National Fuel Gas Co (NFG) 2010 Q1 法說會逐字稿

Good day Ladies and Gentlemen and welcome to the first quarter 2010 National Fuel Gas Company earnings conference call.. My name is Jasmine, and I will be your operator for today. (Operator Instructions) As a reminder this conference is being recorded for replay purposes. I would now like to turn the conference over to your host for today, Mr. Jim Welch, Director of Investor Relations. Please proceed.

Thank you and good morning, everyone. Thank you for joining us on today's conference call for a discussion of last evening's earnings release. With us on the call from National Fuel Gas Company are Dave Smith, President and Chief Executive Officer, and Ron Tanski, Treasurer and Principal Financial Officer. Joining us from Seneca Resources Corporation is Matt Cabell, President. At the end of the prepared remarks we will open the discussion to questions.

We would like to remind you that today's teleconference will contain forward-looking statements. While National Fuel's expectations, beliefs, and projections are made in good faith, and are believed to have a reasonable basis, actual results may differ materially. These statements speak only as of the date on which they are made and you may refer to last evening's earnings release for a listing of certain specific risk factors. With that we will begin with Dave Smith.

Thank you Jim and good morning to everyone. As you read in last night's release National Fuel's earnings for the first quarter of fiscal 2010 were $64.5 million, or $0.78 per share, up approximately $107 million, or $1.31 per share over the first quarter of fiscal 2009. Adjusting for nonrecurring items, the largest of which was the ceiling test charge Seneca recorded in last year's first quarter, operating results improved slightly quarter over quarter. Overall, particularly given the decline in gas commodity prices, it was a strong quarter for National Fuel and a very good start to the fiscal year. Our Utility, Distribution Corporation, posted another quarter of solid reliable earnings consistent with their role in our integrated system.

Our E&P Company, Seneca Resources, increased total production by 20% quarter over quarter which was enough to offset the effect that lower natural gas prices had not only on Seneca's production revenues but also on Supply Corporation's efficiency gas revenues. Bottom line, we're very pleased with our financial results for the first quarter. We're also pleased with the progress we've made in the field. We continue to execute on our plan to focus our capital and other resources on Appalachia.

We're just beginning to see the fruits of that labor in the E&P segment where in the last quarter we achieved first production from our Seneca operated Marcellus program. In mid November, Seneca brought its first two Tioga horizontal wells on line. Production from these two wells, for just that limited period of time, accounted for almost 30% of the increase in the East Division's production for the quarter. As a result of Seneca's success in the Marcellus, we are raising our E&P capital budget and we expect by year's end to employ four rigs in the Marcellus. Two in the East, two in the West. Matt will provide a full update, on Seneca's operation including the Gulf and West Divisions later on the call.

Complimenting Seneca's efforts, in November NFG Midstream completed construction of the first phase of the Covington Gathering System in Tioga County which delivered Seneca's Tioga production into Tennessee's 300 line. Midstream is now working on the second phase of that project which will extend that system further south to Seneca's acreage on State Track 595 which Seneca expects to begin drilling this summer. The necessary rights of way have been acquired and the pipe has been purchased. Construction is underway and progressing as we speak, and we expect, like the first phase, that the second phase of the Covington System will be completed in time to coincide with Seneca's first significant production off that acreage.

Turning to the regulated pipeline and storage segment we continued to make good progress on our multiple expansion opportunities. Supply Corporation has secured the market commitments necessary to support the Lamont and Line N expansion projects. As a result, these are both go projects that will be moving forward, and both are proceeding according to schedule. As you will recall at Lamont, Supply Corporation will build a new $6 million 1200-horsepower compressor station that will provide an additional 40 million a day of take away capacity at an inter connection with Tennessee. The station site has been acquired and the compressor units ordered. Construction is expected to start this March for a June 2010 in-service day.

The Line N project is a $23 million pipeline and construction project at the southwestern end of our system, that will move 150 million a day of Marcellus production, most of it Range Resources production to an inner connection with Texas Eastern. Supply Corporation began the pre filing process in October and expects to file its FERC application this April. Assuming all goes well, and we think it will, the Line N project should be in service in November 2011. I should also note that given the interest producers have indicated for additional capacity on both of these projects, the Lamont and Line N are being designed to be readily expandable.

