Seeking Alpha
We cover over 5K calls/quarter
Profile| Send Message|
( followers)  

Chesapeake Energy (NYSE:CHK)

Q3 2011 Earnings Call

November 04, 2011 9:00 am ET

Executives

Jeffrey L. Mobley - Senior Vice President of Investor Relations & Research

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

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

Analysts

Brian Singer - Goldman Sachs Group Inc., Research Division

Jeffrey W. Robertson - Barclays Capital, Research Division

Bob Brackett - Sanford C. Bernstein & Co., LLC., Research Division

Biju Z. Perincheril - Jefferies & Company, Inc., Research Division

Neal Dingmann - SunTrust Robinson Humphrey, Inc., Research Division

Joseph D. Allman - JP Morgan Chase & Co, Research Division

Scott Hanold - RBC Capital Markets, LLC, Research Division

Timothy Rezvan - Sterne Agee & Leach Inc., Research Division

David W. Kistler - Simmons & Company International, Research Division

Jason Gilbert - Goldman Sachs Group Inc., Research Division

David R. Tameron - Wells Fargo Securities, LLC, Research Division

David Heikkinen - Tudor, Pickering, Holt & Co. Securities, Inc., Research Division

Operator

Good day, and welcome to the Chesapeake Energy 2011 Third Quarter Earnings Results Conference Call. As a reminder, today's conference is being recorded. At this time, I'd like to turn the conference over to Mr. Jeff Mobley. Please go ahead, sir.

Jeffrey L. Mobley

Good morning, and thank you for joining our conference call this morning. We understand there are a few other companies overlapping with us, and so we'll be short and to the point. Aubrey, Nick and myself are in Boston for an offering that is underway. Steven Dixon and John Kilgallon are in Oklahoma City.

I'll turn the call over to Aubrey.

Aubrey K. McClendon

Thanks, Jeff. And I'll begin by clarifying that the offering is for Chesapeake royalty trust units, not anything else.

All right. Good morning. We hope you had time to review yesterday's 2011 third quarter operational and financial release, as well as our Utica transactions release.

Before I begin, I would like to respectfully request that you access our website at chk.com and pull up our slide show labeled November Presentation. It's under the Investors button, and then you can go to Presentations to find it.

Later in my remarks, I'll ask you to look at some slides that I hope you will find useful. Thanks very much for doing this.

As promised, our oil and natural gas liquids production continues on its strong and steady ascent, while we are delivering yet again another impressive JV transaction.

If you are keeping track, this new JV would make our seventh. We started with the Haynesville in July of 2008, and in the 3 years since then, we have also brought in partners on the Fayetteville, Marcellus, Barnett, Eagle Ford, Niobrara and now into 1 phase of the Utica play.

In these 7 JV areas, the company initially acquired approximately 5.1 million net leasehold acres at a cost of $11.1 billion. That's around $2,200 per net acre overall on average.

We then sold 1.5 million of those acres for total consideration of $16.4 billion in cash and carries, meaning we recovered 150% of our total leasehold costs in all the plays combined, while leaving ourselves with 3.6 million net acres in 7 of the nation's very best plays, at a negative leasehold cost of $5.3 billion. That's about a negative $1,500 per net acre. I really don't think the magnitude or significance of what we have accomplished by owning 3.6 million net acres at a profit of $1,500 per net acre has been fully appreciated. It is quite simply unprecedented in our industry.

Said another way, the remaining value or stub value, if you will, of what we have kept in these JVs has an implied value of approximately $40 billion or about $53 per share. Mind you, this is not me saying this. This is what some of the world's largest and most successful energy companies have said these assets are worth.

We are proud of creating and delivering this remarkable treasure trove of net asset value to our shareholders in just the past 3 years.

I would also remind you that we might still have 3 JV deals left to work on in 2012. We have about 400,000 net acres in the Williston Basin, around 1.4 million net acres in the Mississippi Lime play and on our way to 500,000 net acres in another oil play that we aren't ready to discuss yet until we've drilled a few wells in it.

Next, I'd like to focus my comments on our 2 Utica transactions. As we disclosed to you in July, we believed we would complete a Utica JV by year-end 2011, and that we might also bring in a financial partner in addition to or maybe instead of an industry JV partner. We are happy to report that we have done both. Our international partner is very large, very well-respected, very well-known, and we will be delighted to reveal the company's name to you once we complete the transaction. I'd like to emphasize that the deal is very attractive to them and very attractive to us. It's a complete win-win for both companies.

We recover our leasehold costs in the play to date and keep 90% of our Utica acreage, and they now own the second best position in what we believe will be proven up in time as the nation's most profitable play. We continue to be very pleased with our Utica well results to date, but are not releasing any additional well results this quarter because the last time we did it, leasehold prices doubled in the field within weeks.

We are still acquiring almost 1,000 net acres per work day, so we have no desire to put further pressure on leasehold prices. We should have the vast majority of our leasing wrapped up by year end, and at that time, we can become chattier about well results. However, I would note that Rex reported a pretty snappy 9.2 million per day Utica test in Western Pennsylvania last week. So well results in the play should begin accelerating in the months ahead.

We also continued to successfully drill new wells in the Utica, and that the play's become, by far, the more frenzied new leasehold play in the industry since the Haynesville in 2008. And as I've stated publicly in the past few months, the Utica is the biggest thing to hit Ohio since the plow. And back in the day, that was a very big deal, indeed.

I can also tell you that so far in the Utica, we have spudded 19 horizontal wells, and 7 of those are now producing. The rest are drilling, completing or waiting on completion, production or pipelines.

One last thing on the industry JV. It valued our 570,000 net acres in the JV at $8.5 billion, which bodes well for my prediction 3 months ago that we would ultimately see our investment in the Utica valued at $15 billion to $20 billion.

In addition, we are very pleased to report our Utica financial transaction, led by EIG. This is a $500 million preferred equity transaction and a subsidiary that holds about 45% of our Utica leasehold. By the end of the month, we expect this will have grown to become a $1.25 billion transaction.

Next, I would like to offer some insights into our current and future natural gas and liquids production. And for this part of the presentation, I would ask if you would be kind enough to follow along on our slideshow presentation that I asked you to pull up at the beginning of the call.

Specifically, please turn to Slide 17, where we show that during the past 11 years, as Chesapeake has increased its gross operated natural gas production from 1.1 Bcf per day to 5.4 Bcf per day, and in so doing, Chesapeake single-handedly has generated almost half of the entire industry's growth in natural gas production.

Said another way, a 2% gas market share company in 2000, which was us, grew its production 472% over the past decade, while the other 98% of the industry, 49x bigger than us and represented by more than 10,000 other companies, only grew its collective production 12% during the past decade.

As incredible as that is, it's even more incredible how most natural gas market observers fail to understand the impact of these numbers on future supply-demand trends, because for the next 5 years, Chesapeake is planning to keep its gas production essentially flat.

