– : Aubrey McClendon – Chairman and CEO Marc Rowland – EVP and CFO Steve Dixon – EVP, Operations and COO

Dave Kistler – Simmons & Company Scott Hanold – RBC Capital Markets David Heikkinen – Tudor Pickering & Co. Brian Singer – Goldman Sachs Wi Romaldo – Stone Harbor Investments Ray Deacon – Pritchard Capital Adrayll Askew – Hartford Investment Management David Cameron – Wells Fargo Lewis Ropp – Barrow Hanley David Snow – Energy Equities Incorporated Dan McSpirit – BMO Capital Markets Ryan Kelly – Prudential Biju Perincheril – Jefferies Bob Clements – Brittney Capital

Good day ladies and gentlemen and welcome to the Chesapeake Energy third quarter earnings conference call. Today's conference is being recorded. At this time I would like to turn the conference over to Mr. Jeff Mobley, please go ahead, sir.

Good morning and thank you for joining today's conference call. I would like to begin by introducing the other members of our management team who are with me on the call today. Aubrey McClendon, our Chief Executive Officer, Marc Rowland, our Chief Financial Officer; Steve Dixon, our Chief Operating Officer, Mark Lester, our Executive Vice President, Geoscience, and John Kapchinske [ph], our Manager of Investor Relations and Research. Our prepared comments this morning will be brief and then we'll move to Q&A. Out of courtesy to other companies with conference calls this morning we'll wrap up our call at about 10 Clock Eastern Time. I will turn the call over to Aubrey.

Thank you, Jeff, and good morning. We hope you've had time to review last Thursday's operational release and yesterday's financial release. On the operational side our daily production hit a new quarterly record for production at a daily rate of 2.483 Bcfe. In October, our net production has already been as high as 2.6 Bcfe. So we are on track to continue capturing gas production market share in the months and years ahead. By year-end 2010, we expect our daily net production to exceed 2.8 Bcfe and by year-end 2011 we expect our daily net production to exceed 3.1 Bcfe, which would be an increase of 25% from our third quarter 2009 average daily production. These production increases continue to be led by growth from our Big 4 shale and Granite Wash play. We believe they will be leading the production increases at Chesapeake for at least the next 20 quarters and probably for more than the next 40 quarters. That seems like a lot of quarters to you. Well, it is. However, I would like to remind you that Chesapeake has been a public company for 67 quarters and our production has increased for 54 quarters out of those 67 including 31 quarters of the last 33 quarters over the past eight years. In addition, ignoring the impact of what we believe are temporary declines in proved reserves due to the fall in natural gas prices during the third quarter, we are delivering strong underline proved reserve additions. In fact, the third quarter was our best quarter ever in terms of organic proved reserve growth. We produced 228 Bcfe during the quarter and replaced this production over four folds with 989 Bcfe of additions, extensions and performance revisions. And just as impressively those proved reserves cost us only $0.64…

Thanks, Aubrey, and good morning, everyone. Just a very few brief comments from me this A.M. First, I think it's important to note in this very difficult gas price environment, your company has continued to be profitable this quarter on the strength of higher volumes, excellent hedging results as mentioned by Aubrey, and general cost reductions in many areas. In fact, on a recurring basis, we were able to beat consensus estimates over earnings by about 8%. We continue to see the third quarter be an era of decreased service cost and decreased lease operating expenses. We do believe that we're probably pretty close to the bottom and Steve Dixon and his operating staff have worked hard to layer in numerous service company arrangements that will lock in at least 70% of our cost over the next 12 months to 24 months. Second, we continue to entertain unsolicited exchange offers for some of our convertible debt and retired 155.3 million of face amount this quarter at an average discount of about 28% to par in exchange for CHK stock that was issued at an equivalent price of just over $36 per share. Today, that brings us about $1.1 billion of debt extinguished in the last four quarters in exchange for CHK shares. Finally, we ended the quarter with $520 million in cash and about $2.6 billion of undrawn capacity in our three bank credit facilities. This liquidity was primarily created by the monetization of the PXP carry in September, and which is in our Haynesville program and the successful completion of our CMP joint venture with global infrastructure partners during the quarter. With that, moderator, we'll turn it over to questions, please.

Thank you. (Operator instructions). We'll take our first question from Dave Kistler with Simmons & Company. Dave Kistler – Simmons & Company: Good morning, guys.

Good morning. Dave Kistler – Simmons & Company: Quick question with respect to the hedging that you outlined in this call and previously that you're taking the fact of being offensive versus defensive with respect to laying on hedges. Barring the attractive carries you guys have in the Fayetteville, Marcellus, would you think about that a little bit differently and irregardless of those at what price would you look at considering hedging?

