Chesapeake Energy Corp (CHK) 2010 Q4 法說會逐字稿

Good day and welcome to the Chesapeake Energy 2010 fourth-quarter and year-end operational update and earnings results conference call.

Today's conference is being recorded.

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 we will move to Q&A.

I will now turn the call over to Aubrey.

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 sale agreement with BHP.

Our sale of the Fayetteville strongly validates a critical point we've made for some time, the assets of our company are worth far, far more than what was implied by our current stock price, even after the $10 run of 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 while also accelerating the rapid transition of our capital spending towards higher-value liquids-rich plays will be completely transformative for Chesapeake and it's investors in the years ahead.

We are 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 liquid-rich plays, we believe we can generate $10 million 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 million 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 drill bit, 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 the drill bit, 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 whom have enterprise values of $10 billion or more.

We duplicated or exceeded their reserve base in one year through the drill bit.

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 for Chesapeake.

It is truly unique in the industry and will create huge value in the years ahead as we rapidly convert our undeveloped acreage into 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 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 Springs, and Wolfberry plays, to name just the most well-known of our plays with huge amounts of unrecognized upside.

What could these 175 TCF and 15 billion barrels of unproved resources be worth?

We think we have established, through various joint ventures and through 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, and our service company assets, plus $4 billion of drilling carries that are also not reflected in our current market value.

Add it all up and I think you can easily confirm asset value 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.

Yet we are still going to be able to increase our production this year by about 8% to 9%.

Please ask yourself 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 it once again proves 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 final 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 and 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 an increasing level 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 transition to oilier asset base 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.

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 the 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 US will become more challenging in the years ahead.

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.

With much of the rest of the world using oil-based naphtha as a 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 vehicles, especially if gasoline and diesel prices continue to increase.

Even though our federal government and Congress have yet to understand the importance of CNG to reducing US 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 virtually every corporate and state and local government fleet in the US considering moving to CNG vehicles.

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, liquefied natural gas will be exported from the US 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 US will be a very bullish event and should begin to affect the back of the natural gas curve once ground breaks on several of these projects by year-end 2012.

I'll 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 US by year-end 2016.

When the 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 the marginal cost of gas supply in the US is around $5.50 per MCF.

Today's drilling economics are being largely ignored as the industry races to hold acreage acquired in the great Shale gas land grab 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 is one more factor here at work that I'd like to highlight.

I think we can agree that there's almost unanimous consent among investors -- consensus among investors and analysts that 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, and 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.

We are responding by transitioning our drilling programs as rapidly as we can from gas to oil.

To remind you of 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 or oil plays where the rigs will be drilling wells that produce $15 units and a much more competitive rate of return, 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 that investors and analysts believe that somehow a potential increase in natural gas prices from, say, $4 to $5 or maybe even to $6 per MCF will somehow bring those rigs back from drilling oil projects where the revenue level will be $15, or 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 in more valuable oil plays to drilling and 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 your ongoing interest in our company.

Nick?

Our fourth quarter and really all of 2010 represents 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, Monday's announcement will lead to a quick win in our plan to reduce debt by 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 in that we are selling an asset for a very nice return and BHP is acquiring what we think is a perfect entry into onshore North American market.

Given our tax basis in 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 our full cost pool, and so in the future, we will 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 a result of the sale.

As stated before, upon closing, we will look to retire $2 billion to $3 billion of our senior notes.

On to the results for the period.

We had a very solid 2010 with about $1.7 billion of net income and $4.5 billion of operating cash flow on 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 the period where we allocated about 30% our drilling and completion to liquids plays.

I'd like to remind you that we plan to allocate 53% and 74% 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 would also like to remind you that the LOE burden that VPPs represent is included in this number, so it's still best-in-class after that effect.

Additionally, I'd like to cover a few points on our hedging program.

Our natural gas production is currently very well hedged for 2011.

