EQT Corporation (EQT) Q3 2012 Earnings Report, Transcript and Summary

Welcome to the EQT Corporation Third Quarter 2012 Earnings Conference Call. All participants will be in listen-only mode. (Operator Instructions). After today’s presentation, there will be an opportunity to ask questions. (Operator Instructions). Please note this event is being recorded. I would now like to turn the conference over to Mr. Patrick Kane, Chief Investor Relations Officer. Please go ahead.

Thanks Laura. Good morning, everyone, and thank you for participating in EQT Corporation’s third quarter 2012 earnings conference call. With me today are Dave Porges, President and Chief Executive Officer; Phil Conti, Senior Vice President and Chief Financial Officer; Randy Crawford, Senior Vice President and President of Midstream, Distribution and Commercial; and Steve Schlotterbeck, Senior Vice President and President of Exploration and Production. This call will be replayed for a seven-day period beginning at approximately 1:30 p.m. Eastern Time today. The phone number for the replay is (412) 317-0088 and the confirmation code is 10006606. The call will also be replayed for seven days on our website. As you already know, this is the first quarter for EQT Midstream Partners, ticker EQM and its results are consolidated in EQT’s results. There was a separate Press Release issued by EQM this morning and there is a separate conference call at 11:30 today, which creates a hard stop for this call at 11:25. If you are interested in listening in on the EQM call, the dial number is (412) 317-6789. In just a moment, Phil will summarize EQT’s operational and financial results for the third quarter 2012, which were released this morning. Then Dave will provide an update on our strategic operational matters. Following Dave’s remarks, Dave, Phil, Randy, and Steve will all be available to answer your questions. But first, as usual, I’d like to remind you that today’s call may contain forward-looking statements related to future events and expectations. You can find factors that could cause the Company’s actual results to differ materially from these forward-looking statements listed in today’s Press Release under Risk Factors in the EQT Form 10-K for the year ended December 31, 2011 which was filed with the SEC, as updated by any subsequent Form 10-Qs, which are on file at the SEC and available on our website. Today’s call may also contain certain non-GAAP financial measures. Please refer to this morning’s Press Release for important disclosures regarding such measures, including reconciliations to the most comparable GAAP financial measure. Now, I’d like to turn the call over to Phil Conti.

Thanks Pat, and good morning, everyone. This morning, EQT announced third quarter 2012 earnings of $0.21 per diluted share. That compares to EPS of $0.45 in third quarter 2011, after the adjusting for the sale of Big Sandy. Operating cash flow was a $176 million in our third quarter of 2012, compared to $191 million for the third quarter of 2011 and adjusted cash flow per share was a $1.18 in the current quarter, compared to a $1.28 in the third quarter last year. Our operational performance was outstanding again this quarter, with 33% higher production volumes, 30% higher gathering volumes and continued low per unit operating costs. However, as I’m sure, you are aware commodity prices in the recently completed quarter were significantly lower than they were last year, resulting in both lower operating income and cash flow. This quarter, as Pat mentioned was our third with an MLP. As you know EQT Midstream Partners complete its initial public offering in early July. The EQT Midstream Partners results are consolidated in EQT results and we recorded a $4.8 million or $0.03 per diluted share deduction in the quarter for the portion that went to non-controlling interest unit holders to arrive at the net income to EQT shareholders. While there is no gain on the accounting books as a result of the IPO, on the tax books we recognized a gain of approximately $110 million. That gain results in additional cash taxes for 2012 of approximately $13 million as we were able to offset most of the tax obligation with our tax yields from intangible drilling cost deductions and tax depreciation. Another non-operational variance from the norm this quarter was our effective tax rate of 24%. The lower effective tax rate was due to less income on our companies that…

