Chesapeake Energy Corp (CHK) 2010 Q2 法說會逐字稿

Good day and welcome to the Chesapeake Energy 2010 Second Quarter Operational Update and Earnings Results Conference Call.

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.

Good morning.

Thank you for joining our 2010 Second Quarter Earnings and Operational Update Conference Call.

Joining me today is Aubrey McClendon, our Chief Executive Officer.

Steve Dixon, our Chief Operating Officer, Marc Rowland our Chief Financial Officer, Nick Dell'Osso our Vice President of Finance, and John Kilgallon our Manager of Investor Relations and Research.

Our prepared remarks this morning should last 10 to 15 minutes and then we'll move to Q&A.

Aubrey?

Thank you, Jeff.

Good morning to you all.

We hope you've had time to review Monday's operational release and yesterday's financial release.

We always strive to provide the most detailed information in the industry to our investors.

On the operational side, our daily production for the first quarter was very strong at 2.8 bcfe, up 14% year-over-year.

That's after selling a significant amount of production through various VPPs, asset sales and our Barnett joint venture deal with Total.

On a sequential basis, our production was up 8% and most importantly our liquids production was up 41% year-over-year.

Because of the strength of our drilling program and outstanding performance of our wells, we are increasing our 2010 and 2011 production growth forecast to 13% for 2010 and 18% for 2011.

Much of that growth will come from our rapidly increasing liquids production.

In fact, we expect our liquids production to increase by 60% in 2010 and 80% in 2011.

Both of which are remarkable numbers, especially for a company our size.

Next, I'd like to highlight our exceptionally low finding costs during the first half of the year.

We added a net 1.2 tcfe in a drilling and completion cost of only $0.87 per mcfe.

I don't believe there's another company in the industry that's capable of that even 2.5 tcfe to 3 tcf per year to their proved reserves at under $1 per mcfe.

This success has been achieved by the nation's most active and highest quality drilling program led by our industry leading leasehold positions in America's best unconventional natural gas and liquids plays.

The growth in our liquids production and in our proved reserves and our planned slowdown in natural gas drilling are our most important messages today.

I want to make clear, in fact, crystal clear that Chesapeake is pursuing a differentiated growth model from many of our colleagues in the industry.

The CHK model is not a commitment to increasing gas production without regard to natural gas prices.

Quite the opposite, in fact.

Unless gas prices increase over $6 per mcf, Chesapeake is committed to continuing to reduce its gas drilling CapEx and increase its liquids drilling CapEx.

In fact, in 2011, we will see an $800 million swing as we reduce gas CapEx by $400 million in increased liquids CapEx by that same $400 million, all the while planning to keep year-over-year CapEx flat.

I'll repeat, we are reducing natural gas CapEx while increasing liquids CapEx while planning to keep overall drilling CapEx flat in 2011 versus 2010.

With regard to the oil and liquids plays that will drive Chesapeake's growth model in the years ahead, I want to remind you that we started to make this transition back in 2008 when it became clear to us that oil prices were likely to outperform natural gas prices for a long time to come.

However, because of the long lead time in developing the technological expertise to find and test unconventional oil plays, and the length of time it takes to put leasehold plays together, it is only now that we are really starting to see the payoff from the strategy shift that we initiated in 2008.

This will be the single largest strategy shift in Chesapeake's history.

Once it has been completed during the next few years, it will generate huge benefits to our shareholders.

We believe that unlike with natural gas, Chesapeake's success in finding large new reserves of unconventional oil in the US will not negatively affect oil prices.

Obviously, this has not been the case with our large discoveries of unconventional natural gas during the past few years.

One final thought on our liquids plays, for now, we are disclosing the names and locations of 12 of these plays, but there are more on the way.

In these 12 plays, we have drilled about 280 wells and have amassed an industry leading position of 2.4 million acres on which we have identified more than 8 billion barrels of potential un-risk liquids rich resources.

We now own the largest inventory of leasehold in two of the top three new unconventional liquids plays, the Niobrara and the Eagle Ford shale, where we now own 675,000 and 555,000 net acres respectively, located very strategically in the liquids-rich portion of each play.

We are especially pleased with our position in the Eagle Ford and are very excited to move forward with the JV on this acreage.

We are in good position here with many potential partners, all of whom we believe are working hard to get to the right answer.

Speaking of acreage, I am well aware of the huge amount of capital we have laid out for acreage so far this year as we transition away from our former gas-only strategy and towards our more balanced gas and oil strategy.

First of all, some of our gassy peers have chosen not to make this transition and appear willing to take their chances with future gas prices.

That is a risk to which I am not willing to expose our investors.

On the other hand, if you believe oil and NGL prices will be much stronger than gas prices for a long time into the future as we do, then you have two choices.

You can either buy your way into more liquids production through acquisitions or you can organically grow your way into more liquids production through leasing and drillings.

The first approach is one that has been taken by some companies recently, but it is a very, very expensive route.

We prefer the second approach provided it is onshore and in the USA.

