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Executives

Murry Gerber - Chief Executive Officer

David Porges - President and Chief Operating Officer

Philip Conti - Chief Financial Officer

Randall L. Crawford - President of Midstream & Distribution

Johanna G. O'Loughlin - Special Counsel

Analysts

Sam Brothwell - Wachovia Capital Markets, Llc

Rebecca Followill - Tudor Pickering & Co. Sec

Holly Stewart - Howard Weil Inc.

Ronald Barone - UBS

Richard Gross - Barclays Capital

Scott Hanold - RBC Capital Markets

Faisel Khan - Citigroup

Shannon Nome - Deutsche Bank Securities

Ray Dinken - Pritchard

(Shamut Ushuni) - UBS

Joel Hammond - JP Morgan

Scott Hanold - RBC Capital Market

Equitable Resources Inc. (EQT) Q4 2008 Earnings Call January 29, 2009 10:30 AM ET

Operator

Ladies and gentleman, thank you for standing and welcome to the 2008 year-end conference call. (Operator Instructions).

Philip Conti

Good morning everyone and thank you for participating in Equitable 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 a few topics including our 2008 reserve update also released this.

Following Phil's—Murry's remarks we'll open the phone lines to questions. But first I would 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, reserve replacement ratio, expectant well costs, financing plans, capital budget, and capital expenditure, 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 regard certain non-gap financial and operational measures could be discussed this morning by listing today's earnings release, the companies 2007 4-10K and on our web site.

I would now like to turn the call over Phil Conti.

Philip Conti

Thanks Pat and good morning everyone. As you saw in the press release this morning, Equitable announced 2008 earnings for diluted share of $2 was compared with earnings per share of $2.10 in 2007. Two thousand and seven results include a net pre-tax gain of about $126 million from the sale of (inaudible) food reserves in the Nora, and $21 million of expenses associated with the now terminated acquisition of Peoples 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 companies captive insurance subsidiaries both of which were in the fourth quarter 2008 results.

The net impact 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 and expiration 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 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 lowered cash taxes resulting in accelerated depreciation 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.

For 2008 production performance was driven by higher revenues due to higher realized prices and higher sale volumes. We are reporting total sale volumes that were 9% higher than in 2007 and 12% higher when adjusted for the sale of North Hill properties (ph).

In the fourth quarter the good news continued as reported sales volume were over 19% higher than the fourth quarter of last year. I mentioned prices were also up the average well head price in' 08 was about 16% higher and that was driven by higher (inaudible ) for our unhedged volumes.

For the year higher operating expenses offset a portion of the benefits 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 increase drilling and production levels. About a quarter of the increase was from higher production taxes again reflecting the increase in (inaudible) and higher volumes.

In addition the company invested $9 million in 2008 for the purchase and interpretation of Sizemec Data (ph) targeting deep zones which shows up as expiration expense in the financial results.

Moving onto the Midstream business offering 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 liquids 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 prepared a transport record production volumes to market.

On the pension settlement for just a moment, over the past ten years Equitable, as you know, has reduced 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 resources 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 ten 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 sell agreement to require People's and Hub Gas.

The rest of the variance could be explained by colder weather year-over-year. As we previously announced Equitable Gas Company did reach settlement of its Pennsylvania rate case earlier this month. A Pennsylvania administrative law judge recommended that settlement be approved by the Pennsylvania PUC.

Projected annual revenue increased from the new rates as 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 stand point with again the 19 plus percent reduction 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 non-mix natural 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 of—they realized about $10.9 million less and price related revenues in 2008.

That’s because a storage deal was settled in the fourth quarter of 08 had spreads that were about 40% lower than in the fourth quarter of 07. That decline was partially offset by increase in revenues associated with basis spreads captured through the utilization of our Big Sandy pipeline.

Overall liquid—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 pension settlement charge explains a large reduction in mid stream operating income in the fourth quarter of 08.

Couple of other items, executive compensation, as a result of the volatile equity markets, it's clear that compensation committees of public companies are rethinking their approach towards incentive comp and Equitable’s no different.

For 2009 the compensation committee has decided implement a program that again seeks to align management compensation to a long term share holder return. Consistent with prior programs the payout factors are stock performance relative to a peer group similar to the plan that just ended, an absolute return on total capital. However, the executive compensation program will only pay out if share holders receive 2009 results comparatively better than the recently completed four year period which ended with a $33.55 stock price on a 1.75 times multiplier.

The expense of this program will—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 prices finishes 2009 at a price $0.20 cents—20% higher than the closing price in 08 an Equitable 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.