Another major pipeline project that will be built is the Tioga County Extension Project which will extend the Empire Connector from Corning, New York, about 16 miles south to Jackson Township in Tioga County, Pennsylvania in the area where there has been significant Marcellus production. That project, which is estimated to cost $45 million, will also include modifications to Empire's existing facilities, modifications that will allow for bi-directional flow ultimately into the TransCanada Pipeline System at Chippewa. Empire has executed a binding precedent agreement with an anchor shipper for 200 million a day of firm transportation which is enough in and of itself to support that project moving forward and we're optimistic that we will sign agreements for at least another 100 million a day with other Marcellus producers in the region.

Preliminary routing and environmental work have been completed and engineering work is now underway. We expect to file an application with FERC sometime this summer. The projected in-service date September 2011. Lastly, Supply continues to see strong interest from Marcellus producers in the initial phases of its West-to-East project. The first phase, which would go in service in 2011, is designed to move 100 million a day of Marcellus production through a new 39-mile pipeline extending through Elk, Cameron and Clinton counties to Leidy Hub.

The second phase, which would provide an additional 325 million a day of capacity starting in 2012 extends the West-to-East system another 43 miles through Clearfield in Jefferson county to our Line K System. Currently, Supply Corporation has executed precedent agreements for 100 million a day of firm transportation service and is now in the process of finalizing agreements for another 75 million a day. While it's not enough to support the entire project we believe the anticipated level of Marcellus drilling in the area will ultimately require the construction of a major pipeline like the West-to-East project and we remain very optimistic that it will be built. We will continue to market its capacity and we will continue to keep you informed on our progress.

In closing, this was a great quarter for National Fuel, particularly with regard to our accomplishments in Appalachia, where we will continue to focus our efforts and our resources. And to that end, and this is probably as good a forum as any to announce it, Jim Welch, who heads up our IR efforts will be moving over to Seneca as the Marketing Manager for their Appalachian production. Jim did a great job for us in IR, and given his work ethic and his prior experience in Interstate Marketing, I have no doubt he will do a great job at Seneca.

Replacing Jim as director of IR will be Tim Silverstein who like Jim, has had the benefit of working with various departments, including IR, as part of our rotating MBA program. We're all confident that Tim will do a great job in his new position and I'm sure will you all get to meet Tim in the very near future. So with that, I thank you for your attention and I will turn the call over to Matt for an update of Seneca's operations.

Thanks, Dave. Good morning, everyone. Seneca had a great quarter with production up over 20% versus last year's first quarter. West Division production was essentially flat while the Gulf was up 42% and the east was up 48%. The Gulf production increase is primarily due to the hurricane shut-ins experienced last year, but also reflects new production this year from our Cyclops field. We're planning to spend only $15 million to $20 million in the Gulf this year which includes the drilling of a third well at Cyclops which we expect to spud sometime this month.

In California, some natural decline was offset by new production from our Ivanhoe acquisition. We recently drilled six new wells on the South Midway Sunset property that we acquired from Ivanhoe with very encouraging results, confirming some of the upside potential we had recognized at the time of the acquisition. We have eight more development locations planned this fiscal year and expect to drill another 15 to 20 next year. This year's program should add approximately 200 barrels of oil per day by year end.

In the East, we have solved most of our system constraints for our traditional shallow production, and also brought on production from the Marcellus Shale. We have had two Seneca operated Marcellus wells producing into the Covington System since early December. These two wells had a combined average rate of about 8.5 million cubic feet per day for the month of December. Since our last earnings call, we have fraced two more wells in Tioga County, the first floated an initial rate of over 10 million cubic feet per day, and averaged 9.5 million a day over seven days. This well had a 5,700-foot lateral and was fraced in 15 stages.

We also attempted a zipper frac on two adjacent parallel wells. The first few zipper stages went well, but we ultimately had to abandon the zipper frac process due to an operational problem with one of the wells. We completed the fracing of the other well and will be flow testing it this weekend. Our average seven-day IP over our first three Seneca-operated horizontals is 6.7 million cubic feet per day. Last month, we participated in the Pennsylvania DCNR lease sale. We were the high bidder on two blocks. Our total high bids were $71.8 million. Bidding was very close, such that we left only $3.6 million on the table.

