Marcus C. Rowland: Q1 and Q2, the last quarter of ’07 and Q1, we have increased our hedging from previous positions and now we’re virtually 100% hedged. We have increased the amount of hedges we have on all the way into 2009, and simply the guidance has caused the numbers to perhaps look like it is a slight decrease in the percentage hedged.
Dave Kessler (Simons & Company): Can you discuss your thoughts on the economic dislocation we’re seeing between gas and oil right now, and your thoughts on when or whether they will come back into historical equilibrium?
Aubrey K. McClendon: We probably don’t expect them to anytime real soon. We really don’t think that they should. We think they are being influenced by two completely different markets. Oil today is reflecting the fact that it’s an increasingly short, scarce resource in the world and the visibility of forward production is increasingly opaque. On the other hand, natural gas production growth, both in the U.S. and around the world, is much more clear and as a consequence, markets are much more well-supplied, both presently and they are expected to be in the future. There’s a little true substitutability as there is. We don’t expect gas prices to trade on a historic six-to-one BT relationship.
We do think at the end of the day that there will be a move towards natural gas, as we move into an increasingly crude or oil short world. We believe some part of the world’s transportation system is going to have to move to natural gas, whether it’s natural gas directly into vehicles or whether it’s a derivative of natural gas supplied by electricity for some plug-in capability for cars. The world oil market is looking for a price that is capable of restraining demand and obviously we haven’t seen anything from $50 to $100 oil yet that’s done that. Until we find that price, we expect oil to continue to go up. We do think it will help sustain higher gas prices than maybe what otherwise would be out there, but we certainly are not calling for a return anytime soon of a six-to-one relationship. In the longer term, I believe gas has considerable value as it could be used as a transportation fuel in an oil-short world.
Brian Singer (Goldman Sachs): In the Fayetteville, are you seeing the uplift in the wells that you are operating that’s causing an increased debt, or is that more a function of Southwestern’s? Can you talk about how you see that $3 million cost moving up or down over the next year?
Aubrey K. McClendon: First of all, we’ve always been a long lateral company. They were a short lateral company, so we’ve been seeing these EURs for the last six months. We wanted to see some more production before we confirmed them, so we’ve not changed anything in our development plan over what we’ve been doing. We always racked our wells with slick water, we always drilled long laterals and other companies are coming to what we have always done rather than vice versa.
With regard to costs, we are at $3 million and believe that we’ll continue to be able to drive that down. It is an area that is still not built out as well as we’d like it to be from a service company infrastructure basis. But given that we’ve got around 12 rigs running in that area and Southwestern has 20 or so and there’s probably eight or so from other companies, that’s about 40 rigs and that will support a good service basin there and that’s getting built out right now. Our long-term goal is to be able to drill these wells for $2.6 million and we hope the EURs will continue to creep up over time as we drill more wells where you have a lot more geological control. We were also still drilling a significant number of wells today without the benefit of 3D, and when we get our area fully shot with 3D we think that our well results will be better and our costs can be lower.
Brian Singer (Goldman Sachs): Overall how much production is being targeted for asset sales? Has any of that been removed from your production guidance and how you are planning to account for that?
Marcus C. Rowland: Right now, it looks like we’ll be doing likely a transaction that will result in what we call pre-pay accounting, where you book the cash received as deferred revenue and then take the production through your income statement in the future, amortizing that deferred revenue over the time of actual production. We are looking to be in the neighborhood of approximately 60 million a day of Appalachian production that would be monetized.
Scott Hanold (RBC Capital Markets): Could you talk about the Deep Bossier a little bit? What would it take for you to move that from your merging plate to more of a focus area? Where are you at there what are the key milestones you see there going forward?
Aubrey K. McClendon: Key milestones would be successful drilling and production. We don’t have any operated Deep Bossier production right now and we certainly see it all around us and we waited on some seismic to come in before we kicked off our drilling program. We are completing two wells that on logs look like they’ll be productive, and so hopefully in the next 30 days we’ll have some Deep Bossier production. We have three rigs drilling right now, which should give capability of drilling about 12 wells per year. Obviously that’s a number that can be accelerated quickly if we started to have anything close to the success that EnCana has had to date in their part of the play.
