Chesapeake Energy Corp (CHK) 2011 Q1 法說會逐字稿

Good day, and welcome, everyone, to the Chesapeake Energy 2011 first-quarter earnings results conference call.

Today's conference is being recorded.

At this time, I would like to turn the conference over to Jeff Mobley.

Please go ahead, sir.

Good morning, everyone and thank you for joining our 2011 first-quarter financial and operational results conference call.

With me this morning are Aubrey McClendon, our Chief Executive Officer; Steve Dixon, our Chief Operating Officer; Nick Dell'Osso, our Chief Financial Officer; and John Kilgallon, our Manager of Investor Relations and Research.

We will have prepared remarks by Aubrey and Nick and then we will go to Q&A.

Good morning.

We hope you have had time to review yesterday's 2011 first-quarter operational and financial release.

We are off to a very good start to 2011 and I would like to begin my remarks by highlighting three significant achievements in the first 90 days of the year.

First, I hope you noticed that we have already reached our 25% debt reduction goal of the 25/25 plan.

Now we just need to maintain where we are from here on and that is our plan.

Secondly, we have efficiently and uniquely built an internal oilfield service company as a way to counter oilfield inflation and enhance the efficiency of our operations.

We believe this enterprise is worth at least $7 billion and we intend to seek partial monetization of it in 2012.

Third, we have established industry-leading leasehold positions in two potentially very significant new liquids-rich plays.

The first of these is the 1.2 million net acres that we have acquired in the Utica Shale play of far western Pennsylvania and eastern Ohio.

The second is the 1.1 million net acres that we have acquired in the Mississippian Carbonate Play in northern Oklahoma and southern Kansas.

We expect to initiate JV efforts in both of those plays in the 2011 second half and to provide more production results from our efforts in both plays as the year progresses.

In the meantime, I would remind you that recent liquids-rich JV acreage values have been in the range of $5,000 to $20,000 per net acre.

Using something in the $10,000 per acre range would indicate that these positions could be worth $23 billion to our Company.

Combine that with the $7 billion of service company value pick-up and you can say that we are highlighting more than $30 billion of potential value creation in this quarter alone.

Given where our stock is valued at preopening today, I guess I can say no good deed goes unpunished and also I guess I am glad that we didn't highlight say $60 billion of possible value creation this quarter, our stock might be down even more.

As for our production, we had an excellent quarter despite tough winter weather.

It is a testament to the quality of our operations teams and to the diversification of our asset base that our production exceeded expectations for the quarter.

Most importantly, our liquids production continued to grow rapidly and we remain on track to reach 150,000 net barrels per day by year-end 2012 and 250,000 barrels per day by year-end 2015.

During the 2011 first quarter, we averaged 67,000 barrels per day.

Quite an impressive jump from just 32,000 barrels per day two years ago in the 2009 first quarter.

Just to remind you, we believe there are 13 significant liquids-rich plays currently under development in the US and we have leading positions in 11 of them, a top five position in the 12th and have no presence in the 13th, which, for those of you who are curious, would be OXY's California play.

Here are the 12 that we are in -- the Granite Wash, Cleveland, Tonkawa and Mississippian plays in the Anadarko Basin of western Oklahoma and the Texas Panhandle, the Eagle Ford Shale of south Texas, the Niobrara Shale in the Powder River and DJ Basins, the Avalon, Bone Spring, Wolfcamp and Wolfberry plays of the Permian Basin, the Three Forks Bakken play of the Williston Basin and the Utica Shale in Ohio.

We believe it is simply unprecedented that we have assembled leading positions in 12 of the 13 most important liquids-rich plays in the US at very attractive per net acre leasehold cost.

This will lead to very substantial net asset value creation for Chesapeake shareholders for decades to come.

I next would like to highlight the very valuable and substantial vertically integrated service business that Chesapeake has built in the past two years.

Taking advantage of the equity value creation that our ongoing demand for oilfield services creates every day, we have decided that in certain service business lines that present significant potential growth chokepoints or offer unusually high profit margins, Chesapeake will seek to supply approximately two-thirds of our own demand for such services.

For example, today, we own the fifth largest drilling contractor in the US, the second-largest compressor rental company in the US, and the third largest oilfield trucking and tool and equipment rental business.

In addition, we are in the process of building our own hydraulic fracture stimulation company, which we expect will have 250,000 horsepower in the field in the next 18 months.

