EQT Corp (EQT) 2007 Q4 法說會逐字稿

Good morning.

My name is Vanessa, and I will be your 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'll be a question and answer.

If you like to post a question during this time, please press star then the number 1 on your telephone keypad.

If you'd like to withdraw your question, press the pound key.

If you have previously pressed star 1 to post a question, we request that you please press the pound sign and then star 1 again.

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.

So, we'll briefly review the 2007 financial results that were released this morning.

Then Murry will provide comments regarding Equitable's operational performance, our reserved press release, which was also issued this morning and our future prospects.

Following Murry's remarks, we'll open the phone lines for questions.

But first, I'd like to remind you that today's call may contain forward-looking statements related to such matters as our projected well drilling program and infrastructure development initiatives, reserves, financing plans, the move to three reporting segments and other financial and operational matters including production and daily sales volume guidance.

In addition, we will discuss probable, possible and unrisk reserve potentials today.

And the SEC guidelines strictly prohibit the company from including such reserves in SEC filings.

Before turning the call over to Phil, I'd like to encourage you to participate in the 2008 Analysts Conference which is scheduled for March 11th 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.

There are other expectations expressed in the forward looking statements today.

These factors are listed in today's earnings release.

The NDNA section of the company's most recent form 10-K are 2007 10-Qs as well as on our web site.

I'd 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 fruit 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 determinated acquisition of People's Gas and Hope Gas.

Given the reserved update, Murry's remarks will be lengthier than normal so I will try to keep a summary of 2007 fairly brief.

Starting 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 resulting 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 in 2007, we only owned those properties for 4 1/2 months.

I mentioned price and sales volumes.

The average well head price in '07 was about 3% higher even though (inaudible) declined about 5% year-over-year.

The higher effective price for the year came as a result of higher average hedge 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 you saw on the table in the release in 2009, the average hedge price increased by $1.29 for Mcfe and the percent hedge drops considerably in 2009.

So if the market stays near current levels, we expect a sizeable increase in our effective well head price in 2009.

I mentioned volumes were also up.

We are reporting a 0.9 Bcfe 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 from the sale of the Northfield properties.

We make that normalization, volumes were actually up 5.4% in 2007.

And the fourth quarter, reported sales volumes were 0.6% higher than the same quarter last year, but again, after adjusting for the asset sale, the growth in sales volume was like 7 1/2% versus the same quarter in '06.

Operating expenses and supplier 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'll remember that our 50% share of the Nora Gathering activity is now reporting in equity income.

So those gathering and compression costs did not, in fact, 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 account 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.

Remainder of the increase in operating expenses was primarily due to DDNA expenses as a result of our ramped-up drilling and infrastructure investments in the supply business.

Moving on briefly to utilities, of course, the biggest impact on utilities results was the 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 the charge total $21 million and the 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 warmer than normal.

And second, natural gas prices were very volatile in 2006, providing our marketing group with the opportunity to take advantage of our asset position and chief higher margin in that business.

As is typically the case, the majority of those margins were recorded in the first and fourth quarter of 2007, when 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 200 - be generating far greater deductions for tax purposes than ever before.

As examples, approximately 70% of the cost of drilling our vertical wells and 75% of the cost of our horizontal wells are considered intangible drilling costs or IVCs 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 years following the asset being put in service.

Even though physical asset lives are often 25 years and longer.

The result of all that is the equitable expects to be in a net operating (inaudible) 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 People's and Hope transaction, we will still need to access the capitol 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 overtime with debt equity and possibly other security that have equity content such as hybrids.

We intend to 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 debt balance of between 4 and $500 million and 2008 CapEx plan, net of cash flow from operations in 2008, we expect to raise a little over a billion dollars in the capital market billion dollars in the capital marks this year.

In the first step, we plan to issue up to $500 million in the conventional public debt the first half of the year and will follow that with more debt and securities with equity content.

We've 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 than that but given the volatile market conditions and ongoing discussions with the rating agencies, it doesn't make sense for us to go further than that at this point.

Our history is that we're mindful of the balancing act between our credit rating and investor delusion and we believe we have a history of working in the long-term interest of our shareholders and we will continue to do that.

And with that, I'll turn the call over to Murry.

Phil, thank you very much.

my report is longer than normal today.

My report is a little longer than normal today because there is a lot to go over.

Bear in mind, as Pat said, We'll have an analyst conference in Pittsburgh on March 11 and we'll go into more detail on a number of items I'm going to touch on today.

First of all, let's start with the impact of the horizontal drilling on Equitable.

I am comfortable that results of our horizontal drilling technology provide us with the sustained 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 go build infrastructure that we were hesitant to build in the past and we were hesitant because of a lack of confidence in the ability to fill the capacity of the expensive infrastructure that needed to be built N.

In my mind, that hesitancy is no longer there.

What we're 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'll 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 model, the dog is the well and the 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.

A corridor represents a swath of our acreage inclusive of a number of well sites, (inaudible) 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/ggpl, for example.

