Expand Energy Corporation (EXE) Q4 2010 Earnings Report, Transcript and Summary

Good day, and welcome to the Chesapeake Energy's 2010 Fourth Quarter and Year-End Operational Update and Earnings Result Conference Call. [Operator Instructions] At this time, I would like to turn the conference over to Mr. Jeff Mobley. Please go ahead, sir.

Good morning, and thank you for joining our 2010 fourth quarter and full year earnings conference call. With me today is Aubrey McClendon, our Chairman and CEO; Nick Dell'Osso, our Chief Financial Officer; and Steve Dixon, our Chief Operating Officer. Our prepared remarks should last about 15 minutes and then move to Q&A. And I'll now turn the call over to Aubrey.

Great. Thank you, Jeff. Good morning. We hope you've had time to review Monday's Fayetteville sale announcement along with yesterday's operational and financial release. We are very pleased with our 2010 results as well as the results from our Fayetteville sales agreements with BHP. Our sale of the Fayetteville strongly validates a critical point we have made for some time. The assets of our company are worth far, far more than what is implied by our current stock price even after the $10 round in the past few months. As first announced on January 6 of this year, Chesapeake has moved into a very exciting phase of our company's history. During which our 25/25 Plan will deliver to investors investment-grade balance sheet metrics resulting from reducing our long-term debt by 25% and best-in-class production growth of 25% during 2011 and 2012. The effect of achieving these two objectives will also accelerate the rapid transition of our capital spending towards higher value liquids-rich plays will be completely transformative for Chesapeake in its investors in the years ahead. And we're certainly off to a fast start in implementing this plan in the first two months of this year. We will continue to focus on profitably harvesting some of the great assets we have gathered in over the past few years. Looking forward to the next five years, through an accelerated development drilling program that is increasingly directed to liquids-rich plays, we believe we can generate $10 billion to $11 billion of EBITDA in 2015. If we are able to do so, then we should be able to increase our enterprise value to a range of $70 billion to $80 billion versus our current enterprise value of about half that. We have the strategy, the land, the science, the people and the capital to achieve this goal and I believe we will achieve it. Clearly, the implied value creation and delivery to our investors from achieving that level of enterprise value is enormous, and we are very excited about delivering it to you in the years ahead. There are two aspects of our 2010 performance that I would like to feature this morning because I believe they are so important to understanding the potential of our future performance. First of all, we were able to double our oil production from about 30,000 barrels per day in the 2009 fourth quarter to over 60,000 barrels per day in the 2010 fourth quarter. Our liquids growth rate was particularly strong in the 2010 fourth quarter, increasing 23% sequentially versus the 2010 third quarter. Secondly, the company through the drillbit developed 5.1 Tcfe of proved reserves in 2010 at a cost of only $1.07 per Mcfe. That means in just one year and just through drillbit, we found more reserves than any of these highly regarded companies have built up in their entire history, Range, Ultra, Southwestern, Newfield and Petrohawk, to name a few, all of them have enterprise values of $10 billion or more. We duplicated or exceeded their reserve base in one year through the drillbit. This is an extraordinary achievement and we hope each of you will reflect on what that tells you about the powerful value creating machine we have built at Chesapeake. It is truly unique in the industry and will create huge value in the years ahead as we rapidly convert our undeveloped acreage in production, proved reserves, cash flow and earnings. Now I'd like to turn to our Fayetteville asset sale to BHP and review its four most important implications for our company. First and most obviously, it is the key to achieving the 25% debt reduction portion of our 25/25 Plan which we believe will unlock the enormous asset value that we have built up inside our company. Second, I would like to point out what this sales price tells you about the value of our remaining assets. Please note that we are selling just 10% of the PV-10 of our proved reserves as of year-end 2010, implying that our remaining proved reserves are worth at least $40 billion. That means that all of our unproved resources, that's 175 Tcf of natural gas and 15 billion barrels of liquids, are valued at absolutely zero at today's Chesapeake market valuation. Where else, but at Chesapeake can you acquire resources of this size and quality for free? World-class resources such as in the Marcellus, Haynesville, Bossier, Barnett, Eagle Ford, Niobrara, Cleveland, Tonkawa, Granite Wash, Mississippian, Avalon, Wolfcamp, Bone Spring and Wolfberry plays to name just the most well-known of our plays with huge amounts of unrecognized upside. And what could these 175 Tcf and 15 billion barrels of unproved resources be worth? We think we have established these various joint ventures into the value paid for our Fayetteville assets that our unproved assets are worth at least what our proved assets are worth or around $40 billion. In addition, we also have $6 billion of non-E&P assets such as our midstream assets and our interest in Chesapeake Midstream partners CHKM in our service company assets, plus $4 billion of drilling carries that are also not reflected in our current market value. Added all up, and I think you can easily confirm asset values of more than $80 billion for CHK. Third, please consider that we are selling the Fayetteville asset that only represents 14% of our production, 14% of our proved reserves, 10% of our PV-10, but yet 20% of our market cap and yet we're still going to be able increase our production this year by about 8% to 9%. Please ask yourselves what other company could sell 14% of its production or 20% of its market cap and still grow production in proved reserves by 8% to 9% in the same year. We think that once again, proved that Chesapeake is unique in its capability to grow production in an extraordinarily efficient and profitable manner. Fourth and finally, our Fayetteville sale accelerates our transition to a more balanced production profile between natural gas and liquids. In 2009, only 8% of our production was