I don't think our hedging is impacted by our carries. Our hedging is impacted by long developed strategy that Mark and I've had and Jeff has joined us in recent years in trying to hedge prices that create value rather than limit value creation, and I think some companies that for example, wouldn't hedge $8 gas in 2010, a year or two ago. It's a little curious that they are eager to hedge $5.50 or $6 gas lately. And I reiterate [ph] the markets and Jeff has a very extensive and we think accurate production model for the entire U.S. and includes Canadian input as well. We think that leads us to the inescapable conclusion that gas production will be down significantly in months and quarters ahead and we think that will present us with ample opportunities. And so, if we wanted to just go hedge, we can hedge, but we think there's more to hedging than just simply executing the hedge. We think you need to do it at the right time and we haven't felt like the right time has arrived yet. Dave Kistler – Simmons & Company: Great. That's helpful. And then kind of thinking about Jeff's model that you highlight, if we look at the most recent 914 data, obviously, we're seeing kind of lumpy results month over month. Any thoughts or any changes regarding sort of the anticipated rollover that you've outlined for 2010 as the real rollover year versus 2009 and do you equate that, the fact that it's been pushed out a little bit to efficiencies or is there some sort of high grading of portfolio, just kind of your conceptual thoughts that would be helpful.

I'll give you a couple and turn it over to Jeff for his analysis. But I think we've been reasonably consistent over the past six months we thought we would see declines in the fourth quarter of 2009 that you're not going to see public confirmation of that until 2010, but I think Jeff model for some time has shown a bottoming of gas production on a year-over-year basis, let's call it, the late first quarter, early second quarter of 2010, and then those decline continue throughout 2010 to get to an absolute trough of production some time in the first half of 2011. So why is it taking longer for some of this stuff to show up? I think the same as what we saw in Canada, few years ago. It just takes a long time for uncompleted wells to work through the system, and I think that's what's happening today, and obviously investors have been very clued into this phenomena on a both voluntarily and involuntarily, uncompleted or wells that have not yet been hooked up and that backlog we think is largely cleared itself. We think it's cleared itself at our company and suspect that it has in the industry. So I'll turn it over to Jeff for further commentary. Jeff Yes, just a few other comments there. Frankly we're still trying to reconcile the numerous revisions that came out on the last round of the 914 data and it's not entirely clear if it fully represents an accurate picture. However, if you take what's been observed in the weekly storage reports, it's clear that the market has tightened over the past several weeks, and you saw a resurgent subdemand through low fuel prices in September combined with ministry curtailment. I think both of those are reversed themselves somewhat here in October, but still the trend with a much lower rate count should lead to substantial declines in production we head into 2010 and we haven't seen any new data to discourage that yet. Dave Kistler – Simmons & Company: Great, thank you for the clarifications, guys.

Thank you, Dave.

And now we'll open the line up to Scott Hanold with RBC Capital Markets. Scott Hanold – RBC Capital Markets: Good morning.

Good morning, Scott. Scott Hanold – RBC Capital Markets: Can you talk about the strategy of becoming sort of an acreage reseller and how do you look at the value of this relative to you're just focusing those dollars on potentially higher return E&P activity?

For several years, Scott, I think we've been pretty vocal in saying there's at least two ways to make money in this industry. One is the way traditional way of you just go out and drill a well and wait for the production to roll in over the next 50 years and there you have it, and that is traditional and we do a lot of that. I think over the last couple of years that we've recognized that our company has a unique ability to develop new plays and to buy vast amounts of acreage in those plays, and then seek out partners who for one reason or another aren't in those plays and place them in those place at prices that are attractive to them and attractive to us. If you look in the last seven quarters, we made over $10 billion doing that. We didn't make $10 billion during that same time just drilling and producing wells. And so we view it as a very profitable sideline of business, and some people have a hard time understanding that. But that's what virtually every other business model in every other industry is. You develop inventory hopefully with an eye towards doing something that your competitors can't do and then you sell it and you make a profit and that's what we've done. One challenge for us is this model is not particularly conducive or it's not particularly reported well by forecast accounting because we don't have a line on our income statement that shows profit from leasehold sales, but you can see it in our depreciation rate and we fully disclose all the items that go into that. So I think it's a fantastic way and again we have created $16 a share of value through that process over the last seven quarters and I think it's something that we'll be able to do for years into the future. We have the ability to know what a gas is, we have the ability to buy the leases and we have the confidence that when we sell those leases, we'll be able to replace those leases in that sales process to hopefully generate a profit margin, it's very substantial. Scott Hanold – RBC Capital Markets: Do you all think that is a lower risk relative to regular oil and gas activity?

I think it is simply because once you make the sale, you've got the proceeds, and when you drill a well and then you don't hedge it, you really don't know what your returns are going to be. So I think we have a long-term value creation business and a short-term value creation business and the fact is it's unique in the industry and so a lot of people have a hard time understanding it. But it seems pretty simple to me. Scott Hanold – RBC Capital Markets: Okay. And one last question relative to sort of on the same line on the Barnett JV, any updates in the last couple of weeks in San Jose?

We are still in conversation with some folks and if we do anything there, it will be on terms that we find attractive, and our hope would be that we would wrap those discussions up sometime in calendar year 2009. Scott Hanold – RBC Capital Markets: I appreciate it. Thanks.

