EQT Corporation (EQT) Q4 2007 Earnings Report, Transcript and Summary

Good morning, ladies and gentlemen. My name is Vanessa and I will be your conference operator today. At this time, I would like to welcome everyone to the Equitable Resources 2007 Earnings Conference Call. All lines have been placed on mute to prevent any background noise. After the speakers’ remarks, there will be a question-and-answer period. [Operator Instructions]. Thank you. It is now my pleasure to turn the floor over to your host, Mr. Patrick Kane. Sir, please go ahead.

Thanks Vanessa. Good morning everyone and thank you for participating in Equitable's year-end 2007 earnings conference call. With me today are Murry Gerber, Chairman and Chief Executive Officer; Dave Porges, President and Chief Operating Officer; and Phil Conti, Senior Vice President and Chief Financial Officer. Phil will briefly review the 2007 financial results that were released this morning. Then Murry will provide comments regarding Equitable’s operational performance, our reserve press release, which was also issued this morning and our future prospects. Following Murry’s remarks we will open the phone lines for questions. But first I would like to remind you that today’s call may forward-looking statements related to such matters as our projected well drilling programs and infrastructure development initiatives, reserves, financing plans, the move to thee reporting segments in other financial and operational matters, including production and daily sales volume guidance. In addition, we will discuss probable possible and un-risked reserve potentials today. And the SEC guidelines strictly prohibit the Company from including such reserves and SEC filings. Before turning the call over to Phil, I would like to encourage you to anticipate in the 2008 Analyst Conference which is scheduled for March 11 and we will do that midday in Pittsburgh. I will send more details out in the middle of February. The conference will be webcast also for people that will not be attending. Finally, it should be noted that a variety of factors could cause the Company’s actual results to differ materially from the anticipated results or other expectations expressed in the forward-looking statements today. These factors are listed in today's earnings release, the MD&A section of the Company's most recent Form 10-K, our 2007 10-Qs, as well as on our website. I would now like to turn the call over to Phil Conti.

Thanks Pat and good morning everyone. As you saw in the release this morning, Equitable announced 2007 earnings per diluted share of $2.10, which compared with earnings per share of $1.80 in 2006. The ’07 results include a net gain of $126.1 million from the sale of approved reserves in the Nora field deranged resources earlier in the year. There was also a $10.1 million charge in the fourth quarter associated with terminated acquisition of Peoples Gas and Hope Gas. Given the reserve update, Murry’s remarks will be lengthier than normal. So, I will try to keep the summary of 2007 fairly brief. Staring with supply, the ’07 supply performance was driven by higher revenues due to higher realized prices and higher sales volumes, which were more than offset by higher costs resolving from reserves for certain royalty disputes that we took in the first quarter, as well as other legal costs and higher operating costs supporting our growth initiatives. Year-over-year comparisons of supply are somewhat distorted by the fact that in 2006 we had operating income from the sold Nora properties for the full year, while 2007, we only owned those properties for four and a half months. I mentioned price and sales volumes, the average well-head price in ’07 was about 3% higher even though NYMEX declined about 5% year-over-year. The higher effective price for the year came as a result of higher average hedged prices and a lower hedge percentage in 2007 versus 2006. Our 2008 average hedge position is about the same as it was in 2007, but as you saw on the table in the release, in 2009, the average hedged price on our swaps increases by $1.29 per Mcf and the percent hedges drops considerably in 2009. So, if the market stays near current levels, we expect a sizable increase in our effective well-head price in 2009. I mentioned volumes were also up. We are reporting 0.09 Bcf increase in total sales volumes in ’07. But to get a clearer picture of our operational progress, you would have to adjust for lost volumes on the sale of the Nora Field properties. We make that normalization volumes were actually up 5.4% in 2007. In the fourth quarter, reported sales volumes were 0.6% higher than the same quarter last year. But again, after adjusting for the assets sale, the growth in sales volume was more like 7.5% versus the same quarter in ’06. Operating expenses and supply were up $18.7 million in 2007. SG&A expenses were up about $9.5 million, primarily due to the charge for the royalty dispute I mentioned a minute ago. Reported gathering and compression expenses were essentially unchanged compared with ’06 and were down quite a bit in the fourth quarter. However, you will remember that our 50% share of the Nora gathering activities is now reported in equity income. So, those gathering and compression costs did not impact operating income for the second half of ’07. That change coupled with the absence of a $3.3 million pension charge we recorded in the fourth quarter of 2006 more than accounts for the decrease. If you adjust for those items gathering and compression expenses increased by approximately $10 million for the full year, due to higher activity levels, including higher labor, electricity, compliance costs, and insurance expenses. The remainder of the increase in operating expenses was primarily due to DD&A expenses as a result of our ramp up drilling and infrastructure investments in the supply business. Moving on briefly to utilities. Of course, the biggest impact on utilities results was a termination of the purchase and sale agreement to acquire Peoples and Hope. Utilities wrote-off $10.1 million of deferred transaction expenses upon the termination of the transaction in the fourth quarter. For the year, Peoples and Hope related expenses, including net charge, totaled $21 million and write-off and the other transaction related expenses associated with the Fell Dominion deal show up in the utilities SG&A expense. From an operating standpoint, utility revenues were $10.3 million higher than ’06, for two main reasons. First, as you saw in the release, weather was colder than last year, although, weather in 2007 was still normal warmer than normal. And second, natural gas prices were very volatile in 2006, proving our marketing group with the opportunity to take advantage of our asset position and achieve higher margins in that business. As is typically the case, the majority of those margins will recorded in first and fourth quarter of 2007 won the contracts settled. We expect quarterly results to vary significantly based on market conditions and the timing of contract settlements. But for 2008, full year operating income for marketing should be in the range of the ’06 and ’07 full year results from that business line. A couple of other quick items. Income taxes, one change on the horizon that you may not have considered is with regard to our cash tax position, because of the significantly ramped up drilling and midstream capital expenditure. And you would have seen in the press release in December, those are each going to be in excess of $500 million in [Technical Difficulty]. Generating far greater deduction for tax purposes than ever before. As examples, approximately 70% of the cost drilling our vertical wells and 75% of the cost of our horizontal wells are considered intangible drilling cost or IVC as they are often referred to. And those can be deducted in the year that the expenses incurred. Also, much of the midstream investment qualifies for an accelerated depreciation method. As an example, about 75% of those investments are deducted in the first full year following the asset being put in service, even though, physical asset lives are often 25 years and longer. The result of all that is Equitable expects to be in the net operating lost position for tax purposes and anticipates relatively minimal cash taxes for the foreseeable future. That is a fairly dramatic change from the recent path than we have regularly paid out approximately 15% to 20% of book pretax income in the form of cash taxes. A quick word on financing. Despite the termination of the Peoples and Hope transaction, we will still need to access the capital markets in 2008 and beyond. As Murry has discussed numerous times in the past and will elaborate more point in a minute, we have a substantial number of profitable investment opportunities to pursue in our production in midstream businesses. And as a result, we will be spending in excess of our operating cash flow for at least the next several years. We expect to fund our growth plan over time, with debt equity and possibly other securities that have equity content, such as hybrids. We intent do minimize the use of common equity, while maintaining an investment grade rating and we will explore all viable alternatives to common equity. In the near-term, including our current net short-term debt balance of between $400 million and $500 million and our 2008 CapEx plan, net of cash flow from operations in 2008, we expect to raise a little over $1 billion in the capital markets this year. As a first step, we plan to issue up to $500 million of conventional public debt in the first half of the year, and we will follow that with more debt in securities with equity content. We reviewed our plan with the rating agencies and that plan is fully reflected in the current ratings. I know you would like to have more specifics on that, but given volatile market conditions and ongoing dissuasions with the rating agencies, it doesn’t make sense for us to go further than that at this point. Our history that we are mindful of the balancing act between our credit rating and investor dilution and we believe we have a history of working in the long-term best interest of our shareholders, and we will continue to do that. And with that I will turn the call over to Murry.

