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

Good morning and thank you for joining Chesapeake's 2007third quarter conference call. Hopefully you’ve had a chance to review ourpress release and updated investor presentation posted to our website yesterdayafternoon. Before I turn the call over to Aubrey and Marc, I need toprovide you with a disclosure concerning forward-looking statements thatChesapeake's management will make during the course of this call. Thestatements that describe our beliefs, goals, expectations, projections, orassumptions are considered forward-looking. Please note that the company’sactual results may differ from those contained in such forward-lookingstatements. Additional information concerning these statements is available inthe company’s SEC filings. In addition, I would also like to point out that during thecourse of our discussion this morning, we will mention terms such as operatingcash flow and EBITDA, and we will also mention items that we believe aretypically excluded from analyst estimates. These are all non-GAAP financialmeasures. Reconciliations to the comparable GAAP measures can be foundon pages 22 through 25 of our press release issued yesterday afternoon. Whilethese are not GAAP financial measures, the financial performance -- GAAPmeasures of financial performance, we believe they are common and useful toolsin evaluating the company’s overall performance. Our prepared comments this morning should last about 15minutes and then we’ll move to Q&A. Aubrey.

Thanks, Jeff and good morning to each of you. I would liketo begin by introducing the other members of our management team who are on thecall today: Marc Rowland, our CFO; Steve Dixon, our COO; Mark Lester, ourSenior VP of Exploration; and Jeff Mobley, our Senior VP of Investor Relationsand Research are all with us here this morning. The third quarter of 2007 marks Chesapeake's 25thconsecutive quarter of sequential production growth and I believe it is alsothe 23rd consecutive quarter in which we have raised production guidance. Andit just might have been our best operational quarter ever. Not only was ourproduction up 27% on a year-over-year basis but it was also up 8% on asequential basis. That’s a compound annual growth rate of 34%. In fact, if you combine last quarter’s 9% sequential growthwith this quarter’s 8%, you can see the combined half-year growth number is 17--

Please stand by while we fix the connection here, ladies andgentlemen. Good day, ladies and gentlemen. Thank you for your patience.Your conference call will resume now. Jeff, you may begin.

Good morning. This is Aubrey McClendon again. Sorry for theinterruption. We do not know what the technical malfunction was. I’m going tostart again with the third quarter of 2007 marks Chesapeake's 25th consecutivequarter of sequential production growth and I believe it is the 23rdconsecutive quarter in which we have raised future production guidance. It mightjust have been our best operational quarter ever. Not only was our productionup 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 lastquarter’s 9% sequential growth with this quarter’s 8%, you can see that our half-yeargrowth number is 17%. Remember please that we voluntarily curtailed 3 bcfe of ourproduction this quarter. Had we not, our third quarter sequential productiongrowth would have been an astonishing 11%. It should be crystal clear to all ofour investors that Chesapeake's growth is accelerating, even from an everlarger base of production. Perhaps this is somewhat surprising to those whohave been asking us for years when the law of large numbers would catch up withChesapeake. We see our growth this year as an obvious confirmation of thebenefits of our large scale, our distinctive technological abilities and ourunmatched leasehold in three seismic inventories. In addition to impressive percentage growth numbers, ourabsolute growth numbers are remarkable as well. Our third quarteryear-over-year production was up 429 million Mcfe per day. This means that inthe past year, we have increased our production by an amount that if it were astandalone company, would be the 17th largest U.S. natural gas producer.Meanwhile, our sequential production growth was 158 million per day and withoutcurtailments, 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…

