Chesapeake Energy Corporation Q4 2007 Earnings Call Transcript

Feb.22.08 | About: Chesapeake Energy (CHK)

Chesapeake Energy Corp. (NYSE:CHK)

Q4 2007 Earnings Call

February 22, 2008 9:00 am ET

Executives

Jeff Mobley - SVP of IR and Research

Aubrey McClendon - Chairman and CEO

Marc Rowland - EVP and CFO

Analysts

David Tameron - Wachovia

Brian Singer - Goldman Sachs

David Heikkinen - Tudor, Pickering, Holt

Gil Yang - Citi

David Kistler - Simmons & Company

Ellen Hannan - Bear Stearns

Michael Hall - Stifel Nicolaus

Shannon Nome - Deutsche Bank

Benjamin Dell - Bernstein

Operator

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.

Jeff Mobley

Good morning and thank you for joining Chesapeake's 2007 fourth quarter and full year Earnings 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's management will make during the course of this call. The statements that describe our beliefs, goals, expectations, projections or assumptions are considered forward-looking. Please note that the company's actual results may differ from those contained in such forward-looking statement. 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 this morning, 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 estimates. These are all non-GAAP financial measures. The reconciliations to comparable GAAP measures can be found on page 18 through 20 of our press release issued yesterday afternoon. While these are not GAAP measures of financial performance, we believe they are common and useful tools in evaluating the company's overall performance.

Our prepared comments this morning should last approximately 10 minutes, and then we will move to Q&A. Aubrey?

Aubrey McClendon

Thanks, Jeff, and good morning to each of you. I would like to begin by introducing the other members of our management team who are on the call with Jeff and me today, 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 that in 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 progress of our asset monetization.

As you many of you know, after the Katrina and Rita natural gas price surge in late 2005, Chesapeake's management team became increasing bearish about US natural gas prices for a number of reasons, one of them, in fact, the result of our own aggressive natural gas production growth plans. As a result, Chesapeake has been extensively hit during the past two years, and this 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 in our evolving overtime that lead us to conclude that natural gas prices may have upside in them during the next two years. Among these are rising electricity usage in the US, 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 than 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 is 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 multiyear 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 Niña summers, the bias has been towards warmer weather and this current La Niña is bordering on the strongest La Niña event ever recorded.

Moving on from gas prices, I'd like to discuss the 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 ageing 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, 2,500 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 1, 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 remained one of the 100 best employers in the US by Fortune Magazine, a designation that only two other E&P companies received. We've worked hard to build a distinctive company and culture, and believe it is paying big dividend 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 creation 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 ENP 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 multiyear gas hedging at or above $10.

The shareholders of Chesapeake then, we have three rocket stages working for us in the next several years. First, you have growth and proved reserves of 2 Tcfe per year, which we reviewed last week. As discussed then, I believe these added reserves should be worth $7 billion to $8 billion a year value. Secondly, you should see our unrisked, unproved reserve increase by at least 5 Tcfe. Again, as discussed last week, I believe those book 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 crude reserve 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 of value creation.

So you add it all up and you get around $16 billion to $17 billion of potential value creation per year of around $30 per share. I then aggressively risk this at 50%, and that's how another way that I support last week's calculation that we should be able to increase the value of Chesapeake 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 it as well.

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

Marc Rowland

Thanks, Aubrey, and good morning everyone.

I'd like to start out by speaking about our production guidance for a moment. We didn't highlight this in our press release, but our November 6 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 production stay on our books. In a sale, I guess somewhat obviously, they've 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 at 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 preferred less the common dividend stream, which is obviously greater than the place 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 analyst 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.

To speak a moment our second round of VPPs, we are 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 VP 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 the 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, and then, ultimately, hopefully closing by the end of April, we believe that we are going to see valuations of our midstream business between $3.5 billion 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 forecast are for this asset to grow even faster in '08 and '09 as we move further into the connection process in the Barnett Shale, the Fayetteville Shale and our other projects.

So with that, I think that concludes our remarks. And moderator, if you would begin the question and answer process, please?

Question-and-Answer Session

Operator

(Operator Instructions)

And we'll take our first question from David Tameron from Wachovia.