Phil, thank you very much. My reports are little longer than normal today, because there is a lot to go over. Bear in mind as Pat said, we will have an Analyst Conference in Pittsburgh on March 11 and we will go into significantly more detail on a number of items that I am going to tough on today. First of all, let’s start with the impact of horizontal drilling Equitable. I am now comfortable that results of our horizontal drilling technology provide us with the sustain potential for organic reserve and production growth. The implications of this fact are far reaching and are quite important to our future development of the region. In particular, the results from horizontal drilling give us the courage to build infrastructure that we were hesitant to build in the past. And we were hesitant because of the lack of confidence in the ability to fill the capacity of the expensive infrastructure that needed to be built. In my mind the hesitancy is no longer there. What we are saying now is that if we build the infrastructure, we can fill that infrastructure. Why? Because the resource base accessible by horizontal drilling is widely distributed on our acreage and horizontal wells are significantly more prolific as producers than other vertical wells. Therefore, the ability to fill a pipe is no longer a serious concern for us as it once was. This important realization is now governing the way in which we plan our business and organize ourselves to get work done and I will talk more about that later. In effect, the business model in our mind for the development of the Appalachian region has changed. It is changed from a well driven business model to a pipe driven or infrastructure driven business model. Simplistically in a well driven business model, it obvious the well and tail is the infrastructure. Wells are drilled wherever the geologist leads them to be and are hooked up to wherever infrastructure exists. In our current pipeline driven business model, the production and sales growth will occur through completion of a series of pipeline midstream projects or corridors as we described them. A corridor represents a swath of our acreage inclusive of a number of well sites, notionally a thousand or so, that requires midstream investments and pipeline compression processing et cetera. This corridor project radiates from a central processing facility like Langley, for example, which is then connected to the larger pipes that get gas-to-market like Big Sandy, Flap, PGPL, for example. Conceptually then we hope to be able to chart our volume plan going forward is an orderly stack of sequential corridor projects, each of which adds incremental capacity for natural gas sales, that will be filled by horizontal wells. We will talk much more about this concept in March, but I did want to give you that upfront. Reviewing the drilling for 2007, in the fourth quarter, including horizontal, in the quarter, we drilled 163 gross wells, 170 net, 38 horizontal wells. In the year, we drilled 635 gross wells, 88 of which were horizontal. The cost for horizontal well averaged about $1.22 million. Reserves for horizontal wells are still in the previous range of guidance that we have given you that is from 0.75 to 1.5 Bcfe per well. With this new data from the wells that we have drilled, we are conforming no change to the decline curves we have previously released to you, regarding horizontal shale and coal bed methane drilling. Some recent progress. We are currently drilling a low pressure Marcellus well in southern West Virginia. We are also currently drilling a high pressure Marcellus well in Green County Pennsylvania. We are drilling a horizontal Berea sandstone well. This is a concept well to see if drilling this sort Devonian silty sandstone might generate increased productivity versus the adjacent fractured shale. So, we will be excited to see the impact of that. We have drilled two Virginia horizontal shale wells, one in the Nora Filed, 50% with range and the other one in the Roaring Fork Field where Equitable has 97% interest. The Nora well had first month average production of 469 Mcf per day. The Roaring Fork well will be a producer, but won’t be represented of the play as during fracturing we had some unanticipated communication with three other wells. So, we are going to have to drill some more down there to figure it out… figure out how that works. So, the first well will be a producer, but it’s not going to be representative in our view. We have more to talk about on that later. Importantly, based on the results of drilling 18 horizontal wells in West Virginia, we are now ready to declare as we had done previously for Kentucky, that as a working hypothesis future shale wells in West Virginia will be drilled horizontally. So, we have a choice in West Virginia now as we have set previously in Kentucky, we will drill wells horizontally. We feel good about those wells that we have drilled there in West Virginia. So, far this year, in January, we spud 17 horizontal wells. We have 11 rigs running for horizontal drilling. Interestingly all of these rigs are capable of drilling horizontal wells from grass routes to TD. So, we have really built up. The rig fleet here, that’s capable of drilling horizontal. We also have three coal bed methane rigs running and one other rig dedicated to vertical well drilling. In 2008, the Company intends to drill 750 gross wells. Current plans are to drill 250 to 300 horizontal wells, 300 coal bed methane wells with the remainder being other vertical wells drilled by ourselves or partners. And I want to emphasize that our limit to drilling horizontal wells at this point is land permitting, not drilled rigs or personnel. Turning to natural gas reserves, I won’t review all the numbers we gave you on our natural… in our press release but I would like to make a couple of points. Reserve replacement ratio is dominated by organic growth through the drill bit and you saw our reserve replacement ratio was 386%. I think as you saw also from our release, our reserve replacement costs continues to stand out as a strength of this Company. I would like you to focus on three other factors, you reserve… as you look at the reserve picture. First we are now breaking the P3 reserve into three categories, Shale, CBM and other, the latter including conventional targets like the Big Lime, Veremax [ph] and et cetera. The obvious headline is the increase in shale reserves which were up 193%, year-on-year, from 26.83 Bcfe to 51.77 Bcfe. Coal bed methane is down in P3, the sale of interest to Nora had some… sale of the interest in Nora to Range had some impact on that. But practically the success of shale drilling costs caused the CBM development to rank lower on our priority list at this point. But we are hopeful that new technologies and new opportunities will change that in the future. Another fact that you would like to know, which I thought was interesting is that 71% of the wells that Equitable drilled in 2007, were drilled on locations that were classified at the time of drilling as unproved locations. For comparison, 59% of the wells we drilled in 2006 were at unproved locations at the time of drilling, and from 2005 to 2007 we have drilled 995 wells that were classified as unproved at the time of drilling. There were virtually no dry holes and interestingly in our look back analysis, the reserves we developed from these wells in total are spot on with those that were booked as unproved at the time of drilling. Perhaps this is obvious but I will say it anyway. EQT does not distinguish among existing well classifications approved probable or possible once selecting a drill site as obvious from our behavior. Maybe this is too much but these facts certainly generate a lot of questions that beg for answers. For example, do these facts indicate conservatism on EQT’s part of profane reserves or is this a natural outcome of outmoded reserve booking methodologies when applied to resource plays. My own view leans to the latter explanation. The industry is just now learning how to deal with reserve evaluations for gas fields involving expansive tracts of more or less homogenous hydro carbon bearing reservoirs like shales. The existing SCC and engineering reserve booking methodologies which were constructed for geologically well defined fields are not translating very well to this resource place. So, that’s the P3 picture. Second based on a review of our entire acreage position we provided a table representing our view of additional reserve potential attributable to key emerging plays and I wanted to discuss a few of those. First, the Devonian shale reentry and extension align. We don’t yet have enough data points to move the re-entry potential into the P3 categories but it is still potentially an important play in our mind. We drilled two re-entry wells to date. Our intention in 2008 is to drill 15 to 20 additional re-entry wells to assess the opportunity. To remind you our first re-entry well produced naturally 417,000 Cfe per