Conceptually then, we hope to be able to chart our volume plan going forward as 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'll talk much more about this concept in March.

But I wanted to go of you that up front.

Reviewing the drilling for 2007 in the fourth quarter, including horizontal.

In the quarter, we drilled 163 gross wells, 117 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 well are still in the previous range of guidance we have given you, from 0.75 to 1.5 Bcfe per well.

With this new data from the wells that we've drilled, we're confirming 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 southwestern West Virginia.

We're also currently drilling a high pressure Marcellus well in Green County, Pennsylvania.

We're drilling a concept well to see if drilling this sort of Devonian sand stone might generate productivity versus the adjacent fractured shale.

We'll be excited to see the impact of that.

We've drilled two Virginia horizontal shale wells, one in the north field, 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 Mcfe per day.

The roaring forkwell 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're going to have to drill some more down there to figure it out, figure out how that works.

The first well will be a producer and it's not representative in our view.

We'll 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, if we have a choice in West Virginia now as we've set previously in Kentucky, we will drill wells horizontally.

We feel good about those wells that we drilled there in West Virginia.

So far this year in January, we've spot 17 horizontal wells.

We have 11 rigs running for horizontal drilling.

Interestingly, all of these rigs are capable of drilling horizontal wells from grassroots to TDs.

So we really build up the rigged fleet here that's capable of drilling horizontal.

We also have three coalbed methane rigs running and 1 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 coalbed methane wells with remainder being other vertical wells drilled by ourselves or partners.

I'll emphasize that our limit to drilling horizontal wells at this point is land-permitting, not drill rigs or personnel wells.

Turning to natural gas reserves, I won't review all the numbers we gave you 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, the reserve replacement costs continues to stand out as a strength of this company.

I would like you to focus on three other facts as you reserve, as you look at the reserve picture.

First, we're now breaking the P-3 reserves into three categories, shale, CBM and other.

The latter, including conventional targets like the big lime, miramax, 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.

Coalbed methane is down, Mp-3, the sale of interest to Nora had sale and had some impact on that and practically the success of shale drilling caused CBM development to rank low or our priority list at this point and we're hopeful new technologies and now 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 classified at the time of drilling as unproved locations.

For comparison, 59% of the wells we drilled in 2006, were on 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 the wells in total are spot-on with those booked unproved at the time of drilling.

Perhaps this is obvious but I'll say it anyway.

EQT does not distinguish among existing well classifications approved, probable or passable when selecting a drill site, as obvious from our behavior.

Maybe this is too much, but these specs certainly generate a lot of questions that begged for answers.

For example, do these facts indicate conservatives among EQT's part in reserves or is this's natural outcome among booking methodologies when applied to resource plays.

My own viewing for the latter explaining.

The industry is now learning how to deal with reserve evaluations for gas fields involving expansion tracks of more or less homogenous reservoirs like shales, existing SEC and engineering reserve booking methodologist which were constructed for geologically well--defined fields are not translating very well to the resource plays.

So that's the P-3 picture.

Second, based on a review of our entire Acreea position, we provided a table representing our view of additional reserve potential attributed to key emerging plays and I wanted to discuss a few of those.

First, the Devonian Shale re-entry and extension line.

We don't yet have enough data points to move the re-entry potential into the P-3 categories, but it's still an important play in our mind.

We have drilled two re-entry wells to date, the 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 cubic feet per day for the first month at a cost of $573,000.

The second re-entry well produced after fracturing, 633 Mcfe per day at a cost of 1.2 million and again, that is the first month's average production, which is what we try to use around here to normalize the noise around IPs and that sort of thing N.

Virginia, in addition to the two wells we have drilled so far in shale, our intension is to drill 20 more wells in 2008, 10 in partnership with range and 10 with in the Roaring Fork Field with we have a significant interest.

Marcellus, as I mentioned the, we're drilling our first high pressure well in green County.

We added a lot of value out, there I will tell you.

That is a joke.

This well will be drilled to a vertical depth of 7700 feet and we're planning for a 3500-foot lateral.

The well is being drilled with mud when cutting with slick water and In other words, this is a Barnett-style completion, consistent with drilling of a normal to overpressured shale reservoir.

Cost of this particular well is $4 million.

We're estimating which is a bit high versus coasted by some of our competitors but our well includes conservative instructions, unusual costs for data gathering and costs associated with the fact that we're drilling through our own storage field.

In this case, we have to run another string of pipe.

We're hoping to put the well in line when pipeline capacity is available targeting late March.

Stay tuned.

So you know, we own approximately 190,000 acres in the high pressure Marcellus play.

And again, that is 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 believe drilling techniques we have used heart Huron Shale, air drilling, form faking is the preferred methodology.

Our first well was drilled to 4979 tbd with the lateral length i the shale of 3357 feet.

We're currently waiting for equipment to come in mid-february and the reason it's coming in mid-february is we're going to drill another well and frak both at the same time.

The cost for the well is about 1.2, estimate 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.