David Tameron - Wachovia

Hi. Good morning. Can you talk a little bit, Aubrey, about the infrastructure in the Barnett seems to be kind of rearing its ugly head for some companies, can you talk a little bit about how guys are positioned going forward and if you expect any constrains?

Aubrey McClendon

We do expect constraints. We've experienced constraints today. Any time you try and dig underground in an urban environment, 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 58 different municipalities. 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 is always the risk that we'll have other issues. The main concern few years ago that there wouldn't be enough takeaway capacity once you've gathered the gas inside the play, I think we are all squared away there. It is mainly getting it from wellhead 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 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.

David Tameron - Wachovia

All right. And then, a big picture kind of macro question, it seems like F&D costs have come down this year across the board, and 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 want to pay less for properties going forward if F&D costs are lower? Can you talk a little bit about that, any changes in M&A market going forward?

Aubrey McClendon

You are talking to the wrong company these days about this. As you will know, David, we're really not active in the acquisitions markets, 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, I think that's part of it. But when we started to say really two years ago was 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 and revenue that we saw in 2005 and 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 50%.

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 timeframe 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 findings 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 issue one at a time every time you drill a well. You've got to do what we and handful of other companies have done, which is build the gas resource plays, grasp the engineering and geological challenges and then go out and drill hundreds and 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 efficiencies go up.

David Tameron - Wachovia

All right. Thanks.

Operator

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

Brian Singer - Goldman Sachs

Thank you. Good morning.

Aubrey McClendon

Good morning.

Brian Singer - Goldman Sachs

The hedges that you put in place following Katrina and Rita at very high prices seem 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 that in the context of thinking about further drilling increases from here? And given your comments on people, do you have, I guess, the willingness and ability to further ramp up activity?

Aubrey McClendon

Well, we currently have the property set that would enable us to drill more wells if we 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 it provides us with 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 go ahead and tell you a little bit about our hedging thoughts these days.

J. Mark Lester

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 up feature or the embedded put, and receive prices that are -- 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 directly translates into an increase in rig count by [Mr. Dixon's Strelestris Group], but obviously 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 are able to lock in higher prices over a stream years, it makes the sale of those molecules at higher prices, and therefore more cash flow for the same amount of molecule. 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 markets and in the gas markets.

Brian Singer - Goldman Sachs

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

Marcus Rowland

We have that possibility.

Brian Singer - Goldman Sachs

Okay.

Marcus Rowland

I think that's a good estimate, right.

Brian Singer - Goldman Sachs

Great. Looking at your cash flow statement, it looks 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 is component of your spending that's non-E&P. But I guess could you talk to what that was and how should look at total spending in 2008 relative to your $5.5 billion E&P budget or so before considering E&P asset sales?

Aubrey McClendon

Well, let me flip to that detail and it may take me a moment here. We might go to next question and come back to that Brian if you don't mind.

Brian Singer - Goldman Sachs

No problem.

Aubrey McClendon

Operator, we will take the next question and then we will come back to Brian, please.

Operator

Okay. We will take our next question from David Heikkinen from Tudor, Pickering, Holt.

David Heikkinen - Tudor, Pickering, Holt

Good morning guys. I had question about Rockies Express and their impact on MidCon and Permian gas realization so far than what you are expecting in '08 and then a potential reversal in '09 and what the overall impact will be on the gas realization?

Aubrey McClendon

Well, we have followed that like everybody else in the industry. And from what we have read, it seems like that we have seen somewhere between $300 million and $500 million a day of incremental supply. It has been relatively cold in the Rockies and of course in California as well. So not as much gas is 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 had so far this year. We are about as well protected as we could be from basis hedges and have made well over $1 billion on our 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 so the pipe gets overrun and we expect that to be true as well. So about every three years I think you can expect the Rockies to have good gas prices, six months to a year, out of the three years. So, go ahead.

David Heikkinen - Tudor, Pickering, Holt

Just thinking about the second and quarter third quarter, you get past the cold weather in the Rockies. You are 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?

Aubrey McClendon

It is so related, it's 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'm just not qualified to get anymore specific than that.

David Heikkinen - Tudor, Pickering, Holt

Okay. And then, 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, '010, what other expense increases would you see? Just a transparency upon each of the other categories and maybe I can talk to Jeff offline about it, but just curious, a picture.