Quick note on income taxes you may have noticed that our affective 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 offering loss position for cash taxes and can no longer utilize certain deductions and credits that we benefited from when we were not in a net operating loss position.

This impact was more dramatic in the fourth quarter since we comparatively didn’t have as much pre tax 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 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 then finally a quick cash flow forecast update, during the third quarter conference call, we forecasted 2009 operating cash flow of $700-$750 million. In 2009 year-end short term debt of about $700 to $800 million net of any seasonal working capital swings and that was based upon a $7.50 NYMEX price and a $1 billion CapEx budget for 2009.

If you would, based on the current 2009 strip of about $5.00 for MMbtu and that 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.

Murry Gerber

Okay Phil. Thank you and welcome everybody. As Phil mentioned this was—any number of measures a record year for Equitable and he’s discussed many of the relative 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 happens 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 and Appalachian that’s number one.

Number two EQT can and is just at the front end of demonstrating that it’s natural gas sales growth rate can exceed 20% and of course our fourth quarter growth rate in production sales demonstrate that. Of course access to capital is 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 at natural gas prices at the current levels or below.

I would like to talk just 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 you know an expansion in 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 yield.

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 Bereau and Marsellus plays in our proved category for the first time.

The Huron shale play acts for another 344 Bcf approved additions. Off setting those increases were small decreases in Cobed Methane and other categories related primarily to back off reduction in volumes from old wells where new midstream infrastructure has not been built.

Also there is a little bit of reduction in CBM due to development prioritization in light of the economy. P3 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 Bereau and Marsellus plays in our unproved categories for the first time.

The Huron shale play acts for an additional .8Tcf of the increase. More importantly we thought you’d be interested in our internal process for how we booked reserves for the major play categories. As a general comment we have of course used the FCC definitions for accounting for our proved reserves and Ryan (ph) Scott audits those assessments.

For unproved categories probable and possible use the SPE guidelines. Probable locations we consider to be any non P U D location in our core development area 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 Marcella’s 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 mass vast majority of spacing units we have on acreage in Kentucky and southern West Virginia beyond the probable locations. Profitable reserves for Berea horizontal include—again horizontal locations beyond the probables only in Kentucky and for the Marcella’s possible reserves include vertical and horizontal off-sets the probable locations within our core area.

At this time less than 10% of our Marcella’s acreage is included in our 3-P totals. For a merging plays we are including reserves we think will fly up into one of the few three categories with further worth over the next couple of years and therefore we are not representing it the numbers we have put forward in the emerging plays category describes the total resource potential of acreage in Appalachia.

Currently included in our emerging plays are the following, for Huron the emerging plays include Virginia. There are some encouraging results in the Huron and 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—and 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 well and the new horizontal wells. I know what you’re thinking and just consider this another interesting upside to the ETC story.

For Berea, locations for Berea in West Virginia and Virginia are not currently excluded from P-3. Though our encouraging results in both states, but we are not yet ready for these locations to fly out into the P-3 categories. We need more results from those wells and just so you know we also had mid-stream infrastructure such that it needs to be built the cost to keep debris in play fully in those states.

For Marcella’s as I previously mentioned, we already included 10% of acreage in 3-P, potential locations on the rest of 400 thousand acreage are included in the emerging play category and the range obviously is due to in our assessment of a range of essential (inaudible) comes for those particular locations.

So I hope that helps you kind of frame what’s in and what’s out as far as our current reserve reports concern. Turning to costs, I wanted to make a couple comment on costs. Both in our earnings release and in our reserve release there are 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 dime to our unit 2008 F&D costs.

This factor alone counts for almost the entire year-on-year variance including are runner, in and out factors that affected the unit F&D but if you want to make short hand explanation for that, it’s steel.

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

Excluding these refract costs our unit LOE expense went from $0.31 in 2007 to $0.33 in 2008, which again that lowest in the U.S. oil and 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 at the break even natural gas price for EQT to continue to earn nominal cash profit is $2.50 per MNDTU.

For debts and purposes we will earn at least our cost of capital at a constant full re-price 5:00 of about $4.50 per MNDTU and our current assessment of maintenance capital required to keep production flat is about $150 to $160 million.

There are a couple of other technology updates on multi-laterals. We start 11 multi-laterals, six in the Huron and five in the Cleveland all but one of the wells was stacked with a second multi-lateral and one pad contains four wells with two stacked pairs. You could use multi-laterals averaged at about 11,700 feet of lateral drilling.

Five wells are turned to lye, three wells have at least 30 days worth of production and are averaging between 200 and 900 MCFU per day for their 30 days and we plan to drill a number of other multi-laterals in 2009.

