Chesapeake Energy Corp (CHK) 2007 Q4 法說會逐字稿

Good day and welcome to the Chesapeake Energy hosted earnings release conference call.

Today's call is being recorded.

At this time, I would like to turn the call over to Mr.

Jeff Mobley.

Please go ahead, sir.

Good morning and thank you for joining Chesapeake's 2007 fourth-quarter and full-year earnings conference call.

Hopefully you've had a chance to review our press release and updated investor presentation posted to our website yesterday afternoon.

Before I turn the call over to Aubrey and Marc, I need to provide you with disclosure concerning the forward-looking statements that Chesapeake management may make during the course of this call.

The statements that describe our beliefs, goals, expectations, projections or assumptions are considered forward-looking.

Please note the company's actual results may differ from those contained in such forward-looking statements.

Additional information concerning these statements is available in the company's SEC filings.

In addition I would also like to point out that during the course of our discussion we will mention terms such as operating cash flow and EBITDA and we'll also mention items that we believe are typically excluded from analyst assessment.

These are all non-GAAP financial measures.

The reconciliations to comparable GAAP measures can be found on pages 18 through 20 of our press release.

While these are not GAAP measures of financial performance, we believe they're common and useful tools in evaluating the company's overall performance.

Our prepared comments should last approximately 10 minutes and then we'll move to Q and A.

Aubrey?

Thanks Jeff.

Good morning to each of you.

I'd like to begin by introducing the other members of our management team on the call with Jeff and me.

Marc Rowland, our CFO, Steve Dixon, our Chief Operating Officer, and Mark Lester, our Executive VP of Exploration are all here this morning.

A week ago we had a very productive conference call following our, first in a long time, operations update press release.

You may notice in that yesterday's release we repeated a few key operational highlights for your convenience.

Since I focused on operations last week, this week I thought I'd focus on natural gas markets while Marc will update you on the process of our asset monetization.

As many of you know, after the Katrina/Rita natural gas price surge in 2005 Chesapeake's management team became increasingly bearish about U.S.

natural gas prices for a number of reasons, one of them the result of our own aggressive natural gas production growth plans.

As a result, Chesapeake has been extensively hedged during the past two years and it has turned out to be a good decision as we have made $2.5 billion in 2006 and 2007 from our hedging activities.

Looking forward, however, we see many bullish factors that have developed and are evolving over time that lead to us conclude that natural gas prices may have upside in them during the next two years.

Among these are rising electricity usage in the U.S., stubbornly high oil prices, higher coal prices, emerging environmental trends, and for the first time in a long time, winter weather that this year is near the 30-year average and above the 10-year average.

All of these factors are supportive of stronger natural gas prices and we have seen during the past two years.

However, to natural gas consumers, our message remains the same.

There will be plenty of natural gas to meet your needs and at affordable prices, especially when compared to oil prices and when compared to coal prices with future carbon costs built in.

We believe there's no need for natural gas consumers to be alarmed by our call for natural gas prices to increase somewhat during the next two years.

To Chesapeake investors, I believe we are seeing a multi-year trend develop for prices that could keep them in the $8 to $10 range, instead of the 6 to $8 range in which we have been stuck for the past two years.

I believe this new higher range is especially likely to be sustainable if summer weather is hot this year, particularly in key southern electricity markets.

I will remind you that in the past, strong La Nina summers, the bias has been towards warmer weather, and this current La Nina is bordering on the strongest La Nina event ever recorded.

Moving on from gas prices, I'd like to discuss a topic we started thinking hard about five years ago.

And it's now suddenly garnering quite a bit of attention, including a front page article in the second section of The Wall Street Journal yesterday.

And that's what are we doing to attract young people to our company in a rapidly aging industry?

I'm happy to report some very interesting statistics with regard to our human capital.

First of all, we have about 6,500 employees, about 4,000 of them are in our E&P operation, and 2,500 work for our service businesses.

Of those 4,000, 25,00 work in our headquarters in Oklahoma City.

Of these 2,500, fully 40% are younger than the age of 30.

Five years ago, that number was less than 10%.

Furthermore, in the eight months since July 1st, 2007, we have hired almost 425 people in Oklahoma City.

Of those, 60% are younger than the age of 30.

We pay very well, have excellent benefits, have a beautiful campus, have a very flat organizational structure, are executing an aggressive and successful business strategy and we encourage creativity and innovation.

All of these characteristics help make the company very attractive to young and more experienced alike.

In fact, just last month we were named one of the 100 Best Employers in the U.S.

by Fortune Magazine, a designation that only two other E & P companies received.

We have worked hard to build a distinctive company and culture and believe it is paying big dividends through our ability to attract a highly qualified and increasingly youthful workforce.