Scott Hanold (RBC Capital Markets): On the Fayetteville, you’ve indicated that it appears at this time there may be some service and infrastructure constraints. Do you foresee there being bottlenecks for completing wells and getting production out of there at this point, in the next six to 12 months? Or is there enough stuff being done to provide some comfort over the next year?
Aubrey K. McClendon: We move the gas ourselves, so there’s no delays there. One of the big growth areas for MLP will be in building out gas-gathering infrastructure in the Fayetteville. With regard to infrastructure, costs are higher than they might be if it was in a little more populated area, or in an area of more historic production, but that’s improving and we think it’s getting better every day and we don’t see any delays in getting anything done. It’s just the matter that the unit costs are a little bit higher than we would like them to be.
Jeff Hayden (Pritchard Capital Partners): In the Barnett Shale, especially in the core area and now even expanding out into tier one, we’re hearing a lot more people talk about the 500 foot spaced wells and about 250 foot well spacing. Have you done any pilots on 250 foot well spacing or what is your opinion with regard to that right now?
Aubrey K. McClendon: We’ve not done any of that and at this point, have our hands full drilling our wells down to 500 foot spacing. However, our experience has been, and this is true throughout the industry, that every time you decrease the spacing by one-half, i.e. go from 2,000 feet to 1,000 feet apart, 1,000 feet apart to 500 feet apart, your reserves drop by about 30% per well. We would expect if you were to go to 250, that that would happen as well and you might get into some tougher economics. That’s the reason why we continue to build acreage in this area, that we think we’ll be producing gas here for decades and we’ll be figuring out more and more ways to get the gas out. Right now we are only probably recovering about 20% or so of the gas in place per section. But that 80% will consume the attention of lots of people around here for probably decades to come.
Jeff Hayden (Pritchard Capital Partners): You talked about the Marcellus Shale and a little bit in Appalachia. How much of your acreage is prospective for the Marcellus?
Aubrey K. McClendon: Right now, about 750,000 acres is what we have and that’s a combination of leasehold that we acquired through our CNR acquisition, as well as acreage that we bought off the ground. We are drilling our first few vertical and horizontal wells right now. I’ve seen a few other numbers out there but I don’t think anybody has any amount of acreage that’s close to the 750,000 or so that we have.
Michael Ange (TIAF Crest): On your debt levels, obviously you’ve got some of these asset monetizations in the next quarter and then some in the quarter after that. Whether we should be looking at that to have debt come down or to have that slow the growth in debt?
Marcus C. Rowland: There’s two ways that we look at it. The plan as laid is for no increase in debt at all, so saying that we are going to slow the increase and the rate of growth of debt is not correct. We are planning to decrease our debt levels with the plan that we’ve laid out. Most of that initially will go to reducing our revolving credit facilities. The bigger picture for us to make sure at this point gets communicated, the asset monetizations for us are taking what are no growth, long-lived, fully developed properties that can be monetized at a cap rate of around 7%, and taking that cash and moving it into 35% or 40% on average internal rates of return in the Barnett Shale and the Fayetteville and other drilling areas that we have going on without increasing our debt and without increasing our shares, while building the overall reserves and production levels of the company at a record pace. We are by far the largest growth company in the large cap universe. If we can sustain those growth levels over several years with no increase in our share count and a decrease in our debt levels, we will have accomplished something that few companies have ever been able to do on the scale that we think we can do it.
Scott Palmer (Janney Montgomery Scott): You have consistently over the last number of years had vision of growth in demand of 1% to 2% per year and growth of supply of minus 1% to 2% per year, and that’s not there anymore. Do you feel significantly different now about that supply and demand relationship? Since the growth in supply this year was fairly significant, how do you feel about things?
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