In the Marcella’s in 2008 we spent 23 Marcella’s wells seven horizontal, 16 vertical, 13 of those are in line with at least 30 days of production. The horizontals that there are only two of them that have been online that long, the 30 day IPs of 1,300 to 2,000 MCFU per day, expected cost for wells, I’m 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 online with 30 day IPs and they’re producing about 400 MCFU per day for average for the first 30 days. We plan to drill 45 Marcella’s wells in 2009 but that could change depending on well results. We will continue to experiment with the air drilling.

Most of our drilling will be focused in Green County Pennsylvania and Dodd Rich County, West Virginia where we’re building, gathering and processing infra-structure and I think as we mentioned before our acreage is very near the acreage that’s currently being developed by range in a very concentrated area and consol I know has had good results and we’re right in the middle of all of that stuff and we’re you know encouraged to see their results from those drilling.

Finally as you saw on the release at this point where we’re reiterating our capital expenditure guideline of a billion dollars for 2009 and with that we’ll turn the call over to questions.

Philip Conti

Thank you Murry, that concludes the comments portion of the call. Operator, can we please now open the call for questions.

Question-and-Answer Session

(Operator Instructions). Your first question comes from Scott Hanold with RBC Capital Market.

Scott Hanold - RBC Capital Market

Morning.

Philip Conti

Morning.

Scott Hanold - RBC Capital Market

Can you talk a little bit better about NEL prices that actually have come down in fourth quarter, I think its firming up a little bit now but what are the shots points on fees and hedges in there, on the midstream side is there a certain (inaudible) self and protection, you know re-connect times?

Murry Gerber

Yes Scott we have been periodically looked at putting hedges in for our liquid fee. These that we’ve got on liquids is that you, as far as hedging, 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 now ball view and what we experience up here.

And sometimes that basis risk is greater than the absolutely 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.

Scott Hanold - RBC Capital Market

Is there any real good option for it or is it just one of those things here you’re going to get the price or it is what it is.

Murry Gerber

What we’ve been investigating and 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, but by that I mean investigating whether it makes sense to generate our own electricity using natural gas liquids on that sort of thing.

Or compressed natural gas or liquids on compressed natural gas stream if you will, for a 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 on in ’09.

Scott Hanold - RBC Capital Market

Okay so that’s a longer term solution.

Murry Gerber

That is true.

Scott Hanold - RBC Capital Market

Okay and the—

Murry Gerber

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

Scott Hanold - RBC Capital Market

All right thanks.

Murry Gerber

(Inaudible) butane.

Scott Hanold - RBC Capital Market

I'm up north here, I open my windows and keep the heat on so.

Murry Gerber

There you go. Now I know.

Scott Hanold - RBC Capital Market

Thank you.

Philip Conti

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

Scott Hanold - RBC Capital Market

Looking at the reserves some of the emerging reserve numbers when you talked about you know some of the re-entries and you know wanting to see some more production results before you start bringing that into you 3P number, you know can you give me a sense of how long that assessment should take and is this something you could look to in 2009 as a bit of upside?

Murry Gerber

Yes, I think so. I think the—there's no question - 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 you know we're going to need six months or so production. Many of these wells only have a couple or three months of production and you know we'd really rather have—our engineers would really rather have a little bit more look at that and really, it's only affects the locations that are actually at the location of the existing old vertical well.

And so they, you know 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 you know significant more progress there—we'll make a much better assessment at that time.

Scott Hanold - RBC Capital Market

Okay and then turning to the multi-lateral press, I guess you drill a lot of those, now there the 209 a day rate you've been getting the first 30 days, can you give a sense on where that fits into your expectation and you know where you hope to get that in 2009?

Murry Gerber

Well keep in mind, yes, these are you know, we're reducing the cost for those things - we're improving the geometry - I think we're pretty satisfied, these things are cruising naturally, keep in mind we're not fracking these things. So, no their absolutely within the range of what we hoped we would be getting, so far. But again, any of the CDs (inaudible).

Scott Hanold - RBC Capital Market

What do you expect the cost on that to be?

Philip Conti

Well a little less than the standard vertical frack-well. I think the standard (inaudible) by 1.2 million. We expect these to be a little cheaper.

Scott Hanold - RBC Capital Market

Okay, the lower—

Murry Gerber

I think for one 12,000 foot multi-lateral, they'll be you know 100,000 cheaper or so, a little better.

Scott Hanold - RBC Capital Market

Okay, one last question, if I could and I think I may have missed this if you said it, but I think you're in the part where you talked about getting potentially a tax refund in '09, is that still something you expect and what's the timing on that?