I'd like to wrap up by reemphasizing some of the bullish comments I made last week about future value create possibilities at Chesapeake.

As we discussed then, I believe 2008 and 2009 will be golden years of value creation for Chesapeake and other well-positioned E & P companies.

Unit costs are on the decline as service industry capacity continues to expand faster than the rig count is increasing, and at the same time, gas prices are moving up, which should provide Chesapeake the opportunity to accomplish multi-year gas hedging at, or above, $10.

To shareholders of Chesapeake then, we have three rocket stages working for us in the next several years.

First you have growth of proved reserves of 2 tcfe per year, which we reviewed last week.

As discussed then, I believe these should be worth $7 to 8 billion a year of value.

Secondly, you should see our unrisked, unproved reserves increase by at least 5 tcfe.

Again, as discussed last week, I believe those reserves are worth around $1 in mcfe, so that would create $5 billion of value per year.

Finally, for every $0.10 change in natural gas prices the value of Chesapeake's proved reserves increases by almost $400 million, or $0.80 per share.

Given that I believe the strip is likely to move up by $1 per year in each of the next two years that could create an additional $4 billion value per year.

So you add it all up and you get around $16 to $17 billion of potential value creation per year, around $30 per share.

I then aggressively risk this at 50% and that's how I support -- another way that I support last week's calculation that we should be able to increase the value of Chesapeake's stock by about $15 per share during each of, at least, the next two years without anything out of the ordinary occurring.

I find this net asset value creation math very compelling and hope that you do as well.

I'll now turn the call over to Marc for his comments.

Thanks, Aubrey.

Good morning, everyone.

I'd like to start out by speaking about production guidance for a moment.

We didn't highlight this in our press release but our November 6th outlook guidance anticipated that our VPP structures in '07 and '08 would be treated as prepayments for accounting.

As it turned out, we executed a VPP that was treated as a sale.

In a prepayment, the reserves and productions stay on our books.

In a sale, somewhat obviously, they do not.

So while removing 90 million a day in '08 and 135 million a day in '09, as a result of our executed and predicted VPP structures, that had been previously included in the 11/6 guidance, we ended up leaving the numbers the same, effectively raising our guidance substantially again.

An important transaction for us in the fourth quarter was the induced conversion of two of our preferred stock issuances.

When we began the end of -- or the beginning of the fourth quarter, we had nearly $2 billion of preferred stock outstanding.

We redeemed virtually all of our 5% and our 6.25% preferred stocks for a total right at $1 billion, effectively reducing the amount of preferred stock that we had outstanding by over 50%.

We issued common stock for the present value of the dividend stream of the preferreds less the common dividend stream, which is obviously greater than the base of the preferred, but essentially exchanges common for shares already in our fully diluted count and saves approximately $55 million in fixed charges per year and improves the balance sheet.

Some debt analysts, and obviously the rating agencies, have considered our preferred stocks to be somewhat debt-like in the past, depending on the exact nature of the preferred, and this should go a long way toward improving the balance sheet in their eyes.

Speak a moment about our second round of VPPs.

We're in the process of putting our information memorandum together, and we hope by the end of next week that we'll be able to send out that IM to quite a number of people that have been eagerly awaiting it.

The number of calls that we've received subsequent to the execution of our first VPP is substantially up and we've engaged Jefferies again to represent us in this transaction, and they've affirmed that they've had a significant number of calls and a high level of interest.

It's nice also that the back of the curve has moved up since the time of our December VPP, and higher gas prices over next 10 years are available to us.

Our midstream monetization process is well underway.

We've got a number of very significant and highly recognized major firms that are in a due diligence process as we speak.

Every day Steve Dixon and our group of folks, Jim Johnson over at CEMI -- are educating the potential investors on the opportunity available to them.

We are seeking $1 billion in capital from a partner.

This will be a private limited partnership structure, and as we work toward finalizing that structure over the next three to four weeks, then ultimately hopefully closing by the end of April, we believe that we're going to see valuations of our midstream business between $3.5 and perhaps $4 billion or even a little greater.

Just to remind you, our annualized run rate for the fourth quarter EBITDA of these assets was approximately $165 million.

While that's up substantially our forecasts are for this asset to grow even faster in '08 and '09 as we move further into the connection process and the Barnett Shale, the Fayetteville Shale and our other projects.

So with that, I think that concludes our remarks.

Moderator, if you would begin the question and answer process, please?

The question-and-answer session will be conducted electronically.

(OPERATOR INSTRUCTIONS).

We'll take our first question from David Tameron from Wachovia.

Hi, good morning.

Can you talk, Aubrey, about the infrastructure in the Barnett -- seems to be kind of rearing its ugly head for some companies.

Can you talk about how you're positioned going forward and if you expect any constraints?

