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Chesapeake Energy (NYSE:CHK)

Q1 2011 Earnings Call

May 03, 2011 9:00 am ET

Executives

Steven Dixon - Chief Operating Officer, Executive Vice President of Operations & Geoscience and Member of Employee Compensation & Benefits Committee

Aubrey McClendon - Co-Founder, Chairman, Chief Executive Officer and Chairman of Employee Compensation & Benefits Committee

Jeffrey Mobley - Senior Vice President of Investor Relations & Research

Domenic Dell’Osso - Chief Financial Officer and Executive Vice President

Analysts

Scott Hanold - RBC Capital Markets, LLC

Brian Singer - Goldman Sachs Group Inc.

David Kistler - Simmons & Company International

David Tameron - Wells Fargo Securities, LLC

Neal Dingmann - SunTrust Robinson Humphrey, Inc.

Rehan Rashid - FBR Capital Markets & Co.

John Abbott

Gary Stromberg - Barclays Capital

Operator

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.

Jeffrey Mobley

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 . I will have prepared remarks by Aubrey and Nick, and then we'll go to Q&A. Aubrey?

Aubrey McClendon

Good morning. We hope you 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 a 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 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 pickup, 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'm 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 team and to the diversification of our asset base that our production exceeded expectations for the quarter. Most importantly, our liquids production continue 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 2 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 U.S., and we have leading positions in 11 of them, a top 5 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 and Tonkawa and Mississippian plays in the end of Anadarko Basin in western Oklahoma and in 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 in the Permian Basin, the Three Forks/Bakken play at 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 U.S. and very attractive per net acre lease hold 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 2 years. Taking advantage of the equity-value creation that are on-going demand for oilfield services creates everyday, 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 2/3 of our own demand for such services.

For example, today, we own the fifth largest drilling contractor in the U.S., the second largest compressor rental company in the U.S. and the third-largest oilfield trucking and 2 of the equipment rental business. In addition, we are in the process of building our own hydraulic fracture simulation company, which we expect we'll 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 frac-ing 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 5-year-old investment in Frac Tech, which soon will have a cost basis of only $100 million with 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, an alignment of interest, operational synergies, greater capacity of equipment, increased safety and better coordinated logistics. In addition, our controllable 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're 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'll now turn the call over to Nick.

Domenic Dell’Osso

Thanks, Aubrey. As you noted, the first quarter was truly remarkable for Chesapeake and we're extremely proud of our first quarter results, and our progress thus far in our 25/25 Plan. A few headlights I'd 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 is $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 sale 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'd like to point out that given our fairly high exit rate for the quarter, we are approximately back to where we were at 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'll 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. OE was down $0.05 per mcfe last quarter, but has 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 that is primarily related to oilfield service cost inflation, and slightly higher costs of finding oil.

The primary cost line that has increased this completion cost, and I 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 the direct reason we're 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 a 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, underlining the converts that were retired, we're about 10 million shares of Chesapeake's 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'll able to continue growing our production sequentially -- or likely continue to grow our production sequentially and reach our 25% 2-year production growth goal by the end of 2012.

As you all update your balance sheets and your models, I'd 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 2 to 3 years. This now includes the carry with our Niobrara JV with CNOOC, and we expect we'll grow this year with JVs in the Utica and Mississippian plays at a $1.25 F&D cost 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 full collection of our purchase price from these sales of working interest in our plays.

On the hedging front, we remained nearly fully hedged for gas in 2011, and have hedged approximately 35% of our first half 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 their 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 9 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'd like to open up the lines for questions.

Question-and-Answer Session

Operator

[Operator Instructions] And our first question comes from Dave Kistler of Simmons & Company.

David Kistler - Simmons & Company International

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

Domenic Dell’Osso

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 VPP's the same. And so I think that -- a 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'll 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.

David Kistler - Simmons & Company International

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're encountering? And as you pursue vertical integration, I would guess you're sourcing some of the people from existing service companies that might have more stability with a service company that's internal to an E&P company, and just kind of wondering how that's affecting the landscape with service providers outside of those that you've vertically integrated?

Aubrey McClendon

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, so in total. And so there's still plenty of business, 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's likely to be laid off every 2 or 3 years. No fault of the company that he works for, it's just that's the rhythm of the business. And 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're 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 from several people today, that they are upset that we increased our CapEx guidance for the year by $500 million. But we didn't increase our activity with this kind of mark-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 built not only a service company that will create efficiency and lower funding costs, but also acts as a unique hedge against the rising oilfield service costs.