Murry Gerber

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 that operating cash forecast that we give.

Scott Hanold - RBC Capital Market

Okay, appreciate it. Thanks guys.

Philip Conti

Okay Scott

Operator

Your next question comes from Shamut Ushuni, (ph) of UBS

Shamut Ushuni - UBS

Good morning, guys. Some of my questions have already been asked as I've been bouncing from conference calls here, but I was wondering if you can sort of talk about the efficiency in your drilling program? Can you talk about air drilling is that a little science project or not or whether it's moving forward and also, if you can talk about basted drill, are you seeing kind of efficiencies there and so forth, if you can comment on that.

Philip Conti

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

Shamut Ushuni - USB

I meant Marcellus.

Philip Conti

I have to keep reminding everybody that the Huron play is the bread and butter play for Equitable right now and Marcellus is a good thing, but it's icing on the cake, but 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.

Shamut Ushuni - USB

Okay. And then, my second question is just with respect to CapEx, how much flexibility do you have to be able to dial it down if gas prices continue to be where they are six months from now?

Philip Conti

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 it back if we could make EVA, right? That may be a problem for a lot of companies, but it's not a problem for Equitable Resources, so I think we're going to be looking at it 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. But, we're very EVA-focused here.

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

Shamut Ushuni - USB

Is that going to be the primary indicator?

Philip Conti

We are driven by EVA here, yes. And by the way, subject to liquidity, right? We'll make EVA as long as we have money, but if we don't have money or 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 and prices.

And as we move through '09, there's more flexibility to reduce if you're looking at what our requirements are or where non-economic decisions—kind of dumb decisions —would kick in.

By that I mean, from a rig commitment perspective, it's obviously as you roll through time, it's easier to cut back as some of those rig commitments drop off and of course, a fair amount of that billion dollars 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 later part of 2009, into 2010, there's—if the market conditions would deteriorate even more—we do have the capacity to dial that back even more to the point where you could head toward that maintenance number that Murry talked about if that seemed like the intelligent thing to do.

Shamut Ushuni - USB

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

David Porges

Economics are changing. As prices come down, probably what is happening —which is a little bit different as we prioritize and Murry kind of eluded to this in 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 that causes—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?

Philip Conti

I think the way to put it is that the 450 number is kind of based on a normal program if we did everything we wanted to do, we'd still break even on a cost for 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 we have and so, Dave's right. We are high grading things.

Case in point, 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. Well, 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, quote, unquote, because we don't have add any Midstream for that particular play.

So, those choices are being made as we speak.

David Porges

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, 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 toward that focus that we've been talking about for a few months on drilling into where we really don't need any more Midstream.

Philip Conti

And I think that 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 that we're undergoing right 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. That's kind of the internal decision-making process that's going on day to day.

I apologize about the long answer, but it's helpful to understand how we're thinking about these things.

Shamut Ushuni - USB

No, absolutely and that's kind of where I was headed. I just wanted to understand your thought process. That was actually very, very helpful.

One last question, just a crossing the T, dotting the I question. You'd mentioned previously that you were looking for a tax rebate of sorts this year, if you could just remind us how much that is.

David Porges

Phil just did that.

Philip Conti

It'll be a little bit under $100 million and it's sort of locked and loaded. We'll get it in 2009.

Shamut Ushuni - USB

Perfect. All right, thank you very much, guys.

David Porges

All right.

Shamut Ushuni - USB

Thanks for taking my question.

Operator

The next question comes from Joel Hammond (ph) from JP Morgan.

Joel Hammond - JP Morgan

Yes, thank you. Good morning, everybody.

Philip Conti

Hi.

Joel Hammond - JP Morgan

In terms of your negative reserve revisions, could you give us the volume number there and could you talk about that a little bit?

David Porges

In general, the reserve revision—first of all, it's not cost-related or price-related—let me get that out. I mean, there's a little, teeny bit, maybe, but it's insignificant. The real issue is that where we don't have modern infrastructure, Midstream infrastructure, we've had some back off in some of the old wells and that's really the vast majority of what we're talking about there and a little bit of prioritization.

We've been between shale and coal bed methane; a little bit of prioritization toward shale and a little bit away from coal bed and that really counts for the total, but it's a very small amount.

Joel Hammond - JP Morgan

Okay. So, could you just give us a rough number, there?

David Porges

It's roughly 66.

Joel Hammond - JP Morgan

Sixty. Okay and mostly coal bed methane. I guess you talked about cost of capital, so what's your calculation of your cost of capital?

Philip Conti

It's about eight, 8.5%, we think.

Joel Hammond - JP Morgan

About 8.5%?