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 offto Q&A. On the cost side of our business,drilling rigs continue to come down. Using a 1,000 horsepower rig as a standardmeasure, new contracts today are in the $15,000 to $17,000 per day range, downfrom three months ago by $500 to $750 per day, and down from the beginning ofthe 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 from2% to 5%. The only exception in that would be the Fayetteville, where we’reseeing some increased competition and fewer services at this moment. Loggingand casing prices are flat to down 5% or 6% so far this year. On a separate note, I want to point outthat the average number of days in areas where we have a number of wells forcomparison over a period of time are down also. For example, both theFayetteville and Colony Washes horizontal wells, the average days are downthere per well about 10% for third quarter compared to second quarter, goingfrom 27 days on average to 24 days. Haley, we’re dropping the day count thereby about 5% as well. The Barnett has seen some efficiencies this year but inthis last quarter was essentially flat. With regard to our outlook, you may havenoted that we have expanded our guidance to include approximately $600 millionper year of acquisitions. This has previously been leasehold only and is nowleasehold and property acquisitions. We’ve seen at least one analyst commentthis morning where they made the mistake of calling this an increase in CapEx.Of course, that is wrong, as we have…

(Operator Instructions) Your first question will come fromthe line of Dave Kessler from Simmons & Company. You may proceed, Dave. Dave Kessler - Simmons& Company: A quick question, just looking at yourhedging profile and the comment you made just a bit ago on better gas priceslooking 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 balancethereafter. Can I read much into that?

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

Yeah, that’s correct, Dave. Q1 and Q2,the last quarter of ’07 and Q1, we have increased our hedging from previouspositions and now we’re virtually 100% hedged, including our calls and collarsand so forth. We have actually increase the amount of hedges we have on all theway into 2009, and simply the guidance has caused the numbers to perhaps looklike it is a slight decrease in the percentage hedged. Dave Kessler - Simmons& Company: Okay, that makes a lot of sense. On thatsame thought about gas but tying it a little bit to oil, can you discuss yourthoughts on the economic dislocation we’re seeing between gas and oil rightnow, and your thoughts on when or whether they will actually come back intohistorical equilibrium?

We really probably don’t expect them toanytime real soon. We really don’t think that they should. We think they arebeing influenced by two completely different markets. Oil today is reflectingthe fact that it’s an increasingly short, scarce resource in the world and thevisibility of forward production is increasingly opaque. On the other hand, natural gasproduction 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 bein the future. So there’s a little true substitutability as there is. We reallydon’t expect gas prices to trade on a historic six-to-one BTU relationship. We do think at the end of the day thatthere will be a move towards natural gas as we move into an increasingly crudeor oil short world, as we believe some part of the world’s transportationsystem is going to have to move to natural gas, whether it’s natural gasdirectly into vehicles or whether it’s a derivative of natural gas supplied byelectricity for some kind of plug-in capability for cars. So to us, the world oil market is doingwhat it should be doing; it’s looking for a price that is capable ofrestraining demand and obviously we haven’t seen anything from $50 to $100 oilyet that’s done that. Until we find that price, we expect oil to continue to goup. We do think it will help sustain higher gas prices than maybe whatotherwise would be out there, but we certainly are not calling for a returnanytime soon of a six-to-one relationship. In the longer term though, I definitelybelieve gas has considerable value as it could be used as a transportation fuelin an oil-short world. Dave Kessler - Simmons& Company: Great. Thanks for those thoughts.Switching just to one last question, an asset-specific question; with theWoodford Shale, you guys upgraded it to the -- out of the emerging playcategory and yet at the same time, are making a decision to sell a portion ofit. Can you give me a little color around both of those components and thenalso, can I infer that there is potentially a sweet spot within the Woodford,similar to the Barnett?

Well, we love the play. We have 65,000 acres to sell and think it’s a fabulous play and we look forward tothe 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 thepiece you’re selling and the piece you’re keeping, and I guess comments fromother folks, is there or have you guys been able to ascertain if there is asweet spot like the core in the Barnett?

Yeah, Dave, sorry, that was a little bittongue-in-cheek. There is certainly a place that we’d rather be and so we aregoing to keep 35,000 acresand sell the other 65,000 and that 65,000 is in places that other people haveconsidered more prospective than we have. It’s a play that we are going to putcapital 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 thesame time, monetizing a bunch of leaseholds that we probably wouldn’t be ableto get to ourselves. Dave Kessler - Simmons& Company: Great. Thanks for that color. I’ll letsomebody else hop on.

