Chesapeake Energy Corp (CHK) 2010 Q3 法說會逐字稿

Good day and welcome to the Chesapeake Energy 2010 third quarter operational update and earnings results conference call.

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, everyone, and thank you for joining our conference call this morning.

With me today is Aubrey McClendon, our CEO; Steve Dixon, our COO; Nick Dell'Osso, our CFO; and John Kilgallon, our Manager for Investor Relations and Research.

Our prepared comments this morning should be about 10 or 12 minutes and then we'll open up it for Q&A.

Aubrey?

Good morning, thank you, Jeff.

We hope you've had time to review yesterday's operational and financial release and we're pleased with our results.

On the operational side our daily production for the third quarter was very strong at 3.0 Bcfe, up 23% year-over-year, and 9% sequentially.

An added highlight is our rapidly growing liquids production, which was up 50% year-over-year.

We are currently producing more than 55,000 barrels of liquids per day and have our sights set on exceeding 150,000 barrels per day by year-end 2012, and 250,000 barrels per day by year-end 2015.

We think that will make us a top-five producer of liquids in the US by the end of 2015.

Next I would like to highlight our exceptionally low finding cost during the first nine months of the year.

We added on a gross basis 4.0 Tcfe of proved reserves at a drilling and completion cost of only $0.97 for Mcfe.

Basically, we are building a top 10 US natural gas producer every year inside our Company, an incredible achievement, we believe.

And not only are we good at finding gas cheaply at the $0.97 per Mcfe level, we are also good at selling it for much more.

To date this year we have received well north of $3 per Mcfe when we've sold properties through VPPs.

It's always good to buy low and sell high and that's what we try to do around here, whether it's leasehold or proved reserves.

Our latest JV, the CNOOC deal in the Eagle Ford is expected to close in the near future, and our data room is open for the Niobrara Shale JV, in which own 800,000 net acres evenly split between the Powder River and DJ Basins.

We expect to also sell a 33% working interest in this play and what we believe will be an attractive price, both to us and to our future partner.

We believe the recoverable resource under our 800,000 net acres is an unrisked approximate 4.6 billion barrels of oil, representing potentially $400 billion of future undiscounted revenue.

This is a reminder that the size of the play that we have chased and have captured is quite remarkable.

Some of you may be wondering what is next in our liquids plays.

I can tell you that we have several new plays under evaluation or development, including an almost 100,000-acre new position in the Williston basin and one million acre position in another play that will probably be ready for disclosure in a JV data room in the first half of 2011.

We believe there will be worldwide interest in this next big play of ours.

One other thing, on the Anschutz deal we'll be selling about 25% of the assets we acquired that aren't a great fit for us.

We'll do that as soon as we can after we close, and then with what is left we'll combine it with some other acreage we have and do a JV in the first half of 2011.

I noticed several analysts were confused on this point so I thought we should clear it up.

Finally I'd like to point out that our realized cash hedging gains since 2001 now reach almost $6 billion.

In addition we have hedged approximately 80% of our anticipated gas production in the first half of 2011 with swaps and an average strike price of $6.35 per Mcf, and approximately 43% in the second half of 2011 with swaps at an average strike price of $6.61 per Mcf.

If today's 2011 strip holds true, we should record another $1.5 billion in hedging gains in 2011.

That $1.5 billion, along with an expected $2 billion in drilling carries in 2011, will provide Chesapeake with $3.5 billion in cash from two important competitive advantages in what most expect will be a tough industry environment in 2011.

We also expect to generate more than $1.5 billion in cash and $1.5 billion in additional drilling carries from two new JVs that we should close in 2011.

So that's a total of $6.5 billion in competitive advantages before we even consider the expected $3.5 billion in operating cash flow that we should generate in 2011 without any hedges.

We are a resourceful management team, we relish tough operating environments, we take pride in what we have built and we look forward to additional opportunities that may come our way in 2011.

This completes my commentary and I'll now turn the call over to Nick Dell'Osso, our CFO.

