EQT Corp (EQT) 2008 Q4 法說會逐字稿

Ladies and gentlemen, thank you for standing by, and welcome to the 2008 year end earnings call.

All lines have been placed on mute to prevent any background noise.

After the speakers' remarks there will be a question-and-answer session.

(Operator Instructions)

Thank you, I would now like to turn the conference over to Pat Kane, Chief Investor Relations Officer.

You may begin your conference.

Thanks, Sierra.

Good morning, everyone and thank you for participating in Equitable's year-end 2008 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.

In just a moment, Phil will provide an update on the company's financial results which were released this morning, then Murry will briefly review a few topics, including our 2008 reserve update also released this morning.

Following Murry's remarks, we'll open the phone line to questions.

But first, I'd like to remind you that today's call may contain forward-looking statements related to such matters as our well drilling and infrastructure development initiatives, reserves, reserve replacement ratio, expected well costs, financial plans, capital budgets, and capital expenditures, growth rate, operating cash flow, and other financial and operational matters.

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 these forward-looking statements.

These factors, along with other cautionary matters regarding certain non-GAAP financial and operational measures to be discussed this morning are listed in today's earnings release, the company's 2007 Form 10-K and on our web site.

I'd now like to turn the call over the Phil Conti.

Thanks, Pat, and good morning, everyone.

As you saw in the press release this morning, Equitable announced 2008 earnings per diluted share of $2.00 which compared with earnings per share of $2.10 in 2007.

2007 results include a net pre-tax gain of about $126 million from the sale of crude reserves in the Nora Field and $21 million of expenses associated with the now-terminated acquisition of People's and Hope Gas.

Results in 2008 included an $85 million swing in executive compensation expenses as a result of reversing expenses previously booked under the 2005 executive compensation plan.

There was also a $10.7 million pension settlement charge, and a $7.8 million investment impairment related to the company's captive insurance subsidiary, both of which were in the fourth-quarter 2008 results.

The net impacts of those items, as well as the loss of operating income from the sold Nora properties, the Lehman bad debt expense that we took last quarter, an exploration expense in 2008 that was not present in 2007 I think masked the fact that 2008 in total was an outstanding year for the company from an operational as well as a financial perspective.

If you normalize for all of those items, Equitable's operating income grew about 27% in 2008.

Operating cash flow also increased by over 160% as a result of increases in operating income at all three business units, as well as lower cash taxes resulting from accelerated depreciations of our capital investments.

I will go into a bit more detail on taxes and cash flow in a minute, but first, a quick review of the 2008 financial results starting with production.

2008 production performance was driven by higher revenues due to higher realized prices and higher sales volumes.

We are reporting total sales volumes that were 9% higher than in 2007 and 12% higher when adjusted for the sale of the Nora Field properties.

In the fourth quarter, the good news continued as reported sales volumes were over 19% higher than the fourth quarter of last year.

I mentioned prices were also up.

The average wellhead price in '08 was about 16% higher.

And that was driven by higher NYMEX prices for our unhedged volumes.

For the year, higher operating expenses offset a portion of the benefit from higher volumes and prices.

Approximately half of the increase in operating expenses was for DD&A and lease operating expense.

Both of which reflects our increased drilling and production levels.

About a quarter of the increase was from higher production taxes, again reflecting the increase in NYMEX and higher volumes.

In addition, the company invested $9 million in 2008 for the purchase and interpretation of seismic data targeting deep zones which shows up as exploration expense in the financial results.

Moving on to the midstream business, operating income here was down about 4% for the year despite the fact that total net operating revenues were 16% higher than in 2007.

The increase in revenues was driven by three main factors -- higher gathering rates, new revenues associated with putting Big Sandy pipeline into service, and higher natural gas liquid margins.

In the second half of '08 midstream, and specifically the gathering and processing business within midstream, recorded a $10.7 million charge that I mentioned upfront, associated with the settlement of pension obligations that resulted from the restructuring of our Kentucky operations, as well as a $5.2 million bad debt loss on the Lehman Brothers bankruptcy.

Excluding those two items, operating expenses were about 26% higher at midstream as a result of our ramped up activity level.

The majority of which was planned as we prepare to transport record production volumes to market.

On the pension settlement for just a moment, over the past 10 years, Equitable, as you know, has produced the number of employees receiving a defined benefit pension from about 1,965 employees to currently about 19.

We prefer instead to provide retirement benefits in the form of defined contribution plans.

As a result of this restructuring, our cash funding requirements are down considerably, and the retirement benefit obligation of Equitable resource was only $67 million at year end or less than 2% of our market cap, as opposed to closer to $350 million had we not adopted this approach over the last 10 years or so.

Moving on to distribution, operating income at distribution was about $60 million in '08, or $25 million higher than 2007.

About $20 million of the increase was due to the absence of acquisition charges on the terminated purchase and sale agreement to acquire People's and Hope Gas.

The rest of the variance could be explained by colder weather year over year.

As we previously announced, Equitable Gas Company did reach agreement with the Pennsylvania rate case earlier this month.

A Pennsylvania administrative law judge recommended that settlement be approved by the Pennsylvania PUC.

Projected annual revenue increase from the new rates is about $38 million, although only about half of that will show up in 2009 since the new rates won't go into effect until this spring.

In addition to achieving the favorable rate case settlement, distribution improved customer service levels to the best in Pennsylvania for our call center, our on-time scheduling and, most importantly, safety.

We believe these service levels contributed to a favorable rate case result.

A couple of quick observations on the fourth-quarter results.