Ultimately, we may seek to build a fleet of around 750,000 horsepower to serve our current 1 million horsepower daily fracking needs, which surely will grow in the years to come.

In addition to avoiding potential growth chokepoints and capturing high profit margin business lines, these service company investments also provide a very significant inflation hedge and value-creation vehicle.

As case in point, please consider our five-year-old investment in Frac Tech, which soon will have a cost basis of only $100 million, but a value that we estimate could be $1.5 billion by year-end 2011.

Chesapeake's industry-leading drilling and completion activities require a high level of planning and project coordination that we believe is best accomplished through vertical integration and ownership of a significant portion of the oilfield services that we utilize.

This vertical integration approach also creates a multitude of cost savings and alignment of interest, operational synergies, greater capacity of equipment, increased safety and better coordinated logistics.

In addition, our control of a large portion of the oilfield service equipment we utilize provides unique advantages in accelerating the timing of leasehold development and therefore accelerates the creation of present value from our vast inventory of undeveloped properties.

Based on projected levels of unconsolidated EBITDA from our oilfield service assets of approximately $1 billion in 2011 and $1.4 billion in 2012, we believe the combined value of our oilfield service assets, including the $1.5 billion potential value of our 30% investment in Frac Tech, is worth more than $7 billion.

We are in the process of beginning to evaluate various alternatives to partially monetize our oilfield service assets and expect to achieve a very good result in 2012.

I will now turn the call over to Nick.

Thanks, Aubrey.

As you noted, the first quarter was truly remarkable for Chesapeake and we are extremely proud of our first-quarter results and our progress thus far in our 25/25 plan.

A few highlights I would like to point out on our operational and financial results for the quarter.

Net income came in at $518 million, or $0.75 per fully diluted share and operating cash flow was $1.4 billion on production of approximately 3.1 Bcfe per day.

Of course, on the last day of the quarter, we closed the sale of our Fayetteville Shale assets to BHP Billiton for about $4.65 billion in final proceeds, which represented just over 400 million cubic feet a day or approximately 13% of our average daily production in the quarter.

I would like to point out that given our fairly high exit rate for the quarter, we are approximately back to where we were on our exit rate for year-end 2010 with our current production levels.

That means that we effectively replaced the entire amount of Fayetteville production in our growth during the first quarter of this year.

To that end, we continue to invest aggressively in our existing portfolio of assets and spent $1.7 billion on drilling and completion costs for an F&D of $1.25 per Mcfe, having added approximately 1.3 Bcfe of reserves.

Given we estimate we will spend about half of our CapEx on liquids properties this year, I will also point out that 1 Bcfe is equivalent to 217 million barrels of oil equivalent.

On the cost side of the equation, we continue to have very favorable lifting costs and F&D costs in a very challenging services environment.

LOE was down $0.05 per Mcfe last quarter, but is guided to stay at approximately $0.90 per Mcfe going forward pro forma for the Fayetteville.

Many of you have already noted in your comments yesterday evening and this morning that drilling and completion CapEx guidance is up approximately 10% for 2011 and 2% to 3% for 2012 versus our last set of guidance.

This is driven by a combination of factors, but is primarily related to oilfield service cost inflation and slightly higher costs of finding oil.

The primary cost line that has increased is completion costs and we would like to note that due to the Frac Tech restructuring, we will have an economic gain on our investment there more than offsetting the increase in CapEx.

This is a direct reason we are very happy to have a $7 billion service organization at our disposal, providing both a financial and operational hedge on rising services costs and the availability of crucial equipment and services.

Shifting to the transaction front, we announced the results of a very successful tender of our senior notes and convertible bonds yesterday with the proceeds of our Fayetteville transaction.

When the tenders close, we will have purchased approximately $1.3 billion of straight senior notes and $700 million of convertible bonds for a total of $2 billion in debt retirement.

Importantly, underlying the converts that were retired were about 10 million shares of Chesapeake common stock.

Again, tying the operational success in here, we were able to sell 13% of our production, use the proceeds to permanently retire 17% of our outstanding debt and we will be able to continue growing our production sequentially or likely continue to grow our production sequentially and reach our 25% two-year production growth goal by the end of 2012.

As you all update your balance sheets and your models, I would like to point out that, at the end of the quarter, our carries from JV partners are approximately $3.5 billion due to us over the next two to three years.