In 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 head price on gas by selling calls in out years on a relatively small portion of our projected production, and 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 multi-party hedge facility that allows us to hedge through 12 different highly rated financial counterparties for as much as five years of our production at one time.

Today, we've used just over 50% of that capacity.

Also, I'd like to remind everyone that, given the facilities supported by our oil and gas reserves as collateral, if we are ever underwater on our trades, the value of our counterparty's collateral goes up as an offset.

As a 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 maintain 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 change in projected production for the year.

Looking forward, we are 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 to review the economics of the JVs 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 our 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 JVs 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 and the Company through a debt buyback.

So that concludes our prepared works for the day.

With that, operator, we will turn it back over to you for questions.

(Operator Instructions).

David Heikkinen, Tudor Pickering Holt.

Good morning.

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?

Sure David.

In general, we certainly are cognizant of all of the problems getting oil out of those areas, but have a multi-capacitive 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 a pipeline.

Obviously, pipeline is the ultimate answer choice for all of these plays.

So we have a very big and active marketing group and midstream group, and they are attacking all of these areas with all the resources that we have come as well as some third-party partners.

So we've built in the delays into our production ramp-up forecast that are embedded in new plays.

We have inefficiencies like in the Eagle Ford of trucking oil for -- to 400 miles round-trip today, whereas within a year or so, we will have our pipelines in there.

Steve, what's --?

Pipelines will be in '13, with rail hopefully the end of this year.

Yes, so we'll be -- we are trucking today, we go to rail and then ultimately a pipeline.

That's kind of the three phase approach to really each of these areas that we are talking about.

Obviously, if you've got a truck with a tank on the back, it's a good time to own that asset.

Can you talk about that kind of lumpiness for those plays?

When do you get the rail capacity?

What is that capacity now?

How much capacity do you have for trucking?

I'm just trying to think about as we model and run out 2011, 2012, 2013 as each of these plays kind of grows.

I think that really highlights the advantage of our business strategy, David, that we are 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 drives home the benefit of a multi-play approach.

So we think, when you look at our production forecast, you can -- there will be some quarters that will be growing at different speeds than surrounding quarters, but generally speaking, it's a linear growth model that we will be reporting, we think.

Again, there will be delays -- some bigger delays in some areas than in other areas, but overall they'll have that asset diversification we think is really important.

Okay.

Then just thinking about your commentary around the macro, I just wanted to think about overall operating cost and margins for a typical gas well in your portfolio versus one of the new typical oil wells.

If you could just walk us through what is the cost structure of each, and kind of where is the margin delta?

Sure.

If you look at signing costs, which I guess is the place to start, our signing costs are going to be somewhat higher in our oil plays.

That can be no higher to as much as 25% to 50% higher.

Then lifting costs typically in an oil well are going to be around 50% higher or so.

It just kind of depends on how much of the liquids come with substantial gas production as well.

Beyond that, it's really about the same.

So we think, if you are -- let's say you're finding gas at $1.25 an MCF and that translates into oil of $7.50 a barrel, that probably means you're finding oil in the $10 to $11 range.

That's one of the reasons why of course we always want it carried because, in the initial years of a play, we certainly want more of those costs to be borne by our partners rather than by us.

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, in the Fayetteville, and you're going to buy -- pay back $2 billion to $3 billion of senior notes, how do think of using your revolver and then kind of capacity on that heading forward?

I'll let Nick answer, but obviously it will be greatly reduced as a result of what we're doing this year and next year.

Yes, so that's right.

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 are all of our incoming cash proceeds from deals like this.

We will tender for some bonds, and so you'll see the revolver go to zero and then tick back up to some usage.

It will continue to be our working capital facility, which will be utilized higher at some times than others, but it will be less over time than it has been over the last year or so.

This pursuit of investment grade status, your thoughts around that?

Now is it --?

What's your question?

Pursuit of investment grade?