Despite the fact that Equitable operating income for the fourth quarter was down about $12.4 million versus the fourth quarter of '07, it was an excellent quarter from an operating standpoint with, again, the 19%-plus production sales volume growth that I mentioned, as well as increasing gathering, processing, and transmission volumes in our midstream businesses.

The favorable operating trends were more than offset by unfavorable market conditions for natural gas liquids, which negatively impacted our midstream business.

While NYMEX gas prices were virtually flat in the fourth quarter versus the fourth quarter of '07, the liquid prices, which, as you know, tend to follow oil prices, were down considerably.

The average liquid price in our midstream processing business was $0.71 a gallon in the fourth quarter '08, or about 45% lower than the $1.30 we received in the fourth quarter of '07, and that variance resulted in a $13 million of less revenue quarter over quarter.

So liquid prices were lower, and the reduction was partially made up by an over 47% increase in NGL volume production in the quarter.

Lower seasonal spreads in natural gas prices in the fourth quarter also contributed to the midstream results.

They realized about $10.9 million less in price-related revenues in 2008.

That's because the storage deals that settled in fourth quarter of '08 had spreads that were 40% lower than in the fourth quarter of '07.

That decline was partially offset by an increase in revenues associated with basis spreads captured through the utilization of our Big Sandy pipeline.

Overall, lower liquids prices and lower storage spreads in the fourth quarter resulted in approximately $24 million less revenue than in the fourth quarter of 2007, and that, coupled with the pension settlement charge, explains the large reduction in midstream operating income in the fourth quarter of '08.

A couple of other items -- executive compensation.

As a result of the volatile equity markets, it's clear that compensation committees at public committees are rethinking their approach toward incentive comp, and Equitable's no different.

For 2009, the compensation committee has decided to implement a program that, again, seeks to align management compensation to long-term shareholder return.

Consistent with prior programs, the payout factors are stock performance relative to a peer group, similar to the plan that just ended, and absolute return on total capital.

However, the executive compensation program will only pay out if shareholders receive 2009 results comparatively better than the recently completed four-year period, which ended with a $33.55 stock price and a 1.75 times times multiplier.

The expense of this program in 2009 will be determined quarterly on a mark-to-market basis.

To give you an idea of the potential outcome, if, for example, the stock price finishes 2009 at a price 20% higher than the closing price in '08, and Equitable's relative shareholder performance improves to the two times multiplier level, there would be a total expense associated with this one-year plan of about $23 million.

A quick note on income taxes.

You may have noticed that our effective book tax rates for the year increased versus '07 from 36% in '07 to about 38% this year.

Despite the fact that our cash tax payments have gone down significantly.

The increased effective tax rate is due to the fact that we are in a net operating loss position for cash taxes and can no longer utilize certain deductions and taxes that we benefited from when we were not in the net operating loss position.

This impact was more dramatic in the fourth quarter since we comparatively didn't have as much pretax book income available to achieve the proper effective tax rate for the full year.

Taxes were booked at 43% in the fourth quarter rather than the 35% booked in the fourth quarter of '07, resulting in an extra $5 million in income taxes recorded and in fourth quarter '08 due to the rate differential.

That's about $0.04 a share.

Going forward, for modeling purposes, I would suggest a reasonable starting point would be to use the annualized 2008 effective tax rate of 38%, and then we will forecast the full-year effective tax rate when we release first-quarter 2009 results.

And finally, a quick cash flow forecast update.

During the third-quarter conference call, we forecasted 2009 operating cash flow of $700 million to $750 million, and 2009 year-end short-term debt of about $700 million to $800 million, net of any seasonal working capital swings.

That was based upon a $7.50 NYMEX price and $1 billion CapEx budget for 2009.

If you would, based on the current 2009 strip of about $5 for MMBTU and the same $1 billion CapEx budget, we would expect operating cash flow to be about $100 million lower.

And therefore, short-term debt to be approximately an additional $100 million higher by 12-31-2009.

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

Okay, Phil.

Thank you, welcome, everybody.

As Phil mentioned, this was, by any number of measures, a record year for Equitable.

He discussed many of the relevant facts, and a bunch of them are also included in the release, so I won't repeat those.

But standing back from all of that, here's how I see what's happened strategically for Equitable in 2008, and our report confirms that.

First of all, horizontal air drilling can be employed in a massive campaign to accelerate the profitable development of the Huron shale in Appalachia, that's number one.

Number two, EQT can, and is just at the front end of, demonstrating that its natural gas sales growth rate can exceed 20%.

And of course our fourth-quarter growth rate in production sales demonstrates that.

Of course, access to capital is a temporal barrier.

And third, that our reserve base, newly revised, born out of new technology and industry-leading cost structure, will sustain high natural gas growth rates for a long time to come even if natural gas prices are at the current levels or below.

I would like to talk a little bit about reserves.

Just to be clear, though, in light of the economic situation, for the next couple of years, we are employing our weather the storm plan which contemplates our spending the vast majority of our time, money, and attention in areas where infrastructure has already been built.

So, an expansionist view of reserves at this moment was not at the front of our mind as we constructed this reserve report.

However, the combination of drilling results, technology, and most importantly our low cost structure combined to yield a pretty large increase from year to year.

As we reported in the press release, proved reserves stand currently at 3.1 trillion cubic feet, up 428 Bcf ,or 16% versus our 2007 report.

Of the 428 Bcf increase, 130 Bcf is due to inclusion of the Berea and Marcellus plays in our proved category, for the first time.

The Huron shale play accounts for another 344 Bcf approved additions.

Offsetting those increases were small decreases in coalbed methane and other categories related primarily to backoff reductions and volumes from old wells where new midstream infrastructure has not been built.