Thank you, Phil. We continue to focus on achieving our objective, maximizing shareholder value, via an overarching strategy of economically accelerating and a monetization of our asset base and prudent pursuit of investment opportunities, while living within our means. The tactics continue to evolve somewhat, based upon market conditions and the fact that we are completing some of the tactical steps outlined previously. We took three major steps, all related to our Midstream business, so far in the past two years with the sale of our only processing plant and our Big Sandy Pipeline in 2011, and our successful IPO of EQT Midstream partners mid-year 2012. We still have more work to do as we look forward to accelerating the development of our vast opportunity set. We have two plays that we are not currently developing. Our CBM acreage representing about 250 Bcf of proved developed reserves but not much additional 3P value at current market prices and our huge Huron Play with one Tcfe of proved developed reserves and 7.7 Tcfe of 3P reserves. We will look to realize value from these two plays, but probably in different ways. It is most likely that we will eventually sell the CBM play outright since there is not much value in the undeveloped locations at anything close to current prices. To that end we did do some work to determine what potential buyers might be willing to pay for those assets. For the time being the transaction market value is not high enough to want further pursuit of a cash transaction. We will revisit this issue as natural gas prices recover, thereby increasing the value of the PDPs. The Huron on the other hand has significant value in the undeveloped locations at the current strip. So we are more likely to…

Thank you Dave. This concludes the comments portion of the call. Laura, can we please now open the call for questions? Question-and-Answer Session

(Operator’s instruction) And our first question is from Neal Dingmann of SunTrust.

Just a quick question on the -- just look at your Marcellus horizontal well status. It looked like, as far as just a well spud down just slightly third quarter versus second. So I'm just wondering, the rate there, I guess that you see going forward is that what kind of growth rate, just on total well spud and then but it looks like frac stages, might be extending just slightly if you could a little bit on how you're spacing it.

Hey, Neal, just so you know, we have Steve Schlotterbeck and Randy Crawford sitting in with us and also to help answer questions and this sounds like a great one for Steve.

Yes, Neal, I think that's just the sort of the normal fluctuation of timing. You see a little bit lower well count due to drilling longer laterals but I don’t think there's really much to read in there. We still expect to end the year around 130 - 132 well spuds. So really no new news there. I think on the frac stages, you didn’t specifically ask about it but the fourth quarter is going to be a very busy quarter for us in terms of bringing online and new frac stages and for reference over the past four quarters, the biggest quarter for us in terms of new frac stages online was three quarters ago with 578 stages. In the fourth quarter this year we expect to bring online over 1,100 new stages. So we have a lot of new production coming on this quarter.

It’s a big number and then Steve, just to follow that, there didn’t appear to be any takeaway issues. I was just noticing on the wells complete but not online. Is that related to the takeaway or not necessarily?

There’s always a hand full of wells that waiting on our pipeline to be completed but for the most part its timing of these multi well pads. So we happened to hit a spot here early in the fourth quarter, where a number of large pads are ready to go. So we would be bringing a lot on so the backlog will fall, really a trivial amount of pipeline or capacity issues involved in those numbers?

Okay then lastly, in that same area, it sounds like you obviously are doing now primarily pads. Does that mean, Steve, I guess you just want to look on kind of unit basis that you'll be able to get more wells in some of these key areas because of that? I guess the question would be, how many wells max per pad and then how many, if you hit sort of some of these key areas, how many wells could you get In some of these units?

Well we have been focusing our efforts in two key areas, one the Greene County area, which is a dry gas area but is our most productive area. We focused a lot of our attention there this year and the second area is Doddridge County, which is higher Btu gas. It's still equivalent from an economic basis to Greene County. So we've already been focusing there. You're going to see pads range from four wells to many as ten wells. A lot of it is depending on the specific acreage position in those areas, but a clear goal of ours is to maximize the number of wells per pad, which we take as a big economic advantage and continuing to drill with longer laterals as we can.

And our next question is from Amir Arif of Stifel Nicolaus.

Just a quick question on the unused transmission capacity, the $5 million charge. Can you just tell us, give us some color, where that was? Is this up in the Tioga area and what the total liability might be over the next few quarters or so?