On deep drilling, we categorize the volumes here as undefined because of the vast variance of potential outcomes, but we wanted you to be aware explicitly that EQT has no reserves currently assigned to the deep measures in any reserve category.

Having said that, we've taken some initial steps in evaluating the deep play.

We decided that it makes little sense for us to give up equity in this play until we have done relatively inexpensive geophysical work to figure out the scope of the opportunity.

We have hired and assembled a small small and growing team to do that, it's in place and the hope is we will begin shooting size make data in early 2009.

Next year, we hope to make drilling decisions based on the evaluation of the data and since those decisions will involve high-costs, we will determine at that time whether or not it's 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 it will cost us $15 to 20 million to get to that decision point.

A final note on 2008 drilling, while we've learned a lot about Appalachian horizontal drilling, we still have a lot more to learn.

There are many new concepts we wish to test and during 2008, you should expect that 15% of our wells, horizontal wells will be exploratory in the sense that we will be drilling them to evaluate our emerging plays and valuate new zones or test new drilling geometries.

We talked a little about production guidance, which is 80 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're 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, that's an increase of 12% and I can assure you that growing gas sales is the value driver around which mismanagement is most focused and incented.

On the midstream update, the big sandy project is in final commissioning stages, planned in-service state 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 and installed and the new 138 kilovolt electrical substation is being instructed to accept main line power from AEP in mid-May 2008, and we believe plant commissioning is fired up, can occur 4 to six weeks after the power is in place.

So, that's moving along.

I want to talk about one of these corridors that I mentioned earlier, one key driver for success in Appalachia is construction of these midstream corridors.

The initial one is called the Mayking corridor, located in eastern Kentucky and connects to the languagely -- Langley processing facility and from that, it will get into the Sandy opinion pipeline.

This corridor is an example of one of many that we think we will be building over the next few years, including more than 1300 identified horizontal locations w a capacity of 200 million cubic feet per day.

The infrastructure necessary to complete this corridor includes 50 miles of 30-inch pipe, 60 miles of 20-inch pipe, 120 miles of 12-inch pipe.

The first 4 10,000 horsepower compressors in this corridor are 90% complete.

The discharge at Langley is under construction and with rights of way being obtained on multiple 20-inch suction pipelines.

The first phase of the corridor is scheduled to be in line in the third quarter of 2008, and we think this whole project will cost about $110 million.

And that is, in March, we'll talk more about the corridor cuts and how we're staging the development of these corridors.

Consistent with the growth strategy, really, turning on organization now.

Consistent with the growth strategy and infrastructure-driven model, we feel it's important to consolidate our midstream activities in one place and that conclusion led us to make the decision that we're going to have three business segments and the company going forward.

A production business segment that we'll focus on developing reserves and extending, not only as the position, but extending that if we feel that is one to do.

The midstream business segment has a dual focus, construction of the corridor infrastructure.

That is a key thing, and also, acquisition of downstream pipeline and processing capacities sufficient to get our gas-to-market and get the best possible price for that gas.

And we'll talk more about that in March.

And lastly, we'll have a distribution business segment, which we'll focus on more typical activities for our 275,000 customers in Pennsylvania and West Virginia.

On the management side, as of January 1, 2008, we promoted Steve Slauderbach to President of production.

He has led our developing effort from the conception stage O.

he has over 20 years of upstream enp experience, the last 12 years have been in Appalachia with eastern American energy, predecessor to stat oil and came to Equitable in 2000.

He's a graduate of Penn State with a BS in petroleum and natural gas engineering.

Randy crawford who led our utility segment will be responsible for the midstream and distribution segments.

Randy has more than 20 years in experience in pipeline ldc and regulatory management and has been on the team for 11 years.

They report directly to our President and CEO, David Porges.

The last topic of the day relates to our current plan for Equitable Gas Company, the LDC.

As you know, Dominion and Equitable jointly terminated the purchase and sale agreement related to people in Hope Gas as of January 15, 2008.

You will also recall that transaction was premised as a round about win, win, win deal with anticipated synergies yielding lower rates for the customers, more jobs for the region and 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're focusing on there right now.

And with that, Pat, I'll turn it over to the operator for questions.

Thank you, Murry.

Certainly.

(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, you know, we're still digesting it all.

I kind of had a couple of quick questions, if you don't mind.

With respect to the horizontal wells you kind of noted it was about 1.2 million of drilling and so forth.

Do you think there is any potential for that number to come down at all?

Are there things that you're still playing with in terms of casing and so forth?

Just sort of a idea on how that would be?

The most significant thing that we're looking at right now, which could impact the costs and really, we're thinking about costs 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 be more productive in developing these reserves.

That doesn't necessarily mean the costs for well are going to go down, though.

The costs of well could go up and the reserves more.

And that would be fine with us.

I think that's the most significant development.

I think we're continuing to tweak geometries and tweak [frocking] techniques and perhaps we can get more productive.

I think that is the key.

We're not focusing on getting the costs down as we are in getting t he productivity up.

The productivity measured both by reserves developed per dollar spent and also amount of production that we get for the dollar spent.