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

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

Well, first of all, we’ve always been along lateral company. They were a short lateral company, so we’ve been seeingthese kind of EURs really for the last six months. We just wanted to see somemore production before we confirmed them, so we’ve not changed really anythingin our development plan over what we’ve been doing. We always racked our wellswith slick water, we always drilled long laterals and so we are not -- I thinkother companies are coming to what we have always done rather than vice versa. With regard to costs, we are at $3million and believe that we’ll continue to be able to drive that down. It is anarea that is still not built out as well as we’d like it to be from a servicecompany infrastructure basis, but given that we’ve got around 12 rigs runningin that area and Southwestern has 20 or so and there’s probably eight or sofrom other companies, that’s about 40 rigs and that will support a pretty goodservice basin there and that’s getting built out right now. So I think our long-term goal is to beable to drill these wells for $2.5 million, $2.6 million and we hope the EURswill 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 moregeological control. We are also still drilling a significant number of wellstoday without the benefit of 3D, and when we get our area fully shot with 3D wethink that our well results will be better and our costs can be lower.

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

Right now, Brian, it looks like we’ll bedoing 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 theproduction through your income statement in the future, amortizing thatdeferred revenue over the time of actual production. Right now, we are looking to be in theneighborhood of approximately 60 million a day of Appalachian production thatwould be monetized but that’s not come out of the guidance for the reasons thatI just listed. I think we made that clear in our footnotes to our outlook as tohow we had handled that.

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

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

Great. Thank you.

Thank you, gentlemen. And your next question will come fromthe 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 kindof the plan of how you develop, there’s been some discussion of north/southorientation and trying to drill 4,000 to 5,000 foot laterals. Is that what you are talking about there, Aubrey?

Well, actually I just, as an example,talked about by the time we drill fourth, fifth, or sixth wells, we will bedoing better. Our plans right now are to drill eight per section and we aredoing some work alongside some work that Southwestern’s doing, which rides thenorth/south orientations that we believe might lead to more efficient drillingpatterns, as we are able to drill longer laterals. They are also working onsome four section, kind of unitized areas that we are also experimenting withas well. Right now, most of our drilling is stilloriented northwest to southeast but we are playing with alternativeorientations of wells to figure out what produces the best and also what givesus 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?

Well, we’ve got properties in the Williston Basin,mainly, and then we have a little bit of gas production in Coloradothat we inherited I believe from our Hugoton acquisition and continue tomaintain it -- so it’s a heavily, oil-weighted package and we think it will beattractive 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 doyou think about that as far as your numbers and guidance?

There will always be a little bit ofproduction, probably, but we’ve not modeled any as we presume this will bemainly bolt-on Barnett and bolt-on Fayettevilleacquisitions. David Heikkinen - Tudor, Pickering & Co.: And one kind of unusual thing in theFayetteville with the oil and gas clearing house move toward leasing, how doyou think that process is going to go by Anadarko, and do you think that willbe a trend of ways to monetize leases over time?

That’s an interesting question andconcept. We will take a look at it. I’m sure other people will take a look atit 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. Ifyou believe in the auction process, which gives you the best outcome, we thinkit’s a pretty good way to go. However, we have been involved in many sealed bidtransactions where somebody throws in a number that is pretty high over thetransom as well, so I don’t know it’s noble, but surely this is the mosttransparent way to do it and we hope to participate in the process and see whatcomes out of it. But we do -- we are seeing more bandingtogether of mineral owners in various hot plays in the country, whether it beneighborhoods in Fort Worth or whether it be mineral owners in SouthernOklahoma, so that’s just an aspect of where we are today in the industry. I will say that it is certainly -- westill believe that for the most part, that every important play in America thatthey lease, that the land grab is largely over and are pleased with what we’vebeen able to grab along the way. David Heikkinen - Tudor, Pickering & Co.: Thank you.

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

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

Key milestones would be successful drilling and production.We don’t have any operated Deep Bossier production right now and we certainlysee it all around us and we waited on some seismic to come in before we kickedoff our drilling program. I think as I mentioned in my introductory comments, we arecompleting two wells that on logs look like they’ll be productive, and sohopefully in the next 30 days we’ll have some Deep Bossier production. We havethree rigs drilling right now, which should give capability of drilling about12 wells per year. So obviously that’s a number that can be accelerated prettyquickly if we started to have anything close to the kind of success that EnCanahas had to date in their part of the play.