Thanks, Aubrey.

Good morning.

I'm pleased to be joining you on the conference call as Chesapeake's new CFO.

As Aubrey discussed, and I'm sure you've seen in our earnings release, Q3 was another successful quarter for CHK.

A couple of quick items I will point out in addition to Aubrey's comments, our continued decrease in LOE per Mcfe, which came in this quarter at $0.95 per Mcfe, as well as our finding costs at $0.97 per Mcfe.

If you'd like to consider what it takes Chesapeake to find oil and gas on an organic basis without the effect of our drilling carries, it comes to $1.16 per Mcfe.

We achieved these low costs through four major advantages.

First, we have a top one or two leasehold position in every important unconventional play in the US.

Second, we have drilled more horizontal wells than anyone else in the world.

Third we are vertically integrated through most of our key service needs, and fourth we have a size and scale that lends itself to great efficiency in our drilling and production processes.

The third quarter was also a very productive period for us on the financing front, as we completed the balance sheet restructuring made possible by our preferred equity offering, which closed in June of this year.

The net effect of this series of transactions is to have added $2.6 billion of equity to our balance sheet, have reduced long-term debt by $1.4 billion and retired or redeemed all bonds that were issued under our older, more restricted form of indenture.

Just to remind you, this was the first step in our ongoing, multi-year strategy of balance sheet improvement.

Additionally I would like to point out the closing of our eighth volumetric production payment transaction on September 30 for $1.15 billion in proceeds.

This represents the sale of 390 Bcf of gas over five years from our Barnett Shale production, monetized at the strip and adjusted for transportation costs.

This brings our total VPP sales to $4.7 billion over the past three years, at a realized price of $4.50 per Mcfe.

This compares favorably to the value of the reserves if left in the ground or sold at current natural gas prices, plus we've kept the upside, kept the tail and paid no taxes on the proceeds.

Furthermore, these sales of primarily gas assets have helped us fund our aggressive and timely shift to more liquids-focused portfolio.

Looking forward, we are excited about continuing to build one of the industry's leading unconventional liquids plays, and I would like to highlight our guidance attached to last night's earnings release in which have estimated 80% and 60% growth in liquids in 2011 and 2012, respectively.

This is an increase to our liquids production guidance for 2012, made possible by gaining clarity on the development plan associated with our pending transaction with CNOOC and our confidence in achieving an attractive JV for our Niobrara acreage.

Additionally, we believe we'll have a JV in the first half of 2011 on a new very large liquids prospect that we have not yet publicly identified.

We have also begun the renewal process for our $3.5 billion revolving credit facility and will be looking to wrap that up in the next few weeks.

The existing facility was set to mature in November of 2012, so we chose to enter the market now and have the new facility, which will again have a five-year maturity, sewn up well in advance of the existing facility becoming a current obligation on our balance sheet.

The reception thus far has been very strong.

We expect the deal will be slightly larger than the current facility to reflect the Company's increased scale of operations since 2007, and we'll have improved commercial terms for CHK's benefit, but generally it will be a very similar facility to what we have in place today.

Finally, as Aubrey discussed, I would like to reiterate that our hedging program has locked in prices for 2011 that average approximately $2.15 over the current strip on 60% of our projected gas production for the year and 80% of our projected gas production for the first half of 2011.

By the end of 2011, our cash gain since initiating our hedging program since 2001, will exceed $7.5 billion.

I personally look forward in taking a more active role at Chesapeake in continuing to lead the industry in this important area of risk mitigation and value creation.

Operator, we're now ready for questions.

Thank you.

At this time we'll start the question-and-answer session.

(Operator Instructions)

Your first question comes from David Tameron with Wells Fargo.

Hi, good morning.

Aubrey, you mentioned 100,000 acres in the Bakken, is that -- I'll just get to it, there is speculation that you guys bout Anschutz 's property up in the Bakken, is that -- can you tell us where you got that acreage?

I cannot tell you where we got it, I can but I won't, but we did not get it from Anschutz.