We've experienced constraints today.

Any time you try and dig under ground in an urban environment it it's not the easiest thing to do.

However, I think we have brought the company's full suite of human resources to that.

I think I mentioned last week we had something like 400 right of way agents in the field in Fort Worth.

We have a large community affairs department that works with -- I think we work with 58 different municipalities in the in the Tarrant and Johnson County areas.

We're on it, it is always a concern, regulation, particularly pipeline regulation is tightening rather than getting looser and so we have built delays into our production forecast, but there's always the risk that we'll have other issues.

The main concern of a few years ago, that there wouldn't be enough take-away capacity once you've gathered the gas inside the play.

I think we're all squared away there.

It's mainly getting it from well head to the interstate pipeline.

Keep in mind all this gas has got to be compressed, and I think we've led the way in starting to build compressor stations that are fully enclosed inside of buildings and keeping them quiet and doing everything that we can do.

But it's not the easiest project in the world in an urban area of several million people to be laying pipelines underneath all the urban infrastructure that exists there.

All right.

And then as related to -- a big picture kind of macro question.

It seems like F & D costs have come down this year across the board.

I don't know if that's a function of resource plays.

I assume it is.

But going forward, does that change the M&A landscape at all, meaning are buyers going to be wanting to pay less for properties going forward, if F & D costs are lower?

Can you talk about that?

Any change of the M&A market going forward?

You are talking to the wrong company these days about this.

As you well know, David, we're really not active in the acquisitions market, so can't really speak to what values are there.

I would say, though, that the decline in finding costs, when you say it's a function of resource plays, we would -- I think that's part of it, but what we started to say, really two years ago, is that rising costs were not so much a function of diminishing reserves per well, although in certain conventional basins, certainly that's true.

We felt like rising costs were the consequence of the industry reacting to the surge in revenue that we saw in 2005, 2006 with the gas price spike, and that put extraordinary pressure on the existing infrastructure of the service industry, and as a result, we saw prices go up generally across the board by at least 5%.

But we also predicted that in 2007 and 2008 the rapid build out of service company infrastructure would lead to declining finding costs during that time frame, and that's why I have, for several years, predicted that '07 and '08, and I think '09 as well will go down as golden years of value creation because you'll have good gas prices, declining finding costs, provided you've got the kind of asset base that allows you to continue to drive efficiencies up and costs down.

And for that you can't be solving geological and engineering issues one at a time every time you drill a well, you've got do what we and a handful of other companies have done, which is build gas resource plays, grasp the engineering and geological challenges and then go out and drill hundreds or thousands of wells.

And so I'm very optimistic about our company's ability to actually drive down its appreciation rate over time as our finding costs decline over time as unit costs go down and our efficiencies go up.

All right, thanks.

We'll take our next question from Brian Singer with Goldman Sachs.

The hedges that you put in place following Katrina and Rita, very high prices, seemed to play a major role in allowing you to aggressively drill over the last couple years.

Given your increased outlook on prices and higher prices, how do you view in that the context of thinking about further increases from here, and given your comments on people do you have, I guess the willingness and ability to further ramp up activity.

Well, we certainly have the property set that would enable us to drill more wells if we'd like to.

As you know, we've committed to live within our cash resources and we will continue to do that.

If we see the opportunity to lock in prices that are attractive to us for, say, 2009, 2010, then we'll start to do that and if that provides with us the opportunity to convert more undeveloped acreage into proved developed producing assets, then we'll certainly do that.

So we're mindful of the opportunities that have been provided to us on the hedging front, and I'll let Marc tell you a little bit about our hedging thoughts these days.

Brian, the thoughts I have with respect to hedging, we've been looking out -- obviously prices along the curve are up substantially recently.

We've been able to go into the markets and execute some straight swaps and some swaps because volatilities are up that have a kick-out feature or the embedded put.

And receive prices, as you look out in '09 and '10, at the higher end of what we've ever been able to hedge for, I don't think that translates into a increase in rig count by Mr.

Dixon's, I mean Mr Lester's Group, but also, as Aubrey pointed out, we are committed to living within our resources, so it makes that part of it easier.

Also, as the prices go up it makes our VPP transactions more valuable, as we're able to lock in higher prices over a stream of years, it makes the sale of those molecules at higher prices, and therefore more cash flow for the same amount of molecules.

So it's a great environment to be in from a hedging standpoint.

We are continuing to execute just like we have in the past opportunistically to create higher revenue units per molecule sold, and we're doing that both in the oil market and in the gas markets.

I guess relative to your current rate of activity it sounds like we shouldn't expect any major changes in the immediate term but higher prices could allow to you ramp things up a bit more in 2009.

Always have that possibility.