day for the first month at a cost of $573,000. The second re-entry well produced, after fracturing 633 Mcf a day at a cost of $1.2 million, and again that’s our first month average production which is what we try to use around here to normalize the noise around IP’s and that sort of thing. In Virginia in addition to the two wells we have drilled so far in Shale. Our intention is to drill about 20 more wells in 2008, 10 in partnership with Range and 10 others in the Roaring Fork field where we have a significant interest. In the Huron Pressure Marcellus, as I mentioned we are currently drilling our first high pressure well in Green county. Dave and I were out there today. We really added a lot of value out there, I will tell you. That’s a joke. This well will be drilled to a vertical depth of 7700 feet, and we are planning for a 3500 foot lateral. The well is being drilled with mud. We are intending to frac it with slickwater and in another words this is a Barnett style completion consistent with drilling of a normal to over pressured shale reservoir. Cost of this particular well is $4 million, we are estimating which is a bit high versus costs that have been quoted by some of our competitors but our well includes some conservative assumptions, contemplates some unusual costs for data gathering and for costs associated with the fact that we are drilling through our own storage field. In this case we have to run another string of pipe. We are hoping to put the well inline when pipeline capacity is available targeting late March, so stay tuned. Just so you know we own approximately 190,000 acres in the high pressure Marcellus play and again that’s mostly in Pennsylvania. Going South out of Pennsylvania the geology shows the Marcellus to ride structurally, and it becomes lower pressured and as such we believed drilling techniques which we have used on the Huron shale that is air drilling, pump fracing and packers [ph] plus completion is the preferred methodology. Our first well was drilled to 49.79 Tbd with the lateral length in the shale of a 3,357 feet. We are currently awaiting our fracturing equipment which will come in mid February, and the reason it is coming in mid February is actually we will actually drill another well from that pattern and we are going to frac both of them at the same time. Costs for this well is about $1.2 million, estimated is $1.23 million. Again for your information we own approximately 300,000 acres with reserve potential in the low pressure Marcellus play throughout Northern West Virginia extending from approximately Jackson to Wyoming counties. And deep drilling. We categorize the volumes here as undefined because of the vast variance in potential outcomes but we wanted you to be aware explicitly that EQT has no reserves currently assigned to the deep measures in any reserved category. Having said that we have taken some initial steps in evaluating the deep play. We have decided that it makes little sense for us to give up equity in this play and so we have done some relatively inexpensive geo physical work to figure out the scope of the opportunity. We have hired and assembled a small but growing team to do that. It’s in place and our hope is that we will begin shooting some seismic data in early 2009. Next year we hope to make drilling decisions based on our evaluation of that data and since those decisions will involve high costs we will determine at that time whether or not it is prudent to take a partner. We would like to have three to four drill ready prospects at the time we make that decision and we think that will cost us 15 million to 20 million to get to that decision point. Our final note on 2008 drilling. While we have learnt a lot about Appalachia horizontal drilling we still have a lot more to learn. There are many new concepts we wish to test and so during 2008 you should expect that about 15% of our wells, horizontal wells will be exploratory in the sense that we will be drilling them to evaluate our emerging plays, to evaluate new zones or test new drilling geometries. We had talked a little bit about production guidance which is 80 Bcfe to 81 Bcfe for the year, but we expect to see significant progress in gas sales growth during this year. So, in addition to annual guidance we are targeting average daily sales to rise from the current rate of 210 million cubic feet a day to a rate of 235 million cubic feet a day by year end and that’s an increase of 12%. And I can assure you that growing gas sales is the value driver around which this management is most focused and incentived. On the mid stream update the Big Sandy project is in final commissioning stages, stages planned in service stage is still on track for the first quarter of 2008. Langley is moving ahead, the cryogenic plant is in place. The new 11,000 horsepower compressors, the centrifugal compressors have been delivered. They are being installed and then the new 138 kilovolt electrical substation is being constructed to accept mainland power from AEP in mid May 2008. And we believe plant commissioning and startup can occur four to six weeks after the power is in place. So, that’s moving along. Deadline We do want to talk about one of these corridors that I mentioned earlier, one key for success in Appalachian is construction of these midstream corridors. The initial one is called The May King corridor. It’s located in Eastern Kentucky and connects to the Langley processing facility, and from that facility, the gas will get into the Big Sandy pipeline. This corridor is an example of one of many that we think we will be building over the next few years. It includes more than 13,000 identified horizontal locations, with the capacity of 200 million cubic feet per day. Infrastructure necessary to complete this corridor includes 15 miles of 30 inch pipes, 60 miles of 20 inch pipes, 120 miles of 12 inch pipes. The first four, 10,000 horsepower compressors are in this corridor, about 90% complete. The discharge pipeline about Langley is currently under construction, with rights of way being obtained on multiple 20 inch suction pipelines. The first phase of this corridor is scheduled to be online in the three quarter of 2008, and we think this whole project will cost about $110 million. And that’s… in March, we’ll talk more about the corridor concept, and how we’re staging the development of these corridors. Consistent with our growth strategy… really is turning to organization now. Consistent with the growth strategy and the infrastructure driven business model, we feel it’s important to consolidate our midstream activities in one place. That conclusion led us to make the decision that we are going to have thee business segments in the Company going forward. Our production business segment which will focus on developing reserves and expending not only our own lease position, but expanding that if we feel that we wanted to do. The midstream business segment has a dual focus. Construction of the corridor infrastructure that’s a key thing and also acquisition of downstream pipeline and processing capacity sufficient to get our gas-to-market and get the best possible price for that gas. And we will talk again more that in March. And lastly, we will have a distribution business segment, which will focus on more typical of these activities for our 275,000 customers in Pennsylvania and West Virginia. On the management side, as of January, I, 2008, we promoted Steve Lauterbach [ph] to President of Equitable Production. Steve has most recently led our horizontal drilling to development afford from the conception stage on. He has over 20 years of upstream E&P experience, including eight years with Marathon. The last 12 years have been exclusively in Appalachia, with Eastern American Energy, predecessor to Statoil and then came to Equitable with our purchase of the Statoil properties in 2000. He is a graduate of Penn State, with B.S. and Petroleum and Natural Gas Engineering. Randy Crawford, who led our Utility segment, will be responsible for both the midstream and distribution business segments. Randy has more than 20 years experience in pipeline LDC and regulatory management and has been on the Equitable team for 11 years. Both of these executives report directly to Dave Porges our President and COO. The last topic of the day relates to our current plan for Equitable gas company, the LDC. As we know, Dominion and Equitable jointly terminated the purchase and sale agreement related to Peoples and Hope Gas as of January 15, 2008. You’ll also recall this transaction was premised as a round win-win-win deal with anticipated synergies yielding lower rates for customer, more jobs for the region, and importantly, enhanced returns for shareholders. However, that is history. Our strategic priorities for Equitable Gas right now are to improve service levels, improve system integrity, and improve returns, and that’s really all we are focusing on there right now. And with that Pat, I’ll turn it over to… the operator for questions.