So it's really not a cost minimization.

It's a productivity improvement that we're targeting.

I hope that helps.

No, it does.

Basically the idea of that is the cost is what it is, we can increase the reserves dramatically on a per-dollar spent basis.

That is really -- ultimately, in any kind of a commodity-type business, and we're in that business, that is what you want to do.

Okay.

The other question I had is just with respect to the re-entries and so forth.

Is there an upside potential to rebooking if the re-entry's proved to be successful?

Is that something that can be a material upside in retrospect to how the (inaudible) currently now?

I'm not sure yet.

The rules, maybe Dave -- the rules around how this re-entry will be booked are rather complicated and do you have a few on that -- view on that?

It's not as easy as you think it should be.

It's more likely it will result in more probables and possibles.

Right now, the rules you're referring to have to deal with your ability to book proved reserves in horizontal and pertains to offsets.

We will probably, let's say re-entry goes successfully.

We might have a notion internally that we can extrapolate the success of that more broadly than the reserve-booking rules would allow us to at least from the perspective group reserves.

There is weirdnesses.

That is all being reviewed now, the reserve booking that are inadequate for these resource plays.

As Dave said, you would think if we drilled 3500 vertical wells in the shale and you think, okay, scope the playout, what if we went into all 3500 and drilled a horizontal well, right?

You would think that is interesting.

It's all proved, you know it's proved because you drilled the well.

Well, if I drill x number of re-entries, I could book the whole thing as proved.

You think that would be the case but that is not the case and that is because the rules are the rules.

We will if we get to that point.

We're not at that point now.

When we get to that point, we will call out those aspects of probable and possible reserves that pertain to re-entry.

Right, we'll make a line-item for that.

That was windy but you get the drift.

Right now what we're hoping is that the re-entry is successful as we hope it will be.

Okay.

That sounds good.

That takes care of my question.

I have more but I'll jump back into the queue.

Thank you.

Thank you.

Your next question is coming from Samuel Brothwell of Wachovia Securities.

Please go ahead.

Good morning, guys.

Hi, Sam.

You surprised us this morning at the March meeting, are you going to be able to give us a bit more detail on the Marcellus, where it's located and may be some first well data?

I am hopeful we'll have data on the first low pressure Marcellus wells.

I don't think we will on the high pressure.

We'll probably know something but we won't have that in line.

We have pipeline capacity issues in Pennsylvania, we have to hook it up to a pipeline.

We'll know something more than we know now.

March 11, I'm not sure we're going to know.

Marcellus wells, Sam, we're not anxious to bracket until we can turn it in line.

That's where the pipeline issue comes in.

Yes and the high pressure ones.

Yes.

And some of the information will come as a result of the frakking.

We're not going to be at that point for the wells that we're drilling now for the high pressure list we're drilling now at the time.

And low pressure should have [frack] produced a couple at that point and we'll have a little bit more data on that.

That makes sense in light of the change in strategy.

Murry, I would be remiss if I didn't ask as you think about funding the whole program going forward.

Is the possible sale of the distribution business one of the options that you would explore?

I am going to redirect that question and tell you the management here is completely focused on the production and midstream business.

Can I ask some more of that?

When I said about the LDC is true.

We have to work on improving customer service and getting integrity up and proving the returns.

That is all I'm going to say about it right now.

Fair enough.

Thank you, Murry.

Thank you.

The next question is coming from Rick Gross of Lehman Brothers.

Please go ahead.

Morning.

Good morning.

A couple of things.

First, you mentioned the word "acquisition," of downstream pipe and processing and as I kind of look around the landscape and Appalachian, there is not much to acquire and so I was just curious whether that meant more projects like the Tennessee giant pressure or how I put that in context.

And maybe that was not as clear as it should be.

The Tennessee project is clearly in that category.

What I'm trying to distension wish here, Rick, and I think we'll talk about it in March more, is the upstream infrastructure we're putting in the corridors that are basically getting gas from the well to some centralized processing or compression plant and distinguishing that from downstream capacity to get the gas to markets and acquisition in this could mean things like the Tennessee if that goes forward but it also means acquisition of pipeline capacity to get our gas to market.

Okay, so acquiring FT as opposed to acquiring a specific asset like...

Yes.

Don't think I'm Mark West Facilities or something.

I'm not going -- that, the former, well, first of all.

Yes.

The answer is yes to first part of the question.

We would be willing to acquire if we needed to equity interest in pipelines.

That is what the long line pipelines in 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 that.

We're 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?

Yes, the (inaudible) in this argue in the Appalachian basin.

We got a tremendous infrastructure shortfall when you compare what is in place now with the plans that equitable and other companies have had for producing natural gas.

That means there has to be new pipelines built, et cetera, and we're the biggest player in Appalachia right now and there are large players.

For firms like -- anyone is going to build new pipeline capacity, even if it's small, a lot of times they will look to firms like equitable and other companies to step up and sign up for FT.

It's not just FT and existing pipe.

We're going to have to be conceivably one of the foundation of -- .