We are not the buyer of the Anschutz Rockies package.

Okay, I just thought I would get that out there.

Second question.

If I think about your position in the DJ and the Powder, can you give me a split of the federal acreage versus state acreage in those two areas?

I don't think I have that kind of detail with me right now, but I would say it's probably less than a third, probably more than a quarter, but that's a little bit of a guess, David.

Okay.

And where I was going with it is I know there has been an issue with chargeability from time to time with different offerings.

We're mindful of the chargeability issues and know where we are and keep in mind also that you can relieve yourself of chargeability issues when you form federal units, and our goal across the -- especially the Powder River, is to get virtually all of our leasehold there in a federal unit, which also helps us quite a bit in terms of getting things HBP much more easily than a traditional play.

Okay.

One last question.

The 2012 production uptick in oil, I assume you talked about CNOOC and the acceleration there, then I assume Bakken is a part of that as well?

Is that a right way to look at it?

Actually we haven't modeled any production from -- and you said the -- we would refer to it as really the whole Williston Basin, but we are not modeling any production there.

The 2012 uptick is simply now greater confidence in what we're going to see out of the Eagle Ford that we have a partner.

I think we'll be able to obtain a partner in the Niobrara, which will help us uptick activity there.

So I think those two issues are the ones that gave us the confidence that our 2012 production would be considerably higher than what we had previously modeled for.

Okay.

I'll let somebody else chase the comment about the Williston rev and the Bakken, see if there is anything there.

I'll jump off.

Thanks, Aubrey.

Okay.

Your next question comes from the Jeff Robertson with Barclays Capital.

Aubrey, on the acreage you acquired in the Appalachian Basin, you can talk about the 25% you want to sell and where that's located and also how does the rest of it fit into the Appalachian Basin that you all had talked about finding a partner for?

Yes.

I would just say, Jeff, that approximately 25% of what we're buying is not a great fit for us, and will be a better fit for probably a handful of other companies in which the acreage is embedded with.

And with regard to the remaining acreage, it's a really good fit for what we have and we believe that we'll be able to probably do a JV on that idea sometime in the first half of 2011.

That transaction would be in addition to the one you all have outlined before, about finding a partner for your Chesapeake Appalachia?

Well we already have a partner, of course, in our Marcellus play.

If you're referring to the idea that we've talked about in the past about bringing in an equity partner in our Marcellus play, we are still pursuing that.

Statoil has expressed an interest in a little more ownership in our asset as well, but that's really an optional part of our plan.

I have no idea if either of those conversations will result in a favorable outcome.

So this would be a different idea than either of those.

Okay.

Thank you.

Your next question comes from Scott Hanold from RBC.

Good morning.

Good morning.

I guess I'll press the Williston a little bit here.

You all didn't say what you paid for the 100,000 acres, I know you disclosed the price and the Anschutz stuff.

Can give us color on that?

And maybe some indication, are you looking at Montana, North Dakota, or both?

Scott, it's still pretty early and that's a basin that historically we have not done well in.

We've made a run at Black Gold in 2005 and Headington in 2008.

Both of those deals would have given us a really strong position in the Williston today, and we failed in both of those opportunities.

So we've been poking around and we saw something that we liked and we acquired it.

It does not have any production on it, it's just acreage.

And it's an idea that we have that is a little early to talk about in any more detail.

I suspect that it probably doesn't get to a size of needing a joint venture partner, but we'll see.

But I can confirm it's in the Williston Basin and it will be an oil play for us.

Okay.

Is there industry -- a lot of industry activity around you?

Obviously it's almost 160 rigs in the basin, it's hard to believe there is a lot of acreage without production on it?

Yes, I mean we do not buy fringe stuff, that's not really our style.

We try to buy core acreage.

But occasionally we have a different idea than some folks about how the world works and so we'll see how this plays out.

Okay.

Well when do you start getting active?

Has the deal closed, and when could you put some rigs out there?

I don't believe it's closed yet, and we'll probably wait until winter is over and hit it probably in the spring 2011.

