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Chesapeake Energy Corporation (NYSE:CHK)

Q3 2007 Earnings Call

November 7, 2007 9:00 am ET

Executives

Jeffrey L. Mobley - Senior Vice President, Investor Relations

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

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

Analysts

Dave Kessler - Simmons & Company

Brian Singer - Goldman Sachs

David  Heikkinen - Tudor, Pickering & Co.

Scott Hanold - RBC Capital Markets

Eric Kalamaras - Wachovia Capital Markets

Jeff Hayden - Pritchard Capital Partners

Gil Yang - Citigroup

Ellen Hannan - Bear Stearns

Michael Ange - TIAF Crest

Scott Palmer - Janney Montgomery Scott

David Tameron - Wachovia Capital Markets

Joe Allman - JP Morgan

Monica Verma - Gilford Securities

Kent Green - Boston American Management

Operator

Good day, ladies and gentlemen and welcome to the third quarter 2007 Chesapeake Energy Corporation earnings conference call. My name is Jackie and I will be your operator for today’s call. (Operator Instructions) I would now like to turn the presentation over to your host for today’s conference, Mr. Jeff Mobley, Senior Vice President of Investor Relations and Research Analysts. You may proceed.

Jeffrey L. Mobley

Good morning and thank you for joining Chesapeake's 2007 third quarter conference call. Hopefully you’ve had a chance to review our press release and updated investor presentation posted to our website yesterday afternoon.

Before I turn the call over to Aubrey and Marc, I need to provide you with a disclosure concerning forward-looking statements that Chesapeake's management will make during the course of this call. The statements that describe our beliefs, goals, expectations, projections, or assumptions are considered forward-looking. Please note that the company’s actual results may differ from those contained in such forward-looking statements. Additional information concerning these statements is available in the company’s SEC filings.

In addition, I would also like to point out that during the course of our discussion this morning, we will mention terms such as operating cash flow and EBITDA, and we will also mention items that we believe are typically excluded from analyst estimates. These are all non-GAAP financial measures.

Reconciliations to the comparable GAAP measures can be found on pages 22 through 25 of our press release issued yesterday afternoon. While these are not GAAP financial measures, the financial performance -- GAAP measures of financial performance, we believe they are common and useful tools in evaluating the company’s overall performance.

Our prepared comments this morning should last about 15 minutes and then we’ll move to Q&A. Aubrey.

Aubrey K. McClendon

Thanks, Jeff and good morning to each of you. I would like to begin by introducing the other members of our management team who are on the call today: Marc Rowland, our CFO; Steve Dixon, our COO; Mark Lester, our Senior VP of Exploration; and Jeff Mobley, our Senior VP of Investor Relations and Research are all with us here this morning.

The third quarter of 2007 marks Chesapeake's 25th consecutive quarter of sequential production growth and I believe it is also the 23rd consecutive quarter in which we have raised production guidance. And it just might have been our best operational quarter ever. Not only was our production up 27% on a year-over-year basis but it was also up 8% on a sequential basis. That’s a compound annual growth rate of 34%.

In fact, if you combine last quarter’s 9% sequential growth with this quarter’s 8%, you can see the combined half-year growth number is 17 --

Operator

Please stand by while we fix the connection here, ladies and gentlemen.

Good day, ladies and gentlemen. Thank you for your patience. Your conference call will resume now. Jeff, you may begin.

Aubrey K. McClendon

Good morning. This is Aubrey McClendon again. Sorry for the interruption. We do not know what the technical malfunction was. I’m going to start again with the third quarter of 2007 marks Chesapeake's 25th consecutive quarter of sequential production growth and I believe it is the 23rd consecutive quarter in which we have raised future production guidance. It might just have been our best operational quarter ever. Not only was our production up 27% on a year-over-year basis, it was also up 8% on a sequential basis. That’s a compound annual growth rate of 34%. In fact, if you combine last quarter’s 9% sequential growth with this quarter’s 8%, you can see that our half-year growth number is 17%.

Remember please that we voluntarily curtailed 3 bcfe of our production this quarter. Had we not, our third quarter sequential production growth would have been an astonishing 11%. It should be crystal clear to all of our investors that Chesapeake's growth is accelerating, even from an ever larger base of production. Perhaps this is somewhat surprising to those who have been asking us for years when the law of large numbers would catch up with Chesapeake. We see our growth this year as an obvious confirmation of the benefits of our large scale, our distinctive technological abilities and our unmatched leasehold in three seismic inventories.

In addition to impressive percentage growth numbers, our absolute growth numbers are remarkable as well. Our third quarter year-over-year production was up 429 million Mcfe per day. This means that in the past year, we have increased our production by an amount that if it were a standalone company, would be the 17th largest U.S. natural gas producer. Meanwhile, our sequential production growth was 158 million per day and without curtailments, it would have been 191 million per day. At Chesapeake, we are creating through the drillbit the equivalent of a good-sized U.S. natural gas producer every single quarter.

As a result of our production performance, we have increased our growth expectations for future years. We are now anticipating 21% to 23% production growth in 2007, 18% to 22% in 2008, and we have reaffirmed our 2009 production forecast of 12% to 16%. However, please note that will be from a significantly higher base of production.

In addition, our crude reserve growth is closely tracking the pace of our production growth. Accordingly, we have also increased our proved reserve expectations to 11 tcfe by year-end 2007 and 12.5 to 13 tcfe by year-end 2008, and 14 to 15 tcfe by year-end 2009.

What makes these growth numbers even more remarkable is that we now can achieve them while also being cash flow positive and without taking on any significant commodity price or operational risks.

In addition to our operational plan working almost perfectly, drilling and lease operating costs are coming down, as we hope you noticed in our reduced DD&A and LOE cost numbers per unit of production in the third quarter. We are hopeful these favorable cost trends will continue in the quarters ahead.

All of our important areas of production reserve growth are performing as expected or better and we are also developing multiple new conventional and unconventional play concepts in several new and existing areas. We will tell you more about these as we confirm their viability and acquire all of the available leaseholds in the prospective areas.

Moving on to our most important existing plays, I would like to highlight first of all the Barnett. In this play, Chesapeake's net production increased by an incredible 43% on a sequential basis. That means during the quarter, we added 100 million cubic feet per day of net production. On a gross basis, this would have been about 160 million per day, so we are responsible for six-tenths of a bcf of increased gas production in the U.S. on an annualized basis in just one company, in just one play, using just 25% of our cash flow.