liquids. In 2010, we increased it to 11%, but in 2012, we project liquids will make up more than 20% of our total production. And in 2015, our liquids will further increase to more than 30% of our total production mix. Before I turn the call over to Nick for his financial commentary, I'd like to share a few thoughts with you about the macro environment. First and obviously, oil prices should remain strong, maybe even scary strong for years to come. Global oil demand growth appears set to outstrip supply growth at present oil prices, even before considering the potential supply disruptions that may occur as historic geopolitical events unfold before our eyes across the Middle East. The developing world continues to increase its energy intensity and will aggressively compete with the developed world for stagnated oil supplies going forward. We quickly repositioned Chesapeake over the past two years to benefit from strong liquids prices in a technological revolution in our industry that will enable Chesapeake to produce volumes of liquids from unconventional resources that were unthinkable just two years ago. Second, I would like to mention that we have recently enjoyed increasing levels of interest from investors who would like to discuss whether there exists an out year bull case for North American natural gas. We agree that now is the time to examine the North American natural gas market to determine if the worst is over. Even though Chesapeake's transitioned to an oilier asset-based is well underway, and will not change regardless of what happens to natural gas prices in the near term, we would like to remind you that natural gas is of course still important to us, and we still own over 175 Tcf of unrisked natural gas resources under our leasehold. In our delivery of value to shareholders in the future, can exceed the substantial levels I have discussed earlier if North American natural gas prices were able to increase in years ahead. So in these recent discussions with investors, we've been able to identify for them six elements of an out year bull case for North American natural gas that I would like to quickly review with you. First, during the past two years, natural gas has already achieved significant market share gains in the electrical generation market at the expense of coal largely on the basis of price, but also because of environmental issues. Certainly, the social and political acceptance of burning coal in the U.S. will become more challenging than the years ahead, and we expect natural gas to pick up at least 10 to 15 Bcf per day of increased demand at the expense of coal in the electrical generation market during the remainder of this decade. Number two, North America has the lowest natural gas prices in the industrialized world and with much of the rest of the world using oil-based, NAFTA as the fundamental building block for chemicals and plastics, we believe industrial natural gas demand in North America can increase annually by up to 1 Bcf per day as a result of the low prices for natural gas in North America, especially relative to Europe and Asia. Number three, we are finding increasing momentum in the marketplace for CNG vehicle, especially the gasoline and diesel prices continued to increase. Even though our federal government and Congress have yet to understand the importance of CNG to reducing U.S. oil imports, creating American jobs, improving the environment and our economy and enhancing national security, we believe that $4 and $5 gasoline and diesel prices may finally get their attention. In the meantime, the CNG market is moving ahead with virtually every corporate and state and local government fleet in the U.S. considering moving to CNG vehicles, and OEMs are now responding as well. I believe CHK's CNG vehicle team is the best in the country in advising these potential fleet customers on how best to make this transition to American natural gas from foreign oil. Number four, we believe that by year-end 2015, liquified natural gas will be exported from the U.S. and/or Canada to foreign markets connecting, for the first time, North American natural gas markets with higher valued European and Asian natural gas markets. This development will be notably aided by a widening of the Panama Canal in the next few years to accommodate large LNG vessels. We believe LNG exports from the U.S. will be a very bullish event and should begin to effect the back of the natural gas curve once ground breaks on several of these projects by year-end 2012. I will add that Chesapeake is actively engaged in helping to advance several of these LNG export projects. Number five, we believe commercial scale gas to liquids or GTL facilities will be in operation in the U.S. by year-end 2016. When ground breaks on at least one of these projects by year-end 2013, we believe it should also have a very bullish effect on North American natural gas markets. I might also add that Chesapeake is actively engaged in this market as well, helping to advance several GTL projects. Number six, finally, we believe that drilling for natural gas in North America will continue to decline during the remainder of this year and in 2012, especially once acreage in many of the large natural gas shale plays becomes held by production or HBP, especially in the Haynesville. We estimate that the marginal cost of gas supply in the U.S. is around $5.50 per Mcf. Today, drilling economics are being largely ignored as the industry races to hold acreage acquired in the great shale gas landgrab of 2008. As that HBP process comes to an end this year, we believe that natural gas production growth should stop until prices settle in at a long-term price range of $6 to $7 per Mcf. There's one more factor here at work that I'd like to highlight. And I think we can agree that there's almost unanimous consensus among investors and analysts in North American natural gas prices will never increase above a certain long-term ceiling price. For some of you that's $4.50 per Mcf, for others, that's $5 per Mcf and perhaps for others, it's $5.50. We certainly understand the reason for this low current ceiling price unanimity. However, I'd like to remind you that Chesapeake, along with virtually every other natural gas producer both big and small, in both public and private, is responding to the huge return on investment gap that exists between drilling oil wells today versus drilling natural gas wells and we are responding by transitioning our drilling programs as rapidly as we can from gas to oil. To remind you the obvious, we can drill a natural gas well and receive around $4 per unit of production