Jeff Mobley - SVP of IR and Research Aubrey McClendon - Chairman and CEO Marc Rowland - EVP and CFO Steve Dixon - EVP, Operations and COO J. Mark Lester - EVP, Exploration

Michael Hall - Stifel Nicolaus & Company, Inc. Scott Hanold - RBC Capital Markets Shannon Nome - Deutsche Bank Securities Jason Gammel - Macquarie Research Equities David Heikkinen - Tudor Pickering & Co. David Tameron - Wachovia Capital Markets, LLC Brian Singer - Goldman Sachs Gil Yang - Citigroup Thomas Gardner - Simmons & Company International Joseph Allman - J.P. Morgan [Eric Calamares] - Wachovia Marshall Carver - Capital One Southcoast, Inc. Monroe Helm - CM Energy Partners Jeff Davis - Waterstone Capital Biju Perincheril - Jefferies & Co.

Good day, everyone, and welcome to the Chesapeake Energy conference call. Today's conference is being recorded. At this time I'd like to turn the conference over to 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, and Mark Lester, our Executive Vice President of Exploration. Our prepared comments should last about 15 minutes this morning and we will then move to Q&A. I now turn the call to Aubrey.

Thanks, Jeff, and good morning to each of you. I believe our results for the year 2008 were very good, especially when you consider that we were required to take a non-cash after-tax impairment charge of almost $2 billion. And yet we were still profitable by more than $600 million for the year. Stripping away impairments and other non-cash items, during 2008 we earned almost $2 billion in net income on record production of 843 Bcfe. Operating cash flow exceeded $5 billion and adjusted EBITDA exceeded $6 billion, both of which were company records. Also in 2008 we sold undeveloped leaseholds that had a cost basis of only $1.1 billion for $5.3 billion in cash and $4.6 billion of future drilling carries, creating $8.8 billion of profit in the process. And importantly, we retained a stake in the assets worth an indicated value of $26 billion. On the operational side we discovered the Haynesville Shale and built the dominant leasehold position in this field, which we expect to become the largest producing gas field in the U.S. by mid-decade. Furthermore, we helped prove the Marcellus play as highly commercial and we have also established the largest leasehold position in that play. Our Barnett Shale production increased over the past year by 50% to 925 million per day gross operated and 610 million per day net. In addition, our Fayetteville Shale production increased over the past year by 80% to 285 million per day gross operated and 180 million per day net, even after we sold off 25% of our assets in the play to BP in the third quarter. Also during the year we established through our joint ventures with Plains, BP, Statoil a transaction template that we believe will become the industry standard. Further, we are engaged in discussions with several large international energy firms wanting to enter into new joint ventures with us. Through our three JVs we also created a $4 billion receivable that is not on our books, but will be highly beneficial to us in the next few years as we will have three other companies paying a significant share of our drilling bills during what will be a time of exceptionally low drilling costs. This represents almost 3 tcfe of future reserve additions at no capital cost to Chesapeake. Simply put, we created more value in 2008 than in any other one-year period in our company's history. In fact, I believe we created more value in 2008 than we did in the entire five-year period from '03 to '07, when our stock price increased by 400%. Despite this, our stock price in 2008 declined by 60% amid the global financial crisis. Nevertheless, Chesapeake's value creation accomplishments of 2008 were real and they remain embedded in our company to be recognized and rewarded in the months and years ahead. We have prepared the company well to withstand rough financial markets and low near-term gas prices, and our substantial competitive advantages have positioned the company to prosper in 2009 and in 2010 and, in fact, for decades to come. I will next highlight that Chesapeake has at least four competitive advantages that should enable us to be an industry outperformer for years to come. First, our asset quality is second to none. This period of low gas prices will drive home what we have been saying at recent energy conferences, that is, while the last quarter of 2008 may have been all about balance sheet strength, from here on it's going to be about asset quality strength. And the foundation of asset strength in the U.S. in 2009 and beyond we believe will be determined by how skillfully companies have positioned themselves into the four best plays in the United States - the Haynesville, Marcellus, Barnett and Fayetteville Shale, which we now are referring to as the Big 4 shales. If a company is not in these plays in a major way, we do not see how such a company creates value competitively with those companies who are in those plays. The simple reality is this conventional assets and marginal unconventional assets will see higher finding costs over time, while the Big 4 shales will experience lower finding costs over time. For years I believe major industry players have all had about the same type and quality asset base, but now I see a steadily widening gap between the Big 4 share haves, of which there are not more than about 10 companies, and the Big 4 shale have nots, of which there could be as many as 10,000 companies in this industry. Over time, the haves will have lower finding costs, lower operating costs, lower maintenance CapEx, lower risk, higher returns on capital, and higher growth rates. On the other hand, the have nots will be burdened by higher finding costs, higher operating costs, higher maintenance CapEx, higher risk, low returns on capital, and lower growth rates. The differences can be discerned today by close observers of the industry; however, in years ahead, the differences between the haves and the have nots will be there for all to see plain as day. I would like to emphasize that Chesapeake is the only company with a top two position in these four big shale plays. No other company has a top two position in more than one of them, and to acquire a top two position today in one of these Big 4 shale plays would be almost impossible. Chesapeake has a unique and irreplaceable asset base in these Big 4 shale plays and this asset base will drive relative outperformance for years to come. Chesapeake's second major competitive advantage is our $4 billion of drilling carries. Created by our three joint ventures with Plains, BP, and Statoil, these carries are as good as gold. They will be earned by us tax free and will be received over the next four years with approximately $1.2 billion coming to us in 2009 and about $1 billion in 2010. And as drilling costs fall significantly in 2009, these carries will be worth even more as they will enable Chesapeake to develop more reserves than we had previously modeled in a higher-cost world. I wish we could have booked this $4 billion as a receivable during the fourth quarter of 2008 or perhaps even factored this receivable for cash. It sure might have saved some balance sheet anxiety along the way. Nevertheless, these carries are real, they are big and they are unique in this industry. Chesapeake's third major competitive advantage is our hedge position. Today we have hedged almost 80% of our projected 2009 production at an average NYMEX price of approximately $7.71 per Mcfe and as of last Friday, we had a positive marked-to-market gain of $1.6 billion on our open positions, which of course, after yesterday's gas price decline, would be even larger today. Few companies are as well hedged as we are, and the days of companies saying we don't hedge because our balance sheet is so strong will probably come to an end under investor pressure as during this time of low gas prices it will be seen that a tremendous amount of balance sheet strength can be lost if a company is not well hedged during an extended period of low gas prices. Even though the economy is still weak, with the gas rig count dropping so quickly, our bias will be to maintain our 2009 hedges, but look for an opportune time later in the year to lift some or all of our second half of 2010 hedges and maybe some first half 2010 hedges as the year rolls along. Chesapeake's fourth major competitive advantage results from a combination of the first three, and it's that Chesapeake can replace its produced reserves with only 15% of its projected cash flow in 2009 and only 20% in 2010. You have seen other companies in the industry report that they will have maintenance CapEx requirements greater than 100% of their projected cash flow in 2009. This is a very important Chesapeake competitive advantage and we believe that investor understanding of our very low maintenance CapEx requirements in '09 and '10 will be a key driver behind why our company will likely substantially outperform its peer group. With regard to today's very low natural gas prices, we are excited about them because the seeds of a gas recovery have been sown and they are being well watered as we speak. In fact, the lower gas prices go today, the better it is for Chesapeake - perhaps a surprising statement you might notice. Well, for starters, we have $4 billion of our drilling costs that are going to be paid for during the next few years. No one else in the industry has anything like this. Furthermore, these carries are worth more in a low gas price environment because drilling costs will be lower. It's even possible that our $4 billion of carries will end up acting as if they are worth closer to $5 billion as drilling costs decline in 2009, perhaps by as much as 25%. In addition, we're more hedged than anyone else in the industry and so we are more able to ride out a low gas price environment with less pain than most others. As to the visibility of the seeds of a gas price recovery being sown, all you have to do is look at the gas rig count. It will likely bottom out in the first half of 2009, down anywhere from 50% to 70% from its 2008 peak, in fact, down to as much as a five-year low. Therefore, by year end 2009 you should see gas production in full retreat in the U.S., setting the stage for a strong rebound in gas prices in 2010 and 2011. Please remember that no matter how bad the economy gets, gas demand cannot fall faster than the 25% to 30% rate that supply can deplete. This fundamental law of depletion will restore gas prices to equilibrium more quickly than most observers believe possible. If you have any additional questions about play results or macro issues, I'll be happy to answer them in the Q&A session, and I'll now turn the call over to Marc Rowland for his further comments.