We have maintained for several years that by being willing to take on the challenges of leasing and drilling in urban Tarrant County, Texas, we could create a distinctive Barnett franchise for Chesapeake. We have done just that, and believe we are barely beginning to scratch the surface of our capabilities in the Barnett.

One more thing; as our drilling shifts northward into Tarrant County from Johnson County, our well results are getting better and better, and so this quarter we increased our projected EURs, or estimated ultimate recovery, to 2.65 bcfe per well from our previous expectations of 2.45 bcfe per well.

So to recap for Barnett, we have 235,000 net acres of leaseholds; we have booked 1.8 tcfe approved reserves; we have unbooked Barnett reserves of 4.4 tcfe; and believe we can increase our leasehold position by 40,000 net acres per year for at least the next few years. By doing so, we believe we can add a backlog of 600 wells per year, which should fully offset the 600 wells per year we plan to drill.

So for at least the next five years, we have built the equivalent of a perpetual motion machine in the Barnett.

In the Fayetteville, our production growth during the past three months was up by a smooth running 100%. We have really hit our stride in this play. Our well results keep getting better. Our costs keep coming down and we have increased our targeted EURs by 25% to 2.0 bcfe from 1.6 bcfe previously.

Our leasehold inventory continues to grow as well. We are now up to 420,000 net acres of core Fayetteville leaseholds. On this leasehold, we have 60 million per day of production, have booked just over 200 bcfe approved reserves, and have at least 5 tcfe of risked unproved reserves.

We are also continuing to consolidate our lease holdings in this play and believe we will exceed 500,000 net acres here within the next year.

The final play I will highlight is the Deep Bossier trend in East Texas. The value of this play was dramatically confirmed this week when EnCana paid $2.5 billion to acquire privately held Leor Energy. Leor had 70 million per day of production in the trend and 55,000 or so net acres of leasehold.

While we do not yet have any Deep Bossier production of our own, we are completing two promising wells now. We have three rigs drilling new wells and we have 380,000 net prospective Bossier acres.

If you want to drill big gas wells onshore in America today -- wells that can make more than 30 million per day -- we believe there are only three places to go: the deep Anadarko Basin in Western Oklahoma, the Deep Haley area in West Texas, and the Deep Bossier trend in East Texas. Chesapeake has a premier leasehold position in all three areas and so we believe our big gas well exposure is unique in the industry.

Finally, Chesapeake's leasehold and seismic inventories in other areas of the company continue to grow. We now own a record 23 tcfe of risked, unproved reserves that nicely complements our 11 tcfe of proved reserves. These large risked unproved reserves give Chesapeake great forward growth visibility in both production and proved reserves for many years ahead.

It’s a very nice position to be in. We are an increasingly long energy company in an increasingly short energy world.

In summary, the benefits of Chesapeake's strategic shift from resource capture to resource conversion that began in 2006 are noticeably accelerating. Chesapeake's production and reserve growth is tops in our peer group. We will be cash flow positive indefinitely. Many of our unit costs are on the decline. Our share count and debt levels are static or declining, and we have $100 oil on the horizon. Surely higher natural gas prices are not far behind.

Imagine the impact of all these favorable operating and financial trends on Chesapeake's stock market valuation if, by year-end 2009, Chesapeake is producing 40% more gas and oil than we are today and we have 40% more proved reserves than we have today.

Given our present enterprise value of $33 billion, this would mean we can deliver to shareholders at least $13 billion of additional market equity value. That would be roughly $25 per share in two years, or more than a 60% potential increase.

To deliver that potential, we just have to keep executing our plan. There are no leaps of faith or issuances of securities needed to get from here to there.

I’ll now turn the call over to Marc for his commentary.

Marcus C. Rowland

Thanks, Aubrey and good morning, everyone. A few comments this morning relating to cost trends, CapEx guidance, and updates related to our various financing initiatives and then we’ll be off to Q&A.

On the cost side of our business, drilling rigs continue to come down. Using a 1,000 horsepower rig as a standard measure, new contracts today are in the $15,000 to $17,000 per day range, down from three months ago by $500 to $750 per day, and down from the beginning of the year fully 10% to 15% when they ranged from $17,500 to $21,500.

Sahara footage rates on the shallow river rigs are down slightly. Pressure pumping is down as well. Cementing costs, we’ve seen recent drops from 2% to 5%. The only exception in that would be the Fayetteville, where we’re seeing some increased competition and fewer services at this moment. Logging and casing prices are flat to down 5% or 6% so far this year.

On a separate note, I want to point out that the average number of days in areas where we have a number of wells for comparison over a period of time are down also. For example, both the Fayetteville and Colony Washes horizontal wells, the average days are down there per well about 10% for third quarter compared to second quarter, going from 27 days on average to 24 days. Haley, we’re dropping the day count there by about 5% as well. The Barnett has seen some efficiencies this year but in this last quarter was essentially flat.

With regard to our outlook, you may have noted that we have expanded our guidance to include approximately $600 million per year of acquisitions. This has previously been leasehold only and is now leasehold and property acquisitions.

We’ve seen at least one analyst comment this morning where they made the mistake of calling this an increase in CapEx. Of course, that is wrong, as we have been spending much more than that annually without guiding to any specific target. Our new outlook is completely consistent with the plans we laid out in September and not at all a change except to say we generally expect to do much less in acquisitions.

I would point you to page 9 of our November presentation, which is posted on our website, where we have a complete analysis of the cash in and out forecast for 2008 and now 2009.

A quick update on various financing initiatives. Of course, in the done column, successfully completed the rig and natural compression sale and leaseback. I would point out the compression facilities also provide for future funding. We have future orders for a couple hundred million to meet our expected build-out needs in compression in 2008/2009. We also have a new compression fabrication facility in Oklahoma City that we have purchased to enhance our cost savings and efficiency in this area.

Also on the done column, our new $3 billion debt facility both expands the amount of liquidity available to the company and extends the maturity to 2012.