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

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

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

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

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

Well, we move the gas ourselves, so there are no delaysthere. Marc mentioned what we are doing on the monetization of our midstreamgas assets through an MLP. One of the big growth areas for that MLP will be inbuilding out gas-gathering infrastructure in the Fayetteville, so no problemsthere. With regard to infrastructure, I mentioned simply that costsare higher than they might be if it was in a little more populated area, or inan area of more historic production, but that’s improving and we think it’sgetting better every day and really don’t see any delays in getting anythingdone. It’s just a matter that the unit costs are a little bit higher than wewould like them to be.

Thank you. Appreciate your time.

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

Good morning. A question on the cash resource plan that youprovided, you’ll have the ability to clean down most of your revolver it lookslike by certainly the first half of ’08. Tto the extent that acquisitions don’tmaterialize for ’08 and ’09, how do you perceive the use of cash away from thoseother acquisition opportunities?

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 2.1outstanding and we call for potential surpluses over the full two years of only2.9 million, and obviously all of that is not going to be front-loaded in thefirst quarter. There will be ups and downs, and yes it’s possible that theacquisitions 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 spenda lot of money because of the value that we are creating down there, we werejust going over some numbers internally today and we think that there is stilla couple hundred-thousand acres at least available in that play. Now, it’s going to come at small units at a time butnonetheless, when you have the activity level that we have down there and weare leasing from many different players, both ourselves and we have groups ofpeople working for us, there will be a lot of acreage acquisitions that willcome out of that. With all that as being a caveat, we do anticipate being ableto reduce our bank lines over time as we execute this plan, but I don’t reallysee us getting into any kind of a stock buy-back or a note buy-back. We’ve gotsome notes that are callable first in 2008 and right now, it looks attractivefor us to go out in the market and probably refinance those with longermaturities, perhaps pushing the maturities out to 2019, but I don’t see usgoing into the market and making any kind of a move to tender for any of oursecurities that are outstanding today.

Okay, that’s helpful. Thanks, Marc.

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

Thanks. Hey, guys, nice quarter. Real quick, in the BarnettShale, 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 arestarting to hear more and more people talk about 250 foot well spacing. Justwondering if you guys have done any pilots on 250 foot well spacing or just whatyour opinion is with regard to that right now?

We’ve not done any of that and at this point, kind of haveour 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 throughoutthe industry, that every time you decrease the spacing by one-half, i.e. gofrom 2,000 feetto 1,000 feetapart, 1,000 feetapart to 500 feetapart, your reserves drop by about 30% per well. So we would expect if you were to go to 250, that that wouldhappen as well and you might get into some tougher economics. But that’s thekind of upside that I think we’ve got that we really haven’t even begun to tryand quantify and that’s the reason why we continue to build acreage in thisarea, that we think we’ll be producing gas here for decades and we’ll befiguring out more and more ways to get the gas out. Remember, right now we think we are only probably recoveringabout 20% or so of the gas in place per section. But that 80% will consume theattention of lots of people around here for probably decades to come.

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

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

All right, great. Thanks a lot, guys.

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

Good morning. A couple of my questions have been answeredalready but Aubrey, I just have one for you, and that is that in an earlierdiscussion about oil versus gas, that was an interesting discussion. You’vealso made the comment in the past that you’d gladly trade your reserves foroil, it’s just that you can’t find any. Are you thinking of taking theportfolio or the efforts of the company and skewing that towards a little bitmore effort in looking for oil? Does your technical expertise that the companyclearly has in discovering natural gas help you in any way, give you acompetitive advantage in looking for oil?