Also there was a little reduction in Cbm due to development prioritization in light of the economy.

P-3 reserves stand at 9.47 Tcf, up about 2.24 Tcf or 31% versus the 2007 report.

Almost 1.5 Tcf is due to inclusion of the Berea and Marcellus plays in our unproved categories for the first time.

The Huron shale play accounts for an additional 0.8 Tcf of the increase.

More importantly, we thought you would be interested in the internal process for how we booked reserves for the major play categories.

As a general comment, we of course use the FCC definitions for accounting for our proved reserves.

And Ryder Scott audits those assessments.

For unproved categories, probably and possible, we use the SPE guidelines.

Probable locations we consider to be any non-PUD location in our core development areas where we have good well control.

For Huron, our core development areas are in eastern Kentucky and southern West Virginia.

For Berea, our core development area is in Kentucky.

For Marcellus, the core area is Southwestern Pennsylvania, northern West Virginia, and for reserve purposes only includes areas adjacent to wells we have already drilled.

Possible reserves include Huron horizontal locations, with a vast majority of spacing units we have on acreage in Kentucky and southern West Virginia, beyond the probable locations.

Possible reserves for Berea horizontal include, again, horizontal locations beyond the probables only in Kentucky.

And for the Marcellus, possible reserves include vertical and horizontal offsets to probable locations within our core area.

At this time less than 10% of our Marcellus acreage is included in our three-P totals.

For emerging plays, we are including reserves we think will fly up into one of the P-3 categories with further work over the next couple of years.

And, therefore, we are not representing that the numbers we have put forward in the emerging play category describes the total resource potential of our acreage at Appalachia.

Currently included in our emerging plays are the following -- first of all, for Huron, the emerging plays include Virginia.

There are some encouraging results in the Huron in Virginia, but not enough yet to have these locations included in our P-3 categories.

On re-entry, while we've had a number of success -- this is Huron re-entry now -- we've had a number of successful re-entry wells drilled in the Huron during the year, and we're obviously very, very encouraged by that.

Our engineers would like us to hold back on booking additional reserves from horizontal wells drilled immediately adjacent to the existing vertical wells until we are absolutely sure there is not interference between the old vertical wells and the new horizontal wells.

I know what you're thinking, and just consider this I know what you're thinking, and just consider this another interesting upside to the EQT story.

For Berea, locations for Berea in West Virginia and Virginia are currently excluded from P-3.

There are encouraging results in both states, but we are not yet ready for these locations to fly up into the P-3 categories.

We need more results from those wells, and just so you know, we also have midstream infrastructure that needs to be built to prosecute the Berea play fully in those states.

For Marcellus, as I previously mentioned, we've only included 10% of our acreage in 3-P.

Potential locations on the rest of our 400,000 acres are included in the emerging play category and the range obviously is due to our assembly of potential EUR outcomes for those particular location.

I hope that helps you frame what's in and what's out as far as our current reserve report's concerned.

Turning to costs, I wanted to make a couple comments on costs.

Both in our earnings release and in our reserve release, there's some discussion of these costs.

And particularly at this time, I wanted to focus on a couple of them anyhow.

F&D costs, as you can see, have pretty much held the line from year to year.

Particularly in light of significant increases in steel.

As a matter of fact, steel price increases added about a $0.10 to our unit 2008 F&D costs, and this factor alone accounts for almost the year on year variance.

Clearly there were other in and out factors that affected the unit F&D, but if you want to make a shorthand explanation for that, it's steel.

On LOE during the fourth quarter, we tried a number of refracs on vertical shale wells, and that accounted for a big chunk of the quarter-on-quarter and year-on-year variance.

Excluding these refrac costs, our unit LOE expense went from $0.31 in 2007 to $0.33 in 2008, which, again, that level is among the lowest in the US oil and gas industry.

Turning to a couple of other metrics that I thought you might be interested in, we've talked about this before, but our current view is that the break-even nature gas price for EQT to continue to earn nominal cash profit is $2.50 per MMBTU.

For investment purposes, we will earn at least our cost of capital at at a constant forward price of about $4.50 per MMBTU.

And our current assessment of maintenance capital required to keep production flat is about $150 million to $160 million.

There are a couple of other technology updates on multilaterals.

We spot 11 multilaterals, six in the Huron, and five in the Cleveland.

All but one of the wells was stacked with a second multilateral.

And one pad contained four wells with two stacked pairs.

Each of these multilaterals averaged about 11,700 feet of lateral drilling.

Five wells are turned in line, three wells had at least 30 days worth of production.

And are averaging between 200 and 900 MCFE per day for the first 30 days.

And we plan to drill a number of other multilaterals for 2009.

In the Marcellus, in 2008 we spud 23 Marcellus wells, seven horizontal, 16 vertical.

13 of those are in line with at least 30 days of production.

The horizontals, there are only two of them that have been on line that long.

The 30-day IPs are 1,300 to 2,000 MCFE per day.

Expected costs for wells, for conventional drilling, we still are at $4 million or less.

And again, we're still looking at horizontal air drilling, as we mentioned previously.

The vertical wells, 11 are on line with 30-day IPs, and they're producing about 400 MCFE per day average for the first 30 days.

We planned to drill 45 Marcellus wells in 2009.

But that could change depending on well results.

We will continue to experiment with air drilling.

Most of our drilling will be focused in Green county, Pennsylvania, and Doddridge county, West Virginia, where we're building gathering, and processing infrastructure.

And I think, as we've mentioned before, our acreages, is very near the acreage that's currently being developed by Range at a very concentrated area.