Thanks, Aubrey, and good morning. Welcome to everyone. My additional comments today will be brief. You may have noticed that our depreciation, depletion and amortization rate for the fourth quarter was down to only $2.12 per Mcf equivalent. This is down from a high of $2.60 per Mcfe in the second quarter of 2007 and, in fact, the last time it was this low was the fourth quarter of 2005. I would also call your attention to our outlook, where we have guided to a full year rate of between $1.90 and $2.00 for 2009. This may well prove to be a high estimate, but assuming it's accurate, at the midpoint of guidance would represent a 17% reduction from the full year 2008 rate of $2.34 per Mcf equivalent. There are several important reasons for this. First, concentration of drilling activity in the Big 4 shale plays, where our finding costs are superior to other shale and almost all conventional plays. The drilling carries, secondly, that Aubrey emphasized that began to kick in during 2008 will be in full force for all of 2009. Finally and very important, reduced service costs that really just began to kick in in late 2008 in our opinion. We are renegotiating rates downward with every vendor, large and small, on every new well. I wouldn't be at all surprised to see our year-over-year costs down in 2009 by over 25% compared to 2008. Nearly every day vendors are approaching us with new, reduced rates and we're negotiating with each and every one of them earnestly. We believe production costs and general and administrative costs can also be lowered, although we have not changed our guidance for either category for 2009. Like most every natural gas producer, recent field differentials to NYMEX have blown out in most basins. Our average differentials, as noted in our release, were a negative $2.07 per Mcf in the fourth quarter of 2008 as compared to only $0.59 negative per Mcf in fourth quarter 2007. While we have some basis protection on for 2009 through 2012, as noted on Page 26 of our release in the Outlook section, it's clearly not enough and has not been enough to protect us fully this year. In Q4 we averaged selling gas in the Barnett for $3.97 at the wellhead, $4.13 in the mid-continent as compared to $6.65 in Appalachia and $6.16 in the Gulf Coast, differentials that we've never in our many years of history seen. This negative bias to the Western basis will cause rigs to come down, obviously, very quickly in these areas, but the question remains - does this get better and how? In our opinion, three ways. First, additional pipeline capacity is generally being added in the worst basis markets. New projects are coming on or will soon come on in Haynesville, Fayetteville and Barnett. Second, we have committed gas volumes substantially to a number of these projects for a fixed firm transportation fee that will get the gas out and into better markets at much less of a cost than the current basis differentials. Third, there is some evidence that Rockies gas production has peaked and may have already begun a decline based on transportation utilizations recently being below 100%. On the firm transportation side, we now have four projects committed to in Haynesville, including the ETC project recently announced and several more that are nearing conclusion of negotiations. We see Fayetteville starting up with NGPL in April, Boardwalk in May, with Fayetteville Express also committed to by Chesapeake for the out years. In the Barnett, there are a host of commitments for projects already in and operating and numerous ones to come on in the near future. As a final point, I want to remind you that CHK has recently concluded two senior note issuances totaling $1.425 billion and the proceeds have already been applied to our revolving credit facility. Several additional liquidity or monetization projects are still under way, but we don't have anything to add firm at this time to report to you. We remain committed to a disciplined spending program that will have CapEx be in line with our ongoing cash resources as we have recently stated. Moderator, with that we'd like to turn it over to the Q&A session, please.

(Operator Instructions) Your first question comes from Michael Hall - Stifel Nicolaus & Company, Inc. Michael Hall - Stifel Nicolaus & Company, Inc.: Quickly on the macro front, maybe if you could talk to your expectations on L&G this year and how concerned you are with the potential for rising imports in the U.S.?

Well, clearly that exists out there, Michael, and I think to get to the answer of it you have to know where the economy of the world goes, especially Asia and Europe, over the summertime. So it's something that we can't know the answers to that, of course, but I think it's baked in the gas prices that there will be more L&G that comes to the U.S. I still think that U.S. gas prices are likely to remain below European and Asian gas prices and so not as much gas will come here as some people are projecting. But it's clearly an issue for us and as long as the economy around the world remains weak I think it will remain a risk and likely keep a ceiling on summertime gas prices. But I do want to emphasize that by the third or fourth quarter - fourth quarter for sure U.S. gas production should be declining pretty sharply, and we think it could be on a year-on-year basis as much as 3 to 4 to even 5 Bcf a day. And so I think that if any L&G comes in it will simply be replacing some gas production that at the margin will be in full retreat. Some people have asked whether or not shale plays and L&G are in competition with each other for the U.S. market and I don't see it that way because shale play gas is only about 8 Bcf a day today versus a U.S. market of about 60 Bcf a day. So I believe to the extent that any L&G lands here, it'll be because the 52 Bcf a day of conventional gas will be declining so rapidly that there's room to bring in L&G. It's certainly a risk, but we believe that depletion risks are greater and will serve the balance of the market even with additional L&G importation. Michael Hall - Stifel Nicolaus & Company, Inc.: And then looking further out, you talk about U.S. production turning perhaps by the third quarter, certainly by the fourth, how quickly or how hard do you think it is to turn that back around and for the industry to start growing again? How many rigs do you think would have to be applied back to the rig count, things along those lines?

I think what you're going to see, even if you get price signals that would encourage the industry to begin drilling again, I think the industry will be slow to do so. A lot of buckets are being emptied today that have been filled up over the last three or four years with cash from relatively strong prices and, as those buckets get emptied during the course of the year, I think that any increase in price in 2010 and 2011 probably goes to fill up those buckets again before you start to see people get real aggressive with the drill bits. I think that if you just go back in time and look at other price declines like we've gone through and other rig declines like we're going through, I think that the decline comes fast, it comes hard, and the recovery comes slow. So I guess the only other thing I would say is that the industry is capable of producing as much gas as the country requires, and if the country, through policy choices that are made over the next few years, decides to favor gas over coal, for example, in electrical generation or decides to more aggressively move our transportation network away from imported oil and towards domestically produced natural gas, the industry can respond very quickly if we're given the proper price signals to do so. Michael Hall - Stifel Nicolaus & Company, Inc.: Then finally, moving over in the Haynesville, can you talk a bit about what you're seeing on the East Texas side of the play?

