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Chesapeake Energy Corporation (NYSE:CHK)

Q3 2008 Business Update Call

October 15, 2008 2:30 pm ET

Executives

Aubrey K. McClendon - Chairman of the Board, Chief Executive Officer

Marcus C. Rowland - Chief Financial Officer, Executive Vice President

Jeff A. Fisher – Senior Vice President Production

Jeffery L. Mobley – Senior Vice President Investor Relations

Analysts

Shannon Nome - Deutsche Bank

Brian Singer - Goldman Sachs

David Tameron - Wachovia Capital Markets LLC

Unidentified Analyst

Michael Hall – Stifel Nicolaus

Gil Yang – Citigroup

Dan McSpirit – BMO Capital Markets

Thomas Nowack – Bank of America

Shannon Nome – Deutsche Bank

Kelly Cringer – Banc of America Securities

Mike Harris

Aubrey K. McClendon

My name is Aubrey McClendon and if you hadn’t noticed, that video was made more than a couple weeks ago with regard to reference on enterprise value. We do recognize that there are lots of things you can do with your time. This is the first occasion that we have had an investor conference on campus so we’re very pleased with the response. We do hope you’ll take some notes and let us know next time what you’d like to see more of, less of and we always want to try and do better.

With that I thought I would go ahead and jump in. I’m going to talk about 10 or 15 minutes and then Marc will speak. There are a lot of questions you could ask of me that Marc might answer so then we’ll be together to answer your questions jointly.

So we’ll get underway with what I was hoping to accomplish for the meeting which was that you would walk away with a better understanding of our company and to be impressed with the attractiveness of our strategy, the quality of our assets and technology, learn more about our financial resources. We’re obviously going to lead with that rather than go third with it. We’ll talk a lot about our asset monetization strategies that are really unique in the industry and we want to make sure everybody has a solid fundamental understanding of why we do what we do there.

I want to talk about the uniqueness of our culture. Hopefully as you all get the chance to walk around campus a little bit you’ll see that this is a different place. From the beginning my view was anybody could rent space in an office building and I wanted to build something distinctive, and I think we’ve been able to do that with our campus. We find that it puts employees at ease and certainly makes the headquarters campus more accessible and I think just a friendlier place to be. This is our blue room. It’s won several awards in the past year or so and again it’s our way of taking a corporate auditorium and trying to put a little bit of a distinctive flair to it.

Then I want to talk about the vision for the future and also talk about how over the past 19 years we’ve navigated a number of challenges as we have grown from a $50,000 investment in 1989, we had 10 employees, to today we’re the most active driller and largest producer of gas in the US.

Obviously there have been a lot of challenges along the way. Certainly the last couple weeks have been challenging for me and all I would say about that is it’s over, it’s behind me. I spent 19 years building a significant stake in the company’s equity. Due to circumstances much larger than me that stake unfortunately was involuntarily lost to some margin culls. A tough deal but life isn’t always fair, and life’s been good to me so I have moved on and started working on rebuilding my position in the company day-to-day and focused of course on providing the leadership along with my colleagues to the company and its employees and our shareholders.

Let’s talk about Chesapeake. Today the company’s enterprise value is not $50 billion. It’s closer to around $22 billion or so and so I just want to take a look at where we are. I think the first place to start is, what’s the company worth at $5 natural gas? I think most people in the audience would recognize a completely unsustainable gas price in our industry. I think everybody knows how decline curves work in this business.

If we were to get to a price that never went above $5, which again is I think impossible to occur because of the rate at which gas production would begin to decline, but if you could imagine that we still have PV-10 of our assets of $15.5 billion and you just go through the other assets that we have and I think at $5 gas our stock is worth $30 a share. Earlier in the year when things were better, it was my view that the company stock was worth at least $100 a share and it’s interesting that you don’t really have to have a heroic gas price assumption to get there. At $8 we think that’s what the company’s underlying net asset value is worth.

There have been a lot of crazy things said and rumored about the company in the past couple weeks. One of the more surprising to me is that somehow we were going to be unhedged if gas prices went lower from here. The reality is our hedge value is the same at $5 as it is at $8, and Marc will again explain this more to you. We think we’ve built a company that has enormous value, is well protected from further downturns in gas prices from here, and offers exceptional value.

The problem with buying our stock or any other stock in the sector today is of course you can wake up tomorrow and have lost 15% or 20% of your money for reasons not related at all to the company. The way I kind of think about what happened to me, I always felt like if I was going to lose money on my stock, it was going to be because of operational mistakes or strategic mistakes that we made.

On June 30 we had a $60 some odd stock price and we were set to earn close to $10 a share cash flow in 2009, earn over $3 a share of earnings. At September 30 the stock price was $38 and nothing had changed except during the 90 days from June 30 to September 30 we executed I think the most innovative joint venture transaction in the industry has seen in a long time with our deal with plains in Haynesville, we sold an asset to BP that generated a great profit margin for us in the Woodford, and then did a second innovative joint venture with BP in the Fayetteville.

We did everything that we said we were going to do during the quarter and ended up with a stock price at $38 on September 30. Today we wake up 15 days later and the stock price is $16. So what’s happened at the company? We’re still going to earn almost $10 a share of cash flow in 2009. We’re still going to earn over $3 a share of earnings, and nothing’s changed. And we’re well on our way in the fourth quarter to completing some transactions that I think are just as innovative and just as valuable to the company.

Apparently people are doubting our ability to do that and therefore also doubting the ability of our colleagues in the industry to complete innovative transactions. But nothing’s changed in the past 105 days except our stock price is down 70%. There’s been no underperformance by the company in terms of any of its metric during that time and I hope that that comes through today during our presentation.

Let’s talk a little bit more then about our strategy. We certainly think that over the last 19 years if there was anything you could say about the company, I hope you would say that we have been as proactive as anybody else in the industry in terms of looking out into the future and anticipating change. The company strategy has certainly evolved over time.

We’ve been a public company now 15 years and during the last 15 years I think if you looked at who was early to horizontal drilling, who was early to resource plays, who was early to understand at the turn of the century that gas prices were likely to move structurally higher from $1 and $2 that they had been for years, early to appreciate the value of a lease, early to appreciate that when you use higher gas prices on areas that new technologies can unlock vast new reserves of gas that once you establish the lease positions you’ll have them forever and that they will provide differentially better performance for decades to come.

We were early to shales. We weren’t the earliest to the Barnett Shale but we caught up fast in the Barnett and used what we learned there to establish leadership positions in the Woodford and the Fayetteville, in the Haynesville and also in the Marcellus. We were early to Appalachian. Tom Ward and I started together there in 2002/2003 to look around. I was attracted to two things really about Appalachia. The first was that I liked gas prices closer to the consumer.

We’d just spent some time in the Rocky Mountains looking at coalbed methane and I walked away saying I never want to own assets in the Rockies. It may be the greatest place to look for gas, find gas, but it’s always going to be a tough place to make money and nowhere is that more true than it is today in that area. So I wanted to be close to markets and achieve higher gas prices.

The second thing is it’s an enormous basin from a geological perspective and we felt that it hadn’t been attacked by a modern exploration in its history. So we felt that if we could get there and we could apply some of the same techniques that we had used to rejuvenate the Anadarko Basin, some of the same techniques that we were using to unlock the cracked code in the Barnett, we would be able to really create enormous value there. So we bought Columbia Natural Resources for $2.1 billion there and our asset base there is worth many, many times that today and gave us a huge chunk to start in the Marcellus.

We were early to hedging. We have long talked about our desire to even out the highs and lows in this business. You typically make more money in the lows of the industry than at the highs so we were willing to deprive ourselves of revenues at peak points of the cycle in exchange for having more revenues at the bottom part of the cycle. I think we’ve done a good job of doing that and today you’ll see the percentages of gas that we have hedged above $9 in 2009 and 2010.

We were early to vertical integration. We have a Top 10 drilling company. I think it’s sixth or seventh in the country. Top 10 in compression and Top 10 in drilling services as well. It’s been our goal to dampen inflation in the business by investing vertically in some of these assets and have an inflation hedge, but what began as an inflation hedge became an operational advantage.

What we found out is that on location when you’re using rigs built specifically for Chesapeake, these are not just built for use but these are built for our use by our engineers, when you put the same ball cap or hard hat on a rig employee that we have around here, everybody’s on the same team and things go quite a bit better.

We were also early to demonstrate the value of joint venture arrangements. As you all know we have the largest leasehold inventory in the industry and over the past six months or so, once we became convinced that gas prices were unlikely to continue to rise indefinitely in the future, instead we thought they would pause for a number of years before we got transportation involved in the equation, that it would be a good time to bring some of that present value forward, bring in some larger partners. We’ve been able to do that so far I think to great effect and we will be able to do that going forward as well.

I won’t spend much time on the history other than just to say again the company has been confronted with numerous challenges since we started and today where we are is we have built a company that also is just as nimble, just as capable of evolution and just as cutting edge as it ever has in terms of our ability to adjust on the fly. Everybody I presume in this audience has had to adjust their lives on the fly in the last two weeks to 30 days. Certainly your employees have had to do that and we certainly have as well.

But at the end of the day we’ll be a stronger company as a result of it. One of the great advantages of a time like this is we can drive down the cost of our business that’s not only going to be true soon on the drilling side but it’s especially true today on the leasing side as we are continuing to be very, very aggressive in driving down prices in areas of shale plays so we can acquire leases we think at a lower price going forward.

I wanted you to be able to focus on the quality of our assets and technology. I apologize to you that we have scheduled two hours for Marc and myself because I feel like most people are reasonably familiar with me and Marc and the transparency of the company’s financial statements I think is well known among investors. I think we put out more information than anybody else.

So our goal for today and tomorrow is really to allow you to do a deeper dive into the asset side of the business and to meet some of our key players. Given where we are with markets today we felt like it was important to respond to whatever financial concerns that would be out there.