You dictate who gets to build by dedicating your supply

And also, a lot of times they won't bill unless they know folks like us are willing to step up and we're signals we are.

Okay.

And that is right.

I don't think we have 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 will take a step in March when we talk about it and there is with all the gas we hope to come out of here, certainly the reserve potential would suggest we can and we have to think how we market it and we are thinking about that and will in March.

We'll have a full review then.

And liquids and other pipeline projects in the context.

Okay, the other is a quick clarification of an earlier question on this booking conversion of originally booking things on vertical pods.

Yes.

And now you're converting to exclusively horizontal where you can.

You know, there is stuff going on and in fact your own engineers are involved about you used to get eight offsets versus two.

Were there any dislocations in your puds this year as a function of, in effect, this declaration to go from processing one way to another?

Did we get some proved reserves actually moved back to -- excuse me, some pods to 2-3, 3-p?

We recognized the issue.

It didn't have a material practical effect on the reserves this year.

Okay.

Yes.

An incremental thing.

In and around the entries and as you migrate the stuff.

It didn't happen this year.

No, it doesn't and that is what -- to a material extent.

You're right.

That is an issue.

You run the risk it's possible to move on out for that reason and that, I think, you get back to Murry's comments about the appropriateness of the reserve classifications for a resource play.

Exactly.

Okay thank you.

You're welcome.

Thank you, your next question is coming from Ray Deacon of BMO Capital Markets.

Please go ahead.

Thank you.

I was wondering if you have a breakdown of $535 million of E&P Cap Ex, how will that be distributed across the different plays, debonian shale, extensions ramp?.

No.

I;m sorry.

I'm afraid you're going to ask that.

We just broke up into drilling versus the midstream.

We haven't done that yet.

Got it.

And maybe -- I'll tell you, one of the reasons we haven't done it to be frank with you is I would like to drill as many horizontal wells as we can and that is kind of a moving target, right?

I said it in my comments today but I really meant it.

There is no limit at this point that we see.

Practical limit to how many horizontal wells we can drill.

Our guys are, you know, really, really doing a great job here and what I mean is there is no limit from a rig availability personnel, that kind of thing.

What we're limited by is to get the permits and get on the ground and do the wells and if those barriers start to clear and we're working on clearing them and working hard to clear them, then, we'll put as much Cap Ex as we can in the horizontal well versus something else.

And I have been hesitant to give those breakdowns.

I'm trying to push it, push the envelope and it would not be productive to put it out and change it every quarter.

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

Yes, that is a good point.

Okay.

And far as the infrastructure costs that you're spending, is that likely to remain at that level, if you look at 2009 and 2010, or does it taper off in 2010?

Of course, we haven't given the numbers, Ray, and I can't do it today.

You come to an unavoidable conclusion that is this is going to keep up for awhile.

We'll try to give more color in March.

Okay, got it.

And on the increase in the probable possibles was more than I was expecting.

What kind of -- did you have your reserve engineers, you know, is this kind of fully reviewed by them or like a contingent resource study, how would you characterize that 13 t number.

The pig number.

The p-3 was reviewed and the resource potential -- potential at this point do represent for the most part,ality lost acreages.

We have a notion of how many wells there could be and since we don't have much data, we gave a range on volume per well.

It's what everyone else does.

You put spots on the map and try to evaluate how much volume for well.

We have to do more drilling and move it up the latter a bit.

If you're asking whether it's been those emerging playing have been fully vetted by outside reserve engineers, no.

Yes.

Got it.

And actually one last question.

With Nora CBM, it looks like you don't have quite as aggressive a number as some people.

What would your CBM estimate be for down spacing and Nora, I guess n this 3P number.

Think it's fair to say that most of that number is related to Nora, yes.

I don't, you know, we don't -- what we really did this year is it kind of, kind of reduced the amount of non-nora CBM that we really put here.

The prioritization of the work to the shale.

We have so much to do on the shale and so really, I think it's fair fair to say that most of the 3P is Nora related.

The vast majority.

You have a little bit of stuff here and there and most is Nora.

Okay, got it.

With the reserve bookings, do you follow -- is it a 3-year ad inventory you that book, is there kind of a rule you that try to stick to?

We stick to the rules.

It has to be economic.

Got it.

And they have to pass economic muster.

That is what we're using on the P-3.

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 it was.

Just want to make sure.

In terms of the last update in the rating agencies, the w double a 1, are they aware of the Cap Ex plan you guys have outstanding and are their they -- what you talked about in terms of your financing plan this year and may be something half equity linked and sort of financing the rest of the second half of the year.

Is that kind of part of that rating?

They have -- yes.

The rating you referenced was moody and they took us to double aa1.

You also saw SMP took us to triple B flat.

And both had full disclosure on our financing plans.

I want to make sure you know we're clear we're going to do up to $500,000 of debt and more debt plus equity and equity content securities to follow that.

I don't want to give you the impression that everything following is going to have an equity component to it.

The first half is half a million and the second is mostly dead -- .