That's a good estimate.

Looking at your cash flow statement, it looked like the outflow from investing before considering your asset sales for the fourth quarter was about $2.5 billion.

I think you had about a $1.5 billion E & P budget.

Obviously there's a component of your spending that's non-E & P.

How should we look at total spending in 2008 relative to your $5.5 billion E & P budget before considering asset sales?

Well, let me flip to that detail.

It may take me a moment.

We might go to the next question and come back to that if you don't mind, Brian.

No problem.

Operator, we'll take the next question, and then we'll come back to Brian.

we'll take our next question from David Heikkinen from Tudor Pickering.

Had a question about Rockies Express and their impact on Mid-Con and Permian gas realizations.

So far then you're expecting in '08 and then a potential reversal in '09 and what the overall impact will be on the gas realization.

Well, we've followed Rex like everybody else in the industry, and from what we've read, it seems like that we have seen somewhere between 300 and 500 million a day of incremental supply.

It's been relatively cold in the Rockies and, of course, in California as well.

So not as much gas has made it west -- or east, rather, as perhaps some people had predicted.

Down the road, the question really is on basis, will it affect Mid-Continent basis.

We haven't really seen that it has so far this year.

We are about as well protected as we could be from basis hedges and have made, I think you know, well over a billion dollars on over basis hedges to date.

So going forward, we think the Rockies will probably always be challenged from a basis differential as every pipeline project that's ever been built there has promised permanent salvation from high basis differentials and within a matter of months to a year or so the pipe gets overrun and we expect that to be true as well.

So about every -- out of about every three years I think you can expect the Rockies to have good gas prices about six months to a year out of the three years.

So, go ahead.

Just thinking about the second, third quarter, get past the cold weather in the Rockies, you're pretty protected, but if you thought about un-basis protected gas, I mean, what would you expect basis to do at Mid-Continent Permian gas?

Oh, it's so related and so affected, David, by regional weather patterns and by overall gas prices that I would hate to really hazard a guess.

I would point you to our outlook, which does have a prediction of basis differentials across the company, and beyond that, I probably am just not qualified to get any more specific than that.

Thinking about your '08, '09 projections, particularly on the expense side no, production taxes vary with increasing gas prices, but with the expectation of a step-up in the strip in '08, '09, '10, what other expense increases would you see just cents per mcf on each of the other categories, and maybe I talk to Jeff off-line about it, but just curious on the picture.

The easiest thing is to turn to page 23 in our press release and look at the guidance that we've given, and then compare it to our results for the year or the fourth quarter per mcfe, which we give you on page 3 of our press release, and just picking a couple of them, production expenses for the quarter were $0.88 in mcfe.

For the full year, they were $0.90.

We are predicting for 2008 that that's going to be $0.90 to a dollar, and we say the same thing for 2009 as well.

Everything else more or less stayed the say.

You'll see a feature of the company as we always are -- try to be a little bit high on our outlook page as to what our expenses are going to be, but you will see that we don't -- we're not anticipating an increase in DD&A rates, we're not assuming any increases in G&A or in depreciation or in interest.

So, again, it's a flat cost environment, in which we expect to live in with a normal volatility of gas prices, prices giving us the opportunity to lock in revenues that should be well above what the averages are for the next year or two.

So with a $7.50 benchmark that you're using in your guidance, if I ran $9, what you're saying is the costs are not going to go up dramatically unless there's a big change in activity level in industry?

The only thing that's variable is production taxes and will costs at the margin be slightly higher if the industry needs -- wants to put on 150 rigs rather than stay level, because gas prices go to $9.50 or $10.

That's possible.

But I would remind everybody that the rig count on a year-over-year basis will actually be down were it not for the activities of two companies.

And that's Chesapeake and Sandridge.

And, so you know, I think it's important to recognize that the industry during the past year has reached a equilibrium with which it's either comfortable from a prospect basis or from a people basis or from a cash resource basis.

And going forward, I can't speak for Sandridge, of course, but the days of us adding 40 or 50 rigs a year are probably behind us rather than ahead of us.

And so I think one of the great features of pressure on the rig count of the past couple years has been the activities of just a couple of companies and that we'll probably reduce pressure going forward.

Thanks, Aubrey.

Thank you.

We'll take our next question from Gil Yang with Citi.

Good morning.

Aubrey or Marc, could you talk about, DD&A sequentially dropped in the fourth quarter, you've got F&D costs that are, depending how you look at it bumping around $2, yet you're forecasting DD&A rise in '08.

Could you just give a little color?

I'll take that, Gil.

The logic is we're trying to be conservative.

Costs did come down in the fourth quarter.

We had an exceptionally good quarter, from the drill bit standpoint, as our operations people have shown us over the last couple days.