Well, we're just drilling our first well there. I think it's called the [Rocksboro] well and it's in Harrison County, I believe. And Steve, are we in the horizontal portion?

Yes.

So we probably won't have results there for another 30 days. We don't have an opinion there, although clearly reservoir quality does degrade as you go to the east and so I think our expectations - I'm sorry, to the west, sorry, to the west, rather, sorry - so our expectations take that into account. Most of our acreage is on the Louisiana side; about 75% of our acreage is in Louisiana as opposed to Texas.

Your next question comes from Scott Hanold - RBC Capital Markets. Scott Hanold - RBC Capital Markets: On that Barnett Shale joint venture that you indicated that there's some interest by some international players, can you give a little bit of color? I mean, is this something that we could see in the next couple of months and what does this mean to relative activity levels? I know the Barnett is one area where you guys toned activity down and if you did do a JV, would that require stepping it up a little bit?

Good questions. Let me just say in general that there is a high degree of international energy company interest in gas shales in the U.S. And if you are one of those companies I think as you survey the U.S. gas scene you're looking for companies that have a large asset base in these shale plays and probably you're looking for somebody who's done business with international energy companies. So I think most if not all roads lead to Chesapeake in terms of those conversations. We have multiple ongoing conversations with multiple international energy companies, some of which involve the Barnett, some of which involve some other plays, and we are very excited about the possibilities that could come out of these discussions. And at this point I'd rather not comment on what it might mean to the Barnett or any other play, but just suffice it to say that we have been able to create enormous shareholder value through our 2008 transactions and in 2009 we expect to create additional value by using this template that we've established to introduce various international energy companies into the U.S. gas shale scene. Scott Hanold - RBC Capital Markets: Could you comment on whether or not you'd look to structure it in a similar fashion to what you did with some of your other JVs?

Yes, I think the hallmarks of the JVs are that we have a majority interest and that some of the consideration is paid in cash upfront and some is paid in carries over time. Typically these transactions have all involved a transfer of both production and proved reserves, as well as an interest in the upside. So those are the three features, main features, of the JVs, and I would expect any future JV that we would do would have those same hallmarks. Scott Hanold - RBC Capital Markets: And one question relative to your comment on the U.S. rig count probably needs to drop 50% to 70% from peak levels and we're probably somewhere around halfway there. I know when you guys take a look at your activity levels, I think you're thinking in terms of a 30% reduction overall on premiere peak levels. As the largest producer of natural gas in the U.S., how do you see your role in trying to help balance the market versus letting some of the marginal guys just be forced to drop rigs?

I think we kind of approach it two different ways. First of all, we've done two things that are absolutely unique in the industry. We are almost 80% hedged and we have $4 billion of our drilling bills paid for by other companies. So we've built ourselves to be ready to drill in a time like this. This is the time to drill, when prices are low and while other companies are dropping their rig counts much more aggressively than we are. The reason is because we don't have to; we anticipated this downturn, got ready for it, and built several competitive advantages that, again, are unique. Having said that, we do feel some responsibility to be helpful in the industry and to show some leadership so we've gone from 158 operated rigs to we're at 111 today. We'll bottom probably in late spring around 105 - 106. I do think it is the responsibility of those who chose not to hedge and those who have higher finding costs to have to cut their CapEx much more aggressively than we're going to have to, and this will be a huge competitive advantage as we get a lot of money spent, much of it paid for by other companies, in a time of very low service costs.

Your next question comes from Shannon Nome - Deutsche Bank Securities. Shannon Nome - Deutsche Bank Securities: Any risk, I guess, of nonperformance on the part of your joint venture partners? I guess obviously you have comfort with their capacity and their intention to perform, but I'm wondering if contractually, do they have any outs in terms of cutting back spending vis-à-vis current plans or how is that set up?

They do not have any options in that regard, and we are fully confident that BP, Statoil and Plains can and will meet all of their obligations. Shannon Nome - Deutsche Bank Securities: And the second question relates to one of the concerns we've had surrounding a production response to the rig count. We agree that by late this year we're going to start seeing some pretty aggressive declines; the question is how long it takes. And some of my companies have weighed in that they have at least a quarter - in some cases, two plus quarters - of wells drilled but not yet completed in their backlog. Is that something that you all have as well bottlenecked and/or do you see that elsewhere in the industry?

I think we do see that. We have in the Barnett Shale ourselves, Steve, probably 250 or so wells either not completed, waiting on pipeline, and certainly we've heard others comment about similar numbers, particularly in the Barnett. Logistics there are a little bit tougher. We do not outside of the Barnett ourselves have much of any inventory that's not just the usual due course of business sort of, you know, it takes awhile to complete kind of stuff. Certainly, that's going to add some months probably. I think it's already sort of figured into our numbers. I did mention that there's some early evidence perhaps that Rockies production has already peaked. We saw some more than anecdotal but actual pipeline evidence here in the last few weeks that capacity out of the Rockies was going unused. The only reason that could be in my opinion is production is off already and, of course, drilling there has probably slowed faster because of the wider differentials than other places. So it's one of about a zillion factors that go into trying to estimate whether it's end of third quarter, fourth quarter, beginning of first quarter. I think we get the trend and all of us probably know the trend is our friend here, but as to the exact minute or quarter that it starts, that's pretty hard to guess, as you would think. Shannon Nome - Deutsche Bank Securities: I completely agree. Interesting point you make on the Rockies. One of I guess the other wrinkles here is that it's possible companies are doing some drilling due to rig obligations but not completing the well, deferring completion, thus adding to this backlog. I would think the Rockies in particular would be an area where, if we're seeing excess capacity on the pipes, that that could be readily refilled given a recovery in price. Is that a concern at all?

You know, we don't operate in the Rockies to any great extent at all and so I'm not sure I know the answer to that. Our closest connect there is with our own joint venture with Delta in DHS Drilling. Almost all of our rigs are laid down now in that venture. I think there's three or four operating out of 18 or 19 capacity. So I'm not really seeing any evidence nor have I heard of anything where in the Rockies they're drilling but not completing. But certainly that's one option if you've got a drilling rig commitment or if you've got perhaps a lease that allows you to establish commercial productivity without fully completing the well and turning it on. I'm sure there's some of that going on, without question.

Your next question comes from Jason Gammel - Macquarie Research Equities. Jason Gammel - Macquarie Research Equities: I had a couple of questions on Haynesville results. Aubrey, have you changed what you're thinking about in terms of IPs or have you really come to what you think is going to be optimal in terms of lateral link and frac stages at this point? And then further, would you have any comments on what you're seeing in terms of decline rates after six months?