Please see Slide 18, which shows our projected annual 10% production increases coming almost entirely from liquids production growth from 2012 through 2015. Said in the simplest way that I can, natural gas markets during the past 5 years were basically changed single-handedly by the efforts of 1 company. And now I'm telling you, during the next 5 years, it will be very different from now. And the futures curve is currently pricing natural gas, we believe, incorrectly because the same company that helped bring you the gas oversupply is now dedicated to increasing its liquids production, and its gas production will not increase much from here.

Now for all you gas consumers out there, don't worry. If gas demand picks up, as we believe it will, from coal switching, industrial demand growth and transportation fuel switching, and if LNG exports begin in 2015, as we believe they will, then Chesapeake will return to growing its gas production to make sure that U.S. gas markets remain well supplied.

Now back to liquids production for a moment. I read the most remarkable statement 2 days ago by another company during a conference call on which they proclaimed they had found 900 million barrels net to them in the Eagle Ford. So far, so good. I have no doubt about the accuracy of that claim. But incredibly, they went on to claim that their 900-million-barrel discovery was the largest oil discovery by any company in the U.S. during the past 40 years. Normally, I don't pay much attention to competitors' claims, but this claim was just too inaccurate to let it pass uncorrected.

In fact, the hard working and innovative employees of Chesapeake have found not 1, not 2, not 3, but actually 4 liquids plays that are bigger than the 900 million barrels claimed to be the industry's biggest discovery by any 1 company in the past 40 years.

So what are those 4 plays for Chesapeake? They would be the Eagle Ford, where we own 460,000 net acres; the Mississippi Lime play in Northern Oklahoma and Southern Kansas, where we own 1.4 million net acres; the Cleveland Tonkawa play in the Anadarko Basin, where we own 750,000 net acres; and now the Utica, where we own 1.35 million net acres after our JV sale.

Collectively, we believe the potential of these plays, net to Chesapeake shareholders, are over 4.3 billion barrels of oil equivalent. And by the way, our net leasehold cost in those plays is now only $100 per net acre.

As you consider your investment options, I hope you will keep the magnitude of these discoveries in mind and how we have derisked them and reduced our leasehold costs to the lowest in the industry.

We thank you for allowing us to correct the record on this important point.

Even though, our gas production will stay largely flat during the next 4 years, that doesn't mean the entire company's overall production will remain flat. In fact, our overall production should increase by approximately 50% between 2011 and 2015, with the vast majority of this increase coming from our rapidly increasing liquids production.

Said another way, from year-end 2009 through year-end 2015, we believe our liquids production should increase by approximately 225,000 barrels of liquids per day.

We have examined other companies' forecasts, as well as industry analytical work, and believe this will be the greatest increase in liquids production, measured in barrels of liquids per day, by any company in the U.S. And it will likely be among the very best in the world as well.

Please turn to Slides 19 and 20 to see how we are doing so far. On a percentage increase basis since the beginning of 2010, we are second only to SandRidge, who generated much of their increase from acquisitions. But please be clear, we love the Mississippi Lime as much as they do.

On an absolute liquids production increase basis, we are second only to EOG, but not by much. And over the next few years, we think we might be able to pass that very fine company by, but we shall see.

And by the way, I hope you saw on Page 21 of our earnings press release and on Slide 27 of our November presentation that we have now rolled out our 2013 production and financial forecasts. In doing so, we have established that in 2013, we plan to average 200,000 barrels of liquids production per day. I'd like to point out that, that used to be our 2013 exit rate goal, not our full-year average. That's a big change, and I hope you appreciate its significance.

And for 2015, we have shifted from our year-end exit rate of 250,000 barrels of liquids to an average for the entire year of 250,000 barrels. Again, that's another big shift forward. And, of course, all of this growth will be organically delivered from the drill bit, just as all of our growth has been for the past 3 years.

This dramatic increase in liquids production in 2012, 2013 and on through 2015 will have tremendously positive financial results for our company, as revenue, profits and returns will increase dramatically on a per-unit-of-production basis.

To remind you, we are also still forecasting that in 2015, we will double our EBITDA from 2011, while increasing our overall production by about 50%. We'll be able to achieve that impressive feat by continuing our best-in-class production growth, with a steadily increasing value per unit of production as we -- as our production mix shifts more and more to liquids that are more highly valued than natural gas. And we will do this, of course, while delivering a balance sheet with investment grade metrics.

As I turn the call over to Nick, I also ask that you take a quick look at Slides 27 and 30 to make sure you are aware of the value of our non-exploration & production assets. It's about $17 billion these days or about $23 per share. These are real values for real assets, and I hope you appreciate how much value we have created for our shareholders in our ancillary businesses that in our competitors' business are transferred away to third parties.

I'll turn it over to Nick now.

Domenic J. Dell’Osso

Thanks, Aubrey. It was another good quarter for Chesapeake, indeed. Our production cash flow and proved reserve growth all highlighted the tremendous growth inherent in Chesapeake.

Starting with proved reserves, we added 1.2 Tcf equivalent of reserves for the quarter, which is the second quarter in a row we've added approximately 1 Tcf equivalent of reserves. This, again, appoints to the unique, powerful and valuable asset creation machine we've created at Chesapeake. Additionally, when we look at our reserve adds year-to-date, we've added 4.2 Tcfe before asset sales and 1.4 Tcfe net of asset sales, including the Fayetteville. This equates to 700 million barrels of oil equivalent and 240 million barrels of oil equivalent, respectively. Which oil equivalency, we think, would be the more relevant metric in our recent past, given our adds are so heavily weighted to oil and liquids. This, again, is just the value we've created through proved reserve growth and doesn't include our Services business, our investments and our Midstream assets.

On a related note, we ended the quarter at $11.8 billion in debt for a debt to proved reserve ratio of $0.67 per Mcfe. That represents a 10% decrease in this key ratio since December 31, 2010, and great evidence of the success of our 30/25 plan, which, of course, we're looking forward to delivering to investors by December of 2012.

Further, I'd like to point out that on a pro forma basis for our transactions announced yesterday, plus the expected proceeds from our royalty trust offering, which, all combined, we estimate will total over $2.3 billion in cash into the company in the coming weeks, our debt to proved reserve ratio would be $0.54 per Mcfe.

Next, I'd like to focus a bit on our vertical integration strategy and point you to the new section of our outlook, where we've provided guidance for both Chesapeake Midstream Development, which is our wholly-owned Midstream company, and Chesapeake Oilfield Services, which is our wholly-owned oilfield services company known to us as COS. We've just finished a very successful bond market offering for COS, where we sold $650 million of notes to investors at a 6 5/8 coupon, and also closed on a $500 million revolving credit facility.

Our goal is to monetize a portion of the equity in COS in 2012, which when you look at our forward EBITDA guidance for the business in 2013, you can easily see should be worth $6 billion to $7 billion in enterprise value. And that does not include our 30% stake in Frac Tech.