The capacity is related to the Tennessee 300 line, and as we've said, we've got long term and short term lease for that and we continue to see the value in that capacity over the long term. It's a constrained area, and it is centered in and around the Tioga, Northern Pennsylvania area.

And how much is that total commitment, that you might not end up using in terms of costs or capital?

Well, it's really a contractual asset. We have contracted $350 million a day capacity and we continue to utilize that as we ramp into our production, and we're executing on a short term, some additional releases and in the long term, but the value associated with that capacity as I said in a constrained area, is seasonal in nature. So it's difficult to predict how that will go quarter-over-quarter. There's a lot of seasonality with it.

And as you are aware, when we first enter into those kind of agreements, since these are new pipes because there's growth or new expansion, you have to enter into an agreement to take out all of the capacity that you're going to get for that particular project, all up front. It's just that as Randy said, with our own production, we're ramping into the need for it; so some of it gets reserved for our own use, for our own produced assets. In some cases we have contracted out for a two-three year period et cetera, on pretty much a firm basis; but then we always keep some that's a little bit on of a short term cushion versus what our current needs are, which would allow us to make sure we can move our own production if it increases more rapidly than expected or that we would sell into the market. And what we're talking about then, is that what happens with that additional portion only, and that's the piece that has tended to be, as you would imagine, a bit seasonal. So for the most part you're making money on the first and fourth quarters and you're losing a bit of money in the second and third quarter, but we did not enter into that capacity just so you know for trading purposes. That is designed over time to be moving our own produced gas.

Okay, that’s fair. And then can you just give us some timing in terms of 80,000 acres in Tioga, the swap or the sale as well as timing on when you decide what to do with the Huron Berea?

I’m sorry, I am not sure if we heard that. Is it possible for you to speak up a little?

Sure, just the timing in terms of the selling or swapping the 80,000 acres that you’re talking about in Tioga, where there is a 2Q (ph)?

It’s actually 8,600 acres. So I must not have been clear on my comments. I apologize for that. It is 8,600 acres in Tioga and I just say that we’re in the midst of finding out what might be out there for that property. I don’t know that I’ve got any specific timing to offer off and incidentally, our attitude is that all the assets at some point are for sale. So sometimes we run formal processes and sometimes we just kind of do market checks. So it really kind of depends on market conditions, what would happen there and I would say and the Huron that we are in the early stages of looking at what the alternatives are because we do suspect that it’s likely to be something a little bit more structured with the Huron, since the issue there is the development opportunity, we think has so much value in it. But we’re going to have to figure out how we can best extract that value.

Okay, and then just one final question. In terms of the 30% production growth you played out for ‘13, how many wells does that require in terms of drilling in ‘13?

See, I don’t know that it requires many wells in ‘13. You’re aware of the lag, we’ve got this extensive lag, especially with multi well pads; I guess maybe we’ve even got a little bit longer lag but, but, gee Steve, I don’t know , we probably don’t need all that many wells?

It doesn’t require lot of drilling next year. 2012 is drilling the majority of our growth in 2013.

Now by the same token, that means of course that most of the wells that we drill in 2013 are not really going to be contributing much to 2013 volume, lest you think that we could race way, way higher than that; once you get what Steve, about the first quarter of 2013, it’s really not going to contribute much to 2013 volumes.

Okay and then the ‘13 guidance is coming out December in terms of the capital side?

Yes, the formal guidance, yes, because that will get blessed by our board and we typically think of it at our December board meeting. It’s typically in the very end of November, the very beginning of December, and that’s when the Board approves the capital budget.

Our next question comes from Ray Deacon of Brean Capital.

Randy I had a question, as far as, when you talk about doing a small dropdown, what sort the range of value you could do that without having to issue units at EPM.

We’ve got, obviously a variety of options with the inventory that we have at the EQT; and so again we have access to $350 million on a revolver that we could access, we could then draw. Certainly we wouldn’t be looking to do all of that but we have that opportunity, I don’t know if….