Okay.

On the Granite Wash, there has been some indication from other people in the industry that they have seen some communication on some of the Granite Wash wells.

Has that been something you've seen as well?

Scott, this is Steve.

We've seen some frac interference, when you're pumping your frac, but I don't think we've seen much on negative depletion from off-set wells, though we haven't downspaced that much either.

We've done some floor well deals in the Colony.

Yes, 160 spacing.

And have a pretty good idea of what recovery diminution is going to be on infill.

I think those are mostly frac heads, Scott.

Okay.

Got it.

Thanks, guys.

Your next question comes from Brian Singer with Goldman Sachs.

Thanks.

Good morning.

Good morning.

Can talk to what the drivers are of the widening of guidance for differentials for both liquids and natural gas?

Is that just the market, is it the increased gathering costs or transportation costs?

I think there are probably two things, Scott, and I'll see if Nick or Jeff wants to jump in with any further information.

But, one, of course, is natural gas liquids are in the 50% crude range and crude has gone on a little run in the third quarter.

NGLs didn't really keep up, so I think that's one issue.

And then on the gas side, as gas prices are lower, your differentials widen on a percentage basis because most of your transportation costs are fixed and when you have a variable cost change then your percentages.

So you may have noticed that we're running at 2011, 2012, $4.50 and $5.50 on expected gas prices and when we just studied the historical differentials, we were seeing when gas prices were at those levels we felt like we were a little on the light side and decided to step it up a little bit.

Got it.

Thanks.

And I guess continuing on the Williston Basin path here, ultimately where do you see yourself positioned in the play?

Is this just a one-time acquisition of a small acreage position or do you see this as something that you could spend more capital on, and meaningfully more capital on, but from a drilling and acreage acquisition perspective?

First of all, I'm encouraged that you refer to 100,000 acres as small.

That means you've got your mind right about how we think about things around here.

But we don't know where this leads, and I don't know the size, but I have expressed confidence in the past that certain plays would get to half-million or a million acres and that would be big enough to bring in a JV partner.

As I mentioned in previous answer to a question, I suspect this does not reach JV size.

Got it.

Okay.

Thanks.

And then I guess is it fair to say then that you're testing different plays from the Sanish and Three Forks that others are testing or that that concept is different, or can add a little bit more color to what you are doing differently than others?

I can't really offer much color.

Just sometimes we have different ideas about things, and most of the times they work, sometimes they don't, so we'll see how this one works out.

Great.

Thank you.

Okay.

Thank you, Brian.

Your next question comes from Dave Kistler with Simmons & Company.

Good morning, guys.

Good morning.

Real quickly, with the amount of drilling that you guys do on the natural gas side, can you talk a little bit about the inventory we're hearing about on these drilled uncompleted wells, maybe both from the perspective of Chesapeake and the perspective of the non-op role that you have in a lot of wells that are drilled, with the likes of a few of the service companies thrown out, 2,500 and above, just be curious to get your perspective?

Oh, with 140 rigs running and we'll drill 2500, 3,000 wells this year, we're always going to have a backlog of commentary from some other companies that they are having a hard time getting wells fracked or whatever their excuse might be at the time.

We just view that as a normal part of our business.

That's one of the reasons why we're vertically integrated.

We've got the fifth largest drilling contracting company in America, we're the second largest compression company in America, we have our own trucking company, we have a lot of specialized service companies that do things for us, we own 26% of Frac Tech So given our scale we think we are generally able to step in front of the line with most service companies and we're their biggest North American customer generally by far.

So we think we're doing fine.

We'll always have a backlog, but I don't view that this is much different than it's been over the last couple of years, where backlogs have ebbed and flowed.

Okay.

So not necessarily just specific to Chesapeake, but you think the numbers that the service companies are throwing out might be a tad overstated, or as you highlighted, maybe just excuses from other folks?

Well, we don't have a way to count it and if the service companies say that's the number, I'm not going to dispute their count.

It's not something we track around here.