This now includes the carry with our Niobrara JV with CNOOC and we expect we will grow this year with JVs in the Utica and Mississippian plays.

At $1.25 F&D costs, that equates to 2.76 Bcfe of proved reserves we will add to our balance sheet over this period solely with the funds collected from these carries that represent the full collection of our purchase price from these sales of working interests in our place.

On the hedging front, we remain nearly fully hedged for gas in 2011 and have hedged approximately 35% of our first half of 2012 gas production.

We did lift approximately $768 million of hedges during the quarter, primarily related to needing to adjust our hedge book for our Fayetteville sale.

The proceeds from these lifted hedges will show up through the remainder of this year and into next year in the quarters of the respective hedge as realized gain.

Lastly, we have completed and expect to shortly close our ninth VPP for approximately $845 million on 180 Bcfe of reserves, or $4.69 per Mcfe.

The reserves in the package are approximately 80% gas, 20% liquids and this brings our total VPP sales over the course of nine transactions to 1.2 Tcfe at a total sales value of $5.5 billion for an average per Mcfe sales price of approximately $4.60.

With that operator, we would like to open up the line for questions.

(Operator Instructions).

Dave Kistler, Simmons & Co.

Good morning, guys.

Real quickly, looking at the VPP, recently some other folks have entered into royalty trusts instead of VPPs and I was curious if maybe you could comment a little bit about how rating agencies treat it as debt even though it probably shouldn't be treated as debt and whether there is an advantage to maybe looking at a royalty trust and is that something you would consider going forward?

Dave, that is something that we have talked about and will consider.

We don't yet have a real clear picture about how the rating agencies will look at them.

I did spend some time with the rating agencies last week and reviewed our VPP position with them.

They don't all look at VPPs the same and so the hope that we have is that we can continue to make the case that these are, in fact, royalty interest sales similar to a royalty trust and we will see where this all plays out.

But the royalty trusts that have been done are very effective monetization tools and something that we would consider.

Okay, that's helpful.

I appreciate that.

And then, just focusing on your vertical integration strategy for a moment, can you talk a little bit about -- are there people constraints that you are encountering and as you pursue vertical integration, I would guess you are sourcing some of the people from existing service companies that might have more stability with a service company that is internal to an E&P company and just kind of wondering how that is affecting the landscape with service providers outside of those that you have vertically integrated?

Thanks, Dave.

Several good questions there.

In reverse order, even though we do provide a lot of our own services, if you strip away our internally provided services, I still think we are the largest US-based customer for service companies in general or in total.

So there is still plenty of Chesapeake business for outside service providers to compete for everyday and they do so.

With regard to the benefits of what we do, certainly enhanced coordination of operations is the easiest thing or the most important thing that we can talk about.

When you get people on location that all work for the same company, communication is easier, you share the same financial incentives and everything is better and we think safer as well.

With regard to the hiring of people, you hit on a very important note.

If a fellow works for a third-party drilling contractor, for example, he knows that he is likely to be laid off every two or three years, no fault of the company that he works for, it is just that is the rhythm of the business.

When a guy comes to work for us, he knows that we won't ever lay down our own rigs and so we know that just looking, for example, at the turnover inside of Bronco, which was basically an industry average company, was somewhere between 150% and 200% per year.

The turnover at our own drilling company is somewhere around 25% per year.

So dramatically different approach to the business and outcome where you're not in this constant cycle of hiring, training, firing, hiring training, firing.

We are able to keep guys and attract the very best.

So lots of reasons to do it and again, to hit on a point Nick made and as noticed from several people today that they were upset that we increased our CapEx guidance for the year by $500 million, but we didn't increase our activity, we've just kind of marked to market where we think frac costs are going to be, but we have an almost perfect offset to that through our investment in Frac Tech.

And I hope people will recognize that we have built not only a service company that will create efficiency and lower finding costs, but also act as a unique hedge against rising oilfield service costs.

Great, thank you for the clarification.

One last thing, more of a cleanup item, looking at the unproved properties acquisition, which I am assuming is incorporating leasehold or it has in the past, running about $880 million give or take, is that particularly front-end loaded?

In the past, you had talked about your acreage acquisition costs being about a third of what it was last year.

And if I ran that forward, it would be a little bit above that.

So just trying to tie that up.

Sure.

We would expect that to be an attention that some people would pay to during this release.