We started building the foundation for this transition back in 2008 with our discovery of the granite wash play in western Oklahoma.

During the past two years, our move to oil has been gaining momentum until this year when the pace greatly quickened as about 10 new oil plays developed either under our initiative or in a few cases by some of our peers.

My review of the recent history of the unconventional gas business tells me that it took only about three years from the confirmation of the Barnett size and the Fayetteville discovery in 2005 to the discovery of the Haynesville Marcellus and down dipped Eagle Ford in 2007 and 2008.

I hope you'll recognize that there hasn't been another big unconventional gas play since those discoveries of two years ago.

If you didn't play big in those three years from 2005 to 2008 then you were left behind or were relegated to paying big premiums to establish positions in these premier, new, unconventional gas plays.

Paying up after the fact can work just fine for big international companies, but it doesn't work for us.

In moving from unconventional gas history to thinking more about how the history of unconventional liquids will be written, it was my assessment that 2010 would be the year that companies either locked down positions in these big new liquids plays or were left out and left behind or perhaps relegated to paying very big premiums down the road.

I decided that Chesapeake had to play while costs were still affordable for companies our size and we have played in a big way.

While we still have more leasing to complete in the second half of 2010, the spend will not be as heavy as it was in the first half.

Furthermore, starting in the third quarter 2010, we will begin selling off minority positions in some of these new oil plays to recover much if not all of our initial leasehold investments.

That process will continue into 2011.

When it's all said and done, we will have locked down the best unconventional liquids position in the industry and we will have very low remaining costs in our retained acreage.

If you do not believe that we are capable of this, then I respectfully refer you to our $10 billion of joint venture we entered into in the Big 4 shale gas plays in 2008 and in early 2009 in which we sold about $2 billion of leasehold cost for $10 billion in value.

There's one more aspect of our leasehold buying and selling I'd like to discuss.

For CHK's tax reasons and for partner cash flow reasons, when we sell acreage into a JV, we only receive a portion of the total consideration in up front cash.

The rest comes in drilling carries over time, ie, a reduction in our CapEx for drilling.

For starters, we can't book these drilling carries as receivables because they are contingent on us drilling wells to earn the carries.

That's always a disappointment as our financial statements do not reflect these very big and very valuable drilling carries, which total right now about $3 billion.

I can assure you that we will drill the wells over time and we will receive this cash.

However, when we receive the cash, we record it as a reduction in our drilling CapEx, not as a reduction in our leasehold CapEx.

However it is, in fact, very much a recovery of leasehold CapEx that has simply been triggered by drilling.

But that's not the way it shows up in our financial statements.

Since many analysts routinely kick out our carries in their analysis of our finding costs because to them they are somehow not real, we end up with the worst of all worlds.

Our industry leading low-finding costs are virtually disregarded and our industry leading leasehold CapEx investments are overstated by the amount of the drilling carries received.

Therefore, our true leasehold Cap Ex should always be evaluated by looking at what we spend less what we will collect in up front cash and also less what we will collect in future drilling carries.

This is a big issue.

I hope you will now have a better appreciation of how our leasehold CapEx is always overstated, and in my view, therefore, very likely under-appreciated as our number one profit center over the years.

One more thing in regard to profit centers.

I do hope you will recognize that our cash hedging gains since 2001 have now reached $5.4 billion.

I offer congratulations to the other two members of the hedging committee who are here with me today, Marcus Rowland and Jeff Mobley.

We have delivered outstanding value to investors here in far greater amounts than anyone else in the industry has and I do believe this is a vastly under-appreciated aspect of management's performance over time.

I'd like to close my commentary with reading you an excerpt from our press release that we believe very clearly states what we are seeking to accomplish this year and in the years ahead.

We plan to reduce drilling of natural gas wells except those required to hold leasehold by production or to use a drilling carry provided by joint venture partner until such time as natural gas prices rise above $6 per mcf.

We plan to lease and develop substantial new liquids-rich plays in which the company can acquire very large leasehold positions of 250,000 to 750,000 net acres.

Within one year of acquisition, we plan to sell the minority position in a new play recovering all or virtually all of the costs to acquire the leasehold in the play and to fund a significant portion of Chesapeake's future drilling costs in the play.

We plan to accelerate drilling of liquid-rich plays until year-end 2012 when the company's drilling capital expenditures are balanced approximately 50/50 between natural gas and liquids.

We plan to continue adding proved reserves, net of monetizations and divestitures of approximately 2.5 to 3.0 tcfe for up to 500 million barrels annually and we project by the end of 2012, we are likely to own 18 tcf approved reserves and about 1 billion barrels of oil and encourage you to consider what that would be worth.

Finally, we plan to accomplish these goals without the additional equity and with the reduction of debt level such that the company becomes investment grade within the next few years.

The key challenge we face in implementing this strategy is to allocate capital between our very large gas asset base and our emerging unconventional liquids plays.

We have considerable gas drilling that we need to drill to earn $3 billion of outstanding carries and also to hold very valuable and very high quality gas acreage.

