we continue to find these both appraisal and exploration targets that are suitable tiebacks to Buzzard. I think we will have to drill those and see where they lead but even without those, we are looking at a three to four year flat period for Buzzard before we go and decline. And as those exploitation and exploration opportunities turn out to be successful, that gets extended.

Greg Pardy – RBC Capital Markets: Just in the Gulf of Mexico, how are you thinking about the Gulf of Mexico? Is there a broader production target that you would hope to achieve or is the Gulf of Mexico from an exploration standpoint just fit into the broader global program that you have got?

Marvin Romanow: The way I characterize the Gulf of Mexico, it’s part of our exploration portfolio worldwide with the biggest areas being the North Sea, West Africa and the U.S. Gulf. Our drilling program is focused on large targets in the deepwater. Appomattox I expect will become the best discovery we have drilled in the Gulf of Mexico ever. And it’s – those kind of targets when you drill them, they almost always will require facilities. So that typically means probably a five-year development window to bring them on stream. But when I look at the company overall, just from our conventional exploration side, we are spaced out quite nicely with Usan coming on stream in two years, Hobby Golden Eagle two years after that and then you are right in the window of bringing Appomattox on stream right after that. So we have a very nice series of things to develop.

Greg Pardy – RBC Capital Markets: And just the last one from me is with Long Lake, it looks as though improvement there for sure. I know kind of yes, no modeling questions, but can you just give us what the operating cost would have been or was in the first quarter and then is there just a blend – I know you gave a number for the PSC, but is there just a blended number between bitumen and PSC? We are just trying to get what the operating netback is going to look like in 1Q, so we can look at progress during the balance of the year?

Kevin Reinhart: Greg, it’s Kevin. Given the size of these specs costs that we experienced at Long Lake, and early stages on the ramp up, using that operating cost per BOE really is a meaningless number. It also has third party volume purchases in that number. So it’s not a good indication for modeling. I think what I would point you to is the fact that by the end of this year, so later in the second half, we should be a positive cash flow here as we ramp up production. And then as operating costs start to get amortized over more barrels, and at that point you will be able to start trending where operating costs are going. But at this point in the ramp up, I think it’s a little too early to start drawing lines from where we are today.

Marvin Romanow: Just to follow up, we still have – when we look at our absolute operating cost, we still have all the expectations and these are very reasonable expectations that we will get to $20 to $25 a barrel operating cost when we are fully ramped up. During quarter one, as we showed in our results, we used to capitalize the operating losses and now we flow them through our cash flow and through our expense statements. On quarter one, we had an operating loss of just under $60 million. But you have to remember that was at 18,000 a day in production and at 25,000 today. And somewhere right around 25,000 or perhaps a few thousand barrels more, we are getting very close to breaking even at current prices on a cash basis.

Greg Pardy – RBC Capital Markets: Just full rates on steam generation, when would you expect to get there? I know you are quoting a 140,000 now.

Marvin Romanow: Well, what we are limited today by is how much steam the wells will take. We are not limited by the steam generating capability. So the next phase of ramp up we are going through is to keep circulating the wells till they are ready to turn on (inaudible) are still in the steaming stage and continue to apply more steam as the steam chambers develop in all of the other wells. So we are not facility steam limited today.

Operator: The next question is from Mark Polak from Scotia Capital. Please go ahead.

Mark Polak – Scotia Capital: Just in terms of Appomattox discovery, I am wondering if you can give us any sense on potential volumes or sort of how you think of it relative to Shiloh and Vicksburg.

Marvin Romanow: What I would point to is when we disclosed the results for Appomattox, we discovered 425 feet of high quality sand. The structures in all of these – in these areas are sizable. So the strategy here is largely to make sure we drill all of the large structures first before we move to thinking about what kind of sizing you would have for development option and as we continue to do that, we will have a better idea on what kind of size range to talk about. But as of today, we are quite confident that we have discovered enough oil to support a standalone facility.