Aubrey McClendon

The easiest thing is, frankly, 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 taking 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's going to be $0.90 to $1 and we say the same thing for 2009 as well.

Everything else more or less stays the same. You'll a future of the company as we always try to be a little bit high on our outlook page as to what our expenses are going. But you'll that we are not anticipating an increase in the DD&A rate. We are not assuming any increases in G&A or in depreciation or in interest expense. So again, it's a flat cost environment in which expect to live in with normal volatility of gas prices giving us the opportunity to lock in revenues that should be well above what the averages are for the next year or two.

David Heikkinen - Tudor, Pickering, Holt

So with the 750 benchmark that you're using in your guidance, if I ran $9, what you're saying is the costs are not going to up dramatically unless there is a big change in activity level in the industry of $0.95.

Aubrey McClendon

The only thing that’s variable is --

David Heikkinen - Tudor, Pickering, Holt

Production taxes.

Aubrey McClendon

The production taxes, and will costs at margin be slightly higher if the industry wants to put on 150 rigs rather than to stay level because gas prices to $9.50 or $10. That's possible but I would remind every body that the rig count on a year over year basis should actually be down were it not for the activities of the two companies and that’s Chesapeake and Sandridge. And so, 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, 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 rig account over the past couple of years has been the activities of just a couple of companies and that will probably reduce pressure going forward.

David Heikkinen - Tudor, Pickering, Holt

Thanks Aubrey.

Aubrey McClendon

Yeah. Thank you.

Operator

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

Gil Yang - Citi

Hi good morning. Aubrey or Marc, could you talk a little bit about DD$A sequentially dropped in the fourth quarter, you've got F&D cost that are depending how you look at it, bumping around $2 or so. You're forecasting DD&A rise in '08. Could you just give us a little more color what logic there is?

Marcus Rowland

Yeah, I'll take that Gil. I mean the logic is, we're trying to be conservative, cost income down in the fourth quarter, and we had an exceptionally good quarter from the drill bit standpoint. I think, as our operations people have shown us over the last couple of days. We expect prices from a budgeting standpoint to basically stay unchanged, although we're seeing some price deflation, particularly in some areas with respect to frac cost 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. And there has not been an increase in our DD&A guidance from the November 6th. So, you are not sure.

Gil Yang - Citi

No, I understand. I am just trying to bring together the idea that you have F&D closer to $2 and you had dropping F&D -- rather DD&A.

Marcus Rowland

Remember that's DD&A. That's finding cost without lease holding, without capitalized items. So, that's the difference I think.

Gil Yang - Citi

Okay. All right. The second question, going back to the previous line of questioning; Aubrey, what do you think, if you do get this, and I understand you are saying that may be you don't see much of pickup and recount overall, but if you are right and you do see $1 increase in the gas price median, let's say over the next couple of years, what increase in gas production domestically do you think we'll end up seeing, because we assume we're maybe 5% today on a month-to-month basis. Is that going to rise or do you think you need that $1 increase to keep it at flat going forward or to keep it at a modest growth rate going forward?

Aubrey McClendon

I'd rather speak in terms of bcfs a day, because on a percentage basis, of course, you are 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. And clearly, the last year has benefited by increases in what Rex has let out of the Rockies and then of course independence nodes are one-time events that are not -- there is no following sort of subsequent events similar to that.

But I think if we look at what we and virtually every other big company and medium-sized company is projecting, almost everybody is in double-digit production growth, or put out double-digit growth targets for the next couple of years. I'll remind you that, our production alone last year increased to over 500 million cubic feet a day on a net basis, on a gross basis. It was probably close to 700. So, we think, we haven’t projected that again, but 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 the company and an industry for the next, at least, two or three year. So, I think its 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've joked, but it's got a serious side to it, which is I think it would be more profitable today to build an LNG liquefaction plant in America than it would be to build another regas plant. So, we are looking for partners if anybody wants to join us on that, because we do think that we are doing a great work for the U.S. natural gas consumer and we will continue to keep LNG imports low in years to come.

Gil Yang - Citi

Okay. Thanks Aubrey.

Aubrey McClendon

Okay. Thank you.