It was actually Dave that mentioned that. We would be thinking about something pretty small, just as Dave mentioned, try out the process. We have to go through a Conflict (ph) Committee with EQM and there’s counting implications that we need to sort of try out. So if can, we’d like to try to do a small one before we do a large one.

Yes, if you are trying to get a sense for modeling purposes for EQT, I don’t think you really need to pay much attention to that. I think you would be looking more at, what it would look like, what a larger drop might look like? You should get more deeply into 2013.

Okay, and just big picture thoughts on the Marcellus, I believe the Marcellus is producing about 6.4 Bs a day. Where do you guys think that is in the year? I feel like I’m hearing a lot of people talking about cutting back. I guess do you guys have a view?

I guess there are some areas in the Marcellus, we’ve talked about tiering, and I might have a comment and Steve I think will have a comment but when we talk about the economic tiering let’s say within the Marcellus, we have observed that there has been fair amount of cutting back in the lesser, kind of the lowest tier, which seems like it’s generally speaking, geographically more like in the middle of the play. Not really so much in the North Eastern part of the play or the South Western play. Steve do you have?

I think that’s very true. The only thing I would add is we’re not really up in the Northeast part of the play but we do continue to hear about the Midstream constrains up there. So that might moderate what happens there over the next year or two but I think in this town that we’re at, where we have a lot of capacity, we have great economics. So I think it’s going to be continued significant activity down there.

Yes, we hear a lot of about the number of wells that are prevented from being turned in line due to the Midstream but we really don’t have very much direct experience with that. From our prospective, most of it, as Steve alluded to it and answered to an earlier question, is much more just kind of some little timing issues but we don’t actually see those things that get reported on as been big, large backlogs of wells that evidently get represented as has being completed and ready turn in line but not able to turn in line, and we understand if that’s happening, the people in that part of the play might decide they don’t want to drill more wells for a while. That would make sense, but we don’t actually have any direct experience with that in the South Western part of play.

Got it. And I feel like I heard for a couple of years that differentials were going to go away in the Marcellus and I'm seeing $0.20 to $0.30 premiums on Tennessee. Any sense with that that’s going to change going forward and are you benefiting as a result right now of having that locked in capacity on Tennessee.

Ray, this is Randy. As I said, it is a constrained area. There are wells that we hear that are continuing to be turned in line and so we think that capacity certainly near term and maybe into the future, as other development goes will add value and so over the calendar year, with the long term and short term leases, we have been able to recover our cost, plus after this year.

I’ll tell you, we have the sense that most companies that we kind of think of as our peers, kind of similar sized and stuff and like have taken a kind of a similar approach with making sure that they’re lining up this capacity. I guess we’re presuming that there must be other folks who did not take that approach, but the ones that we follow most closely we could tell took approaches that more or less were similar to what ours were, where you take big positions on these pipes when they do get built and we’re certainly happy that we’ve done so. Though that said, if you are planning to build a big industrial facility, we’re prefer it that you build in South Western PA or Northern West Virginia.

Just one quick one; is the 30% growth in 2013, you’re not assuming that you’re able to make something happen in the Huron to achieve that, it sounded like.

No that doesn’t include anything in the Huron. As a matter of fact, the reality is that would mean it has to overcome a little bit of natural decline in the Huron. I don’t have numbers in front of me but it’s just, we haven’t been drilling there for several months and unfortunately we can’t make the volumes go up without drilling.

And our next question is from Becca Followill of U.S. Capital Advisors.

Two question for you. One on the Huron, if you look at another source of capital for that, E&P side and that’s an area that requires incremental infrastructures. So how do you handle the capital for incremental infrastructure?

Well, to start with, if it were an incremental development plan, we would be targeting the parts of the play where less infrastructure was necessary. So, that’s certainly something that we’re aware of. To some extent, depending on the pacing, one can simply kind of drill into the decline as it were. To really take broader advantage of the development opportunity though, as you suggest Becca, we would have to have paired with it a Midstream program. But when we are looking at the solutions, we are taking that into account. We never really just look at the capital that would be associated with the development. We would look at the capital that would be required for the Midstream build out.