Mark Polak – Scotia Capital: Just in terms of (Nottihead), any sense on timeline for unitizing and eventually sanctioning the project?

Marvin Romanow: (Nottihead), I was in the United States last week to review the results of our well and discuss future plans. We are just in – now that we have got the well results, we are in dialog with all of our partners. There are at least five participants that need to sign off on the unitization. Those discussions I believe will progress very well. And hopefully sometime towards the end of this year, we will be able to share what our development plan for (Nottihead) looks like.

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

Arjun Murti – Goldman Sachs: Just a follow-up on Long Lake. I think you mentioned you are kind of at full steaming capability and you clearly made progress ramping up the volumes. Just wondering what is then the variation between your exit target of 40,000 to 60,000 barrels a day. What will be driver being at the higher, lower end of that? Is it how the reservoir responds to the steam or there would be other factors that would cause the variation?

Marvin Romanow: It would be two things. One is to make sure we have reliable steam generation that's very consistent. Every time we have an interruption in our steam because of a facility issue, it takes us sometimes a few days, sometimes a few weeks to get back up to the ramp up profile. The second is all of these wells have to move through their evolution of circulation and then initial ramp up and ramp up to full capacity. And what we are seeing here with this consistent steam that we're been able to apply for the last six months since the turnaround is that even some of our wells that we thought were mature and fully ramped up are showing good progress on continuing to grow volumes and declining steam oil ratios. So as I mentioned earlier, we are today limited by how much wells the – how much steam the wells can take not by the steam that the facility can generate.

Arjun Murti – Goldman Sachs: That's very helpful. And I think in the release where you talk about the SOR in producing wells being five it obviously does include some of the newer wells. Is there any sense of what some of the – and for lack of a better term older wells are at or can you not disaggregate things any further?

Marvin Romanow: There's still quite a variation as we look to optimize with especially ESPs, so we are still only half converted to ESPs. Our steam optimization has got to be –that's an important cornerstone of optimizing our steam and making sure the pressures are balanced between wells and between pads. But what I would say is that when you look at the trend of our weekly steam oil ratios, we've been consistently on a downward sloping trend since the middle of February and we're still circulating wells and we've still got wells that are in the early phases of ramp up.

Kevin Reinhart: What I would add to that Arjun is that some of those mature wells, many of them are already below our design expectations, so the average of three that we expect on the field we have several wells that are below that. We know that some wells are going to be better than average and some not quite as good as average, but we are very encouraged by the fact that many of those more mature wells have already got down on the SOR to the right end of the average.

Arjun Murti – Goldman Sachs: That's really helpful, thank you. What are the next steps on Appomattox, if I can switch gears here?

Marvin Romanow: On Appomattox as I mentioned in my prepared comments is we are going to take a few months to assess the well results and pick locations on two adjacent structures and appraise this structure, so that drilling should commence sometime this summer and it'll take us into 2011. We are also looking at potentially bringing another rig into the area to drill some of our acreage to the south.

Arjun Murti – Goldman Sachs: And if it's your best discovery ever in the Gulf, that would make it bigger than the combined Knotty Head Pony complex.

Marvin Romanow: Well what we said about Appomattox is that we found enough oil to support a hub, there's two adjacent structures. We are very excited about the opportunity to drill those. And as we drill those and appraise this structure, we will have a clear idea as to where it fits in.

Arjun Murti – Goldman Sachs: That's terrific, thank you very much.

Operator: Thank you. Our next question is from Bob Morris from Citigroup, please go ahead

Bob Morris: Good morning. A couple of questions on the joint venture you mentioned with regards to the deepwater Gulf of Mexico. Could that entail selling some of your interest in the existing discoveries that you already have or would that just be on future drilling?

Marvin Romanow: Our joint venture has focused around our exploratory acreage where have quite a handful of targets and something in the order of 250, 280 land blocks I can't remember the exact number. We have not at this point had any discussion about incorporating in the existing discoveries that we have got.