David Kistler - Simmons & Company International

Great. Thanks for the clarification. And one last thing, more of a cleanup item. Looking at the unproved properties acquisition, which I'm assuming is incorporating lease hold or it has in the past, running about $880 million, give or take, is that particularly front-end loaded? In the past you talked about your acreage acquisition cost being about 1/3 of what it was last year. And if I ran that forward, it will be a little bit above that. So just trying to tie that up.

Aubrey McClendon

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 $600 million to $700 million of deals that were signed in 2010 that would spillover 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 the 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 cost, and we're obviously off to a good start there.

Operator

And our next question comes from Brian Singer of Goldman Sachs.

Brian Singer - Goldman Sachs Group Inc.

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?

Aubrey McClendon

Sure. Good question, Brian. During the quarter, about 53% of our production was NGL are long term -- I'm sorry 53% was oil rather than NGL, 47% was NGL. Our long-term model is 60% oil, 40% NGL. It's simply a function right now of the Granite Wash's throwing off so much, so many volumes of NGLs in our kind of 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 we'll trend up to around 60% oil. NGLs are running today, depends on where you deliver them, either Bellevue or at Conway, but they're running 47%, 48% of WTI, so you're kind of $52 or $53 a barrel. And so that's $9 or so per mcf compared to $4 or so per mcf on natural gas. So natural gas liquids are highly valued and not as high as oil, and that's 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 this attributed the whole $10 increase to a wider guidance. There's a second thing at work, of course, which is you do have take away issues in many of these plays, which have led to a greater basis differential against WTI, and of course there's also the WTI 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're engaged in also that will help fix the basis differential from WTI to Brant[ph]. 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.

Brian Singer - Goldman Sachs Group Inc.

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

Aubrey McClendon

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

Brian Singer - Goldman Sachs Group Inc.

Okay. 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've mentioned in the past that you're 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?

Aubrey McClendon

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 I think we'll end up in the 250,000 to 300,000 range. And probably we'll look for a partner during the course of the year, but that's all that we have mentioned about the Williston at this point.

Brian Singer - Goldman Sachs Group Inc.

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

Aubrey McClendon

We just need to limit it to conversation about the Williston if I can at this point.

Operator

Our next question comes from David Tameron of Wells Fargo.

David Tameron - Wells Fargo Securities, LLC

Couple of question. Eagle Ford, it looked like rigs increased production is that -- am I reading into that or is that a function of bottlenecks in the play or can you talk a little bit about that?

Aubrey McClendon

I'm not sure, David, what you're referring to.

David Tameron - Wells Fargo Securities, LLC

Just looking at the quarter-over-quarter production kind of the Eagle Ford. I guess, bigger picture, getting away from that specific detail, can you talk away take away right now?

Aubrey McClendon

Yes. Sure, David, you're referring probably to the table on Page 6.

David Tameron - Wells Fargo Securities, LLC

Yes.

Aubrey McClendon

We still have -- and I'll let Steve jump in here too. But 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 oil shut in, and maybe Steve has more.

Steven Dixon

Yes. And there is a lot of bottlenecks associated with trucking, part of it was also completion prohibitions during the dear hunting season over the winter. And so we were able to get some oils drilled but a lot didn't get completed until the spring. So we should have a very good quarter in the second quarter.

David Tameron - Wells Fargo Securities, LLC

Okay. In any particular part as far as your entire acreage? Any region that's more impacted than the others?

Aubrey McClendon

They're everywhere.

Steven Dixon

Well, in the oil hauling, the trucking choke, it kind of affects everyone. We are putting in quite a bit of the liquids pipelines so that will get fixed.

David Tameron - Wells Fargo Securities, LLC

Okay. And then Aubrey, in the press release, there was a comment there about you could spend $100 billion over the next decade. Can you talk -- can you give us some more color around that or just kind of what that message was coming from that state?

Aubrey McClendon

Sure. It's just growth, it's just what we're possible that we'll be able to spend based on what our asset is and what our cash flow will grow to. So it's a big company, and it's 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're 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.

Domenic Dell’Osso

But David, that would be gross.

Operator

And our next question comes from Neal Dingmann of SunTrust.

Neal Dingmann - SunTrust Robinson Humphrey, Inc.

Say, Aubrey, just wanting your general thoughts on current M&A activities and prices in areas like the Permian, Eagle Ford, Powder River and DJ, including the Niobrara, kind of what you're seeing today versus the start of the year and is it kind of sort of playing out as you thought?