In the works today, our Appalachian asset monetization is proceeding very well. We’ve had some very strong interest from a number of very large financial players. The anticipated proceeds from our first 35% working interest initiative has been so attractive it’s caused us to increase the expected size of that deal and now we are looking for proceeds in excess of $1 billion that we expect to wrap up by the end of this year.

Something new that we haven’t really mentioned before is the monetization of our non-core E&P assets in the Rocky Mountains and some sale of Woodford Shale. Both are anticipated to close by the first quarter of 2008 at the latest and we expect proceeds somewhere in the neighborhood of $300 million for those on a combined basis.

Next up for us, and most important, probably, is our monetization of the midstream MLP assets that we have. We are currently in the process of examining the formation of this with the help of UBS. We are putting the financial packages together. What we have discovered in laying out our growth plans is that the growth in this area will be on the very high side. This is making it very attractive to both strategic and financial players. We’ve had many reverse inquiry calls in this area and we would expect the valuation of this business to be well in excess of $1 billion some time, to be partially monetized in the first quarter of 2008 with either a private, strategic, or financial partner.

That wraps it up for me. Moderator, we’ll go to the question-and-answer session, please.

Question-and-Answer Session

Operator

(Operator Instructions) Your first question will come from the line of Dave Kessler from Simmons & Company. You may proceed, Dave.

Dave Kessler - Simmons & Company

A quick question, just looking at your hedging profile and the comment you made just a bit ago on better gas prices looking around the corner. When I look at your latest changes to your hedging, it looks like you increased Q407, Q108, and kind of decreased the balance thereafter. Can I read much into that?

Aubrey K. McClendon

I think that’s really just growth in our production forecast and I do not believe we’ve changed our hedge positions in those out quarters at all.

Marcus C. Rowland

Yeah, that’s correct, Dave. Q1 and Q2, the last quarter of ’07 and Q1, we have increased our hedging from previous positions and now we’re virtually 100% hedged, including our calls and collars and so forth. We have actually increase the amount of hedges we have on all the way into 2009, and simply the guidance has caused the numbers to perhaps look like it is a slight decrease in the percentage hedged.

Dave Kessler - Simmons & Company

Okay, that makes a lot of sense. On that same thought about gas but tying it a little bit to oil, can you discuss your thoughts on the economic dislocation we’re seeing between gas and oil right now, and your thoughts on when or whether they will actually come back into historical equilibrium?

Aubrey K. McClendon

We really probably don’t expect them to anytime real soon. We really don’t think that they should. We think they are being influenced by two completely different markets. Oil today is reflecting the fact that it’s an increasingly short, scarce resource in the world and the visibility of forward production is increasingly opaque.

On the other hand, natural gas production growth, both in the U.S. and around the world, is much more clear and as a consequence, markets are much more well-supplied, both presently and they are expected to be in the future. So there’s a little true substitutability as there is. We really don’t expect gas prices to trade on a historic six-to-one BTU relationship.

We do think at the end of the day that there will be a move towards natural gas as we move into an increasingly crude or oil short world, as we believe some part of the world’s transportation system is going to have to move to natural gas, whether it’s natural gas directly into vehicles or whether it’s a derivative of natural gas supplied by electricity for some kind of plug-in capability for cars.

So to us, the world oil market is doing what it should be doing; it’s looking for a price that is capable of restraining demand and obviously we haven’t seen anything from $50 to $100 oil yet that’s done that. Until we find that price, we expect oil to continue to go up. We do think it will help sustain higher gas prices than maybe what otherwise would be out there, but we certainly are not calling for a return anytime soon of a six-to-one relationship.

In the longer term though, I definitely believe gas has considerable value as it could be used as a transportation fuel in an oil-short world.

Dave Kessler - Simmons & Company

Great. Thanks for those thoughts. Switching just to one last question, an asset-specific question; with the Woodford Shale, you guys upgraded it to the -- out of the emerging play category and yet at the same time, are making a decision to sell a portion of it. Can you give me a little color around both of those components and then also, can I infer that there is potentially a sweet spot within the Woodford, similar to the Barnett?

Aubrey K. McClendon

Well, we love the play. We have 65,000 acres to sell and think it’s a fabulous play and we look forward to the value that we are going to receive by selling these 65,000 acres to somebody else.

Dave Kessler - Simmons & Company

Okay, I guess then, with separating the piece you’re selling and the piece you’re keeping, and I guess comments from other folks, is there or have you guys been able to ascertain if there is a sweet spot like the core in the Barnett?

Aubrey K. McClendon

Yeah, Dave, sorry, that was a little bit tongue-in-cheek. There is certainly a place that we’d rather be and so we are going to keep 35,000 acres and sell the other 65,000 and that 65,000 is in places that other people have considered more prospective than we have.

It’s a play that we are going to put capital into and in that 35,000 acres we think we’ve got upside of half a tcf, and so we are going to go do everything we can to develop that while at the same time, monetizing a bunch of leaseholds that we probably wouldn’t be able to get to ourselves.

Dave Kessler - Simmons & Company

Great. Thanks for that color. I’ll let somebody else hop on.

Operator

Thank you very much, Dave. Your next question will come from the line of Brian Singer from Goldman Sachs. You may proceed, Brian.

Brian Singer - Goldman Sachs

Thank you. Good morning. In the Fayetteville, you took up your expected EURs, likely as a result of the longer laterals. Are you seeing the uplift in the wells that you are operating that’s causing an increased debt, or is that more a function of Southwestern’s? And can you talk about how you see that $3 million cost moving up or down in the next -- over the next year?

Aubrey K. McClendon

Well, first of all, we’ve always been a long lateral company. They were a short lateral company, so we’ve been seeing these kind of EURs really for the last six months. We just wanted to see some more production before we confirmed them, so we’ve not changed really anything in our development plan over what we’ve been doing. We always racked our wells with slick water, we always drilled long laterals and so we are not -- I think other companies are coming to what we have always done rather than vice versa.

With regard to costs, we are at $3 million and believe that we’ll continue to be able to drive that down. It is an area that is still not built out as well as we’d like it to be from a service company infrastructure basis, but given that we’ve got around 12 rigs running in that area and Southwestern has 20 or so and there’s probably eight or so from other companies, that’s about 40 rigs and that will support a pretty good service basin there and that’s getting built out right now.