There's a very large growth ramp in COS' projections that's important to that business, as well as the parent companies, in pressure pumping operations. Our new pressure pumping subsidiary, Performance Technologies, frac-ed our first well on Monday of this week with great success. And we will enjoy significant cash flow savings for Chesapeake and cash flow growth for COS through this business.

To give you some perspective on what this investment in frac equipment can mean for us, approximately 40% of the total cost to drill and complete a well in today's unconventional development programs can come from pressure pumping.

We're extremely proud of the management team we have attracted to Chesapeake and the suite of operations and assets they provide every day as one of the top 5 onshore U.S. local services providers in the industry, with what we believe is one of the best risk-adjusted business models and growth trajectories in the oilfield services industry.

Lastly, I'd like to focus a bit on our hedge profile. As I'm sure you've all noticed, we are relatively unhedged at the current moment. We saw an opportunity to lock in our hedge gains during the quarter and have locked in a gain of $1.48 per Mcf in Q4 of 2011 and $0.39 per Mcf in 2012, at what we think are very attractive long-term prices. We believe the natural gas pricing environment in Q3 represented a floor and are now exposed to being able to hedge again at higher prices in the future. As Aubrey noted, there are multiple factors on both the supply and demand side of the natural gas equation that can very positively impact the natural gas price in 2012, and we're well-positioned to take advantage of those dynamics.

With that, operator, we'll open the line up for questions.

Question-and-Answer Session

Operator

[Operator Instructions] We'll take our first question from David Heikkinen with Tudor, Pickering.

David Heikkinen - Tudor, Pickering, Holt & Co. Securities, Inc., Research Division

First question on the Utica plans going to 30 rigs. Can you walk us through the rig split inside the joint venture and outside the joint venture?

Aubrey K. McClendon

David, we haven't done that, but basically, we plan for about roughly 75% to 80% of our drilling to be inside of the joint venture area. I can't be more specific than that because some of it is going to depend on the success we have in the oil phase of the reservoir, as well as what gas prices do and what incentives we have to develop the dry gas side of it. So the vast majority, though, will be in the middle of the play, the wet gas phase.

David Heikkinen - Tudor, Pickering, Holt & Co. Securities, Inc., Research Division

Okay. And then what role do you expect your joint venture partner to play in the Midstream and marketing side on NGLs or...

Aubrey K. McClendon

They'll have the right to participate alongside us on a pro rata basis for any investments that we make in the Midstream area.

David Heikkinen - Tudor, Pickering, Holt & Co. Securities, Inc., Research Division

Okay. And thinking about additional joint ventures and plans from here forward, can you just update us on kind of overall number of joint ventures and areas you're working and your thoughts there?

Aubrey K. McClendon

Sure. Well, we've done 7 to date, and I mentioned that we had 3 more areas where we had significant-enough leasehold positions, and I guess significant-enough leasehold positions in areas where we haven't already accelerated our drilling and would like to have a partner. And I believe I identified those as the -- potentially the Mississippi Lime, the Williston Basin, and then also we have a third play where we're accumulating acreage. It's on the oil side. In places like the Permian and the Anadarko Basin for the Cleveland Tonkawa and Granite Wash plays, we really have already ramped our drilling up. We don't have a big leasehold cost position that needs to be de-risked. So those are areas where we wouldn't pursue a JV partner.

David Heikkinen - Tudor, Pickering, Holt & Co. Securities, Inc., Research Division

And maybe specifically on the oily part of the Utica and what you did in joint venture, would you expect to potentially move something forward there?

Aubrey K. McClendon

A good question, David. Sorry. I think on the dry gas phase, we want to get a number that's great for our shareholders. And in this gas price environment, that would be tough to do. So we'll wait until we get a rebound in gas prices. And as both Nick and I alluded to, we think that will start to begin to be visible in the next year or so. And so we can wait. A lot of our acreages are already HBP in the Utica. And then on the oil phase, we just need to focus our attention there. And when we feel like we've got a body of work that justifies going forward with a JV there, we will likely pursue something like that.

David Heikkinen - Tudor, Pickering, Holt & Co. Securities, Inc., Research Division

Okay. And then just a question on Chesapeake Oilfield Services. As we started looking at margins relative to kind of oilfield services peers, they looked a little bit lower. Can you walk us through kind of how you set pricing? Is it lower because it's operated? I mean, just relative. And then an outlook as far as how pricing gets set if that business moves forward.

Aubrey K. McClendon

Sure, I'll let Nick address that for you.

Domenic J. Dell’Osso

Sure. We set pricing based on what we pay others in each basin, and so it's a model that matches what we view as a market price. And we, of course, have great clarity into what we pay others because we plan to and typically don't use any more than 2/3 of our own services in any 1 basin. So we are a significant customer of many other services companies everywhere that we operate. As far as our margins being a bit weaker than others, it probably depends on who you're looking at, David. But we think that with the advent of PTL coming into our business in 2012, you will see the margins within COS increase pretty dramatically. We also have a new management team who's focused solely on this business and improving the overall margin and return to investors here. So I'd say you'll see that come up over time.

Aubrey K. McClendon

And remember, David, to date, a lot of our COS revenue comes from drilling and from trucking areas, which don't traditionally have the highest margins in the service industry.

Operator

We'll take our next question from Dave Kistler with Simmons & Company.

David W. Kistler - Simmons & Company International, Research Division

Real quickly on Chesapeake Utica, L.L.C. Can those shares convert into Chesapeake shares at any time? And noticed that your diluted share count has gone down, so I'm guessing the answer is no.

Aubrey K. McClendon

That's correct. They are not convertible into big Chesapeake shares, and in fact, they're not even convertible into common of the sub. That's an important distinction between the EIG deal that we've done with PXP, where those preferred shares are convertible into common stock of the sub that owns those Gulf of Mexico assets. So basically, they have the right to convert into basic ownership of the asset. Here, there is no upside participation other than the small override that we granted. So it's a really important distinction. And I did see in at least 1 research note some analyst who was saying that we had issued 1.25 billion of preferred shares from Chesapeake. That is absolutely not true. We are selling from a subsidiary that -- and those shares have no ability to convert into common of the company or into the sub itself.

David W. Kistler - Simmons & Company International, Research Division

I appreciate that clarification. So then as we think about this going forward, is it ultimately an obligation that you retire in cash? And we just think of it as kind of a 7% interest-bearing security that, for all intents and purposes, the only other additional stream for it is the 0.5% interest in your ultimate drilling plans or ultimate working interest in the Utica?

Domenic J. Dell’Osso

The latter part of what you said, Dave, is spot on. It is perpetual preferred, which comes with a 7% dividend rate. And it does have the -- like you said, the royalty, very small royalty associated with it. Should we pay out cash flow from this entity, it will go towards retiring this security, but it is callable solely at our option when and how we choose to do so. The preferred can stay outstanding forever and earn a 7% coupon forever, should we not choose to call it.

David W. Kistler - Simmons & Company International, Research Division

So then just looking at it...