Aubrey McClendon

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

Neal Dingmann - SunTrust Robinson Humphrey, Inc.

Yes, sir. I'm just kind of want to...

Aubrey McClendon

Honestly, we don't play in the M&A market and don't really even look in the M&A market. We, by acreage, post sale and then try to sell it at retail through JVs. So if you're referring to acreage values, I think that you can look at the Anadarko transaction with KNOC in the Eagle Ford and you'll see a $20,000 acre print. You can see some other deals. You can look at SandRidge's royalty trust and back into an acreage value there, that's probably the same amount. So we see continued strong interest in participations and what we think is the most profitable place in the world to look for and produce a barrel of oil. And that's in the U.S. and so we had these commanding leasehold position that we think are going to continue to increase in value. So if you're 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.

Neal Dingmann - SunTrust Robinson Humphrey, Inc.

Got it. And then your comment about the oil services, obviously, your down in position in a lot of those. Do you continue to look for a little privates, I mean, whether it's on the fluid side or some other parts of the completion area that you would think that sort of add to your stable?

Aubrey McClendon

Well, we bought 3 rig companies in the last 6 months or so, 2 private companies that were kind of special situations that brought us, I think, 13 rigs, if I recall. And then we're doing Bronco. And Bronco just happened to be an opportunity that we thought we should take advantage of. Everything else we've done really through organic growth, that's how we're building our own pressure pumping operation. That's how we're building all of our other service lines. So again, 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.

Neal Dingmann - SunTrust Robinson Humphrey, Inc.

And are all the Bronco rigs, are those still operating? Did you keep those basically in the same location and you're still operating those as they were kind of when you took that over?

Aubrey McClendon

Just to reminder you, we haven't -- we don't own Bronco. Yes, we are tendering for Bronco and that date, 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 the existing E&P companies.

Operator

Our next question comes from Gary Stromberg of Barclays Capital.

Gary Stromberg - Barclays Capital

You have some comments in your other report on the benefits of achieving an investment grade rating? And then Aubrey in your comments you talked 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 service potentially next year. What do you do with those proceeds? And I guess part 2 is, Nick, you mentioned you may met with the rating agencies last week. What did they say about that have to do to get to investment grade?

Aubrey McClendon

I'll take the first part and go over to Nick. I want to remind you, Gary, that we do have other CapEx demand other than E&P. We have midstream demand, we have service company demands, and so our goal is to have our debt stay where it is our go down, while of course our asset size will continue to grow up to increase over time. And we can pull off, I don't know what we'll get from an asset monetization on our service company, we tend to be pretty conservative than what our expectations are. But like we did with the Fayetteville sale, when we can hit a home run and we'll 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 use them to repay long-term debt that trades in the open market. 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 where the market -- how the market sees where the company is today and its credit statistics. I don't think we'll ever see eye-to-eye with the rating agencies on VPPs, they're quite simply just wrong in their approach to that. But that doesn't mean that, that is they are -- anything other than tremendous economic and financial monetizations on our part. So the market though sees us as a strong crossover credit. And I hope in the next year or so that, that will continue to trade in the investment-grade territory. And how long it takes the rating agencies to get there, I can't predict. But I know it will trade there before our rating gets there. I'll turn it over to Nick now.

Domenic Dell’Osso

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's not quite that formulaic. There's many reiterations that they go through on their side, and they have reacted well to our 25/25 Plan progress thus far this year, and we'll continue to keep them apprised of what we plan to do in the future, but there's no specific target we can give you guys. I'll just point out again 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're eager to continue to make progress there and have those show up on our results.

Operator

We'll go next to John Abbott of Pritchard Capital Partners.

John Abbott

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? I guess, just...

Aubrey McClendon

No. We don't break it down. Just to remind you, gathering is not in there. So that's 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.

Domenic Dell’Osso

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're talking about rigs and traditional other service equipment.

John Abbott

Okay. And the pressure pumping that you're constructing is the 100,000 horsepower this year and 200,000 next year, I'm not remembering that.

Aubrey McClendon

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

John Abbott

Okay. Got it. And just, can you -- are you disclosing -- I think you have said in the past your acreage cost in the Utica was about $1,100, $1,200 in acre. Is that...

Aubrey McClendon

No. I think the last conference I was with, I talked to about around $1,500 or so. So that's more or less in the ballpark.

John Abbott

Okay. Got it. And the Mississippian or the Bakken or the Williston are you disclosing that or?

Aubrey McClendon

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 have essentially today no cost basis. So when you get a little further down the road, we'll be happy to talk more about our cost basis there. But the Utica acreage is by far more expensive than the Mississippian acreage.