Operator

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

David Kistler - Simmons & Company

Good morning, guys. You kind of followed up on your comments on LNG just now, Aubrey, when you kind of mention the dynamics that are 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?

Aubrey McClendon

Sure, we'd be happy to. In Canada, I think most observers of Canada, including us, were probably little surprised last year that we didn't see more evidence of production drop off. But I think that, this year we are likely to see it. It has 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 of gas a day. People forget that the rest of world consumes 220 bcf 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 of supply to come on just to feed the world market. I think it is well documented that the liquefaction surge that people expect that this year has been delayed. It's obviously clear to everybody as well that the cost of plants have gone up by two to three fold than the old days of thinking that you could land LNG at U.S. shores and be competitive at $3 an mmbtu, just a fantasy these days. And so, what we are seeing happen, what we saw happened on oil and we have seen happen in metals and we are seeing happening in agricultural commodities, we are now seeing it happen to coal and to a limited extent natural gas as well, which is, and 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 we think the rest of the world will suck up most of this LNG growth in years to come. And for the U.S. to receive more than a couple of bcf a day on average, despite whatever our regas capacity is, we are 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 $140 a ton, sulfur dioxide credits were $24 a ton and 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 them, the need for abating their pollution. So, I love the way it's setting up. And I think it's a great news for both U.S. gas consumers that prices will be relatively restrained. While at the same time, I think for gas producers, you are likely to see a little bit higher range in the next two years than what you have seen in the last two years.

David Kistler - Simmons & Company

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

Aubrey McClendon

Yeah, sure it does. The idea that the U.S. has best storage system in the world is correct. And so, there is again a notion that we are going to be a dumping ground for LNG in the summer time. And I think there is certainly an element to that, that it is absolutely true, and we saw that in last summer. We also saw that it can start to go away pretty soon as it start to go away in September. I will also tell you that I don't have any physical evidence of this, but it certainly will make an intellectual sense to everybody on the call that there will be a day when Asian buyers will grow tried of only being able to buy cargos in the fall and winter and paying $15 to $18 in 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 cargos around at all time during the year rather than just during the high price times. And 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 LGN markets around the world.

David Kistler - Simmons & Company

And just last question kind of following up on that, what you think of kind of seasonality in the arbitrage or winter versus summer? Does that impact how you have been laying on your hedges looking at '09 and the fact that you added a bunch of knock outs again? Were those laid on universally or were they laid on, on a seasonal fashion?

Aubrey McClendon

That's a great question. We have actually, in the last six months, gone almost exclusively laying them on in 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 have had two months during that entire time period where the part of our hedges which were laid under the kick outs actually weren't effective. And so, it was as if we had never hedged and unfortunately, those months were pretty low. And so, it did cost us some money, but overall, we've achieved much greater [visibility] through this strategy than what we otherwise could.

David Kistler - Simmons & Company

Great. Well, thank you guys so much for that additional color.

Jeff Mobley

David, thanks for the questions.

Operator

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

Ellen Hannan - Bear Stearns

Good morning. I have three questions. And the first, Aubrey on the Fayetteville activity that you are running 11 rigs there now and you said that 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 Fayette, maybe something less in one of your other areas or an incremental -- add to your rig count?

Aubrey McClendon

Right now, we are not sure if there would be an increase in overall rig count or if we would slide some rigs around. Ellen, we re-budget every month and we evaluate place every month and so, in some place, lose rig, some place gain them. And so, it could be a net gain, but at this point, all we know for sure is that Fayetteville needs more rigs and we will make sure that one way or another that asset team receives access to those rigs during 2008.

Ellen Hannan - Bear Stearns

Okay, thanks. My other two questions are actually 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 and looking at abbreviated statement here, where is the cash from the VPP in the fourth quarter? What category did that flow through to? And the other question I had was on the monetization of the non E&P assets going forward. How should we think about that in terms of what that’s going to make your balance sheet look like?

Marc Rowland

Okay. I will just remind you what happens when you execute a VPP like we do is, your debiting cash and you crediting your full cost pool. So, it's treated as a sale of assets. It's 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 reverses were reduced accordingly. The full cost of pool was reduced by approximately 1.1 billion. So, that at the margin, although, very small, positively effects DD&A rate as well.