Thank you, Murry. That concludes the comments portion of the call. Vanessa, can you please open the call up for questions. Question and Answer

[Operator Instructions]. Your first question is coming from Shneur Gershuni of UBS. Please go ahead.

Hi. Good morning, guys.

Good morning.

A lot of information on the drilling side, I just kind of… we’re still digesting it all. But I kind of had a couple of quick questions, if you don’t mind. With respect to the horizontal wells you have noted that there was that 1.2 million in drilling so forth. Do you think that there is any potential for that number to come down at all? Are there things that you are still playing with in terms of casing and so forth? Just sort of kind of an idea on how that would be?

Yes, the most significant thing that we’re looking at right now which could impact the cost. And we are really thinking about cost and not so much per well, but in terms of reserves developed is multilateral drilling. And so, I am hopeful that multilaterals will help us to be more productive in developing these reserves. That doesn’t necessarily mean the cost per well are going to go down though. The cost of wells could go up and reserves could go up more and that would be fine with us. So, that’s I think the most significant development. I think we’re continuing to tweak geometries and tweak fracing techniques, and perhaps, we can get more productive. But I think that’s the key word. We’re not focusing on getting the cost down as we are and trying to get the productivity up. Productivity measured both by reserves developed per dollar spent and also amount of production that we get for the dollar spent. So, that’s really not a cost minimization. It’s really a productivity improvement that we’re targeting. I hope that helps.

It does. Basically the idea being is, that’s the cost is, we can increase the reserves dramatically on a per dollar spend base.

Yes, I mean that really… ultimately in any kind of commodity type business and we are in that business, that’s what you want to do.

Okay. The other question I had is just with respect to the reentries and so forth. Is there an upside potential to rebooking the pud if the reentries is proved to be successful? Is that something that can be material upside in retrospect to how the positive book to currently right now?

I’m not sure yet. I think the rules… maybe Dave has a view on it. The rules around how this reentry will be booked are rather complicated. I don’t know, Dave, do you have a view on that that’s special.

It’s not as easy as you think it should be. It’s more likely that, that would result in more probables and possibles. Right now, the rules Murry is referring to have to do with your ability to book proved reserves in horizontal and it pertains to offset. So, we will probably… let’s say we probably go successfully, we might have a notion internally that we can extrapolate the success of that more broadly that the reserve booking rules would allow us to, at least, from the perspective of proved reserves.

Yes, there is some weirdness in the reserve booking. By the way, that’s all being reviewed now, the reserve booking which I think are kind of inadequate for these resource plays. But you would think as Dave said that if you drilled… we have 3,500 vertical wells in the shale, right? And you say okay, sculpt the playout, what if we win it all 3,500 and drill the horizontal well, right. You think okay, that’s interesting. It’s all proved, you know it’s proved, because you drilled wells. It’s proved and developed by the way. You think, well, if I drilled X number of reentries, I could just book the whole thing is proved. You would think that would be the case, but that is not the case. And I can’t… because the rules are the rules.

But we will, if we get to that point. We’re not at that point. But when we are at that point, we will call out those aspects of probable and possible reserves that pertain to reentry.

We’ll make a line item for that.

That was windy, but you get the drift there.

Right now, what we’re hoping that the reentry will be as successful as we hope it will be.

Okay. That sounds good. That takes care of my questions. I have some more, but I will jump back into the queue. Thank you.

Thank you. Your next question is coming from Sam Brothwell of Wachovia. Please go ahead.

Hi, good morning guys.

Hi, Sam.

Hey, certainly surprised us this morning. One question at the March meeting, are you going to be able to maybe give us a little more detail on the Marcellus? Where it’s located and maybe some first well data?

Well, I’m hopeful that we’ll have some data on the first low pressure Marcellus wells. I don’t’ think we’ll on the high pressure. We’ll probably know something, but we won’t have that inline. We have got some pipeline capacity issues in Pennsylvania as I look at up to the pipeline. But you know something more than what we know now. But March 11, I’m not so sure we are going to know.