I think what you’ll find by the time you leave tomorrow is that if you weren’t convinced of it coming in I hope you’ll be convinced of it going out, that we have the best assets in the US and we say E&P but I would include major companies as well. We’re number one in the Haynesville, number one in the Marcellus, number two in the Barnett, and number two in the Fayetteville. In the top four shale plays in America, we’re number one or number two. Nobody else is a top two in more than one play. In each of these plays we’re a primary mover.

We are also going to be able to be cash flow positive from this point forward. That includes a part of our business model that apparently some people still have a hard time understanding and I think there are two ways to make money in the business. One is to drill wells and just have the gas produce out over time.

But there are other ways as well and that is doing these various asset monetizations. I think when we’re through with 2008 you will see that our company will have monetized somewhere between $10 billion to $12 billion of assets during the year including drilling carries and would have an indicated profit margin if you will on that of about $10 billion. I can assure you that buying leases for X and selling them for 5X or 10X is a lot more profitable than trying to produce gas at $5 or $6 mcf.

Apparently again there is enormous concern out there among investors that nobody in the industry has any money or has any interest in being partners with us in some of these plays. I can assure you that is incorrect and you will know that over the course of the next 60 days.

I think something else that people haven’t focused on is our DD&A rate. We are a full cost company. I’ll talk a little bit more about that in a second. At a time when most people’s funding costs have been going up over the last couple of years and will continue to going forward, particularly those companies without a big shale presence, our costs are going to go down. Our DD&A rate will go down. That means our net income will be higher, our returns on equity will be higher.

In many respects over the last three or four years have been called pulling along a little ball and chain in the form of a lot of leases that we bought as we were trying to establish dominance in a number of plays that we felt we had a two-year window to establish that dominance after which there would be really no way to get back involved. Now what you’re going to see is an unleashing of the value of those land assets in our business and it will have an enormous financial implication on our income statement going forward as well.

I’ve talked a lot about the leasehold and finally you’re going to see some technology later today. I hope you’ll stick around for the 3D seismic tour and also the reservoir technology center tour as well.

Marc will spend more time on this page than I will. He has a whole presentation of course but I just wanted to remind you we have over $1 billion of cash on hand today, that we are building cash during the fourth quarter by at least $2 billion, and we will generate positive cash in 2009 and 2010 as well.

I guess another thing that’s been a little surprising to me is I’ve seen some analyses where if gas prices go to $5, people go out and spend their cash resources. Why would we do that? Why are we not capable of decreasing our capital expenditures? We are not going to spend more cash than what we can generate. If gas prices go down from here, we’ll cut cap ex from here just like everybody else in the industry will. It’s just a fact of life and that will set up the next up cycle probably sometime in 2010/2011, we’ll get a great chance to hedge again I think at some much higher prices than we are today.

Marc will walk through just how much capital we need to spend to just replace our reserves. I think you’ll be amazed that in 2009 it’s almost zero when you consider our carries. It affords us tremendous discretion in terms of how we choose to spend our money going forward.

You’ll also see a dramatic improvement in the company’s balance sheet in the third quarter. We’re going to have record earnings. Our mark-to-market loss from the second quarter will fully reverse to the third quarter. About a $6.5 billion change in mark-to-market now. I’d rather have not seen that. I’d rather still have $13 gas today but at the same time it is a reminder that we take a balance sheet hit when our mark-to-market losses roll through the income statement.

I wanted to talk about our asset monetization strategy. Again I want to remind you that we think about two ways to make money in the business. We don’t just think about producing gas. We also think like a manufacturer would, which is you don’t just keep things in the warehouse. You move your merchandise. You move your freight. You buy things early. You buy things cheap. Then you wait for the rest of the industry to come around and recognize the value of what you have.

The neat thing is leasehold is always cheap in a play whether you pay $5,000 an acre or $10,000 or $20,000 or $30,000. In most of these shale plays it matters hardly at all as to what you pay for leasehold because you consume so much leasehold at 88 acres generally a well and these wells can cost $3 million to $6.5 million. So you put some leasehold on top of that it’s just not much money at the end of the day. We’re going to continue to use that as a secondary manner of creating value for the company.

I want to talk a little bit about accounting. I’ve read all my life or all my professional life that somehow successful efforts is more conservative than full cost. I’ve always debated that because successful efforts at the end of the quarter you’re not subject to these write-downs that full cost companies are.

But this highlights really a big deal for us. In the third quarter, had we been a successful efforts company we would have had about $6 billion of extra profits that would have run through our income statement. Instead you’re never going to see it. It’ll come through on lower DD&A over the years ahead but to believe that somehow successful efforts is more conservative when you are not allowed to recognize gains that we’re actually making when we sell leasehold for 10X that we paid X for, I’d like for you to think about that. It again creates enormous latent balance sheet strength going forward as our DD&A rate will continue to go down.

I’ll close to remind you again on the innovative JV arrangements. We’re going to have more of those by the end of this quarter.

I mentioned a little bit about culture. I won’t go into this much more except I will talk about the youthfulness of the company. We started 19 years ago. Arguably I guess you could say we’ve come farther with less in a shorter amount of time than anybody else in the industry, and I think four or five years ago I became concerned about the future of the industry in terms of a lot of grey hair and where do we go?

We started to actively recruit young people and today we have 2,800 people on campus, this campus that you’re on today. A full 43% are younger than 30 years old, and given that people don’t seem to graduate from college until they’re 23 or 24 these days it’s a lot of young people. I’m really excited about the impact that they’re making. I can’t imagine that you could be at any other company in this industry and be around a more youthful, a more energetic workforce than you are here.

What’s our vision for the future? Near term is tough. It’s not tough to do what we have to do. We’re again well hedged, we are in the best plays in America, we come in every day and we’ve accomplished what we intended to accomplish the day before, again we think and act like manufacturers, our processes run 24/7, we know what our costs are down to the almost penny per mcfc, we know the costs are going lower over time, our efficiencies are going higher.

What we don’t know is what the price of our product is going to be. That’s why we hedge and we’ve done a good job I think of taking a lot of chips off the table through our hedging program. The other thing of course that we can’t do anything about is the economic environment in which we operate. We’ll be very careful, we have continued to cut cap ex and we’ll continue to cut cap ex if we need to. We have again enormous discretion on how we spend money.

I can’t do anything to convince anybody here or anybody listening that we have enough money. We’ve told you that we have enough money, $1.1 billion. I think we’ll end the year at $3.5 billion. I just read that at September 30 British Petroleum had $3.6 billion. I’m sure they have more resources than us, but the point is that we have plenty of cash today, we’ll continue to build cash through the quarter and into ’09 and ’10.

Longer term is a much different story than the short term. Natural gas is simply the fuel that is going to continue to make an enormous impact in our country and in our world. My own view is that we’re near a point of peak oil production whether it’s today or two years ago or five years from now or 10 years from now. It doesn’t really matter to me if it’s geological or if it’s geopolitical or a little bit of both.

At the end of the day we’re at a point where it’s exceedingly difficult to increase the supply of oil, and I think over time our country and other importing countries are going to need to move to natural gas. We’re all fortunate that we live in a country where 85% of our gas is produced every day from American wells and 99% from North American wells.

I skipped over one point that I’d like to finish and I’ll turn it over to Marc, which is there’s a huge change coming in how the public is going to see the volume of proved reserves that we have. One of my biggest frustrations over the past few years is that I think we’ve made poor policy choices in America about natural gas and about other fuels because we haven’t understood how much natural gas there is.

When you drill a horizontal well in a shale formation and you can only book a PUD on one side and one PUD on the other side and ignore the vast expanse of shale around you, you’re going to understate the industry’s proved reserves and the company’s proved reserves. I think you make bad policy choices if it always appears like you’re going to run out of natural gas in 10 years.

Starting with the 2009 reserve reports which will be released in the early part of 2010, the SEC has modernized reserve recognition for shale reservoirs as well as other types of reservoirs. I think our reserves will jump over 20 tcfe on a proved basis then. It’s pretty ugly out there today. There’s no denying that but in another year I think you’ll wake up and hopefully see a little brighter future and you’ll definitely see a company in an industry with proven reserves far greater than they are today.

Marc, I will go ahead and turn it over to you.

Marcus C. Rowland

The first few slides are constructed to address questions that Jeff and Aubrey and I have received by email, telephone, have read about in various analyst reports, so this presentation’s a little bit retooled from what I originally was going to give but hopefully can address some matters of importance of the moment in a straight forward way, and we’ll be available for questions in just a few minutes.

The next part of the slide will be more of a routine financial performance. I then want to spend quite a bit of time talking about hedging. Hedging has been an issue whether it’s counterparty risk, how knockout provisions work, what the status of our knockout provisions are.

Then I’ll finish up with something that I have never shown before and one of the reasons for having this is to introduce you to new parts of the company and that’s our Chesapeake Midstream Partners. If you get a chance we have a new CFO of that business, [Nick Dolosso]. He’s been here a few weeks now; five or six weeks; and he’s sitting right down here and will have a chance to speak to you individually.

As Aubrey said we have $1 billion of cash on hand approximately. It is true that we drew down on our credit facilities fully at the end of September.

Three weekends ago I was headed into the weekend thinking that it was likely a [Fortress], it was likely that Wachovia and it was possible that other banks that are members of our facility would not be capable of funding the following Monday. For that purpose we drew down at that time. We put $1.5 billion in cash and short-term securities. As it turned out, both of those were either saved or taken over potentially. That did not happen. Everyone in our facility except for Lehman Brothers funded. Lehman Brothers had a $75 million slice of our facility and we did not receive $11.4 million of our facility as a result of that.

Another question has been what is the status of our bank covenants? We have a $3.5 billion revolving credit facility that matures in November of 2012. Our first maturity of any other note is due in July of 2013. This facility and not any of our notes have the only maintenance covenants that we have financially in the company. Shown here are the two covenants. One is a debt-to-equity type covenant of 0.7 to 1. You can see we’re substantially under that. At the end of the third quarter we’ll move to be further under that. The other one has to do with coverage and you can see we’re well under any possibility of having a trigger there.