Okay. Thanks, Scott.

Now, we'll go to David Heikkinen with Tudor Pickering & Co. David Heikkinen – Tudor Pickering & Co.: As you look at your Haynesville production that you just updated grew from 210 million a day to 330 million a day, can you talk about, you did talk about some about exit rates. Looks like exit rates may be exceeding your original target. How do you think about that growth rate now going into the end of the year with a 35 rig program?

Well, Dave, I may defer here to Steve, but I think in our operational release last week we did give you a projection for year-end 2010 of 670 million a day growth and 500 net and for year-end 2011 that would be 930 million a day growth and 690 million a day net. So that's how we see the growth unfolding. Did I misunderstand your question? David Heikkinen – Tudor Pickering & Co.: Yes, basically it looks like given a 35-rig program, you did increase your guidance on your last operational update a little bit on your year-end target and as you think about that progression on a monthly basis, it's grown roughly 120 million a day. I'm just trying to get an idea, the conservativeness or the better wells that are built into last month data versus your type curve to trying to see how that growth of bringing those wells in that short of a timeframe led to the amount of growth versus where your overall target fair?

Dave, I just say that we've a very conservative process of forecasting production and we consistently beat production both as company level as well as a play level. So I think those are the minimum numbers that we expect to achieve. Steve, is there anything you want to add to that or?

No. It's all positive news…

Cycle times are lower, reported results seem to be –

We've had a quite of influx of non-op activity also that we're participating and that's really grown.

Can you just take this opportunity to give an update on well cost in the Haynesville? We've had some wells come in around $6 million.

Just continuing to drive down per well cost both on the drilling side through faster drilling, less days, and on the completion side.

I think last week we got to rig release on 29 days on a well that was 4,500 feet and have a number of wells that we've completed now for $6 million or less. So you want some rate of return now from the difference between a $6 million well and a $9 million well is pretty remarkable what those differences are. I mentioned 4,500 foot well or how many stages could that be gross?

It will be over double-digit. David Heikkinen – Tudor Pickering & Co.: And then thinking about as you add real estate into the Marcellus, your acreage goes up, you rig rate hedge going to be selling some real estate. How do you value a real estate transaction company? I'm just trying to think about, is it the same earning stream and the same valuation metrics of how you would value in just a straight E&P business?

I don't have an answer for that, David. I guess that's your well challenged and think the answer so far has been we're not going to put any value on it, but that doesn't bother me because we'll just keep doing what we do and we'll take the cash that we obtain from those and either go drill wells that we wouldn't have been able to drill or repay debt or do any number of things that create value. At the end of the day I haven't seen any real commentary or too many others, but I think it's pretty extraordinary that nobody really focuses on what these carries have done to our funding cost. If you think about going forward, this is a sustainable, durable competitive advantage that should enable us to achieve the highest returns on capital in the business by reducing our future funding cost. David Heikkinen – Tudor Pickering & Co.: Do you think though from a financial modeling standpoint, I know this is how the market thinks about it, you get better value if you did more cash proceeds upfront as opposed to carries, where then it does hit your balance sheet immediately or does that even factor into your thought process other than just finding costs lowering over couple of years?

I think that the balance that we have is one of at least two elements to it. The most obvious is that the drilling carries the way that we've structured them, our tax deductible for the paying party and non-taxable income for us being carried as opposed to cash, which would be a taxable transaction and in fact in 2008 we had some tax leakage that we're now recovering. So that's one pretty solid element. The other part of the strategy I think that's important to us from an investor standpoint, our partners, we're investing in or they're investing in plays that are huge in size. Sometimes not well-defined and so the carries actually benefit them as well in the sense that they get to spend their money basically to develop proved reserves as their drilled in large areas. And I think that has increased the total value to us as well. David Heikkinen – Tudor Pickering & Co.: Okay. Thanks.

And now we'll open the line up to Goldman Sachs, Brian Singer. Brian Singer – Goldman Sachs: Thank you. Good morning.

Good morning, Brian. Brian Singer – Goldman Sachs: I wanted to follow-up on Scott's question and your comments with regard to using a good acquisition and divestitures at the process center. I can see in your guidance that you expect to be a net seller through 2011, but can you talk to how large the opportunity set is in the current market in terms of new plays that you maybe looking at that could be a source of acquisitions now and divestitures later?