Well, we continue to refine our pro forma with really monthly results coming in. We are still seeing a 6.5 Bcfe pro forma as the best fit. We have had to adjust the model to account for the really high IPs that are coming in; however, we continue to layer on top very aggressive first-year decline rates. I think, Steve, we're at 82% to 85%? I think 82% first year declines. So we don't know if they'll actually decline quite that much, but that's what we're modeling. That's what you almost have to model when the wells come in at 10 to 15 to 20 million a day. And in all likelihood the wells that come in at 20 million a day are going to be better than 6.5 Bcfe. So, you know, as you look across the Barnett and the Fayetteville, there are areas that are better than others and we're going to see that in the Haynesville despite the homogeneity of the rock, that there'll be still some sweet spots. And so far we're seeing some of those emerge, but even the wells that appear to be not 20 million a day wells are still comfortably fitting our pro forma. So we're excited about what we see, and of course you're seeing almost monthly additional confirmation from other operators of what they're finding in the play as well. And I think the industry is kind of coalescing around this 6 to 7 Bcfe range. You have noticed that some operators have had trouble drilling horizontal wells in the play to date. And I'm sure they'll get that straightened out, but in the meantime it's been a big competitive advantage for us to be able to hit the ground running here, having already been successful in other horizontal plays, specifically the Barnett and the Fayetteville. Jason Gammel - Macquarie Research Equities: I'm not sure if you're going to be able to comment on this or not, but a Barnett Shale joint venture, would you envision that that, would your existing production be a component of a joint venture or would that be essentially undeveloped acreage only?

Oh, I think there's several ways to approach that. First of all, some companies are interested in more kind of starter set type opportunities and others might be interested in larger opportunities. So I think what I mentioned before is that a feature of [successful] JVs to date have been some element of existing production and reserves and then the upside associated with acreage in the area. So I would expect that any Barnett JVs we do - or, for that matter, JVs in other parts of the company - would follow that successful template that we've established so far. Jason Gammel - Macquarie Research Equities: Maybe one more bookkeeping one if I could. The reserve additions, would you be able to provide what percentage of those additions were PUD or if your overall PUD percentage has changed materially?

I don't have the exact addition of PUDs versus PDPs, but Steve, our PUD percentage was almost exactly the same. Jason Gammel - Macquarie Research Equities: Which was what?

34% or 35%. I think the answer is - without having the exact answer and knowing that our PUDs did not change in component - would not have been proportionally different than it's been in the past.

Your next question comes from David Heikkinen - Tudor Pickering & Co. David Heikkinen - Tudor Pickering & Co.: Marc, you casually mentioned that services cost could be down 25% year-over-year; for every new well, you're driving rates down. I'm curious about two things. One, can you give us some thoughts as far as the breakdown of those services on the pressure pumping versus drilling side? And then a follow-on question as far as can you give us any update as far as leasing and kind of the current rates for each of the plays where you're doing some leasing - Haynesville, Marcellus primarily?

Sure. I'm more familiar with the first part of that question. The pressure pumping costs are coming down. Of course, we have a venture - Frac Tech - where we own 20% of it and so we're pretty close to that business. But as pumping services lagged coming up, they're now lagging coming down a little bit because of the backlog of wells that Shannon referenced and we talked about earlier in this call. But we're now seeing those costs coming down full force really in the middle of this quarter and going forward. Drilling rig rates we talked about in our last call. We actually had an example of the Haynesville 1,500 horsepower rig that we were offered by a vendor and actually are paying - Steve, was it $10,000 a day or thereabouts for that rig?

With top drive I guess it'd be around $11 -

Yes, with top drive $11,500 or something like that. And at the peak, that particularly item would have probably been at $24,000, $23,000, something like that, a year ago, so really substantial rig rate decreases. Steel prices, of course, have fallen considerably and will be going down, and just about every other component - diesel costs, particularly transportation costs surrounding trucking and every other item is down. So I think 25% is really a conservative estimate on year-over-year. As we talked earlier, the rig count goes down on the gas side to 700, 650, 800, whatever the number ends up being, that will be off so substantially that the capacity that was built to service basically a 2,000 rig count is still in place and will remain in place. And I believe based on conversations we've had with our various vendor partners that they're going to be more concentrated in market share rather than margins going forward. So that's my flavor of what's going on in the service side. Aubrey, do you have any comments on acreage?

Yes, sure, I do. David, certainly we've seen acreage costs decline across the board and it's been extremely helpful to us. You might have noticed that our forecast for CapEx for acreage crept up a little bit this go round versus where we were with our last guidance in December, and the reason for that is simply we don't have clarity on whether or not our JV partners are going to share with us in additional acreage purchases this year. They have the right to share in that acreage on either a monthly or quarterly basis, and our acreage gets offered to them at a promoted price and so it's possible that some of them may make elections not to participate. So we're in the $350 to $500 million range for acreage this year, which will function as a much higher than that given how aggressively acreage costs have come down in all of the Big 4 shale plays where we are still nibbling at acreage. David Heikkinen - Tudor Pickering & Co.: Can you talk at all about the equity that you're issuing on some of the renegotiations? Have you any update as to number of shares exposed or anything along those lines?

Oh, I think you know, David, that we set aside 25 million shares to do that and we have been in discussions with various parties over the last two to three months to try and clean up some of the deals that were discussed in a different economic environment than the one that we're in. So I think we have said pretty consistently that we established that number as one that we thought we would use and we're not through using it yet, but we expect to use it over time. David Heikkinen - Tudor Pickering & Co.: And then as you think about the service costs coming down by 25%, it implies that you'll get a third more wells drilled in each of the carries. Can you update us? Is that basically how you're thinking about the carries lasting longer as services costs come down and how far that actually gets you in each area now for the drilling carries?

Well, it should take us deeper into the future, no doubt about it. I think, for example, in the Fayetteville we were previously expecting that the BP carry might run out in October of this year; we're now projecting that it probably extends through the full year. So it's just a function of how low prices go or costs go, and then you just do the math on does $4 billion act as $5 billion or $4.5 billion or $5.3 billion? It just depends on how low costs go. David Heikkinen - Tudor Pickering & Co.: Have you factored that into your CapEx thoughts for '09 and '10 is maybe a more specific question.

No, we have not, nor have we really factored in these kind of cost declines in any of our cost structure going forward.

Your next question comes from David Tameron - Wachovia Capital Markets, LLC. David Tameron - Wachovia Capital Markets, LLC: Just following up on David's question there, if we think about going back to '07 or maybe we're in the $6.50 - $7.00 price range, how much do service costs have to come down on your current drilling program in order to get the same margins you enjoyed back in '07? What's the magic number there?

Remember that we kind of are looking at the world differently than maybe others are or even we used to, which is we view that the cost curve across the whole industry used to be relatively flat and the reason for that is everybody owned about the same kind of assets. Today we see this widening gap between companies that have hung on to their conventional assets or have wandered into some unconventional areas that are high cost, and we think those areas get worse over time. And the reason is simply that most of them are increased density plays. I mean, take East Texas for example, or parts of the Anadarko Basin. For the last 10 years the industry has been drilling in these areas, not finding really new reserves but just doing drilling rate acceleration wells. And that worked when gas prices went up by about $1 an Mcf per year. Well, we think those days are over. Now we see that the vast majority of the industry's asset base deteriorates over time and quality and finding costs go up, while on the Big 4 shale plays we think finding costs will go down. So we don't think that the most efficient plays that we're involved are going to set gas prices. We think it will be the least efficient, which actually will tend to support higher gas prices than you would think. So in your $6.50 to $7.00 gas world, we would expect Chesapeake to become more profitable over time than we were in the last $6.50 to $7.00 environment because our costs will be lower; however, we expect for many companies in the industry their profitability to be less in that gas world going forward than it was a year or two ago simply because of the asset quality deterioration that we think takes place in these non-Big 4 shale areas. David Tameron - Wachovia Capital Markets, LLC: So Aubrey, from an industry perspective does that imply more M&A over the next six months as far as industry consolidation?