Our senior note indentures, which we have some that we label as noninvestment grade and the more recent covenants are labeled investment grade, but our most restrictive covenant is located in a couple of indentures pre-2005 issuance. You can see here that this is an incurrence test only and we have to have EBITDA to pro forma debt of 2.25 to 1, and we’re currently at 9 to 1 which satisfies the test. It’s a two-pronged test but we satisfied that amount.

Financial markets are melting down. The oil and gas stock market has melted down. You’re not going to be able to satisfy your program going forward. What’s going to happen to all of the things that you’ve been working on?

Listed here are the things that we’re working on. This afternoon we are closing on a $460 million Midstream bank financing facility that will be fully available to us at closing this afternoon. We’ve entered into sales of assets that will close next week for a couple of hundred million dollars located in Oklahoma. We are working on these other items. We have different timing on them but we believe most if not all of these will occur in the timeframe that we’ve outlined here.

How low can it go, it’s been a phrase that’s been shot to me? What cap ex do you need to maintain? I’ve taken a little bit different approach here and show you maintenance cap ex in a different fashion, which is just two plays that we have; the Haynesville and the Fayetteville.

Haynesville we’re covered for 50% of our costs from our partner PXP during 2009 and then for a little forward but concentrating on 2009.

In our BP arrangement with the Fayetteville, we’re covered for 100% of our costs up to a certain amount. You can see here that we’re expecting that to cover all but $100 million of our expenditure in that play with $445 million we are going to spend on a net basis in 2009; $545 million as currently estimated with the information that was put out to you.

What’s that going to find for us? It’s going to find 930 bcf of equivalent reserves on a proved basis, proved developed producing at that point, and that will be 95% or so of the 975 bcf that we intend to provide and it’s being found in F&D cost of about $0.60.

That $545 million represents just about 12% of the operating cash flow that we anticipate at the lowest price stick that we anticipate. A middle price stick anticipates less than 10% of our capital would be required if we wanted to or had to or were forced to due to market conditions, we would still be on a path to restore our reserves fully and in fact the rest of the capital is available for growth, and that’s w hat we’re going to do.

Counterparty risk. Who owes you money? What did they do with it? Are you ever going to see it? All those kinds of questions. I’ve listed our biggest counterparties. Today on a net basis we’re owed about $590 million on a mark-to-market basis. All of these are not confirmed marks down to the last penny but most of the big ones are. Barclays and Deutsche Bank are currently the larger amounts up there but you can see we’ve also got Goldman, Morgan Stanley and then on down the list.

We owe two banks right now. The largest, Credit Suisse, we owe $62 million and to five other institutions we owe $49 million so a net of $595 million.

I think as you look at this list you can see a couple of different things. We’re well diversified. There is no single concentration of a large amount in any hand that’s likely to fail if any of these are likely to fail, and I think none of them are likely to fail at this point. Here are our counterparty amounts and we’ll talk about how they’re structured if you want to later.

Back into the financial highlights now. Some of this Aubrey’s already covered. This is a pretty straight forward way of looking at what we’re doing. I’ve shown you the hedging positions. I’ve shown you the joint venture arrangements.

We’ve talked about the balance sheet already quite a bit so I won’t spend a lot of time on that but we are in a position of improving and increasing our balance sheet strength. This will happen steadily through the fourth quarter; certainly in 2009 where we’re going to be living within our operating cash flow; plus a little bit of asset sales if we want to expand our acreage program to what we’ve fully shown you that we might invest. We think we offer great value to investors today.

This is the detail of the plan for remainder of 2008, 2009 and 2010. We’ve tried to structure it in such a way that it logically fits together starting with operating cash flow, cash flow from the sale of leasehold netted out to what we cost, our other sources of cash, and then our uses of cash.

If we focus on 2009, you can see our drilling program at midpoint’s about $4.5 billion as opposed to operating cash flow of about $6 billion. So we’ve got cash flow.

Remember I’ve already indicated how little cash flow that we could spend in just two plays to nearly fully replace our production. We’ve got a great amount of flexibility here. These are discretionary cap ex expenditures almost entirely. Perhaps some of the Midstream once we start to build it, the pipe has to be finished, but once the drilling rig is off of the well that can be cold stacked, it can be hot stacked, it can be just put in temporary retirement, and we can cease expenditures with no complications.

We’re not going to do that in the plays where we have partners and we have carry arrangements and in those plays where we think the best economics exist. We’re doing that logically I think in the conventional areas; some parts of Oklahoma, West Texas. You probably know or have heard that our South Texas assets have been in a data room and the bids are due here shortly so we’re contemplating moving out. We think the proceeds from the sale of those assets probably approach $1 billion in this reduced price market.

So again, lots of flexibility. We intend to end up with big positive cash balances at the end of this year and stay cash flow positive for 2009 and forward, and at the same time grow production and reserves substantially.

Pick a price slides. You can see that we have lowered the price estimates in reaction to the current market. We now show you for 2008, 2009 and 2010 what happens to our results $6 through a $10 price deck. You can see there’s very little affect in 2008 now because all the pricing is in essentially except for November and December.

2009 moving on here. Quite a bit more price sensitivity especially at lower levels. I’ll get into our kick-out levels but still even at a $6 average for the year our EBITDA here is $6 billion. Going on to 2010 we do the same thing. You can see we remain really solidly profitable even at low prices. You can study all of the things that go with this, the various financial metrics and so forth at your leisure. I won’t try and repeat everything that’s on the screen. I know you guys can read.

We have a strong operating budget. We have a very carefully constructed cash flow plan. What’s that going to do to our profile? Here I’ve shown you what some of the strengths of our business are. We’ve talked about long debt maturities. No debt maturities for four or five years. The capability of generating tremendous amounts of EBITDA and cash flow while growing the reserves, while growing production and having a very low, minimal actually, maintenance cap ex requirement in 2009 and 2010.

Our cupboard’s full as shown here. 14 million acres we do not have to perpetuate this land acquisition and in fact are severely curtailing most of those expenditures as we speak.

Credit profile; second slide on this. It’s showing you some of the items I’ve already talked about. Again, lots of free cash flow, the willingness and the dedication to make sure that our expenditures are well inside of operating cash flow hedged in such a way that it does not become a problem for us to continue the growth and at the same time display fiscal conservatism and responsibility that we think our investors are due.

Slides show here related to maturities. You can see that the bank credit facility is the first slot, 2012, I’ve already talked about. A profile that most of our maturities are concentrated ’16, ’17, ’18. We have eight set of notes that are cullible right now; became cullible in September. We don’t anticipate under current market conditions that we’d be able to do anything about that but the market will change and our intent is to continue to cull when cullible at an attractive price those maturities and push the maturities out. If you had been here three or four years ago, you would have looked and seen maturities that were in the ’10, ’11 and ’12. All of those are gone. They’ve been pushed out to ’16, ’17 and so forth.

The other element to a strong credit profile is obviously margin. If you can’t make widgets or automobiles or things at a profit and sell them at a substantial amount of cash margin, ultimately your business plan is not sustainable. Our cash operating costs are up a little bit over many years. It’s moved into the low $2 range and that includes dividends, includes interest, includes all the lease operating costs, severance taxes, etc. But even today with the prices decreasing a little bit our margin still is over $6 per mcf.

As we move forward I’m sure this will move up and down, talking the hedging slide about how we’re going to try and protect those margins.

Oil and gas hedging. You’ve seen the counterparties that we hedge with. I think there are 19 arrangements in total. Six of those are secured hedging facilities where we have pledged oil and gas reserves directly to protect against margin culls.

The balance of the hedging arrangements are with counterparties where we have pledged para-pursue collateral out of our bank line and those are much smaller facilities and in fact at the moment on July 2 I think which marked the high water mark of our mark-to-market obligation of $6.55 billion to all of these counterparties, we had no margin culls. We’ve very carefully constructed the safety valve to be such that we don’t face that potential liquidity crisis even given multibillion dollar obligations.

Let’s talk about volatility here. Obviously gas prices have been very volatile. The July contract went off at $13.40 something. Today gas prices are $6 three months later, four months later, a 50% or more reduction. We have capitalized on volatility by selling high priced culls, we have sold a lot of 11, 12, 12.50 culls, collected the premium for that and then obviously that is not going to be an obligation as these have been expiring worthless.

But we’ve also done something else. That’s to imbed puts into a swap and that is then called a kick-out or a knockout depending on how you want to refer to it. I’m kind of going to skip through this. This is just some things that we’re all very familiar with, and get right to what the next slide is talking about.

Here are the various instruments that we’ve used. A swap is simply a derivative instrument. None of the hedges that we do are physical. They’re all paper. They’re not on a NYMEX exchange or any other exchange. They’re what’s called over-the-counter. These are the various types.

I’m going to focus because the largest percentage of our production recently hedged has been with the kick-out or knockout swaps. What does that mean?

I’m going to give you a real simple example. Gas for the month of January is at $8 let’s say, and I want to enter into a transaction that hedges that $8 but I want to get more than $8 because I normally wouldn’t hedge at that level. So I go to a counterparty and I say, “I’ll give you the right if on the last day and the only day of contract settlement it’s below a certain price, I’ll allow that swap to go away.” That’s called the kick-out or the put.

In my case of $8, I’m going to establish that I think it might go down but it’s not going to go down below $5.75 which becomes the kick-out level. Why would I want to do that? Well first of all, I’ve got a pretty strong sense that while gas prices might fall if I did it over a number of months, it’s not sustainable below a kick-out level of $5.75. But more important why I’m doing it is because they’re not going to pay me $8 on the swap; they’re going to pay me $8.75 or $9. Typically our kick-out premiums have averaged between $0.60 and as much as $1.05 and a good average for you is $0.80 of pickup in value.

Now we’ve been doing this for years. In fact we’ve been doing it for almost six years. In all that time there have been four months that have kicked out any swap levels. We’ve collected hundreds of millions of dollars of additional premium by putting that put value in the swap, and we have been kicked out four times. One of those months there was just one trade that was kicked out.