Sure. We are developing a number of new plays, and we don't know if any of them work out of course, and we publicly disclosed one of those plays is not new to the industry, but new to us which would be the Eagle Ford and remains to be seen how big our position is. We're taking a little different geological approach to it than maybe some other companies are. So we'll see how we do in the acreage acquisition and then decide at that point. If our position has increased to a size where we want to monetize part of it. We have some other plays around the country where we think we have the capability of acquiring more acreage and selling some of it. But one thing for sure is there is no shortage of companies, especially big companies, big international companies that are looking for an entry into some of these plays, and we have demonstrated that we know how to work a deal with big international companies. We know how to get along with those companies. We know how to deliver results to them, and so we have people from all corners of the globe these days coming into see us, to talk about things, and we are excited to have those conversations and believe that some of them will lead to events in the future that are substantial, that lead to substantial increases in shareholder value. Brian Singer – Goldman Sachs: So I guess to be to quantify it then, what level of willingness do you have then to use the balance sheet, in other words, as you are projecting currently 1 billion to 1.3 billion or so of net inflows from net divestitures to the extent that you see opportunities, what could that swing to in terms of at least temporarily net acquisitions in any given year?

Are you saying how much could it go down from what we projected? Brian Singer – Goldman Sachs: I guess you're currently projecting cash inflows from divestitures, but you're highlighting the potential to make some significant leasehold acquisitions and then later so and I guess the question then is what could the number go to in terms of a net cash outflow at least temporarily in a given year?

Brian, I don't think it's possible. We've said that we're going to generate amounts of cash flow increases, cash resource increases in 2010 of 325 million to 900 million overall and with regard to properties of a billion to a $1.350 billion in 2011 on the property line, we expect to be cash positive 900 million to 1.25 billion, and for the company overall 550 million to 1.25 billion. So we have acquisitions of acreage budgeted inside of those numbers and if we were to see some deal that would require us to go above that, then we would simply do an offsetting divestiture to balance that. These are the numbers that we will manage the business to deliver to just as we did in 2009. We'll do it in 2010 and 2011 as well. Brian Singer – Goldman Sachs: Thanks. That's helpful. I think perhaps we didn't appreciate was maybe the point that you just made that any additional acquisitions you would balance with additional divestitures if I got that right.

You do have it right. Brian Singer – Goldman Sachs: If I could ask one number question lastly to, Mark, I think at the analyst meeting he'd highlighted about 12.2 billion in net debt. Unfortunately I don't recall whether that was end of third quarter number or that day number or something projected for the end of the year, but it seem like net debt was a little bit less than a 11.6 billion or so in the third quarter and I just wondered if you could clarify.

Brian, I don't remember exactly what I said at the analyst meeting, but I can tell you what it is right now. As of September 30th and it will take me just a second to flip to my balance sheet here in details. Our senior notes payable were $10.4 billion and our credit facilities outstanding were 1.630 rounded. So the total of those would have been our gross debt and then other cash would have $520 million would have been subtracted off that to get to net debt as of September 30th That is about 11.5 net of cash. Brian Singer – Goldman Sachs: Okay, thanks. Perhaps I'll follow up with Jeff after. Thank you.

And now we'll open the floor up to Wi Romaldo with Stone Harbor Investments. Wi Romaldo – Stone Harbor Investments: Hi, just two clarifications. It's not clear from the press release the two midstream revolver. Were they fully drawn or not fully not drawn?

Well, I don't know about the press release being clear but what I mentioned was that we had a lot of undrawn facilities, and the Chesapeake midstream joint venture was $12 million drawn out of a $500 million facility at September 30th and the other midstream facility was undrawn

So $12 million drawn on 750 million midstream facility. Wi Romaldo – Stone Harbor Investments: Okay. And the other one is can you give a sense of what was the prices that were used to come up with a reserve number, because if you look at NYMEX, the price was actually up from June to September.

If you go to Page 3 of our press release, you'll see what prices we used during the quarter. Jeff, you want to go ahead and give her those?

Yes, the prices used at the end of the third quarter were $3.30 per Mcf NYMEX base prices or basically Henry Hub base prices and $70.21 per barrel. Keep in mind that the price needed to calculate reserve is the price in the cash market. I’ve seen several folks had looked at the NYMEX futures price at the end of September and keep in mind that would have been for the November contract. So keep in mind it's the cash price that matters for the calculation of reserves at the end of each quarter.

Jeff, I think I said that's on page 5, the fifth paragraph down. Wi Romaldo – Stone Harbor Investments: Okay. Thank you

Thank you.

Now we'll take a question from Ray Deacon with Pritchard Capital. Ray Deacon – Pritchard Capital: Yes, hey. Mark, I was wondering is that the comment you made about the reserves at the year-end 2010 and 2011. Is the gas price assumption there north of $6 or do you still think you can meet or exceed that if gas were in the $5 to $6 range given that well cost declines that you've seen?

Well, I think that we're using a normalized price that's higher than what it is today, and I'm going to guess that we fully recover at something between 6.50 and $7 and probably – do you want to take that?

I think I've been right at $5 –

Fully recovered 5.50.

And then remember, Ray, the price that we used at the end of the year will be a 12-month arithmetic average for 2009, of which 11 months are already set. Ray Deacon – Pritchard Capital: Right. Okay. Got it. Great. I guess it seems like a number of pipelines proposed in the Marcellus and Pennsylvania and I guess can you talk at all about transportation cost, where do you think that could be heading or where it is now or any kind of comments on that?