There is a lot of 2010 spillover.

We talked about that, that we had probably $700 million of deals that were signed in 2010 that would spill over into 2011.

The vast majority of that is going to be in the first quarter.

I would also direct you to the line under that, which is sale of leasehold during the quarter, which was $3.3 billion, which is a result of our Fayetteville sale, but also our Niobrara sale and so for the quarter, we are $2.5 billion ahead.

I have said on many occasions whether we spend $2 billion gross or $2.5 billion gross, it will remain my goal for the Company to end up the year with negative leasehold costs and we are obviously off to a good start there.

Great, thanks so much, guys.

Brian Singer, Goldman Sachs.

Thanks, good morning.

Can you talk about your liquids realizations and the drivers of the change in your guidance, widening out the differentials as a percent of WTI?

And beyond 2012, should we expect that that differential will narrow based on what you know about the mix within your liquids portfolio, particularly maybe some comment on the Utica and how that plays a role as well?

Sure.

Good question, Brian.

During the quarter, about 53% of our production was oil, 47% was NGLs.

Our long-term model is 60% oil, 40% NGL.

That is simply a function right now of the Granite Wash which is throwing off so much -- so many volumes of NGLs in our black oil plays, if you will, the Eagle Ford, the Niobrara and Cleveland, Tonkawa, and Mississippian, for example, plus our Permian plays are certainly just in the very beginning of their ramp-up.

So we expect that will trend up to around 60% oil.

NGLs are running today -- it depends on where you deliver them, either Belvieu or at Conway -- but they are running 47%, 48% of WTI.

So you are kind of $52 or $53 a barrel and so that is $9 or so per Mcf compared to $4 or so per Mcf on natural gas.

So natural gas liquids are highly valued, not as highly as oil and that is why we are focused more on finding oil.

We widened our guidance simply because we also took our long-term oil price up to $100 and when we did so, we basically didn't increase our realizations very much and just attributed the whole $10 increase to wider guidance.

There is a second thing at work, of course, which is you do have takeaway issues in many of these plays, which have led to greater basis differentials against WTI and of course, there is also the WTI versus Brent differential as well.

And there are lots of initiatives underway to correct the basis differentials in the various fields, but, of course, also several recently announced projects that we are engaged in also that will help fix the basis differential from WTI to Brent.

So lots of progress to report over the next couple of years and closing those basis differentials in the meantime.

We are on track to meet all of our liquids production goals and to reach that 60% oil percentage as well.

And what is your expected split in the Utica in terms of oil versus gas versus NGLs?

I don't have enough information to project that yet, Brian.

Sorry about that.

Okay.

Thanks.

And lastly, can you provide a little more color on your Williston position and activities there?

I may be recollecting incorrectly, but I believe you mentioned in the past that you were testing more new concepts as opposed to the Three Forks Bakken, but I think you mentioned the Three Forks Bakken here.

Can you just give us an update on what you're seeing there?

Yes, we actually haven't started to drill there yet, Brian, so I can't update you, but I can just confirm that we have around 200,000 acres in the play and think we will end up in the 250,000 to 300,000 range and probably we will look for a partner during the course of the year, but that is all that we have to mention about the Williston at this point.

Okay.

Are these new concepts or is this the same kind of Bakken Sanish Three Forks that others are pursuing?

Just need to limit it to a conversation about the Williston if I can at this point.

Thanks.

Thank you very much.

David Tameron, Wells Fargo.

Good morning.

A couple questions.

Eagle Ford, it looked like rigs increased production.

Am I reading into that or is that a function of bottlenecks in the play?

Can you talk a little bit about that?

I am not sure, David, what you are referring to.

I was just looking at the quarter-over-quarter production coming out of the Eagle Ford.

Or I guess bigger picture, getting away from that specific detail, can you talk about takeaway right now.

Oh, I'm sorry, Dave.

You were referring probably to the table on page 6.

We have lots of logistics issues in the Eagle Ford where we are limited by the amount of oil that we can produce.

And so we have a whole lot of wells shut in.

Maybe Steve has more.

Yes, I mean there are a lot of bottlenecks associated with trucking, but part of it also was completion prohibitions during the deer-hunting season over the winter, so we were able to get some wells drilled, but a lot didn't get completed until this spring.

So should have a very good quarter in the second quarter.

Okay, and any particular part as far as your entire acreage?