Domenic J. Dell’Osso

So we stay in line with the terms of the preferred.

David W. Kistler - Simmons & Company International, Research Division

So then just looking at it from a cost-of-funding standpoint, at 7% capital, with giving up a very, very small portion of your ultimate cash flow out of the assets, is this a structure that you'd consider using for all of the other areas that you're walking through developments of?

Domenic J. Dell’Osso

I think it's possible, Dave. What we liked about this transaction was, there have been a couple of other financial sponsors who have done aggressive deals around unconventional, early stage assets in the industry over the past 18 months to 24 months. And so we saw, as we began talking about our Utica play, that a number of sponsors came to us with some pretty creative ideas. They see that there's a pretty good amount of value that the strategic JV partners have been capturing, and they have an appetite to try and compete for those projects. And so we thought that this really did a nice job of solving what we like to solve for, which is getting a return of our investment in the leasehold, bringing to bear some capital to accelerate the development of the play, but very importantly here, preserving nearly all of the upside associated with this play for us. The investor has made a great deal for themselves, and they'll make a nice return on their investment here. And so it's, again, very much a win-win situation. But we do think that this is an attractive source of capital relative to the JVs. And it's competitive with the JVs. And so I think there's a place for both.

David W. Kistler - Simmons & Company International, Research Division

Sure. Appreciate that. Then just one last one. On the 5,000 acres that you have acquired in a newly deemed oil play, can you talk a little bit about how big you think that could be or you're hoping that could be? Just so we have a way of thinking about what that might mean for leasehold spend going forward.

Aubrey K. McClendon

Yes. Sure, Dave. This is Aubrey. Let me correct, you said 5,000 acres.

David W. Kistler - Simmons & Company International, Research Division

Sorry, 500,000. Sorry.

Aubrey K. McClendon

We don't have 500,000 in hand. We're headed that way. We have multiple hundreds of thousands, but that's kind of our goal. The acreage is really inexpensive. So it's not part of -- a significant part of our leasehold spend for the quarter or for the year. And I really don't want to say more than that. We'll be drilling in this area in the early part of 2012, and we'll see how we go. But I do confirm that it is a oil- and liquids-based play in the U.S.

Operator

We'll go next to Jeff Robertson with Barclays Capital.

Jeffrey W. Robertson - Barclays Capital, Research Division

Aubrey, in the Utica, can you talk a little bit about the capital profile over the next several years for the assets that are covered by the joint venture?

Aubrey K. McClendon

Jeff, if you're referring to what's our projected CapEx per year -- is that what you're looking for?

Jeffrey W. Robertson - Barclays Capital, Research Division

Well, yes. I guess you talk about it in the release on the joint ventures that the proceeds and the funding you have in place will cover your development capital, along with cash flow, for the next several years. So I'm just curious if you can lay out how you think this part of the asset will evolve in terms of capital spending and activity over the next several years. And then also, I guess secondly to that is, in your projections for liquids volumes going out through 2015, are you able to talk yet about how much of that is expected to be from the Utica play?

Aubrey K. McClendon

No. I mean, I could, but I'm not. We've still got a reasonably significant risk factor on Utica volumes going forward. So they do not -- I think they'll have a heavier weight as we go forward. But you could see clearly that we've been de-risking some plays as we moved along. As this -- in this release, we talk about moving forward from exit rates in 2013 and 2015, 2012, for that matter, from exit rates to averages for the year. So clearly, we're feeling more comfortable about some plays all across the board. With regard to the first part of your question, remember that although the EIG and unnamed company JV will -- along with cash flow, will handle our expenses in this area, the CapEx will still get reported that is not subject to the JV. So remember, the EIG deal gives us money today for spending that we will do over the years in the future. So even though we won't -- even though we are fully funding what we will do in the years ahead, we'll still report that CapEx. And in terms of giving you specific dollar amounts, we're just not ready to do that yet. But we have given you our rig schedule. And so I think you can basically begin to see how you could make the correlation from rigs to CapEx.

Jeffrey W. Robertson - Barclays Capital, Research Division

And then is it safe to say, based on your comments about the risking in your liquids forecast, that as the Utica evolves over the next several years, the numbers you would have in your current liquids forecast are very heavily risked and therefore, they could go up?

Aubrey K. McClendon

I think that's something that we can all be hopeful about.

Operator

We'll go next to Brian Singer with Goldman Sachs.

Brian Singer - Goldman Sachs Group Inc., Research Division

Following up on Jeff's question, your Slide 18 highlights, that sharp liquids -- sharp oil growth that you're planning beginning in 2012, and we noticed you did narrow your differential for liquids prices in your guidance. Was the narrowing of the differentials a function of assuming more oil within the mix or just stronger NTLs prices? And can you kind of talk about your outlook or maybe a little bit more color for your outlook for Utica oil growth in light of what appeared to -- from your initial wells to be being a bit more NGLs-rich relative to oil-rich?

Aubrey K. McClendon

Yes, Brian, this is Aubrey. So 2 things. We narrowed the differential in 2012 because we believe that, in 2012, there will be a solution to the cushing to Gulf Coast differential or call it Brent, call it LLS, whatever you want to call it. It's already come in from $28 a barrel at its high to $17 or $18 today. We believe there will be a physical solution to that emerge this year, and we'll be part of it, honestly. And then for 2013, we continue to believe that, that narrowing of that oil differential will occur. But also, by the end of 2013, we'll have seen at least 1, maybe 2 pipeline solutions that will take care of the ethane discount that exists at Conway today to Bellevue. You may be aware that Bellevue ethane prices are almost 3x what they are at Conway in Kansas, where a lot of our production does ultimately get priced and/or processed. So those are the reasons why we are planning for increased or shrinking differentials, not really a big shift in our oil versus NGL percentages. In fact, you can look at that slide on, I think Slide 18, and see that, over time, I think our oil portion of our liquids is about 60% and NGL is about 40%.

Brian Singer - Goldman Sachs Group Inc., Research Division

And I guess when you think about drilling in the Utica in the AMI and the JV, should we expect similar type NGL -- should we expect the wells to predominantly be more NGLs? Or should we expect rising levels of oil and condensate?

Aubrey K. McClendon

Well, it depends where we drill. Obviously, to the extent we drill to the eastern side of our acreage, it'll be gasier. And to extent we drill to the western side, it'll be oilier. So at that point, I'm not willing to suggest anything other than that, given the competitive pressures in the field today from other companies trying to figure the play out.

Brian Singer - Goldman Sachs Group Inc., Research Division

And lastly, the language in your CapEx guidance seemed to change to proved well costs from drilling and completion costs previously. And you now seem to be breaking out well costs on unproved properties separately in your cash flow statement. Can you add more color on whether we should anticipate additional upstream CapEx going forward beyond the proved well costs in your guidance?