We also have tremendous opportunities in new unconventional liquids plays.

These two activities result in very large capital needs.

Fortunately, our assets are exceptional, and we've been able to attract partners or expect to who will finance much of our new liquids projects.

Because our assets are so valuable, we will be able to accomplish the oil and gas industry hat trick in the years ahead.

We will grow reserves and production by 13% to 18% annually, reduce leverage and not issue any additional equity.

Our assets give us the ability to use a range of asset level financing tools to raise money at significant premiums to our cost basis in these assets.

In summary, having helped to revolutionize the onshore US natural gas business, we look forward to doing the same for the US oil business, but we will do so receiving $10 to $15 per production unit versus the $4 to $5 per production unit we're receiving for our gas right now.

This brighter more profitable tomorrow cannot arrive soon enough for me.

This completes my commentary.

I'll now turn the call over to Marc.

Thanks, Aubrey.

Good morning, everyone.

Very solid and profitable quarter in our opinion, also one that saw a lot of attractive financing transactions.

Notably, we completed in May, the issuance of $2.6 billion of cumulative convertible preferred stock including approximately $1.5 billion that was sold to prominent Asian investors for the first time ever.

We used the proceeds to redeem $1.3 billion of senior notes in June and additional $0.6 billion of notes that were redeemed in July after the quarter closed.

The remaining preferred proceeds were used to reduce our bank debt so with the issuance of $2.6 billion of base amount of preferred, we reduced our debt by a similar amount.

In June, we closed on our VPP number seven or volumetric production payment for $322 million of proceeds or about $8.75 per mcf equivalent for around 38 bcf of sales.

Obviously, monetization at a rate well above what our company's valued at in total.

We also concluded two other assets sales that we had spoke about earlier in the year for $330 million in proceeds, one in the Permian Basin and one in the Appalachian area.

So, a busy quarter that resulted in end of quarter cash, and undrawn credit facilities of $2.8 billion.

As Aubrey noted, our hedging gains over the last many years, particularly powerful in quarter two, giving us an additional realized cash revenues of $2.26 per mcf equivalent.

Subsequent to quarter end, we were successful in launching our Chesapeake Midstream Partners IPO.

New York stock exchange symbol CHKM.

We priced 21.25 million primary units at $21 per unit.

The high end of our expected range.

Today, those units are trading for about $23, giving CHKM an enterprise value of around $3.2 billion or $1.34 billion to Chesapeake's 41.45% interest.

There is nearly $1 billion of cash and unused credit facilities to accomplish CHK drop-down acquisitions or other acquisitions inside of CHKM, something we intend to pursue in the near future.

As a sidebar to that, our remaining Midstream assets that were not put in CHKM have nearly the identical production profile as the assets that we've transferred to date.

You may have also noticed that last night we announced a cash tender offer for an additional aggregate $1.5 billion of senior notes of various maturities.

We intend to finance these with notes of longer maturities and the tender is conditioned on our successfully placing these notes in the near future.

I would end by saying our finding costs, the power of our joint ventures and substantial remaining drilling carries along with the other ventures we are pursuing particularly in the Eagle Ford and in the Midstream lead us to be in excellent position to continue with outsized returns on our invested capital.

Moderator, I'd turn it to questions please.

Certainly.

(Operator Instructions)

We'll take our first question from David Kistler with Simmons and Company

Good morning guys.

Good morning, Dave.

Real quickly, would the increase of liquids as we look for--you guys going to be breaking out NGLs and oils specifically?

I don't plan to David, at this point.

What can you count on going forward from here is we anticipate about two-thirds of our growth will be in oil and about one-third in liquids.

I believe today our production profile is about half and half as we have increased our production more aggressively and our natural gas liquids plays in the last couple of years than in our oil plays.

Okay.

Just kind of building off that a little bit.

A lot of folks are, increasing their oil and NGLs production.

Wanted to get your thoughts on where you might be seeing bottlenecks or potential bottlenecks on the NGL side of things and how you guys are thinking about managing that risk?

We manage it a number of ways in ways, similar to the way we managed our gas take away risks when we were in early stages of evaluating positions in the Marcellus and Haynesville and other gas plays, Barnett and Fayetteville of course.

We have a big midstream team and a big team underneath Marc and Nick who work on this kinds of initiatives and we are in constant communication with gas processors and we believe that all the take away capacity we need for our liquids production will be in place at the right time.

I'll say if Marc wants to augment that at all.

I would just say, you ask where those bottlenecks occur and really the three plays that we're in that are most concentrated in liquids are the Granite and Colony Washes, the Southwest Victory area in Marcellus and ultimately in the Eagle Ford.

Under our marketing arrangements and through mid-stream, Mike Stice, we've made commitments to Mark West in the new plants their building up in that area.

And we have additional capacity that we're negotiating in both washes and at Eagle Ford.

That's helpful.

Then just as long as we're kind of on risk mitigation, looking a little bit at the hedging side of things, looks you guys put on some pretty nice gas hedges.