Any region that is more impacted than the others?

There are deer everywhere.

Well, in the oil hauling, the trucking choke kind of affects everyone.

We are putting in quite a bit of liquids pipeline so that will get fixed.

Okay.

And then in the press release, there was a comment in there about you could spend $100 billion over the next decade.

Can you give us some more color around that or just kind of what that message was that was coming from that statement?

Sure, it is just what's possible that we will be able to spend based on what our asset is and what our cash flow will grow to.

So it is a big company and it is going to become a bigger company as we create the value out of these huge liquids positions in 12 of these 13 leading plays.

And we are going to be a leading oil producer in the country in the next few years and that will continue, we think, for many more years after that.

But David that would be gross.

Okay.

All right, that's all I've got.

Thanks.

Neal Dingmann, SunTrust.

Good morning.

Just wanted your general thoughts on current M&A activity and prices in areas like the Permian, Eagle Ford, Powder River and DJ, including the Niobrara, kind of what you are seeing today versus the start of the year and is it kind of sort of playing out as you thought?

Neal, are you referring to -- I think you said M&A, is that right?

Yes, sir.

Just kind of what you are seeing --.

Well, honestly, we don't play in the M&A market and don't really even look in the M&A market.

We buy acreage wholesale and then try to sell it retail through JVs.

So if you are referring to acreage values, I think that you can look at the Anadarko transaction with KNOC in the Eagle Ford and see a $20,000 an acre print.

You can see some other deals.

You can look at SandRidge's royalty trust and back into an acreage value there that is probably about the same amount.

So we see continued strong interest and participations in what we think is the most profitable place in the world to look for and produce a barrel of oil and that is in the US.

And so we have these commanding leasehold positions that we think are going to continue to increase in value.

So if you are referring to corporate M&A or producing property M&A, not in a good position to comment because we simply don't look at that anymore.

Got it.

And then you had commented about the oil services, obviously you're down in position in a lot of those.

Do you continue to look for little privates, I mean whether it is on the fluid side or some other parts of the completion area, that you would think to sort of add to your stable?

We have bought three rig companies in the last six months or so, two private companies that were kind of special situations that brought us, I think, 13 rigs if I recall.

And then we are doing Bronco, and Bronco just happened to be an opportunity that we thought we should take advantage of.

Everything else we have done really through organic growth.

That is how we are building our own pressure pumping operation.

That is how we are building all of our other service lines.

So again, you know, on occasion on the service side I guess we might look at existing small private companies, primarily in the Oklahoma City area, but for the most part it will all be organic growth.

And are all the Bronco rigs, are those still operating?

Did you keep those basically in the same location and you are still operating those as they were kind of when you took that over?

Just to remind you, we don't own Bronco yet.

We are tendering for Bronco, and that tender date I believe is May 23.

So it is business as usual for Bronco, and afterwards then our goal is to use those rigs for our own benefit as their contracts roll off with existing E&P companies.

Very good.

Thank you.

Gary Stromberg, Barclays Capital.

Hi, good morning guys.

You had some comments in your annual report on the benefits of achieving an investment-grade rating and then, Aubrey, in your comments, you talk about having already achieved your 25% debt reduction goal and your plan is to maintain that level of debt reduction.

You have more monetizations obviously in the works here with the JVs and oil services potentially next year.

What do you do with those proceeds?

And I guess part two is, Nick, you mentioned you met with the rating agencies last week.

What did they say about what you need to do to get to investment grade?

I will take the first part and then go over to Nick.

I am going to remind you, Gary, that we do have other CapEx demands other than E&P.

We have midstream demands, we have service company demands and so our goal is to have our debt stay where it is or go down while, of course, our asset size will continue to increase over time.

And if we can pull off -- I don't know what we will get from an asset monetization on our service company.

We tend to be pretty conservative in what our expectations are, but like we did with the Fayetteville sale when we can hit a homerun then we will propose to use that excess to pay down debt.

So that remains our goal.

Of course, one of the problems in attacking our debt structure is the premium at which our debt trades today.

So we have to be mindful of shareholder value as well and so, in this case, we took about half of the Fayetteville proceeds and used them to repay long-term debt that trades in the open market and we took the rest to pay down our revolver.

So going forward, this Company is going to continue to increase its asset size while its debt level will remain where it is or go down and we will continue our steady march towards investment grade.