There is going to be more to follow in 2008 after the first batch.

Okay.

And as you think about financing the large infrastructure progression, what is the right way to finance these?

Half debt, half equity or retained earnings?

How do you guys look at that?

It's typically a 50/50-ish type of Endeavor and we're going to look at other types of security, including MLPs.

I mentioned the Cox position.

We're going to look at MLPs, especially on the midstream side of the business.

They're more attractive than they would have been when you were a tax payer.

Got you.

And we're going to look hard at them.

Fair enough.

And in Times if I'm looking at infrastructure development on the gathering and processing development 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 what that is to cost.

You put stun stuff out there in terms of what we think it is.

Have you talked about terms of what it will cost?

We talked about that in -- we will talk more in March.

The caligation -- calculation has to be that since there is so much infrastructure to be put in place, it has to approach the rate, has to approach what it currently costs us to development this capacity.

As you know, Faisel, over the last two, three years, David and I and Randy Crawford have been raising the infrastructure rates because the cost to put this in is expensive.

You have seen a track on our gathering costs go up over the last three years and I don't think it's done going up, but I haven't given you the terminal number.

We'll try to do a little more in March.

And depends on where it is.

A lot of Kentucky stuff we're talking about is involving some upfront stuff.

Big Sandy and Langley and once you get it done, using it as an example, then the incremental costs up to a point are not going to be as high.

Okay.

And then let's take it to another extreme, though and assume there is a lot of us in the industry would like to see happen and may happen that the high pressure Marcellus play in Pennsylvania work list.

If you have an expansion of rocky's express, whether it's a project we're working on or El Paso or someone else's, if there is another project that brings more capacity from across the state of Pennsylvania, we could have wells that are right next to an interstate pipeline.

I'm guessing the cost to get that to market and it will be high.

A lot is involving and depends on where the largest increase in natural gas come from.

Okay.

And in terms with El Paso, and you guys being an ample tenant, do you think that that has a better-than-50% chance of going through?

I don't know.

We think it's a strong project, based on the interest we have seen.

We can't talk about that we think it's strong, though.

You touched on this earlier.

The multilateral completions.

Yes.

Have you done any of those wells yet?

No, we are -- we're probably later on that.

It's not for engineering.

We had to perm it and it's complex because no one knows what we're talking about.

It's a brand-new animal and they didn't know what it was and we have worked that out and they trying to understand what it means and it's taken long to get that across the goal line from a permitting standpoint and I believe Steve told me we're spotting this week, finally, sorely next week and we're getting one started soon here and, by the way, on that point, one of the things coming on the road is what is the location anyway if multilateral works.

We could be stacked from the same -- [ Indiscernible ] And there are going to be all sorts of cool stuff that we're going to get here.

Cleveland and Marcellus, there are several places we can do this and -- right now, we have not don one yet.

When we do one, we'll let you know.

Going back to an earlier we on the 3P reserve, you said a lot of that movement was because of the Nora field?

Say what?

you said that was due to the Nora field downspacing?

No, no, no, the increase in the reserves we showed from P 3 from '06-'07, if I understand your question s dominated by shale.

I wanted -- I thought I heard something.

He was answering a question then about the reduction in CBM.

Got you.

Got you.

And he was saying the reduction had to do w in CBM, primarily had to do with areas outside of Nora.

Okay.

Understood.

Understood.

Okay.

Fair enough.

Thank you for your time.

Okay.

Thank you, your next question is coming from Rebecca Followill of Tudor Pickering.

Please go ahead.

Good morning.

Great well results and great momentum you guys have on drilling, yet it's not yet showing up on production.

You talked about an exit rate that is significantly higher in 2008.

Help me understand a little 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 making?

Is it interstate (inaudible) capacity?

What's the constraint in there and trying to get a better feel?

And the main constraint, Big Sandy will help.

Langley will help more, May king will help more.

I think it's mostly stuff upstream of the interstate pipelines is my answer to that question.

And that is a lot about we've got.

Some of it coming on in the first quarter, some of it second quarter and it's kind of gradually -- .

Yes.

A little helps at a time.

Right, and the reason I did the year-end rate rather than some incremental rates is that the times of when all the piece comes on could shift one way or the other and so rather than give incremental guidance on that, I chose to do a year-end where we think that enough of the pieces are going to be in place that we should be seeing quarter-on-quarter increases in production.

You're 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 not.

They going to be critical and they're the upstream project.

That is not to say that there are not or will not emerge downstream interstate pipeline capacity or processing or liquid issues.

Those are coming, too.

We're getting ahead of those, we hope.

Now.

But the current issue, call it smaller pipe problems, upstream of the major interstate pipelines.

That right now is the main thing that we're concerned about.

Dave, you want to comment on that anymore?

It's true.

When you look at our drilling.

A lot of the increase is coming from horizontal.

As pleased as we are about the progress we've made, 2008 is going to be the first year where our drilling is dominated by horizontal drilling.

Even with the success we had in 2007, it was still a relatively small percentage of our overall number of wells drilled and prior to that, they were not.

