Chesapeake Energy Corp (CHK) 2011 Q3 法說會逐字稿

Good day and welcome to be Chesapeake Energy 2011 Third Quarter Earnings Results Conference Call.

As a reminder, today's conference is being recorded.

At this time I would like to turn the conference over to Mr.

Jeff Mobley.

Please go ahead sir.

Good morning and thank you for joining our conference call this morning.

We understand there are a few other companies overlapping with us, and so we will be short and to the point.

Aubrey, Nick and myself are in Boston for an offering that is underway.

Steve Dixon and John Kilgallon are in Oklahoma City.

I'll turn the call over to Aubrey.

Thanks Jeff.

I will begin by clarifying that the offering is for Chesapeake royalty trust units, not anything else.

All right, good morning.

We hope you have 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 slideshow labeled November Presentation.

It is under the Investors button, and then you go to Presentations to find it.

Later in my remarks I will 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 one phase of the Utica play.

In these seven JV areas, the Company initially acquired approximately 5.1 million net leasehold acres at a cost of $11.1 billion.

That is around $2200 per net acre overall on average.

We then sold 1.5 million of those acres for a total consideration of $16.4 billion in cash and carries, meaning we recovered 150% of our total leasehold cost in all the plays combined, while leaving ourselves with 3.6 million net acres in seven of the nation's very best plays at a negative leasehold cost of $5.3 billion.

That is about a negative $1500 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 $1500 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 are on our way to 500,000 net acres in another oil play that we are not ready to discuss yet until we have drilled a few wells in it.

Next I would like to focus my comments on our two Utica transactions.

As we disclosed to you in July, we believe 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 would like to emphasize that the deal is very attractive to them and very attractive to us.

It is 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 work 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 1000 net acres per workday though 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.

The well results in the plays should begin accelerating in the months ahead.

We also continued to successfully drill new wells in the Utica and that the play has become by far the most frenzied new leasehold play in the industry since the Haynesville in 2008.

And as I have 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 pipeline.

One last thing on the industry JV, it values our 570,000 net acres in the JV at $8.5 billion, which bodes well from our 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 in 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, 49 times 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 is 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 five 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 five years were basically changed single-handedly by the efforts of one Company.

And now I'm telling you during the next five 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 of you gas consumers out there, don't worry.

If gas demand picks up, and 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 the US gas markets remain well supplied.

Now back to liquids production for a moment.

I read the most remarkable statement two 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 US during the past 40 years.

Normally I don't pay much attention to competitor 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 one, not two, not three, but actually four liquids plays that are bigger than the 900 million barrels claimed to be the industry's biggest discovery by any one company in the past 40 years.

So what are those four 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 that the potential of these plays net to Chesapeake shareholders or over 4.3 billion barrels of oil equivalent.

And, by the way, our net leasehold costs 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 de-risked 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 four years, that does not 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 US.

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 forecast.

In doing so, we have established that in 2013 we plan to average 200,000 barrels of liquids production per day.

I would like to point out that that used to be our 2013 exit rate goal, not our full year average.

That is 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 is 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 three 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 will 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 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 and production assets.

It is 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 businesses, are transferred away to third parties.

I will turn it over to Nick now.

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 was the second quarter in a row we have added approximately 1 Tcf equivalent of reserves.

This again points to the unique, powerful and valuable asset creation machine we have created at Chesapeake.

Additionally, when we look at our reserve adds year-to-date, we have 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 have created through proved reserve growth and does not 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 are looking forward to delivering to investors by December of 2012.

Further, I would like to point out that on a pro forma basis for our transactions announced yesterday, plus 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 reserves ratio would be $0.54 per Mcfe.

Next I would like to focus a bit on our vertical integration strategy and point you to the new section of our outlook where we have 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 have just finished a very successful bond market offering for COS where we sold $650 million of notes to investors at a 6.625% 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 it should be worth $6 billion to $7 billion in enterprise value.

And that does not include our 30% stake in Frac Tech.

There is a very large growth ramp in COS's projections that is important to that business as well as the parent companies [in the] pressure pumping operations.