Ellen Hannan - Bear Stearns

That’s correct. I have no issue with that. The question is, is it cash flow from operations, cash flow from investing or cash flow from financial activity? Where is the cash?

Marc Rowland

I believe the cash on the cash flow statement -- let me look at that, I believe it's from financing activity. I am still searching for the answer to the question. Obviously, we spent about $2.4 billion of actual of actual investing activity and that was broken down in our K, which will be filed next week in detail. But we spent $1.45 billion on the drillings, about $500 million in all leasehold activity, which is off the ground, delay rentals, mineral purchases, deal leasehold for the small deals we did and so forth.

And then, we had another approximate $400 million of expenditures in all of the other assets that we are buying. And that is principally the midstream assets, but of course, there are 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 sale of the VPP and so forth. So, it will not be in operating activity.

Ellen Hannan - Bear Stearns

Okay. And again just lastly, you talk about monetizing non-E&P assets going forward. How we should we think about what, if anything, that does to your balance sheet?

Aubrey McClendon

We would use either a VPP or the MLP. So, I will let Marc respond to that for you, Ellen.

Marc Rowland

Yeah. Well, the balance sheet is going to be unchanged. I mean it is going to be from the MLP standpoint. We are going to still consolidate all of the gathering assets and I don't know what the interest is. But there 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.

Ellen Hannan - Bear Stearns

Okay. Great, thank you. That's it from me. Thanks very much.

Marc Rowland

Thanks, Ellen.

Operator

And we will take our next question from Michael Hall of Stifel Nicolaus.

Michael Hall - Stifel Nicolaus

Yeah, hi. Great quarter, great year. We spent a lot of time talking about some of the supply side kind of macro natural gas commentary. Can we maybe talk a little bit about the domestic demand equation, and specifically, on power generation, we've seen a couple of really big increases of power generation demand the last few years. So, kind of how you see that playing out in the next two to five year period and where natural gas falls into that equation?

Aubrey McClendon

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, with 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, if you look back over the last five years, we've generally loss about a bcf a day of demand from natural gas on industrial side. Some of is it from efficiency, some of it is from actual off shoring of those demand 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 has been kind of a mini surge of a coal plant building but I don't think that's sustainable into the future. And going forward, we think it is the true alternative fuels that will be carrying the load and those alternative fuels are not as other people define them as alternative to the hydrocarbon, but as we define them as alternative to carbon heavy fuel and so in that group of course 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 natural gas demands.

Of course the agricultural sector is providing great support for natural gas demand these days. Corn is the most natural gas intensive crop out there and its use of fertilizer and then of course the ethanol process is very natural gas intensive as well.

So, over the years, we will continue to loss the natural gas demand in industrial area to efficiencies, I think the off shoring of demand trends is likely to come to an end and you can longer say some gas consumer as I said in the past, that US gas price are higher than the world and today we probably have some of the 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 administrations 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 together as we have.

Michael Hall - Stifel Nicolaus

Great, well. I think things then pretty well covered. Once again, great quarter great year.

Aubrey McClendon

Appreciate it, thank you Marc.

Operator

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

Shannon Nome - Deutsche Bank

Hi, guys just a clarification along the lines of Brian's question, the total budgeted CapEx that you guys show now, $4.5 billion to $5.5 billion, is there anything outside of 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?

Aubrey McClendon

Thank you, Shannon. Marc is going to take that, just a second.

Marc Rowland

Yeah, well as you look at our guidance for '08, you've got several categories; you've got your drilling category at the midpoint of which is 4.6. You've got leasehold and property acquisition cost which we begun budgeting in the last few months, and showing that, midpoints 1.3. And we've got monetization of oil and gas properties coming off of a billion and G&G costs as well. Now, what we don't have in there, and to specifically answer your question, we don't have anything from the partner's investment in the midstream, nor do we have anything in the midstream investments budgeted in there.

Shannon Nome - Deutsche Bank

What would that amount to Marc?

Marc Rowland

Well currently, we are 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, kind of 300 of it will have been spent or so, by the time we close this thing that will reimbursed to us in our current thinking. And then the balance will stay in the paper 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 being made by pre-standing entity. Does that make sense?