Bob Morris: Okay. On Appomattox, you mentioned the two offsetting structures, are those just fault separating structures part of the discovery itself, are these totally separate geologic structures from the Appomattox discovery?

Marvin Romanow: We think there are separate sealed fault blocks directly adjacent to ours.

Bob Morris: Okay. And then on Knotty Head appraisal, you mentioned the success you had on the drilling of that with the reduced cost and drilling time. It wasn't clear to me with regard to the specific results of the well itself whether you found that pay or the results that you were looking for with regard to the whole structure there or could you just speak a little bit to the actual well results themselves.

Marvin Romanow: Yes the purpose of the well was to extend the oil in place of Knotty Head and it was successful from that aspect. So the next step is to integrate the results from Amerada Hess' well and ours and look toward what makes the best sort of development option going forward. The choices are, I could broadly characterize them in two ways. One is, you put a large platform with water injection and you go to a full field water supported production system and that would be maybe 10 wells or so and it would be a substantial investment. The other is to get some production history and some well flow capability is to do one-to-three well tie back to an existing platform, get some production history, determine what your recovery factor range could be, and then look to the best way to optimize the field depletion after that. So those are the things we are looking at the present moment and I hope that we have some progress to report later this year.

Bob Morris: Okay, good. And then just one last question, I assume Bugle in the North Sea was unsuccessful?

Marvin Romanow: We are still drilling that.

Bob Morris: Still drilling that. Okay, great, thank you very much.

Operator: Thank you. The next question is from Brian Dutton from Credit Suisse, please go ahead.

Brian Dutton: Yes, good morning. Kevin I was wondering if you could give us some insight into your cash tax position. The cash tax is all in the first quarter. Were they largely out of the UK?

Kevin Reinhart:

: Virtually all. The only places that we pay cash tax is the UK and Yemen and then a little bit in a couple other places, so virtually all of the cash tax is there. So what ends up happening is with increased oil prices, your biggest impact is going to be where your highest production is and that's in the UK, and that's also where our highest cash tax rate is, so cash taxes will go up in the UK. The flipside of that is that because the UK has a high tax rate and we are paying cash taxes now, it means that all of the capital investment that we make going forward including the Golden Eagle Hobby development, it's immediately tax deductible, so we get $0.50 and $1 back right away for every dollar we invest there.

Brian Dutton: Do you foresee any material change to the UK tax positioning for the balance of this year or is everything that you are just talking about in terms of Golden Eagle that's really a 2011, 2012 type tax yield.

Kevin Reinhart:

: No, that's exactly right. Golden Eagle Hobby won't affect us too much this year. When it comes to the UK cash taxes, the best way is to whatever you are modeling in terms of cash flow using price, just look at our capital that we disclosed last year and deducted to, and you apply the tax rate to the difference, because it's all of your cost are immediately deductible, there is no carry forward or amortization to them. So it’s a fairly simple cash tax regime to model.

Brian Dutton: And lastly, I guess you were asked earlier both in netbacks at Long Lake. At some point, will you be disclosing netbacks as you do the other rest of your business at Long Lake?

Kevin Reinhart:

: I think perhaps by the end of this year or into next year, Long Lake will become a large material enough and important enough segment to us that it will warrant its own segment in our financial statements. At this point in time, it's just not material enough to our overall results to segment that out.

Brian Dutton: Thank you.

Operator: Thank you. (Operator Instructions). Our next question is from Terry Peters from Canaccord Adams, please go ahead.

Terry Peters: Thank you, operator. I was asking about the joint venture and my questions have been answered.

Operator: Thank you. There are no further questions registered for the moment. I would like to turn the meeting back over to Mr. Reinhart.

Kevin Reinhart: Alright, well thank you for participating this morning and I think it was a good dialog and some good questions. We are excited about where we are at right now and we are quite looking forward to the next several months and through the rest of the year as we continue to grow production and carry out with our exploration program. Thanks again for joining us this morning and have a good day.

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