Curious if they were set up similar to things you've done in the past where you'd forward sole call options in the out-years and if that is the case, can you just give us a little bit of color on how much production you're willing to commit going forward to be able to augment that swap price.

David, I don't have the exact numbers in front of me.

The hedges we put on are both of the nature where we've sold additional calls and collars and then some of them are straight swaps.

So, the swaps and all of the collar arrangements and the calls are going to be set forward in the 10Q that will be filed on the ninth.

I appreciate the extra color, guys.

Thanks so much.

Next we'll go to David Heikkinen with Tudor, Pickering, Holt

Good morning, guys.

Thanks for the time.

Thinking about the drilling carries.

Why wouldn't you renegotiate the timing of one of your drilling carries until gas prices improved?

I assume, David, this is Marc that you mean to defer those?

Exactly, push them out.

Is there not an ability to do that?

And why wouldn't you do that?

It requires the consenting partner, and I think different people have different views about future gas prices.

Plus, these partners have already put a lot of capital into these plays today.

They are very PV driven, and so we do not sense any interest from Statoil or in Total in slowing down.

In fact, they encourage us to stay active and put their capital to work.

A lot of these carries are in areas remaining in the Marcellus and Barnett where we're still holding acreage by drilling new wells.

So, there's that interplay that goes into that as well.

Of course, if we're receiving the carry, even though our gas prices are low right now, our finding costs are so improved that low cost doesn't really change our return very much at all.

Just remind you in those two plays after carries, our finding costs are less than $0.30 an mcf.

So, it's pretty tough for there to be a gas price not attractive to us.

Just curious.

I would like to say, once the carriers are used, and once the carry is HBP, then we move into a much different mode.

We've already said $6 is our bogey.

So, we look forward to a time a year from now, for example in the Haynesville when most of our acreage will be HBP and if we need to, we can begin gearing down in the Fayetteville.

I remind you our drilling has gone down by half, 17 rigs to 8 rigs.

Guess we've reached the point where we can comfortably glide into finished HBP position.

So, that will occur next in the Barnett after the Haynesville and next after that in the Marcellus.

So, I said it many times before, but a large portion of the industry's drilling right now for gas anyway is involuntary as it works HBP leasehold.

Most of those leasehold positions were established in '06, '07, and '08 and the time to finish HBPing that acreage will be this year and next year and after that.

I think the industry moves into a much different drilling phase.

Just kind of continuing.

From your partner's perspective as you reduced activity below $6 gas price obviously impacts the present value of the total project.

Are they willing to see production decline?

Is that built into the expectation for those projects, the activity decline below $6?

What's your partner's opinion of that?

I really can't speak for our partners.

At this point, we've been asked to spend the carry dollars that have been given us we're required to do so in yearly tranches, and these guys take the long view, and so I think that's, I'm sure that the present course that we're on is likely the one that will be continued.

But now that both those companies have established US operations and have US investor relations folks I encourage you to reach out to them for the final answer to those questions.

What's your thought on reducing activity and allowing production to decline in any of those areas?

The Fayetteville looks relatively stable at half the rig count.

Do you think you'll stabilize production or do you actually think you'll see any decline?

On the Fayetteville, I think it grows a little bit more but at eight rigs over the long period of time it stays about the same.

We're very comfortable with that.

In fact, if gas prices were to go lower from here and our drilling is completely discretionary in the Fayetteville, we're comfortable reducing it further.

We've reduced our drilling everywhere else in the company except for Deep Springer play in western Oklahoma where we are close to another carry arrangement there.

So, essentially, 100% of our drilling in shale play or in gas play today is in an area where there's a substantial carry, up to 75% of our costs, or is in an area like the Fayetteville where we've already cut drilling dramatically or is in the Haynesville where we are a year away from being able to start gliding down.

Of course, there's conversations in the Haynesville will need to take place with some regard to Plains' views on the matter as well.

Then can you just, shifting gears, discuss your plans and kind of structure your thoughts around the Marcellus either equity infusion or how that deal will actually be structured?

I probably don't have a whole lot of detail for you right now.

But, we are engaged with a wide variety of people - some American some international.

I'll see if Marc wants to provide any further color on it.

I think early on, it really hasn't changed from when we first announced it.

We said we would consider anything from the sale of additional minority working interest to an equity infusion by some other type of entity, and we're still negotiating with people on every one of those type of deals.

Okay.

And timing for that is back after this year?

Is that in the monetization plans for this year or next year?

I think we've got that in the beginning of Q4.

I think we think we can get it done in the second half of this year, David.

That's hopeful.

Thanks guys

Okay, David.

Thank you.

Next we'll go to Bob Morris with Citigroup.

Good morning, Aubrey and Marc.

Hi, Bob.

Question on the 18% production growth guidance for next year.

How might that be impacted or is it already incorporated in the anticipated Eagle Ford joint venture?

In other words, on the one hand, give a 25% of the projected production but you're going to get more of other people's money to spend to drill.

I would think that would probably more than offset what you give up in the projected production in the joint venture.