Yes, so 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 are hopeful that we will continue to work with the agencies and get some nice credibility for what we have done, but not wanting to try and predict what and when their reactions 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.

So debt coming down and proved reserves going up pretty rapidly, we think we are headed in the right direction.

Thanks guys.

Brian Singer, Goldman Sachs.

Thanks, good morning.

A couple of questions.

First, what drove the gas guidance increase?

If we exclude the Fayetteville sale, I think your gas production guidance increased a little bit.

Maybe that provides an 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 greater contribution from associated gas.

It's just really a result of kind of running ahead of our model.

And so you can only suppress a model so far and so long I guess.

So really all of our plays continue to work exceptionally well.

We will be very sad to see the Fayetteville go.

It was our second unconventional gas resources play and a very important part of our understanding of unconventional resources in the US.

But I wouldn't attribute it to any particular play, although there's obviously been strong commentary the last couple of days about what we are seeing in the Marcellus.

While the play is not as vital or critical to us as it is to a couple of our competitors, certainly the EURs that are being recorded in southwestern PA and in Northeastern PA, we are experiencing those very soon EURs as well.

So basically wherever we are drilling today, we think we are outperforming our models, and so from time to time, you'll probably see our production tick up.

That's why we give a pretty good range of what the outcome could be in 2010 and 2012 from 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 two-thirds in 2012.

I think perhaps the most important take-away is to examine what the Company's underlying structural rate of growth is.

That's really about 20% per year.

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 ongoing success in our gas plays, along with these liquids plays as well.

Great, thanks.

In the Granite Wash and Colony Wash, can you talk to what you've seen from recent well results, and of the acreage of your acreage position, what percent you've actually 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 and Granite Wash play.

For those of you who may not be familiar with it, Colony Wash is in Washita County and Custer County in western Oklahoma, and then the play that's received probably the most publicity because so many companies are in it, whereas we own 85% of the Colony Wash/Granite Wash play would be the Texas Panhandle Granite Wash play.

We've read over the last couple of days commentaries from other companies there.

We have not expressed or we haven't experienced some of the issues that perhaps other companies have.

I think we have been more conservative in our production forecast and, frankly, in our management of our wells.

And so we are still -- you said 155 acres.

I guess we call it 160 acre since it's roughly four wells (multiple speakers)

(multiple speakers) Average from the multitude of plays in the Anadarko Basin.

Yes, so, at any rate, do we want to -- what percentage do we want to go with here, guys?

On acreage.

For the Granite Wash and Texas Panhandle, basically 100% of our acreage is proven to be perspective.

Then in Colony Wash, I would guess around 80% of our total acreage that is listed there is probably going to be prospective at the end of the day.

We are kind of working on some of the fringe acreage right now.

If I could ask one last one, just looking at your total acreage, that of 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 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.

Then we have continued to build acreage in a 1 million acre play that we will be talking about more as the year wears on.

But those are the three big areas of spend for us throughout all of 2010, and the fourth quarter was no different.

Of course going forward in 2011, our spend should be at least I would guess two-thirds less than what it was in 2010.

Thank you.

Dave Kistler, Simmons & Co.

Good morning guys.

Looking at your 149 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?

Sure.

Jeff, let's see.

This is Slide 14.

I'm just going to let Jeff walk you through it.

If anybody is following online, it's Slide 14 in our slide show presentation.

Yeah, David.

In the slide show, you will see really kind of four lines in the lower left-hand corner of that graph.

Basically what it illustrates is a 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.

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 to that program.

If it was a standalone company, that would be the biggest driller in America besides Chesapeake.

That's just in our liquids play.

That encompasses pretty much all of our drilling except for about three rigs in the deep Anadarko-Springer play.

Great, that's helpful.

Kind of building on a comment that you made, Aubrey, about being in the trucking business right now, it's a great business to be in.

Obviously, rig business has been attractive as we are watching capital.

You get deployed to the oil areas and more rigs going to work every day.