Well, we are involved in, I think, virtually every pipeline project that's being contemplated in the Marcellus, and, Ray, we don't expect any of them to change kind of the way that our cost of transportation is up there right now. Some of the money enhances. So, we still think the northeast would be a Henry Hub plus market for years to come and there are certainly some takeaway issues there, but there are in all place, but with declining production across the system, we're seeing a dramatic decline in differentials and I think I noticed last month the differentials were the lowest they've been in three years inside our company. So we expect that you will see in an industry that now is going to be long pipe and short gas as compared to long gas and short pipe over the last few years, you'll see transportation or differential get reduced to basically the true cost of transportation or perhaps inside of that in some areas. I want to throw in one thing. We'll recover about half of that 2.2 Tcfe suppressed reserves, when gas prices hit about $4. So it comes back pretty quickly and we get all it back in the 5 to 5.50 range. Ray Deacon – Pritchard Capital: Thank you.

Okay, Ray, thank you.

(Operator instructions). Now we'll hear from Hartford Investment Management, Adrayll Askew. Adrayll Askew – Hartford Investment Management: Yes, can you give us some more detail related to the Bossier Shale, I mean, a lot of people are talking a lot more about this, I guess the return and then the potential impact of the 175,000 acres that you have prospective there for the Bossier.

We're excited about the Bossier. Let's see, Steve, one well and producing probably 90 days now?

Closer to that. .

And I think we have that well, probably a little less than 6.5 Bcfe….

I think it was.

25 or something like that.

Between 5 and 6.

So it stays somewhere between 5 and 6 on our first 12. Not a bad start. I believe we are drilling two additional Bossier wells now or just one?

Maybe only one’s drilling.

We have one drilling.

So the reason why you are not going to see a huge ramp at least from us on Bossier drilling is remember that the Bossier sits above the Haynesville, and a lot of leases in Louisiana have what are called “Pugh” clauses which allow you to hold only those rights that you drill through, and so, if you were to drill a bunch of Bossier wells with leases that have few clauses on them, you wouldn't be able to hold the Haynesville. And so right now we are looking for areas where we have leases that don't have few clauses, where we can go drill from Bossier well, get some more information on the play and still hold our Haynesville right. So right now, only one out of our 35 rigs is working on the Bossier, but that could increase in the years, certainly not in the years, but in the weeks and months ahead. But it looks like it's a big time play. I think some day we'll probably start talking about the big five shale plays and I think the Bossier will be the fifth and with 175,000 acres we think that we're probably in a position where we've more acreage in the core of that Bossier play than probably anybody else. Adrayll Askew – Hartford Investment Management: Okay. That's helpful. From an incremental cost standpoint on wells that you're drilling to the lower Haynesville from an incremental cost standpoint to produce from the Bossier what would that be?

I don't think you would see us develop kind of do a lateral concept. We have done that years ago. And we often (inaudible) in fact sometimes we drill four lateral from one well bore. We reduced our drilling time and cost in the vertical section as a whole to such a level that to add the engineering complexity to having two horizontal laterals open in one well bore, we just don't think the additional risk and cost is worth it. So, I think you'll see us follow a program of wells drilled specifically for a particular formation rather than multilateral well. Adrayll Askew – Hartford Investment Management: Okay, that's very helpful. And then on another topic can you give your perspective on the potential for international development of shale gas, how focused are you on that in the near-term and would we hear any announcements from you guys I guess related to that?

Well, we are very focused on it, and we think it's a key to the world being able to transition both to a lower carbon future and also for the world to transition away from oil as patient demand we think overtake basically the world capacity to increase supply in the years ahead. And so natural gas would have to carry much more of a transportation sector load than what it's doing today. We're in the 50/50 JV with Statoil, and we are scarring the world for opportunities and so I can't tell you when you'll see a press release. I would imagine sometime in 2010 we will find something that's actionable and we or they would think about it when the time comes. Adrayll Askew – Hartford Investment Management: Okay, that's helpful. Can you speak to the longer term impact that that would have on the supply side and I guess speak to anyone else that would take the other side and trade and say that in aggregate that would tip the balance from a supply standpoint?

Well, when you think about the size of the markets on we consume 85 million barrels of oil a day, 84 million barrels of oil a day, that's a 350 Bcf a day market for oil, the whole world market for gas right now is 280 Bcf a day. So our view is it wouldn't take much in the way of market share gain in the transportation sector to have an impact on gas demand. So we don't think shale gas is likely to be any kind of a tipping point in the years going forward. In fact, if you look at NLG liquefaction facility construction schedule, you'll see that after 2014 or so there is not much coming on. So we think the world will continue to prefer clean energy. The world would prefer energy that is distributed in its supply from more places than oil currently is we think the future is bright for worldwide demand increases for natural gas and if the demand is there, the supply would be there and shale gas would meet at least part of that demand increase. Adrayll Askew – Hartford Investment Management: Okay, thanks, Aubrey, very helpful.