So I think our long-term goal is to be able to drill these wells for $2.5 million, $2.6 million and we hope the EURs will continue to creep up over time as we drill more wells that are second, third, fourth, fifth, sixth wells in sections where you have a lot more geological control. We are also still drilling a significant number of wells today without the benefit of 3D, and when we get our area fully shot with 3D we think that our well results will be better and our costs can be lower.

Brian Singer - Goldman Sachs

Great, thanks. On the asset sale front, how much production -- I think you’ve mentioned this individually, but overall how much production is being targeted for asset sales? Has any of that been removed from your production guidance based on the accounting that -- how you are planning to account for that?

Marcus C. Rowland

Right now, Brian, it looks like we’ll be doing likely a transaction that will result in what we call pre-pay accounting, where you book the cash received as deferred revenue and then take the production through your income statement in the future, amortizing that deferred revenue over the time of actual production.

Right now, we are looking to be in the neighborhood of approximately 60 million a day of Appalachian production that would be monetized but that’s not come out of the guidance for the reasons that I just listed. I think we made that clear in our footnotes to our outlook as to how we had handled that.

Brian Singer - Goldman Sachs

You now see $60 million a day as a yearly sale?

Marcus C. Rowland

That would be the rate at the time that we anticipate selling it, which is an effective date of January 1. Of course, going forward that will decline, just like all production does.

Brian Singer - Goldman Sachs

Great. Thank you.

Operator

Thank you, gentlemen. And your next question will come from the line of David  Heikkinen from Tudor, Pickering. You may proceed, David.

David  Heikkinen - Tudor, Pickering & Co.

I just wanted to go through -- Fayetteville, you talked about six wells per section. The orientation of those wells and kind of the plan of how you develop, there’s been some discussion of north/south orientation and trying to drill 4,000 to 5,000 foot laterals. Is that what you are talking about there, Aubrey?

Aubrey K. McClendon

Well, actually I just, as an example, talked about by the time we drill fourth, fifth, or sixth wells, we will be doing better. Our plans right now are to drill eight per section and we are doing some work alongside some work that Southwestern’s doing, which rides the north/south orientations that we believe might lead to more efficient drilling patterns, as we are able to drill longer laterals. They are also working on some four section, kind of unitized areas that we are also experimenting with as well.

Right now, most of our drilling is still oriented northwest to southeast but we are playing with alternative orientations of wells to figure out what produces the best and also what gives us the most amount of exposed rock per 640 acres.

David  Heikkinen - Tudor, Pickering & Co.

Okay, and then your Rockies asset sales, where are those properties?

Aubrey K. McClendon

Well, we’ve got properties in the Williston Basin, mainly, and then we have a little bit of gas production in Colorado that we inherited I believe from our Hugoton acquisition and continue to maintain it -- so it’s a heavily, oil-weighted package and we think it will be attractive to a number of players.

David  Heikkinen - Tudor, Pickering & Co.

Okay, and then the property acquisition, as you roll in the $600 million, any production with that or bolt-on, or how do you think about that as far as your numbers and guidance?

Aubrey K. McClendon

There will always be a little bit of production, probably, but we’ve not modeled any as we presume this will be mainly bolt-on Barnett and bolt-on Fayetteville acquisitions.

David  Heikkinen - Tudor, Pickering & Co.

And one kind of unusual thing in the Fayetteville with the oil and gas clearing house move toward leasing, how do you think that process is going to go by Anadarko, and do you think that will be a trend of ways to monetize leases over time?

Aubrey K. McClendon

That’s an interesting question and concept. We will take a look at it. I’m sure other people will take a look at it as well. The problem is it’s a relatively scattered group of leases that are -- some of them are in we think real attractive areas, some of them are not. If you believe in the auction process, which gives you the best outcome, we think it’s a pretty good way to go. However, we have been involved in many sealed bid transactions where somebody throws in a number that is pretty high over the transom as well, so I don’t know it’s noble, but surely this is the most transparent way to do it and we hope to participate in the process and see what comes out of it.

But we do -- we are seeing more banding together of mineral owners in various hot plays in the country, whether it be neighborhoods in Fort Worth or whether it be mineral owners in Southern Oklahoma, so that’s just an aspect of where we are today in the industry.

I will say that it is certainly -- we still believe that for the most part, that every important play in America that they lease, that the land grab is largely over and are pleased with what we’ve been able to grab along the way.

David  Heikkinen - Tudor, Pickering & Co.

Thank you.

Operator

Thank you, gentlemen. And your next question will come from the line of Scott Hanold from RBC. Scott, you may proceed.

Scott Hanold - RBC Capital Markets

Thank you. Good morning. Could you talk about the Deep Bossier a little bit? What would it take for you to move that from your emerging play to more of a focus area? Where are you at there and is there a -- what are the key milestones you see there going forward?

Aubrey K. McClendon

Key milestones would be successful drilling and production. We don’t have any operated Deep Bossier production right now and we certainly see it all around us and we waited on some seismic to come in before we kicked off our drilling program.

I think as I mentioned in my introductory comments, we are completing two wells that on logs look like they’ll be productive, and so hopefully in the next 30 days we’ll have some Deep Bossier production. We have three rigs drilling right now, which should give capability of drilling about 12 wells per year. So obviously that’s a number that can be accelerated pretty quickly if we started to have anything close to the kind of success that EnCana has had to date in their part of the play.

Scott Hanold - RBC Capital Markets

Okay, so looking into 2008, I guess one could suspect you guys  -- if results, look on par with other operators, you could at least run those three rigs out there?

Aubrey K. McClendon

We haven’t planned through 2009 and the bias would be, of course, for them to go up. For example, we’re drilling a well right now I believe that’s 1.3 miles away from the [Laxton] Well, which is their new big well that’s making 65 million a day, so we are in the hunt on a lot of stuff. We just got a little later start as we were waiting on shooting some 3D to give us a little more clarity into what our acreage position looked like.

Scott Hanold - RBC Capital Markets

Is there any opportunity to consolidate more acreage out there, or is it pretty tough?

Aubrey K. McClendon

Well, you know, we’re always on the hunt in every area but we have 380,000 acres so I don’t know what you all think EnCana paid for non-producing leasehold in the Leor acquisition, but if you put any kind of number on it and put it on our acreage, you can see that we’ve got an enormous asset there that needs some value to be generated from it and we think we can best do that through the drillbit.