Against revenue backdrop, it probably amounts to $400 million incremental revenue. We’ve been kicked out for less than $20 million of value lost. That puts us in a position when that kick-out happens that we have no trade on. The trade simply went away. We don’t owe anybody any money. A counterparty doesn’t owe us any money because that trade was as if it didn’t ever happen.

In trying to explain this hopefully I’ve not been too granular but it’s been something that’s been asked a lot.

Now I’m going to go into the second part of these kick-outs and say once they’re put on they don’t have to stay on forever. If we get to where we feel like there’s a good chance that the kick-outs might go away, then we restructure frequently and in fact I’ve taken and eliminated almost all of our November and December. It’s not incorporated in this presentation, but all of our November and December swaps have either been converted to cash value in one counterparty case or it’s been converted to a collar and the collar levels are approximately $7.50 by $9.

We’ve also done that for most all of our production that was previously hedged under kick-outs for April through October of 2009. Again, our feeling is that gas prices could go below there so there’s a lot of value remaining in those swaps even with the kick-out being potentially in play, and why not go and more protect ourselves at this point given the change in the market conditions.

You’ll see a dramatically changed hedge profile at the end of this quarter as a percentage of knockouts in those periods of time that we haven’t had time to incorporate. In fact I was doing some of these today, but when we roll out our earnings and operation call at the end of this month you’ll see a lot different profile.

Obviously bad things can happen. You can have counterparty failure. Not all of these people failed. Wachovia’s still in business. There have been risks though of people believing they’re going to fail, which of course precipitates just about the same effect in this market.

We can have collateral culls. I’ve told you how we’ve mitigated that. We went to the worst up-thrown cycle without any collateral cull at all.

You can have hedging where it’s ineffective, basis can change, the market can move away from you. If we hedge on NYMEX without locking down a Mid-Continent delivery point, you can have basis in the Mid-Continent go substantially away from the hedge so it might be ineffective.

And then of course the real bugaboo for most people, and we’ve gotten over it significantly, is the FAS 133 mark-to-market that can cause some pretty violent swings through your income statement and balance sheet.

Here’s kind of a graphic of our strategy. Going back several years we’ve had basically a dollar move-up per year in the natural gas price. We always felt like there was a natural boundary going back several years ago that was basically a ceiling of oil price parody, and on the low side was driven by what it took to be in the industry.

Of course costs have gone up, oil prices shot up so that disconnected, but you’ve still got what we call the 90% band where we think gas prices are most likely going to be. I’ve superimposed in the red on the right side of this chart what the curve looks like going forward. Of course it’s seasonal. At prices above the midpoint we begin to hedge and try and hedge into strength capturing these big spikes that periodically occur either due to weather, hurricanes, economic volatility, whatever it might be.

Just kind of what I’ve said here, what do we think about NYMEX going forward? We’re going to see it increasing perhaps at a lesser rate than it’s increased in the last few years brought on by more production, substantially more production from Chesapeake. We’re thinking about other things that can affect it and we’ve shown you some of those things on this slide.

Here’s our track record over time. There were two periods of time substantially third and fourth quarter of ’05 and recently in the second and third quarter of ’08 where we’ve actually had cash losses, meaning that we paid our counterparties more than they paid us. It was offset by eight quarters of substantial gain from the hedging program. Now going into the balance of 2008 and 2009 we think again the validity and soundness of our program will be showing a lot of green bars in the next 12 months on this slide.

Simply a recap of where we were a few days ago. Again I mentioned some of this has slid around compared to the five-year strip over there in the lime green. You can see the percentages hedged, the hedging levels. There are a few types of swaps in instruments that we don’t have on this slide; as I mentioned, the culls for example that are contained in the detailed packages in our outlook.

My last part and then Aubrey and I’ll open it up for questions. We formed something called Chesapeake Midstream Partners. This is a wholly-owned unrestricted subsidiary and we have transferred all of the assets that we have in the gathering business, which include a few plants, except for the assets that originally came out of C&R in Appalachia into this subsidiary. Notice the date on here, closing on 10/15, that’s this afternoon.

We are looking at CMP as a separate asset. We’re seeking funding. We talked to you about that throughout the spring. The markets got away from us on that and we were building value so fast that we had disagreements as to what the values might be. Today we are seeking a strategic partner or partners for parts of our business and we’re also in discussions with financial partners, all in addition to the capital that’s available through our line.

I’ll show you a little bit about how this business is set up. We’ve got 100% owner over here of a management company and then it flows down into the partnership where the assets are contained, and then these blue boxes are individual subsidiary subsidiaries that contain different parts of the assets in different areas.

Here’s a map showing some of the major gathering systems that we have in place. We’ve just begun in the Haynesville which is in the Northwest part of Louisiana, and that’s going to be a substantial amount of gathering to be done. The Barnett is our most mature asset. I think it’s set to throw off about $200 million of EBITDA alone in the 2009 period.

Substantially all of these situations are on a fixed fee basis so when Chesapeake operating wants to move an mcf through the pipeline, the pipeline gets paid a fixed fee. In the Barnett it’s around $0.65 plus some compression costs in fuel as we call it. We have similar arrangements in the Fayetteville, and we’ll have identical arrangements in Haynesville.

Then we’ve got a collection of assets across Oklahoma and into West Texas, all supporting our drilling operation.

Like our acreage we have a lot of flexibility in this. Capital expenditures could be borne by third parties. Frequently in the industry you go to a midstream gathering and transportation company in exchange for giving them throughput guarantees or an exchange for some type of financial guarantee. They build the system, operate it for you and you don’t spend the capital. We felt that if we were going to have to put up financial guarantees, we might as well put up the money and own it ourselves and collect that implied 15% or 20% rate of return.

Probably too much detail on here but this is 15 different gathering systems, 650 miles of pipe. This is some pretty big stuff. This sets out our very important and very large Barnett Shale system. We have about 200 miles of proposed pipe to finish the connection of this and then it really becomes a cash cow in the sense that we have built out the system to take care of the gas that’s going to come from all the drilling in the years ahead. As we come back and infill locations on pad drilling the pipeline’s already there, the compressors are sitting there so you just have all that gas moving through at fees for a long time.

Fayetteville, detailing the eight gathering systems we have there. Quite a few miles of pipe in it. The throughput in each one of these slides is scaled for you to see how important it is for us. Again, a little under 200 miles here of proposed pipe; big pipe too. Some of it’s 20” pipeline.

Mid-Continent system overive3w. Various pipelines; lots of miles of pipe; some we’ve bought, some we’ve acquired with properties that we’ve acquired. Most of it we have built particularly in the Fayetteville and Barnett. Haynesville, there’s nothing that’s been acquired; it’s all been built. For the gathering we require one piece of pipe there. Just again a little bit about it.

Here’s the Haynesville system, early stages of development. Only had $53 million a day going through there in September and we expect that to be increased to gross throughput to $77 million a day. About 400 miles surveyed for construction with only 27 miles proposed at this moment.

I’ll wrap up my part by just giving you a little bit more detail, a little bit more granularity on throughputs; EBITDA. The capital expenditure profile over here, you can see we’re ramping up pretty quickly but just like in the Barnett, when you reach that magical point where your cash flow is greater than your capital expenditures, your capital expenditures start to go down pretty rapidly because you’re doing just maintenance or hookup kinds of expenditures and most of the pipe is gone. Lots of information for you to dwell on later but I thought it is an important part of our business that we’ve never really focused on.

With that Aubrey and I are going to stand here and answer some questions.

Question-and-Answer Session

Aubrey K. McClendon

As a reminder to all of you, this is webcast and so we have three of us with microphones. If you have a question, we have about a full hour that we can dedicate towards answering your questions and we’ll be able to address many of those issues. So if you have a question, please wait for a mic and we’ll go from there.

Shannon Nome - Deutsche Bank

A question on the knockouts. Marc, you said you removed the knockouts for November and December. Presumably the cost to that was just taking a slightly lower price on the collars and swaps that replaced the old ones. Is that all there was to that?

Marcus C. Rowland

That’s all that there is to that. These are zero cost exchanges. We don’t pay money. We don’t collect money. We entered into a new collar arrangement and the kick-outs still have a pretty substantial amount of value. In one case we had $1.65 of mcf value per mcf hedged. Now we were going away from something that had about a $10 swap and a $6.50 kick-out or so and that still had $1.65 of value because we were so in the money on the $10 down to where the current price was. We are able to take that and get an above-market put floor at $7.50 and gas is down in the $6 range. In that particular case I think it was by $9.50 on the cull side.

Shannon Nome - Deutsche Bank

It’s on a slide that you had a $200+ million hedge loss in Q3. Was that largely oil? I thought you would have made money on your gas hedges in Q3.

Marcus C. Rowland

We forget sometimes but July contract went off at $13.45. That was most of it and there were certainly some oil hedges that contributed to that. Now September was down and actually was a profit but wasn’t enough to offset July.

Brian Singer - Goldman Sachs

You talked about as you’ve shown reining in your capital spending given market conditions. I wondered if things improve and we have a cold winter or financial markets come back, how aggressively should we expect that you may begin to acquire acreage again in greater detail and raise your capital program?

Aubrey K. McClendon

You mentioned acreage and I think the first thing we would do is probably restore rigs because what we’re doing right now is we’re driving down the unit cost of acreage. Without getting too specific it’s my goal that in places like the Haynesville and the Barnett we’ll in 60 to 90 days be at acreage values that may be half to a quarter of where they are today. That’s our goal going forward. I think we can do that.

In many ways we’re largely done with capturing what we set out to capture. We’re the only company with a Top Four position and a Top Two position in the Top Four shale plays.

To me if for some reason we did have that cold winter or more likely in my opinion that the credit crunch is going to drop the rig count a lot more aggressively than I think most people envision, we’ll ramp up drilling in plays where a lot of our cap ex is going to be carried.

For example, there’s no limit in our agreement with PXP in terms of how many rigs we can run. They have an incentive for us to drill. It gets their money in the ground faster.

In our arrangement with BP we can’t go above 40 rigs and I think we’re at 22 rigs today. We haven’t finished with our Marcellus program yet but I’m sure that our partner there will be interested in us drilling more aggressively there as well.