With the Marcellus wells, Sam, we are not anxious to frac it until we know we can turn it inline and that’ where the pipeline issue comes in. And some of the information you’re looking for though was really probably come as a result of fracing. And we are not going to be at that point for the wells that we are doing now… for the high pressure wells that we are drilling now, at the time of Analyst Meeting.

But the low pressure we should have fraced and hopefully produced a couple of them at that point. A little bit more data on there.

Okay. Now that makes sense in light of the change of strategy. Murry, I would remiss if I didn’t ask as you think about funding, this whole program forward. Is the possible sale of the distribution business one of the options that you would explore?

I am at this point going to redirect that question Sam if you don’t mind and tell you that the management here is completely focused on the production and midstream business.

Can I forward that--?

Certainly what I said about the LDC is true. We got to work on improving customer service getting the integrity up and improving the returns. And that’s really all I'm going to say about it right now.

Fair enough. Thanks a lot, Murry.

Thank you. Your next question is coming from Rick Gross of Lehman Brothers. Please go ahead.

Good morning.

Good morning.

A couple of things. First, you mentioned the word acquisition, down stream pipe and processing and as I kind of look around the landscape in Appalachian, there is not much to acquire and so I was just curious about whether that meant more projects like the Tennessee joint venture or how I put that in context?

And maybe that wasn’t as clear as it should be. Yes. The Tennessee project is clearly in that category but what I'm trying to distinguish here Rick, and I think we’ll talk more about it in March, is the distinction between the upstream infrastructure that we're putting in, in these corridors that are basically getting gas from the well to some kind of a centralized processing or compression plant. Distinguishing that from down stream capacity to get the gas to market and acquisition in this context could mean things like the Tennessee project, if that goes forward, but it also means acquisition of pipeline capacity to get our gas to market.

Okay. So, exactly it’s acquiring FT as opposed to acquiring a specific asset, like--?

It could well. Don’t take that mark west facilities or something. I am not going to… well that’s the former… well first of all yes. The answer is yes, to your first part of the question. We’d be willing to acquire, Investors Day we needed to equity interest in pipelines that’s what these long line pipelines to get at markets. We signal that by our press release with El Paso. But we also would as you suggest acquire FT with respect to things like liquids processing and all. We are open to investments in that particular part of the business. But driven by our needs to get our gas to market and not be impeded. Dave you want to say anything more?

Rick, remember in this. Our view is in the Appalachian basin, we've got a tremendous infrastructure short fall when you compare what is in place now with the plans that Equitable and other company's that the basin have for producing natural gas. That means there will have to be new pipelines built inside et cetera we are the biggest player in Appalachian right now. There are other large players but for firms like… if anybody is going to build new pipeline capacity, even if it’s small a lot of times they will look to firms like Equitable and the other production companies to step up and sign up for FT so its not just FT and existing pipe. But what we're really signaling is we realize we are going to have to be conceivably one of the foundation structure.

No. You can dictate who gets to build by dedicating your supply control.

No. but also they… a lot of times they won't build, unless they know that folks like us who are in fact willing to step up and now we're signaling is that we are.

Right. Okay.

That’s right and I don’t think we've developed, not to belabor this anymore but I don’t think we've developed that thought with you as much as we intend to and we’ll take a stab at that in March, when we talk about it. Because there is, with all this gas that we hope to come out of here and where you have great expectations as you know. Certainly the reserve potential would suggest we can. We got to think about how we market this stuff a lot differently. We're already thinking about that. We just haven’t talked much about it but we will in March. Right, David, and we’ll have a full review then. Just get the liquids and these other pipeline projects into context.

Okay. The other one is a quick clarification of an earlier question. On this booking of, conversion of originally booking things on--?

Vertical pipes.

Yes. And now, you’re going to convert to exclusively horizontal where you can. There is stuff going on, in fact, your own engineers are involved about… you used to get up to eight offsets as puds and now you only get two. Was there any dislocations in your puds this year as a function of… can affect this declaration. You kind of go from processing one way to another. Can we get some proved reserves actually move back to exclusively some puds to 2P3P?

Not practically. We recognize the issue talking about… it didn’t have a material practical effect on our reserves this year.

Okay. so, we can take it as incremental thing. It is around the reentries. In and around as you migrate this stuff it’s a miniata [ph] it didn’t happen this year.

No, we didn’t not to a material extent. But you're right that is an issue you do run the risk that its possible for something to move out of puds for that reason. And that I think, though when you get back to Murry‘s comment about the appropriateness of the current reserve classifications for our resource supply. Not exactly. Okay.

Thank you.

You’re welcome.

Thank you. Your next question is coming from Ray Deacon of BMO capital markets.

Yes. Hey Murray. I was wondering if you have a break down of the $535 million of E&P CapEx, how will that be distributed kind of across the different plays. Devonian Shale extensions ramping?

I was afraid you were going to ask that because no we just broke it up into drilling versus mid-stream. We haven’t done that yet.

Got it.

So maybe. I’ll tell you one of the reasons we haven’t done it to be very frank with you is; I like to drill as many horizontal wells as we possibly can and so that’s kind of a moving target.

Right.

I said it in my comment today but I really meant it. There is no limit at this point that we see. I mean practical limit to how many horizontal wells we can drill. I mean our guys are really doing a great job here. And the… what I mean is there’s no limit from a rig availability, personnel, that kind of thing. What we're limited by in out ability to get the permits actually get on the ground and do the wells. and if those barriers start to clear and we're working on clearing them and we're working hard to clear them. Then we’ll put as much CapEx as we possibly can in the horizontal well versus something else. So, I'm a bit hesitant to give those breakdowns because I'm trying to push the envelope and it wouldn’t be productive to kind of give it out and then change it every quarter.

The money is definitely more shale oriented than the well count is.

Okay. Got it. Yes that’s a good point. And just a as far as the infrastructure the costs that you're spending. Investors Day that likely to remain at that level. If you look at 2009 and 2010 or does it taper off in 2010?

I’ve got of course we got to give it those numbers Ray and I can’t do it today. It’s just that you come to an unavoidable conclusion that this is going to stay. Keep up for a while and we'll try to give you some more color on that in March.

Okay. Got it. And I guess just on the increase in the probable possibles is what more than I was kind of expecting. I guess what kind of… did you have you're reserve engineers… is this kind of fully reviewed by them or is this. Like a contingent resource study or I guess, how would you characterize that, 13T number?

The big number.

Yes.

The P3 certainly was reviewed, and the resource potential at this point do represent for the most part at least acreaged and where we sink. We know the acreage is for each one of those plays. And we have a notion of how many wells there could be and obviously since we don’t have much data. We give it a range on volume per well so, I mean it’s about it’s what everybody else does. Put it on the map and how much volume per well and that’s why the net category versus P3 we got to do some more drilling to figure out what the reserve per well is and then we can move it up the ladder a little bit.