We expect prices, from a budgeting standpoint, to basically stay unchanged, although we are seeing some price deflation, particularly in some areas with respect to frac costs in some areas.

Now, when you say that we're projecting DD&A to go up, I think we're kind of in the $2.50 to $2.70 guidance range, so about the same as what we've been.

There's not been an increase in our DD&A guidance from the November 6th.

So, Gil, not sure --

No, I understand.

I'm just trying to bring together the idea that you have F & D closer to $2, and you had dropping DD&A --

That's finding costs without leasehold and without capitalized items, so that's the difference, I think.

All right.

Second question, going back to the previous line of questioning, Aubrey, what do you think -- if you do get this -- I understand you're saying that maybe you don't see much of a pickup in rig count overall but if you are right and you do see a $1 increase in the gas price median, let's say, over the next couple years, what increase in gas production domestically do you think we'll end up seeing?

We assume we're running 5% today on a month-to-month basis.

Is that going to rise or do you think you need that $1 increase to -- to keep it flat going forward, to keep it at a modest growth rate going forward?

I'd rather speak in terms of bcf's a day because on a percentage basis, of course, you're talking about different basis each year of production, but we look to us like the industry can generate somewhere between 2 and 3 bcf a day of increases going forward.

Clearly the last year has benefited by increases in what Rockies -- what Rex has let out of the Rockies, then independence nodes are one-time events that are not -- there's no following or subsequent events similar to those.

But I think if you look at what we and virtually every other big company and medium size company is projecting, most everybody is in double-digit production growth or put out double-digit growth targets for the next couple years.

I'd remind you that our production alone last year increased over 500 million a year on a net basis, on a gross basis probably closer to 700.

We haven't projected that again but there's -- we have projected growth that's pretty substantial, so using just about 8% of the rig count, we should be responsible for somewhere between 20 and 30% of the industry's growth, and I'm pretty comfortable that we can continue to do that, as both a company and industry for the next at least two or three years.

So I think it it's good news for consumers, and as long as LNG prices stay firm throughout the world, this glut of LNG importation that most everybody had predicted would come to the U.S.

I don't really think comes.

I joke, but it's got a serious side to it, which is I think it would be more profitable today to build a LNG liquefaction plant in America than it would be to build another regas plant, so we're looking for partners if anybody wants to join us, because we think we are doing great work for the U.S.

natural gas consumer and we'll continue to keep LNG imports low in years to come.

Thanks, Aubrey.

Thank you.

We'll take our next question from David Kistler at Simmons and Company.

You followed up on your comments on LNG, Aubrey when you mention the dynamics driving potential up tick in natural gas prices and have driven this recent move, I don't think you mentioned LNG, and also didn't make any commentary with respect to what's happening potentially with fall-off in production in Canada.

Can you give us a little bit more color on those, and also with LNG, how that affects seasonality potentially?

Sure, be happy to.

In Canada, I think most observers of Canada, including us, were probably a little surprised last year that we didn't see more evidence of production drop-off, but I think that this year we're likely to see it, it's been relatively cold there, and so I think imports will be down at least half a bcf per year.

The more exciting and dynamic story is what's happening around the world with LNG growth.

People mostly focus on the U.S.

gas market, which is more or less 60 billion cubic feet a gas a day.

People forget that the rest of the world consumes 220 bcf a day of gas per year, and that the increase in consumption of that gas has been somewhere between rising at 3% to 4% per year, so you need an extra 7 to 10 bcf a year supply to come on just to feed the world market.

I think it's well documented that the liquefaction surge that people had expected this year has been delayed, it's obviously clear to everybody as well that the cost of plant have gone up two to three fold in the old days of thinking you could land LNG at U.S.

shores and be competitive at $3 mmbtu.

Just a fantasy these days.

So what we're seeing happen, what we saw happen in oil and we've seen happen in metals and we're seeing in agricultural commodities we're now seeing is happen to coal and to a limited extent natural gas as well, which is, the world is short a lot of commodities these days and I think what the world is especially short of is clean-burning, environmentally friendly, affordable natural gas.

And so we think the rest of the world will suck up most of this LNG growth in years to come and that if the U.S -- for the U.S.

to receive more than a couple bcf a day on average, despite whatever our regas capacity is, we're going to have to outbid the European market and the Asian market and I will remind you that two days ago spot prices for coal in northern Europe were $40 a ton, and sulfur dioxide credits were $24 a ton.

You add that all up and you get to a $12.50 per mmbtu price.

So, I think the notion that the world has a limitless supply of coal and coal will always be cheap is a very challenged notion right now, and that natural gas has a great chance of stacking up very well against that fuel in the years to come, particularly as places like China and India have to deal with the need for abating their pollution.