I think so. I mean, the exploration process is similar Ithink, particularly when it comes to unconventional resources. As you know,there are some unconventional formations that are potentially oil producers andthere are many more, of course, that are gas producers. I would love to change all of our almost 2 billion barrelsof oil equivalent reserves into oil but it’s not possible and I would note, Iwould 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% ofour production but we definitely have an all-hands alert around here lookingfor oil and we do have a lot of plays that are prospective for oil. Justnothing on the scale that could move the needle the way that the Barnett movesthe needle and the Fayetteville moves the needle, and plays like the Bossiertrend and Haley. I think where we are is recognizing that it’s great to findevery barrel that we can, but in terms of building an enterprise here that issustainable, on a sustainable asset foundation for decades to come. We believethat over time, the world will increasingly want to and have to turn to naturalgas to power its transportation grid, either again directly into vehicles orthrough the electricity grid. So I view that the current separation between oil andnatural gas is probably an historic, at an historic high going forward and in outyears, we would suspect that that gap would somewhat close, mainly through thevalue of natural gas increasing as it gets priced more for its availability,affordability, and cleanliness as well.

Thank you.

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

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

Oh, Ellen.

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

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

Thank you.

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

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

I think there’s two ways that we look at it. The plan aslaid out is for no increase in debt at all, so saying that we are going to slowthe increase and the rate of growth of debt is not correct. We are planning todecrease our debt levels with the plan that we’ve laid out. Most of thatinitially will go to reducing our revolving credit facilities, which of courseare fungible daily as to drawing and repaying. The bigger picture for us to make sure that this point getscommunicated, the asset monetizations for us are taking what are no growth,long-lived, fully developed properties that can be monetized at -- call it acap rate of around 7%, and taking that cash and moving it into 35% or 40% onaverage internal rates of return in the Barnett Shale and the Fayetteville andother drilling areas that we have going on without increasing our debt andwithout increasing our shares, while building the overall reserves andproduction levels of the company at a record pace. I mean, we are by far the largest growth company in thelarge cap universe and if we can sustain those growth levels over several yearswith no increase in our share count and a decrease in our debt levels, we willhave accomplished something that few companies have ever been able to do on thescale that we think we can do it. So sell high and buy low through the drillbit and keep thebalance sheet improving -- these results I think will reward all of ourshareholders and our debt-holders.

Okay, and just one more clarifying question; like I said, itlooks 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 closeby year-end. So should we assume that at least a chunk of that gets used to paydown the revolver some by year-end?

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

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

Exactly.

Got it. Thank you.

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

Good morning. Thanks. Aubrey, good quarter, as usual. My fewquestions are when do you anticipate becoming investment grade? Number two, as far as weather is concerned, last year youmade some just general comments about what your crack meteorological staffanticipated for the winter. I was wondering if you could just share anygeneralizations again this year. And my last question is in regard to supply and demand; youhave consistently over the last number of years had in your investor slidepresentation that your vision has been growth in demand of 1% to 2% per yearand growth of supply of minus 1% to 2% per year, and I noticed that’s not thereanymore. Do you feel significantly different now about that supply and demandrelationship? Since the growth in supply this year was fairly significant, howdo you feel about things?

I think we took that out some time ago, modified it to aview today that our gas supply is definitely growing and probably by anywherefrom 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 asconsumers. Over the last couple of years, gas got kind of a bad rap as being avolatilely priced commodity and some people thought its price was too high. Webelieve that it’s an amazing product that burns cleanly and also trades rightnow of course at about half the BTE value of oil, so we think consumers oughtto love the situation that they are in. From a supply demand perspective, I think what we see isthat during the wintertime, LNG importation into the U.S. will be dramaticallyreduced from what it’s been in the past, as other parts of the world cull thatgas 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 littlemore gas than perhaps in the past, as we are the swing storage provider to theworld. We in general though like the fact that gas depletes at therate of about 35% per year, so know that if there is any extended period of rigactivity declines such as what’s been experienced in Canada,there will be a fall-off in supply. But for right now, companies like our ownand a handful of other mid and large cap companies that are growing rapidlythrough 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 justkeeps getting warmer. And while I pay a lot of attention to the forecasts thatour guys give out, the trend has been towards warmer, so we approach everywinter with a bias towards warmth, really regardless of what our fellas opineon. 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 leastone or two other investment grade companies, I think that we compare actuallypretty favorably. Clearly my opinion is not one that has much impact on ratingagency opinion, so I’ll defer further comment on that to Marc.