These two new blocks add 18,000 acres in Tioga and Potter Counties, not far from our Covington area activity. In the more western portion of our overall acreage position we are nearing TD on a horizontal well in McKean County and preparing to frac a well in Elk County. These two wells and several others planned for the next few months will be very important tests at the western extent of our acreage. These wells will give us a first indication of potential flow rates and gas processing requirements. Regarding our Marcellus joint venture with EOG, EOG has now drilled 22 horizontal wells, 12 have been fraced, and five are producing.

EOG currently has two horizontal wells drilling in the Punxsutawney development area where we are expecting first development by the end of March. Looking at our overall Marcellus drilling plans we are now planning to add a third rig in April or May and therefore now expect to drill 35 to 45 Seneca-operated wells this fiscal year. We now estimate our fiscal 2010 Marcellus Shale capital spending to be $260 million to $280 million, including the $72 million we are spending for the new DCNR leases. This will raise Seneca's overall capital spending to a range of $320 million to $370 million. With this increased activity and our latest drilling success, we are also upping our production guidance to range of 44 to 51 Bcfe for fiscal 2010, which includes five to seven Bcf from the Marcellus, mostly from our Seneca operated Tioga County focus area.

In summary, Seneca's first quarter results were excellent. Production increased substantially. We validated the potential of our recent California acquisition, and our Marcellus drilling results surpassed our expectations. We are on track for production growth exceeding 10% this fiscal year and are confident that we will see 20% growth in 2011 and beyond. With that I will turn it over to Ron.

Thanks, Matt, and good mornings everyone. From a financial reporting perspective, there are no extraordinary items that impacted earnings for first quarter of fiscal 2010. However, there are a couple of things that I will point out that may affect analyst models going forward. Now, Matt already mentioned an increase in the CapEx budget for the Exploration and Production segment.

The E&P budget range that I talked about on our November call was between $245 million and $293 million. The current range is between $320 million and $370 million with a following allocation among divisions- in the Gulf Coast, we have allocated $15 million to $20 million, in the West Coast, $25 million to $35 million. Appalachian Shallow Devonian $20 million to $35 million and Appalachian Marcellus $260 million to $280 million. If you use the middle of that budget range for the Exploration and Production segment, or $345 million, the consolidated CapEx budget for the company is now targeted at $502 million.

The increase in the CapEx results primarily from Seneca's most recent lease acquisition in Pennsylvania. And while we will be outspending our cash flow, this budget increase is not large enough to drive us to the capital markets. From a cash flow perspective, factoring in the $502 million in capital spending for the year, and using the middle of our earnings guidance range, we expect to be cash flow negative for the entire year by roughly $110 million. We still have cash reserves and plenty of credit capacity to cover our working capital needs and to handle this extra $110 million cash requirement. The other item that I wanted to point out was the assumption for the DD&A rate to use for Seneca's production. Last August, our preliminary guidance was to use a rate around $2.35 per Mcfe.

Now, after the finalization of our reserve study, and the year-end calculations for our depletable base and projected production volumes, we think the rate for our 2010 fiscal year will be more in the range between $2.15 and $2.20 per Mcfe. Looking forward through the remainder of fiscal year there are three main items that can cause variances in our projected earnings. The first is variations in weather. As we reported in the back pages of last evening's release, weather for the first quarter was slightly warmer than last year, and we saw a corresponding decrease in throughput across our Pipeline and Utility systems. Notwithstanding that decrease in throughput, earnings in the Pipeline and Storage segment were not dramatically affected because of their straight, fixed, variable rate design.

At the Utility, the weather normalization clause also operated to maintain our margin and our continued focus on controlling costs in the Utility helped us to achieve a slight up-tick in earnings. The second item that can affect our earnings volatility-- or can affect our earnings, is volatility and commodity prices. We've again included an updated sensitivity table at page 21 of yesterday's release to give you an idea of the impact of changing commodity prices on our earnings. The third item is the timing of getting new Marcellus production on line.

The production guidance range between 44 and 51 bcfe is as wide as it is to accommodate the uncertainties of getting the new Marcellus gas flowing from both Seneca-operated wells and our non-operated joint venture wells, as well as a possible shut-in of Gulf Coast production during hurricane season later in the year. Before we open up the line for questions, I will point out that the hedges that we have listed on page 19 of the release reflect the hedging of approximately 56% of the production for the remainder of the year if you use the midpoint of our production guidance. With that, Jasmine, we'll open up the line for questions.