So I love the way it's setting up, and I think it's great news for both U.S.

gas consumers that prices that will be relatively restrained while at the same time I think gas producers you're likely to see a little bit higher range the next two years than what you've seen the last two years.

Do you think that robust demand impacts the seasonality that we've seen historically with LNG coming here in the summer?

Well, I think a little -- yeah, sure it does.

The idea that the U.S.

has the best storage system in the world is correct.

And so there's -- again, a notion that we're going to be a dumping ground for LNG in the summertime.

And I think there's certainly an element to that that is absolutely true, and we saw that last summer.

We also saw that it can start to go away pretty soon, as it started to go away in September.

I'll also tell that you that I don't have any physical evidence of this, but it certainly would make intellectual sense to everybody on the call that there will be a day when Asian buyers will grow tired of only being able to buy cargoes in the fall and winter and paying $15 to $18 an mmbtu as they have now.

I think there will be a rapid build out of above ground storage throughout the world so that gas consumers can be buying LNG cargoes around the -- at all times during the year rather than just during the high-priced times.

If that's not happening now it certainly will, it's just too big of an arbitrage to play between summer gas prices and winter gas prices in LNG markets around the world.

When you think of seasonality and the arbitrage or winter versus summer, does that impact how you've been laying on your hedges looking at '09, the fact that you've added a bunch of knock-outs again, were those laid on universally, or were they laid on, on a seasonal fashion?

That's a great question.

We've actually in the last six months gone almost exclusively to laying them on a seasonal fashion.

The put levels that we will establish for the April, May, and the August-September-October period are much lower than what we will establish in the other months for that very potential seasonality, particularly influenced in the later summer with LNG.

So we have adapted our hedging strategy accordingly, and we think that it's going to work out.

Now, having said that, I think in the six years that we've been doing kick-outs and receiving anywhere from $0.50 to $1 greater than we otherwise would, we've had two months during that entire time period where the part of our hedges which were laid under the kick-outs actually didn't -- weren't effective, and so it was as if we had never hedged, and unfortunately those months were pretty low, so it did cost us some money, but overall we've achieved much greater risk through this strategy than would we otherwise could have.

Great.

Thank you guys so much for that additional color.

Thanks for the question.

And we'll take our next question from Ellen Hannan with Bear Stearns.

Good morning.

I had three questions, and the first on the Fayetteville activity, you're running 11 rigs there now, you say that would probably look to double at some point in the future.

Should we look at that as a shift of higher activity in the Fayetteville, maybe something less in one of your other areas, or an incremental add to your rig count?

Right now I we're not sure if it would be an overall increase or if we would slide some rigs around.

Ellen, we re-budget every month, and we evaluate plays every month, and so some plays lose rigs, some plays gain them.

So could be a net gain, but at this point, all we know for sure is that the Fayetteville needs more rigs and we will make sure that one way or another that asset team receives access to those rigs during 2008.

Thanks.

My other two questions actually are on the balance sheet and the cash flow.

One is, I think, a follow-up to Brian's question, and maybe, Marc, you have that handy.

I was curious, on the cash flow statement, recognizing aim looking at abbreviated statement, where's the cash from the VPP?

What category did that flow to?

The other question, on the monetization of the non-E & P assets going forward, how should we think about that in terms of what's going to make your balance sheet look like?

Just to remind you what happens when you execute a VPP like we do, is you're debiting cash, and you're crediting your full cost pool.

So it's treated as a sale of assets.

It is not recorded as a profit or loss from that activity.

It's simply a credit to the full cost pool.

So in this case, since we sold 208 bcf, our reserves were reduced accordingly, the full cost pool was reduced by approximately 1.1 billion, so that at the margin, although very small, positively affects your DD&A rate as well.

I have no issue with that.

The question is, is it cash flow from operations, cash flow from investing or cash flow from financing activity.

Where's the cash?

I believe the cash on the cash flow statement, let me look at that, I believe is from financing activity.

But I'm still searching for the answer to the question.

Obviously we spent about $2.4 billion of actual investing activity, and that will be broken down in our K, which will be filed next week in detail, but we spent $1.45 billion on the drilling, about $500 million in all leasehold activity, which is off the ground, delay rentals, mineral purchases, deal leaseholds for small deals we did and so forth, and then we had another approximately $400 million for expenditures in all of the other assets that we're buying, and that's principally the midstream assets, but, of course, there's a lot of other assets as well.

So all of that was funded by both cash flow from operations, which is broken out, and then from the cash related to the -- the sale of the VPP and so forth.

So it will not be in operating activity.

Okay.

And again, just lastly, on the -- you talk about monetizing non E & P assets going forward.

How should we think about what, if anything, that does to your balance sheet?