We are far enough down the road in our discussions that it is baked into our production forecast for 2010 and 2011.

Okay.

Good.

Second question.

I know you mentioned would you spend less on leasehold acreage in the second half of the year.

Can you give us some order of magnitude relative to the $2.4 billion you spent on the first half of the year on acreage?

In terms of where it was?

No, you said you'll spend less so obviously you'll spend less than $2.4 billion.

So, are you anticipating spending $1 billion or what is the range you expect to spend in the second half of the year on these leasehold acquisitions.

I'd rather talk about it in terms of net expenditure, and that's going to be dependent on where we end up structuring a JV or two.

So, I'm not willing to communicate to those potential partners that are out there that could back into the number we're looking for.

So, we'll say at this point, I suspect it will be substantially less than what we spent in first half especially on a net basis.

So, for the full year, you still expect monetizations or divestitures to essentially match your leasehold acquisitions--outlays?

I doubt we'll get--I doubt it will match.

Well, when you conclude all monetizations--absolutely, in fact, we'll--we should end up with excess cash this year--when you include monetizations.

If you include just leasehold sales, we will not cover all of the CapEx that's been expended to date, but that's because we're spending money on several plays that we won't be able to JV until 2011.

I kind of look at these things over a full year cycle.

We bought our first lease in the Eagle Ford in November of 2008 and we're at 550,000 acres today less than a year later.

And, I think, within a year of having bought that first lease that we will have executed the transaction and recovered a good bit of our leasehold expenditures.

I think that's a model that will work well for us going forward, so it won't always fit into the handy definition of a year.

But also, I really do believe this will end up being a lot like the gas plays where they come at you fast and heavy and over the course of--it took that he years for gas plays to emerge once the industry found out this kind rock will work.

And now the industry has found out a different kind of rock will work to move oil and NGL molecules through and the pace of which life moves today, I think that three-year time frame is probably going to be collapsed down to a year to a year and half.

Again, you either play or you don't play and we've chosen to play and then, to de-risk it by bringing in partners.

So, just being apples to apples, I was just referencing your comment last quarter that asset sales should match leasehold acquisitions by year end.

But now, you're thinking that asset sales will come up short of matching leasehold acquisitions?

No I didn't say that.

I said asset sales will exceed leasehold investments if you are looking at asset sales defined as asset sales strictly from joint ventures then we'll come up short this year, but if you look at it over the course of the first half of '11, you will get close to matching that.

Finally, just one quick question.

You mentioned the sale of beginning the sale minority interest in some of these liquids or oil places.

What do you think those proceeds will end up totally, roughly?

Don't know.

It's impossible to know.

These are big plays.

They all end up being worth about the same at the end of the day, and you know those net acre numbers as well as I do.

So, if you look at our Niobrara position, we have 675,000 acres.

You can work some math there if you'd like.

And there are other plays that we have where we have substantial leasehold positions.

Not all of which are suitable to bringing in a partner.

For example, in our western Oklahoma, Cleveland, Tonkawa, Mississippi, and plays.

I doubt seriously we bring in a partner because the plays are so kind of integrated with our Anadarko Basin gas operations.

I think we'll be looking at doing JVs on discrete plays.

The Eagle Ford is easy to put in a box, the Niobrara is easy to put in a box.

And there are a couple of other plays that will fit that definition as well.

Okay, that's helpful.

Thanks, Aubrey.

Thank you.

Next, we have Brian Singer with Goldman Sachs.

Good morning.

Good morning, Brian.

I wanted to follow up on a couple earlier questions.

First, I think you mentioned in response to an earlier question that you're at about half NGLs and oil now going to two-thirds oil, one-thirds liquids.

I was wondering if you could give a little more color on the timing of when you see that happening in the context of widening out the guidance for differentials for oil relative to WTI or liquids drilled through WTI in both 2010 and 2011?

Brian, to be perfectly clear, I hope what I said was our existing production base is about 50/50 and our additions going forward are going to be two-thirds to a third so it'll take us several years if not the mid-part of the decade to get to a point where we're fully two-thirds, one-third.

So that's the goal but some of these plays are relatively immature.

It's not always knowable yet today exactly what that exact percentage would be.

But, I think if you use 50-50 today, two-thirds, one-third oil versus NGLs over time, we would expect that the differentials that we've recently widened to account for NGLs will hopefully narrow over time as more of our liquids production comes in the form of oil.

Do you think that you and others in the industry need to begin a process similar to what you're doing with natural gas to try and encourage demand for NGLs or additional sources of export or your comments that did the rise in production will not impact liquids markets applicable to NGLs as well as crude?

Well, we're certainly mindful of that.

And we're single-handedly trying to restore high profitability to the plastics and chemicals industry as well as natural gas this week.

We've driven gas prices lower and provided more abundant liquids.

The difference between liquids and natural gas is that virtually all liquids can be exported.

So, NGLs do have a floor under them, I think, associated with worldwide NGL market.

Of course, and US gas world we haven't yet achieved that.