Are those areas that you would look at spinning out at any particular time, given the large ownership there and the attractive market conditions right now?

Let me first make a comment on what we are doing with our vertical integration and then I'll turn it over to Nick to mention to you several ideas that will range from doing nothing to doing something more dramatic I would guess.

So let's review.

I think we are the fifth-largest drilling contractor in America with over 100 rigs today.

We will continue to gradually add rigs to that inventory over time.

We believe we are 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.

We are the second largest compression company in America.

The obvious kind of void in our vertical integration story is in hydraulic fracturing, which we have filled I guess synthetically through owning 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.

Every day right now, we need I guess just under 1 million horsepower to run our business, and it just so happens that Frac Tech has just about that same amount, maybe a little bit less.

So we are 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 are all done, one could argue that inside of Chesapeake you might have the largest US service company out there when you combine our compression and our rigs and our fracing and our trucking, and we also have a huge oilfield tool and equipment rental business as well, so lots of optionality embedded in that.

I'll turn it over to Nick to maybe give you a couple of things that he has been thinking about.

Yes, so that's the key there is there's a lot of optionality.

We certainly look at the success we've had with taking our Midstream business, creating the JV and then ultimately taking that JV public as a model that is possible to replicate with some of the other businesses within Chesapeake.

It's been very successful for us to have that public entity valuation put on our our interest there is we think fair and reasonable for the investment we've made and the value 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 commitment 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 and to create a business that can be better serving the industry on a standalone 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.

There is a 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 a really great market for us to access.

Really the optionality there is what's key.

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 with in the future.

Great, thank you for that additional detail guys.

Neal Dingmann, SunTrust.

Good morning guys.

Aubrey, I had a question on your slides.

I guess the most recent slide shows one of these about the Permian Mid-Continent Wells doing over 1000 barrels.

I'm just wondering if you could comment.

It does look like you are starting to see some really ramp-up in a number of these areas, like the horizontal Mississippi and Avalon, Bone Springs etc.

I just wonder if you could comment on just how much more I guess those results can continue to explode.

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 and oil basins that the country has ever enjoyed discovering.

We started 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 of the tight rock in the Anadarko Basin.

So formations such as the Cleveland and the Tonkawa began to be looked at, and since that time we've done formations like the Hog Shooter and the Red Fork get looked at.

We are very, very pleased with our Cleveland and Tonkawa results.

The last time I checked, we controlled I think close to 1000 sections of leasehold that will be perspective for those formations we think and continue to be active in acquiring leasehold.

The Anadarko of course is different than the Eagle Ford and Niobrara and Williston and some other places where there wasn't a whole lot of production and you just went in and went in county after county buying new leaseholds.

In the Anadarko, it's really square mile by square mile down in the trenches, fighting for operations and most of these sections are HBP and many of them are on legacy assets that we own.

So we are pleased with that.

Mississippian, we are in the western part of the play.

Other of our friends are in the eastern part of the play.

We are lighter out to the east, so not quite sure how that's going to work, but certainly we like what we've seen in the West.

The wells do have a high water cut, so you'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 disposal wells are easily drilled, permitted and drilled as well.

So 1000 barrel a day equivalent wells are certainly what we're shooting for in all three of those plays.

Permian, really same thing, four plays that we are looking at, strong Bone Springs, Avalon, Wolfcamp and the Wolfberry, and really in two basins I guess.

The Delaware is Avalon and Bone Springs and then Wolfcamp and Wolfberry in the Permian Basin.

Again, the goal remains the same, 1000 barrels a day in tight rock and not all of it of course is shale.

Most of these are tight stands.

So very encouraged by what we are seeing and have huge acreage positions in each of these plays, and will be steadily ramping up in all eight of these plays that individually 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.

One last one if I could.

I heard yesterday one of your competitors talk about a new completion process in the Eagle Ford.