Thanks

And now we'll go to David Cameron with Wells Fargo. David Cameron – Wells Fargo: Hi, good morning, everybody. Aubrey, can you talk a little bit about operating up in Appalachia? Is there any progress done as far as force pooling or anything along those lines that you can talk about?

There are three states involved with Virginia, Pennsylvania, and New York. In New York still under drilling moratorium. New York does have a force pooling walk [ph]. It has some favorable attributes to it. It has some negative attributes to it. We expect to come out from under that moratorium at some point hopefully later this year in 2010. In Pennsylvania, everything we do is on a voluntary pooling basis and the pooling that we can do, which is those of you not familiar with the concept, pooling is simply the amalgamation of leases into one pacing unit from which all royalty owners and working interest owners share proportionally in the production from any well drilled in that unit. We are voluntarily forming those units and some of our leases have no limits on the size of units we can create. Others limit us to 640 acres, others 640 acres plus 10%. Same in West Virginia. We actually there have a lot of legacy leases that actually don't allow pooling. We're very restricted on pooling and we have to go back and reform those leases to be able to drill the lateral links that we need. So it's a laborious and tedious process, but we've got a lot of people and work on it, we have lots of goodwill with our minimum owners. We don't see that really, if you are asking if that's a strength hold or impediment on development of our assets up there, we don't think that that will be. David Cameron – Wells Fargo: Yes. That's a good color. And then can you talk about, as far as Chesapeake or the industry is concerned, are there’s currently infrastructure constrained whether it's gathering processing pipeline, some of the issues we saw August, September, those got away. Can you give me a snapshot of that?

I think Steve Dixon handle it.

A lot of it is green field and so there always be some construction and infrastructure that needs to be built, but there's lots being done. And so, there always be some lag and some need for years to come in the Marcellus. David Cameron – Wells Fargo: But as far as currently, are there current constraints out in the field that you guys are experiencing whether it's Appalachia, Marcellus or whether it’s Haynesville, Barnett, whatever?

Well, nothing more than usual again with our activity level and build out. Some back east where gas coming in and out of storage can create higher line pressures that get back some gas out, but there's no good projects or not a lot of gas backed out right now.

In a lot of our northwest county gas won't be coming on until second half of 2010 as a result of some big projects we have there, but that's related to kind of lag big pipe inside our urban environment. It's just everyday challenge to get that done, but there's nothing out of the ordinary. David Cameron – Wells Fargo: Good. Thanks.

Now we'll take our question from Lewis Ropp with Barrow Hanley. Lewis Ropp – Barrow Hanley: Yes, good morning, guys.

Good morning, Lewis. Lewis Ropp – Barrow Hanley: I apologize if I missed this, but in your format for your cash flow projections, I was curious what you have lumped into the other category that looks like it's about 600 million to 800 million for this year and next year.

Jeff will take that for us.

Good morning, Lewis. Lewis Ropp – Barrow Hanley: Hi, Jeff, how are you doing?

Good. An easier way to think about it is field display gather be from the prior guidance next and a cross reference line items, but the specific items that are in the other category would be the geophysical cost, the midstream infrastructure cost, the other PP&E, along with the items that were previously in the inflow load section of the prior guidance, which would have been midstream equity financings and system sales, as well as midstream credit facility draws and repayments. Lewis Ropp – Barrow Hanley: Okay. Great. I was just thrown off a little bit by the changes in the sign convention and some of that stuff, trying to do it while we were on the call but that –

Hopefully the simple you will make it easier following going forward. Lewis Ropp – Barrow Hanley: I agree. I think it will. The other thing I want to ask, Aubrey, at the end of the second quarter, you had talked about the excess cash generation and increasing proved reserves, getting you to an investment grade metric by the end of next year. I'm not so much worried about the movement in the reserve just based on the commodity price at a point in time, but I had some conversations with you about that excess cash generation and just if you can comment on where you think you stand now and if that's still a goal and how you think we can get there if it is for 2010.

Sure. I'll take a whack at it and then let Mark get it n as well. So let's start with net debt at $11.5 billion and we have previously projected to be, to finish the year '09 at 14 Tcf of proved reserves based on what we think gas prices are going to be and probably in the year at about 13 Tcf with 1 Tcf or so suppressed. So if you skip forward to the end of 2010 and assume that for some reason we don't pay back any debt and still got 11.5 billion of debt, you would be at about 16 Tcf of proved reserves then and so that would result in a deleveraging on a relative basis by about 25% per Mcfe. That's the way I look it. I'll turn it over to Mark. But one final thing is just a real simple way to think about our business is that going forward we’re going to produce about 1 Tcf a year and we're going to find about 3 Tcf per year so that's 2 Tcfe of minimum amount of net reserve additions and we think we can do that indefinitely. So if you just say $12 billion over 2 Tcfe, you can begin to see that we'll delever by $0.15 or $0.16 Mcfe, every year kind of add infinite item. And then one other way to think about it in context is to say what companies today have proved reserves of about 2 Tcfe. Well, as of 12/31/08 that would be companies like southwestern companies like Plains [ph], companies like EXCO, companies like SandRidge, Cabot, we create a new one of those inside our own company, every year, and we do so without really any risk and we do so in generating positive cash resources. So that's kind of the way I think about value creation is any number of well respected highly valued companies we create a new one of those every year and also create positive cash in that process, Mark?