Our new pressure pumping subsidiary, Performance Technologies, fracked 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 of drilling to 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 US oilfield 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 would like to focus a bit on our hedge profile, because I'm sure you have 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 be 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 prices in 2012, and we are well-positioned to take advantage of those dynamics.

With that, Operator, we will open the line up for questions.

(Operator Instructions).

David Heikkinen, Tudor, Pickering.

The 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?

We have not done that, but basically we plan for roughly 75% to 80% of our drilling to be inside of the joint venture area.

I cannot 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 of it, though, will be in the middle of the play, the wet gas phase.

Okay, and then what role do you expect your joint venture partner to play in the mainstream and marketing side on NGL's or...?

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

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 in the areas you are working and your thoughts there?

Sure.

Well, we have done 7 to date and said that we had 3 more areas where we had significant enough leasehold positions, and I guess significant enough leasehold positions in areas where we have not already accelerated our drilling and would like to have a partner.

And I believe I identified those as potentially the Mississippi Lime, the Williston Basin and then also we have a third play where we are accumulating acreage that is on the oil side.

In places like the Permian and the Anadarko Basin for the Cleveland Tonkawa and the 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 would not pursue a JV partner.

And maybe specifically on the oily part of the Utica and what you did not joint venture, would you expect to potentially move something for there?

Good question.

I think on the dry gas phase we'd want to get a number that is great for our shareholders.

And in this gas price environment that would be tough to do, so we will 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 acreage is 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 have got a body of work that justifies going forward with a JV there, we will likely pursue something like that.

Okay, and then just a question on Chesapeake Oilfield Services as we start looking at margins relative to oilfield services peers.

They looked a little lower.

Can you walk us through how you set pricing?

Is it lower because it is operated just relative, and then an outlook as far as how pricing gets set as that business moves forward?

Sure.

I will let Nick address that for you.

We set pricing based on what we pay others in each basin.

So it is a model that is matched as 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 two-thirds of our own services in any one 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 are looking at, David.

But we think that with the advent of PTL coming into our business in 2012, you will see margins within COS increase pretty dramatically.

We also have a new management team who is focused solely on this business and improving the overall margin and return to investors here.

So I would say you will see that come up over time.

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.

Dave Kistler, Simmons & Co.

Real quickly on Chesapeake Utica LLC, can those shares convert into Chesapeake shares at any time?

And I noticed that your diluted share count has gone down, so I'm guessing the answer is no.

That is correct.

They are not convertible into big Chesapeake shares and, in fact, they are not even convertible into common of the sub.

That is an important distinction between the EIG deal that got 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 is really an important distinction.

And I did see in at least one research note that some analyst was saying that we had issued $1.25 billion of preferred shares in Chesapeake.

That is absolutely not true.

We are selling from a subsidiary and those shares have no ability to convert into common of the Company or into the sub itself.

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 if the 0.05% interest in your ultimate drilling plans or ultimate working interest in the Utica?

Yes, the latter part of what you said is spot on.

It is perpetual preferred which comes with a 7% dividend rate.

And it does have, like you said, a 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 and 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 so we stay in line with the terms of the preferred.

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 are walking through developments of?

You know, I think it is possible.

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 is 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 will make a nice return on their investment here.

So it is, 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 is competitive with the JVs.

So I think there is a place for both.

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 are hoping that could be, just so we have a way of thinking about what that might mean for leasehold spend going forward?

Sure, this is Aubrey.

Let me correct -- you said 5000 acres.

Sorry, 500,000.

But we don't have 500,000 in hand.

We are headed that way.

We have multiple hundreds of thousands, but that is our goal.

The acreage is really inexpensive, so it is not 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 will be drilling in this area in the early part of 2012 and we will see how we go.

But I do confirm that it is an oil and liquids based play in the US.

Jeff Robertson, Barclays Capital.

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?

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

Well, yes -- I guess you talk about 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 projection 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?

No.

I mean I could, but I'm not.

We have still got a reasonably significant risk factor on Utica volumes going forward, so I think they will have a heavier weight as we go forward.

But you could see clearly that we have been de-risking some plays as we moved along as in this release we talked 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 are 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 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 are fully funding what we will do in the years ahead, we will still report that CapEx.