Scott Hanold - RBC Capital Markets

Fair enough. One last question on the Fayetteville, you’ve sort of indicated that it appears at this time there may be some service and infrastructure constraints. Do you foresee there being bottlenecks for completing wells and getting production out of there at this point, say in the next six to 12 months? Or is there enough stuff being done to provide some comfort over the next year?

Aubrey K. McClendon

Well, we move the gas ourselves, so there are no delays there. Marc mentioned what we are doing on the monetization of our midstream gas assets through an MLP. One of the big growth areas for that MLP will be in building out gas-gathering infrastructure in the Fayetteville, so no problems there.

With regard to infrastructure, I mentioned simply that costs are higher than they might be if it was in a little more populated area, or in an area of more historic production, but that’s improving and we think it’s getting better every day and really don’t see any delays in getting anything done. It’s just a matter that the unit costs are a little bit higher than we would like them to be.

Scott Hanold - RBC Capital Markets

Thank you. Appreciate your time.

Operator

Thank you, gentlemen. And your next question will come from the line of Eric Kalamaras from Wachovia Capital Markets. You may proceed.

Eric Kalamaras - Wachovia Capital Markets

Good morning. A question on the cash resource plan that you provided, you’ll have the ability to clean down most of your revolver it looks like by certainly the first half of ’08. Tto the extent that acquisitions don’t materialize for ’08 and ’09, how do you perceive the use of cash away from those other acquisition opportunities?

Marcus C. Rowland

Eric, I think that if you study the overall annual plan, which as I mentioned is laid out on page 9, our revolver today is 2.1 outstanding and we call for potential surpluses over the full two years of only 2.9 million, and obviously all of that is not going to be front-loaded in the first quarter. There will be ups and downs, and yes it’s possible that the acquisitions that you mentioned won’t materialize but we are continuing to see, in the Barnett Shale, for example, which is one area where we continue to spend a lot of money because of the value that we are creating down there, we were just going over some numbers internally today and we think that there is still a couple hundred-thousand acres at least available in that play.

Now, it’s going to come at small units at a time but nonetheless, when you have the activity level that we have down there and we are leasing from many different players, both ourselves and we have groups of people working for us, there will be a lot of acreage acquisitions that will come out of that.

With all that as being a caveat, we do anticipate being able to reduce our bank lines over time as we execute this plan, but I don’t really see us getting into any kind of a stock buy-back or a note buy-back. We’ve got some notes that are callable first in 2008 and right now, it looks attractive for us to go out in the market and probably refinance those with longer maturities, perhaps pushing the maturities out to 2019, but I don’t see us going into the market and making any kind of a move to tender for any of our securities that are outstanding today.

Eric Kalamaras - Wachovia Capital Markets

Okay, that’s helpful. Thanks, Marc.

Operator

Thank you, gentlemen. And your next question will come from the line of Jeff Hayden from Pritchard Capital Partners. You may proceed, Jeff.

Jeff Hayden - Pritchard Capital Partners

Thanks. Hey, guys, nice quarter. Real quick, in the Barnett Shale, especially in the core area and now even expanding out into tier one, we’re hearing a lot more people talk about the 500 foot spaced wells. Now we are starting to hear more and more people talk about 250 foot well spacing. Just wondering if you guys have done any pilots on 250 foot well spacing or just what your opinion is with regard to that right now?

Aubrey K. McClendon

We’ve not done any of that and at this point, kind of have our hands full drilling our wells down to 500 foot spacing. I will note, however, that our experience has been, and I believe this is true throughout the industry, that every time you decrease the spacing by one-half, i.e. go from 2,000 feet to 1,000 feet apart, 1,000 feet apart to 500 feet apart, your reserves drop by about 30% per well.

So we would expect if you were to go to 250, that that would happen as well and you might get into some tougher economics. But that’s the kind of upside that I think we’ve got that we really haven’t even begun to try and quantify and that’s the reason why we continue to build acreage in this area, that we think we’ll be producing gas here for decades and we’ll be figuring out more and more ways to get the gas out.

Remember, right now we think we are only probably recovering about 20% or so of the gas in place per section. But that 80% will consume the attention of lots of people around here for probably decades to come.

Jeff Hayden - Pritchard Capital Partners

Okay, great and then just one other quick one; you guys talked about the Marcellus Shale  and a little bit in Appalachia. How much of your acreage is prospective for the Marcellus?

Aubrey K. McClendon

Well, right now, about 750,000 acres I believe is what we have and that’s a combination of leasehold that we acquired through our CNR acquisition, as well as acreage that we bought off the ground. We are drilling our first few vertical and horizontal wells right now and I’m kind of excited about the play. So I’ve seen a few other numbers out there but I don’t think anybody has any amount of acreage that’s close to the 750,000 or so that we believe that we have.

Jeff Hayden - Pritchard Capital Partners

All right, great. Thanks a lot, guys.

Operator

Thank you, gentlemen. And your next question will come from the line of Gil Yang from Citigroup. You may proceed, Gil.

Gil Yang - Citigroup

Good morning. A couple of my questions have been answered already but Aubrey, I just have one for you, and that is that in an earlier discussion about oil versus gas, that was an interesting discussion. You’ve also made the comment in the past that you’d gladly trade your reserves for oil, it’s just that you can’t find any. Are you thinking of taking the portfolio or the efforts of the company and skewing that towards a little bit more effort in looking for oil? Does your technical expertise that the company clearly has in discovering natural gas help you in any way, give you a competitive advantage in looking for oil?

Aubrey K. McClendon

I think so. I mean, the exploration process is similar I think, particularly when it comes to unconventional resources. As you know, there are some unconventional formations that are potentially oil producers and there are many more, of course, that are gas producers.

I would love to change all of our almost 2 billion barrels of oil equivalent reserves into oil but it’s not possible and I would note, I would point to the fact that our oil production increased I think about 25% year over year, so it’s still unfortunately a small number, only about 9% of our production but we definitely have an all-hands alert around here looking for oil and we do have a lot of plays that are prospective for oil. Just nothing on the scale that could move the needle the way that the Barnett moves the needle and the Fayetteville moves the needle, and plays like the Bossier trend and Haley.