There were five before 1/1/07.

so even though we're talking about this movement, we're really still in the midst of converting ourselves into a horizontal drilling oriented company in the shale.

And the first well in Virginia that was drilled and this is the one we drilled for range in the north field, that well, as I said produced almost a half million a day for the first month and came out strong.

The reason I'm making a point, I'm not talking about IPs, but came on at 1.2 to 1.3 million a day.

All of it showed up at the sales meter.

The reason that was true is 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 look at the first downstream meter and we're saying half or sometimes less than half of the gas that we should have expected, that we would have liked to have seen based on the initial production from that well and that' the clog-up right now and I wish I could -

The high pressure Marcellus in Pennsylvania, the reason we're delaying frakking it, is we don't want to frak until we get ready to turn it in line.

We won't be ready until we complete some pipelines that are underway and that is the kind of stuff we're dealing with everywhere right now.

And I think it's important to have this, and we might be talking more about it than we we should.

This is the Appalachian Basin right now and it's sort of our Rockies problem, right?

Rockies had a problem.

We have this clog-up in the gathering processing aside and the shareholders need to know that's not going away right away.

It's going to take time and investment and we think there are good opportunities in those investments and it's going to take time to lubricate the system to get the gas-to-market.

Under no excuses here, that is the way it is.

Thanks.

One of the things that is interesting, when you look at your peers, the Cap Ex that they spending on midstream is nowhere near what you're doing.

People are not talking about this to an extent.

Are you unique in your situation or is the rest of the industry hasn't gotten to talking about it or they don't know the region as well?

You know what?

Becca, I have enough trouble working out -- .

If you don't want to comment on the others, okay.

That is fine.

Changing subjects to MLP.

You said you're going to take a hard look at MLPs again.

What do you mean by take a hard look?

Well, here, you know Equitable as well as anyone does.

We focus on cost-to-capital here.

It was our view that as a tax payer that we had limited amount of assets, at least currently to put into an MLP because of the tax leakage on those tax depreciated assets.

If MLP S OFFER US A LOWER COST OF CAPITAL FOR THE MIDSTREAM CASH FLOWS, RIGHT, IF THEY DO THEN WE'RE GOING TO DO ONE.

THAT IS BASICALLY WHAT IT BOILS DOWN TO.

IF WE CAN DEMONSTRATE THAT TO OURSELVES THAT THIS IS A SUSTAINABLE DIFFERENCE, WE HAVE TO.

EQUITABLE WOULD HAVE TO DO IT.

THAT'S WHAT WE DO AROUND HERE.

THAT IS WHAT I'M GETTING AT.

IT HAS TO BE PROVEN TO US THAT IT IS A REDUCED COST OF CAPITAL IN THAT THING.

THAT IS GOING TO DRIVE US.

And how long will it take you to figure out?

I don't know.

Phil, you want to -- this year project.

Yes.

A this-year project.

It's a newly project.

I'm glad we weren't planning on going to market with one this week.

I think that's good.

Right.

I mean exactly.

Right.

Sustainable reduction in cost to capital.

Thanks, guys.

Thank you very much.

You're welcome.

Thank you, next is a followup question of Ray Deacon of BMO Capital Markets.

Please go ahead.

Hey, Murry, it sounds simplistic, but if you're adding reserves for $0.48 and Chesapeake after adjusting for operating expenses they have to incur as selling reserves for $4, seems like a good business model to me.

Would you consider any of that and also with the ratings agencies, you sounded like we're comfortable keeping your ratings where we are, the slightly lower level and they're going to ask to you to hedge and I guess lastly, what you were looking at the capitol you're spending on the midstream, where do you get by the end of the year if you look at, like takeaway capacity or how much of the probables that does it open up for you?

What is the right way to look that?

Let me take the third question first in March, we'll try to give you pictures on that and we'll show you by region what the production profile is we think we can have and what capacity is available and so can you kind of get a feel for that.

It's regional as Dave mentioned.

Different problems in different areas and there is no way to generalize and let Phil take the hedging thing and we'll talk about the first question.

You want to talk about the hedging thing?

Sure, give us credit we have the LDC business and the significant amount is in the form of the midstream and they give us credit for the fact that historically we hedged.

Having said that, we didn't commit the kind of current rating to doing loads of more hedging.

That is something we'll look at and if we think we need to do it, we'll do it.

That is not a commitment to the rating agencies, does that help?

It does.

Dave started on this and I will elaborate on the first question.

We're also open to the idea of fine tuning our asset base and we think we demonstrated that in '07, whether it's equalizing the interest in Nora by getting the 50/50 across the board or buying back positions that we have, but right now, near-term, we have an issue with a larger-scale divestiture, even with the economics you're Bach kind of held up for a specific circumstance and that is because what we're finding is almost every time we relook at a play, it seems as if there is another development opportunity.

What we're reluctant to do right now would be to divest something without knowing what the further development is.

Even in coal, said we're not spending as much effort in 2008 as Murry alluded to.