And I know we've had some good results.

And we're right in the middle of all of that stuff.

And we're encouraged to see their results from those drilling.

Finally, as you saw in the release, at this point we are reiterating our capital expenditure guideline of $1 billion for 2009.

And with that, we'll turn the call over the questions.

Thank you.

That concludes the comments portion of the call.

Tiara, can we please open the call for questions.

(Operator Instructions) We'll pause for just a moment to compile the Q&A roster.

Your first question comes from Scott Hanold with RBC Capital Markets.

Good morning.

Could you talk a little bit about NGL prices?

It obviously has come down in fourth quarter.

I think it's firming up a little bit now.

But what are the thoughts on putting some hedges in there on the midstream side, just to give yourself some protection when those are weak at times?

Scott, we have periodically looked at putting hedges in for our liquids.

The pieces we've got on liquids as far as hedging is it's difficult to go out very far in hedging.

At least in much volume.

And we've noticed that there's a big basis risk, a locational basis risk associated with where you can really hedge, which is Mt.

Bellevue and what we experience up here.

Sometimes that basis risk is greater than the absolute price.

So even though we are open minded and occasionally have done some hedging of that, we struggled with that as we looked at it in '08 because of those issues.

Okay.

Is there any really good option for it, or is it just one of those things where you're going to get the price, it is what it is.

What we've been investigating -- we probably haven't spoken much about it, but I think a lot of folks are probably investigating -- is enhanced local usage of natural gas and natural gas liquids.

By that I mean investigating whether it makes to generate our own electricity using natural gas liquids.

And that sort of thing.

Or compressed natural gas or liquids, compressed natural gas stream, if you will, for fuel in our fleets.

So local usage of natural gas liquids is something that we've been spending a bit of time, we'll spend more time in '09.

Okay.

But that's a long-term solution.

That is true.

Okay.

Okay.

The shorter term solution is for folks like you to use more propane.

Start smoking and use butane.

I'm up north here I open my window and keep the heat on.

We'll send you a t-shirt or something.

Looking at the reserves, some of the emerging reserve numbers, can you talk about some of the reentries and wanting to see some more production results before you start putting that into your 3-P number.

Can you give me a sense of how long that assessment should take, and is this something you could have looked to in 2009 as a bit of upside.

Yes.

I think so.

I think the -- there's no question -- well, first of all, we have not seen interference yet, okay.

Just to ease your fears.

Maybe a little bit here and there, but nothing that we think is all that onerous.

But I just think that we're going to need a six months or so more production.

Many of these wells only have a couple of, or three months of production.

And, we'd really rather have, our engineers would really rather have a little bit more look at that.

Really, this only affects the locations that are actually at the location of the existing old vertical wells.

They asked, and I thought it was legitimate to just wait for a little bit more time on that.

but clearly in the 2009 reserve report we will have made significant more progress there.

We'll make a much better assessment at that time.

Okay.

And then turning to the multilateral.

I guess you drove 11 of those.

Now the 200 and 900-a-day rates, could you give a sense on where that fits into your expectation and where you hope to get that in 2009.

Keep in mind, we're reducing the costs for those things.

We're improving the geometry.

I think we're pretty satisfied.

These things are producing naturally, keep in mind.

We're not fraccing these things.

They're absolutely within the range of what we hoped that we'd be getting so far.

Again, you need to see these a little longer, too.

Yes.

What do you expect the costs on those to be?

A little less than a standard vertical fracced well.

I think the standard Huron well is now about $1.2 million.

We expect these to be a little cheaper.

Again, for one 12,000-foot multilateral, $100,000 cheaper.

So I mean, a little bit.

Okay.

One last question if I could.

I may have missed this if you said it, but I think in the prior quarter you talked about getting potentially a tax refund in '09.

Is that still something you expect?

What's the timing on that?

Absolutely.

I believe it's the first half of '09, but certainly in '09, we're expecting something a little under $100 million in a tax refund, which is included in the operating cash forecast that we give.

Okay.

Appreciate it, thanks.

Okay, Scott.

Your next question comes from Shneur Gershuni from UBS.

Good morning, guys.

I'm sure some of my questions have been asked as I've been passing from conference calls here.

But I was wondering if you can talk about the efficiency in your drilling program.

Can you talk about air drilling in the project or not or whether it's moving forward.

And also if you can talk about days to drill.

Are you seeing efficiencies there and so forth?

If you can comment on that?

Well, first of all, air drilling -- you must be speaking about the Marcellus because the air drilling is in full, complete execution phase in the Huron play.

Yes, in the Marcellus.

I have to keep reminding everybody that the Huron play is the bread-and-butter play for Equitable now.

Marcellus is a good thing, but it's icing on the cake.

But yes.

So no, I think on the Marcellus air drilling, we are still in the experimental phase.

And I really don't have anything more to report.

We don't have any more results.

We're still doing some.

But we don't have anything to report yet that would be meaningful.

Okay.

And then my second question is just with respect to CapEx.

How much flexibility do you have to be able to ballot down if gas prices continue to be where they are six months from now?

Well, first of all, you saw our break-even -- we'll make the cost of capital at 450.

So there's some question about whether you'd want to ratchet back if we could make EVA, right?

I mean, that may be a problem for a lot of companies but it's not a problem for Equitable Resources.

So, I think we'll be looking at if quarter to quarter.

We'll talk about it again next quarter, and, if we see sustainable prices that are dipping into the low fours, I'm sure we're going to make some changes because we won't make EVA at that point in time.

I mean, we're very EVA focused here.

And I know you're not used to hearing that companies can make their cost of capital at 450, but we can.