But you're asking whether its been those emerging plays have been fully vented by outside independent reserve engineers.

No.

Got it. Actually just one last question is, with lowered CBM it looks like you don’t have quite as aggressive a number as some people. I guess what would your CBM estimate be for down spacing in Nora, I guess in this 3 P number?

I think it’s fair to say that most of that number is related to Nora. Yes. I mean I don’t… we don’t. what we really did this year is kind of reduce the amount of non-Nora CBM that we really put here is reflective of prioritization of the work towards shale Because we've got so much to do on the shale so really I think it’s fair to say that most of that P3 is Nora related so that’s the majority of this Nora. I mean we got some or this stuff a little bit here and there but most of it is Nora.

Okay. Got it. And would the reserve bookings do you I mean do you follow it’ sort of a three year out drilling inventory that you book or is there kind of a rule that you guys try to stick to?

We stick to rules. I mean they have to be economic.

Got it.

I mean they have to pass economic muster and that’s what we're using on the P3.

Okay. Got it. Thanks very much.

Okay.

Thank you your next question is coming from Faisel Khan of Citi investments. Please go ahead.

Hi it’s Faisel. Good morning.

We knew who it was. Hi Faisel. My name wrong too Faisel forgive him.

In terms of the last update of the rating agency. It was teed up, they give up your rating in AA-1 are they sort of aware that CapEx plan you guys have outstanding and are they… it’s what you've talked about in terms of your financing plans. Kind of half debt this year and maybe something half equity linked or equity stored of financing the rest of this for the second half of this year is that kind of part of that rating?

They have both agencies changed our rating in the last few month. The rating new reference was Moody’s they took us to be AA-1 you also saw S&P took us to BBB flat and both of them had full disclosure on our financing plans I just want to make sure you were clear with we're going to do up to $500 million of debt in the first half of the year and then more debt plus equity and equity content securities to follow that so I don’t want to give you the impression that everything that follows us is going to have an equity component to it.

Okay. I got you. So, the first half of the year is $0.50 billion the second half is mostly debt, maybe some sort of--?

It’s all of those things. I didn’t say mostly, that was your word but there’s certainly getting more debt to follow in 2008 after this first batch.

Okay. And as you think about financing these large, these infrastructure projects. What's the right way to finance these? Is it kind of half debt half equity or retained earnings? Or how do you guys look at that?

Typically it’s a 50, 50-ish type of endeavor. We're also going to look at other types of securities including MLP’s I mentioned our change in tax position. Now we're going to take another look at MLP especially on the mid-screen side of the business they are actually more attractive to us now then they would have been when we were a tax payer.

Okay. Got you.

I will tell you what we're going to do. We are going to take a pretty hard look at them.

Okay. Fair enough. And on the… in terms of… if I'm looking at the infrastructure development on the gathering processing and pipeline side. In terms of the cost to get the gas from the well to the marketplace. Have you guys come up with any numbers yet in terms of what that is likely to cost, you kind of… you put stuff out there in terms of weak link it is, but have you guys talked about that in terms of what that might cost?

We will talk a little bit more about that in March, perhaps. The calculation has to be since there is so much infrastructure that needs to be put in place. The calculation has to approach. The rate has to approach what it currently costs us to develop this. Now as you know Faisal over the last two or three years Dave and I have been and Randy Crawford have been raising the infrastructure rates because the cost to put this in is pretty expensive. And so you have seen a track on our gathering costs go up over the last three tears and I don’t think it has done going up but I haven’t given you sort of the terminal number, But we will try to do a little bit more of that in March

It also depends on where it is. A lot of our Kentucky stuff that we are talking about it is involving some upfront step changes in projects, Big Sandy and Langley and once we get that done and once we build say a corner rig, Phil is making this an example, but there will be more after that. Then the incremental costs are up to a point aren’t going to be nearly as high.

Right.

So, then let’s take it to another extreme though. Let’s assume there is a lot of us in the industry would like to see happen and they happen that the high pressure Marcellus play in Pennsylvania works well. Well then if you have got some kind of an extension of Rockies Express, whether it is the project we are working on in El Paso or somebody else’s. There is some other project, some project that brings more capacity from across the state of Pennsylvania we could have wells that are almost right next to inter state pipeline. I am guessing the cost of getting that to market, I think that would be very high. A lot of it is really evolving. It depends on where the largest increases in natural gas come from.

Okay. And in terms of that pipe, that pipeline project at El Paso. Would you guys be anchored in and possibly take equity interest in that pipe. Do you think that has a better than 50% chance of going through?

We think it is a strong project, let’s put it that way I mean based on the interest we have seen but we really can’t talk about that. We think it is strong though.

Okay. And in terms of… you touched on this a little bit earlier, the multi lateral completion?

Yes.

Have you actually done any of those wells yet?

No, no we are… it’s probably… we are probably a little later on that than we thought we would. It’s not for engineering. We had to permit it. It’s a very complex permit because nobody knows what the heck we are talking about. It’s a brand new animal, we have already thrown horizontal at them and they mostly stayed so they didn’t know what that was. We have kind of worked that out, now we have thrown this another little animal at them and they are trying to understand what it means and so it has taken long to take that across the goal line from a permitting stand point but we are ready to go and I believe we are in a.. I believe the shorter back [ph] told me we are spudding this week finally or maybe early next week but we are getting one started pretty soon here.

And by the way, on that point because one of the things that is going to come down the road is what is the location anyway. If multi lateral works we could do stacked multi laterals from the same wells so there is going to be all kinds of cool stuff that we are going to try here because w e have got multiple zones, Cleveland, Huron, Marcellus there are several places we could this so right now we haven’t done one yet nor would we do one, we will let you know.

Going back to an earlier question someone asked on the 3 P reserve movement from last year versus this year. You said a lot of that movement was related to the Nora field down space. Is that correct.

Sorry. What?

I said was that related to Nora field down spacing.

No, no, no. The increase in the reserves that we showed for P3 from ’06 to ’07 if I understand your question is dominated by Shale.

Okay. I wanted to make sure on… I thought I heard differently when someone else was asking that question.

No, we were answering your question then entirely about the reduction in CBM…

Got you.

The reduction had to do with in CBM primarily had to do with areas outside of Nora.

Okay. Understood, understood. Okay. Fair enough. Thank you for the time.

Okay.