The restructuring, and I know it’s in early stages but that structuring, it could come for two different sources of capital, one for the Midstream and one for E&P, or one source. There is options there?

That is correct, yes. And incidentally, it could for the whole Huron or we could break it up into pieces, either around Midstream, the way I just described or something that followed more natural geographic boundaries. So, we are open minded and seriously, I know I have said this before on calls. Maybe people think I’ve been sarcastic but if there are good ideas that folks, we are happy to hear them. We know it going to take a creative solution and we know that we don’t have a monopoly on those.

And then my second question is, we saw that you guys had a permitted a couple of wells in Guernsey County in Ohio and I'm assuming, does it look like they are Utica permits? Can you talk about acreage position there and plans for pursuing drilling where those permits are?

Yes Becca, this is Steve. You are right, we did permit a couple of wells or I think one is permitted, one is permit applied. We hope to drill one or two test wells in Utica this year. We have, at the current time an immaterial amount of acreage in Utica. Our strategy is to drill one or two test wells, see whether we like the play or not, and if we do, at that point we would consider whether we want to build an acreage position in it. So right now it’s fairly immaterial.

And our next question is from Christine Chau of Barclays.

Can you remind us how quickly you expect to ramp up to the 120 million a day at the MarkWest plant when it’s up and running]?

Geez, I don’t know it is almost measured in minutes probably.

Okay. So immediately.

Well, once the plant, it’s not just a matter of the plant being turned in line. They then have to just normally, as you would do with any plant, they are going to have to run through a variety of tests. So it’s not as if the volume would immediately go to capacity on Day 1 but if you put aside plant issues, I think we’d probably we be ready to flow….

I think realistically it's probably over a couple of months to get those wells in line, going to the play, but it is, from the scheme of things very, very quickly.

Okay and then you talked about possible expansions with MarkWest. Do you have like a size? I know you said timing is still being worked out but….

Well, as David said in his comments, we’re looking at a 100 million of incremental capacity above a 120.

And then when I look at the map in that table detailing how many acres you have within each type curve in your Analyst Presentation, you guys are drilling most of your wells by the border of Southwest PA and West Virginia where it’s a mix of wet and dry and I’ve realized that only 35% of your acreage overall is in the wet part but how should we think about the pace that you drill up the wet acreage there might be a lower (inaudible) but may or may not be better economics, depending on where liquids faces are. Do you just primarily focus on the Nine B (ph) wells that are probably drier and have higher initial rates and better production declines or what kind of dislocation does there have to be between NGLs and natural gas that make you think that net present value is better in some of the wetter wells.

Right now for us the economics between the Doddridge County wet area we’re focused on and the Greene county dry area are pretty equivalent. So we really are drilling for economics but we obviously have to factor in capacity. So if you can’t float a gas, your economics generally don’t look too good but right now they are fairly equivalent at current gas price, or liquids price spread. So if that changes then we may want to focus on one area more than the other, although there are also operational constraints, how many loans we can put in one small area. But right now it's pretty equivalent.

Okay so if everything stays the same you would say it's going to be dictated by infrastructure pretty much, it sounds like.

Well infrastructure and land issues. Sometimes if you think you have a chance to fill in some land positions that would allow you to either put more wells on a pad, have a longer laterals, that can obviously influence some of our timing too or (inaudible) prioritization.

Okay and then you guys have talked about how some EQT shareholders have voiced concerns that Equitrans was placed too cheaply into the MLP and recognizing that there is a need for balance between doing what's right for EQM and EQT shareholders, how are you thinking about the potential expansion opportunity at Sunrise that can potentially double your initial capacity at very-very low cost? Should we think Sunrise gets strapped in more of a typical multiple and maybe we will use, Big Sandy as a bench mark and EQM getting the benefit from that organic opportunity or will EQM have to pay up front with the higher multiples?

