Key questions and answers from the second quarter fiscal 2008 earnings call conducted by Chesapeake Energy Corp. (CHK: chart) on August 1, 2008.

David Tameron (Wachovia Capital Marcets): Looking at your level of activity the 156 rigs you have running we’ve heard some concerns from other EOG Apache talking about steel and pipe and tightness in the tubular market, how are you set up for that if you look out over the next six months, the next year?

Steven C. Dixon: It is very tight right now and we’re scrambling to stay ahead of those 156 rigs but getting her done. We have long term arrangements, have been a major pipe buyer for years but prices have gone up significantly in the last few months.

Aubrey K. McClendon: One of our Board members is Pete Miller from National Oil Well, we talked to him yesterday and he thinks it’s mainly maybe topping out perhaps a bit. Again we’ve been the number one consumer of oil field tubulars for years and years so we’ll get our share of our tubulars, they will be more expensive but we will not be running out of tubulars.

David Heikkinen (Tudor Pickering & Holt): Can you give us an update on what’s going on in West Texas?

Aubrey K. McClendon: In the last couple of months we’ve really achieved some completion breakthroughs there, we have some vertical wells that actually are very commercial. We have horizontal wells that are quite good as well. While certainly that play hasn’t arrived at a point where we want to go throw 10 or 20 rigs at it, I think we have cracked the code there enough that it would be a great area to bring in a partner into and start to attack it. It’s just so vast, we have over 1 million acres in the area and there’s so many kind of different play types whether you drill vertical Barnett and Woodford wells or drill a horizontal well and complete the Woodford vertically and the Barnett horizontally.

David Heikkinen (Tudor Pickering & Holt): Any update on oil shales?

Aubrey K. McClendon: I think in March was the first time that we began to talk about we were targeting oil shales and this 20 to 25 person team that we have over in our shale laboratory has been very helpful in working with our team GSI just to come up with some new plays. We were working on five unconventional oil plays and four of these were in shale and one of the five was already producing at the time and we also said that all four that were not producing would be tested by the end of the year. The non-shale play is our West Edmonton Hunt line unit field area Northwest Oklahoma City and that’s working quite well. Petrohawk has a significant interest there as well and I think they’ve released some positive information about it. It’s an old abandoned oil field that we’re now going back in and drilling horizontally and it’s working well for us.

The other four are shale plays in four different states. We are drilling a well right now in the first of these plays and we’ll have the other three tested by the end of the year.

Jeff Robertson (Lehman Brothers): You made some comments about the pressure in the Haynesville, can you talk a little bit about the operating costs in that play? Secondly, can you talk about where you think that ranks in your overall asset mix in terms of returns?

Aubrey K. McClendon: From a return perspective even without the carry from planes we believe it would be the best area for us when you combine lack of compression costs, when you combine gas prices that are $1.30 to $1.50 higher than the Barnett and finding costs that are going to be again without the carry somewhere between $1.33 and $1.50. With the plane and carry for the next two to two and a half years our finding costs in the play are going to be we think around $0.67 to $0.70 in NCFE.

Steven C. Dixon: The big deal is that there’s no compression so these other shale plays a lot of your lifting costs are compression costs so we don’t have that, these shale plays don’t make much water, you have some flow back initially and then that dries up. So the play should have very low lifting costs.

Jeff Robertson (Lehman Brothers): So, the gas doesn’t need to be processed either, does it?

Steven C. Dixon: No, it does not. It’s right on the edge, there is some CO2 but we’re able to sell that. We’ll just keep an eye on that.

Thomas Gardner (Simmons & Company International): Assuming we’re in the fourth quarter of the US land grant, what are your thoughts on the Canadian and European resources plays?

Aubrey K. McClendon: We’re not Canadian players and we’re not international players. Canada is a great place to look for gas, and it’s a tough place to make money so I’m glad that our shales are down closer to market. Internationally, as we start to approach or roll through a time of peak oil production, I think gas shales around the world will get developed until we can start to move the transportation fleet around the world to C&G. Right now there are about 800 million cars in the world, and only about 8 million of them run on natural gas. Obviously, the United States and Canada are not the only countries with shales that would work for gas supply. What nobody else has is an industry like we have to go out and extract that. But, presumably in the decades ahead, that expertise will be exported to other countries and you’ll see the use of gas rise to make up for inevitable shortfalls in the production of oil going forward.

Thomas Gardner (Simmons & Company International): Concerning North American natural gas supply, if some point down the road we do get in to an oversupply situation, what is your view on the lag time before the market corrects itself?

Aubrey K. McClendon: We’ve seen the market get in oversupply almost every year for the last four or five. You get a gas price collapse the last three years that has occurred each year a month earlier than the month last. If you think about 2006, it occurred in the October contracts, if you think about last year it occurred in the September contracts, this year it occurred in the August contract and there are some reasons for that. But, if you were to get a further decline from here, you would see the rig count start to go down and our experience from 07, 06 and going back to 2001 shows you that the industry doesn’t stable or breakeven very long and whether or not that’s a month or two it just doesn’t happen and people can get very negative on gas prices in a hurry. This is an industry that always spends its cash flow, oftentimes more than its cash flow and if we don’t have the cash we can’t spend it so you’ll see 40% first year declines kick in and the market correct.

Every time we go through one of these draw downs in gas prices, the floor is higher than it was before, as it should be, because of higher coal prices and higher industry planning costs and higher oil prices. So, I would suspect those people looking for $6 and $7 gas prices out of this draw down are likely to be disappointed.

Joe Allman (JP Morgan Securities, Inc.): On the issue of natural gas demand from transportation, what do you think the likelihood of that happening in the time table? And, what are the key triggers for that to happen in your view?