I think where we are is recognizing that it’s great to find every barrel that we can, but in terms of building an enterprise here that is sustainable, on a sustainable asset foundation for decades to come. We believe that over time, the world will increasingly want to and have to turn to natural gas to power its transportation grid, either again directly into vehicles or through the electricity grid.

So I view that the current separation between oil and natural gas is probably an historic, at an historic high going forward and in out years, we would suspect that that gap would somewhat close, mainly through the value of natural gas increasing as it gets priced more for its availability, affordability, and cleanliness as well.

Gil Yang - Citigroup

Thank you.

Operator

Thank you, gentlemen. And your next question will come from the line of Ellen Hannan from Bear Stearns.

Ellen Hannan - Bear Stearns

Good morning. Thanks, all my questions have been answered.

Aubrey K. McClendon

Oh, Ellen.

Ellen Hannan - Bear Stearns

We had some technical difficulties. I couldn’t get on earlier. I apologize.

Aubrey K. McClendon

We couldn’t either, so sorry about that. We shared the same difficulty. Thanks, Ellen.

Ellen Hannan - Bear Stearns

Thank you.

Operator

Thank you, gentlemen. And your next question will come from the line of Michael Angle of [TIAF Crest]. You may proceed.

Michael Ange - TIAF Crest

It’s actually Michael Ange. I have a question about your debt levels. Obviously you’ve got some of these asset monetizations in the next quarter and then some in the quarter after that. I’m just curious how we should be looking at that, whether we should be looking at that to have debt come down or really to have that just sort of slow the growth in debt. I’m just wondering if you can clear that up for me.

Marcus C. Rowland

I think there’s two ways that we look at it. The plan as laid out is for no increase in debt at all, so saying that we are going to slow the increase and the rate of growth of debt is not correct. We are planning to decrease our debt levels with the plan that we’ve laid out. Most of that initially will go to reducing our revolving credit facilities, which of course are fungible daily as to drawing and repaying.

The bigger picture for us to make sure that this point gets communicated, the asset monetizations for us are taking what are no growth, long-lived, fully developed properties that can be monetized at -- call it a cap rate of around 7%, and taking that cash and moving it into 35% or 40% on average internal rates of return in the Barnett Shale and the Fayetteville and other drilling areas that we have going on without increasing our debt and without increasing our shares, while building the overall reserves and production levels of the company at a record pace.

I mean, we are by far the largest growth company in the large cap universe and if we can sustain those growth levels over several years with no increase in our share count and a decrease in our debt levels, we will have accomplished something that few companies have ever been able to do on the scale that we think we can do it.

So sell high and buy low through the drillbit and keep the balance sheet improving -- these results I think will reward all of our shareholders and our debt-holders.

Michael Ange - TIAF Crest

Okay, and just one more clarifying question; like I said, it looks like you are going to do, out of the Appalachian asset monetization, somewhere around $1 billion. It looks like you are saying that’s going to close by year-end. So should we assume that at least a chunk of that gets used to pay down the revolver some by year-end?

Marcus C. Rowland

I think you can assume that the day that we close, 100% of it would go to --

Michael Ange - TIAF Crest

Okay, and then it may go back up as you continue drilling and what not?

Marcus C. Rowland

Exactly.

Michael Ange - TIAF Crest

Got it. Thank you.

Operator

Thank you, gentlemen. And your next question will come from the line of Scott Palmer from Janney Montgomery Scott.

Scott Palmer - Janney Montgomery Scott

Good morning. Thanks. Aubrey, good quarter, as usual. My few questions are when do you anticipate becoming investment grade?

Number two, as far as weather is concerned, last year you made some just general comments about what your crack meteorological staff anticipated for the winter. I was wondering if you could just share any generalizations again this year.

And my last question is in regard to supply and demand; you have consistently over the last number of years had in your investor slide presentation that your vision has been growth in demand of 1% to 2% per year and growth of supply of minus 1% to 2% per year, and I noticed that’s not there anymore. Do you feel significantly different now about that supply and demand relationship? Since the growth in supply this year was fairly significant, how do you feel about things?

Aubrey K. McClendon

I think we took that out some time ago, modified it to a view today that our gas supply is definitely growing and probably by anywhere from net of, you know, Gulf decline, somewhere in the 2% to 3% to maybe 4% range. We think that’s a great thing for both the industry as well as consumers. Over the last couple of years, gas got kind of a bad rap as being a volatilely priced commodity and some people thought its price was too high. We believe that it’s an amazing product that burns cleanly and also trades right now of course at about half the BTE value of oil, so we think consumers ought to love the situation that they are in.

From a supply demand perspective, I think what we see is that during the wintertime, LNG importation into the U.S. will be dramatically reduced from what it’s been in the past, as other parts of the world cull that gas away with higher prices, many of which will be linked to oil in some way.

And then the summertime, we’ll probably take in a little more gas than perhaps in the past, as we are the swing storage provider to the world.

We in general though like the fact that gas depletes at the rate of about 35% per year, so know that if there is any extended period of rig activity declines such as what’s been experienced in Canada, there will be a fall-off in supply. But for right now, companies like our own and a handful of other mid and large cap companies that are growing rapidly through the drillbit are providing consumers in the U.S. with a real windfall, we think.

With regard to weather, over the last ten years it just keeps getting warmer. And while I pay a lot of attention to the forecasts that our guys give out, the trend has been towards warmer, so we approach every winter with a bias towards warmth, really regardless of what our fellas opine on.

And with regard to investment grade, I already think we are, so you are probably asking the wrong guy. But when you compare us to at least one or two other investment grade companies, I think that we compare actually pretty favorably.

Clearly my opinion is not one that has much impact on rating agency opinion, so I’ll defer further comment on that to Marc.

Marcus C. Rowland

I think that the trend is definitely toward that. Our goal is to get there, ultimately. We think it’s more inevitable than it is that we are going to go out and radically change our business plan because that’s an absolute essential --it’s not to us. But if I look through the stuff that Jeff’s laid out for us in our presentation and you go to page 7 of the presentation and you start to look at the debt per mcfe numbers that we are projecting by the end of ’09 and you look at the production rates and the asset coverage test, and I reflect back on S&P and their evaluation of our September announcement which was that all of the moves that we were moving toward are credit enhancing and we remain on positive outlook there.