Thank you. Your next question is coming from Rebecca Followill of Tudor Pickering. Please go ahead. Rebecca Followill - Tudor Pickering & Co: Good morning. Great oil results and great momentum you guys have on drilling yet it is not yet showing up on production. You talked about an exit rate that was significantly higher in 2008. Help me understand a little bit better between what exactly is driving that disconnect. Is it the timing of the acceleration. Is it the corridors that you have to get on, the third quarter is making core work. Is it interest rate public capacity. What’s the constraint in the air. Just trying to get a better feel?

I think the main constraint. Big Sandy will help. Langley will help more. Making will help more. I think it is mostly stuff upstream at the interstate pipelines is my answer to that question. Rebecca Followill - Tudor Pickering & Co: And that’s lot of about what we have got, some of it coming on in the first quarter so that second quarter just kind of gradually a little bit ahead of the times.

Yes. And the reason that I did the year end rate rather than some incremental rates is that the timing of when all those pieces come on could shift one way or the other and so rather than give some incremental guidance. I really chose to do at year end where we think that enough of these pieces are going to be in place, that we should be seeing quarter-on-quarter increases in production. You are quite right though. I mean we have a reserve potential here that is staggeringly large. The key issue for this management team is increasing the production and sales of natural gas and all of these projects, I wish they were done but they were not done but these projects are going to be critical and they are really the upstream project. Now that is not to say that there are not or will not emerge downstream interstate pipeline or capacity or processing or liquid issues, those are coming too. We are getting ahead of those, we hope now that the current issue is the…call it smaller pipe problems upstream of the major interstate pipelines. That right now is the main thing that we are concerned about. David you want to comment on that any more?

Though it is true when you look at our drilling a lot of the increase in productivity is coming from horizontal and as pleased as we are about the progress that we have made, 2008 is going to be the first year in which our drilling is really dominated by horizontal drilling. I can remember with the success that we had in 2007 it was still a relatively small percentage of our overall number of wells drilled and of course prior to that they were essentially not like they were five that we drilled for 1107. So, even though we are talking about this movement we are really still in the midst of converting ourselves into a horizontal drilling oriented Company in the Shale.

I will just add-on, just to give you a comfort or not. The first well in Virginia that was drilled and this is the one that we drilled for range in the Nora field. That well as I said almost $ 500,000 a day for the first month but they came on very strong and the reason why I make this point. I don’t talk about IPs much but they came on at one point to $1.3 million a day. All of that gas showed up at the sales meter and the reason that was true is because the gathering system in Virginia has sufficient capacity to handle that kind of rate. That is absolutely not happening in Kentucky and West Virginia where we are putting wells on and we look at the first downstream meter and we are seeing half, or sometimes less than half that we would liked to have seen based on the initial production from that well. And so, that’s the clog up right now. I wish I could…

High pressure in Marcellus we just mentioned in Pennsylvania the reason we are delaying fracing it is because again we don’t want to frac it until we are ready to turn it in line. We won’t be ready to turn it in line until we complete some pipeline projects that are underway. That’s the kind of stuff we are dealing with everywhere and I think it is important to emphasize it but we were maybe talking more about it than we should. This is the Appalachian basin right now. It’s sort of all Rockies problem. Rocky has had a problem getting somewhere. We have this clog up in the gathering processing aside and the shareholders need to know that isn’t going away right away. It’s going to take some time, some investment. We think there are good opportunities in those investments but it will take some time to lubricate this system, to get the gas to market. its no excuses here, it’s just that’s the way it is. Rebecca Followill - Tudor Pickering & Co: Thanks. One of the things that’s interesting is when you look at your peers at what they earn? Little bit of CapEx you are spending on mid stream is nowhere near what they are doing. People aren’t talking about in the same extent. Are you unique in your situation or is the rest of the industry just hasn’t got talking about it or they don’t know the region as well.

Rebecca, I have enough trouble working on Rebecca Followill - Tudor Pickering & Co: Okay. That’s fine. Change of subject. Your MLPs, you said you are going to take a pretty hard look at MLPs. What do you mean by take a pretty hard look?

Well we have all… you know Equitable as well as anybody does. We focus on cost of capital here. It was our view that as a tax payer that we had limited amount of assets to currently to put into the MLP because of the tax leakages on those tax appreciated assets. If MLPs offer us a lower cost of capital for the mid stream cash flows, right? If they do, then we are going to do one. That’s basically what it boiled down to. If we can demonstrate it to ourselves that this is a sustainable cost to capital difference, then we have to do… Equitable would have to do it because that’s what we do around here. And so that’s what I’m really getting at, but it has to be proven to us that it is a reduced cost of capital, in that thing. That’s going to drive us. Rebecca Followill - Tudor Pickering & Co: And how long will it take you to figure out?

I don’t know. Phil you want to…

It’s a this year project.

I’m glad we’re not fighting to go to market with one this week. Rebecca Followill - Tudor Pickering & Co: I don’t think that’s good.

I mean exactly. I mean sustainable reduction in cost of capital. That’s really what we want. Rebecca Followill - Tudor Pickering & Co: Thank you very much.

You are welcome.

Thank you. Next is a follow-up question of Ray Deacon of BMO Capital Markets. Please go ahead.

Would it sound a little simplistic but if you were asked but if you were adding reserves for $0.48, and adjusting for operating expenses. They’ve got to still encourage selling reserves for $ 4. It seems like a good business model to me, would you consider any of that? And also I guess that rating agencies like Standards were comfortable keeping your ratings where they are, at a slightly lower level I guess, so are they going to ask you to hedge, I guess if you’re looking at this capital you’re spending on the mid stream, where do you get by the end of the year if you kind of look at take away capacity or how much of the probables does it open up for you. What’s the right way to look at that?

I’ll only take the third question first. In March we’ll try to give you some pictures on that. We’ll show you what the production profile is that we think we can have and what capacity’s available so you can get a feel for that, because it is very regional, as Dave mentioned. We’ve got different problems in different areas. There’s no good way to generalize and let’s till take the hedging thing and then we’ll talk about the first question. Phil. Do you want to talk about the hedging thing?

Sure I mean, the rating agency should give us credit for the fact that we have an obviously sound business, the fact that a significant amount of our cash flow and spend it in the form of the mid stream. And it does give us some credit for the fact that historically we’ve hedged. Having said that we did not commit as part of the current rating, to doing loads of more hedging? That’s something we will continue to look at and we think we need to do it we will do it but that was not a commitment we made to the agencies. Does that help?

It does exactly. Thanks

Dave, you start on this one, and I’ll elaborate on your first question.