Domenic J. Dell’Osso

Sure. Brian, I'll take that. No, is the short answer. Over the last quarter, we saw a big increase in the spending we've had on wells that are drilling, drilling and completed, variety of stages, but not yet having had a flow test and so, therefore, not yet proved reserves. And so in review of our data and reviewing our results with our auditors, we felt it was appropriate to spike this out separately. We've always forecasted our drilling and completion CapEx on a cash basis. So we think about what we're going to spend drilling wells for a year, inclusive of whether or not the well is immediately proved and put into our full-cost pool or not. Given the delay in some of the basins like the Marcellus that is so significant at times in bringing wells online, it has been appropriate to separate this out into its own category. So, no, we were -- with our CapEx guidance for next year, and there's a lot of things to consider as we roll through the next year. Remember, oilfield services costs have seen a lot of inflation throughout 2011. We think we're over the hump on that. A big part of that for us will be the bringing online of our Performance Technologies, L.L.C., which will be pumping our own frac jobs and providing a big cost savings to us. But there's certainly some things to watch there as we get into 2012. Also, I think -- we've gone out with 2013 now. We've had our '12 guidance out for a year. We do try and give you guys as much guidance into this as early as possible. And so I certainly hope that you all understand that we're looking pretty far into the future at times when we try to give you this guidance, and it is our best estimate at the time. But for now, our 2012 CapEx guidance stays where it is.

Brian Singer - Goldman Sachs Group Inc., Research Division

We do appreciate the early look on '13.

Domenic J. Dell’Osso

And, again, so it stays where it is, inclusive of this separate category.

Operator

We'll take our next question from Scott Hanold with RBC Capital Markets.

Scott Hanold - RBC Capital Markets, LLC, Research Division

Maybe staying on that same subject of CapEx and being a little bit more direct with some of the questions that have been asked out there. You've obviously been picking up some acreage in some plays and have done a very good job of monetizing some of these acquisitions or I'm sure some acreage purchases. But as you look forward into 2012, 2013, I mean, in terms of what you're planning to do, I mean, how big could that leasehold acquisition number be? I mean, we've seen your numbers on a quarterly basis get upwards of $1 billion plus. Is that -- should we think something consistent in '12?

Aubrey K. McClendon

Well, there's lots of ways to think about it, Scott. First of all, our budget this year will be, as promised, significantly less than last year's. So our spend has been going down. And probably next year, it will be less as well. But it's always a curious question to me. We just announced a deal where we're going to make 10:1 on our money in less than a year. And I'm a little surprised people don't ask us why we don't spend more on leasehold. It's clearly a huge area of profit for us, and it is unique in the industry. And it is one of the greatest mysteries of life for me, why people wouldn't encourage us to spend more in that area. The reality is, we're not going to, and we don't need to. But I would look at what we're doing this year as having been down about 1/3 from last year. And next year, I would expect it to be down at least another 1/3 and maybe 1/2. We're just simply, I think the industry, including us, is running out of places where you could go put together big leasehold positions. And we're not chasing anything in California, and we're not chasing the -- for example, the Tuscaloosa Marine Shale and some other things that would be pretty pricey to get involved in. So continue to ramp it down. I'll note that most of our leasehold spending this quarter was in the Utica, in the Anadarko, in the Permian and in the Marcellus. And so those areas continue to be strong, continue to attract strong amounts of capital from us. But going forward, we expect that, that will diminish over time.

Scott Hanold - RBC Capital Markets, LLC, Research Division

Aubrey, do you believe that's true that the opportunities to pick up acreage are sort of dwindling now that a lot of these plays have been found? I mean that's kind of similar commentary we've heard in the past from you. But it seems like, every year, there's another new play that adds a lot of value. Is it different this time?

Aubrey K. McClendon

Well, when we said that we've thought that the big plays were over, I always said I thought there was one more, and that was the Utica. I knew about that one. These other little things that we're working on -- ask any company what's left in the Williston? What's left in the Anadarko? What's left in the Permian? What's left in the Marcellus? What's left in the Utica? There's really just not much out there, and that's why we were in a hurry. When you look back on this 5 years from now, 10 years from now, companies are going to say, "Wow, I wish I had negative $1,500 an acre in my cost pool for the great acreage like Chesapeake does," rather than having to pay $5,000, $10,000, $15,000, $20,000, 25,000 an acre for it in the future. So we love what we've been able to accomplish and know that it's created strong value for our shareholders, in fact, unique value. And so there's nothing other than to point to the numbers and show what other companies, much bigger than ours, for example, are willing to pay for assets that we own.

Scott Hanold - RBC Capital Markets, LLC, Research Division

Okay, appreciate that. And one last question, on this new subsidiary you created with -- in this Utica, with this Utica acreage. With the perpetual preferred, what is your preference in terms of, would you rather see that thing be outstanding for more of a lengthy period of time? Or do you generally have a preference of sort of a plan to redeem that at some point?

Domenic J. Dell’Osso

It'll probably be redeemed over time. That would be our plan. That's the way that we will bring cash out of this entity. But ultimately, that's a decision we'll get to make from a cost of capital and what our alternative places to put capital are. And so just like our decisions around retiring debt, we've gotten to a point where we thought it made sense on our balance sheet to monetize assets and put the proceeds towards retirement of debt as we've come to what we believe is the later stages of the acreage acquisition phenomenon in the U.S. We'll have an opportunity to do that with this security over time as well. But again, there's -- it's totally up to us from a timing perspective.

Scott Hanold - RBC Capital Markets, LLC, Research Division

So it sounds like more in sort of tranches when you have capital to do so. Is that correct?

Domenic J. Dell’Osso

It's a decision we'll make as we evaluate our free cash flow over time. But it's -- I mean, the best way to think about it is, it's a financial decision that we're free to make based on what our relative opportunities are.

Operator

We'll take our next question from David Tameron with Wells Fargo.

David R. Tameron - Wells Fargo Securities, LLC, Research Division

A couple of questions. Nick, can you give -- so what's your total CapEx budget for '12? You have the 6th -- whatever that range is on the E and D [ph] side. And then should we be adding in that additional service in -- or how should we think about your total CapEx budget for '12?

Domenic J. Dell’Osso

Remember this, our Services business now has its own balance sheet. We've raised a significant amount of bonds for it, and we have a $500 million undrawn revolving credit facility that closed yesterday for that business. And we do plan to monetize equity in that business next year. So I would not include Services CapEx. We think that business is pretty well funded in and of itself. The Midstream CapEx, you can see from the guidance we've provided, does have what would be a funding gap, if you will. The EBITDA doesn't typically grow to a big size within that entity, because once an asset does generate sizable EBITDA there, we generally like to sell it to CHKM through a drop-down, which brings asset sale proceeds to offset our spending. And so there's some additional capital that will be funded by the parent company there. And then the only other thing we guide to, as you know, David, is just our drilling and completion capital, which is in our guidance this year for '12, and for '13 as well. So that's how we think about our CapEx.