I think that the trend is definitely toward that. Our goalis to get there, ultimately. We think it’s more inevitable than it is that weare going to go out and radically change our business plan because that’s anabsolute essential --it’s not to us. But if I look through the stuff thatJeff’s laid out for us in our presentation and you go to page 7 of thepresentation and you start to look at the debt per mcfe numbers that we areprojecting by the end of ’09 and you look at the production rates and the assetcoverage test, and I reflect back on S&P and their evaluation of our Septemberannouncement which was that all of the moves that we were moving toward arecredit enhancing and we remain on positive outlook there. I can see easily during the latter part of ’08, with theaccomplishments of the monetization, the enterprise value growth where we’ll beapproaching $40 billion to $50 billion in the next 12 months, the value that Ithink which will be tremendous in the MLP space -- that alone could be a $3billion to $5 billion enterprise within a year. We may not be at investment gradethen but I think we could be a crossover and kind of looking forward topotential upgrades in ’09 that might get us there.

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

Well, Ithink that there are two markets for natural gases, as there are for anycommodity. There’s a cash market and there’s a futures market and the futuresmarket, of course, is mainly a financial market and we think they can becomeseparated from time to time. Our view is that oil has provided a pretty strong updraftand I think it’s not clear yet what kind of a winter we are going to have. Youhad an investment community that was largely short in natural gas, so we thinkthe last month or so has been a fairly predictable -- call it a fairlypredictable pattern, as most Octobers and early Novembers do. You generally seea rise in gas prices during that time in anticipation of winter. So no big surprises here, and of course the question aboutwhere natural gas prices go this winter is largely dependent upon the weatherand secondarily dependent on where oil prices go. But it’s really kind of irrelevant to us. We are essentially100% hedged through the winter and so we’d just as soon gas prices go to zeroand give all gas consumers a big break and get them fully back in the game and gearedup to consume a lot of gas in 2008 and beyond.

Thanks. I appreciate your time.

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

Thanks. Good morning. Could you talk a little bit about whatyou 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 inthe prepared remarks and the press release?

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

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

We’ve got probably half-a-dozen distinct wash plays, some ofwhich are granite wash plays, some Atoka wash plays, some are Cherokee washplays, 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 ourhorizontal results to date.

All right, thanks.

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

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

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

Okay, that’s helpful. And then, in terms of the DeepBossier, your production right now is relatively small. Can you talk about howmany wells that’s coming from? And can you talk about any differences ingeology that you folks see right now versus the EnCana acreage? And that’s iton that one.

Sure, Joe. I think as I said, our production is zero, sothat I think meets your definition of relatively small, and that is coming fromzero wells also. But we do have two wells completed and three wells drillingand from a geological perspective, obviously they are going to be -- we thinkit’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 havediscovered. Really, hats off to those guys. It’s an incredible discovery inwells 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 alot of acreage and we’re kind of right in the middle of the road and hope toget run over by some 50 million a day wells here in the next year or so.

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

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

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

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

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

Well, there’s a couple of small reasons and it is up a minoramount. The first reason is because we are putting out some additional commonshares in our assumed preferred stock induced conversion, so the share countwent up slightly as a result of that. And then just the continuation of stockgrants as part of our executive compensation program as we get larger. Everyemployee in the company receives some stock grant and as the number of ouremployees increase, and particularly our highly paid technical staff, a largepart of that compensation comes from additional stock grants. So it’s just a normal course of business for employee countto 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 ispart of that.

Okay, appreciate it. Thank you.

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

Good morning. I just have two quick questions, the first onedealing with your conventional resource plays. I’m just wondering if you guyscould talk a little bit about the monetization of those plays and potential forMLP.