or we can drill an oil well and receive around $15 per unit of production. We believe that once the industry drilling rigs move away from natural gas plays. To oil rig plays, oil plays for the rigs will be drilling wells that produce $15 units in a much more competitive rate of returns, we think the natural gas curve will have to increase to make natural gas drilling competitive with oil well drilling. I do find it curious as investors and analysts believe that somehow, a potential increase in natural gas prices from, say, $4 to $5 or maybe even a $6 per Mcf will somehow bring those rigs back from drilling oil projects where the revenue level will be $15. I guess, today, I should say, $16 or $17 per Mcf. So to me, this is the greatest misconception about the natural gas market today that somehow an increase of $1 or $2 per Mcf in the price of natural gas in the years ahead is going to create a sufficient financial incentive to cause the return of hundreds of rigs from drilling and more valuable oil plays to drilling in less valuable natural gas plays. I can assure you that it will simply not happen without a substantial rise in natural gas prices. I'll now turn the call over to Nick, and we certainly appreciate your time today and to your ongoing interest in our company. Nick? Domenic Dell’Osso: Thanks, Aubrey. Our fourth quarter and really all of 2010 represent the culmination of a very important shift in our strategy. We believe the success of that shift in strategy will become more apparent with each day during 2011 and 2012. As Aubrey noted in Monday's announcement, we'll lead to a quick win in our plan to reduce debt 25% by the end of 2012. Additionally, the closing of the Niobrara JV facilitates our oil production growth targets as we are now drilling with the benefit of a significant carry in the play. To cover a few quick points on the Fayetteville transaction, the sale represents a true win-win for BHP and Chesapeake, and that we're selling an asset for a very nice return and BHP is a acquiring what we think is a perfect entry into onshore North American market. Given our tax bases and the asset is rather low, we do anticipate a substantial gain for tax purposes on the sale, but expect nearly all of that gain to be absorbed by our NOLs. Of course, as a full cost company, you will see the proceeds from this transaction applied to our full cost pull, and so in the future we'll see a lower DD&A rate rather than a big slug of current income as you would see in a successful efforts company. Our outlook for 2011 and 2012 has been adjusted to reflect the adjustments to production and costs, including this lower DD&A rate as the result of the sale. As stated before, upon closing, we will look to retire $2 billion to $3 billion of our senior notes. Onto the results for the period, we had a very solid 2010 with about a $1.7 billion of net income and $4.5 billion of operating cash flow and just over 1 Tcf of production which equates to adjusted earnings per share of $2.95. Aubrey briefly mentioned our liquids production growth in 2010 which grew over 100% when you compare the fourth quarter of 2010 versus 2009. That increase in our liquids production represented 30% of our overall production increase during a period where we allocated about 30% of our drilling and completion to liquids plays. I'd like to remind you that we plan to allocate 53% and 74% of our drilling and completion capital to liquids plays in 2011 and 2012, respectively. Next, I'd like to touch briefly on our production costs. We experienced an 11% year-over-year decrease to $0.86 per Mcf equivalent. This is best in class by a pretty healthy margin and is aided by a number of factors including the overall scale of our operations. I'd also like to remind you that the LOE that burden that BP's represent is included in this number, so it's still best in class after that affect. Additionally, I'd like to cover a few points on our hedging program. Our natural gas production is currently very well hedged for 2011 and contracts, including contracts already settled, we expect our average realized price for 2011 to be $5.98 per Mcf on gas. We have enhanced our hedge price on gas by selling calls and out years on a relatively small portion of our projected production. I believe that our resulting expected price for 2011 highlights our desire to use our hedging program to chop off the peaks and fill in the valleys of volatile commodity price curves. One of the things that makes this possible is our multiparty hedge facility that allows us to hedge to 12 different highly rated financial counter parties for as much as five years of our production at one time. Today, we have used just over 50% of that capacity. Also, I'd like to remind everyone that given the facility supported by our oil and gas reserves is collateral. If we are ever underwater on our trades, the value of our counter-parties collateral goes up as an offset. As the result of this, it is very difficult for us to ever have a cash collateral call against the facility. However, despite that unlikely scenario, we maintained a significant portion of our reserves as unencumbered collateral. Lastly, on hedging, I'll point out that we have proactively managed down our hedge position for 2011 to take into account the pending Fayetteville sale, so we've already brought ourselves in line with the changing projected production for the year. Looking forward, we're excited to close the Fayetteville sale and as discussed previously have one significant additional JV transaction forecast for the second half of the year. As we will begin to think about that JV a bit more in the coming months, I'd like review the economics of the JV as we see them. You may wonder why we would pursue another JV given the cash created by our Fayetteville sale. However, the returns to Chesapeake and therefore shareholders on assets where we complete JVs are materially higher than should we choose to hold the entire asset. This dynamic is created by the size and scale of the operations needed to develop these fields coupled with the ability to receive our full investment back at the outset of the process. For the JV in place on both the Eagle Ford and Niobrara, our IRR will be about 50% higher than it would have otherwise been. Additionally, our maximum net cash out-of-pocket becomes a very manageable number, allowing us to take the proceeds from the Fayetteville transaction and return them to investors in the company through a debt buyback. So that concludes our prepared remarks for today, and with that, operator, we'll turn it back over to you for questions.