David R. Tameron - Wells Fargo Securities, LLC, Research Division

Okay. And how do you guys think about -- all the questions out there this morning, there are twofold. I'm just going to throw them out there and let you guys address them. One, Aubrey, the people are saying this is an LOI, and therefore, there's a lot more wiggle room and blah, blah, blah. Can you address that? And then second, what do you guys think -- if you look at, again, the funding gap type number, what do you think that is for 2013?

Aubrey K. McClendon

Okay, 2 things. First of all, the LOI is an LOI. You're right about that. But I would look at our track record and say, how many times have we failed to convert an LOI into a closed deal? I'll tell you the answer to that, which is 0. And so, I mean, would people prefer that we have not done a deal at $15,000 and not have an LOI? I mean, it's a little crazy that somehow we would be better off to not have an LOI at $15,000 an acre. So we'll -- we'll do what we always do, which is we get our deals done and we bring them to the finish line. And we'll do it here. We've always done it in the past. With regard to whatever funding gap, I mean, it's just a real easy answer. We will come up with all the cash that we need to run our business and to improve our balance sheet and hit our year-end 2012 target like we've always said we will. And it's not that hard, and there's lots of ways to do it. And it's a little bit, to me, like asking an investor who has no current salary, but he makes $1 million a year from capital gains on his stocks, asking him how he's going to fund his gap because he's got no salary. Well, he makes $1 million a year when he sells assets. And we create a lot of value, along with our operating cash flow. We have a large -- the company has the equivalent of a large salary from its operating cash flow, and we supplement that with capital gains from assets. And at the same time, we still are able to add 1.3 billion barrels of oil equivalent and proved reserves or 4 Tcf a year, while still meeting all of our obligations and reducing our debt. So, I mean, I can't say it anymore simply than that. We've said we're going to do by year-end 2012, and we'll do it. And you can look at our debt at 9/30, yes, it's up, sure. We spend a lot of money on the Utica leasehold, but we turned around and sold part of it for a 10:1 profit that will close by the end of the quarter. So our 12/31 balance sheet will look a lot different from our 9/30 balance sheet.

Operator

We'll take our next question from Tim Rezvan with Sterne Agee.

Timothy Rezvan - Sterne Agee & Leach Inc., Research Division

I know you've touched on this a bit, but any more color you can provide on kind of how we're looking at this $2.3 billion in proceeds around year end and how that can address debt reduction in absolute format, would be appreciated. And any specific color you can kind of provide other than what's been mentioned so far?

Aubrey K. McClendon

Well, Tim, it's pretty, again, straightforward. The cash will come in, and it'll be applied against our revolving line of credit and our debt will go down at the end of the quarter. So we won't be buying any bonds in the quarter, but our debts will float up and down, and it just floated up last quarter because of the -- we didn't close a big deal in the third quarter, plus we spent some money on leasehold. The fourth quarter will be the reverse of that.

Operator

[Operator Instructions] We'll take our next question from Biju Perincheril with Jefferies.

Biju Z. Perincheril - Jefferies & Company, Inc., Research Division

Aubrey, a couple of questions. Just looking at your early completions in the Utica, it looks like you're using a much bigger frac [indiscernible] more sand and more water than [Technical Difficulty] I was asking about, looking at some of the early completions in the Utica, it looks like you are using a lot more sand and water than you typically in some of the other plays. And I was just wondering, does the reservoir need that? Or are you experimenting? And when you talk about the $5 million to $6 million well cost in development phase, does that anticipate you getting to a more normalized frac job, if you will?

Aubrey K. McClendon

Yes, I think that's a good way to think about it. And I think that's normalized on a lot of things. We won't be taking cores, we won't be doing a lot of other experimentation. So we're still tweaking our frac job. It's still a new play. And we'll be trying lots of different things in the future. So some jobs will use more sand, some jobs less, some jobs more liquids, some jobs less. So we're still tweaking. But certainly like what we've seen to date, and look forward, like we do in all plays, to get into kind of the manufacturing phase of it, which will be in full speed in 2012.

Biju Z. Perincheril - Jefferies & Company, Inc., Research Division

Okay. So it's not a reflection that, that's what the reservoir requires.

Aubrey K. McClendon

No, I wouldn't look at it that way at all.

Biju Z. Perincheril - Jefferies & Company, Inc., Research Division

Okay. And then in the Niobrara, the planned acreage sale there, can you tell us how the JV -- the drilling carries there is going to work? Do those carries get reduced by the acreage that you sell?

Aubrey K. McClendon

No, the carries do not get attached to specific acreage. They are just a corporate obligation on behalf of our partner and, of course, a corporate asset on our account. So if we sold all the acreage in a play, I guess we'd obviously have to talk about how to deal with it then. But in the Niobrara, we do have a lot of acreage, and some of it we're just simply not going to get to. And some of it is in other companies' strongholds and a relatively weak position from our perspective so we're doing some trimming on the northern side of some of our leasehold there. The carry will get still spent or still earned, I guess, is the way to think about it on our side, as we drill wells more in our core areas.

Biju Z. Perincheril - Jefferies & Company, Inc., Research Division

Got it. And then lastly, I noticed that you've been recently somewhat active in the Woodbine. First of call, can you say how that compares to your Eagle Ford position? And then second, is that an area where you can get much larger than what you are today?

Aubrey K. McClendon

I don't know. I don't think anybody knows how large we are there. But we're not all that large. I think we drilled 4 wells and like what we've done so far. But it's an area that's pretty tied up. And so we'll be able to piece together some other things. But that's not a multi hundred thousand acre play for us. And I think it would be difficult for anybody else just because there's a lot of overlapping existing production on it right now. But we do like what we've seen to date from our wells. And when I'm talking about the Woodbine, I'm talking about the East Texas Woodbine, which I presume you're talking about as well. Or with some companies, I guess they're calling it Eaglebine.

Operator

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

Neal Dingmann - SunTrust Robinson Humphrey, Inc., Research Division

Aubrey, couple of questions. First, Aubrey, a number of your peers have announced on conference calls about problems with gathering systems and takeaways. Just wondering your comment, as you look at the Utica and some of your other big plays, how you feel about that.

Aubrey K. McClendon

Well, there's a lot of aspects to our business that are challenging, and certainly building infrastructure in new play areas is one of those. But that's one of the advantages to the Chesapeake business model, in that we are vertically integrated all the way from our service operations up to our midstream operations. So there'll be some delays, but we've built those in. I mean, for example, in the Eagle Ford, we've only lately have had kind of a surge of production there because we were waiting on a lot of infrastructure. We just, I think, did a pretty good job of modeling for that. And you don't see us miss our numbers and then blame unforeseen circumstances. We plan for those and take it in stride. And, again, through our balanced and diversified asset base, we can have issues in one area and not affect our overall performance.

Neal Dingmann - SunTrust Robinson Humphrey, Inc., Research Division

Okay. And then just lastly, just obviously, you got the nice price for the Utica. I just wonder how you view here, for the remainder of the year, what your thought is on the M&A market, not only in the East, but just kind of domestically overall.