Well, in our conventional plays, and I think the way wemonetize those is we just produce them and hopefully grow them as well. In someof our older areas, they do present opportunities to do the kind of assetmonetization that we’ve talked about coming out of our Appalachian assets. Forexample, in the Hugoton Field in Kansas and then the West Panhandle field inthe Texas panhandle, we have assets that decline at 3%, 4%, 5% per year on aterminal 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 toevaluate when trying to buy a stream of cash flow from production. So it will be just through production of our assets, as wellas potentially down the road in ’08 or ’09 putting some of those low declinerate wells into an asset monetization program. It probably will not be an MLPbut instead will be a financial monetization.

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

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

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

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

Sorry, 8.6.

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

Just in summary, the actual crude reserves went up fromsecond quarter to third quarter andour risked unproved reserves went from 2.5 Tcf the previous quarter to 2.8, sothey have actually grown. What has been a change is that we’ve made an assumption thatsome of the acreage will be developed on horizontal drilling, so you’ll drillfewer wells bur our expectation is you’d get more -- obviously more reservesper well. But the growth is still apparent in the area.

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

Thanks, Monica. Anything else?

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

Great quarter, Aubrey and fellows. The question pertains toMLP and other monetization of outside assets which could be detached. Theprimary question is when do you figure out that you want to sell it into thesetax deferral type situations or whether you want to own part of the MLP and theGEP because of its potential in the future? And then also, that really pertains to production assetsversus, say, midstream assets such as pipeline, gathering system, storage, etcetera, compression.

I’ll take a swing at that pitch. We’ve been pretty clearthat it is not our intent to form any kind of producing asset MLP. We thinkthat there are some potential governance issues and conflicts that might existwith our business strategy if we were to form our own production MLP. Andinstead, we’d rather go either the prepayment, the VPP, the NPI or just anoutright sale of those assets, again carving out deep rights and development rights and essentially justselling a stream of existing production into what will generally be labeledeither the financial market or an MLP market. Where we really see the opportunity for us though is to takea very latent type of asset, which is our midstream asset base, where we aregrowing it in excess of 100% per year, and form a separate MLP, whichultimately probably will become a public MLP but not initially, and use thatmarketing to raise the funds to continue to grow that asset, and then as itbecomes 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 publicmarket. Whether we remain the exclusive GP or not from a financialstandpoint, we are going to remain the operator and these assets will bemanaged by Chesapeake and Chesapeake employees, and the financial outcome withrespect to either a private partner or ultimately public partners, I’m assumingwill be just like every other MLP. There will be incentive distribution rightsand there will be governance, independent governance, all of which is yet tocome and we are not close to doing that. Hopefully that answers your question. There is a bigdistinction in our mind between a midstream MLP and a producing asset MLP, andwe don’t have any plans to go into the producing asset MLP market.

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

I hope there’s not too much controversy over most of thosethings now. I think we’ve been quite consistent in communicating what our plansare. We have no intent of moving offshore or going to the internationalmarkets. We’re in all of the major plays east of the Rocky Mountains that wecurrently want to be in, or see opportunity in. We have reduced the amount ofcapital expenditures this year over last year with respect to acquisitions, andwe’ve got budgeted reductions going forward. We’ve made it quite clear that we are not in the market toissue additional shares or additional debt and in fact, our plan will be toreduce the amount of capital expenditures in combination with operating cashflow and asset monetization, such that we should have surplus cash that willfurther reduce our bank lines. So hopefully all those things are clearly set forward in ourinvestor presentation and anybody who will take the time to go through what’sprobably one of the more detailed presentations in the whole sector, I thinkthe plan should be very clearly laid out there.

Thank you very much.

Thank you, gentlemen. And you do have a follow-up questionfrom David Heikkinen. David Heikkinen - Tudor, Pickering & Co.:

I think actually that the VPP and the prepay are virtuallysynonymous. Neither one are taxable at the moment of the monetization and forbook 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 theasset actually leaves your books and there is no further income statementtreatment in the future. David Heikkinen - Tudor, Pickering & Co.: Okay, thanks.

Thank you, gentlemen. At this time, you have no furtherquestions, so I would like to turn the call over to Aubrey McClendon forclosing remarks.

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