So, I think there is much less risk of an NGL price collapse in the US but having said that, we're certainly taking our message to consumers of NGLs that we're going to be increasing supply for a long time to come and they should make appropriate investments to be able to handle our new NGL production.

Great.

Thanks.

If I could ask one more.

In your operational updates, you talked about three wells in three different counties in Eagle Ford.

Can you just talk about what those wells say with regard to prospectivity countywide or is it too early to deem a much larger percentage of your acreage perspective at this point?

I don't think it's too early at all.

These wells are very prolific as you can see from our press release and we think that they along with other activity seriously de-risk the acreage that we've established across Dimmitt, LaSalle, Rio, zavalla counties, the northern portion of the two and the southern portion of the other two form the foundation of our holdings, and we believe that we've tested basically all four corners of our leasehold and are quite happy with the results that we're getting to date and really accelerating our activities, Steve, we're at seven rigs?

And eight this month.

The eighth one comes later this month.

All systems are go there.

It's really nice to drill 900 barrel a day oil wells.

That's $80 a barrel.

That's quite a change from drilling the 5 million or 10 million a day at $4 mcf.

Thank you.

Okay.

Thank you.

Next we have Joe Allman with JPMorgan.

Thank you, good morning, everybody.

Hey, Joe.

How are you?

Good, thanks.

Aubrey, in terms of the strategy, what's the ultimate strategy?

Is it to be in terms of production and reserves--roughly 50/50 oil-gas.

And how would that strategy, whatever it is, reflect your long-term view of the oil and gas markets?

Joe, thanks.

I think given where we're starting from, our size, and given that we started the year at 90% gas and 10% oil, I think it's probably unlikely that we ever get to 50/50 oil and gas from a volume reserves perspective, but I do think we can get to a 50/50 value proposition, and we can get there, of course, pretty quickly.

We hope certainly before the mid-part of the decade.

That's predicated on basically, the continuation of what we have, which is a strong oil market that I suspect gets stronger.

You have to look no further than what's happening in China again.

You go back five years and look at what their oil production was--oil consumption was.

I think very few people would've guessed that five years later they would be at 9 million barrels a day.

No one seems to believe that in five more years, China could be at 15 million barrels a day.

But that's, I think, unavoidable.

When you look at that and you lack at when's happening in other Asian countries and you look at oil consumption stabilizing in the OECD countries, then I don't see how you get away from an analysis that says oil prices are going to be strong basically for a long, long time until this world figures out that you can substitute something cheaper for that oil, which is natural gas.

That's a very obvious fact that completely escapes apparently most American policymakers, but at some point, we're going to have to revisit that as we will be unable, in my view, to compete with China for oil supplies in the years ahead.

So, I still feel that oil will be strong.

Gas will be kind of ranged down here for another year or two until the industry is able to reduce its drilling and have more of its drilling become discretionary rather than non-discretionary and for more coal-fired power to get converted to natural gas.

And, I think hopefully some day we'll see in-roads on the transportation side.

I do feel the coal switching floor has come up over the last year or so, and we're not talking about $3 gas prices like we were last year.

Today, we're talking about a switching price above four and hopefully next year it will be a little higher as well.

So, we're just doing what I think anybody would do.

You can go out and spend money and find a unit you can sell for $4 or you can go out and spend money and find a unit you can sell for $14.

Our problem before is we just didn't think we could find any of the $14 units.

Now, we know we can find them and as quickly as possible we're making that acceleration and transition over from $4 units to $14 units.

When you ask about the ultimate goal, the ultimate goal is to make a bunch more money doing what we're doing.

And the way to do that is to replace $4 with $14 units.

Okay, that's helpful and then just different topic.

Your JV with Statoil and your search for international gas shale, could you give us an update of what you've done so far and how that's worked out in the different places?

Does your transition here affect that such that you might be searching for unconventional oil?

Good question, Joe.

I don't want to say anything that's out of school.

So, I will probably the direct the question more towards Statoil, but the only public announcement we've made is that we're looking at a leasehold block in South Africa.

There are many reasons to look at that, but for us, the primary one is to develop a relationship with Sasil and to maybe work with StatOil and Sasil and hopefully achieve the holy grail in the gas business, which would be to turn natural gas into a liquid transportation fuel.

I spent a lot of my time the last three years trying to get the US transportation switched over from a liquid-based system to a gas-based system and maybe it would be a lot easier to take the fuel and transition it from gas to liquid.

And force that conversion rather than try and the conversion of large segments of the US transportation system from liquid to gas.

That's helpful.

And then, In terms of buying additional acreage, what's the advantage of actually buying a bunch of acreage and then flipping a minority part of it versus just buying less acreage from the beginning?

Well in the one instance you can go buy acreage for x.

In the second scenario or go acreage for x and that's what you own, or you can go buy acreage for x and sell it for many many times x and your x becomes zero.

And I'm always attracted to owning less of something for essentially zero cost than I am owning more of something and having full cost.