Is that going to be the primary indicator?

It's just literally EVA?

We are driven by EVA here, yes.

And, by the way, subject to liquidity, right?

We'll make EVA as long we have money.

But if we don't have money, or if there's no access to capital or no prospect of access to capital, then certainly we'll make our judgments that way.

But on a purely economic standpoint, we're quite resilient to downturns in prices.

And there is, as we move through 2009, there's more flexibility to reduce if you're looking at what our requirements are or where noneconomic distinctions, kind of dumb decisions would kick in.

By that I mean, from a rate commitment perspective.

If obviously, as you roll through time it's easier to cut back as some of those rate commitments drop off.

And of course, a fair amount of that $1 billion is still in midstream projects that have already been completed.

And as we mentioned, we did not approve in our recent capital budget for 2009 any additional midstream projects.

So obviously as you move into latter part of 2009 and into 2010, if the market conditions were to continue, or were to deteriorate even more, we do have the capacity to dial that back even more.

To the point where you can head toward that maintenance number that Murry talked about if that seemed like the intelligent thing to do.

Okay.

So you're not going to be looking at opportunistics to get even more EVA by holding back a little bit if you feel that gas prices are soft?

No.

But economics aren't changing.

As prices come down, probably what is happening, which is a little bit different, as we prioritize, and Murry alluded to this with even the reserve reports.

As we prioritize some, in those circumstances where you can get more volumes to market using basically the same midstream that we have in the ground, those are going to look more attractive generally speaking than circumstances where you have to put in incremental midstream.

It's not just liquidity.

You look at the economics and say, boy, do I really want to invest a lot more midstream if it's going to drive the costs up.

Yes.

I think the way to put it is that the 450 number is based on a normal program with, if we get everything we wanted to do, we'd still break even on a cost of capital basis at 450.

But clearly and obviously we're trying to do the best things first, right.

We're trying to generate the most cash flow right now for the money that we have, and so, Dave's right.

We are high grading things.

A case in point, where for example there's a lot of Berea excitement.

And we have a lot of excitement about the Berea.

The problem is there's a lot of midstream infrastructure that needs to be built to expand that play.

Right now, we're probably going to go a little slower there and not spend the midstream, and then continue to spend money on other wells even if well by well they're a little less profitable because we don't have to add any midstream to that particular play.

Those choices are being made, as we speak.

And in contrast to that Berea situation, as we keep sharpening our pencils on the Marcellus, our views currently are that we could probably move more gas to market by leveraging off of our existing assets in the Marcellus region than we had previously thought.

So as Murry said, we're going through play by play, micro-geography by micro-geography.

And certainly there are circumstances there where we'd say, boy, the economics just look tough for putting in more midstream.

Why don't we even go further towards that focus we've been talking about for a few months on drilling into where we really don't need any more midstream.

We've talked a lot about this and I'm sorry this is such a long discussion.

But really a lot of the decision making we're undergoing now has to do with where is midstream, where can we optimize it, and in places where we either don't have it or can't optimize it, those are falling lower on our priority as far as drilling is concerned.

I mean, that's kind of the internal decision making process that's going on day to day.

It's a long answer but it's helpful to understand how we're thinking about it.

Absolutely.

And that's where I was headed.

I just wanted to understand the thought process.

That was actually very, very helpful.

One last question, just a crossing the t, dotting the i question.

You mentioned previously that you were looking for a tax rebate of sorts this year.

Can you just remind us how much that is.

A little under $100 million.

It's locked and loaded, we'll get it in 2009.

Perfect.

All right.

Thank you very much, guys.

Thanks for taking my questions.

All right.

Your next question comes from Joe Almond from JPMorgan.

Yes, thank you.

Good morning, everyone.

In terms of your negative reserve revisions, could you give us the volume number there.

And could you talk about that a little bit.

Yes.

In general, the reserve revision -- first of all, it's not cost related.

Okay, or price related.

Let me get that out.

I mean, it's a little teeny bit maybe.

But it's insignificant.

The real issue is where we don't have modern infrastructure, midstream infrastructure, we've had some backoff in some of the old wells.

And that's really the vast majority of what we're talking about there.

And a little prioritization between shale and coalbed methane, a little bito f prioritization toward shale and a little bit away from coalbed.

And that really accounts for the total.

It's a very small amount.

Okay.

So could you give us a rough number there?

It's roughly 66.

Got you.

And mostly coalbed methane.

You talked about cost of capital.

What's your calculation of your cost of capital?

About 8.5% we think.

About 8.5%?

Yes.

Again it depends on whether you're using internally generated funds or whether you have to go to the market.

If you go to the market right now that would be plus or minus infinity.

So the cost of capital calculation is highly dependent on availability.

And all the modeling and all that stuff presumed a liquid in deep market of investors that were intelligent.

And so obviously we're suffering right now with that market not being available.

But it's probably going up a little bit from that but that's kind of our baseline standard.

And when you talk about the 450 number to get that cost of capital, is that more of a short-term price or is that --

No, no.

That's 450 forever.

But what I mean by that is, is it just a drill or no-drill kind of price, or does that include, say, all costs like leasehold and seismic and capital and --

No.

That's all in.

We've included, even in that number, some provision for some midstream that needs to be used to hook up the wells to the marketplace.

We include that.

Not, as you say seismic, we're not doing much of that.

Lease acquisitions, virtually nil.

I guess in your terms, it would be drill only.

But it also includes midstream to support the drilling.

Got you.

Okay.

Then have you seen any meaningful service cost declines?

I don't know --

There probably are meaningful.

I mean, we've seen declines.