We'd use either a VPP or the MLP, so I'll let Marc respond, Ellen.

The balance sheet is going to be unchanged.

It's going to be -- from the MLP standpoint, we're going to still consolidate all of the gathering assets, and I don't know what the interest is but it will be a minority interest with respect to the treatment of it, so everything will be consolidated, and then the earnings from the minority interest will be shown as minority interests are.

And Mike Johnson has just informed me that the VPP will be a source from investing activities.

Great, thank you.

That's it for me.

Thanks very much.

Thanks, Ellen.

we'll take our next question from Michael Hall at Stifel Nicholas.

Great quarter, great year.

We spent a lot of time talking about the supply side.

Can you maybe talk about the domestic demand equation and specifically on power generation, we've seen a couple really big increases of power generation demand the last few years.

Kind of how you see this playing out in the next two to five-year period and where natural gas falls into that equation.

Michael, thanks.

I think really what we've seen is a trend that has continued or been ongoing for at least the last five years.

I can remember, in the year 2000, I think our stock price was $3 or 4, and maybe gas prices were around $3.

And we were talking then about one of the great trends in our market, and how we might be able to do well going forward, was that we would be shedding the most price sensitive consumer who tends to be an industrial consumer, and supplanting them with a price-insensitive consumer, who is generally you and me when we use electricity.

And really as you look back over the last five years, we've generally lost about a bcf a day of demand from natural gas on the industrial side.

Some of it is from efficiency, some of it is from actual offshoring of those functions.

And then we have offset that by about a bcf a day increase in electricity demand.

Might have been a little higher last year, and going forward.

There's been kind of a mini-surge of coal plant building, but I don't think that's sustainable into the future, and so going forward, we think it's the true alternative fuels that will be carrying the load.

And those alternative fuels are not as other people define them as alternatives to hydrocarbon, but as we define them as alternatives to carbon heavy fuels.

And so that in group, of course, we include wind and solar, but natural gas is really the best base load generation fuel in that.

And so that along with conservation, I think, is what will keep electricity prices in check in the years to come while at the same time providing a nice underpinning of electricity -- rather of natural gas demand.

Of course, the agricultural sector is providing great support for natural gas demand these days.

Corn is our most natural gas intensive crop out there, and its use of fertilizer and, of course, the ethanol process is very natural gas intensive as well.

So we're losing -- over the years we'll continue to lose natural gas demand in the industrial area to efficiencies.

I think the offshoring of demand trends is like toll come to an end as you can no longer say some gas consumers have said in the past that U.S.

gas prices are higher than the world's, and today we probably have some of the most affordable gas in the world.

So I think things are setting up pretty nicely.

Clearly under the next administration is likely to be much less coal friendly than the past administration has been, and I think there are a lot of favorable trends setting up for natural gas in the years ahead, and that's why we've gathered as many natural gas assets as we have.

Great.

All right.

I think the thing has been pretty well covered.

Great quarter, great year.

Thank you, Mike.

We'll take our next question from Shannon Nome from Deutsche Bank.

Just a clarification along the lines of Brian's question.

The total budgeted CapEx that you guys show now, 4.85 to $5.5 billion is there anything outside is that in terms of midstream or any other categories that would be considered in sort of investing activities in '08 or is that all-inclusive?

Thank you, Shannon.

Marc is going to take that.

Well, as you look at our guidance for '08, you've got several categories.

You've got your drilling category, midpoint of which is 4.6.

You've got leasehold and property acquisition costs, which we've begun budgeting in the last few months and showing that.

Midpoint is 1.3.

And we've got monetization of oil and gas properties coming off of a billion, and G & G costs as well.

What we don't have in there, to specifically answer your question, we don't have anything from the partners investment in the midstream, nor do we have anything in the midstream investments budgeted in there.

What would that amount to, Marc?

Current it's -- we're anticipating that the net cash to us will be probably $600 million with the remaining $400 million right now staying in the entity to pay for the balance of the expenditures.

I think, Steve, we've budgeted about $700 million, as I recall, plus or minus, for midstream activity.

So, you know, kind of $300 of it will have been spent or so by the time we close this thing that will be reimbursed to us in our current thinking, and then the balance will stay in to pay for midstream assets for the remainder of the year.

So that's why we've got that shown as basically a net zero for the year for us, although the investment will still be being made by the freestanding entity.

Does that make sense?

I think it does, but your total cash outlays at the end of the year will be a little bit higher than the total budgeted CapEx you're showing here, right, or is it a total --

The total outlays will be greater and it will be offset by cash coming in from the investing partner that we haven't shown.

Okay.

And we'll take our next question from Benjamin Dell at Bernstein.

Can you confirm how many company operated rigs you currently have running?