It's possible we figure out another way to exploit that opportunity.

You don't want to be caught in the wrong side of divesting something, if there is a major new way to exploit the resource.

Right, and just to elaborate, when we did take some care giving you the resource potential from the 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're actually taking -- there is current activity on them, right 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 trite to evaluate it and so I think we're we riped up to do that we're lined up to do that and if we find certain aspects of the reserve are not as good as we think and certain areas down on the priority list, you know, we'll consider that down the road.

Right now is not a time to do that.

We're learning and we're taking actions on all of those emerging plays and reserve potential opportunities right now.

This is going to evolve.

Right.

We do understand the -- what you talking about.

Right.

If you give it up for 15 years, the MPV is something.

Exactly.

We get that and we got the math.

We're worried that we don't want to sell something we don't understand.

Right.

Thanks.

Okay.

Thank you.

Next is a followup question of Rick Gross from Lehman Brothers.

Please go ahead.

Yes, you talked about the business not being pipe-driven opposed to well-driven and the questions meandered through that.

From a standpoint of just trying to conceptually think about this is, I assume, we're going to see stair steps as we build out corridors and turn them on and we built or begun to build out the Big Sandy/Langley corridor and the others behind it.

That was like a war on a single front in Big Sandy, right away issues, we got Langley turned on, we had liquids take away issues.

All the timings are going to want to dove tail.

Otherwise, you end up turning on meters and shutting down the low pressure wells and you're going to go from it sounds like a -- on the single front to the amount of money you're spending the war on a multiple front.

Not one corridor at a time but maybe multiple corridors at a time getting all the stuff to dove tail.

Right.

How do I think about, we'll call it the well count behind that?

It would seem you want to have the wells ready but you don't want to be in a position where if you're delayed six months anywhere along these corridors, you go to the back of the line 15 years from now.

It's clearly the whole planning around the corridors is something we're spending a lot of time on around here and I think we'll talk more about that in March.

It's kind of hard to lay out, but conceptually, one of the big things we're considering right now is if we build a corridor, how much of a flat life for that capacity are we expect something in other words, in the May king corridor, you said there are 1300 well locations back.

There are we going to build, we have decisions on May king, but are we building that to accept the peek production from the 1300 wells or are we accepting that there will be a rampup to a flat life for that pipeline system for some period and then a decline?

In other words, we're going to continue to drill into the capacity with the own well.

That is something we're thinking about.

If it's a flat life, how long is that flat life?

What is the most economic way to think about that and then from that, how do we stage the wells to be drilled?

So, conceptually, you're right.

We're imagining going forward, a stack or stair step of corridors that build up to our production growth and we're sort of mining the gas.

It's very manufacturing kind of a model, but the driver for the growth will be the corridors we stack one on top of the other.

And having said that, you're right.

The planning issues are more complex and we do have to be developing multiple corridors at the same time, permeating multiple corridors at the same time and that is the logistics problem around with which management is spending most of the time right now and that is complex.

It's not unsolvable and we think we have an orderly approach but it's not all sorted out yet.

We'll give more detail on this in March and show you how to stair step, how it works and what the next few projects are.

A couple of financing kind of related things.

The attractiveness of hybrids ebbs and flows to some degree with credit markets and I don't know what your view is there, but our view is credit spreads will continue to widen and on occasion, the hybrid market, if do you the basis point math gets expensive and that appeared to be kind of what you were hoping, putting words in your mouth, to do, opposed to a shorter-term asset sale or straight equity.

Is the math going to be sensitive or is it just the idea we don't want to do equity and so the math is a little off.

We would prefer to do the hybrid?

Like marty said with the MLPs, we're going to look at it as a cost of cap to capital and we were looking higher up and around the financing of the acquisitions.

The only deals are at financial institutions and they at high spreads.

We don't have a view they coming in any time soon.

We hope they do.

It's an efficient way to get equity content.

We'll look at the cost of capital and consider our view of the stock price at the time and we would consider doing one.

Okay.

Round about way of asking about the MLP but in the copparticular of financing and philosophical, can you go the high splits route, the MLP route, the high splits route has pros and cons but just from a straight financing cost the capital standpoint the LLC would seem the way to go.

I think -- .

The other issue is you have huge capital expenditures, there are two philosophies.

We build and drop or we drop and build.

We are so far away from that at this point.

We understand what you're saying and talked about the issues.

I don't know where we're headed.

We're looking at all of those.

Yes.

Okay.

We understand what you're saying, though.

Is VPPS, I was alluded to earlier.

VPPs are straight debt but was alluded the - caught the lending rate on that VPP appear to be pretty attractive.

Is that just off the table because really it's debt or as?

Our view is based on what we kind of issued capital, wasn't clear that the rate that was attractive versus issuing straight debt for us.

We continue -- if we continued on the credit profile, that changes and it's not obvious of an attractive way to get there.

Okay.

Thank you.

Thank you.

There appears to be no further questions at this time.

I would now like to turn the phone back to Patrick Kane for comment.

That concludes today's call.

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