I would say that if we were to restore cap ex, it would much more likely go to the drilling side than on the leasehold side.

Brian Singer - Goldman Sachs

Is it still our goal to remain within our cash flow?

Aubrey K. McClendon

Yes. The company is in my opinion a fully mature company in the sense that we’ve gotten to the point where we’re the largest producer of gas. We’ve gone through an extraordinary time, probably the most extraordinary time in the last 30+ years in our business where we all of a sudden discovered a new way to conduct our business and that’s to find gas at a shale.

I think we arguably more than anybody else in the industry recognized this and we acted on it. It was our opinion that we couldn’t say we’ll pass on the Barnett, we’ll pass on the Woodford, we’ll pass on the Fayetteville, we won’t try and discover the Haynesville, and we’ll pass on the Marcellus and we’ll wait for the shale play that emerges in Iowa or Minnesota. They weren’t going to happen. We had a once-in-a-generation, once-in-a-lifetime opportunity to take advantage of a revolutionary discovery that has changed everything in our industry and has the possibility of changing a lot of things in our country going forward.

I think there’s never in the last 25 years of my life been a plan where you could really achieve some independence from imported oil. Today we really can begin to think about that because we can think about our energy problems from a sheet of paper that says natural gas abundance rather than natural gas shortage. We don’t foresee new shale plays developing that are going to require us to go out and go through the kind of leasehold buying binge that we had to go through.

I think what you’ll see by the end of this year is that when you add it all up we will have bought all this acreage and we will have sold off roughly a quarter on average and we will have captured all of our costs back from that acreage and still own 75% of it. I don’t think anybody else in the industry could come anywhere close to that and I don’t see how anybody could criticize that strategy from a financial perspective.

David Tameron - Wachovia Capital Markets LLC

Marc, a question for you. What kind of conversations are you having with your lenders right now as far as from the bank side? And second question, recognizing you have obviously executed on asset sales, if you don’t get those done in the fourth quarter, worst case scenario everything is pushed back a quarter or two, what’s the plan and where do you go in that scenario?

Aubrey K. McClendon

The first question is we hope they have money to meet their obligations to us I think is the conversation probably.

Marcus C. Rowland

As you can imagine in this time, we’ve had pretty extensive conversations with our lenders. All of them are at a different point in their maturity of working their own problems through. A couple of our lenders are actually being taken over by the national governments of various places or in Wachovia’s situation I guess being taken over it looks like by Wells Fargo.

We’ll have some continued concentration issues to work through but right now our plan is to leave the cash on the balance sheet, until this situation sorts itself out leave the facility drawn. Even though I recognize that there’s negative arbitrage in that, I’m not prepared to repay the facility and have banks for some reason not be around.

The facility has a long maturity and there really is no mechanism for a bank like Wachovia to be able to reduce their commitment to us. If Wells Fargo in combination with their commitment to us decides that they have too much, then their alternative is essentially to go out and sell down that commitment in the market and we’ve seen some banks do that. Generally our stuff is traded right at PAR or very slightly below. There are a few instances that have happened like that.

Other than having great relationships with what we consider to be a great lending group as evidenced by the fact in this time, in the last 30 days we were able to go out with RBS and Wells Fargo and attract new banking commitments for $460 million, I don’t think there’s very many companies that could have done that of any size or credit rating and we were able to do it. Our goal is to get to $500 million and the facility is actually documented to be able to expand or have an accordion feature up to $750 million.

We assume that once the current investment that the government’s making in the banks winds its way through and the markets stabilize that we’ll actually have a number of lenders that wanted to participate and their own credit requirements caused them not to be able to that after the first of the year we’ll have quite a few more commitments.

Your second question was, what if one or more of these asset sales don’t occur? Certainly that’s possible but I mentioned we’ve got six different things working.

We’re set to close on a package of properties next week. The buyer has money. We have closed on $460 million of lendable money through the bank facility. We have VPP working and we already have interest from two institutions that would suggest about a $200 million to $250 million interest. We have indications on our Southern Texas package from people again that either have fully funded commitments or have money on the balance sheet that they’re capable of funding.

We’ll cross the bridge if every one of these things falls out bed in the next two weeks, which I think is highly unlikely. But all of them don’t have to work by any means and we still have $1 billion of cash on the balance sheet right now.

Aubrey K. McClendon

I want to add, Marc’s referred to these two asset sales a couple of times. I want to clarify one thing. The Oklahoma asset sale, why are we selling assets in Oklahoma? This is leaseholds in a particular Woodford play that we don’t see the value of. The irony is we’re about to make an amount of money that will almost pay for the Gothic transaction that we did in 2001 where most of these assets came from. It’s leasehold below a certain depth and a play that we’re not all that crazy about at the end of the day. It’ll be a good investment for the buyer but for us it’s just not something that is big enough to move the needle.

With South Texas, why did we decide to sell South Texas? It’s simply a matter of asset maturity. We’ve owned those assets since 2003 and in some form or fashion built them over time and we feel like they’ve reached the point of maturity where we’re better off taking that cash and plowing it into Marcellus and the Haynesville or some of these other plays that we have.

Sometimes a few years ago I think we used to get criticized for not ever being willing to sell an asset and now we get criticized for being willing to sell an asset. I think you’re going to see continued portfolio positioning and profit maximization here over time if we find things in our warehouse that don’t have as much value to us as what it has to other people in the industry.

Unidentified Analyst

I don’t think you’re being criticized for selling assets. I think you guys are definitely at the forefront of doing some really good financial deals. But I think the problem certainly I have is when I look at your cap ex versus your operating cash flow, over the next couple years you have to perpetually sell this amount of assets in order to fund your program or your program has to get cut back. So that’s kind of where I’m at. I don’t understand how you’re going to do this year in and year out when we’re already looking at your asset sales that you’re doing already.

Aubrey K. McClendon

Imbedded in your question is the presumption that assets can’t be sold. Tens of billions of dollars are sold every year in this industry. I’m surprised that you find it hard to believe that there is not a ready market for the type and quality of assets that we have. We’ll make more money selling leaseholds than we ever will drilling wells. Again as I told you before that by the time this year is over we will have monetized an amount of assets that will exceed $10 billion. If you include the carries with that and have made an 80% profit margin on that, going forward I think absolutely I want the challenge and I want the organization to have the challenge to be able to find $1 billion of assets a year, $1.5 billion of assets a year that somebody else in the industry sees as having more than value than we see.

That’s just prudent portfolio management. I wouldn’t imagine that you intend at the end of next year to own every stock that you own today. Things change, other people will see value in your assets that you don’t see the value in. It’s the same thing here. I think you’re way underselling the financial capability of the industry and underselling our ability to identify assets that have ready asset value.

Tell me, can you point to one thing this year that we said we would do in terms of a sale and tell me where we failed to get it done. Not one. Every single thing we said we would do this year has happened and it’ll happen next year as well. The only thing that’s happened this year is the VCC market has turned out to be weak because things ended up having asset quality issues as I frankly lever dreamed of. Appreciate the concern but it’s not valid.

Brian Singer – Goldman, Sachs

You may also touch on the flexibility to not reinvest in new leaseholds.

Aubrey K. McClendon

Likewise again, there’s some presumption in your question that we have no capability of throttling back our business. We’ve already cut back $4.7 billion of expected cap ex just in the last month. If gas prices go to $5, if they go $4, if they go to $3, we’ll cut back. We are completely capable of laying [inaudible] and we will do that. We are completely capable of driving down a lease price. We’re completely capable of saying no to a lease.

But I just disagree that somehow an asset sale is a less trustworthy source of cash than a sale of assets through production every day. I just completely reject that and I don’t think our track record in the market at all reflects that either. It’s the most profitable thing we do.

Jeff A. Fisher

One other item I think about in that regard, I think the question would be more well understood if our production and our reserves were going down as a result of that. But on a net basis, even after these sales, production and reserve growth continues to be among the strongest in the industry. This just looks like a great rationalization program and I think the answer would be different if we were cannibalizing our operations to fund new activities, but in fact we’re not cannibalizing anything, we’re still aggressively growing on a net basis.

Aubrey K. McClendon

One more thing I’ve got to say, if you find a field and you know that what you found is going to be sellable at a big profit, then you financially should be incentivized to buy a few more leases than you really need if you know that you can sell those at $5 or $10 x. That’s what we’ve consistently done, that’s what we’re going to continue to do. Why? Because we have the capability to find thing, new plays, to put our land machine into motion to buy leases that other companies don’t have the ability to do.

What do they do? They turn around and recognize that and pay us for that expertise. I really believe that every lease we buy today has an embedded resale value of somewhere between 3 and 10 to 1. Unfortunately not every well that I drill today has seen anything close to that ability.

Sorry, I’m not trying to be too hard, but it’s obviously a real issue for me that people somehow believe that we don’t have any ability to sell assets or that it’s somehow wrong to sell assets. I think it’s absolutely the best part of the profit making machine that you have here. It’s just not visible yet. I don’t think the question would be so valid if you could see on our income statement at the end of the year we’ve made $10 billion selling assets and we’ve made $2 billion producing gas.

I guarantee you’d say why don’t you buy more leasehold and sell it to people who don’t know how to buy that leasehold. It’s just the conservative part of successful efforts that doesn’t allow us to do that.

Brian Singer – Goldman, Sachs

Could you guys talk about the volume impact from these sales and/or the cash flow impact that that production would have on your fourth quarter and 2009 numbers?

Aubrey K. McClendon

We put out a new outlook this morning and it’s all accounted for.

[Jeffery L. Mobley]

Brian, you’ll also see in Steve Dixon and Jeff Fisher’s presentation a projection on what our production would be pro forma for the asset sales. You’ll see the difference and if I recall, Jeff Fisher, tell me if I have the wrong number, but our 18% growth this year would have been 25% growth almost entirely through the drill bit had these assets not been sold and that goes all the way back to the first VPP in Appalachia December 31 of ’07.

Brian Singer – Goldman, Sachs

That 18% to 25% is what you’re selling?