[Operator Instructions] And we'll take our first question from David Heikkinen with Tudor, Pickering, Holt. David Heikkinen - Tudor, Pickering, Holt & Co. Securities, Inc.: Can you guys talk about the infrastructure needs and current capacity or bottlenecks and then capital costs in the emerging oil plays, the Eagle Ford, Niobrara and anything in the Permian?

David, in general, we certainly are cognizant of all the problems getting oil out of those areas, but have a multi-capacity approach to do so. Obviously, you can move oil about three different ways, you can move it by truck, you can move it by train, you can move it by pipeline and obviously, pipeline is the ultimate answered choice for all of these plays and we have a very big and active marketing group and midstream group and they are attacking all these areas with all the resources that we have, as well as some third-party partners. So we built in the delays into our production ramp up forecast that are embedded in new plays where we have efficiencies like in Eagle Ford, trucking oil for up to 400 miles round trip today whereas within a year or so we'll have our pipelines in there, Steve, what's the...

Yes, pipelines will be in '13 with rail hopefully in this year.

So we're trucking today, we go to rail and ultimately a pipeline. That's kind of three phase approach to each of these areas that we're talking about. Obviously, if you've got a truckload of tank on the back, it's a good time to own that asset. David Heikkinen - Tudor, Pickering, Holt & Co. Securities, Inc.: Can you talk about kind of lumpiness for those plays when do you get the rail capacity? What is that capacity now, how much capacity you have for trucking? I'm just trying to think about as we model and kind of run out 2011, 2012, 2013 as each of these plays kind of grows?

Well, I think that's really highlights the advantage of our business strategy, David, that we're in so many different plays that I don't think you're going to see lumpiness in our production. You'll certainly see lumpiness in some plays, but that's drive some the benefit of the multi-play approach. So we think when you look at our production forecast, there will be some quarters that will be growing at different speeds then the surrounding quarters. But generally speaking, it's a linear growth model that we'll be reporting, we think. And again, some bigger delays in some areas than in other areas, but overall, to have that asset diversification we think is equally important. David Heikkinen - Tudor, Pickering, Holt & Co. Securities, Inc.: And then just thinking about your commentary around the macro and just wanted to think about overall operating costs and margins for a typical gas well in your portfolio versus one of new typical oil wells. If you just walk us through what is the cost structure of each and kind of where is the margin Delta?

Sure. If you look at finding costs, which I guess is a place to start, our finding costs are going to be somewhat higher in our oil plays and that can be no higher to as much as 25% to 50% higher and then lifting costs typically in an oil well are going to be around 50% higher or so just kind of depends on how much of the liquids come with substantial gas production as well. Beyond that, it's really about same. So we think if you -- let's just say, you're finding gas at $1.25 in Mcf and that translates into oil of $7.50 a barrel. It probably means you're finding oil in the $10 to $11 range and it's one of the reasons why of course we always want carries because of the initial years of a play, we certainly want more of those costs will be borne by our partners rather than by us. David Heikkinen - Tudor, Pickering, Holt & Co. Securities, Inc.: And then on the financial side, you guys have used a lot of your revolver capacity in the past and have run kind of $300 million to $500 million of availability. Now that you're getting cash in the Fayetteville, and you're going to payback $2 billion to $3 billion of senior notes, how do you think about using your revolver and then kind the capacity on that heading forward?

I'll let Nick answer, but obviously it'll be greatly reduced as a result of what we'll be doing this year and next year. Domenic Dell’Osso: Yes, David, so that's right. I mean, we had about $600 million available on our revolver at December 31. The proceeds of this transaction will immediately be applied to the revolver as all of our incoming cash proceeds for deals like this. We will tender for some bonds and so you'll see the revolver go zero and then tick back up to some usage and it will continue to be our working capital facility, which will be utilized higher sometimes than others but it will be less overtime that it has been over the last year or so. David Heikkinen - Tudor, Pickering, Holt & Co. Securities, Inc.: And then just pursuit of investment grade status is also around that, now is it?

What's the question David? David Heikkinen - Tudor, Pickering, Holt & Co. Securities, Inc.: The pursuit of investment grade? Domenic Dell’Osso: David, we certainly are still very focused on targeting investment grade metrics. We try not to predict when the rating agencies will react. We did receive a positive outlook from S&P when we announced our intent to sell the Fayetteville. So we're hopeful that we will continue to work with the agencies and get some nice credibility for what we've done. But not wanting to try and predict what and when their actions will be to our program. Although, we are attacking both the numerator and the denominator of the debt-to-proved reserves which we believe is the key metric that they look at relative to Chesapeake and its peers. And so debt coming down and proved reserves going up pretty rapidly. We think we're headed in the right direction.

We'll take our next question from Brian Singer with Goldman Sachs.

First, what drove the gas guidance increase if we exclude the Fayetteville sale that you're gas production got increased a little bit and maybe that provides opportunity to run through your key gas and liquids plays and update us on any changes to where you may be seeing better gas productivity or a greater contribution from associated gas?

Just really results of kind of running ahead of our model and so you can suppress the model so far and so long, I guess. So really all our plays continued to work exceptionally well, we'll be very sad to see the Fayetteville go. Second, unconventional gas resource play and very important part of our understanding of unconventional resources in the U.S. But I wouldn't attribute it to any particular play. Although, it was obviously been strong commentary the last couple of days about what we're seeing in the Marcellus and while that play is not vital or critical to us, it is to a couple of our competitors, certainly, the EURs that are being reported in Southwestern PA and in Northeastern PA we were experiencing those very same EURs as well. So basically, wherever we're drilling today, we think we're outperforming our models and so from time to time, we'll probably see our production tick up. And that's why we give a pretty good range of what the outcome could be in 2011 and 2012 from a production forecast. But we remain focused on reaching that 25% growth rate over the next two years with roughly a third of it coming in 2011 and roughly 2/3, 2012. I think perhaps most important takeaways is to examine what the company's underlying structural rate of growth is and that's really about 20% per year. And for a company of our size to be able to grow at that rate is quite extraordinary and it's going to be driven by an ongoing success in our gas plays along with these liquids plays as well.

And the Granite Wash and Colony Wash, can you talk to what you've seen from recent well results of your acreage position, what percent do you have actually, you've confirmed the 155-acre density assumption?