I can see easily during the latter part of ’08, with the accomplishments of the monetization, the enterprise value growth where we’ll be approaching $40 billion to $50 billion in the next 12 months, the value that I think which will be tremendous in the MLP space -- that alone could be a $3 billion to $5 billion enterprise within a year. We may not be at investment grade then but I think we could be a crossover and kind of looking forward to potential upgrades in ’09 that might get us there.

Scott Palmer - Janney Montgomery Scott

All right, thanks. As just a follow-up, since natural gas in the last three weeks has rallied and supply is still very significant at this point, any thoughts as to why that is?

Aubrey K. McClendon

Well, I think that there are two markets for natural gases, as there are for any commodity. There’s a cash market and there’s a futures market and the futures market, of course, is mainly a financial market and we think they can become separated from time to time.

Our view is that oil has provided a pretty strong updraft and I think it’s not clear yet what kind of a winter we are going to have. You had an investment community that was largely short in natural gas, so we think the last month or so has been a fairly predictable -- call it a fairly predictable pattern, as most Octobers and early Novembers do. You generally see a rise in gas prices during that time in anticipation of winter.

So no big surprises here, and of course the question about where natural gas prices go this winter is largely dependent upon the weather and secondarily dependent on where oil prices go.

But it’s really kind of irrelevant to us. We are essentially 100% hedged through the winter and so we’d just as soon gas prices go to zero and give all gas consumers a big break and get them fully back in the game and geared up to consume a lot of gas in 2008 and beyond.

Scott Palmer - Janney Montgomery Scott

Thanks. I appreciate your time.

Operator

Thank you, gentlemen. And your next question will come from the line of David Tameron from Wachovia Capital Markets. You may proceed, David.

David Tameron - Wachovia Capital Markets

Thanks. Good morning. Could you talk a little bit about what you are doing -- I guess you were calling it Colony Wash, the Texas panhandle? Can you talk a little bit about the horizontal program that you mentioned in the prepared remarks and the press release?

Aubrey K. McClendon

Sure. Actually, the Colony Wash area is in Washita County, Oklahoma and it’s a homegrown prospect that we drilled probably ten wells to date and have had very nice results and think that we have a large number of wells left to drill in that area. One nice benefit to it is it’s a little bit oilier than some of the other wash plays that we’ve been involved in.

David Tameron - Wachovia Capital Markets

All right, and you guys are doing the same thing on the granite Atoka side? Are you doing some more horizontals over there or not?

Aubrey K. McClendon

We’ve got probably half-a-dozen distinct wash plays, some of which are granite wash plays, some Atoka wash plays, some are Cherokee wash plays, so they are kind of all a little bit different but generally speaking, most of them are horizontal plays and we’ve been real encouraged with our horizontal results to date.

David Tameron - Wachovia Capital Markets

All right, thanks.

Operator

Thank you, gentlemen. And your next question will come from the line of Joe Allman from JP Morgan. You may proceed, Joe.

Joe Allman - JP Morgan

Good morning, everybody. Aubrey, in terms of the sale of the Woodford package there, is that related to lease expiration issues in any way?

Aubrey K. McClendon

No, Joe, just related to the fact that we have some other plays that we have allocated more capital to and this is a play that I think it’s been clear for a couple of years that some other companies are more excited about than we are, so we are going to let them express their excitement by buying some of our leaseholds.

Joe Allman - JP Morgan

Okay, that’s helpful. And then, in terms of the Deep Bossier, your production right now is relatively small. Can you talk about how many wells that’s coming from? And can you talk about any differences in geology that you folks see right now versus the EnCana acreage? And that’s it on that one.

Aubrey K. McClendon

Sure, Joe. I think as I said, our production is zero, so that I think meets your definition of relatively small, and that is coming from zero wells also. But we do have two wells completed and three wells drilling and from a geological perspective, obviously they are going to be -- we think it’s obvious that there will be other accumulations found in the trend. Hopefully some that are as good as the Amarosa field that EnCana and Leor have discovered. Really, hats off to those guys. It’s an incredible discovery in wells that have come in at 50 to 65 million cubic feet of gas per day.

So nothing really to toot our horn on yet except we have a lot of acreage and we’re kind of right in the middle of the road and hope to get run over by some 50 million a day wells here in the next year or so.

Joe Allman - JP Morgan

Your press release indicates you are producing 7 million a day, but --

Aubrey K. McClendon

Yeah, Jeff pointed it out to me. That’s non-op. I said from an operated basis of zero. I should’ve done a better job of --

Joe Allman - JP Morgan

Well, how many wells is that on a non-op basis, do you know?

Aubrey K. McClendon

No, I don’t, Joe. On a net basis, it’s -- Jeff is signaling to me that it’s five wells.

Joe Allman - JP Morgan

Okay, and then lastly, for Marc, you increased your forecast for the share count. Can you talk about the reason behind that?

Marcus C. Rowland

Well, there’s a couple of small reasons and it is up a minor amount. The first reason is because we are putting out some additional common shares in our assumed preferred stock induced conversion, so the share count went up slightly as a result of that. And then just the continuation of stock grants as part of our executive compensation program as we get larger. Every employee in the company receives some stock grant and as the number of our employees increase, and particularly our highly paid technical staff, a large part of that compensation comes from additional stock grants.

So it’s just a normal course of business for employee count to go up with the large production increases and the amount of reserve increase. Everything is shifting up and to the right, and the minor amount of shares is part of that.

Joe Allman - JP Morgan

Okay, appreciate it. Thank you.

Operator

Thank you, gentlemen. And your next question will come from the line of Monica Verma from Gilford Securities. You may proceed, Monica.

Monica Verma - Gilford Securities

Good morning. I just have two quick questions, the first one dealing with your conventional resource plays. I’m just wondering if you guys could talk a little bit about the monetization of those plays and potential for MLP.

Marcus C. Rowland

Well, in our conventional plays, and I think the way we monetize those is we just produce them and hopefully grow them as well. In some of our older areas, they do present opportunities to do the kind of asset monetization that we’ve talked about coming out of our Appalachian assets. For example, in the Hugoton Field in Kansas and then the West Panhandle field in the Texas panhandle, we have assets that decline at 3%, 4%, 5% per year on a terminal basis that have decline curves that are 50 years of age or often more. And so they are the perfect kind of assets that a financial buyer would want to evaluate when trying to buy a stream of cash flow from production.