Yes, we have 81, we believe, and we are building three additional that are build for use in the Appalachian region, and we are -- our rig count is 145, and that bounce around from as low as 140 to 145 range.

Okay, in looking at your full year earnings and revenues from the service sector, which I assume is coming through versus the cup seems to be that you're running at a pretty low margin on those assets.

Is there a particular reason for that?

Well, most of it goes into the full cost pool, Ben.

Remember, we're only able to show the income statement effect of third-party working interest in our wells.

So for example, on a well that we own 100% of, there is absolutely no income statement effect to it.

So the other thing is, we think we provide good value to the industry with our rigs, and certainly have margins that are not excessive in the market today.

Great.

On a totally different point, you mentioned Alaska.

Obviously with the increase in iron ore costs, and essentially steel costs, it looks as though LNG out of Alaska could be an attractive option.

Would you have any interest in getting involved in that if that was the case?

Ben, I will check the transcript, but I'm pretty certain I've not said the word Alaska today.

But with regard to your question, no, the answer is this is a company built only for speed, on shore east of the Rockies, and in the USA.

So we'll leave Alaska to others, and I compliment you on that we've never been asked a question about Alaska before, so this is the first.

If I could just throw one more out there, and I suspect the answer is no, but there's been some talk about tight gas in Europe.

That market's tightening.

There's a large amount of acreage out there essential untouched from tight gas coal and methane, has any of that come across your radar screen or is that something you would completely rule out.

Ben, that's very good question, and we certainly have noticed that some other companies are starting to talk about it.

I think one of the most encouraging things to be a citizen of the world is that there's lots of shale in the world, and wherever there's been oil production, there's shale somewhere near.

So I think a lot of the world's problems with regard to energy supply over time are going to be met by natural gas from shales.

This company sees more shale every day than any other company in the world, and we drill more shale wells.

So I would imagine that our experience and knowledge are absolutely -- or would be absolutely transferable to other areas.

Having said that, we have no interest at this time in pursuing anything outside of the very tight geographical region that I described.

We have 36,000 wells we've got to drill here and we'll stay focused right here at home.

But I do think thinking the about shales from a worldwide basis will I think -- does it provide a lot more optimistic energy future for the world than maybe other people are considering these days.

Okay.

Great.

That was it.

Thank you.

We have a follow-up question from Shannon Nome with Deutsche Bank.

Along those lines just checking in on Appalachia what are the plans this year in the Marcellus shale?

You mentioned you're building some rigs up there.

Presumably those are appropriate for horizontal shale drilling.

As an adjunct to that how do you see the play evolving?

How much time is it going to take before all the infrastructure is set up for that to become a major growth area?

Certainly it's one of the more exciting new developments in the area these days.

Shannon, I'm pleased to announce that, or confirm what we said last week on the call, we have 1.1 million of our 4 million acres in Appalachia we believe are prospective for the Marcellas from West Virginia all the way up into southern New York.

We also have several hundreds of thousands of acres that are prospective for lower Huron shale as well in Kentucky and West Virginia.

We've not been specific with what we're doing with the Marcellas.

We'll let other companies talk more in detail, but we are drilling a combination of vertical and horizontal wells there.

We are optimistic about what lies below that 1.1 million acres of land there as we discussed last week that could be as high as six trillion cubic feet of gas for us using, I think, some pretty conservative spacing assumption on 160 acres per well.

So what the challenge there will be, of course, is geography is always a challenge, and Fort Worth it's the urban geography.

In Pennsylvania and West Virginia, it's the forests and the hills and a lot of land in Pennsylvania that's subject to -- or that might be prospective for the play is actually state-owned land, and there are questions about whether or not state forest land is -- how much drilling can occur there.

Lots of infrastructure that needs to be built, so I don't believe it will be a play that kind of explodes on the scene the way that the Barnett play has over the last five years, let's say, in Johnson County, where you can just go from 0 to 100 rigs in a year.

I think will take longer to get built out.

So I think that's great news for those of us who have built acreage positions in the play, and you think it's great news for eastern gas consumers as well, that there's a multi-decade worth of new supply right at your door step, and we're working with all the relevant regulatory agencies to make sure that we start to get the regulatory structures in place to allow us to aggressively but also prudently develop that asset.

So we're excited about it it and one of the reasons we bought Columbia two-and-a-half years ago was the idea that there was a lot more to do in Appalachia than people had been thinking about for decades and we're excited about being part of a new play developing right in some of the best gas markets in the U.S.

Okay, I believe that brings to us a conclusion today.

I appreciate your interest, in the company's conference call, and if you have any additional questions, please direct them to Jeff, and we'll look forward to talking to you down the road.

Thank you.

thank you.

That does conclude today's conference.

You may disconnect at this time.