I don't believe any of us; certainly I have not; but I don’t believe any of us have commented that we have gotten complaints about the pricing of EQM, to the extent we've commented, I'd think I'd characterized it more as recognizing that there's a tradeoff, between what's in EQT's best near term interests and what's in EQM's best near term interest though our view has been that a fair price is in the long term best interests of both entities, and that's really what we take into account. That does mean to your specific question about the Sunrise expansion and incidentally, this wouldn’t just be Sunrise. This will apply to any number of candidates for sales from EQT to EQM. To what extent if there is further investments to be made, do we make the investments at EQT and sell into EQM at probably a lower multiple on a higher cash flow, versus selling in before making the investment at a higher multiple off a lower cash flow and I think it's fair to say that that is going to be done on a case-by-case basis, there's no interest at the EQT level in selling assets to EQM on the cheap and we also don’t think that it's in the long term best interest of EQT, given our position at EQM to somehow try to get an overly inflated price either. So it will be a balance and it will be a tradeoff, and it's going to be particularly difficult as you’ve pointed to find that when there's expansion opportunities.

And then lastly, just an accounting question; how much of the $7 million decrease in storage and marketing at Midstream was attributable to unrealized losses on derivatives and inventory? Do you guys have that on hand?

It was a little more than half of it I believe. And that's a non-cash thing that sort of unwinds over time. It's sort of an oddity in the accounting. A little more than half of it was that.

And our next question is from Michael Hall of Baird.

I guess a couple of just real quick ones, my (inaudible) has been answering. First on the Huron capital, would you characterize what you're considering as more temporary in terms of a source of capital or something more permanent like another (inaudible).

I’d say what we’d prefer to do is to find something that would a more persistent source of capital, but that’s only because we have that 7 Tcf, almost 8 Tcf of 3P reserves. It’s that logic. And the nature of the development there is it’s just going to work a lot better, if once we get reenergized there and remobilized, if we are able to stick with it for some period of time. So if temporary meant a year, it’s probably not all that interesting. It would be more interesting if we thought that it had the potential to go on and on. But as far as that goes I’m not sure that I had commented on any specific vehicle that we might use other than, it would be better if we thought that it gave us access to capital over a longer period of time as opposed to a capital that could only support the development for a short period of time.

And then I guess in some other related thinking, related to and Midstream leads down the road, around that program, that something around EQM could see it off or feed into a well or…

Absolutely, that’s relating back to the prior question about some of the tradeoffs. At this point, it’s probably fair to say that for the most part, the EQT Huron Midstream position is a little less interesting from the perspective of a sale to EQM, than it would be if we were to reenergize the development there and you had at least stable and maybe even somewhat growing volumes. So, yes actually both things are true. It’s not just that EQM could be an interesting source of capital for that. It’s that it’s actually a more interesting source of capital, if it’s paired with growth.

(Inaudible). Um and then (inaudible) the outlook you provided, does that include capital from dropdowns, further some transactions of (inaudible)?

I’m sorry which part of the outlook are you referring to?

The 30% plus growth for EQT in ‘13.

No, we would say that, that doesn’t really require any form of external capital but that’s really because the lag is such that most of the growth that we anticipate in 2013 is going to result from wells for which most of the capital will have been spent by the end of 2012.

(Inaudible) in ’13 moving into 2015 (ph).

The reason for continuing to push for external capital, like from EQM in 2013 is primarily to facilitate growth in 2014 and 2015 and obviously we’re not about growth rates but to continue to facilitate growth in the out years.

Okay and do you have any updates on average initial production rates? It seemed that during the last quarter, on your Marcellus program, maybe any additional color around how existing rates are stacking up versus your where you are, tight curves and specifically related also to the new completion geometry, you’ve talked about in the past?