Shannon Nome - Deutsche Bank

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 are showing here, right? Or is that an absolute loss?

Marc Rowland

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

Shannon Nome - Deutsche Bank

Okay.

Operator

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

Benjamin Dell - Bernstein

Hi, guys.

Aubrey McClendon

Hi, good morning.

Benjamin Dell - Bernstein

Good morning. I had a couple of question, the first was, can you confirm how many company operated rigs you currently have running?

Aubrey McClendon

Yes, we have 81, I believe. And we are building three additional that are built for use in the Appalachian region, and our rig count is 145 and that bounces around from as well as 140 to 145 range.

Benjamin Dell - Bernstein

Okay. And looking at your full year earnings and revenues from the service sector, which I assume is coming through versus the [cup]. It seems to me that you are running at a pretty low margin on those assets. Is there a particular reason for that?

Marc Rowland

Well, most of it goes into the cost pool, Ben. Remember we are 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 a 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.

Benjamin Dell - Bernstein

Okay, 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 actually, LNG out of Alaska could be more attractive option. Would you have any interest whatsoever in getting involved in that if that was the case?

Aubrey McClendon

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 onshore east of the Rockies, and in the USA. So, we'll leave Alaska to others, and I compliment you on we've never been asked a question about Alaska before, so this is a first for us.

Benjamin Dell - Bernstein

If I could just one more out there, and I suspect the answer is no, but there has been some talk recently about tight gas in Europe. Obviously, as you mentioned that market is tightening, there is a large amount of acreage in land out that has been essentially untouched from tight gas coal and methane and shale gas, has any of that even come across your radar screen or is that something you would completely rule out?

Aubrey McClendon

Ben, that's a 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 is a lot of shale in the world, and wherever there's been oil production there is shale somewhere near.

So, I think a lot of the world's problems with regard to energy supply overtime are going to be met by natural gas from shale and this company sees more shale everyday than any other company in the world, and we drill more shale wells. And 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 will stay focused right here at home. But I do think, thinking about shale from a worldwide basis will, I think it does provide a lot more optimistic energy future for the world than maybe other people are considering these days.

Benjamin Dell - Bernstein

Okay. Great. That was it. Thank you.

Aubrey McClendon

Thanks for your question, Ben.

Operator

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

Shannon Nome - Deutsche Bank

Hi, there. Along those lines just checking on Appalachia what are the plans this year in the Marcella shale? You mentioned you are building some rigs up there; presumably those are appropriate for horizontal shale drilling. And then as an adjunct to that, how do you see the play evolving? How much time is it going to take before all the infrastructure setup for that to really become a major growth area?

Aubrey McClendon

Certainly, it is one of the more exciting new developments in the area these days. Shannon, I am pleased to announce that it was confirmed what we said last week on the phone call that we have 1.1 million acres of our 4 million acres in Appalachia; we believe perspective for the Marcella 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 have not been specific with West Virginia, with the Marcellus. And we will let other companies talk more in detail, about what they are doing, 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 and as we discussed last week that to be as high as 6 trillion cubic feet of gas for us using, I think some pretty conservative spacing assumptions on 160 acres per well.

So, the challenge is there, will be of course, it is geography is always a challenge and Fort Worth it's the urban geography and Pennsylvania and West Virginia it's the forest and hills and a lot of land in Pennsylvania that's subject to that might be perspective for the play is actually say 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 build, so I don't believe it will be a play it kind of explodes on the scenes away that the Barnett play has over the last five years, let's say in Johnson County where you can just go from zero to 100 rigs in the year. I think this will take longer than to get built up, so I think that's great news for those of us who has build acreage positions in the play and I think its great news for eastern gas consumers as well that there is a multi decade of worth of new supply right at your door step and working with all the relevant regulatory agencies to make sure that we start to get regulatory structures in place to allow us to them aggressively. But also prudently develop that asset.

So, we are excited about 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 then people didn't thinking about for decades and we are excited about being part of and the new play developing right in some of the best gas markets in the US.

Okay. I believe that brings us to a conclusion to day, I appreciate your interest in company's conference call and if you have any additional questions, please direct them Jeff and we'll look forward to talking to you down the road. Thank you.

Operator

Thank you. That does conclude today's conference. You may disconnect at this time.

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