In terms of giving you specific dollar amounts, we are 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.

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?

I think that is something that we can all be hopeful about.

Brian Singer, Goldman Sachs.

Following up on Jeff's question, your slide 18 highlights that sharp oil growth that you are planning beginning in 2012.

We noticed you did not narrow your differential for liquids prices in your guidance.

Was the narrowing of the differential as a function of assuming more oil within the mix or just stronger NGL prices?

And can you 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?

This is Aubrey; so, two 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 has 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 will be part of it, honestly.

And then for 2013, we continued to believe that that narrowing of that oil differential will occur.

But also, by the end of 2013 we will have seen at least one, maybe two pipeline solutions that will take care of the ethane discount that exists at Conway today to Belvieu.

You may be aware that Belvieu ethane prices are almost 3 times 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 it's slide 18, and see that over time I think our oil portion of our liquids is about 60%, and NGL is about 40%.

And I guess when you think about drilling in the Utica, in the AMI and in the JV should we expect the wells to predominately be more NGLs?

Or should we expect rising levels of oil and condensate?

Well, it depends on where we drill.

Obviously, to the extent we drill to the Eastern side of our acreage, it will be gassier.

And to the extent we drill to the Western side, we'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.

Thanks.

And lastly, the language in your CapEx guidance seemed to change to proved well cost from drilling and completion cost previously.

And you now seem to breaking out well cost on proved 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?

Sure.

No, is the short answer.

Over the last quarter we saw a big increase in the spending we have 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.

So, in review of our data and reviewing our results with our auditors, we felt it was appropriate to spike this out separately.

We have always forecasted our drilling and completion CapEx on a cash basis, so we think about what we are going to spend drilling wells for a year inclusive of whether are 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 significant at times in bringing wells online, it has been appropriate to separate this out and to its own category.

So, no, we're with our CapEx guidance for next year, and there is a lot of things to consider as we roll through the next year.

Remember, oilfield services cost have seen a lot of inflation throughout 2011.

We think we are over the hump on that.

A big part of that for us will be the bringing online of our Performance Technologies LLC which will be pumping our own frac jobs and providing a big cost savings to us, but there is certainly some things to watch there as we get into 2012.

Also, I think we have gone out with 2013 now.

We have had our 2012 guidance out for a year.

We do try and give you guys as much guidance into this as early as possible, and so certainly hope that you all understand that we are looking pretty far in the future at times when we try to give you this guidance, and it is a best estimate at the time.

But for now, our 2012 CapEx guidance stays where it is.

We do appreciate the early look on 2013.

Thank you.

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

Scott Hanold, RBC Capital Markets.

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 have 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 in terms of what you are planning to do, how could big could that leasehold acquisition number be?

We have seen numbers on a quarterly basis get upwards of $1 billion plus.

Should think something consistent in 2012?

Well, there is lots of ways to think about it.

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 is always a curious question to me.

We just announced a deal where we are going to make 10 to 1 on our money in less than a year.

I'm a little surprised people don't ask us why we don't spend more on leasehold.

It's clearly a huge area profit for us.

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 are not going to, and we don't need to.

But I would look at what we are doing this year as having been down about one-third from last year, and next year I would expect it to be down at least another one-third and maybe half.

I think the industry, including us, is running out of places where we could go put together big leasehold positions.

And we are not chasing anything in California, and we are not chasing 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 will 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.

Do you believe that it is true that the opportunities to pick up acreage are sort of dwindling now that a lot of these plays have been found?

That's a kind of similar commentary that we have heard in the past from you, but it seems like every year there is another new play that adds a lot of value.

Is it different this time?

Well, when we said that we thought that the big plays were over, I always said I thought there was one more and that was the Utica, and I knew about that one.

These other little things that we are working on, ask any company what is left in the Williston, what is left in the Anadarko, what is left in the Permian, what is left in the Marcellus, what is left into Utica?

There is really just not much out there, and that is 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 $1500 an acre in my cost pool for the great acreage like Chesapeake does, rather than how having to pay $5000, $10,000, $15,000, $20,000, $25,000 an acre for it in the future.