Just wondering if you can 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 wonder if you could comment on the Eagle Ford or a couple of your other liquid plays, if there are different things you're doing on the completion side, along that front, that you will continue to see these results increase.

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

It's Steve Dixon.

We are always looking for improvements, and we're fortunate to have a number of plays and lots of wells drilled to experiment and to always try to optimize our completions.

We don't believe that there is any silver bullet on any new product.

Schlumberger has had a fiber prop into a transport assist product for a while and may have some applications in some plays, but it's not really -- what we think will be a game changer.

But there is improvement being implemented it all of the time.

Cost savings we are striving for.

It's been a tough year in simulation on the cost side.

But again, we are very fortunate to have lots of data, more data than anyone else, and always trying to have continuous improvement.

Thanks Steve.

Great execution, guys.

Thanks so much, Neal.

Appreciate it.

David Tameron, Wells Fargo.

I'd echo nice job over the last few months doing what you said you're going to do.

Thank you, David

Just stepping back, I just want to focus a little more on the macro stuff you talked about and why there's been so much focus on liquids.

What are you seeing?

I know you went through the points, but are you seeing something today different than what you saw three months ago or six months ago to get you a little more encouraged, or are we just getting closer to that inflection point?

I'm just trying to figure out why the nat gas commentary today and what's changed at all.

First of all, a guy doesn't have to spend much time making the bull case for oil.

We are living and breathing it as we all watch TV and see what's happening around the world.

But even away from Mideast turmoil, you had $90 oil before that started, and clearly we've got a US issue, short-term issue, on the differential between WTI and Brent.

But we think over time there is so much money in the arbitrage that it will get close.

It's just a matter of time.

So plenty of money to be found in oil, 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 US.

The discovery of the ability to move oil out of these unconventional reservoirs certainly has been a game changer for our company and certainly I think will be for the industry as well, and has enormously positive implications for our country as perhaps we can lower oil imports in the future and create some great paying jobs here.

I threw in the natural gas commentary today because it 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.

In the last year, there were ample reasons for everybody to be bearish about natural gas and to think that it's just a terrible product, and you're never going to make any money at it.

But today, we really do have a lot of inbound traffic with people saying we are kind of wondering when the worst is over.

So they have their reasons and we developed our own reasons, I think the most important of which and I think the one I don't hear anybody talking about but it's one I like to talk about, which is, again, once we make this 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 shift back to making a $6 widget when we're going to make a $15 widget?

I think that's what people fail to appreciate.

At the end of the day, this is a terrific product, something 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 out what arbitrage, and we're going to try and help them.

It's going to be arbitraged through, at least in our view, about six different ways.

But the long-term thing I'd like for people to think about here is that, once the rigs move from gas to oil, gas going from $4 to $6 is not going to bring the rigs back.

It certainly won't at this company, and I can't imagine it happening at any other company as well.

That answers it.

Thanks for all the color.

Everything else was answered.

Appreciate it.

Curtis Trimble, MKM Partners.

Sure, I appreciate it.

Just following up with what Dave was talking about and extending 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 European, etc.?

Sure.

Thanks for the question.

We are not doing any 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.

I think we ended up evaluating something like 170 basins around the world.

It looks like there's a lot of potential when you first start, but when you recognize that you've got to have the right kind of rock, you've got to have reasonable commercial terms, you've got to have rule of law, have to have indigenous gas demand, have to have indigenous gas pipeline, capacity and have to have indigenous service company infrastructure, the world shrinks pretty rapidly.

So yes, there's a lot of guys looking at Poland and Ukraine and India and China and all that, but we never could see how a gas -- unconventional gas project around the world could compete with one of ours here in the US.

More importantly, about halfway through that exercise, we discovered that we could find unconventional oil in the US.

We quickly arrived at the conclusion, the further conclusion that no international gas project could ever compare with the US oil project.

That's why you have BHP here, and that's why you have Reliance here; it's why you have CNOOC here.