Mike this is Steve. The only thing I really have to offer, I don’t have specifics on average IPs but I will say we continue to be very comfortable with the tight curves we provided. We see no reason to adjust those. I will say since we focused on lot of our drilling in the Greene County area, that’s one of the best areas for the reduced cluster spacing frac technique. So we are, on average doing a lot more stages per well. For example in the fourth quarter, for those wells I mentioned that will be turning in line, those will have 28.5 stages per well on average and the average stage length is 192 feet. So the modified completion technique has 150 foot stages. The base design has 300 foot stages, so you can tell from that if there is high percentage of wells with the new technique.

And our next question is from Holly Stewart of Howard Weil.

Just really one bigger picture question, I guess from Dave and certainly not trying to run around the December budget announcement but you…

Those kind of questions, my colleagues let me answer to it, the big picture.

You’ve talked about in the past, kind of the cash flow CapEx deficit being filled with these asset sales, and given really you’re just kind of kicking off the process here, how should we think about the budget in December? Should we think about it at a lower level, given that you’re very early in the process or just, bigger picture trying to get sense for how to think about it?

Well, I don’t want to make any commitment. As I said before I don’t want to make any news on this call but it isn’t really so much for legal reasons. It’s because the Board hasn’t approved a budget yet. But the construct is that we would like to routinely, and this is part of the idea with EQM, is we would like to be able to continue to routinely invest anyhow 300 million, 400 million, something like that or so more than what our internally generated cash flow would allow, but that’s just because we think that that’s what optimal overtime from a perspective of monetizing our asset and opportunities sets. So in that regard I wouldn’t say that the thought process has really changed versus the thought process that went into 2012 numbers, the 2011 numbers. Where it comes out specifically as far as the numbers is really where it’s hard to go to, but I don’t see that there is a particular need, given the capital we’ve already raised that you should be assuming that we would only be able to spend based on operating cash flow in 2013, because we’ve already been raising money from other sources. So how much do we have on the balance sheet now as far as cash?

$639 million. You’ll see that in the queue later today.

So we’ve been trying to stay a year or two ahead with that and I would say that’s kind of mindset coming into the 2013 budget, again without trying preempt the Board’s authority in deciding what the capital budget should be. Is that at all helpful or is that, kind of a politician’s answer.

No it is helpful. I was just trying to get a sense if we saw a fairly large number, is that because there is plans to do something or, just trying to really get sense on, if you guys had all felt held up by this process?

No I think that’s just though, I think where we are and actually it was one of our investors who used this terminology, but we have a variety of leverage that we have to pull to be able to generate additional capital and we think it’s the right thing to do to move, (inaudible) management if you will to move money from the opportunities that aren’t as interesting to us or that fall further down our priority list and from my perspective. I certainly hope this is the way people at the company look at it. It’s just an ongoing process. That’s not just a 2012 or 2013 process. We are going to be doing that for some period of time. We are going to be looking at which assets would be best. We know we are going to make the money by monetizing molecules and to the extent that we are selling them, one molecule at a time versus in bunches, is really what we have to decide and I think that’s the issue that we’re going to be facing strategically for a period of time, for a more than a couple of years probably.

And next we have a follow up question from Michael Hall of Baird.

Yes, thanks for the follow up. I just wanted to quickly (inaudible) of last quarter and I don’t know if there is any updated thoughts but if you have updated color, it would be appreciated around, thoughts on the utility distribution business and as it relates to that as a source of capital down the road. Any updated thoughts around that?

Mike, I’ve been informed that we’ve run out of time because of the upcoming event. Actually we probably have run out of time, but our thought process is the same. Strategically there is nothing that’s changed. We do have a list of things that we’re working through, as you’ve heard on a number of the calls but that’s one where I definitely don’t have any news that I wish to make on today’s call but our strategic perspectives have not changed.

And this concludes our question and answer session. I would like to turn the conference back over the Patrick Kane for any closing remarks.

Thank you all. I would like to just thank everybody for participating and will look forward to the next quarter. Thank you.