Philip Conti

Again, it depends on whether you're using internally generated funds or whether you have to go to the market. If you have to go to the market right now, that would be plus or minus infinity. So, the cost of capital calculation is highly dependant on availability and all the modeling on all that stuff presumed a liquid and deep market of investors that were intelligent.

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.

Joel Hammond - JP Morgan

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

David Porges

No, that's 450 forever.

Joel Hammond - JP Morgan

What I mean by that is it just kind of a drill or no drill kind of price or does that include say, all costs, like lease hold and seismic and capitalized G&A.

Philip Conti

No, that's all in. We've included even in that number some provision for some Midstream that needs be used to hook up the wells to the marketplace, so we've included that; not, as you say, seismic, we're not doing much of that. Lease acquisition's virtually nil, so this is just—I guess in your terms it would be drill only, but it also includes Midstream to support the drilling.

Joel Hammond - JP Morgan

And then, have you seen any meaningful service cost to clients?

Philip Conti

I don't —

David Porges

(Inaudible) are meaningful. We've seen declines, but we haven't seen the level of declines that we would expect. I focus on steel as an example. We see the steel, but the sort that gets sent for the use in the automobile industry. You could see the prices of that dropping, but the oil field tubulars, oil country tubulars are not dropping as much as we would like to see them and that affects us. That probably affects our thinking on the Midstream side of business, for instance.

Joel Hammond - JP Morgan

Okay.

David Porges

So, we buy more steel when it's this expensive.

Joel Hammond - JP Morgan

Okay.

Philip Conti

Oh, Jack Surma from U.S. Steel called me just before Christmas and thanked me for our business. Is that meaningful? I certainly thought it was, actually.

David Porges

Yes, we are seeing declines. We haven't seen the declines to the extent that we would like to see it and incidentally, to answer a kind of obvious question out of that, our current mindset is that 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.

Joel Hammond - JP Morgan

Okay.

Philip Conti

We are taking spot prices on steel right now; by the way, we're not making long-term commitment.

Joel Hammond - JP Morgan

Okay and last thing on the Marcellus Shale, you mentioned the two wells, have you done anything different on the next wells that might give us some different results there?

Philip Conti

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. We're all using basically, the same technology so, I don't think that's a variant. The variant is the natural variants in the production characteristics of the Marcellus itself.

So, all I could say is we're right in between all these big wells that everybody's talking about. So, we'll get one or more.

Joel Hammond - JP Morgan

Okay and your dialoguing. There's a lot of chatter amongst the different operators, so you know what they're doing. They know what you're doing?

Philip Conti

I would say, yes. These are all very, very smart guys and everybody's looking at each other and it's very difficult to keep a proprietary drilling secret.

Joel Hammond - JP Morgan

Okay. Very helpful, thank you.

Operator

Your next question comes from Faisel Khan with Citigroup.

Faisel Khan - Citigroup

Good morning.

Philip Conti

Good morning.

Faisel Khan - Citigroup

The cycles that you said $150 million is the capital you need to keep production flat is that correct?

Philip Conti

Yeah.

Faisel Khan - Citigroup

Okay. And what about on the Midstream side, if you wanted to couple that with Midstream?

Philip Conti

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?

Faisel Khan - Citigroup

Yeah, that makes sense, so 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 back cash flow over the course of the year or two?

If you're looking 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 to kind of keep —

Philip Conti

We haven't given sustainable growth rate, but what we have said is that 15% growth rate for 2009, given what we're spending, given the billion dollars. Beyond that, we haven't given a number that's goes out.

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

Faisel Khan - Citigroup

Right and I understand that, but if you spend a billion dollars this year, then you'll have to use you balance sheet to fund the difference between your operating cash flows and your CapEx right?

Philip Conti

Right.

Faisel Khan - Citigroup

So, if you had to balance the two, what would that —

Philip Conti

I can't give you a number. I don't know what it is.

Faisel Khan - Citigroup

Okay.

Philip Conti

Really, if you start doing that, you have to re-think a whole lot of things.

Faisel Khan - Citigroup

Okay.

Philip Conti

We've certainly done that internally. I just haven't given that number out.

Faisel Khan - Citigroup

Okay.

Philip Conti

But, what you're saying is what is the growth rate this year if we had to spend 600 or $700 million. I haven't given that number out.

Faisel Khan - Citigroup

Okay. All right, fair enough. What was that hedge impact in the quarter for productions? You realized 444 out of the well and I'm looking at an Appalachia price, what was hedge impact in the quarter?

Murry Gerber

I don’t' have a number right in front of me. Why don't you follow up with Pat on that?