Aubrey K. McClendon

Well, I think our transaction shows that there is still healthy demand by bigger companies for the assets that smaller companies have. I don't know how else to describe it. And every time everyone feels like that's over, there's an M&A transaction like a Statoil for Brigham or something like that. And we just -- we've got something that the world wants, which is the highest return on assets in the worldwide oil and gas business. And so, until returns in the rest of the world rise to meet those here -- and I don't think they will, and I don't think they can because of the basic terms of those deals. And when you apply the risk factors, both political and geological and timing risks to all those, I think all roads lead back to the U.S. And that's why there's not a big oil company in the world that I'm aware of that's not seeking to increase the size of its commitment to North America. So I think that's a trend that will continue for years and years to come.

Operator

We'll go next to Jason Gilbert with Goldman Sachs.

Jason Gilbert - Goldman Sachs Group Inc., Research Division

Aubrey, I hear what you're saying about the rationale for pursuing leasehold acquisitions even at the cost of higher leverage in the short term. I was just wondering, overall, if you view IG ratings as nice to have for a company of your size and scale or as a must-have, and what's the urgency there?

Aubrey K. McClendon

Well, I think we've been on record that it's something that we think is an inevitable outcome of our business strategy. It's not so much that we have to have it by a certain time. Obviously, we have access to any capital markets we want. And the company's debt trades is a strong crossover credit, I think. So -- but at the same time, we think we have investment grade assets, we think we've got investment grade strategy. I honestly think if people were to allocate part of our debt to our Midstream and our Service businesses, I mean, on Page 27 or 30, I can't think right now, in our slideshow, we talk about $17 billion of non-E&P assets. Think about our Midstream as part of that and our Service assets as part of that. If we were to be able to allocate 30% or 40% of the capital structure of those companies with debt that is today burdened against our E&P assets, you'd see that we have an investment grade balance sheet already on our E&P assets. So that's why we're eager to get Chesapeake Oilfield Services public and continue to grow our Midstream business, so that we can reflect the fact that a lot of the company's leverage that rating agencies put all against our oil and gas reserves are, in fact, more properly -- should be more properly distributed across the company's asset base.

Domenic J. Dell’Osso

I'll add to that, that, again, in my comments, I pointed out that even without doing that allocation, our total debt at the end of the quarter was -- pro forma for the transactions we've been working on this week is $0.54 per Mcfe. So even without that allocation, that's a pretty attractive number and it's really beginning to look like an investment grade metric.

Jason Gilbert - Goldman Sachs Group Inc., Research Division

Okay. Yes, I hear you. And a second unrelated question, just on back to the land-grab question. I was wondering, what are you seeing in terms of international shale opportunities, potential for an international strategy and timing and scale of what that might look like?

Aubrey K. McClendon

We've consistently, over the last couple of years, said we have no interest in international shale assets or any kind of assets. And that includes Canada, and that includes Mexico. And nothing's changed. We are focused on the good old U.S.A., and that's where we will always remain.

Operator

We'll take our next question from Bob Brackett with Bernstein Research.

Bob Brackett - Sanford C. Bernstein & Co., LLC., Research Division

As you guys transition from gas, when do you think you'll start splitting NGLs and black oil in your financial reportings to help us with our homework?

Aubrey K. McClendon

Bob, I'm not aware exactly when we'll cross that line. We need to do it. I suppose it'll be in 2012. But Jeff or Nick, I don't know if you-all have a different answer to that.

Domenic J. Dell’Osso

We don't have a different answer to that yet. But we're looking at it, Bob, and it'll certain happen at some point.

Aubrey K. McClendon

We generally say we're around 60% oil -- 55% to 60% oil, and the rest is natural gas liquids. So I can save you some homework, if you'd like, by using those numbers.

Operator

We'll take our next question from Joe Allman with JPMorgan.

Joseph D. Allman - JP Morgan Chase & Co, Research Division

So in terms of CapEx for 2011, it appears that you didn't change your drilling and completion CapEx from the $6 billion to $6.5 billion. But year-to-date, I think you spend about $5.2 billion. That implies in the fourth quarter, you're going to spend $0.8 billion to $1.3 billion. So is that reasonable?

Domenic J. Dell’Osso

That's where we are today. Yes, that's where we are today, inclusive of the $875 million that's in there for the...

Aubrey K. McClendon

Yes, you quote the 5 point --

Domenic J. Dell’Osso

Our range for the year is $6 billion to $6.5 billion, and that range is still relevant.

Joseph D. Allman - JP Morgan Chase & Co, Research Division

I think in the third quarter, you spent about $1.95 billion, and in the prior 2 quarters, about $1.6 billion, $1.7 billion. So what's going to bring the number down so much in the fourth quarter?

Domenic J. Dell’Osso

Well, again, the $5.3 billion that you talk about year-to-date includes the $875 million of the work in process. And so we do think that was a bit of an anomalous quarter, we think, on a go-forward basis. And so we had a lot of stuff to do in the third quarter. And we think just as the normal flow of business ebbs and flows, we're still looking at $6 billion to $6.5 billion for the end of the year, total.

Aubrey K. McClendon

And, Joe, that's what's comparable to the number on Page 12, the $4.5 billion number. So you need to be comparing apples and apples.

Joseph D. Allman - JP Morgan Chase & Co, Research Division

Okay. And then -- okay. So you changed the name of that category. So what's -- again, you might have covered this in the beginning, but I missed it. what's the purpose in changing the name of the category from drilling and completion costs, which seems to be more comprehensive, to proved well costs?

Domenic J. Dell’Osso

Well, the purpose of changing the name is just to try and be accurate with the way that we're having to report this now. I mean, it has gotten to be a big number. We can't and shouldn't continue to put a number that large in our proved reserve cost because it does represent costs associated with assets that are not yet proved. And so it skews inappropriately our F&D costs if we were to do it, and it would skew inappropriately going forward our depletion costs. And so it needs to be broken out separately. And we're trying to be clear about how we're spending money. There's an element of money that we spend every quarter on wells that take a period of time to come online. And again, we've had some very large infrastructure projects in the industry that you read about every day that are being worked on and that are the result of us having spent, in this past quarter, $875 million on assets that have yet to be proven. And so it's only appropriate to leave those costs out of our full-cost pool for the moment. Those costs will flow into our full-cost pool as these assets are -- as these wells are flow-tested and the reserves are proven. That number will move up into proved drilling and completion costs. So that $875 million will flow up into that line at some point in the future. And it's reasonable to think that it'll be within a year or so.

Aubrey K. McClendon

Joe, one other way to think about it, our reported finding costs on Page 12 were $1.8 per Mcfe. And even if you were to throw the work-in-process costs into that equation and don't give us any credit for the Tcf associated there, our costs are $1.29 per Mcfe. So, again, I think the emphasis is misplaced on what we're spending, not on what we're finding. And if you can find reserves at $1.08 or $1.29, our view is we ought to be doing as much of it as we can. That's how we create value, and that's how we're going to continue to do it.