Jeff A. Fisher

18% to 25% is what we have sold or will sell.

Aubrey K. McClendon

If we can find it too and sell it in five or six we think that’s a nice adjunct to our business, an 18% net growth is still plenty good.

Brian Singer – Goldman, Sachs

On your midstream capital in ’09, talking about $1 million to $1.2 million?

Aubrey K. McClendon

Right.

Brian Singer – Goldman, Sachs

How much of that can you put off onto third parties or how much of that is just gathering that you need to do internally within Chesapeake?

Aubrey K. McClendon

All of it is essentially gathering but that doesn’t mean it couldn’t be put off to a third party. As I mentioned, we’re in discussions with a few strategic players, well recognized household names that are in this business to come in and join us now that the asset has been matured to the level and participate with us and a lot of that will be covered either through the strategic partner or, in some instances, in Oklahoma particularly, we’ll just go away from third party decisions and actually just ratchet down the expenditure and rely on third party gatherers.

We may even sell some systems. This is another where, particularly in Oklahoma, I think parts of Western Oklahoma, there are numerous buyers for these systems that we interconnect with. No decision has been made on any specific system, but those are the kinds of things that we’re thinking about.

Michael Hall – Stifel Nicolaus

Clearly the market is dislocated from any looks at NAV. You walked through the NAV calcs and we all do the same and our comes out well above current market value. Implied within those NAVs are pretty high multiples at times. How should we as investors think about the multiples implied by NAVs and do you get any push back in the market from those implied multiples and when you’re out acquiring, I know you’re not acquiring producing assets any more, but at one time you were, how did you think about those multiples?

Where might those limits be in terms of the multiples relative to NAVs?

Aubrey K. McClendon

I’m not sure I fully understand the question.

Michael Hall – Stifel Nicolaus

Within a $100 per share price the implied EV to EBITDA multiples for example is going to be, call it 10 x whereas large cap E&P companies typically don’t trade at that kind of multiple. How do you buck that as a large cap company? As prior acquires are producing assets how did you think about those multiples?

Aubrey K. McClendon

We never bought anything at 10 times EBITDA and we haven’t really bought producing properties in any major way for years. What we’ve bought is the ingredient that go into finding gas and that’s land primarily and then blending it with science and blending it with people and that’s what happens here. Again, I’m not sure I fully appreciate the question. I’ll just say that clearly what is normal NAV, nothing is normal today, so it’s irrelevant.

But it doesn’t mean that over time as things return to some normalcy that you won’t see a return to those kind of valuations. Specifically if we can show from cash transactions that that value exists on the balance sheet, obviously nobody gives it value today and we sold 20% of our Haynesville position and left 80% on that particular valuation, made our Haynesville worth $13 billion. That’s more than our whole equity valuation today.

Clearly nobody says the Haynesville has any value. In fact today nobody says anything has any value outside of our crude reserves and on our crude reserves, they think gas prices are going to go $5. I don’t know how to respond other than we will continue to live within our cash resources and we’ll hunker down and continue to do what we do every day. Think about this, every year we’re capable of living within our cash resources, we’re capable of producing a TCF of gas and we’re capable of finding three TCFs of gas.

That’s the game plan, is to produce one and find two more on top of it and continue to grow and occasionally also do some selling at prices that have a huge embedded profit margin in them.

Jeff A. Fisher

One of the ways I think about answering that question is we’re not so interested in EBITDA multiples and as Aubrey said we haven’t bought any production on EBITDA or any other basis for a long time. I think about our VPP transactions and what value they create in the market and compare that to how we trade. That seems to be a pretty good indication of what the assets should be worth.

Generally speaking, in the last three that we’ve done you could take strip pricing and you could take a discount rate that was somewhere around 6.5% over a 10 year period of time and you can imply then an EBITDA multiple if you wanted to on that, but if we were to do that on our whole crude developed producing plays and just say okay, we’re going to sell and make a giant VPP and there was a theoretical buyer for that giant VPP, you end up in that $60 or $70 range on just PDP crude developed and crude undeveloped properties.

Aubrey K. McClendon

It’s a huge point. If the financial world was in good enough shape right now, we could go out and do a VPP on our whole PDP base which is, Jeff 7.5% TCF? 8% TCF, something like that?

Jeff A. Fisher

Right.

Aubrey K. McClendon

If the world were big enough and could handle it, we could do a $35 billion to $40 billion VPP on a company, have $20 billion in our pocket and have all of our upside.

Gil Yang – Citigroup

Two questions, maybe a quick one and a somewhat longer one. First question is you drew down your bank credit line $1.5 billion, but you’ve only got $1.1 billion on the balance sheet today. Could you talk about what happened to the $400 million in the last week or so? The second question is for the properties you expect to acquire over the next couple years, could you characterize what kinds of properties those would be in terms of would it just be filling in acreage around properties you currently have?

Aubrey, you said that there’s no new shales that you see on the horizon but what are you going to be buying for that spend?

Jeff A. Fisher

I’ll take the first part. Obviously at the end of the month, that’s our normal high point of cash flow. The way our business works, maybe you guys don’t all know this, but the $800 million or $900 million of revenues that we sell and collect which are all collected in the last few days of the month and typically the contract specifies that we’ll be paid if we sell gas to XYZ purchaser, we will get wired that money between the 24th and the 29th or 30th of the month.

Our cash flow cycle is one where we have a big peak of cash and then it goes out during the month followed by another big peak of cash and so forth.

Aubrey K. McClendon

That would be true of any company in the sector is going to be cash flow negative on 25 days. It’s just a fact of life in our business.

Jeff A. Fisher

Actually in our acreage acquisition budget, there were a couple of deals that closed in the first part of October that were funded. All of that’s been eradicated now to any degree so we don’t anticipate that there’s going to be that kind of symmetry going forward, if you will, for that question.

Aubrey K. McClendon

On the leasehold, our leasehold buying is a rounding error in Oklahoma, mid-Continent I don’t think we have any more than $175 million, maybe $200 million of maintenance leasehold acquisition in various mid-Continent plays. Everything has been targeted for the Haynesville, the Barnett and the Marcellus, and to a lesser extent, the Fayetteville. I think that’s the neat story is that we’re seeing that some of our competitors who have been after us hot and heavy in the last six months and the Haynesville has kind of gone away.

We’re going to see leasehold values in that play plummet. I would project, I would think that what you will see through the course of 2009 is that we’re likely to lower continued guidance going forward on leasehold cap ex, not because we’ve lost our appetite to buy an acre and turn it into a PDP reserve, but because the days of $20,000 and $25,000 an acre of values in the Barnett and Haynesville are gone and I think probably gone forever.

I hope that will allow us to save enormous amounts of money that we just haven’t yet reflected in our budget but I think will happen. Likewise, if what I think happens on the drill rig count, our drilling cap ex budget will go down as well just through unit cost savings and a lot of people are focused on why hasn’t the right count gone down that much? We’re headed down to 133 I think by the end of the year and we’re at 155 or something today.

We’ve agreed we’re cutting 22 rigs but they start laying down basically next week and then accelerate through the months of November and December. Remember the industry is operating today on decisions made in a $10 to $13 gas world and it takes six months or so for those decisions to play themselves out. Once they play themselves out, you’ll see the rig count melt away pretty quickly and I think see the gas market begin to reestablish some balance in 2009.

In the meantime, we’ll just ride it out and again refer back to Marc’s commentary that we could replace almost 100% of our production with $500 million of cap ex. I don’t think anybody else in the industry can say they can take 10% to 12% of their cash flow and replace reserves. Nobody can say that. We can say that in 2009. What we’ve been seeing somehow is one of the most vulnerable companies to a time of economic stress like this. In reality through our hedging and through our drilling carries, we’re actually in better shape than almost anybody to ride out a time like this.

Dan McSpirit – BMO Capital Markets

Your drilling carries are a pretty big part of the financial picture going forward for capital. Could you speak to, not so much the BP deal, but particularly the Plains deal as far as their ability to perform and what their obligations and your remedies are under that agreement?

Aubrey K. McClendon

Last time I checked, Plains has a $1 billion check coming to them for Oxeon December 1st and I’m confident that they are aware of their obligations to us next year and have that fully funded. Their situation is as ridiculous as ours in many respects. I think the company’s equity value is something like $1.6 billion and they’re getting ready to collect $1 billion in cash on December 1st leaving $600 million of equity value to be a proxy for value of 500 million barrels of crude reserves plus 20% of what’s going to be America’s probably second largest gas field, first largest for a while until the Marcellus overtakes it.

I’m completely confident that they’ve got the cash resources to meet their obligations to us and we don’t spend much time thinking about BP as well. I would say the Marcellus transaction will highly likely be with a company much bigger than we are.

Dan McSpirit – BMO Capital Markets

You’ve talked about your reserve replacement cost and amount of cap ex that you’re about 10%. For production in 2009 to stay flat with 2008 levels, how much capital would you have to invest to maintain a flat production rate in ’09 and then same thing into 2010?

Aubrey K. McClendon

Same answer.

Marcus C. Rowland

Yes, it’s going to be basically the same answer. The cash flow from the Haynesville and the Fayetteville is going to have a profile similar to what we’re producing today. If it’s slightly different, it’s not materially different.

Aubrey K. McClendon

Flat reserves and flat production are roughly equivalent.

Marcus C. Rowland

So then without the carry we would think about it as kind of a I guess about $2.5 billion. What is the number? I’m just trying to think about it. Are you talking about maintenance cap ex there?

Dan McSpirit – BMO Capital Markets

Yes, exactly.

Aubrey K. McClendon

The Haynesville carry next year, do you happen to have that off the top of your head? Let’s see, we use $1.7 billion over three years. I think next year’s carry is $550 million from Plains. Our Fayetteville carry was $800 million, we used some of that in ’08 and then we run out in November. So that’s probably close to a $500 million number as well. It’s $1 billion, that’s 17%, 18%, 19% of our cash flow. So next year you add that with the 12%.