Faisel Khan - Citigroup

Okay. Got it.

Murry Gerber

The hedge information's in the table there, but I don't have that exact number you're looking for.

Faisel Khan - Citigroup

Okay and 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? Is it like 50% propane?

David Porges

No, it's propane and then some butane, mainly. 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 is ethane, but most of that gets blended into the methane stream.

Faisel Khan - Citigroup

Okay.

David Porges

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

Faisel Khan - Citigroup

Okay.

David Porges

There's a little bit of natural gasoline. But, it's a propane-butane.

Philip Conti

The propane is sold mostly locally. Actually, the Appalachian region is a net importer of propane. The butane and higher components are used as diluents to blend with Canadian oil as it comes down to the Gulf Coast.

David Porges

And just so you're clear, we don't fractionate. Right, so we get a blended price based on that, but we sell natural gas liquids straight.

Murry Gerber

So, your question that how much more money would we have made if we didn't have any hedges in 2008, is that sort of the question?

Faisel Khan - Citigroup

No, just for the fourth quarter.

Murry Gerber

Oh, for the fourth quarter, NIMEX was flat. There wasn't much of a difference at all, about $8 million.

Faisel Khan - Citigroup

$8 million. Okay.

Murry Gerber

But, for the year, it was about $105 million lower. But, that was the effect of our hedges.

Faisel Khan - Citigroup

Okay. Is there anything in this proposed stimulus package, in terms of bonus depreciation rights and like that that would help you guys on the tax side?

Murry Gerber

Our guys are looking at it, but they haven't updated me on that yet.

Philip Conti

You're saying other than the inflationary impacts of it. If you want to flip something into that package that helps us, though, we're happy to give it look.

Faisel Khan - Citigroup

We'll see what we can do.

Philip Conti

I want to know why we're all not bailed out. Gee whiz, let's all stand in that line.

Faisel Khan - Citigroup

Fair enough. Thanks, guys for the time. I appreciate it.

Philip Conti

Thanks, Faisel.

Operator

Your next question comes from Shannon Nome with Deutsche Bank.

Shannon Nome - Deutsche Bank Securities

Hey, Murry.

Murry Gerber

Hey, Shannon.

Shannon Nome - Deutsche Bank Securities

How you doing?

Murry Gerber

Fine, thank you.

Shannon Nome - Deutsche Bank Securities

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

Philip Conti

Thank you.

Shannon Nome - Deutsche Bank Securities

Thank you to you.

Philip Conti

Thank you. We don't hear that much anymore, so thank you for saying that.

Shannon Nome - Deutsche Bank Securities

So, my question, couple just quick ones, the realizations in Q4 were a little lower than I had bottled them (inaudible). Can you refresh us on how, you know what the D-dux (ph) are to get you from a, say, $6+ hub price, down to the 444? I know a chunk of that is the head loss, do you happen to have those breakdowns?

Philip Conti

Just in the quarter, Shannon?

Shannon Nome - Deutsche Bank Securities

In the quarter, yes, if you have it. You know, what's the BTU adjustment, what's the basis, what's the gathering trends?

Philip Conti

Why don't we, do you have it, Tad, or do you want to—

Unidentified Company Representative

Yes, in rough numbers, $1.75 of the revenue that 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.

Shannon Nome - Deutsche Bank Securities

Yes, okay, that's a little higher.

Philip Conti

Keep in mind, and we are going to look, some of those are internal pricing things, and we are going to relook at that in the first quarter and see if that is all appropriate. We try to set these businesses up as complete stand-alone and I think we did, but as we looked at the numbers for the fourth quarter, we were wondering whether we established the transfer pricing in the right way, and it’s all inside baseball.

But we want to make sure that we are not misrepresenting some of these transfers; and not misrepresenting, trying to do it consistently while everybody else is doing them so people don't get confused. So we have a little more to do on that, but the number is about $1.75 this quarter.

Shannon Nome - Deutsche Bank Securities

All right, then in terms of basis premium, we kind of have been using $0.20, I don't know if that is—

Philip Conti

Yes, that is fine. I mean, on average, yes.

Shannon Nome - Deutsche Bank Securities

BTU adjustment, any changes there, or is that in the—

Murry Gerber

No, 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 is actually showing up in the form of liquids. It is not showing up in the form of, you know, when we are selling it, we are not selling the end of 1,100 or so, or 1,130 BTU.

We are not selling higher BTU gas, we are selling liquids along with the gas. So we definitely got hurt with liquids prices. I mean, since we do produce wet gas, that definitely nicked us in the fourth quarter.