(Operator Instructions) Your first question comes from the line of Jonathan Lefebvre with Wells Fargo Securities. Please proceed.

Good morning, gentlemen. Just wanted to touch on, in the release you mentioned that the pipelines were impact by $0.08 due to lower efficiency on gas revenues, mainly due to lower commodity prices. I guess my question is, is that gas efficiency is that essentially retained fuel on the pipes? And then going forward, how should we interpret this to impact the earnings for this year?

Yes, Jonathan, yes, it is retained gas, and I don't think it was $0.08. I think it was more in the range of $0.02 to $0.03. Yes. $0.03. That was the efficiency gas. And moving forward, there's no question that gas commodity prices going to ultimately impact that efficiency gas number, and, gee, I think last year, it was probably averaged first quarter less than $4 or so. So it was a pretty skinny number this first quarter compared to the prior year's quarter.

Should we be thinking about this impacting the -- it was offset partly by Empire Connector. Can we get a sense for how much that offset there, and is there any sensitivity in terms of gas price that you can give us for how that might impact?

We have the gas price sensitivity table in the back includes both the impact for efficiency gas and Seneca production. So those are both rolled in there together. And I don't have the breakout right at my fingertips as to what that is. But I guess a very, very rough approximation, and, again, this is rough, we had normally seen about 3 Bcf of efficiency gas in a normal year at normal transportation volumes. So if you use that as a rough guideline, compare that to the throughput numbers that we have in the back pages, you can get sense for where that might be headed.

Got it Okay. Then going forward, are you going to break out the Marcellus production from the Appalachia production as you ramp up? Or will it be consolidated?

We'll probably just still report the Appalachian. We've already got a large breakout. We broke out the number of wells, Marcellus wells, drilling activity, but to get much more detail, I don't know that you gain all that much.

Great, guys, I appreciate the time.

Operator, do we have any more questions coming up?

Your next question comes from the line of Carl Kirst with BMO Capital. Please proceed.

Hey, good morning everybody, nice quarter. Congratulations, Jim. Question, first, Ron, you had mentioned about the range of the production for this year. When we look at the number of Marcellus Shale wells being drilled, should we still think of that as roughly half of those being turned to sales, and can you remind us kind of post Covington coming on line this summer what's going to be the biggest constraint towards ramping that up?

Well, the base forecast that we have, Carl, normally had a six-month delay built in, in terms of the drilling activities from the completion of drilling activities to the turning into line. To the extent that those wells are drilled in the Tioga area, we obviously won't have that constraint. So it's really a matter of -- Matt maybe can help me out in terms of where the locations are.

I just want to expand on Ron's comment about Tioga County. Even in Tioga County we will have cases where the particular pad we're drilling on now is a six-well pad. We'll drill all six of those wells before we frac any of them. So the production will be lumpy.

It's most efficient, most cost effective if we drill up a pad, frac the whole pad, then put it all on line. So the first well on that pad may be drilled six months before it comes on line. I think that's really what -- that's a big impact, plus there are wells that we'll drill on the western side of our acreage that are more kind of get a flow test and determine whether that's the next development area, which won't necessarily go on line for a long time. Then there's the EOG piece of the production which we have less control over and is a little more difficult for us to predict.

Right. Great. With respect to the two western wells right now, the one that's being fraced, the one that's getting close to TD, is that something where if those are material, I guess, in as much as perhaps they get close mimicking Tioga, would you guys be press-releasing those, or is it something that essentially we should be waiting until the next quarterly conference call, or is that something you can even address at this point?

Carl, I would expect that given-- there's a well Matt talked about in the eastern area that we would have talked about today, and then in these western areas, I would think we would lean toward disclosing that if it were material.

Okay. And then last question, if I could, I'll jump back in the queue, but with respect to the results this quarter, the LOE looked like it was a very nice number, low number, ex taxes. Is that something that we think can be sustained, or are we going to see that rise back up?

Well, one of the things that affects LOE is our production rate. So as production goes up, the unit LOE goes down. The other thing that has a big impact on our LOE is the cost of the gas that we need for steam fuel in California. So higher natural gas prices, while we still prefer them for our revenue side actually, the higher the gas price is the more it hurts our LOE in California.

Maybe I can ask that in another way. But to the extent that gas prices kind of currently stay in sort of this $5 range, and if you annualize fiscal first quarter production that basically gets you roughly to the midpoint or around there, under those two, if we kind of keep the production where it is, and where gas prices are, would LOE basically be staying in the same range then?