I don't know if I have a percentage. Steve may, but just generally, just to recall, Colony Wash is a play we discovered in 2007 and kicked off the whole horizontal Granite Wash play, and for those of you who may not be familiar with it, Colony Wash in Washita County and Custer County in Western Oklahoma. And then the play that's received probably most publicity because so many companies are in it. Whereas we own about 85% of the Colony Wash, Granite Wash play, we'll be the Texas Panhandle Granite Wash play. We've read over the last couple of days commentaries from some other companies there, we haven't expressed or we haven't experienced some of the issues that perhaps other companies have. I think we've been more conservative in our production forecast and, frankly in our management of our wells. And so we're still you said 155 acres, I guess, we call it 168 acre infrastructure to four wells.

Average than of multitude of plays of Anadarko Basin.

What percentage do we want to go with here guys? On acreage? Domenic Dell’Osso: For the Granite Wash in Texas Panhandle basically 100% of our acreage is proven to be prospective and then in the Colony Wash. I guess around 80% of our total acreage is listed there is probably going to be perspective at the end of the day. We kind of working on some of the fringe acreage, right now.

Just looking at your total acreage, the 13.2 million versus the 13.8 million from the end of the third quarter, not too big of a change adjusted for the Fayetteville sale, can you just talk to the acquisition spending during the quarter and just some color there?

Sure. Most of our spending during the fourth quarter would have been finishing up in the Eagle Ford and Niobrara in preparation for our JVs. And then we have continued to build acreage in a million-acre play that will be talking about more as the years wears on. Those are the three big areas of spend for us throughout all of 2010. The fourth quarter was no different going forward in 2011, our spend should be at least I would guess 2/3 less than what it was in 2010.

We'll take our next question from David Kistler with Simmons & Company. David Kistler - Simmons & Company: Looking at your 159 rigs that you guys are operating right now, as we look at the Niobrara JV being completed, the Fayetteville sale done, do you have any kind of revision towards how you're looking at those rigs being directed from a liquids perspective and a gas perspective over the next year or so?

Jeff, let's see, this is Slide 14, I'm just going to let Jeff walk you through it and if anybody's following online, it's Slide 14 in our slide show presentation.

David, in the slide show you'll see really kind of four lines in the lower left hand corner of that graph. And then basically what it illustrates is, pretty level load of drilling in the Marcellus and Barnett particularly as we utilize our drilling carries. The dry gas plays will begin to ramp down the middle of this year particularly in the Haynesville Shale as we've accomplished a lot of our HBP drilling objectives. We'll continue to grow our liquids plays most notably in the Eagle Ford and the Niobrara. And if you really think about the growth in our drilling program from the beginning of 2010, obviously a year ago to the end of 2012, we will add approximately 120 -- nearly 120 rigs for that program and if it was a stand-alone company, that would be the biggest drill in America besides Chesapeake and that's just in our liquids play and that encompasses pretty much all of our drilling except for about three rigs in the deep Anadarko-Springer play. David Kistler - Simmons & Company: And kind of building on a comment that you made, Aubrey, about being in Trucking business. Right now, it's a great business to be in, obviously, Rig business has been attractive as we're watching capital get deployed to the oil areas and more rigs going to work everyday, are those areas that you would look at spending at any particular time, given the large ownerships there and the attractive market conditions right now?

Let me first make a comment on what we're doing with our vertical integration and I'll turn it over to Nick to mention to you several ideas that will range from nothing to doing something more dramatic, I would guess. So let's review. I think we're the fifth-largest drilling contractor in America with over 100 rigs today. We'll continue to gradually add rigs to our inventory over time. We believe were the largest oilfield truckers. We, at this point, do not have the capacity to haul oil but we are working aggressively on becoming an oilfield trucker of actual oil. And we are the second largest compression company in America, but [ph] obvious kind of void in our vertical integration story is in hydraulics, fracturing which we have drilled I guess synthetically through ending 26% of Frac Tech. So in addition to looking at ways to monetize that investment in this year, we are also building our own in-house capacity to hydraulically fracture wells and every day right now we need, I guess, just under 1 million horsepower to run our business and it's just so happens that Frac Tech has just about that same amount, maybe a little bit less. And so we're going to start by building four spreads this year and gradually building it out over time. We think this really will help the industry by bringing costs down, but also allow us to control more of our destiny. When we're all done, one could argue that inside of Chesapeake, you might have the largest U.S. service company out there when you combine our compression and our rigs and our frac-ing and our trucking and we also have a huge oilfield tool and Equipment Rental business as well. So lots of optionality embedded in that and I'll turn it over to Nick, to maybe give you a couple of things that he's been thinking about. Domenic Dell’Osso: Yes, so that's the key there. There's a lot of optionality. We certainly look at the success we had with taking our midstream business, creating a JV and then ultimately taking that JV public as a model that as possible to replicate with some of the other business within Chesapeake. It's been very successful for us to have that public entity evaluation put on our interest there as we think fair and reasonable for the investment we've made and the value that it creates in the marketplace today. We think it's possible that in the future we may want to do something similar with our Services business. No commitments to do that, no real plans to do that, but some thoughts around what you could do to highlight the value that we've created there into creative business that can be better served in the industry on a stand-alone basis capturing the margins for our shareholders for not just our services, but for third-party services as well. So a lot of different things you could do there if you were to look at the public markets. We do utilize the sale-leaseback market for both our compressors and rigs today. Those are rather high return to us or I should say a rather low cost of capital to us to do that and so that's been really a great market for us to access. And just really the optionality there is what's key and what's key for you guys to realize is that there are very large businesses that have very real value embedded here that we could do something within the future.