So we love what we have been able to accomplish and know that it has created strong value for our shareholders, in fact unique value.

So there is 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.

Okay, appreciate that.

And one last question, on this new subsidiary you created 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 a plan to redeem that at some point?

It will probably be redeemed over time.

That would be our plan.

That is the way that we will bring cash out of this entity.

But ultimately that is a decision we will 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 have gotten to a point where we thought it made sense on our balance sheet to monetize assets and put proceeds towards the retirement of debt as we'd come to what we believe is the later stages of the acreage acquisition phenomenon in the US.

We will have an opportunity to do that with this security over time as well.

But again, it is totally up to us from a timing perspective.

So it sounds like more in tranches when you have capital to do so.

Is that correct?

It is a decision we will make as we evaluate our free cash flow over time.

But the best way to think about it is, it is a financial decision that we are free to make based on what our relative opportunities are.

David Tameron, Wells Fargo.

A couple of questions.

Nick, so what is your total CapEx budget for 2012?

You have the sixth -- whatever that range is on the E&D side.

And then should we be adding in that additional service?

Or how should we think about your total CapEx budget for 2012?

Remember that our services business now has its own balance sheet.

We raised a significant amount of bonds for it.

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 provided, does have what would be a funding gap, if you will.

The EBITDA does not 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 is some additional capital that will be funded by the parent company there.

And then the only other thing we guide to, as you know, is just our drilling and completion capital which is in our guidance this year for 2012 and for 2013 as well.

So that is how we think about our CapEx.

Okay.

And how do you guys think about -- all the questions out there this morning, they are twofold.

And I will just throw them out there and let you guys address them.

One, Aubrey, the people are saying this is an LOI and therefore there is a lot more wiggle room and blah, blah, blah.

Can you address that?

And then second, what do you guys think if you look again at a funding gap type number, what do you think that is for 2013?

Okay, two things, first of all the LOI is an LOI.

You are right about that.

But I would look at our track record and say, how many times have we failed to convert a LOI into a closed deal?

I will tell you the answer to that, which is zero.

And so, would people prefer that we have not done a deal at $15,000 and not have an LOI?

I mean, it is a little crazy that somehow we would be better off to not have a LOI at $15,000 an acre.

So we will do what we always do, which is we get our deals done and we bring them to the finish line.

And we will do it here.

We have always done it in the past.

With regard to whatever funding gap, it is 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 have always said we will.

And it is not that hard, and there is lots of ways to do it.

It is 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 is going to fund his gap because he has 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.

The Company has the equivalent of a large salary from its operating cash flow, and we supplement that with capital gains from assets.

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 cannot say it any more simply than that.

We have said what are going to do by year-end 2012 and we will do it.

And you can look at our debt at 9/30, yes, it is up.

Sure, we spent a lot of money on the Utica leasehold.

But we turned around and sold part of it for a 10 to 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.

Okay, good.

Appreciate it.

Thanks.

Tim Rezvan, Sterne, Agee.

I know you have touched on this a bit, but any more color you can provide on how we are 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 provide other than what has been mentioned so far?

Well, I think it is again straightforward.

The cash will come in and it will be applied against our revolving line of credit and our debt will go down at the end of the quarter.

So we will not be buying any bonds in the quarter, but our debt will float up and down.

It floated up last quarter because we did not close a big deal in the third quarter, plus we spent some money on leasehold.

The fourth quarter will be the reverse of that.

Okay, thanks.

My other question on the differentials has been addressed, so that is all I had.

Geoffrey Dancey, Cutler Capital.

I'm all set.

Thank you.

(Operator Instructions) Biju Perincheril, Jefferies.

(Technical difficulty)

I'm 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 do in some of the other plays.

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 costs in the development phase, does that anticipate you getting to a more normalized frac job if you will?

Yes, I think that is a good way to think about it, and I think that is normalized on a lot of things.

You know we will not be taking cores, we will not be doing a lot of other experimentation.

So we are still tweaking our frac job.

It is still a new play and we will be trying lots of new different things in the future.

So, some jobs we use more sand; some jobs less, some jobs more liquids, some jobs less.