I think that's probably a reasonable assumption, Carl. If the average gas price for the year is equivalent to the average gas price for the quarter in California.

Great. Thank you, guys.

(Operator Instructions) Your next question comes from the line of Becca Followill with Tudor Pickering Holt. Please proceed.

Hey Guys, great results. Matt, can you walk through again-- I missed some of what you were talking about in Tioga County on the zipper frac, what happened and you said the average of the three wells was 6.7 million a day. I assume that excludes the wells where you had to abandon the frac. Can you walk through that again? Thank you.

Sure. We started the zipper frac. The way the zipper frac works, we have two parallel horizontal well bores, and we frac-- we alternate stages that in fracture treatment. So we're fracing one well bore, then the next well bore, back and forth as we work our way from the toe of the well to the heel. We got through the first several stages in both wells, then we actually had a perforating gun stuck in one of the wells.

Rather than taking the time to fish that perforating gun, we just continued to frac the other well. So we've completed the frac of one well. That well will begin flowing this weekend. Actually, I think it's probably beginning to flow as we speak. But I don't have a rate on it yet. The other well, we'll have to go back in there and fish out that perforating gun before we finish that completion.

Okay, great. That's all I needed. Thank you.

Your next question comes from the line of Carl Kirst with BMO Capital. Please proceed.

Hey, guys, sorry, just wanted to follow one one last item. With respect to the lease sale that was just done, if you guys are evaluating capital spent between the West and the East, as the West is kind of slowly in this nascent stage, should we be expecting perhaps more acreage being added in the east, whether it's through lease sale or perhaps even other agreements, or is it now that we're getting kind of a critical mass in the east we're going to stand pat, let's see what we get in the east, then perhaps ramp up dollars in the west if it so demands it?

Carl, I guess I will repeat our strategy for lease acquisitions in the Marcellus. We acquire acreage that is adjacent to our existing acreage that makes sense to acquire, and we also will look at large contiguous blocks in an area that we think may, in some way, be superior to some of our existing acreage. These DCNR blocks are in a very, very good part of the Marcellus, so these are big blocks that we like and that we were able to acquire at what we think is a very favorable price per acre. There's no reason why we would stop looking at those kind of opportunities, and it really has no bearing on what we're doing on the West side. In other words, we've got a plan for the West which is drill a handful of kind of test wells this year, get flow rates, understand processing, gas processing requirements, then determine focus areas to develop and prioritize those focus areas.

Great. Thank you.

Your next question comes from the line of Tim Winter with Gabelli & Company. Please proceed.

Good afternoon, gentlemen. Congratulations on another good quarter. I had more of a big picture question. Can you talk a little bit about strategy going forward as the CapEx budget grows and resources necessary to take advantage of the Marcellus grows? Should we just assume come 11, 12, just straight debt and equity financing to fund the Capital Expenditure program or how are you considering other creative structures, like an MLP or maybe a portfolio approach to the west assets versus the east assets maybe deploying, selling some of those and deploying cash into the east. Can you talk a little bit about that?

There were a lot of questions in there, Tim. Let's just generally talk about the CapEx which, those increase from about $500 million this year to over $900 million in 2012. So there's no question that we'll be increasing the CapEx, much of that is in that pipeline and storage area because of those big projects we talked about, and much of it is in ramping up in the Marcellus. Right now, even with all of the projects we have on the table, number one, we still a fair amount of cash.

Number two, I think this year we're maybe negative cash flow $103 million. So we're really in a pretty good position to lever up over the next couple years. Even with the projects we have on the table, we're still within our 50/50 debt equity ratio that we target. So we're in pretty good shape in terms of being able to allocate capital, in particular to those two areas.

Now, with regard to things like MLPs, we actually are looking at -- we have a study that's looking at the advisability of MLPs. We're always looking at various alternatives, certainly a number of different parties have approached us with regard to things like joint ventures. So all of those kind of mechanisms, all of those opportunities, we will measure on a case-by-case basis, but they'd have to be pretty compelling, given that I think we're in a pretty good position right now with where we are in our ability to lever up.

Okay, thank you.

Your next question comes from the line of Brian Horey with Aurlian. Please proceed.