Yes, I agree with all of that, and the bars have moved around from time to time depending on the price outlook that the rating agencies and certainly in this low price environment, given some of the issues that the rating agencies have had with their own business I think, safe to assume that they are much more conservative these days. But generally historically anywhere in the $0.60 to $0.65 total proved reserve to debt, if your proved undeveloped it's not more than 35% to 40%, it's traditionally been viewed as being near investment grade and certainly we will be there on the other standards. The other parts of our balance sheet there going to have an important part too. We talked in the last quarter extensively about the Chesapeake midstream business and the potential ultimately to establish some value marks there that could add a few billion dollars of value to our business without adding any net debt. And so historically the rating agencies have had a little bit of a challenge trying to assign value to things like proved undeveloped acreage, drilling rigs, building real estate and our midstream businesses, but certainly that's a component and we're driving the car in the right direction, and I'm sure that we'll end up in the right city. Don't know when that might be. Lewis Ropp – Barrow Hanley: Okay, guys, well, thank you very much. That helps a lot.

Now we'll move on to Energy Equities Incorporated, David Snow. David Snow – Energy Equities Incorporated: Can you talk about extension of the Haynesville into the deeper direction going to the south I guess and the west is it?

Yes, it's been the same. Augustine County and then Southern Shellbee as well. We haven't really played that. There have been some nice wells that have been brought in down there, I would point out that we report our Haynesville wells on 22/64 choke, other companies on a 24, and there was a pretty flashy result in the last couple of days that was reported on 37/64 choke. You can get these 15 million a day, 20 million a day wells up some pretty big numbers if you want to use a big choke. But that's about 2,000 feet deeper than we're playing it and so we have some leasehold down there, a lot in central Shellbee County. We're watching it carefully. I think at least one of those wells had reported walk off over $15 million. So you have to, when you see the well results you don't often see the cost associated with them, but we view that it looks like it's going to be a good area and if there's any lease hold to be had down there we hope to be competitive with it, but right now we kind of like the sweet spot we're at. David Snow – Energy Equities Incorporated: Are you still pursuing any more oil plays?

Every day and in every way. David Snow – Energy Equities Incorporated: Any color on that?

Other than the stuff is hard to find, and we're working at it hard, and our county wash plays got $100 million barrels of oil alone, net to us we think and we're doubling our rig count in that area to get some more of that. We have a number of oil plays underway. We've had a significant share in the Cleveland sand play and the Anadarko basin developing plays in the tong wall [ph] and some other traditional Pennsylvanian age formations that sporadically produced across the Anadarko basin and we've had some success in the Permian Basin as well and we're looking at, we've got prospect in the Rockies that most people are aware that we're working on and it's oil as well, so more to come on that in 2010 we hope. David Snow – Energy Equities Incorporated: Great. Thank you very much.

Thank you, David.

Now we'll go to Dan McSpirit with BMO Capital Markets. Dan McSpirit – BMO Capital Markets: Gentlemen, good morning, and thanks for taking my questions. On your Haynesville Shale, well cost update of $6 million or less, one, how low can you go? I ask that in light of the earlier comment on lifting cost and services related costs. Maybe having bottomed here. And then two, can you speak to similar joint complete cost reductions elsewhere say in the Marcellus where you illustrate an average drilling complete cost of I think $4.5 million per well?

Sure. I got a couple of thoughts and then turn it over to Steve. The $6 million is not a level that we're at across the board. Some of our rigs are capable of doing that, but the vast majority are not there yet, although I think we're pretty routinely inside the $7 million number. So rather than focus on trying to get below 6, I think Steve and his team is trying to get more of our existing 35 underneath 7 and driving it towards 6. I'll let him talk about things that we're doing in the Marcellus that could reduce our cost there.

Finish up on Haynesville, we're just continuously improving performance. We're still doing that in the Barnett and the Fayetteville even though we've been there for years now. So that will continue to happen in the Haynesville. In the Marcellus, still a lot of science there, still a lot exploring various areas, still getting our service industry up to speed. And so those costs are not where we want them, but are moving the right direction and we'll continue to do so. Dan McSpirit – BMO Capital Markets: Very good. Thank you.

Now we'll take a question from Ryan Kelly with Prudential. Ryan Kelly – Prudential: Hi, good morning. Thanks for taking my questions. I apologize you may addressed this question already, but update on the new structure hedging facility that you guys talked about on the analyst day and I think it was included in some of your recent filings. Is that still be up and running?