The more important thing to me than the rating is how the market sees where the Company is today and its credit statistics.

I don't think we will ever see eye to eye with the rating agencies on VPPs.

They are quite simply just wrong in their approach to that, but that doesn't mean that is they are anything other than tremendous economic and financial monetizations on our part.

The market though sees us as a strong crossover credit and I hope, in the next year or so, that debt will continue to trade into investment-grade territory and how long it takes the rating agencies to get there I can't predict, but I know that we will trade there before our rating gets there.

I will turn it over to Nick now.

Yes, so the second part of your question was really what the rating agencies have told us we need to do and of course, it is not quite that formulaic.

There are many iterations that they go through on their side and they have reacted well to our 25/25 plan progress thus far this year and we will continue to keep them apprised of what we plan to do in the future.

But there is no specific target we can give you guys.

I will just point out again that the 25/25 plan, like Aubrey said, attacks both sides of what we think is the key equation, which is debt to assets and it lowers the numerator and increases the denominator pretty aggressively.

So we are eager to continue to make progress there and have those show up in our results.

Okay, thank you.

John Abbott, Pritchard Capital Partners.

Aubrey, I had a question about the breakdown of the segment contribution from the oil services side.

Do you have kind of a rough breakdown between gathering, pressure pumping, transportation and drilling?

No, we don't break it down.

Just to remind you, gathering is not in there, so that is in our midstream business.

So at this point, we prefer to just think about it as one consolidated integrated business rather than break it out by business line.

And we currently account for our Frac Tech investment on the equity method and don't have any of our pressure pumping equipment in the field yet.

So primarily you are talking about rigs and traditional other service equipment.

Okay.

And the pressure pumping that you are constructing is the 100,000 horsepower this year and 200,000 next year.

Am I remembering that --?

100,000 this year and 150,000 next year for a total of 250,000.

Okay, got it.

And are you disclosing -- I think you had said in the past your acreage cost in the Utica was about $1100, $1200 an acre?

No, I think at the last conference I was with, I talked about around $1500 or so, so that is more or less in the ballpark.

Okay, got it.

And the Mississippian or the Bakken or the Williston, are you disclosing that?

Oh, I don't think that we have, but Mississippian would be well less than that and a lot of our acreage there is legacy leasehold that would have essentially today no cost basis.

So when we get a little further down the road, we will be happy to talk more about our cost basis there.

But the Utica acreage is by far more expensive than the Mississippian acreage.

Okay, got it.

Great.

Just one question, any update on Susquehanna County and is the EPA trying to get involved?

I will let Steve Dixon address that.

Well, we have provided all the data of the incident to the DEP and we expect to be able to get back to work fully hopefully later this week.

We provided both data on the chemicals used, the release and the failure itself that was in the wellhead where a leak developed on a connection at a flange.

And so we got basically all that data to them late Friday and expect to be able to move forward again later this week.

I might also add that the cessation of our completion operations was voluntary on our side.

We just needed to make sure we had double-checked all of our other wellheads, so we didn't have a repeat of this incident.

Thank you.

(Operator Instructions).

Rehan Rashid, FBR.

Good morning, Aubrey.

On your 39,000 wells to drill, $100 billion for CapEx to spend over time, from a people standpoint, what functionality is the most acute to address and just in general people adds over time that we need to address?

We don't really think about having people bottlenecks because we have been so successful at building our culture here and attracting particularly a young employee base.

We have about 11,000 employees today, about 4,000 of which are in Oklahoma City.

Half of those 4,000 are 33 years of age and younger.

So we are certainly building the next generation of leadership in our Company and the industry right here.

I think we are receiving around 500 resumes a day.

So we have no problem running out of potential people to hire.

So I don't really think about that as a chokepoint.

We have got the leasehold, we have got the partners, we have oil prices where we think they are going to be strong for years to come and we think gas prices that maybe have another year or so to struggle.

But after that, we will start to pick up as well.

So we think we are really well-positioned to meet a growing industry's needs and think the world needs more clean energy in the form of natural gas and certainly it needs more liquids energy in the form of oil.

One more quick one, for next year, the CapEx, does that include some more level of service costs and collection or how much of it?

Yes, we really had built into next year some things that we weren't sure were going to take place this year.

So I think we are in pretty good shape with where we are, but the prediction of CapEx is difficult because really two things have affected us lately.