Thanks for taking my question. It sounds like things are going well generally in the Marcellus. The question I had is-- there's been a lot of commentary about the issue of water use in the region and processing of frac water and so forth. And I'm wondering if you can provide some commentary, one, on from a little bit more of a macro perspective, how big a constraint do you think that is for the play in general, and what do you see the industry doing to try to manage that, and secondly, specifically what do you guys have in place to deal with those issues?

We are actively recycling all of our frac water. And I think more and more that's the direction the industry is headed. I think long term the processing of frac water may be one of the more important factors in kind of limiting the pace at which industry can move, but so far, I think industry is doing a good job of staying ahead of it. I don't think it will have any significant impact to our program.

Brian, it would be, I think it's fair to say, more significant impact if we were in New York as opposed to Pennsylvania, where that certainly the New York City communication, let's say, the New York City group is clearly working pretty hard in the watershed area of New York City, in the Marcellus to keep that fracing out. But in our case, I mean, we have been fracing for, I don't know, 40 years, probably since the '60s.

If the question is also about hydrofracing, that's a whole other, different case and we're not having any problems in Pennsylvania, and industry is addressing the issue of hydrofracing and potential regulation at the federal level, and frankly the EPA has determined that there is no significant risk, and the fracture stimulation is effectively regulated at the state level.

Okay, thank you.

Your next question comes from the line of Holly Stewart with Howard Weil. Please proceed.

Good morning, guys. Quickly, can you talk about some of the recent well results under the EOG JV and how much that contributed to production during the quarter?

Sure. Holly, the EOG MO has been not to frac in the winter months, so they drilled-- I think I said it in here, they drilled 22 wells and fraced I don't remember exactly what the number is -- they have fraced 12 and five are producing. The area where they're most active is our Punxsutawney development area. None of those wells are on line. We expect that first production toward the end of March. And they will bring on several wells kind of back to back and ramp that production up gradually in that area. I really don't have any new flow test results because it's been a long time since they've fraced a well. But in general, these have been wells in Punxsutawney that are, oh, from say maybe the weakest wells are a little less than two million a day IPs, and the best are approaching four, but a little less than four.

And then production impact during the quarter?

During the upcoming-- oh, I'm sorry, during the fourth quarter-- first quarter, our first quarter, the production impact, we had about pretty close to half a Bcf of production from the Marcellus, and 60% of that was from our two wells in Tioga County. Net production. The remainder is from the EOG wells.

If you want to talk about the upcoming quarter, we can do that as well.

Well, as we stand today, the production -- our Marcellus production right now is about 80% from our three wells in Tioga, and 20% of our net production is from the five producing wells from EOG. Keep in mind, two of those EOG wells, the two earliest wells, are wells where we have a minority interest. The other three we have a 50% working interest and a 60% NRI.

Perfect, that's all I had.

Your next question comes from the line of Ray Deacon with Pritchard Capital. Please proceed.

I had a question for Ron about the pipeline announcements. Do these smaller projects you announced, do they change the scope of the West-to-East line, and can you just talk about what the earnings contribution could be from that by the time it is on-line if it does move forward?

They don't change the overall scope, Ray. They change the timing. We had talked about through time that the entire West-to-East Appalachian lateral was such a big project that it was tough to get all of the market support all at once to allow us to move forward.

So we broke that into smaller pieces, and essentially the projects that we have now, or that Dave talked about and that we have in the release, are kind of the central portion of the West-to-East corridor, and on either end. And then ultimately we're going to hook that all up together with smaller projects. I think it's a little early to start talking about the earnings contributions, specifically the timing of those because most of these are projects that will be coming on in late 2011, and they will have -- may not even affect or impact earnings for 2011. We're talking more of a 2012 time frame.

Got it. Thank you.

At this time, there are no further questions. I would now like to turn the call back over to your host for today, Mr. Jim Welch. Please proceed.

We'd like to thank everyone for taking the time to be with us today. A replay of this call will be available at approximately 2;00 p.m. Eastern Time on both our website and by telephone and will run through the close of business on Friday, February 12th, 2010. To access the replay on-line, visit our Investor Relations website at investor.nationalfuelgas.com, and to access by telephone, call 1-888-286-8010, and enter passcode 42539167. This concludes our conference call for today. Thank you and good-bye.

Ladies and gentlemen that concludes today's conference. Thank you for your participation. You may now disconnect. Have a great day.