Shannon Nome - Deutsche Bank Securities

Yes, that makes sense. Okay, and then the simple one, I just missed the Marcellus well points for ’09. How many wells was it?

Unidentified Company Representative

We said 40 to 45 which is, you know, originally I said we would have 75 total Marcellus wells drilled by the end of ’09 and we did 23 last year, and we said another 40 to 45, which is a little lower. I’m not so sure that number is right, we are still looking at that number.

We are certainly encouraged by what we see and 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, you know, we have a lot of other infrastructure in Pennsylvania, particularly that we are trying to figure out how to work into the Marcellus play so it can provide us some more capacity.

So we are going to take a look at it, but usually 40 to 45 wells, and any mix of vertical and horizontals.

Murry Gerber

And we didn’t say this earlier, but our strategy on the Marcellus drilling, the initial wells that we have been drilling, there has been a strategy to define the play outline. Some of the other guys, I am not saying this is wrong, are concentrating drilling on very specific places where they have had some good success.

And I don't think that is a horrible idea, but you know the genetics here at Equitable are that we are paranoid about the midstream needs that come from the drilling that we do, and 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. And that has been driving our initial wells, and so we have wells all over the place.

You know, our 23 wells are scattered. And you know now we’ve kind of got a couple areas we like and we are 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 we’ll see how those wells work and probably do some more, if we’re able to.

Shannon Nome

Will the mix shift to more horizontal, and the 23, you said there is probably twice as many vertical’s as horizontal’s. Would that flip, maybe, in 2009?

Murry Gerber

I think it’s going to be more balanced between horizontals and vertical’s, and some of that just has to do with the geometry of releases that we have. So what you can fit in to the spacing. So and I don't think, David, I don't think I have a particular bias one way or the other for the vertical or the horizontal.

We think the verticals are profitable, we think the horizontals are profitable, we are still experimenting, as I said, with air which could tip the balance with horizontal.

Unidentified Company Representative

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

Murry Gerber

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

Shannon Nome

Right. all right, great. Before I hang up, any thoughts on the FEC booking rules coming here in ’09? You’ve obviously got a huge amount of things.

Murry Gerber

Yes, I think in general this whole thing around reentry, for example, it is kind of an interesting; you see right now if you h v a vertical well, you have to book offsetting vertical wells. They won't, even if you're, as what happened here, if you are in shale, if you 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 PUD’s, and then beyond that, you can book whatever the heck you want, which is a very strange result. So I think we would see a substantial increase improved just because of that factor. And I can't give you the number now, but it could be potentially pretty meaningful.

Shannon Nome

Thank you, Murry.

Murry Gerber

Okay.

Operator

The next question comes from Sam Brothwell with Wachovia.

Sam Brothwell - Wachovia

Thank you, guys. Just one real quick clarification. Your 450 break-even, is that a high price or is that in the basement?

Unidentified Company Representative

Imex.

Sam Brothwell - Wachovia

That's what I thought. Just two other things, on the midstream, are you still looking at partnering with somebody on that?

Unidentified Company Representative

Yes.

Sam Brothwell - Wachovia

Enough said. And then the last question is with the change in the administration and Congress, we are hearing some noise about on the environmental issues, water, and even possible making some noise about regulating fracture stimulation. Any thoughts on that?

Unidentified Company Representative

Well, yes, I’ll save the obvious ones, but what we are going to do, and I mentioned this a few times on the road recently, is we are in the process of building a recycling plant for Marcellus, water handling, we hope it will be up in the third quarter, or maybe a little earlier during this year. We are going to try to recycle that water.

Now that doesn’t address, which is the one concern that some people have that we are hurting the aquaphors with salt water from the cracks. I hope adults will finally come to the conclusion that we've been doing that for 70 years now, and haven't damaged any aquaphors, but forget about all that, we are trying to recycle as much of that brack water as we possibly can.

And, you know, drill more wells from the same pad so that you can reuse the water. We are going to do pan drilling, it is going to help in the Marcellus, recycling is going to help in the Marcellus, but we are focusing more of our attention on the disposal of the water, rather than the acquisition of the water.

Sam Brothwell - Wachovia

Okay. Well, thanks a lot.

Unidentified Company Representative

Okay.

Operator

Our next question comes from Rebecca Followill of Tudor Pickering.

Rebecca Followill - Tudor Pickering

Good morning. (Inaudible) already been asked, but if you guys had booked the (inaudible) drill wells, what reserves would that have resulted in?

Unidentified Company Representative

I didn’t give you that number. You saw what the table showed, and a fairly large amount of that emerging play could be accounted for in this particular category. Sorry.