Also you spread your acreage around you're able to cover your bases when you only have a certain amount of money.

You have to choose what part of a play you're going to play in and when you are able to go buy bigger acreage quads and then diversify your working interests by selling down, you can mitigate your geological risks that way.

And then, just two quick ones.

The $6 gas threshold using for ramping up gas drilling what is that price?

Is that a 12-month strip?

That's probably the best way to think about it.

It's, for us, it's almost more of a psychological level, but I don't think if we saw prompt gas go to $6 and the curve was $4 that would cause much of a change in our behavior.

But, if you saw the out-year curves get out above six and, I think including something close to the prompt 12 months that's the signal for us that the market has cured itself enough that we could get out there and do more gas drilling.

Okay, great and then, Marc, in terms of capitalized interest, what's the guidance for capitalized interest going forward and what's the best way to model that?

And how much discretion do you have on that number on a quarterly basis?

Well, we have no discretion on it on a quarterly or any other periodic basis because everything is dictated by GAAP and with respect to how it's calculated it's simply the amount of unevaluated acreage taken at our capital rate.

And then, that's what it is on a quarterly basis.

Guidance, I think for that, of course it shows up in our 10Q and 10K all of the time.

For Q2, on our natural gas and oil properties we had capitalized interest of $171 million.

Then with G&G, which is a separate pool and some of our construction which is very minor on Midstream assets.

The total was $178.8 million for the quarter.

Most of the folks that follow us particularly on the debt side, of course, extract that back out.

We always show it clearly in our filings with the SEC and put it into interest expense for a calculated basis or an adjusted basis.

So, anyway, I don't know how else to say it.

It was $161 million last quarter and it's $178 million and if you go back a year ago, it's basically not too much different, $152 million in the second quarter of 2009.

So, does that get to your question, Joe?

Yes.

And then, guidance coming forward--

It's totally a function of what our unevaluated acreage is from a GAAP standpoint.

So, to the extent we transfer, unevaluated acreage into evaluated then we quit capitalizing interest on it.

And to the extent we sell unevaluated acreage in a joint venture or another sale, then the proceeds for that reduce unevaluated acreage, and to the extent, we buy into a new play and that acreage is unevaluated at the time that we buy it then that adds to the amount.

So, I'd have to look and be knowledgeable about all of the future joint ventures we were going to do and how much of it was unevaluated acreage and where we were going to buy acreage and how fast we were going to convert our drilling program unevaluated into evaluated before I could begin to know how to project what the interest might be that's capitalized.

Okay.

All right.

Very helpful.

Thank you.

Thanks Joe.

We'll go next to Dan McSpirit from BMO Capital markets

Gentlemen, good morning and thank you for taking my questions.

Good morning, Dan.

Thank you.

Regarding your very pronounced strategy of selling minority interests to fund drilling activities, how do you view that as a lesser form of dilution maybe for selling equity to fund those same activities?

It's clearly a lesser form in the sense that it's no dilution of equity, of course.

I think our view is that you can go and buy new lease plays but once you sold equity, of course, you can't recapture that.

So, we take a very stingy view to issuing equity and the fact that we did so this year was a special situation to a group of special investors and it accomplished a pretty substantial one quarter de-leveraging and we think it was the absolute right thing to do.

Going forward, we just don't see any need for that further and we'll continue to sell down in new plays but also we'll continue to monetize some gas assets.

One of the ways to get to a more balanced revenue model if not only to add oil but to subtract gas, also.

I'll let Marc carry it from there.

Yes, Dan.

I think about dilution a little bit the same way Aubrey does.

Obviously, equity is pure dilution, but to calculate what your dilution is you have to look and see how the acreage is being valued inside of our CHK common stock price.

And, I think the work that Jeff and John and others have done in developing the net asset value slides that we show frequently indicates that almost no value for unevaluated acreage is being ascribed and the stock if you look at our proved reserves and the investments that we have in CHKM and CHKD, our development part of that.

And the other assets we have and you just look at what we trade at then there's really not much implied value for all of the unevaluated acreage.

And, clearly, like we've done in the last two years to sell those for evaluation of $10 billion, you just look at it and say that's much less dilutive from a value proposition, not just from a pure accounting standpoint.

Got it.

Thank you.

And then, one more if I could.

You lay out and repeat your strategy like no other independent in the business from leasing to attracting partners to now getting to an investment grade status, yet the equity capital markets fail to move on this strategy.

What is it, do you think, the equity capital markets investors either don't get or don't like about that strategy or do you think it just simply takes time to play out?

I think probably it takes time to play out and we're still a 90% gas company and everybody hates gas prices and hates gas prospects in the future.

So, I think it's difficult for us to escape the gravitational pull of oil.

I'm sorry, the gravitational pull of low gas prices until we prove that the transition of oil will work.

So, I just encourage people to look at it this way.

By the end of 2012 to the latest 2013, the company's going to have 24 tcfe, same share account and less debt.

So, today, our enterprise value is $29 billion.