John Abbott

Okay. Got it. Great. And just one question, any update on Susquehanna County and the EPA trying to get involved. When do you expect to be...

Aubrey McClendon

Sure. I'll let Steve Dixon address that.

Steven Dixon

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 chemicals used, the release and the failure itself that was in the wellhead where a leak developed on the 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.

Aubrey McClendon

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 the other wellheads, but didn't have a repeat of this incident.

Operator

[Operator Instructions] And we'll go next to Rehan Rashid of FDR.

Rehan Rashid - FBR Capital Markets & Co.

On your 39,000 well to drill, $100 billion of 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?

Aubrey McClendon

We don't really think about having people bottlenecks because we have been so successful at building our culture here and attracting a particularly 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're receiving about 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've got the leasehold, we've got the partners, we have oil prices where we think they're 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'll start to pick up as well. So we think we're really well-positioned to meet a growing industry's needs. And we think the world needs more clean energy in the form of natural gas and it certainly needs more liquids energy in the form of oil.

Rehan Rashid - FBR Capital Markets & Co.

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

Aubrey McClendon

Yes. We really had built into next year some things that we weren't sure we're going to take place this year. So I think we're in pretty good shape with where we are. But the prediction of CapEx is difficult because it's, really, two things have affected us lately. One is the dramatic increase in completion cost, which again I think we fully offset by our hedged position in Frac Tech. The second though is that we have such a huge leasehold inventory base that as the industry ramps up it's drilling, we spend a lot more money on non-op participations. And so you've 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'll see, but we think we like where we are there.

Operator

And we'll go next to Scott Hanold of RBC Capital Markets

Scott Hanold - RBC Capital Markets, LLC

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're building internally. What amount do you look at for 2011 and 2012, and I'm assuming that's not included in your drilling and completion expenditures?

Aubrey McClendon

I'm sorry, what -- did you ask what the amount is, Scott?

Scott Hanold - RBC Capital Markets, LLC

Yes, that's right.

Aubrey McClendon

We haven't -- yes, we haven't disclosed that because we're -- 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, we haven't set forth the public specific CapEx budget for service side nor have we done so on midstream. It is reported though in our, I guess, in our Qs. If we want to -- Nick if you want to talk more about that or just wait until the Q comes out and let it speak for itself.

Domenic Dell’Osso

Yes, we spent relative charge, really, in completion of CapEx. We spend a modest amount of capital on our services business every year, and we'll continue to do that. We are growing it right now the way that I would think about it for you guys as we were at approximately 160 rigs at our peak back in 2008. We're at approximately at our peak level again now and we're growing, and so our need to invest in the services businesses is front and center of our minds, again, as we get to the point where we're increasing our operated rig counts. We'll continue to invest there but it's relatively modest compared to what our joint completion CapEx is.

Scott Hanold - RBC Capital Markets, LLC

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

Domenic Dell’Osso

Yes. There are progress payments made along the way and there's -- some has been made and some is 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.

Scott Hanold - RBC Capital Markets, LLC

Okay. Understood. One last question. In terms of your hedging and sort of using these -- selling forward or I guess the written calls on the oil. It looks like you indicate that you've got 41% of your forecasted production that's covered by these. But if I'm not mistaken, you had indicated that roughly 55% of that production though is NGLs -- or I'm sorry is oil. So when you kind of look at that 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?

Aubrey McClendon

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. And Conway was at 43% and Bellevue was at 53%. And within 1 percentage point, that's where they're 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, and 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. And so right now, as I look at our overall hedge position versus our entire resource base, we've hedged at about 1% of our entire resource base. In the meantime, we've made $7 billion in cash hedging in the past 10 years. So hopefully, we can make that much more in the next 10 years.

Scott Hanold - RBC Capital Markets, LLC

And 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 look at -- right now you're seeing about 41%, but if you're just to look at the actual oil volumes itself, it's 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?

Aubrey McClendon

Scott, I think I tried to just answer that by saying that we're certainly willing under certain circumstances go to a 100%. But on oil, it's highly unlikely that we would find ourselves incentivize to do so, unless you had a really rapid spike in oil prices from here. We believe that world oil demand will continue to grow. World NGL demand will continue to grow. And we're optimistic about oil prices, and so we'll periodically hedge. But at this point, we're not looking to take oil hedges to 100%.

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.

Operator

And that does conclude today's conference, ladies and gentlemen. Again, we appreciate everyone's participation today.

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