Okay.

Thanks.

And then just looking at your hedging portfolio and as you start entering into more WTI hedges, as you're growing your liquids portion.

Will you be hedging more WTI than potentially you produce, using some of that as a dirty hedge potentially for NGLs, or how should we think about your philosophy on that?

Well, first of all, I would think about our philosophy as being generally optimistic about oil prices going forward, so I think we'll try to plan our hedging with that in mind.

Also realizing that whatever we're hedging today with regard to out-year oil will be relatively small percentage of what we expect our oil production to be by that timeframe.

With regard to dirty hedges, we're not familiar with the term, but if you define it...

Yes, just in terms of having a very thin NGL hedging market, oftentimes people have used WTI hedges as a proxy for NGL hedges.

Yes.

What we're concerned about these days are natural gas prices, and that's what we spend most of our time focused on trying to make sure we have those shored up.

Oil of course is relatively easy to hedge, NGLs relatively difficult.

So we'll stay focused on gas and occasionally do some oil hedging and realize, of course, that our expanding production base in the out-years gives us a lot of flexibility there that maybe other companies without such rapidly growing oil base don't have when it comes to hedging.

Great.

Thanks so much, guys.

Thank you, Dave.

Your next question comes from Biju Perincheril with Jefferies and Company.

Hi, good morning.

Aubrey, you talked about two possible joint venture opportunities, one in Appalachia combining the Anschutz acreage with some of yours, and then second, you said a new liquids play.

Are we talking about one and the same?

Yes.

Let me clarify that, Biju, when I talked about two JVs in 2011, I'm talking about the Niobrara, which we are marketing today but it won't close until 2011 in all likelihood, and then a new play idea that we have.

So those would be the two that we're talking about.

Okay.

So those two are separate from the one in Appalachia that will be combining some of your acreage with the newly acquired acreage from Anschutz .

No.

That's a conclusion you're drawing that I wouldn't draw.

Okay.

Got it.

The acreage that you bought from Anschutz, can you talk about the targets there?

Is it Marcellus or is it more Utica?

And then the Utica sale that you guys are targeting, you can talk about the liquids potential

Biju, I appreciate the question and obviously the interest, but it's not really something that we're at liberty to talk much about today.

It was a highly competitive process and we're pleased with where we've ended up, but that's really a 2011 project and I'll have to politely ask to be able to back off that question until then.

That's very understood.

Thanks.

Thank you.

We'll go next to Dan McSpirit with BMO Capital Markets.

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

You state that 45 of the 140 operated rigs running today are drilling liquids-rich plays.

What does that ratio look like at year-end, and then further out, year-end 2011 and year-end 2012?

We have that information, Dan.

Let's see if we can produce it.

Page 17 of the slides on the Web.

Okay.

Great.

If you're on our website, or go to it at some point, note slide 17, which is a projected CapEx budget over the next three years going out, so 2012.

In 2010 we'll spend 31% of our money on liquids CapEx, 2011 it should be 45% and by 2012 we'll be spending almost two-thirds of our capital on liquids plays.

So I suspect that people really don't appreciate that impact when we start replacing $3 and $4 Mcfs with $13 and $14 Mcfs on a similar cost basis.

You really see a huge move in per unit value creation, and that will drive some numbers in 2012 and beyond that I think most people are currently not modeling for.

So that will remain a focus of the Company.

Of course, if gas prices for some reason were to come back at higher levels, we can always pick our gas drilling back up, but at this point, our goal is to go from 90% natural gas CapEx in 2009 to go to 35% gas CapEx in 2012.

I think few companies are really going to be able to make that kind of a shift, particularly of our size.

Dan, just to clarify, you mentioned 145 rigs, and you said drilling liquids.

We have 145 total rigs running today, about.

Dan, did you say 45 rigs drilling liquids or 145?

No, 45 of the 140.

Correct?

Yes, that's right.

And my question was,what does that ratio look like at year-end 2011?

We gave it to you in dollars, so just flip it.