Joseph D. Allman - JP Morgan Chase & Co, Research Division

Okay. So let me clarify. So this $6 billion to $6.5 billion, are you saying that this is the money you're spending on PUDs, drilling PUDs?

Domenic J. Dell’Osso

No. Not necessarily, no. The money, that could be -- those could be -- in fact, those are not PUDs. If they were PUDs, they would be in the dollars spent on proved reserves. So generally, we don't often drill -- well, I shouldn't say often. We do, of course, drill PUDs. But a significant portion of the wells that we drill are on non-proven locations because we're out trying to hold leasehold in early stages in our plays. And so these are wells that exist in a probable or possible category on an internal reserve report. Once they're drilled, they become proved developed producing wells, and then an offset to them is called the PUD. And we typically won't come back and drill that PUD if it's already being held by leasehold for some period of time. Of course, there's a 5-year rule on PUDs. And so, generally, these are dollars that are being spent on wells that are not yet proven and that have not yet been flow-tested. This is something that you'll see successful efforts companies have to report on a regular basis. It's different for us as a full-cost company because, generally, all of your dollars spent on drilling and completion will be put into your pool, assuming that you're going to know whether or not it went to a productive well in the relatively near future. What we've seen over the last year is that there is a significant delay on a fair amount of our properties where you don't get to make that determination because you don't have the infrastructure in place.

Joseph D. Allman - JP Morgan Chase & Co, Research Division

But you're changing the way you're doing this with this third quarter release versus what you did before, right?

Domenic J. Dell’Osso

Correct. Because the number became material, and we needed to spike it out separately.

Joseph D. Allman - JP Morgan Chase & Co, Research Division

Okay. So just sort of $6 billion to $6.5 billion, if to compare that to Schedule B, it's apples and oranges, right? So really, that $6 billion to $6.5 billion, you need to add that $800-plus million to what you have in Schedule A now to make it apples-to-apples with Schedule B. Is that correct?

Domenic J. Dell’Osso

No, that's not correct.

Joseph D. Allman - JP Morgan Chase & Co, Research Division

Okay. So why is that not correct? I'm sorry.

Domenic J. Dell’Osso

Yes, we'll tell you -- why don't you follow-up with Jeff and John and myself later. But it's not correct. The $6 billion to $6.5 billion is our drilling and completion spend for 2011.

Aubrey K. McClendon

Joe, we are in Boston, and we've got to run and see some investors on this Chesapeake royalty trust deal. So I'm sorry to ask you to take that offline. But...

Joseph D. Allman - JP Morgan Chase & Co, Research Division

Okay. I've just got a couple more. So just in terms of long-term debt, it was up by $1.7 billion from the second quarter to the third quarter. Was that pretty much all a draw on the revolver? And what is the status of the revolver now?

Aubrey K. McClendon

Joe, it was all from the revolver, and you'll see it kind of reverse itself in the fourth quarter as we bring these deals to fruition and close them to cash.

Joseph D. Allman - JP Morgan Chase & Co, Research Division

Got you. Okay. And just a couple of quick ones. So when you guys put out that Utica well release with the first 4 wells, I think you put out peak rates, which my interpretation is from talking to you guys, it means not 24-hour rates. So is that true? And what's the value of that data? And why would you put that out?

Aubrey K. McClendon

Joe, we think it's important data to put out. We don't say whether it's 24 hours or 6 hours or 2 hours or whatever. It's just industry-standard to use peak spot rates, and we've done that. And there's nothing unusual about it. We've drilled some really good wells and felt like the industry -- our investors, rather, ought to know about it. Of course, the industry jumped on it, and leasehold prices went up pretty dramatically. So just at this point, it doesn't make -- it's not in our best interest, our shareholders' best interest to throw more gasoline on the fire. Other companies obviously are starting to talk about their wells. Rex did it. I'm sure Range will have some results before too long. So, again, very pleased, and, of course, our partner has had access to all of our drilling results as well. So obviously, their decision was based on results that they've seen on a level of detail that you or anybody else hasn't been able to see.

Joseph D. Allman - JP Morgan Chase & Co, Research Division

Got you. And then just a last quick one. So the fact that you closed out your hedges, is that reflective of just a need for cash in the near term?

Aubrey K. McClendon

Joe, I think we made it pretty clear that we feel like the bottoms are in, in the natural gas markets. We also took advantage of some days when there was worldwide financial chaos. And oil price is way down, and gas price is way down that we didn't think were justified by supply-demand fundamentals. So we went ahead and cashed out a good bit of them and then will look to the opportunity to put them back on. We've done this on several occasions in the last 5 years and, typically, we've been pretty successful at being able to put it back on. Maybe you noticed, we've made $8.1 billion on our hedges since 2006. So we don't always get it right, but we've got a pretty good track record there.

Okay. I think -- I'm told that, that was the last question. We appreciate your interest. And, again, we'll be a little hard to get ahold of today as we're in Boston, but we'll do our best to get back to you with any additional questions that you have. Thanks very much.

Operator

Again, ladies and gentlemen, thank you for your participation. This will conclude today's conference call.

Copyright policy: All transcripts on this site are the copyright of Seeking Alpha. However, we view them as an important resource for bloggers and journalists, and are excited to contribute to the democratization of financial information on the Internet. (Until now investors have had to pay thousands of dollars in subscription fees for transcripts.) So our reproduction policy is as follows: You may quote up to 400 words of any transcript on the condition that you attribute the transcript to Seeking Alpha and either link to the original transcript or to www.SeekingAlpha.com. All other use is prohibited.

THE INFORMATION CONTAINED HERE IS A TEXTUAL REPRESENTATION OF THE APPLICABLE COMPANY'S CONFERENCE CALL, CONFERENCE PRESENTATION OR OTHER AUDIO PRESENTATION, AND WHILE EFFORTS ARE MADE TO PROVIDE AN ACCURATE TRANSCRIPTION, THERE MAY BE MATERIAL ERRORS, OMISSIONS, OR INACCURACIES IN THE REPORTING OF THE SUBSTANCE OF THE AUDIO PRESENTATIONS. IN NO WAY DOES SEEKING ALPHA ASSUME ANY RESPONSIBILITY FOR ANY INVESTMENT OR OTHER DECISIONS MADE BASED UPON THE INFORMATION PROVIDED ON THIS WEB SITE OR IN ANY TRANSCRIPT. USERS ARE ADVISED TO REVIEW THE APPLICABLE COMPANY'S AUDIO PRESENTATION ITSELF AND THE APPLICABLE COMPANY'S SEC FILINGS BEFORE MAKING ANY INVESTMENT OR OTHER DECISIONS.

If you have any additional questions about our online transcripts, please contact us at: transcripts@seekingalpha.com. Thank you!

Source: Chesapeake Energy's CEO Discusses Q3 2011 Results - Earnings Call Transcript
This Transcript
All Transcripts