I don't know, David. I would suspect not. I mean, for example, we wouldn't want to go acquire more conventional assets at this time. So maybe it does among other companies that feel like if you can't upgrade asset quality maybe you can downgrade your cost structure by doing some consolidation. But everybody always talks about consolidation; it really doesn't occur very much. I see two things occur in 2009 that I think will be pretty significant. One is this widening gap between the haves and the have nots that I've spoken quite a bit about, and the second thing is I think the rival of some new international energy players into the North America gas market will be significant. I doubt frankly that they do it through M&A. I think that they're likely to do it through the joint venture concept and hopefully they'll do it with us. David Tameron - Wachovia Capital Markets, LLC: And one more question for Marc. Obviously, working cap's an issue for all CFOs right now throughout the industry. Can you give us a feel for what your monthly working cap number that you need to fund is?

Well, we've talked about this quite a bit, David. Working capital basically swings from a high point in the end of the month for us, receiving all of our revenues for oil and gas sales and our hedging gains kind of concentrated in the last few days of the month to the mid part to the third week of the month being the low point, which is three or three and a half weeks later. We've paid all of our bills and CapEx and so forth for the month with basically no revenue. And so if you basically look at our revenue on a monthly basis and just think that that's our revenue swing or our working capital swing, that's about what we do. It's $700 to $900 million per month depending on prices.

Your next question comes from Brian Singer - Goldman Sachs. Brian Singer - Goldman Sachs: A couple questions on kind of CapEx and financial conditions. As you mentioned with the senior note issuances, financial conditions maybe until the last couple of days have improved a bit. So I guess the question is as tight capital conditions ease, should we expect you to get more aggressive with your budget either for drilling or lease acquisition? And then I guess in parallel with that, should we regard your comments on investment grade credit rating as a priority within the company or more of an aspiration?

Well, on the latter part, I think it's more of an inevitable outcome rather than either an aspiration or a direct goal. As we've said in the past, we are not going to go rushing out and issue a bunch of equity to pay off $2 billion or $3 billion of debt prematurely just to reach investment grade. We function just fine where we are. We're comfortable with our balance sheet. And I think at the various debt conferences I've spoken about investment grade as being an outcome over the next couple of years of the plan that we have in place. We're going to add several trillion cubic feet of proved reserves on the existing standards and maybe more than that on the revised standards that are coming up from a reserve bookings standpoint and really have no net debt issuance over the next couple of years, which segues into the first part of your question. Additional liquidity at this point is meant to be just that. We have not and are not planning to increase our capital expenditures at all. We have rolled out the same drilling budget, unchanged from our guidance a couple of weeks ago and really unchanged from our December 7th guidance where we substantially lowered what we're spending. Cost will help us probably to rein in capital expenditures even below what we've budgeted if the forecast that we kind of hold amongst us for lower service costs is realized which, again, has not been fully baked into our budget at all. So there's not one ounce of us that want to change capital expenditures up, either per acreage or for acquisitions, which we have none that we have done or are talking or contemplating nor capital expenditures. Honestly, we want to sit here in a position where we have plenty of liquidity in case we're wrong about how low gas prices go or how long they stay low. Obviously, as we talked about during the note issuances, this was sort of a CFO belt-and-suspenders action and I feel really comfortable where we are today. Brian Singer - Goldman Sachs: I think what I heard you say is to the extent that service costs surprise to the downside or relative to what's in your budget, you will drill the same number of wells and spend less as opposed to spend the same amount to drill more?

That is correct. Brian Singer - Goldman Sachs: And could you discuss well costs trends specifically in the Haynesville and Marcellus, I guess both from the perspective of efficiencies as you get to know the plays better and then whether the service cost decreases apply to both those regions given that they still seem to be a bit hot?

These are both new plays, so we're changing our procedures and the size of our stimulations and so there's really not a baseline to measure total well costs. On a unit basis, though, we're seeing substantial savings from our various vendors in 20%, maybe as much as 30%. So things are going our way. Brian Singer - Goldman Sachs: And could we expect that there's potential, I guess, downside to the guidance that you've put out for well costs in the past in both those two plays?

Yes, sir. I think it'll come both from those unit costs, but also just drilling efficiencies and completion efficiencies. We still have a very significant element of science in all that we're doing in the Marcellus and a fair amount of science still being done in parts of the Haynesville, so those science projects cost money. And as we gather that information, the need for additional science will tend to decrease over time.

Your next question comes from Gil Yang - Citigroup. Gil Yang - Citigroup: Turning to the Haynesville for a second, what's the terminal decline rate that you're modeling in to get that [inaudible] and how soon do you reach that?

Gil, I'm sorry, you faded out. You said something about decline rate in the Haynesville? Gil Yang - Citigroup: Yes, what's the terminal decline rate you're using in the Haynesville and how many years do you model that getting out to?

The terminal decline's 5% and when we reach that, I don't have that in front of me but probably 8 to 10 years.

I think I saw one about a week ago and it may be in the 10 to 15 year time period, I thought. I think it gets down to 6% or 7% by year 8, 9 or 10. And Steve, we see in all of our shale plays this kind of 5% terminal.

Well, but it's what we're using. Actually what we see in older shale plays like back East in those Devonian shales, they're 3%. So we're just artificially cutting these all off at 5%.

And we have Devonian shale wells in Appalachia that have been producing for -

Over 100 years. These shales should continue to bleed in for a long, long time. Gil Yang - Citigroup: Is that what [Netherland Soule], those decline curves, the 80% first year and then getting out to 5% in 15 years, is that what Netherland Soule is allowing you to book there?

I don't know who did our Haynesville reserves, but yes, I mean, that is our curve, that 82% and 5% finals.

But again, those terminal declines are not different than any other shale play that we've got.

No.

And you're asking about Haynesville, but independent reservoir guys do the Eastern reserves and they do the Barnett Shale and the Fayetteville and all of these are independently prepared by third-party reservoir assayers. Gil Yang - Citigroup: Well, I guess the question is just that since there's no production history beyond maybe a year or two, are they comfortable giving you that typical shale well decline out in Year 3 to infinity?

You've got to start somewhere. And obviously if you don't have a well that's older than two years old in the Haynesville, you've got to rely on what other shale plays have done. And again, I don't think any company, with the possible exception of Equitable, has older shale wells than we do. Again, we've been looking at decline curves in the East from shales that are over 100 years old, so I think we have a pretty good handle on what happens in the out years they break over. And, you know, the oldest wells in the Barnett now that are horizontal are up to 10 years old, so you clearly have good information there. Every shale play's a little different but at the end of the day they're all hyperbolic decline curves with first year decline rates of somewhere between 60% and 85%, and we project based on experience and expectation that the terminal decline rates on all these will be about 5%. Steve, how many different outside reservoir engineers do we use?

Four or five.

Four or five main ones, so they all have to pretty much get to the same answer on those terminal decline rates. And I do believe we cut off our tail reserves in the 65-year range. There's no PV out there, but there will be someday. Gil Yang - Citigroup: And then the last question is just going back to the capital structure, if you are investment grade in two years, understanding, Marc, I guess you said that this is a result as opposed to a goal, nonetheless, if you get to investment grade at the end of 2010, some of your carries will be rolling off. What will then be happening to Chesapeake at that time? Will capital spending need to rise to fill the void left by the carries or do you see yourself going to 20% debt-to-cap by 2012?

