- The company’s average differentials were a negative $2.07 per Mcf in Q4 of 2008 versus 59 cents negative per Mcf in Q4 of 2007.
- In Q4, the company averaged selling gas in the Barnett for $3.97 at the wellhead, $4.13 in the mid-continent as compared with $6.65 in Appalachia and $6.16 in the Gulf Coast.

On the firm transportation side, the company now has four projects committed in Haynesville.

- This includes the ETC project recently announced and several more that are nearing conclusion of negotiations.
- The management foresees 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.

The company has recently concluded two senior note issuances totaling $1.425 billion.

- The proceeds have already been applied to the revolving credit facility.
- Several additional liquidity or monetization projects are still under way.

Key questions and answers from the fourth quarter fiscal 2008 earnings call conducted by Chesapeake Energy Corp. (CHK) on February 18, 2009.

Michael Hall (Stifel Nicolaus & Company, Inc.): On the macro front, could you talk about your expectations on L&G this year and how concerned you are with the potential for rising imports in the U.S.?

Aubrey McClendon: That exists out there and 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.
We can''t know the answers to that but 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. However, it''s clearly an issue for us and as long as the economy around the world remains weak, it will remain a risk and likely keep a ceiling on summertime gas prices.
However, I do want to emphasize that by the third or fourth quarter, U.S. gas production should be declining 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. 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. 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.): In the Haynesville, can you talk about what you''re seeing on the East Texas side of the play?

Aubrey McClendon: We''re drilling our first well there. It''s called the Rocksboro well and it''s in Harrison County.

Scott Hanold (RBC Capital Markets): On the Barnett Shale joint venture, you indicated that there''s some interest by some international players. Can you give more detail on that?

Aubrey McClendon: There is a high degree of international energy company interest in gas shales in the U.S. If you are one of those companies 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. 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.
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.

Shannon Nome (Deutsche Bank Securities): We''ve had concerns surrounding a production response to the rig count. We agree that by late this year we''re going to start seeing some aggressive declines; the question is how long it takes? 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?

Marc Rowland: We have in the Barnett Shale ourselves 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 have much of any inventory that''s not just the usual due course of business.
Certainly, that''s going to add some months probably. It''s already 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 drilling there has probably slowed faster because of the wider differentials than other places.
Thus 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. We get the trend and all of us probably know the trend is our friend but as to the exact minute or quarter that it starts, that''s hard to guess.

Jason Gammel (Macquarie Research Equities): On Haynesville results, 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? Would you have any comments on what you''re seeing in terms of decline rates after six months?

Aubrey McClendon: We continue to refine our pro forma with 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 we''re at 82% to 85%.
Thus 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 20 million a day. In all likelihood the wells that come in at 20 million a day are going to be better than 6.5 Bcfe.
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. 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.
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. I think the industry is 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. 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.

David Heikkinen (Tudor Pickering & Co.): You mentioned that services cost could be down 25% year-over-year; for every new well, you''re driving rates down. Can you give us some thoughts as far as the breakdown of those services on the pressure pumping versus drilling side? Can you also give us any update as far as leasing and the current rates for each of the plays where you''re doing some leasing, primarily Haynesville and Marcellus?

Marc Rowland: 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 close to that business. However, as pumping services lagged coming up, they''re now lagging coming down a little bit because of the backlog of wells that we referenced and talked about earlier in this call. 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 $11,500 or something like that. At the peak, that particular item would have probably been at $24,000, $23,000 a year ago and hence 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.
Hence 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. Based on conversations we''ve had with our various vendor partners, they''re going to be more concentrated in market share rather than margins going forward.

Aubrey McClendon: 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.
Thus we''re in the $350 million 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 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?