So we are still tweaking, but certainly like what we have seen to date and look forward, like we do in all plays, to get into the manufacturing phase of it, which will be in full speed in 2012.

Okay, so it is not a reflection that that is what the reservoir requires?

No, I would not look at it that way at all.

And then in the Niobrara, the planned acreage sale there, can you tell us how the drilling carries there are going to work?

Do they carries get reduced by the acreage that you sell?

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 would 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 are just simply not going to get to, and some of it is in other companies' strongholds in a relatively weak position from our perspective.

So we are doing some trimming on the northern side of some of our leasehold there.

So, 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.

Got it.

And then lastly, I noticed that you have been here recently somewhat active in the Woodbine.

First of all, 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 have today?

No, I don't think anybody knows how large we are there, but we are not all that large.

I think we drilled four wells and liked what we have done so far.

But it is an area that is pretty tied up and so we will be able to piece together some other things, but that is not a multi-hundred thousand acre play for us.

And I think it would be difficult for anybody else, just because there is a lot of overlapping existing production on it right now.

But we do like what we have seen to date from our wells.

And when I talk about the Woodbine, I'm talking about the East Texas Woodbine, which I presume you are talking about as well or what some people I guess are calling the Eaglebine.

Neal Dingmann, SunTrust.

A couple of questions.

First, a number of your peers have announced on conference calls about problems with gathering systems and takeaways.

I just wanted your comment as you look at the Utica and some of your other big plays, how you feel about that.

Well, there are a lot of aspects to our business that are challenging and certainly building infrastructure, and new play areas is one of those.

But that is 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 will be some delays but we have built those in.

I mean for example in the Eagle Ford, we only lately have had a surge of production there because we were waiting on a lot of infrastructure.

We just, I think, do 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.

Okay.

And then just lastly, obviously you got the nice price for the Utica.

I just wondered 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 domestically overall?

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 is over, there is an M&A transaction like a Statoil for Brigham or something like that.

And we have 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 risk to all those, I think all roads lead back to the US.

And that is why there is not a big oil company in the world that I'm aware of that is not seeking to increase the size of its commitment to North America.

So I think that is a trend that will continue for years and years to come.

Thanks Aubrey, great quarter.

Jason Gilbert, Goldman Sachs.

Aubrey, I hear what you are 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 is it a must-have?

And what is the urgency there?

Well, I think we have been on record that it is something that we think is an inevitable outcome of our business strategy.

It is not so much that we have to have it by a certain time.

Obviously we have access to any capital markets we want in the Company.

The Company's debt trades as a strong crossover credit, I think.

At the same time we think we have investment-grade assets.

We think we have got an investment-grade strategy.

We honestly think if people were to allocate part of our debt to our midstream and our service business -- on page 27 or 30, I can't think right now, in our slide show 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 would see that we have been an investment-grade balance sheet already on our E&P assets.

So that is why we are 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 should be more properly distributed across the Company's asset base.

I will add to that that, again, in my comments I've pointed out that even without doing that allocation our total debt at the end of the quarter was pro forma for the transactions we have been working on this week is $0.54 per Mcfe.

So, even without that allocation, that would be a pretty attractive number and is really beginning to look like in investment-grade metric.

I hear you.

Thanks.

A second unrelated question -- back to the land grab question.

I was wondering what are you seeing in terms of international sale opportunities, potential for an international strategy and timing and scale of what that might look like?

We have 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 has changed.

We are focused on the good old USA and that is where we will always remain.

Bob Brackett, Bernstein Research.

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

Bob, I'm not aware exactly when we will cross that line.

Need to do it, I suppose it will be in 2012.

But I'll let Jeff and/or Nick, I don't know if you all have a different answer to that.

We don't have a different answer to that yet, but we are looking at it and it will certainly happen at some point.

We generally say we are around 60% oil, 55% to 60% oil and the rest is natural gas liquids.

So I can save you some homework, if you would like, by using those numbers.

Will do.

Thanks.

Joe Allman, JPMorgan.

In terms of CapEx for 2011, it appears that you did not change your drilling and completion CapEx from the $6 billion to $6.5 billion, but year-to-date I think you spent about $5.2 billion.

So that implies in the fourth quarter you are going to spend $0.8 billion to $1.3 billion.