Rebecca Followill - Tudor Pickering

Okay. Second and equally difficult question, when you guys quote your rates for Marcellus, you quoted 30 day IEP, and I understand your reason for doing that, we have talked about that before. But your peers all quote a different IEP. Any thoughts of giving those just so we can get a comparison?

Unidentified Company Representative

No.

Rebecca Followill - Tudor Pickering

Okay, bye, thank you.

Unidentified Company Representative

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

Unidentified Company Representative

Yes.

Unidentified Company Representative

That's all, we just don't think, it’s not quite a random number generator, but we just don't think, because you are talking about the first minute or etc, we just fear that it’s not particularly useful information.

Murry Gerber

I’ll tell you what you can do. Take all of their numbers and just apply them to us and you’ll be fine because those will be as good as any other number we could give.

Rebecca Followill - Tudor Pickering

But your wells are comparable on an initial flow rate?

Murry Gerber

We think so, yes. Because, I mean, back 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 IEP’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 we 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 I am not, there is nothing geological that I can see, there is 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 have exposed themselves to the statistical range more frequently.

Unidentified Company Representative

And they are probably also further up the learning curve, frankly, with Marcellus than we are. I mean, we think we define the leadership in the lower Heron, and we think we’re active in the Marcellus, but they are probably a little bit further up the learning curve, and our folks are very focused on that fact.

Rebecca Followill - Tudor Pickering

Okay, great, thank you.

Operator

Your next question comes from Ray Dinken with Pritchard.

Ray Dinken - Pritchard - Pritchard- Pritchard

Yes, hey guys, how are you?

Murry Gerber

With the name pronounced wrong.

Ray Dinken - Pritchard

Oh, 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 (inaudible) and I just was wondering if you could switch capital into the Marcellus or the Borea, how those would stand you in terms of your ability to kind of move up the cost curve for your return, and does the billions of dollars in capital include any—

Murry Gerber

We really haven't given our IRRs for all of these yet. IN our own internal planning they are really 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 total results from the well, whether or not we have to put new midstream in. So that's my answer to that question.

Ray Dinken - Pritchard

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

Murry Gerber

I don't know that we’re against any legitimate and relatively cheap form of alternative capital. Bill, you might want to comment.

Philip Conti

It just hasn’t looked all that attractive recently.

Ray Dinken - Pritchard

Right, okay, got it. And are you saying where the wells in the Marcellus will be, in which counties this year?

Murry Gerber

Yes, we did, we said mostly Greene County and Dodridge County, West Virginia. Greene County, Pennsylvania, Dodridge County, but I mean we also have some wells in Wepsell County, Lewis County, Richie County, Gilmer County, West Virginia, so it is going to be in that northern West Virginia and southwest Pennsylvania area.

Ray Dinken - Pritchard

Okay, got it. Does any area or county look better than any other place at this point?

Murry Gerber

Well, I think if you look at the results of what others have, 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, and so that's an area where we are going to be drilling some more wells, too. We only have one in that area.

Ray Dinken - Pritchard

Okay, got it. You have to complete several in the Hamilton, will all these be to the Marcellus, do you think?

Murry Gerber

We are using a mix. I mean, we are not biased. Certainly if we can figure out, and then 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. So I think we in the industry are sort of sorting that out at this point.

Ray Dinken - Pritchard

Got it, okay. And I guess just maybe Phil can answer the question on the issue with storage and your ability, will that be a recurring issue what we saw in the fourth quarter, storage going forward, I guess?

Philip Conti

The storage gain, I’m sorry, the storage gain?

Ray Dinken - Pritchard

It was part of the reason for the weakness in the midstream.

Philip Conti

Oh, the storage spreads were down in the year and in the quarter. Is that what you're referring to?

Ray Dinken - Pritchard

Exactly, right.

Philip Conti

You know, they sort of rebounded some lately so they are sort of in between where they were in ’07 and where they were in ’08 right now, so we rebounded a bit.

Ray Dinken - Pritchard

Got it. Great, thanks very much.

Murry Gerber

Okay, thanks, Ray.

Operator

If there are no further questions, are there any closing remarks?

Murry Gerber

Yes, thank you. That concludes today’s call. This call will be replayed for a seven day period beginning at approximately 1:30 p.m. Eastern time today. The phone number for the replay is 706-645-9291. The confirmation code for the replay is 30334098. The call also will be available on our website for seven days, and you could listen to it there. Thank you everyone for participating.

Operator

Thank you, this concludes today’s conference call. You may now disconnect.

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Source: Equitable Resources Inc. Q4 2008 Earnings Call Transcript
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