I think the number is probably without the carries, it would be about 30% of our cash flow at an $8 price tag that we would use to maintain production and maintain reserve value.

Marcus C. Rowland

Thinking about it in a slightly different way if we produce about a trillion cubic feet, 975, our drill bit cost today is around $2 and you increase that for acreage and all the other stuff that goes into it. I’m just going to be put a big number and say that it becomes $2.5 billion to replace a trillion cubic feet of production and that’s $2.5 billion out of $6 billion of cash flow approximately.

[Jeffery L. Mobley]

With that math, though, recognize that Marc was quoting your average F&E for the whole company and if all you’re trying to do is replace production, i.e., maintenance cap ex, you’re going to drill your best wells and then be lower [inaudible].

Marcus C. Rowland

That was a real scoping estimate, not a detail of this play, this play.

Thomas Nowack – Bank of America

Just a question on the secured hedging facility, I think you need to maintain a 1.3 times collateral value relative to that hedge value.

Marcus C. Rowland

Correct.

Thomas Nowack – Bank of America

So a couple questions, where are you now on that value? What has to happen to commodity prices to get you below that? The third question is, do you have the ability to post assets that are securing the credit facility as collateral for the secured hedging facility?

Marcus C. Rowland

I know some of these numbers right off because we happened to have a multi-party secured hedging facility conference this morning where we invited all of the many banks that want to come in and enter into secured hedging facilities with us. At 9:30 the secured hedging collateral arrangement was 2.35 to 1 against the existing obligations at that time which were about $500 million and that was for not the amount outstanding but for the total amount of the facility available to us.

Remember it’s right way risk in the sense that while the credit required is 1.3 times it’s based on strip pricing of the underlying reserves. So in the case at June 30th when prices went to $13 and the strip was very elevated we take the reserve report and we run the strip pricing of $13 through and your collateral value is many times what it would be in a normalized pricing environment. So the right way risk part of that is as your obligation grows because you’ve hedged and values have moved above that, then your collateral grows substantially as well.

To answer that question, in most normalized situations we have not seen any ability to lose collateral value at a time when we owe a bunch of money, it just doesn’t work that way. We do have the ability though to enter into either assignment of additional unpledged reserves and we have a substantial billions of dollars of those or we have the capability of assigning para-pursue under our bank collateral facility to satisfy any obligations we would have. Was there one more part of that question that I missed or did I get it all?

Thomas Nowack – Bank of America

This may be tough, but what would have to happen for commodity prices to drop below the 1.3 times? Is that possible?

Marcus C. Rowland

I don’t think they could because if we’re hedged and prices drop, then the amount that we owe anybody is zero. So 1.3 times of a not number is positive coverage. You can’t have prices dropping real low so your collateral value is low and owe anybody any money.

Aubrey K. McClendon

Just to be clear, the facility would be in a place for us to do hedges and the value of the hedges would go up as collateral values goes down and the whole point for doing this in the first place was for our lenders to have right way risk so that actually the concern was as prices went up and our hedges went out of the money and we would end up owing people like at June 30th $6.5 billion. We didn’t want to be in a position to be scrambling to make market call.

I didn’t have the ability to do that same kind of facility or I’d have done it. Any rate, that way we really cannot get out of balance there because of the interaction between the two ROAs working in tandem.

Shannon Nome – Deutsche Bank

On the maintenance cap ex question, are there any obligations next year outside of the upstream drilling that would be required to keep production flat in terms of infrastructure or any leasehold obligations that we should add to that maintenance cap ex? The second question, while you’re thinking, would be on your cash resource plan just to clarify, when you show drilling outlays is that grossed up for the carries and then you show the carries in your resources category or is that all net of the carries, your drilling outlay?

Marcus C. Rowland

Net cash, net cash out the door. I guess, Shannon, there would be an element of maintenance cap ex in the form of gathering systems but again if we wanted to get out of the gathering business tomorrow, there are lots of people who would love to be build gathering systems in the nation’s best gas plays. We don’t like to wait on people and we don’t like the profit margins that sometimes we get charged by midstreamers. So we prefer to do it ourselves, size the pipe right, get the wells hooked up timely and it’s same concept as on using our own drilling rigs.

It’s just an integrated operation works a lot more smoothly. I guess you could you would have to add some cap ex to tie in Haynesville wells or Barnett wells, but maybe that increases our maintenance cap ex from 12% to 18%. It’s not much money at the end of the day. The final question or embedded in the first part of your question, Shannon, was requirements on acreage and we do not have any substantial acreage commitments that would require cap ex and in fact in this environment, there may even be some leases that you could renew for so much less money that you would choose not to even drill them.

Aubrey K. McClendon

You would maybe get better royalties and there’s all kinds of things in play today that have not been in play the last couple of years.

Kelly Cringer – Banc of America Securities

A couple questions, first on the liquidity front, given the current market environment we’re in, what’s the liquidity that you’ll feel comfortable with once you get all the assets sold?

Aubrey K. McClendon

The answer is more or never enough. Are you talking about for all through ’09?

Kelly Cringer – Banc of America Securities

Yes.

Aubrey K. McClendon

Our plan we end the year at over $3 billion and we build cash in 2009 as Marc said until we can trust banks. There’s no reason to pay banks back and I think you’ll just see cash build on the balance sheet. We could repay debt, we could tend different notes, we could buy back stock. There’s lot of things that we could do.

Marcus C. Rowland

But just generally speaking, this size of company we want to be running typically $1 billion of availability for cash. I think we’re going to run a lot more than that.

Aubrey K. McClendon

A lot more than that. We’re coming through this unique period of time in our history and the industry’s history where we had this ability to lock down some unique positions and now from here on out, it’s to take advantage of those unique assets. So you’re going to see much reduced capital spending, why you’re going to see much greater cash resources brought into the company, both from rising production over time at 15% to 18% to 20% per year plus the occasional asset sale that will add to the cash on hand as well.

Kelly Cringer – Banc of America Securities

What’s a typical working capital swing or cycle on a monthly basis so that cash peaks at the end of the month then draws down throughout the month? But given the size of the company that you guys have, what’s the swings that you’ll see in a month?

Marcus C. Rowland

It’s basically whatever your oil and gas revenues are. You’re going to collect that one time during the month and you go through the cycle so it’s going to be $600 million to $700 million at today’s pricing levels.

Unidentified Analyst

Aubrey and Marc just in view of your outlook on natural gas, what is your view on natural gas swaps and in their use going forward? Are you going to take a hiatus here now that you’ve, excuse me knock out provisions rather, are you going to take a hiatus here and wait for the supply/demand balance to be restored in the gas markets or what’s your plan going forward there?

Aubrey K. McClendon

I think it’s to do what we’ve done historically which is if you remember that graph that Marc showed, every time we lose money on hedges you tend to make money for the next six to eight quarters and then you get a chance to do it all over again. Remember we lose money when there’s a gas price spike so that happened in the first and second quarter of this year. We lost money on hedges. We’re going to make money in the second half of ’08 and in ’09 and probably ’10.

Then that natural cycle plays itself out and we’re going to get another chance to hedge I think sometime later in ’09, maybe we have to wait until early 2010 but we’ll get it. We can have Haynesville declines that first year at 81%. If you have Barnett declines at 70%. Every shale play in America is going to be a first year, probable exception is the Marcellus which is experiencing much lower declines but the other big shale plays right now all have 70% plus decline curves. Our conventional wells decline at that.

50% of the production in America is from wells that are less than two years old. This financial situation is going to take an enormous toll on the rig count. I’m pretty confident that it’ll be a tough ’09. We’ll be in competitively better shape than most anybody else because of all our drilling carries and because of our hedges and we’ll sit there and mind our business and people will look back one day now just like they did in 1999 and 2000 and say I could have bought that stock at 1.5 times cash flow and they didn’t owe any money for four years and they were cash positive and they’ve got the best assets in America.

You know what was I thinking. And I think that’s what you’re going to find in the next couple of years as markets recover and as we get a chance through the recovery of supply/demand balance to go out and hedge and call it 2010 for the next couple of years. I’d love to hedge for five or 10 years but typically you hedge into a back redated price deck which isn’t particularly fun and we’ve just gotten to a size where actually we’ve done a better job than our counterparties have in terms of growing and the counterparties out there are just not big enough today to handle more than a year and a half or two years of Chesapeake hedging.

I wish it were different. Again I’d love to go do a massive company’s EPP and put $20 billion in our pockets and own everything.

Kelly Cringer – Banc of America Securities

One other question, with regard to asset sales, have you seen a reluctance due to the credit crunch of some of these companies wanting to close deals? You indicated that things were moving positively but surely on the international front particularly there’s been some reluctance to move forward?

Aubrey K. McClendon

I don’t probably keep up with the international as much as maybe I could or should, but I’m not aware of any and I’ll just assure that the people that we’re in negotiations with have financial capabilities that are exceptional. We do not see that issue and again maybe it’s hard to communicate this but there are a lot of people in this industry who don’t like to buy gas reserves when gas prices are $10 or $11.

There’s a lot of companies set up that particularly on the private side, they just collect cash when it’s $10, $11, $12 and then they wait for the decline. Our South Texas buyer may be a big name company, it may be a name that you’ve never heard of and some guys out there writing close to a $1 billion check and maybe today 40% of that’s equity or 50% of that’s equity rather than 10% or 20% before.

There is always a silver lining to the cloud and right now a whole segment of the industry is mobilized and looking for stuff to buy and our view is that could we have sold South Texas for more six months ago? Sure but is the cash that we’re going to get today more valuable to us today than it was six months ago? Absolutely.

Unidentified Analyst

Could you hang a couple of numbers on your assumptions behind late ’09 or 2010 rebalancing in the gas market? What kind of decline in rig count?

Aubrey K. McClendon

I think I said at our last conference call I thought that 200 to 400 rigs would go down. I don’t think most people share that assessment but that was two weeks earlier, or three weeks earlier in the credit crunch. That’s still where I think goes. We have a 2,000 rig count that, the whole industry is unprofitable today. If you weren’t hedged, if you aren’t selling first of the month index gas in Oklahoma today, you’re selling gas for $2.50. On Arkansas you’re selling gas for $3 and in Barnett you’re selling it for about $3.