On the divestiture issue, we’re always open to the idea of fine tuning our asset base, I think we demonstrated that in ‘07 whether it’s equalizing the interest in Nora by getting to 50-50 across the board or buying back the positions that we have as we start counting. Some of the more important ones are selling but right now, in the near term we would have an issue with a larger scale divestiture even if the economic that your talking about held up for a specific circumstance. And that’s because what we’re finding is every time we re look at a play, it seems there is another development opportunity. So what we’re a little reluctant to do right now would be to divest something without knowing what the further development is. I mean even in Coal, in which we said we’re not putting much effort in 2008, as Murray alluded to… it’s quite possible and we are sure we are putting effort into this that we’ll figure some other way to go after that and exploit that opportunity. You don’t want to caught in the wrong side of divesting something if there is a major new way to exploit the resource.

And just to elaborate, we did take some care in giving you that resource potential from emerging clay table and the care that we took, and I hope this came through in the discussion, was that all of those categories we showed you, we are actually taking… there is current activity on them, and today’s point we understand if there is a large reserve potential out there it makes no sense for us to show it and not do anything to try to evaluate it. And so I think we’re definitely lined up to do that and if we find that certain aspects of the reserve aren’t as good as we think or there are certain areas that are way down on our priority list we’ll consider that down the road but right now is not a time to do that. We’re just learning but we’re taking action on all of those emerging plays and reserve potential opportunities, right now, so this is going to evolve. We do understand the arbitrage you are talking about.

If you give it up for 15 years, the MTV…

Exactly. We get that. We got the math. We’re just worried that… we don’t want to sell something that we don’t understand.

Right, got it. Thanks.

Okay.

Thank you. Next is a follow-up question of Richard Gross from Lehman Brothers. Please go ahead.

You talked about the business being not pipe driven as opposed to well driven and Rebecca’s question kind of meandered through that. From a stand point of just trying to conceptually trying thinking about this, I assume we’re going to see stair steps as we build our corridors and turn them on and we built and we began to build out the Big, Sandy, Langley corridor as such and you have got the other project behind it, and that was like a war on a single front, and Big Sandy we got right of away issues, we got Langley turned on, we’ve got liquid take away issues, all these timings seemingly you do not want to dove tail because other wise you end up turning on meters and shutting down all the low pressure wells. So you are going to go from a… what sounds like a war on a single front, for the amount of money your spending, to a war on kind of multiple fronts. You are going to be not one corridor at a time but maybe multiple corridors at a time, getting all this stuff to dove tail.

Right.

How do I think about because the well cost behind that. It seems to me that you want to have to wells ready but you don’t want to be in a position where if you are delayed six months anywhere along these corridors, you go to the back of the line, 15 years from now.

Well clearly that’s… the whole planning around the corridors is what we’re spending a lot of time on around here and we’ll talk more about that in March cause it’s kind of harder to layout, but conceptually, one of the big things that we’re considering right now is if we build a corridor, how much of a flat light for that capacity are we expecting? In the order words, in the making corridor, for example, we said there are 1,300 well locations back there. We are going to build… we made some decisions about how are we building that to accept the peak production from those 1,300 wells or are we accepting that there’ll be a ramp up to a flat life for that pipeline system for some period of time and then there’ll be a decline, so, in other words we’ll be continuing to drill into that capacity with our own wells. I mean that’s something we’re thinking about? If it’s a flat life how long is that flat life? What’s the most economic way to think about that? And from that, how do we stage the wells to be drilled? So, but conceptually your right? We’re imagining going forward a stack or stair step of corridors that build up to our production growth. We think it’s sort of mining this gas. It’s a very manufacturing kind of a model but the driver for the growth will be these corridors that we stack on top of another. Now having said that, you’re right. The planning issues are more complex. We do have to be developing multiple corridors at the same time, permitting multiple corridors at the same time. And that’s the logistics problem around which as management is spending most of it’s time right now. That’s complex. It’s not unsolvable. We think we have an orderly approach but it’s not all sorted out yet but we’ll give a lot more detail to this in March. And show you how the stair step kind of works? And what the next few projects are.

Okay. Couple of kind of financing related things. The attractiveness of hybrids ebbs and flows to some degree with credit markets. I don’t know what your view is there but our view here is that credit spreads will kind of continue to widen. And on occasion the hybrid market if you do all the basis point math, gets expensive. And that appeared to biking of what you were, I thought maybe hoping putting words in your mouth to do as opposed to maybe a shorter term asset sale or straight equity. Is the math going to be very sensitive or is it just the idea the idea that we just plain don’t wanted to be do equity and so the math is a little off and we’ll still prefer to do the hybrid.

Well, like Murry said with the MLPs we are going to look at it in a class of capital and your right, the hybrid spreads dramatically since a year ago when we were really looking hard at them around the financing of the acquisition, and the only deals that are getting done right now are the financial institutions and they are at high spreads and we don’t have a view that those are going to come in anytime soon. We hope they do, because we did like that security and sounds like it’s a very efficient way to get equity content. We will look at the cost of the capital, we will consider our view of the stock price at the time, and if we think it makes sense to do one, we’ll consider doing one.

Okay. Around about way of asking about the MLP, but kind of in the context of financing. Philosophically, you can go to the high splits route, you can go the LLC route. The high splits route has pros and cons, but just from a straight financing cost to capital standpoint the LLC would seem to be the way to go.

Yes. I think the other issue is that you’ve got such huge capital expenditures. There’s two philosophies. We build and drop or we drop and build. We are so far away from that at this point that we understand what you're saying we've talked about these issues but I don’t know where we're headed

We’ll look at all those

Okay. we understand what you’re saying though.

Is VPP as was alluded to earlier? VPP is strength debt but as was alluded to the will cost the lending rate on that VPP appears to be pretty attractive. Is that just off the table because really its debt or is--?

Our view is based on what we kind of issue capital wasn’t it clear that they were to… the all in rate was that attractive versus showing straight debt for us. Now we continue to get down the credit. If we continue down the credit profile that changes but for investment grade issue its not obvious that that’s the more attractive way to get there.

Thank you.

Thank you. There appears to be no further questions at this time. I would like to turn the floor back to Patrick Kane for any closing comments.

That concludes today’s call. The call will be replay for a seven day period beginning at approximately 1:30 Eastern Time today. The phone number for the replay is, 706 645 92 91. You will need a confirmation code which is 8104548. The call will also be replayed on our web site for seven days. Thanks everybody for participating.

Thank you this does conclude today’s Equitable Resources conference call. you may now disconnect and have a great day.