So, just tell me if in two and a half years if 24 tcf gas is worth $29 billion, I doubt it.

And I think it's worth more like $50 billion to $60 billion and if your debts lower or the same even.

It's your count.

It's only increased by employee stock grants then it doesn't take a very smart person to do the math on dividing $50 billion by our number of shares outstanding and see where you end up in 2.5 years.

And, it's completely mechanical.

This does not require a new discovery.

It doesn't require a new slug of capital.

It doesn't require anything other than me and our 9,000 colleagues show up for work every day and continue to deliver this reserve growth of 2.5 of 3 tcf a year.

We create every year a new company inside our own company that the market would capitalize at $8 billion to $10 billion.

And you can ignore that for a while, but I don't think it gets ignored over the long term.

Marc, anything else you want?

No, I think that does it.

Very good.

Thank you again.

Next we'll go to Biju Perincheril of Jefferies & Company.

Thanks, good morning.

A quick question, obviously, you to look at future monitization decisions.

Can you talk about what role VPPs will continue to play.

Is there some sort of limit to how much you can do considering that I've seen the banks look at those transactions as debt?

We like VPPs a lot for a number of reasons.

Tax free.

You get to keep the tail and you get to keep the upside on drilling, but I'll let Marc address the liquidity in that market and other thoughts he has on VPPs.

Our plan is to continue to have one or two VPPs per year.

We will size them and assign a tenor to them to maximize the oil-gas relationship and maximize the sweet part of the market for what we see the economic demand.

Right now we're seeing as much interest as we ever have, and I think the reason for that is at least partly the nature of the banks being heavy on capital and light on investment opportunities and remember while the rating agencies might consider part of these to be debt for GAAP purposes, the sale, the reserves are taken off.

We have no dollar obligation going back to '06 when we did our first VPP, there's never been one month in any VPP where the production wasn't satisfied from the curve that we sold to the investor.

Today, the capital rate on those is probably close to what our bonds trade at.

I would think a five year VPP probably could come inside 7.5% pretty easily and think about what the investor's getting for 7.5% than a 50 bit two-year treasury market.

They're getting an investment grade product that is completely bankruptcy proof.

They own the assets.

It's fully hedged.

So that becomes a secured hard asset loan for them, which is really an investment obviously because they don't book it as a loan.

So, there's a lot of demand for that product, and we'll continue to work with the big financial institutions that we've sold to in the past and I know from Nick Dell'Osso who specializes that in our team and discussions we've had with those players that they have a lot of appetite right now.

Okay.

The bank in your lending group - Do they generally look at VPP obligations as debt or not?

I think the banks in our lending group, there's several lending groups in our big revolving credit facility, I think there's 34, 35 players, something like that.

I think they look at them as asset sales.

I don't know of any.

Really, it's only the rating agencies, which you find yourself in this perverse scenario where the more you receive in proceeds from a VPP sales, the worse the rating agencies industries think it is.

So, if you go sell a hundred bcf of reserves and you receive $500 million.

If you could somehow get $800 million for it, they think that's worse or if you sold it for $100 million, they would say that's better.

So, you can't compete with that logic.

Got it.

That's very helpful.

And we'll go next to Eve Segal with Credit Suisse.

Have you given guidance to the CapEx bend on the mid-stream over the next several years what might be a good run rate and the second part of that question would be how do you view the MLP in terms of also in respect to future monetizations and helping to finance the growth of the overall entity?

Sure.

I don't think we've given specific guidance on the MLP out.

Several are on the mid-stream out several years.

Currently and of course all of this depends on who we do joint ventures with and how much of the midstream that joint venture partner takes on.

Generally, we've reason spending on the $500 million to $700 million outside of the CHKM the new MLP publicly traded entity.

I think that's probably not going to be more than that as we take on additional joint ventures and as we do dropdown sales similar to the one that western and Anadarko announced just this last week.

Where I think we'll be from guidance on drop-downs is I think we'll be in a position to do a couple of them per year at anywhere from $250 million to $500 million each in size and that they'll either be part of one of our systems like Haynesville or Fayetteville or other opportunities and not only will we receive capital in that scenario, but then that will, in turn, reduce the capital spend for the further development of those systems that are transferred.

And It's completely consistent with our partner GIP and what we have told the market with respect to our sponsorship of CHKM that we want to do drop-downs in a very favorable setting for the partnership.

We own 41.25% of it.

We don't intend to sell any of the units.

So, this is going to be another form of capital that will benefit those investors in that partnership on an accretive basis.

And it will provide us with the capital and capital relief from further expenditures as we go forward.

Okay, thanks.

For what it's worth, I suggest that folks probably when they think about Chesapeake probably aren't calculating or putting in the value of the MLP into your enterprise value as well?

I would guess that's absolutely right.

It's on a long grocery list of things put in the basket.

All right.

All right.

I think that's it for today.

I appreciate everybody's participation.

If you have additional calls or questions, please call Jeff or John.

Thank you very much.

Bye-bye.

That does conclude today's conference call.

Thank you for your participation.