Well, I honestly haven't modeled it out to really think about it that carefully. The carries don't roll off at the end of 2010. We've talked about a 2009 and 2010 budget and how much of the carries are in place, but actually I think about half of the carry still remains going forward from that point, so I wouldn't focus too much on the end of 2010 being different. If we are a crossover or if we are investment grade, I really don't see much changing and that's why we're not in such a flurry to get to investment grade. Our debt will still be outstanding or most of it from the senior not standpoint. What is callable will be callable at a premium. And I don't know what interest rate environment we'll be in but I presume it will possibly be substantially higher than we are today, so our current rates on our existing noninvestment grade debt might be actually quite attractive and we may just keep it all in place. So a pretty speculative question, actually, and I probably don't have a very good answer for it.

I might just add that what we would see on the asset side, though, again is this continued differential widening between what happens on finding costs, so I think that what we would see in 2011 and 2012 is I would expect our finding costs to be lower in the Big 4 shale plays than they are today on a combination of better efficiencies and perhaps lower cost, while at the same time our conventional assets probably do not get better over time and therefore require a higher gas price than we've seen in the last couple of years to make those plays work.

Your next question comes from Thomas Gardner - Simmons & Company International. Thomas Gardner - Simmons & Company International: Just a few follow on questions there in the Haynesville and Barnett. With respect to the Haynesville, can you address the gross off take capacity constraints?

Sure, we can. We have said publicly in the past that we think it will be a - takeaway capacity will come into play in terms of restraining the overall growth of the Haynesville. But we've been very proactive in establishing our own corporate takeaway capacity. I think you might have seen us take a Bcf a day of capacity on the latest pipe out of the area, the Tiger pipeline that's an energy transfer project. I believe that that takes us up to 1.8 Bcf a day of firm transport, so we have our needs covered for quite some time, I think. With regard to how the whole play develops, it really depends a lot, I think, on gas prices and what happens to Barnett production. If Barnett production is close to a peak as the rig count in the Barnett has declined from around 200 rigs, I believe, to around 120 or so today - maybe even 110 today - this huge surge of production that we've seen out of the Barnett that has hurt gas prices throughout East Texas and into Louisiana, I think, will back off some and maybe even create some capacity at Carthage and at Perryville, while will open up the ability or increase the ability for the Haynesville gas to come on. So, anyway, what we've done is we know our acreage. We can model what our production does for years to come in the Haynesville and, again, taking out 1.8 Bcf a day of firm transport from that play and so believe that while others may struggle to get their gas out, we will be in good shape. Thomas Gardner - Simmons & Company International: And that Tiger comes on in mid-2011?

Let's see. I think we've got it scheduled for July of '11. Thomas Gardner - Simmons & Company International: Okay, so do you see industry bumping up against a capacity constraint before you get to that time period?

We're barely able to hear you, but I think I understand, Tom, what you're asking - will there be industry constraints. Again, I think that is so dependent on what the overall rig count is in the Barnett and East Texas and in the Haynesville that that's difficult to answer, but I do suspect that if you haven't grabbed or created your own pathway to firm transport, I think there's a good possibility that some companies will have a hard time getting their gas out of the area. Thomas Gardner - Simmons & Company International: And just a follow on to Gil Yang's line of questioning, if you will. In the Haynesville, do you have a specific horizontal well that's demonstrated the steep initial declines mitigating to a significant degree?

Well, I think our oldest well has been online 9 or 10 months, I believe. And we plot the declines monthly, so it's based on that experience is why we are projecting this 82% first year decline rate. So we've seen nothing that has changed that. I think we started before the play even started; I think we anticipated something like a 75% decline rate. So what has changed over the past year from experience is that the wells are coming in at a higher IP rate. They also decline quickly, and so we've honored that by adjusting that first year rate of decline. Thomas Gardner - Simmons & Company International: So is the risk to the upside or downside there on the 6.5 Bcf at this point in your view?

Well, based on what we're seeing, I think, Steve, the first month production to get to 6.5 has to average about, what?

[12], isn't it?

No, on our curve performance only 8, 8.5 first month average.

Yes. They come on initial production, I think, to get to that 8.5, you anticipate they come on at 11 or 12 million a day I think on kind of Day 1. For the first month they average 8.5. So given that the wells that we've been bringing in lately are well above our pro forma - in fact, we've circulated a report daily that green lights, yellow lights, and red lights all of our wells, and I believe something like 85% to 90% or all but two of our past 10 wells, I believe, are in the green light category, which is they are tracking above pro forma at this point. Thomas Gardner - Simmons & Company International: And just one quick follow up question in the Barnett. Does the lower activity there put the 6 to 6.5 Bcf a day peak in 2012 that was discussed at your analysts' day at risk?

Probably a little bit, yes, for sure. It really depends on what other companies are doing. At the time we had no knowledge of what [Devin] and others would do. I think Dave announced they're going from 32 rigs to 8 rigs, I think, if I recall. We've gone from 43 rigs to 28 rigs, I think, 27 rigs. And so I think we end up going to about 25 rigs. So everybody's dropped rigs pretty aggressively there. And I read a lot of analysts' comments that, you know, only vertical rigs are coming down; I mean, it's not true. And the Barnett's been the biggest driver of incremental gas production and that rig count is actually off more than what you've seen the rig count drop across the nation. So it would seem to us as we track industry production in the Barnett that I think the latest that I saw, if the gas rig count goes to 100 from here and stays there is that we're pretty much at peak right now; if the rig count goes to 120 and stays there, I think you do get into the high 5s and it would take a rig count, I think, in the 140 - 150 range to get out to that 6 and 6.5 number and it might take another year or two beyond the 2012 range. So, again, these are great wells, but they come on with big declines and you have to keep drilling to sustain that, so if the market price for gas does not support additional drilling than the cause of this gas oversupply right now will quickly adjust. And again, it can adjust faster than gas demand can go down; gas supply will go down a lot faster.

Your next question comes from Joseph Allman - J.P. Morgan. Joseph Allman - J.P. Morgan: Aubrey, previously you spoke about five oil resource plays, and we know that one of them is [Wayloo]. Any update on the other oil plays?

Yes, let's see, Joe. Kind of ticking through them, one has for sure not worked. We are working on a couple of others. Of course, probably none of them work at $35 oil. So we're continuing to press forward there. But the challenges of finding new plays of significance does, I think, support what we said about shales on the gas side, which is we think the major ones have all been found. A number of shale plays have not worked in the last couple of years. And we've discovered a few that have and, of course, they're big and they're important but, to keep that in perspective, we don't believe that we're going to see additional Barnett, Haynesville, Fayettevilles or Marcelluses developed in years to come. There's just simply no place for them to hide in the stratographic column after the industry has spent so much time and effort identifying shales over the last five years. It's tough to move oil through shales and that's why there's so few oil shale plays that work. And I think we still have a shot at a couple of them working, but that's tough business to go out and find shales that allow oil to move through them. We are certainly encouraged by a couple of results that we have, but we'll wait until later in the year to decide if they're going to be commercial. And a lot of it's going to depend on price. Joseph Allman - J.P. Morgan: And then a separate issue. Late last year you were looking at some leasehold acquisitions that you'd agreed to and you were hoping to renegotiate for a lower price and you were hoping to potentially use Chesapeake stock. Any update with those transactions?