So is that reasonable?

That is where we are today.

Yes, that is where we are today inclusive of the $875 million that is in there for the -- our range for the year is $6 billion to $6.5 billion and that range is still relevant.

I think in the third quarter you spent about $1.95 billion, and in the prior two quarters about $1.6 billion, $1.7 billion.

So what is going to bring that number down so much in the fourth quarter?

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 are still looking at $6 billion to $6.5 billion for the end of the year total.

And that is what is comparable to the number on page 12, the $4.5 billion number, so you'd be comparing apples and apples.

Okay.

So, you changed the name of that category.

Again, you might have covered this in the beginning but I missed it.

What is the purpose in changing the name of the category from drilling and completion cost, which seems to be more comprehensive, to proved well cost?

Well, the purpose of changing the name is just to try and be accurate with the way that we are having to report this now.

It has gotten to be a big number.

We cannot and should not 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 are trying to be clear about how we are spending money.

There is an element of money that we spend every quarter on wells that take a period of time to come online.

And again, we have 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 is 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 wells are flow tested and the reserves or proven.

That number will move up into proved drilling and completion cost.

So that $875 million will flow up into that line at some point in the future, and it is reasonable to think that it will be within a year or so.

Joe, one other way to think about it, our reported finding costs on page 12 were $1.08 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 are spending, not on what we are 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 is how we create value and that is how we are going to continue to do it.

Okay, so let me clarify.

So this $6 billion to $6.5 billion, are you saying that this is the money you are spending on drilling PUDs?

Not necessarily, no.

In fact those are not PUDs.

If they were PUDs, they would be in the dollars spent on proved reserves.

We do of course drill PUDs.

But a significant portion of the wells that we drill are on non-proven locations, because we are 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 are drilled they become proved, developed, producing wells.

And then an offset to them is called a PUD.

And we typically will not come back and drill that PUD if it is already being held by leasehold for some period of time.

Of course, there is a five-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 will see successful efforts companies have to report on a regular basis.

It is 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 are going to know whether or not it went to a productive well in the relatively near future.

What we have 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.

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

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

Okay, so the $6 billion to $6.5 billion, to compare that to Schedule B, it is apples and oranges, right?

So really that $6 billion to $6.5 billion, you need to add that $800 million plus to what you have in Schedule A now to make it apples-to-apples with Schedule B.

Is that correct?

No, that is not correct.

Okay, so why is that not correct?

I'm sorry.

Yes, we will tell you, but why don't you follow-up with Jeff and John and myself later, but it is not correct.

The $6 billion to $6.5 billion is our drilling and completion spend for 2011.

Joe, we are in Boston and we have got to run and see some investors on this Chesapeake royalty trust deal.

So I'm sorry to ask you to take that off-line but --

Okay, I have just got a couple of 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?

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

Got you.

Okay, and a couple of quick ones.

So when you guys put out that Utica well release for the first four 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 is the value of that data and why would you put that out?

Joe, we think it is important data to put out.

We don't say whether it is 24 hours or 6 hours or 2 hours or whatever.

It is just industry-standard to use peak spot rates, and we have done that and there is nothing unusual about it.

We 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 is not in our best interests or 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 have seen on a level of detail that you or anybody else has not been able to see.

Got you.

And then just a last quick one.

So the fact that you closed out your hedges, is that reflective of a need for cash in the near-term?

I think we made it pretty clear that we feel like the bottoms are in on the natural gas markets.

We also took advantage of some days when there was worldwide financial chaos and oil prices way down, sent gas prices way down that we did not think were justified by some of the 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 have done this on several occasions in the last five years, and typically we have been pretty successful at being able to put it back on.

Maybe you noticed we have made $8.1 billion on our hedges since 2006.

So we don't always get it right, but we have got a pretty good track record there.

Very helpful, thank you.

Okay, I think -- I'm told that that is the last question.

We appreciate your interest, and again, we will be a little hard to get a hold of today as we are in Boston.

But we will do our best to get back to you with any additional questions that you have.

Thanks very much.

Again ladies and gentlemen, thank you for your participation.

This will conclude today's conference call.