One is the dramatic increase in completion costs, which, again, I think we fully offset by our hedge position in Frac Tech.

The second though is that we have such a huge leasehold inventory base that, as the industry ramps up its drilling, we spend a lot more money on non-op participations.

And so as you have seen the oil rig count really aggressively move up in the last 90 days, that has probably caught us even by surprise and another portion of that CapEx increase for the year is non-op and we really don't focus or spend a lot of time modeling production growth from those incremental non-op rigs, but they do have a CapEx increase.

So those are the two main drivers of this year's increase.

And next year, we will see, but we like where we are there.

Okay, thank you.

Scott Hanold, RBC Capital Markets.

Yes, hi, it's Scott Hanold at RBC.

And a quick question for you on CapEx in terms of spending for your oilfield services, some of the stuff you are building internally, what amount do you look at for 2011 and 2012 and I am assuming that is not included in your drilling and completion expenditures?

I'm sorry.

Did you ask what the amount is?

Yes, that's right.

Yes, we haven't disclosed that for various competitive reasons, we do tell you what our drilling CapEx is likely to be to the best of our abilities, but at this point haven't set forth the public specific CapEx budget for the service side nor have we done so on the midstream.

It is reported though in our Q if Nick's wants to talk more about that or just wait until the Q comes out and let it speak for itself.

Yes, relative to our drilling and completion CapEx, we spend a modest amount of capital on our services business every year and we will continue to do that.

We are growing it right now.

The way that I would think about it for you guys is we were at approximately 160 rigs at our peak back in 2008.

We are at approximately our peak level again now and we are growing and so our need to invest in the services business is front and center of our minds, again, as we get to a point where we are increasing our operated rig count.

So we will continue to invest there, but it is relatively modest compared to what our drilling and completion CapEx is.

Okay, can I ask, in terms of the pressure pumping you all are building, is a lot of that expenditure yet to be done or is there a certain amount that you obviously have to commit initially to get that process started?

Yes, there are progress payments made along the way and some has been made and some yet to come.

So it will be kind of a methodical quarter-by-quarter payment program there as we continue to add crews over time.

We talked about a 2011 and a 2012 delivery of horsepower, but, of course, they don't all show up on one day.

Okay, understood.

One last question.

In terms of your hedging and selling forward or I guess the written calls on the oil, it looks like you indicate that you have got 41% of your forecasted production that is covered by these, but if I am not mistaken, you had indicated that roughly 55% of that production though is oil.

So when you kind of look at the balance, where do you want to be in terms of how much of your oil do you want to commit to some of these hedges?

Well, if the price were right and we didn't want to keep some oil open for further increases, we could hedge 100%.

Natural gas liquids do trade pretty closely to oil if you look back where they were a year ago when oil was $30 a barrel less.

Conway was at 43% and Belvieu was at 53% and within 1 percentage point, that is where they both are today even though the price of oil has gone up by 40% in the past year.

So we think you can hedge NGLs pretty effectively through hedging oil.

But we are pretty optimistic about the price of oil going forward.

We sold some calls to enhance our ability today to brighten that oil future to buy leasehold that we wouldn't otherwise have been able to afford in some of these oily plays.

So right now, as I look at our overall hedge position versus our entire resource base, we have hedged about 1% of our entire resource base.

In the meantime, we have made $7 billion in cash hedging in the past 10 years so I hope we can make that much more in the next 10 years.

Just to clarify a little bit because maybe I wasn't clear there, how much of your oil volumes would you be willing to commit to that?

Like if I were to look at, your saying 41%, but you were to look at the actual oil volumes themselves, it is probably somewhere closer to 75%.

Would you be willing to go in excess of that because of those NGL volumes or would you kind of limit it to where the oil volumes would actually be?

Scott, I think I tried to just answer that by saying that we are certainly willing under certain circumstances to go to 100%, but on oil, it is highly unlikely that we would find ourselves incentivized to do so unless you had a really rapid spike in the oil prices from here.

We believe that world oil demand will continue to grow, world NGL demand will continue to grow and we are optimistic about oil prices.

And so we will periodically hedge, but, at this point, are not looking to take our oil hedges to 100%.

Got it.

Thank you.

Okay, thank you and thanks to everyone else and we look forward to further conversation with you and hope you have a good day.

Thank you.

That does conclude today's conference, ladies and gentlemen.

Again, we appreciate everyone's participation today.