We'll take our next question from Neal Dingmann with SunTrust.

Aubrey, I had a question on your slides. I guess most recent slides shows on one of these about the Permian mid-continent wells doing over 1,000 barrels and I just wondered if you could comment, it does look like you are starting to see some really ramp up in the number of these areas like the horizontal Mississippian, Avalon, Bone Spring, et cetera. I just wondered if you could comment on just how much more I guess those results to continue to explode?

Neal, our operations team never likes to talk about our production exploding, so I'll talk about it increasing rapidly perhaps. Clearly, we've had a commanding presence in the Anadarko for over a decade and the Anadarko is really one of the most prolific gas well basins of the countries ever enjoyed discovering. And we started with the Granite Wash in 2007 and then in 2008 and '09, basically, we and everybody in the industry started to look very closely at all the tight rock in the Anadarko Basin. And so formation such as the Cleveland and the Tonkawa began to be looked at and since that time the information is like the Hawk Shooter and the Web Fork [ph] get looked at. We're very, very pleased with our Cleveland and Tonkawa results. Last time I checked we controlled, I think close to 1,000 sections of leasehold that would be perspective for those formations we think and that continue to be active in acquiring leasehold. The Anadarko of course is different than the Eagle Ford and Niobrara and Williston in some other places where there wasn't a whole lot of production and you just went in and went on county after county, buying new lease holds in the Anadarko, it's really square mile by square mile down in the trenches and providing for operations, and mostly sections are HBP are many of them are on legacy assets that we own. So we're pleased with that. Mississippian, we're in the Western part of the play, all of our friends are in the Eastern part of the play and we're lighter out to the east. So not quite sure how that's going to work. But certainly, we look what we've seen in the West. We also do have a high-water cuts, we've got to deal with that. But Oklahoma is a pretty favorable location to be dealing with water, there's plenty of electricity handy. And also, disposal wells are easily drilled and permitted and drilled as well. So 1,000 barrels a day equivalent wells are certainly what we're shooting for and all three of those plays. Permian, really same thing, four plays that we're looking at are stronger, Bones Spring, the Avalon, the Wolfcamp and the Wolfberry really in two basins, I guess, the Delaware is Avalon and Bone Spring and then Wolfcamp, Wolfberry in the Permian Basin. And again the goal remains the same, 1,000 barrels a day in tight rock, not all of it of course are sold, most of these are just tight sand, so we're encouraged by what we're seeing and have huge acreage position in each of these plays and will be steadily ramping up in all eight of these plays. Individually, it don't get as much attention as some of the bigger shale plays. But collectively, are certainly very, very important basins for us as we move forward converting our production base from gas to more oil.

And one last one if I could, Aubrey. I heard yesterday when your competitors talked about a new completion process in the Eagle Ford, just wondered if you could comment kind of around your process. You continue to see obviously quicker well -- better well results both on the cost side and just on the processes I wondered if you could comment on the Eagle Ford or a couple of your other liquid plays, it's the different things that you're doing in completion side along that front that you'll continue to see these results increase?

Sure. I'll turn the call over to Steve.

Neal, Steve Dixon. We're always looking for improvements and we're fortunate to have a number of plays and lots of wells drilled to experiment and we always try to optimize our completions. We don't believe that there is any silver bullet on any new product. Schlumberger had a fiber prop and transport assist product for a while and you may have some applications in someplace, but it's really not we think will be a game changer. But there is improvement being implemented all the time. Cost savings was high [ph], it's been a tough year on stimulation on the cost side. But again, we're very fortunate to have lots of data more than anyone else and I always trying to have continuous improvement.

Our next question is from David Tameron with Wells Fargo.

Just stepping back, I just want to focus a little more on the macro stuff you talked about, why there's been too much focus on liquids what are you seeing? I know you went to the points, but are you seeing something today different than what you saw three months or six months ago that gives you more encouraged or we just getting closer to that inflection point? I'm just trying to understand that gas commentary today and what's changed at all?

Well, first of all, and I doesn't have to spend much time making the bull case for oil. We're living it and breathing it as we all watch TVs and see what's happening around the world. But even away Mid East turmoil, you had $90 oil before that started. Clearly, we've got U.S. issue, short-term issue on the differential between WTI and what we think over time there's so much money in that arbitrage that it will get close it's just a matter of time. So plenty of money to be found in oil and we've known that for a long time, but I don't think we in the industry understood until a couple of years ago about how you found a lot of oil in the U.S. and then discovery and the ability to move oil out of these unconventional reservoirs is certainly a game changer for our company and certainly I think will be for the industry as well and as enormously positive implications for our country and perhaps we can lower oil imports in the future and create some great paying jobs here. I threw in the natural gas commentary, because it's really is true that we have really seen the whole tone of investor calls and interest in our company change really since the start of the year with regard to natural gas and last year, there were ample reasons for everybody to be bearish about natural gas and to think that just terrible product and you'll never going to make any money on it. But today, we really do have a lot inbound traffic with people seeing that we're kind of wondering when the worst is over. So they have their reasons and we developed our own reasons. And I think the most important of which, and I think the one that I don't hear anybody talking about, but it's the one that I like to talk about which is, again, once we make the shift from gas to oil and more importantly, the implications of that are moving from assembly line that's making a $4 widget and we're going to make a $15 widget, why in the world would we shipped back to making a $6 widget when we can make a $15 widget. And I think that's what people fail to appreciate. At the end of the day, this is a terrific product, something that this country needs, a low carbon fuel source and it just sells today at a terrible price because we reinvented supply before demand got reinvented. But it's too big of an arbitrage between gas and oil today. A lot of smart people with money out there are going to figure we're tying to help them and it's going to be arbitrage who at least in our view about six different ways. The long-term thing I'd like for people to think about here is that once the rig moves from gas to oil, gas going from $4 to $6 is not going to bring the rigs back, it's certainly wrong with this company and I can't imagine it happening in any other company as well.