Yes. I don't remember if it was Dave Heikkinen or somebody asked about that earlier and I think I said that we had put aside 25 million shares of stock to deal with those outstanding issues. And we have made a few deals and are in negotiations on a few more and expect that we'll have the decks cleared of those some time during 2009. Joseph Allman - J.P. Morgan: And then on your reserve revisions, do you have a number for the proved developed reserve provisions versus the PUD reserve provisions?

I don't. I don't know if we have a reserve report reconciliation with us.

That will be in our 10-K. I don't have that number. That was sort of asked earlier, Joe, and I didn't have the specific component between PDP and PUD. But our PUD percentage, the answer was our PUD percentage didn't change. Joseph Allman - J.P. Morgan: And then in terms of your E&D spending, from your prior outlook to the current outlook, the E&D spending didn't change. And I know you said that you're basically not baking in a whole lot of service cost reduction, but is your assumption about service cost reductions the same from the prior outlook to this outlook so that your spending is effectively really the same for E&D?

Yes, it's the same but we've now seen a lot greater reductions than we were seeing in December. In fact, they're kind of accelerating as we speak. We've had major vendors come to see us in the last couple of weeks who have basically said what would it take to keep some rigs running? We're talking about big percentage declines, not the 5% and 10% we kind of saw in November and December. We've not baked those in because we really haven't seen the bottom, but the bias is going to be definitely towards being able to spend less money as those costs come down. We will not adjust our rig count upward if costs go down. Our rig count is set where it is and we're happy with that. It covers our acreage, covers our obligations to our partners, and if we can squeeze out another $1 billion or $500 million from our drilling costs over the next year per year, then that'll just be additional liquidity that we create. Joseph Allman - J.P. Morgan: East Texas, Haynesville, any thoughts about your acreage there in East Texas versus your acreage in North Louisiana based on some results that you've seen from others or from yourselves?

Yes. We're just drilling our first well there, Joe, in Harrison County. We're out horizontal; won't know anything for 30 days, but the way that we have it mapped, we like the core area that we have in Louisiana better and thankfully it's where 75% to 80% of our acreage is.

Your next question comes from [Eric Calamares] - Wachovia. Eric Calamares - Wachovia: Could we get a little more clarity as to what the potential monetization strategies might be for later this year? Is it something where it would look similar to what we've already seen or are there different types of things that could potentially be offered up?

I think what we've talked about in the past is a VPP and also some JVs.

Well, the four or five things that we've spoken about include VPPs. They include sale of some properties. They include some sale-leaseback transactions; we're in the process of negotiating a sale and leaseback on some of our surface locations. They include the joint venture projects that we talked about. All of those things are still on the table. And we're working on and I failed to mention the midstream partnership or monetization of some of those assets, which is still very active as well. So nothing, Eric, has changed in regard to those things proceeding. Obviously, it's been a volatile time and one of the reasons we wanted to secure the debt that we used to pay down our revolver was because the timing and the amount and the price variability of all of these things is always in question and when you're relying on some other party to come to the table and write you a check for any of those transactions, we don't have a specific date. None of these things are in ink, but they're all in process. Eric Calamares - Wachovia: And then additionally, is it your hope or do you expect these most to be front-end loaded?

The way we've got it scheduled now actually is toward the end of the first quarter would be the first thing that we're looking at and then sort of evenly between the second, third and fourth quarter thereafter. Eric Calamares - Wachovia: And I guess further going forward, regarding lifting hedges at least to 2010, that is presumably going to be partially gas price driven, but can you give an indication as to what size we might be looking at for that?

Well, you can look at our hedge position, which is outlined in the outlook for 2010 and know that that's the maximum that we could do. It's a big volume and so we're not going to wake up one morning and say we're going to remove all of our hedges. Just like we legged into those hedge, I suspect, if we do anything - and that's not certain either - if we do anything it'll be a leg out kind of a deal. But we've spoken about being well hedged in 2009. We still think that there's a possibility of downside here to prices during this year and so we've only talked about the possibility again, not even the probability but the possibility - that if we do anything it'll be for 2010 kind of time range and probably the back half of 2010.

And I'd like to emphasize that the bias would be towards keeping hedges on because I think we have to run the business with more attention, of course, to the downside than the upside. Having said that, though, there could be gas prices that come in 2009 that simply so completely guarantee a recovery in 2010 that we'd feel like we'd need to take advantage of that. And of course that will be rig driven as well. I don't know what this week's rig reduction will be but of course we're running at the rate of almost 200 rigs a month over the last couple of months, so it doesn't take much more of that to get to a point where you can really regain some confidence about what's going to happen in 2010 - 2011. And I know everybody's looking for kind of historical precedents here to see where the rig count goes to, but I would remind folks that this is the first time that I can recall in 25 years that you have not only a bad commodity price environment but you've got enormously restricted access to credit, and those two factors together will absolutely drive the rig count down probably further than most people thought. We started to say late last fall that we thought that the credit market might be a larger factor on driving the rig count down than even gas prices. So that has certainly accelerated that. The rig count decline has accelerated in the last couple of months, and I think it'll continue for at least the next couple of months. Eric Calamares - Wachovia: And I guess one last question regarding any sort of capital markets activity. Marc or Aubrey, can you kind of give your position as to where you would see the need for increased capital as we head into the rest of '09 and specifically the first half of '09 and under what conditions might you go back to the marketplace?

I'll speak for all of us in saying that we don't see any need for any kind of capital market activities at this point. We took advantage of a very robust recovery in the debt markets and feel like we're very well positioned at this point and have not only no thoughts of doing anything, but see no need to do anything either.

Your next question comes from Marshall Carver - Capital One Southcoast, Inc. Marshall Carver - Capital One Southcoast, Inc.: Yes, most of my questions have been answered. I did have a question on the guidance issued yesterday for cash inflows and outflows, which is based on $7 NYMEX gas for '09. It sounds like you all think gas is going to be below that with your commentary about wanting the 2010 hedges and just curious why you all chose the $6 to $7 NYMEX price and if gas is a good bit below that - like $5 - would you be inclined to lay down more rigs or what your thoughts are on that?

Well, clearly we're not going to outspend cash and we've said that on numerous occasions. We just think that as the year rolls on and the visibility of gas production declines, it becomes more obvious to industry observers - and we're optimists so we hope at some point the economy stops worsening - that that range of $6 to $7 is certainly something that's achievable. You've got to remember, the whole industry is hemorrhaging cash right now. The worldwide oil industry is hemorrhaging cash. And industries like this can hemorrhage cash for awhile, but when the worldwide oil depletion rate might be 7% or 8% per year in the U.S., first year gas decline rate's 25% to 30%, they can't hemorrhage for very long before depletion takes over and restores the balance in the marketplace. So it's still my view that $6 to $7 is going to be an uneconomic NYMEX price for probably 50% of new drilling in the U.S., so I don't think that's a particularly heroic gas price. If we're wrong and the economy doesn't contribute or, sorry, doesn't cooperate and if we don't see the rig count go down as much as we had hoped for, we're still in good shape and you can look at our guidance in our slide show and see that even at $5 natural gas prices - that's on Page 15 our operating cash flow for 2009, the difference between $7 and $5 for us is $110 million. Our operating cash flow goes from $4.020 billion to $3.91 billion. So you can run gas prices at zero this year and we still are going to generate somewhere north of $3.5 billion of operating cash flow. So that's why it really doesn't matter and I said in my introductory spiel, the lower gas prices go this year for us, the better it is; it sets up the rebound. And I think it differentiates our strategy from the strategy of other companies who for various reasons choose not to hedge.