If we're running 150 rigs in 2012, which I think we'll be running more, you will see...

Got it.

But actually, as I look at it, on slide 17 we also have a graph that shows exactly what our rig count will do overall, as well as what the components of it will be.

So you might want to flip to page 17.

I will.

Thank you.

And then second question here, the 150,000 barrels a day in liquids production expected to come by year-end 2012, how much of that is oil versus NGLs?

I think we're still modeling about 60% oil or so, we'd like it to be 65% oil but right now we're at 60%/40%.

Okay.

Great.

And then lastly here, in your discussions with the ratings agencies, how do they view the use of JVs and VPP's in the context of achieving investment grade status, assuming it is at all relevant to the conversation?

I'll let Nick answer.

They see VPPs largely as debt, which is kind of nutty because I'm sure Nick will give you a good example of why that is beyond nutty, but go ahead.

They do see VPPs as debt.

JVss they see as having a partner, they have a lot of question about what those JVs mean, but they do not necessarily view that any differently than the rest of you guys would.

VPPs, we've had lengthy discussions with the agencies on this point and they continue to view them as debt.

Again, we sell the reserves, transfer title to them, we take the reserves off our books.

The only obligation we have ongoing is to be a prudent operator of the property, and they are a partner in the property like anyone else is.

So we do have the obligation, as they are now a royalty owner in the property, to pay their operating costs.

So that's no different really than any other royalty owner.

And if you think about the way that those guys are going to look at it as debt, one of the things that we always scratched our head about is if we do a VPP in a gas price environment of 2011, where the strip is going to average something in the, let's call it mid-5s to low-5s versus having done a VPP in first half of 2008 where the strip was much higher than that, it's actually going to result in more debt in 2008 than in 2011 for the same property just because the price was higher.

And it's really just an obligation in volumes and it can't be measured as debt.

To say it another way, this last deal that we did on the Barnett was, Nick, how many Bcf?

390 BCf.

So call it 400 Bcf that we sold for $1.15 billion.

If we had sold it for $1, they would consider that a better deal than if we had sold it for $4 billion.

They would consider $4 billion a bad deal because it's more money and therefore more debt.

Of course, they ignore the cash that you get from selling it.

So it's one of the insanities of dealing with rating agencies and there is probably no better definition of it than that one.

Got it.

Understand.

Thank you, again.

Your next question is from Joe Allman from JPMorgan.

Thank you.

Good morning, everybody.

Hey, Joe.

Aubrey, on the same topic.

Do you still plan to reduce debt and become investment grade, or have other priorities risen to the top?

That's still the plan, Joe.

When we look out by year-end 2012, we think we'll be a 22 Tcfe to 24 Tcfe Company, that's almost four billion barrels of oil.

By that time we shouldn't have more than $10 billion of debt.

So is $0.40 an Mcfe or is $2.50 per barrel debt?

Are those investment grade stats by year-end 2012?

Absolutely.

Looking at our book cap today, I guess our debt is 42%.

If you just look at the earnings capability of Company over the next few years, we'll be earning close to $2 billion a year.

You'll see that percentage continue to drop.

So we absolutely think we're there and our goal is to drop absolute levels of debt, which we've stated is our goal.

But certainly on a relative basis, as we increase our reserve by 2.5 -3.5 Tcf per year, you will see debt drop very dramatically on a relative basis for sure.

Got you.

And to achieve that goal, as you buy more assets and acreage, does it get more difficult to sell?

I know you can certainly flip acreage, but the fact that you've sold some of your producing assets like the Barnett Shale and others make it more difficult to make sales going forward, especially of core producing assets that are more valuable?

No, because our machine can convert so many PUDs and probable impossibles and in the PDPs per year.

Our out-year projections already anticipate that we'll be selling $1 billion a year of VPPs and we still talk about the growth that we're delivering of 18% in '11, 18% in '12, those are after projected asset sales.

So you're seeing a lot of companies starting to come up with, we can't make our growth targets because we have to go sell assets and when you include the asset sales, there is no growth.