The industry is hemorrhaging cash today on a daily basis and I can assure that that is not sustainable and it just takes a while to finish rigs and get out of rig commitments and all that. I think you’re going to see a real melt away of the rig count starting in November when you’re going to see our 20 some odd rigs go through. That’s 1% of the rig count right there. I think you have to get back into the, I don’t know if it’s 1,500 or 1,600 or 1,700 rigs, but my guess is you have to get back there.

Remember one thing, the dark side of technology is higher decline rates and you do have to have more rigs today than you did three years ago or five years ago for two reasons. One, remember we’re in this gas price problem because production is up five BCF a day from two years ago. The more you build that and the more you build it with short reserve life wells, the more rigs you have to have to sustain it.

Many of you all have much sophisticated models than I do but my sense is that you’ve got a 200 to 400 rig break that you’d see a real balancing of the market.

Unidentified Analyst

In light of some of those low prices you mentioned in certain regions, can you discuss the risk about giving your full cost accounting for ceiling test write downs, what the look back provision allows and how much time you have to recalculate those calculations? What second order of the consequences might be for where those assets may be collateralized or what they might be supporting?

Marcus C. Rowland

Full cost, to remind everybody, is taken at a snapshot in time and you use the prices in effect on the last day of the reporting period which is March, June, September and December for us and you, on an unescalated basis, discount it back at 10%. You take the present value and compare that to your cost pool including future development cost. If it’s less you have a ceiling test impairment and you have until the time that you report your earnings to look back and if prices have recovered before you report, then basically you footnote it.

If it’s recovered enough, you just say I would have taken a loss of X but prices have recovered before I’ve reported and so I don’t have to take a loss. Now keep in mind with respect to our full cost that our costs are actually coming down pretty significantly because of the nature of the transactions that Aubrey mentioned, not going through our income statement. Well it has to go through somewhere and it goes into the credit of the full cost pool.

When we sold acreage to PXP or when we sold acreage to BP either in the first transaction in the Woodford or the second transaction in the Fayetteville, we didn’t record an income statement profit but what we did was all those dollars went over and reduced our full cost pool. I don’t have the exact number today on the top of my head but it’s still well below where our prices are today if we were to be forced to evaluate full cost. Of course we’re not going to evaluate it until December 31st now.

[Jeffery L. Mobley]

Calculations on NIMEX, we don’t take our COMO prices and apply that across the whole company.

Marcus C. Rowland

You take your prices basis adjusted that you’re getting in everywhere. In Appalachia with PTU adjustments we’re still selling gas for $8 or whatever there, $9 I don’t know what the number is and that’s the price you would use in that area. With respect to financial covenants there are no covenants in any of our banks or indentures that are in any way triggered off of having a full cost ceiling loss. In fact our bank facilities specifically carves out mark-to-market changes including non-cash impairment charges out of any calculation.

We’ve been through full cost ceiling losses or challenges before and there is no effect on anything that we’ve pledged for collateral, no effect on any of our bank or indenture arrangements.

Unidentified Analyst

You mentioned that you made more money selling leasehold than actually drilling wells right now and you also mentioned Barnett and Haynesville acreage prices coming down. At what price per acre does that relationship not hold true anymore if the price per acre is dropping?

Aubrey K. McClendon

There’s two things, it depends on whether or not your sales price comes down further than your cost basis. If we were planning to let’s say bring somebody in to make an area up, let’s say Sahara, an area where we have almost 1 million acres in Northwest Oklahoma, the answer to your question is highly dependent on what somebody would come in and pay us for this at 25% interest and it’s a big historical position. My thinking is that given the relative stability of long term asset values in the industry compared to this short term wild swings that the value that somebody would pay you for a perpetually HPB million acre position in Northwest Oklahoma would not be dependent on what was happening at the field level in terms of leases.

If we can go out there today and cut our lease bonuses in half, for example, then actually there’d be a scenario where we could actually improve our profit margins from some leasehold sales. And there will always be things like this transaction that we talked about in the Anadarko Basin where we’re selling a couple hundred million dollars of leasehold. Again for the buyer it’s going to be a great trade for them, it puts them in a hot play. But our basis is zero.

When you own 15 million acres you’ve got a lot of stuff laying around that people are always calling you about, not that we don’t know we own it, it’s just that you’d be surprised at how little our cost basis is in all this kind of non-shale stuff. One final thing, the reason we haven’t brought somebody into the Barnett is simply we’re so far into the development of the Barnett and that it’s so urban intensive, our view that to bring a big worldwide international oil company into a play that subjected them to urban drilling risk which is a nonstarter.

If anybody is curious out there why it’s the only shale play that we’ve got underway that we don’t intend to bring a partner in for, that’s the reason. I think we’ve got about 10 minutes unless anybody, if you all are exhausted, we’ll give you break. If you’ve got some more, we’ll stay here 10 more minutes.

Marcus C. Rowland

Also remind you that we’ll be around for questions and answers personally, individually through the reception this evening. At dinner also.

Analyst Mike Harris

Just a couple of quick questions on the hedging, the April through October knock outs that you took out for ’09, is that collar similar to the November-December collar, 750 to 950?

Marcus C. Rowland

I think I did one today at seven and a quarter by $9 and we did one at 750 by $8.75. That is for virtually all of the volumes that we had previously had in kick outs for that time period.

Analyst Mike Harris

For ’09 what time percentage of remaining swaps with kick outs in them would you think we have today? Have you eliminated a third, a quarter?

Marcus C. Rowland

We’ve eliminated more than half because we only have them remaining now in five months and it was about 35% as I recall of our hedge position. It’s got to be down to 15% off the top. Actually I’m waiting for the head schedule to be delivered and I’ll give the exact number tonight because I wanted them to rerun it after the trades we did today so I could be prepared. It just hasn’t been delivered yet.

Aubrey K. McClendon

Keep in mind that also when we do these, Mike, we also adjust them per month. It’s not 6.25 across the whole strip so it might be 5.75 in April but may be 6.50 in December of January. We try to accommodate the normal rhythms of where we think the low price events can really occur.

Marcus C. Rowland

All of our, for that matter, swaps or our kick outs are fit to curve and when we talk about a 6.25 kick out that has a range in it I think from 5.70 up to 6.75 depending on the month.

Mike Harris

Then when the market comes back to where you think it makes sense to start hedging again, is the intention to continue to use these kick out provisions?

Marcus C. Rowland

I think that we will use them. We have in the most recent past used a lot more straight swaps in this last run up and I think it’ll be just fine. We’ll see all of these that we previously had on convert into very nice collar positions and will have been a vindication of why we did it which was to create value from the volatility. We couldn’t go out without the value that we have embedded in those kick outs and get that same put call skew today. It’s above the market.

Aubrey K. McClendon

Said another way, it’s also a 20 to 1 investment. We’ve lost $18 million or given up $18 million and gained over $400 million. Nothing in this business is non-risk but 21 or 22 to 1 return is pretty good and to monetize volatility is a pretty good thing. When we’ve sold a hundred million dollars of oil calls and we were selling $150, $125 oil calls all the way down.

Mike Harris

But the ones that you’re changing into the cost of those collars effectively though those would go into the lost category, right? Because the option that you sold at a much higher price is more so that’s going against you?

Aubrey K. McClendon

We probably wouldn’t have hedged at all, that’s the point. There are a lot of times on the curve when you look at it and you say, I really don’t want to hedge $8.50 gas but I’ve hedged $9.25 gas but I don’t have $9.25 gas. I can get $9.25 gas by taking the risk that gas prices on one day of one month are going to close at or below $5.75 or ^.00 or $6.25. Remember you’ve got math at work for you here as well.

It’s just not what happens during the month, it’s got to happen on one afternoon of one day a month and statistically it’s a pretty good bet without regard to the better bet which is to bet on the fundamentals that over a period of time you’re not going to kick out altogether because you’re so far below, the industries break even. We kicked over two months in a row.

[Jeffery L. Mobley]

One time, August and September. Last year about seven.

Aubrey K. McClendon

Again not all of them. So yes, it can happen once.

Unidentified Analyst

[Inaudible] cash basis, how much?

Marcus C. Rowland

We have a substantial amount of basis hedged, it’s detailed in our outlook as to where the basis is. Actually it’s probably one of the most profitable trades the company has ever done going back to 2002. We were able to enter into basis swaps going all the way out through 2010 and it was in our view at the time a no brainer because Mid-Continent basis was selling for as little as $0.14 and it had never been lower than that.

So it was a zero cost insurance policy and I remember January of 2003 rolling around and we collected our first check for that and we’ve been collecting ever since then and in fact in the month just passed, one counterparty paid us $28 million of basis profit on our basis trade.

Aubrey K. McClendon

Aren’t we up totally like $1 billion?

Marcus C. Rowland

Including mark-to-market that trade is equivalent to about 1 billion of [inaudible].

Aubrey K. McClendon

And the reason we made it, it happened after we got back from the tour of the Rocky Mountains and I said there’s a lot of gas up there. I don’t think they’ll make much money producing it but it’s going to have an impact on our prices here in the Mid-Continent and so we started work. Where we made a mistake is when you’ve been hedging it for a year or two at $0.14, $0.15, $0.18, $0.20 an NCF and then it goes to $0.40 or $0.50 you say I don’t know if I should do that. Of course today we should have hedged anything up to probably $1.

Also the market’s a little thin and when the Enrons of the world went down it took a big whack out of the basis market, it’s tougher.

Marcus C. Rowland

There’s really no natural counterparty on basis. You have electricity transactions that provide spots of liquidity but there’s not a guy sitting around saying I want to be short basis in Mid-Continent.

[Jeffery L. Mobley]

That about wraps up the time that we’ve allotted for this session. Appreciate all the questions, they’re very good ones. We hope that answered many of the questions and concerns that you might have had prior to today.

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Source: Chesapeake Energy Corporation Q3 2008 Business Update Call Transcript
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