It's why Total is here.

It's why Statoil is here.

It's why the Koreans are here.

It's why the world is coming to the US is that we have unlocked the key towards -- to the most profitable oil development projects in the world.

Clearly, people are evidencing that by opening their checkbooks.

Again, it's something that we are 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.

They're going to snap up a number of these, and I think that will re-price US E&P companies.

Then I think you're going to see them start to buy oil projects as well.

So I think it's a terrific time to be long oil and gas assets in the US, and there will be a day when gas gets a little more respect here.

But we have, I'll just reiterate that we have no interest in any international projects.

We've got decades and decades worth of activity right here in America.

I'm sorry.

I meant more on the market development side, figuring out additional uses for gas.

Is there a driving your CNG commentary with the US, that type of -- affecting the other side of the equation, not just on the supply side but also on the demand side?

Sure.

There's a lot more CNG cars and trucks around the world than there are here in America.

We are encouraging the OEMs who make factory-ready CNG cars and trucks around the world to do so here.

GM has already come out with two models.

We know Ford and GM are both planning more models in the years ahead.

So the US is behind for various reasons, but I really do think we will catch up.

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.

I appreciate it.

Thank you.

(Operator Instructions).

Dan McSpirit, BMO Capital Markets.

Good morning.

Thank you for taking my questions.

Dan.

I wonder if you could 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 that 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 fit the specific needs of BHP, the buyer in this case, and it came down to simply the right time, right place?

Well, let's kind of examine what we had.

We had four big unconventional assets -- Fayetteville, Marcellus, Haynesville and Barnett.

When we looked, we first of all looked at what fit us rather than what might fit another company.

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 to consider any kind of a sale there.

The asset size there we knew would limit the number of buyers.

That would have a price tag well north of $10 billion.

The Barnett is embedded inside of an urban and suburban environment in Fort Worth.

Total got comfortable with being our partner there, but it's a tough place to be an operator and so didn't really think that would be one that would attract worldwide interest in the asset.

Then finally, the Haynesville we are not through HBP-ing, and we've still got the Bossier to develop.

Again, it's a huge well north of a $10 billion asset as well.

So circle back to the Fayetteville.

The right size, largely HBP, a great asset, great returns in a state that's receptive to natural gas drilling from a regulatory and environmental perspective.

We felt like we didn't know if -- when we started out, we didn't know who would be interested, but we felt like a wide variety of companies.

So we are really, really happy with the outcome, really happy that BHP is going to be in charge of the asset.

For most people, it may be a surprise to the world's fourth most valuable company and a company with enormous resources and obvious ambitions.

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, and they got a great price for it, and we were able to sell a great asset at a great price for us.

So it's one of those situations where I think both companies can walk away the better for it.

At this point, we've done the gas asset selling that we need to do, and now it's power forward and concentrate on the 25% production growth now that we pretty much are going to have the 25% debt reduction part of the plan in the bag.

Got it, appreciate the context.

The next question, if I could?

Referring to your proved an unproved resource table in the press release, when will we begin to see the data filled in under the Powder River and DJ Basin potential, or is the timing just simply dependent on a JV?

Is there any Niobrara well data that you could share with us today that speaks to the resource potential, especially of the low GOR variety?

Sure, Dan.

On Page 15 of our slide presentation, I think, for the last couple of months, we've highlighted a couple of Frontier and Niobrara wells up in the Powder River Basin.

I don't think we've publicly announced anything in the DJ yet, but we will start to fill in that data during the remainder of 2011.

We just don't like to put out a lot of information about risk factor and anticipated density per well when we've only drilled a couple of dozen wells.

So we certainly have those assumptions in-house, and obviously they were confirmed by CNOOC when they became our partner there, but for public disclosure, it will take a little more time in 2011.

Of course, one other great thing 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 a tidal wave, if you will, if information get released on those plays over the next -- over the remainder of the year.

Okay.