It is, Ryan. We have a $10.4 billion structure or secure hedging facility with 13 counter parties. It is fully up and operational. We're just in the last weeks of moving over some additional collateral that would allow us to go to the full amount, but we can hedge today quite a lot and it's ready to roll. Just waiting on a recovery in gas prices. Ryan Kelly – Prudential: When we think about the collateral and naturally the banks don't use PB10s, but eased on priced ex, but the values have been going down. Is there any risk that the collateral requirement in the hedging facility can crowd out the collateral for the credit agreement or the bank facility, don't need to go around?

Structurally, there's protection at the bank level for doing that. We have to maintain 15% of our reserves in an unpledged or sort of super collateral negative pledge, if you will, to protect the bank situation. Having said that, we just went through our collateral redetermination with the banks although we didn't have a formal reserve redetermination we do that annually. We did provide a collateral update package and the banks accepted it as it was. So today, we're sitting there with several billion dollars worth of unpledged collateral at either place, either the hedged facilities or the bank, and I guess we could choose to reduce the hedging facility since obviously 10.5 billion right at the moment is about 10 billion more than what we got on. Ryan Kelly – Prudential: Sure. The bank covenant leverage at quarter-end was?

The bank coverage ratio? Ryan Kelly – Prudential: The covenant leverage for the credit facility.

As to the debt per EBITDA? Ryan Kelly – Prudential: Yes.

I don't have the exact amount. We'll have that in our Q in the next couple of days. That is calculated in the treasury and not in our finance department, so I didn’t have that. Ryan Kelly – Prudential: Sure. Okay, thanks guys.

Thanks, Ryan.

Now we'll open the floor up to Biju Perincheril with Jefferies. Biju Perincheril – Jefferies: Hi, good morning. First, I was hoping you can give us an update on the two wells that you drilled and (inaudible) how those wells are holding up maybe a 30-day rate if you have it?

I don't think we have it but the rates were flashy because the wells had been shut in for six months or so. It has not changed our opinion that East Texas is not likely to be as good as the core, which I think hopefully, it's not a surprise to anybody. One of the things that we will do, Biju, is that we have started a process of selling or offering for sale I should say a portion of our acreage in the Haynesville that we are not going to be able to get to. Other companies will like that very much, and there's a lot of would be in East Texas and some of it would be north of Shreveport. It’s what we do all the time, basically trim away some things that either don't look good to us and might to other people and some things that perhaps we're not as focused on or can't get to. I'll say that it wasn't our intention for those wells to create a stir. We think they will produce about the way that we have projected East Texas wells to produce. Biju Perincheril – Jefferies: Okay. And you had mentioned that in the analyst meeting you were seeing pretty significant pressure draw downs. Has the pressure stabilized? Or we saw being a pretty significant draw downs there?

When you say pressure draw down are you talking about in those two wells or in general? Biju Perincheril – Jefferies: No. In those two wells.

They have big initial decline rates and probably would not have come in at 15 million a day if they haven't been shut in for a while. We don't report individual production rates and certainly won't for those two wells, but I just say that they are performing as we would expect them to and we think that's going to be encouraging for some and maybe not for others. Biju Perincheril – Jefferies: Okay. That's helpful. Thanks.

Now we'll hear from Brittney Capital with Bob Clements. Bob Clements – Brittney Capital: Good morning, guys. Probably the Obama administration doesn't seem to fully appreciate natural gas as a part of their long-term menu of energy sources. The gas industry kind of been out lobby by the coal industry in the past as well. What's the industry doing to change this?

I think we are engaged across the board in a way that we never had before. We're communicating in ways we never had before. I think most visually we have formed something called America's natural gas alliance. 29 of the 30 largest independent producers of natural gas in the U.S. and Canada, and we have committed a penny in Mcf of production, which is I guess around $80 million, $90 million a year, and we will use that money to drive home our point of natural gas abundance. And when you realize that there is natural gas abundance then you can begin to think about environmental and energy and national security issues differently. Our problem really isn't so much the coal industry, creditability factor of that industry is pretty low, and I think what our biggest challenges are just simply history. Remember, this is an industry where we haven't been able to say our product is in abundance most of the past 20 years, and today we now say that and it takes a lot of people time to catch up to where we are from where we were four years ago. You talk about natural gas and scarcity. I think the other thing is some traditional users of natural gas are not particularly helpful to us. They do not want to see markets for natural gas develop, and we have our work cut out to convince those folks that there is plenty of natural gas for them and there's plenty of natural gas to begin convert our transportation system away from oil to natural gas in a way to reduce our reliance on coal and the power sector. All those things take time. I would lobby it if our president were as conversant about the advantages of natural gas as he is with some other technologies that are either affordable or scalable or even in some cases existent. So we got some work to do there, but we will stay up. Bob Clements – Brittney Capital: Thanks, Aubrey.

Very good. Thank you. I think we're all done. We appreciate your questions. We look forward to further conversation. Please get hold of Jeff if you have any follow-up. Thank you.

Ladies and gentlemen, that does conclude our conference for today. Again thank you for your participation.