And what we've been able to show is that we think asset sales are important and vital and an everyday part of what we do to fund the business, and also to monetize older assets, and we've chosen to do so through VPPs.

The rating agencies don't care for them, but that's not what has to be the ultimate driver.

The ultimate driver has to be the best way to create value and through asset monetizations and we think benefits, which Nick talked about, of keeping the upside, keeping the tail and not paying taxes on them are pretty important issues to keep in mind.

So we want you to remember that as we talk about out-year growth of 18%, that is after asset sales that take care of any funding gap that we might have.

So converting leasehold into PDP is what the machine does around here.

We've got the capability of doing that of up to 4 Tcf per year and we'll continue to do that year after year.

That's helpful.

And in terms of the Marcellus Shale, it's interesting that you'll take a quarter of the acreage that you bought, and it sounds as if you're going to combine it with the acreage or assets in another play and do a JV there, and so that's an interesting idea.

What would be the benefits of that to you?

Joe, you're talking about the Anschutz acquisition and I'm trying to be responsive to questions without being overly transparent with what our plans are.

I'll just say that we acquired about a half-million acres, about a quarter of it doesn't fit us very well, we're going to intend to sell that.

I'm sure it will be a 2011 transaction.

And then we have an idea with what to do with the rest of it that will fit in pretty nicely with some other acreage we have and we'll see where that takes us in 2011.

Okay.

Fair enough.

Thanks.

Bye-bye.

Thank you, Joe.

(Operator Instructions)

Your next question will come from Steve Parla with Affiliated Research Group.

Thank you for taking my question.

Is there anything material behind the minimal widening of the 2010 production guidance and the increase in 2012, or is that just a sharper pencil?

And, separately, as we listen to you speak about liquids growth out through 2015, is there any implication about what you expect the gas excess to be out that far?

Thanks.

You bet.

Good question, Steve.

Let's talk about, first of all, our change in production guidance.

For 2010, we did previously have just a spot number for our oil production at 19 million barrels.

We went ahead and added a range there of 18 to 19, and that really reflects some ethane rejection that occurred that took our NGL barrels down and we hadn't properly accounted for that in our models, and now we are doing a better job of that.

And then also some hook-up delays related to some midstream activities.

So we'll see where we co me out there, but we felt like it was prudent to put a range in rather than just a spot number of 19 million barrels.

And then 2012, I think Nick mentioned this, but just greater clarity on some of our plays, particularly the Eagle Ford and I think I might have mentioned the Niobrara, as well.

So that's been able to give us that clarity.

What does that mean with regard to our thoughts about gas prices?

I think we just have to live with today's reality, which is the projection for gas prices going forward and comparing that to the curve would make anybody with the choice of drilling an oil well or drilling a gas well be inclined to drill an oil well.

And so that's what we're doing, and three years ago we were a single-product Company focused only on natural gas, didn't really think we could find oil in any meaningful quantities.

We didn't want to go out and buy it.

But that has changed in the last three years and we have figured out a way to find liquids.

And so we're going to back down our gas drilling over time, and, again, as I mentioned before, we'll be down to one-third of our drilling in 2012 will be gas, compared to 90% last year.

If gas prices rebound and the country says we need more gas, we can absolutely respond to that very quickly.

But right now, the focus is on oil because it's three or four times more profitable to look for it than it is natural gas.

And obviously you can lock in some of that differential right now?

Well, yes, sure we can.

We can lock it in.

If you're talking about the differential between gas and oil, we can lock it in terms of hedging, absolutely.

Thank you.

Okay, thank you, Steve.

Your next question is from Kevin Cashman with Assurant.

My question has been answered, guys, thanks.

Okay.

Thank you.

With no further questions in the queue at the time, I would like to turn the conference back over to Aubrey McClendon for any additional or closing comments.

Great.

We appreciate your participation today.

If you have further questions, route them to John, Jeff, or Nick.

Thank you.

That does conclude today's conference.

We thank you for your participation.