But we haven't seen the level of declines that we would expect.

I'd focus on steel as an example.

We see the steel of the sort that gets sent to use in the automobile industry.

You could see the prices of that dropping.

But the oil field tubulars, the oil country tubulars are not dropping as much as we would like to see them.

And that affects us.

I mean, that probably affects our thinking on the midstream side of the business, for instance.

We buy more steel when it's this expensive.

John Zimmer from US Steel called a couple weeks ago, just before Christmas and thanked me for our business.

I don't know.

Is that meaningful?

I sort of thought it was actually.

We are seeing declines.

We haven't see declines to the extent that we would like to see it.

Incidentally, to answer an obvious question out of that, our current mindset is to the extent that we do see further declines, we are not inclined to increase our activity level, but rather to reduce our capital expenditure.

I got you.

We are taking spot prices on steel right now, by the way.

We're not making long-term commitments.

Okay.

Got you.

And lastly, on the Marcellus shale, you mentioned that two wells.

Have you done anything different on the next wells that might give us some different results there?

You know, yes.

We're in the neighborhood of everybody else.

You got to look at this statistically.

We have a lot fewer horizontal wells than Range does.

And obviously this is a statistical game, to some extent.

So I'm confident we're going to run into some big wells here along the way.

I mean, you know, we're all using basically the same technology.

So that's not, I don't think that's a variance.

The variance is, the natural variance in the production characteristics of the Marcellus itself.

So, all I can say is we're right in between all these big wells that everyone's talking about.

We'll get one or more.

Okay.

I know you're dialoguing, there's a lot of chatter amongst the different operators so you know what they're doing, they know what you're doing.

I would say, yes.

These are all very, very smart guys.

And they're all looking -- everybody's looking at each other.

And it's very difficult to keep a proprietary drilling secret.

Got you, very helpful.

Thank you.

Your next question comes from Faisel Khan with Citigroup.

Good morning.

Good morning.

I just wan to go back.

You say the $150 million is for the capital you need to keep production flat, is that correct?

Yes.

Okay.

And what about the midstream side, if you wanted to couple that with midstream.

Yes.

What we presume that -- yes.

That's a good question.

For clarity, if we were just going to keep production flat, we wouldn't need hardly any midstream at all other than the midstream required to hook the well up to the system.

So when you're into a flat scenario, if we were into a flat scenario, we wouldn't be putting any midstream in, or just a real little bit.

So does that make sense?

Yes.

That makes sense.

I guess the next question is, as you're looking at the current curve and your projected cash flows for the year, what's the growth rate to match that cash flow over the course of the year or two?

If you look at the current curve, if you're trying to juggle, if you want to live within your means and the access to financial markets remains tight, what's that sustainable growth rate at the current curve?

We haven't given a sustainable growth rate.

But what we have said is that 15% growth rate for 2009, given what we're spending, given the $1 billion.

Beyond that, we haven't given a number that's goes out.

If this liquidity situation continues forever and gas prices are down in this range forever, we haven't given a sustainable growth rate for that.

I understand that.

But if you spend $1 billion this year, then you'll have to use the balance sheet to fund fund the difference between your operating cash flows and your CapEx, right?

Right.

So if you had to balance the two?

I don't know what it is.

Really, if you start doing that, you have to rethink a whole lot of things, you know.

Okay.

So I mean, we've certainly done that internally.

I just haven't given that number out.

What you're saying is what is the growth rate this year if we had to spend $600 million or $700 million.

I haven't given that number out.

Okay.

Fair enough.

What was the net hedge impact in the quarter for production?

We realized 444 in the well, and now I'm looking at an Appalachia price.

What was the hedge impact in the quarter?

I don't have it right in front of me.

Why don't you follow with Pat on that.

The information's in the -- the hedge information is in the table there.

But I don't have that exact number you're looking for.

Okay.

Then on the NGL price, it's a little bit different than if we're looking at market NGL prices.

What's the composition of your NGL barrel?

It's mainly, it's propane and then some butane mainly.

I mean, we don't really sell ethane.

If you look at the gas stream coming out of the ground, most of the liquids coming out of the ground are methane.

But most of that gets blended into the methane stream.

So you're mainly looking at a combination of propane and butane.

There's a little bit of natural gasoline.

There's a little.

But it's mainly, it's a propane/butane.

The propane is sold mostly naturally.

Actually the Appalachia region is a net importer or propane.

The butane and other higher components are used as ebullients to blend with Canadian oil as it comes down to the Gulf Coast.

Just so you're clear, we don't fractionate.

So we get a blended price based on that.

But we sell natural gas liquids -- the liquids stream.

The question -- how much more money would we have made if we didn't have any hedges in 2008?

Is that sort of the --

At least for the fourth quarter.

Just for the fourth quarter.

For the fourth quarter Nymex was flat.

There wasn't much of a difference at all, about $8 million.

For the year, it was about $105 million lower.

If that would affect our hedges.

Got you.

Is there anything in this proposed package that comes with depreciation or anything like that that would help you guys on the tax side going into the end of the year and next year?

Have you looked at that at all?

Our guys are looking at it.

But they haven't updated me on that yet.

You're saying other than the inflationary impacts of it.

If you want to slip something into the package that helps us, we're happy.

I want to know why we're all not bailed out.

Gee whiz, let's all stand in that line.

Fair enough.

Thanks, guys, for the time.

Appreciate it.

Thanks.

Your next question comes from Shannon Nome from Deutsche Bank.

In a world where most of your peers talk about living within cash flow, it's refreshing to hear somebody investing within return.

Thank you.

Thank you.