Your next question comes from Monroe Helm - CM Energy Partners. Monroe Helm - CM Energy Partners: Aubrey, just to follow up on that thinking, if you went to your four big shale plays, what kind of 12month NYMEX price would cause you to think about not being able to drill in those four particular basins to meet your [inaudible] return? Can you kind of go by basin as to what kind of minimum NYMEX 12-month price you need to keep the drilling going - and without concerning the hedges, I guess.

Yes, we really look at numbers in those basis without hedges, but we certainly look at them with carries for the context of your question. In a play like the Fayetteville where we will spend no money this year and BP will pay all of our expenses, obviously we'll drill there no matter what gas prices are. With regard to the Haynesville and Marcellus plays, again, in the Haynesville, 50% of our costs are being picked up, so we think our finding costs are going to be about $0.65 to $0.70 an Mcf there this year. In the Marcellus, Statoil's picking up 75% of our costs, so we think our finding and development costs will be about $0.30 an Mcfe there. So you can see that there's really not a gas price that I think can be imagined that's going to affect our activity in those three shale plays. Where it could affect our activity further is in the Barnett if we don't do a joint venture there, don't pick up some carries and gas prices get weaker from here. Then we'll continue to cut in the Barnett and we'll continue to cut in other areas of the company. Going forward, Monroe, I would just say that if you just run an average finding cost for those plays for us without carries of less than $1.50 an Mcfe and look at LOE for those areas and look at differentials, you can see that those areas will be successful at some pretty low gas prices. But it's what's happening at the opposite end of the asset quality spectrum that's going to determine gas prices in '09 and '10 and '11, we think. Monroe Helm - CM Energy Partners: Another question was on your September balance sheet, I think you had $11 billion of unevaluated properties. Do you know what that number was at the end of the year and then was there an impairment - is part of the impairment charge related to the unevaluated properties?

I think it was right at $11 billion as well on unevaluated leaseholds, so whatever we added during the fourth quarter got essentially - an equivalent amount got moved to the full cost pool. I think with regard to acreage that was impaired, I'm pretty certain that we impaired all of our Alabama acreage, that we move it into the full cost pool. I think that was $100 and some odd million. I'm not offhand - unless Mark is - aware of any other area where we had condemned the whole area. J. Mark Lester: No, that's correct. And Aubrey, you're right, $11.1 billion of unevaluated at September. $11.2 billion at 12/31.

Your next question comes from Jeff Davis - Waterstone Capital. Jeff Davis - Waterstone Capital: Just a couple of quick housekeeping. What's the impairment of investments there?

The impairment of investments is related to I think five different items, Jeff. We have, in addition to the impairment on the full cost pool, we had an impairment on a gas processing plant in Southern Oklahoma that's uneconomic at these prices - too little volume's going through. We had an impairment related to our interest in a refining operation in Western Oklahoma. We also had impairments in our rig investments, one of which was a 50/50 joint venture with Lehman Brothers and the other one is a venture with Delta Petroleum. And then finally we had some impairments in our other investments in different companies. Jeff Davis - Waterstone Capital: What's the $100 million increase in other PP&E?

The increase in other PP&E is rig compressors, computers, just general -

Would midstream go in it?

I don't think midstream is in other, Aubrey. Jeff Davis - Waterstone Capital: And then how would you guys characterize the M&A market today? You know, some of my fear of the reliance on some asset sales and heard your response that some of them, you know, may be here in the first quarter, but then equally weighted throughout the remainder of the year, I mean, my expectation is as gas prices continue to move lower here, barring basis, get redetermined lower, you know, we could be seeing some distress sales. So in the context of needing to sell assets and competing against distress sales, what are your thoughts there?

Let's be clear on a couple of things. We don't need to sell assets. We are selling some assets in the context of a potential joint venture because we would like to build additional liquidity this year. So to the extent that troubled companies put assets up for sale, we're not going to be competing with that. The international companies that we're working with are not going to look for $100 million of bad assets from some company. They're looking for something that Chesapeake uniquely has, which is big-time shale positions in all four of the best shale plays in America, and with a management team that knows how to put together some of these joint ventures and with a JV template that works for both us and them. So we can't comment on the M&A market. We're not engaged in it; don't intend to be engaged in it. We're focused on one market, a market, we think, of our making, which is the international joint venture market.

Also I would add, Jeff, that our midstream, for example, while we haven't put anything together yet, is not oil and gas price dependent. Actually, it has improved as steel prices and other costs have come down. We're investing less dollars per foot of pipe in the ground and it's all volumetrically determined based on a fixed-fee arrangement. So that asset particularly probably has gotten better, not worse, in this price environment. And as Aubrey mentioned on the joint ventures, various of our joint ventures won't peak in production until 10 or 15 years out, and so I don't think price [decks] on a long term have really changed from the investor's perspective, you know, that much on the long term potential of these plays. Jeff Davis - Waterstone Capital: I might push back a little bit on the - if I combine your net leasehold transactions and midstream financings, the total of those two, of cash inflows, is in excess of your net cash change shown on your schedule so, you know, without some asset sales you're going to be free cash flow negative in a year when you have huge carries helping you. So I might push back a little bit on Aubrey's comment that you're not relying on asset sales.

Well, we'll let you push back all you want. I suspect you didn't think we could do a deal with Statoil last fall or probably with BP or Plains either. We'll get done what we said we're going to get done, just like we did in the second half of 2008.

Your next question comes from Biju Perincheril - Jefferies & Co. Biju Perincheril - Jefferies & Co.: A couple of quick questions. In East Texas can you give us some additional color on your plans for the rest of the year, how many wells you've planned? It looks like you have permits in all three counties there.

We're planning on keeping two rigs running in East Texas to evaluate our Haynesville position there. Biju Perincheril - Jefferies & Co.: How many wells there might be this year and are you testing all three counties?

We missed one of your words. How many what?

Well count. I thought it was the - Biju Perincheril - Jefferies & Co.: Yes.

How many wells will that result in?

12 - 13. Biju Perincheril - Jefferies & Co.: And then over in Louisiana, in areas where you do have no infrastructure issues, what are the [inaudible] time to drill and complete and hook up a well currently?

Probably about 90 days average from spud for sales. Biju Perincheril - Jefferies & Co.: From spud to sales, okay. And then any new Marcellus results that you can share with us, either over in West Virginia or in Northeast [Pierre]?

I'm sorry. What would you like us to share with you?

Marcellus results.

No. I mean, we've mentioned how well we've done in Northern West Virginia. We just took our first well in the Northeastern PA, our first horizontal well in Northeastern PA to sales. That well's in Bradford County. It's a very impressive well and we're not going to discuss rate at this point, but I think we have two rigs up there right now - three rigs in Northeastern PA. And again, we're drilling right along a couple of pipelines up there. We'll have more information as the year rolls on, but at this point we'd prefer to keep flow rates to ourselves. I think that given that we've been on here for a hour and a half, I think it's fair to all of our callers to go ahead and sign off. We appreciate your questions. If you did not get a chance to have a question answered, please send it in to Jeff and we'll get it answered today. And appreciate your interest in our company. Take care. Bye, bye.

That concludes today's conference. You may disconnect at this time. We do appreciate your participation.