Our next question is Curtis Trimble with MKM Partners.

Just kind of following up with what Dave was talking about, sending it internationally can you engage in a little bit of conversation of anything that you've looked at across the ocean, not necessarily the South African component, but the European, et cetera?

Curtis, we're not doing anything internationally today and can't imagine that we ever would, given the inventory of projects that we have. We did spend two years with Statoil, commencing in November of '08, looking around the world at unconventional gas prospects and I think we ended up evaluating something like 170 basins around the world. And it looks like there's a lot of potential when you first start. But when you recognize that you got to have the right kind of rock, you've got to have reasonable commercial terms, you've got real loft after having indigenous gas demand, indigenous gas pipeline, capacity and have to have indigenous service company infrastructure. The world strengthens pretty rapidly. The others and lot of guys looking at Poland and Ukraine and India and China and all that, but we've never could see how unconventional gas project around the world could compete with one of ours here in the U.S. More importantly, about halfway through that exercise, we discovered that we could find unconventional oil in the U.S. and we quickly arrived at the conclusion, with further conclusion that no international gas project could ever compare with the U.S. oil project. And that's why you have BHP here and that's why we have Reliance here that why you have seen out like Total is here. It's why Statoil is here, and a lot of Koreans are here and it's why the world is coming to the U.S. as we have unlocked the key to the most profitable oil development projects in the world. And clearly, the people are evidencing that by opening their checkbooks and again it's something that we're proud and pleased to be part of and I think it will revalue assets because obviously gas assets are undervalued in the eyes of these big major companies and they're going to snap up the number of these. I think that will reprice U.S. E&P companies and then I think you're going see to start to buy oil projects, overall. So I think it's just a terrific time to be long. Oil and gas process in the U.S. and there be a day when gas gets a little more respect, just reiterate that we have no interest in international projects, we got decades and decades worth of activity right here in America.

I meant more on the market development side, figuring out additional uses of gas there driving your CGV commentary with the U.S., that type affecting the other side of the equation, not just on the supply side but also on the demand side.

Sure. There are a lot more CG cars and trucks around the world than there are here in America. We are encouraging OEMs who make factory ready for CMD cars and trucks around the world to do so here. GM's already come out with two models. Ford and GM are both planning more models in the years ahead. So the U.S. is behind for various reasons, but I really do think that we'll catch up and we're going to be forced to catch up when gasoline prices start to become a major topic of economic and political concern here in the weeks and months ahead.

[Operator Instructions] We'll take our next question from Dan McSpirit with BMO Capital Markets.

I wondered if you can share your thoughts on the decision to sell the Fayetteville shale assets. Why were they chosen versus other natural gas assets in the portfolio? Was it they simply didn't compare as favorably to those other assets just simply on a return point of view? Or was it an asset that set the specific needs of BHP, the buyer in this case, and it came down to simply right time and right place?

Well, if you could examine what we had, we had four big unconventional assets, Fayetteville, Marcellus, Haynesville and Barnett. And when we looked - we, first of all, look at what fit us rather than what might fit another company, and we were looking for an asset divestiture about this size to achieve our 25/25 objectives. The Marcellus is way too underdeveloped at this point considering kind of the sale there and the asset size there we knew would limit the number of buyers that would have a price tag of well north of $10 billion. The Barnett is embedded inside the urban and suburban environment in Fort Worth. And Total got comfortable with being our partner there, but it's a tough place to be an operator. And so it didn't really think that, that would be one that would attract worldwide interest in the asset. And then finally, the Haynesville we're not through HBP and still got the Bossier to develop. And again, it's a huge well north of $10 billion asset as well. So circle back to the Fayetteville, rightsize largely HBP, great asset, great returns in a state that's receptive to natural gas drilling from a regulatory and environmental perspective and we felt like we didn't know when we started out, we didn't know who would be interested, but we felt like a wide variety of companies. So we're really, really happy with the outcome, really happy with BHP. It's kind of in charge of assets for most people, maybe it's the price the world's fourth most valuable company and the company with enormous resources. And obvious ambitions and they're going to do a great job with this project and we're going to spend the next year making sure that there's no hiccups when we do the handoff. They've got a great asset, they've got a great price for it and we were able to sell a great asset at a great price for us. That's one of the situations where I think both companies can walk away the better for and at this point we've done the gas assets selling that we need to do and now it's power forward and concentrate it on the 25% production growth now that we pretty much are going to have the 25% debt reduction part of the planned in the bag.

Referring to your proved and unproved resource table in the press release, when will we begin to see the data field in under the Powder River and DJ Basin potential or is the timing just simply dependent on a JV? And is there any Niobrara well data that you can share with us today that speaks to the resource potential, especially at the low GOR variety?