We don't hear that much anymore.

So thank you for saying that.

You bet.

So my question, couple just quick ones.

The realizations in Q4 were a little lower than I had on the gas side.

Can you refresh us on how, what gets you from a $6-plus hub price down to the $4.44.

I know a chunk of that is a hedge loss.

Do you happen to have those breakdowns or?

In the quarter, Shannon?

In the quarter?

Yes, in the quarter, if you have it.

What's the BTU adjustment, what's the basis, what's the gathering trend?

Do you have it, Pat, or do you want to --

Yes.

In rough numbers, $1.75 of the revenue we get from selling our gas is transfer price over to midstream.

It shows up as midstream revenue.

And that covers your gathering, your processing, and your transportation.

Yes.

Okay.

That's a little higher --

Keep in mind, and we're going to -- we have to look.

Some of that is internal pricing things.

We're going to relook at that in the first quarter to see if that's all appropriate.

We tried to set these businesses up as complete standalone.

And I think we did.

But as we looked at the numbers for the fourth quarter, we're wondering whether we established a transfer pricing in the right way.

And it's all inside baseball.

We want to make sure that we're not misrepresenting some of these transfers.

And not misrepresenting them, trying to do them consistently with how everybody else is doing them.

So people don't get confused.

So we've got a little more to do.

The numbers are about $1.75 this quarter.

All right.

And then in terms of basis premium we've kind of been using $0.20.

I don't know if that's a --

Yes, that's -- that's fine.

On average, yes.

BTU adjustment, any changes there?

That's not in the transfer price.

That would not -- the BTU adjustment doesn't change it.

But of course the practical reality for us, for the most part, once you get beyond about 1,100 BTU it's actually showing up in the form of liquid.

It's not showing up in the form of -- when we're selling it, we're not selling -- beyond about 1,100 or so or 1,130 BTU, we're not selling higher BTU gas, we're selling liquids along with gas.

We definitely got hurt with liquid prices.

I mean, since we do produce wet gas.

That definitely nicked us in the fourth quarter.

That makes sense.

Okay.

And then a simple one.

I missed the Marcellus wells for '09.

How many wells was it?

We said 40 to 45.

Originally I said we'd have 75 total Marcellus wells drilled by the end of '09.

And we did 23 last year.

We said another 40 to 45.

Which is a little lower.

I'm not so sure that number is right.

We're still looking at that number.

We're certainly encouraged by what we see, encouraged by it.

As Dave said, we are going to have some infrastructure, we want to fill that infrastructure up as fast as possible.

You may have missed this, but Dave also mentioned that we have a lot of other infrastructure, in Pennsylvania particularly, that we are trying to figure out how to work into the Marcellus play to provide us more capacity.

So we're going to take a look at that.

But notionally, 40 to 45 wells.

And any mix of vertical and horizontal.

And we didn't say this earlier, but our strategy on the Marcellus drilling, the initial wells that we've been drilling, have been a strategy to define the play outline.

Some of the other guys -- I'm not saying this is wrong -- are concentrating drillings in very specific places where they have had some good success.

And I don't think that's a horrible idea.

You know, the genetics here at Equitable are that we're paranoid about the midstream needs that come from the drilling that we do.

So we've really scattered our Marcellus wells out to try to define limits.

So that we know how much midstream infrastructure we have to put in it.

That has been driving our initial wells we have wells all over the place.

Our 23 wells are scattered.

And now we've got a couple areas we like.

We're going to drill as many wells there as we can, consistent with the infrastructure that we planned, the $40 million-a-day infrastructure.

And so now you we'll see how those wells work.

And probably do some more.if we're able.

Will the mix shift to more horizontal, and the 23, you said there's probably twice as many verticals as horizontals.

Will that split maybe in 2009?

I think it's going more balanced between horizontals and verticals.

Some of that has just to do with the geometry of the leases that we have.

What you can fit into the spacing.

David, I don't think we have a particular bias one way or the other, vertical or horizontal.

We think the verticals are profitable, we think the horizontals are profitable.

We're still experimenting with air, which could tip the balance toward horizontal.

I think the biggest issue that we're dealing with now is, as we've rethought the midstream needs around there, we're thinking about whether we want to push more of our '09 capital spending towards Marcellus and away from some other areas, but that's likely not to affect us until the latter part of 2009 because, obviously, a lot of things for the first half are pretty set in place.

And it wouldn't be away from the shales, by the way.

Right.

Great.

Before I hang up, any thoughts on the SEC booking rules coming at the year end '09?

You've obviously got a huge amounts of --

Yes.

I think, in general, this whole thing around re-entry, for example, is interesting.

See right now, if you have a vertical well you have to book offsetting well.

Even, as has happened here, in shale, we have a vertical shale well, we can't book an offsetting horizontal well.

You can't do it.

You have to book offsetting verticals in your PUDs.

Beyond that, you can book whatever you want.

Which is a very strange result.

I think you're going to see -- we would see a substantial increase in proved just because of that factor.

And I can't give you the number now, but it could be potentially pretty meaningful.

Thank you, Murry.

Okay.

Your next question comes from Sam Brothwell with Wachovia.

Good morning, guys.

Just one real quick clarification.

Your 450 break even, is that a (inaudible) area price or is that innovation?

It's a Nymex price.

That's what I thought.

Just two other things.

On the midstream are you still looking at partnering with somebody on that?

Yes.

Yes.

Enough said.

And then the last question is, with the change in the Administration and Congress, we're hearing some noise on the environmental issues, water, and even possible making some noise about regulating fracture stimulation.

Any thoughts on that?

Well yes.