So it will be just through production of our assets, as well as potentially down the road in ’08 or ’09 putting some of those low decline rate wells into an asset monetization program. It probably will not be an MLP but instead will be a financial monetization.

Monica Verma - Gilford Securities

And just to get a sense, going on to Appalachia and Sahara and the [Okla-Tex] ones, could you talk a little bit about the reserve revisions down, especially in Appalachia, the 1.5 Tcf?

Aubrey K. McClendon

Let’s see -- when you say down, down from --

Monica Verma - Gilford Securities

From the previous quarter, sorry. It looks like in the previous quarter, Appalachia had un-risked somewhere around 9 and then now it’s looking at 7 Tcf.

Aubrey K. McClendon

Monica, I don’t have the second quarter earnings release here that I could compare to, but most of it just tends --

Monica Verma - Gilford Securities

Sorry, 8.6.

Aubrey K. McClendon

-- just different risk factors that we are applying and sometimes acreage gets moved around between different plays, so I’ll tell you what, if you don’t mind, I’m going to let Jeff call you back and reconcile that. You should see some kind of inter-category movement from quarter to quarter as play outlines change and risk factors are a little more modified, but there’s no -- maybe Jeff’s got something.

Jeffrey L. Mobley

Just in summary, the actual crude reserves went up from second quarter to third quarter and our risked unproved reserves went from 2.5 Tcf the previous quarter to 2.8, so they have actually grown.

What has been a change is that we’ve made an assumption that some of the acreage will be developed on horizontal drilling, so you’ll drill fewer wells bur our expectation is you’d get more -- obviously more reserves per well. But the growth is still apparent in the area.

Monica Verma - Gilford Securities

Okay. I’ll give you a call later. Thanks.

Aubrey K. McClendon

Thanks, Monica. Anything else?

Operator

Thank you, gentlemen. You do have a question from Kent Green from Boston American Management. You may proceed, Kent.

Kent Green - Boston American Management

Great quarter, Aubrey and fellows. The question pertains to MLP and other monetization of outside assets which could be detached. The primary question is when do you figure out that you want to sell it into these tax deferral type situations or whether you want to own part of the MLP and the GEP because of its potential in the future?

And then also, that really pertains to production assets versus, say, midstream assets such as pipeline, gathering system, storage, et cetera, compression.

Marcus C. Rowland

I’ll take a swing at that pitch. We’ve been pretty clear that it is not our intent to form any kind of producing asset MLP. We think that there are some potential governance issues and conflicts that might exist with our business strategy if we were to form our own production MLP. And instead, we’d rather go either the prepayment, the VPP, the NPI or just an outright sale of those assets, again carving out deep rights  and development rights and essentially just selling a stream of existing production into what will generally be labeled either the financial market or an MLP market.

Where we really see the opportunity for us though is to take a very latent type of asset, which is our midstream asset base, where we are growing it in excess of 100% per year, and form a separate MLP, which ultimately probably will become a public MLP but not initially, and use that marketing to raise the funds to continue to grow that asset, and then as it becomes a little bit more mature and the growth rates drop perhaps into the 30% to 50% per year forecast, then to take advantage hopefully of the public market.

Whether we remain the exclusive GP or not from a financial standpoint, we are going to remain the operator and these assets will be managed by Chesapeake and Chesapeake employees, and the financial outcome with respect to either a private partner or ultimately public partners, I’m assuming will be just like every other MLP. There will be incentive distribution rights and there will be governance, independent governance, all of which is yet to come and we are not close to doing that.

Hopefully that answers your question. There is a big distinction in our mind between a midstream MLP and a producing asset MLP, and we don’t have any plans to go into the producing asset MLP market.

Kent Green - Boston American Management

Thank you for that clarification. The second question pertains to the controversy in the entire company about whether you are going to keep issuing share counts, buying everything in sight, want to move into the oil field, want to go offshore, never going to sell anything and then whether you are going to harvest, you know, this large amount of land acreage and unconventional drilling potential that you’ve had going for a number of years. There seems to be two sides to this issue. Just wonder if you would reiterate the plan that you said earlier.

Marcus C. Rowland

I hope there’s not too much controversy over most of those things now. I think we’ve been quite consistent in communicating what our plans are. We have no intent of moving offshore or going to the international markets. We’re in all of the major plays east of the Rocky Mountains that we currently want to be in, or see opportunity in. We have reduced the amount of capital expenditures this year over last year with respect to acquisitions, and we’ve got budgeted reductions going forward.

We’ve made it quite clear that we are not in the market to issue additional shares or additional debt and in fact, our plan will be to reduce the amount of capital expenditures in combination with operating cash flow and asset monetization, such that we should have surplus cash that will further reduce our bank lines.

So hopefully all those things are clearly set forward in our investor presentation and anybody who will take the time to go through what’s probably one of the more detailed presentations in the whole sector, I think the plan should be very clearly laid out there.

Kent Green - Boston American Management

Thank you very much.

Operator

Thank you, gentlemen. And you do have a follow-up question from David  Heikkinen.

David  Heikkinen - Tudor, Pickering & Co.

Marc, could you just compare and contrast the prepay accounting asset sale with the VPP? I just want to understand the logic of the two different structures.

Marcus C. Rowland

I think actually that the VPP and the prepay are virtually synonymous. Neither one are taxable at the moment of the monetization and for book purposes, both are treated as deferred revenue rather than an asset sale. So VPP and prepayment accounting is essentially a deferred revenue accounting, and what you are contrasting are those two against an asset sale, where the asset actually leaves your books and there is no further income statement treatment in the future.

David  Heikkinen - Tudor, Pickering & Co.

Okay, thanks.

Operator

Thank you, gentlemen. At this time, you have no further questions, so I would like to turn the call over to Aubrey McClendon for closing remarks.

Aubrey K. McClendon

I have none. I appreciate your participation on the call. Give us a call if you have any questions. Thank you. Bye-bye.

Operator

Thank you, ladies and gentlemen, for your participation in today’s presentation. You may now disconnect and have a wonderful day.

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Source: Chesapeake Energy Q3 2007 Earnings Call Transcript
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