Sure, Dan. On Page 15 on our slide presentation, I think the last couple of months, we've highlighted a couple of frontier in Niobrara wells, up in the Powder River Basin. I don't think we publicly announced anything in the DJ yet, but we'll start to fill in that data during the remainder of 2011. We don't like to put out a lot of information about risk factor or anticipated density per well when we've only drilled a couple of dozen wells. So we certainly have those assumptions in house and obviously it will confirmed by CNOOC when they became our partner there but that's for public disclosure. It will take a little bit more time in 2011. And of course, one of the great things about that play is there's a lot of industry activity as well. So like the Eagle Ford, you're going to get really kind of tidal wave, if you will, of information get releases on those plays over the remainder of the year.

You spoke at the top of the call about your participation in certain LNG and GTL projects. Any additional texture or color you could share?

None other than, I think it's well known that we've been working closely with the Chinear [ph] trying to provide them with the supply assurance that they need to attracts off takers to their proposed facility and so we'll see where that ends up taking it. But clearly, we've exported every other product of significance in America and we export gas everyday to Mexico and to Canada by pipeline and we've exploited LNG from Alaska for decades. So we think the time has come to begin exporting gas from the form of LNG, from the point of Gulf Coast. With regard to GTLs, we're very excited about the possibility of the chemical transfer transformation natural gas to oil. Obviously, the world has being doing it in some form or fashion for the last 70 years, but we're looking for real breakthroughs in a process that heretofore is pretty energy intensive consumer as much as 40% of the natural gas in the process is converting it into a liquid. We think it's really interesting idea and we're in communication and dialogue with people about how we might contribute in gas to a venture that could prove that up. And that's the Holy Grail. If we can make a $4 product competitive with $15 product or substitutable for a $15 product, then we will have made an enormous contribution to our industry and our company shareholders as well. So we got a whole group set up to do nothing but pursue breakthroughs and evaluating people who come to us with potential breakthroughs in GTL technology. So very excited about it and I think there'll be one in the next couple of years that will lead to a GTL, commercial GTL projects in the U.S. by year-end 2016.

[Operator Instructions] We'll take our next question from Marshall Carver with Capital One Southcoast.

You spent a lot of time in your concluding remarks at the Analyst Meeting about how much value Chesapeake was creating, buying acreage and then JV-ing at a big profits. And then you switched strategy somewhat and the stocks respond marvelously with the new 25/25 Plan. Just a question on, did you think basically the land grab is somewhat over for both oil and gas? And did that pay a part of your plan or was it much more --- a big part of it was the harnessed the evaluation gap between where you thought your assets were working with the stock was trading. But what are your thoughts along the land grab and where that stands and then beyond 2012, what are your thoughts on acquiring acreage, your plans basically outlined the next couple of years, but Chesapeake has certainly created a lot of value over the last couple of decades acquiring acreage. What are your thoughts over the midterm, the 2013s and 2014s?

Good way to conclude the call and kind of wrapping all this up. I really would like for you to think about the 25/25 Plan as not a abrupt change from what we were doing in 2010, but really, a natural evolution from what we were doing in 2010. And to give you just some context, in 2006, 2007, we realized that we could find natural gas in enormous quantities in unconventional reservoirs, primarily shales and we recognized that this was such a game changer that the opportunity wouldn't last very long. And so we went out and spent billions of dollars to acquire that gas leasehold and then quickly de-risk it by bringing in the partners that I've mentioned on this call. And I do think the gas -- I did think the land rush was over in 2008, but I didn't have enough faith I suppose or vision to recognize that our operational team and other companies would be able to take that expertise in that technology and apply it to unconventional reservoirs of which shale of course is just one. And so when that became obvious to me in 2009 and all of a sudden, we could change the product that our assembly lines in our gas factory was making to something more highly valued in the form of oil and natural gas liquids, then it wasn't a difficult decision to make that transition away from just sole focus on gas. So we did that in 2010 and it's expensive on a net basis we spent almost $5 billion doing that. We stretched investors patience, I think, and clearly stretched our balance sheet a bit to do that. But to have not done it would have been a huge mistake and instead this call would have all been about why we should think gas prices would be better going forward and don't pay attention to those guys who are drilling wells that are valued at 4x more than our wells are valued at. So the 25/25 Plan is a natural evolution of taking advantage of what I think is a once-in-a-lifetime opportunity that was presented to us in late '09 and early '10 to go out and establish positions in the Eagle Ford, the Niobrara, the Permian Basin, the Anadarko Basin, small position for us in the Williston and a few other places. And it really changed the course of our company's history going forward. And now it's all about harvesting because we think that we've systematically we've explored along with other companies and all of the sedimentary basins in the U.S. Will there still be any device when we sell. We're going to continue to invest and pouring it up in our areas. But do I think there's another Eagle Ford out there? Do I think there's another Niobrara, another Williston Basin? I think there may be one more, but I don't think there's two, or three, or four, or five more. So I think that's face of the industry's history and our history is coming to a close and I think people can now see that they're going to get paid from this enormous inventory of leasehold that we've build up that we think is best in industry and we're going to start converting it to production reserves and cash flow and earnings. And that's I think that's going to be the next 10 years of the company's history, I think are going to be far more rewarding than the past 10 have been I think I saw yesterday that S&P 500 we were in the top 10 and returned a little past 10 years to shareholders. So my aspiration is to deliver that same kind of outperformance in the next 10 years and I think we have the assets and the strategy and the capital and the people to do that. So if there are no other questions, we'd like to thank you for your participation today's call. If you have other questions, certainly, channel them through Jeff and we'll get back to you soon as we can. Thanks, very much

And that does conclude today's conference. Thank you for your participation.