I'll save the obvious ones.

What we're going to do, and I mentioned this a few times on the road recently, we are in the process of building a recycling plant for Marcellus water handling.

We hope it will be up in the third quarter, maybe a little earlier during this year.

Where we're going to try to recycle that water.

That doesn't address the point you're raising which is the one concern that some people have that we're hurting the aquifers with salt water from these fracs.

I hope adults will finally come to the conclusion that we've been doing that for 70 years now and haven't damaged any aquifers.

But forget about all that.

We're trying to recycle as much as that frac water as we possibly can.

And we're drilling more wells from the same pad so that you can reuse the water.

We're going to -- pad drilling is going to help in the Marcellus.

Recycling is going to help in the Marcellus.

But we're focusing more of our attention on the disposal of the water rather than the acquisition of the water.

Okay.

Well, thanks a lot.

Okay.

Your next question comes from Becka Fowler with Tudor [Pickling].

I'm sorry if this has already been asked.

If you guys had books the redrill wells, what reserves would that have resulted in?

I didn't give you that number.

You saw what the total table showed and a fairly large amount of that emerging play could be accounted for in this particular category.

Sorry.

Okay.

Second, an equally difficult question.

When you guys quote your rates for Marcellus, you quoted 30-day IP.

I understand your reason for doing that.

We've talked about that before.

But your peers all quote a different IP.

Any thoughts of giving both just so that we could get a comparison?

No.

Okay.

Tried.

Thank you.

We just don't think that's useful information.

That's all.

We just don't think -- it's not quite a random number generator.

But we just don't think -- you're talking about, say, the first minute or, you know, et cetera.

We just fear that it's not particularly useful information.

I'll tell you what you can do, take all of their numbers and just apply them to us and you'll be fine.

Those will be as good as any other number you could get.

So your numbers are comfortable on initial flow rate --

We think so, yes.

Within the natural variation of what the rocks are going to generate, I think Range has had bigger wells than we've had.

And those are, by the way, those are represented in some larger 30-day IP's that they've reported.

And I think that's right.

But the statistical range for all of these Marcellus wells certainly will include the big ones that they've talked about, the middle ones, and then the smaller ones.

And I think we're right in that.

We will end up, when all is said and done, right in the same statistical range as all of the rest of these wells.

So there's nothing geological that I can see.

There's nothing technological that I can see that makes the difference.

It's just that Range has drilled a lot more horizontal wells in the Marcellus than we have.

And they've exposed themselves to the statistical range more frequently.

And that also probably means they're further up the learning curve, frankly, Marcellus than we are.

We think we've defined the leadership in the lower Huron.

And we think we're active in the Marcellus.

But they're probably a little -- there are others who are a little bit further up the learning curve.

And our folks are very focused on that fact.

Okay.

Great.

Thank you.

Your next question comes from Lay Denkin with Pritchard.

Yes, hey, how are you?

Hey, Ray.

Sorry for the name pronouncement there.

That's fine.

I was just curious is there a chance, that you get further into the year and you decide that a Huron well doesn't float your boat in terms of the return on capital employed?

And I just was wondering if you could switch capital into the Marcellus or the Berea, how those would stand up in terms of your ability to move up the cost curve or improve your returns?

And does the $1 billion of capital include any --

We really haven't given out IRRs for all of these yet.

But in our own internal planning, they're relatively close given what we've seen so far.

The key issue, Ray, as we mentioned before is, where is the infrastructure because that has a very meaningful impact on short-term cash flow results from the wells, whether or not we have to put new midstream in.

So that's my answer to that question.

And you would still not be optimistic or excited about the use of VPP as a means to fund some of this infrastructure?

I don't know that we're against any legitimate and relatively cheap form of alternative capital.

I just don't -- Phil, you might want to comment.

It just hasn't looked at all that attractive recently.

Okay.

Got it.

Are you saying where the wells in the Marcellus will be, in which counties this year?

Yes, we did.

We said mostly Greene county and Doddridge county, West Virginia.

Greene county, Pennsylvania, and Doddridge county.

But I mean, we also have some wells in, Wetzel county, Lewis county, Ritchie county, Gilmore county, West Virginia.

So it's going to be in that northern West Virginia and southwestern Pennsylvania area.

Okay.

Got it.

Does any area -- can they look better than any other place at this point?

If you look at the results of other people's wells, that area defined by Range on the north and then the CNX had a big announcement to the south, that area appears to be right now one of the better areas.

So that's an area where we're going to be drilling some more wells, too.

We only have one in that area.

Okay.

And are you going to target -- you had to complete, I know, several in the Hamilton -- will all of these be to the Marcellus do you think?

We're using a mix.

We're not biased.

Certainly, if we could figure out -- and in some areas the Marcellus might be easier to drill than in others.

So where you can drill it, we probably will drill it there.

Where you can't drill it, we'll choose the Hamilton rather than fight our way through the Marcellus at a very high well cost.

I think we in the industry are sorting that out at this point.

And just maybe, Phil, the question on the issue of storage and your ability to -- will that be a recurring issue, what we saw in the fourth quarter, the storage gain going forward?

The storage gain?

I'm sorry, the storage gain?

Part of the reason for the weakness in the midstream side.

The storage spreads were down in the year and in the quarter.

Is that what you're referring to, Ray?

Exactly.

Right.

Yes.

You know, they rebounded some lately.

Okay.

And they're in between where they were in '07 and where they were in '08 right now.

So they were down a bit.

Got it.

Great.

Thanks very much.

Okay.

Thanks, Ray.

There are no further questions.

Are there any closing remarks?

Yes.

Thank you.

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