Then last one if I could?

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?

No, other than I think it's well-known that we have been working closely with Cheniere to try and provide them with the supply assurance that they need to attract off-takers to their proposed facility.

So, we'll see where that ends up taking us.

But clearly we export every other product of significance in America, and we export gas every day to Mexico and to Canada by pipeline and we've exported LNG from Alaska for decades.

So, we think the time has come to begin exporting gas in the form of LNG from the Gulf Coast.

With regard to GTLs, we are very excited about the possibility of the chemical transformation from natural gas to oil.

Obviously, the world has been doing it in some form or fashion for the last 70 years, but we are looking for real breakthroughs in a process that heretofore has been pretty energy intensive, consuming as much as 40% of the natural gas in the process of converting it into a liquid.

We've seen some really interesting ideas and we are in communication or in dialogue with people about how we might contribute some gas to a venture that could prove that up.

That's the Holy Grail.

If we can make a $4 product competitive with a $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've got a whole group set up to do nothing but pursue breakthroughs -- or evaluating people who come to us with potential breakthroughs in GTL technology.

So very excited about it, and I think there will be one in the next couple of years that will lead to a GTL, commercial GTL projects in the US by year-end 2016.

Thank you.

Appreciate the comments.

Thank you, Dan.

(Operator Instructions).

Marshall Carver, Capital One Southcoast.

Good morning.

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 it at big profits.

Then you switched strategy somewhat and the stocks responded marvelously with the new 25/25 plan.

Just a question on -- did that -- did you think basically the landgrab is somewhat over for both oil and gas, and did that pay a part of your plan, or was it much more -- I know a big part of it was to harness the valuation gap between where you thought your assets were worth and where the stock was trading.

But what are your thoughts along the land grab and where that stands?

Then beyond 2012, what are your thoughts on acquiring acreage?

Your plans basically outline 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, you know, the 2013s to 2014s?

Marshall, thanks for the question, and I think a 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 an abrupt change from what we were doing in 2010, but really a natural evolution from what we were doing in 2010.

To give you just some context, in 2006/2007, we realized that we could find natural gas in enormous quantities in unconventional reservoirs, primarily shale.

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 derisked it by bringing in the partners that I've mentioned on this call.

I did 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 and that technology and apply it to unconventional reservoirs of which shale of course is just one.

So when that became obvious to me in 2009 that all of a sudden we could change the product that our assembly lines and 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.

It was 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've all been about why you should think gas prices will be better going forward and don't pay attention to those guys who are drilling wells that are valued at four times more than our wells are valued at.

So the 25/25 plan is the 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, in the Niobrara, and the Permian Basin, Anadarko basins, small position for us in the Williston and a few other places, and to really change the course of our company's history going forward.

Now it's all about harvesting, because we think we've systematically explored, along with other companies, all of the sedimentary basins in the US.

Will there still be a need to buy some leasehold?

Sure.

We're going to continue to invest in coring it up in our areas.

But do I think there is another Eagle Ford out there, or do I think there is another Niobrara or another Williston Basin?

I think there may be one more, but I don't think there's two, three, four, or five more.

So I think that phase of the industry is history, and our history is coming to a close.

I think people can now see that they are going to get paid from this enormous inventory of leasehold that we've built up that we think is the best in the industry.

We are going to start converting it to production and reserves and cash flow and earnings.

That's I think going to be -- the next ten years of the Company's history I think are going to be far more rewarding than the past ten have been, even though I think I saw yesterday that, among the S&P 500, we were in the top ten in return over the past ten years to shareholders.

So my aspiration is to deliver that same kind of outperformance in the next ten years.

I think we have the assets and the strategy and the capital and the people to do that.

If there are no other questions, we would like to thank you for your participation in today's call.

If you have other questions, certainly channel them through Jeff and we will get back to you as soon as we can.

Thanks very much.

That does conclude today's conference.

Thank you for your participation.