Chesapeake Energy Corp (CHK) 2009 Q3 法說會逐字稿

Good day, ladies and gentlemen, and welcome to the Chesapeake Energy third-quarter 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 and thank you for joining today's conference call.

I would like to begin by introducing the other members of our management team who are with me on the call today; Aubrey McClendon, our Chief Executive Officer; Marc Rowland, our Chief Financial Officer; Steve Dixon, our Chief Operating Officer; Mark Lester, our Executive Vice President; and John Kilgallon, our Manager of Investor Relations and Research.

Our prepared comments this morning will be brief and then we'll move to Q&A.

Out of courtesy to other companies with conference calls this morning we'll wrap up our call at about 10:00 Eastern time.

I'll now turn the call over to Aubrey.

Thank you, Jeff, and good morning.

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

On the operational side our daily production hit a new quarterly record for production at a daily rate of 2.483 bcfe.

In October our net production has already been as high as 2.6 bcfe, so we are on track to continue capturing gas production market share in the months and years ahead.

By year-end 2010, we expect our daily net production to exceed 2.8 bcfe and by year-end 2011 we expect our daily net production to exceed 3.1 bcfe, which will be the increase of 25% from our third-quarter 2009 average daily production.

These production increases continue to be led by growth from our big-four shales and Granite Wash plays.

We believe they will be leading the production increases at Chesapeake for at least the next 20 quarters and probably for more than the next 40 quarters.

If that seems like a lot of quarters to you, well, it is; however, I would like to remind you that Chesapeake has been a Public Company for 67 quarters and our production has increased for 54 quarters out of those 67, including 31 of the last 33 quarters over the past eight years.

In addition, ignoring the impact of what we believe are temporary declines in our proved reserves due to the fall in natural gas prices during the third quarter, we are delivering strong underlying proved reserves additions.

In fact, the third quarter was our best quarter ever in terms of organic proved reserve growth.

We produced 228 bcfe during the quarter and replaced this production over four-fold, with 989 bcfe of additions, extensions and performance revisions.

And just as impressively, those proved reserves cost us only $0.64 per mcfe to deliver.

Yes, that is $0.64 and, yes, that's the lowest in the industry and, yes, we believe that will lead to Chesapeake delivering the highest returns on capital in the industry this year.

While low natural gas prices have temporarily suppressed 2.2 tcfe of our proved reserve bookings during the first three quarters of 2009, rest assured that these will all come back once gas prices recover to around the $5 per mcf level.

Excluding price-related revisions it now looks like we will easily exceed our previously-stated year-end 2009, '10 and '11 goals of 14 tcfe, 16 tcfe and 18 tcfe respectively of proved reserves.

This will lead to some very serious shareholder value creation and some equally serious deleveraging of our balance sheet during the next 26 months.

The next item I would like to highlight is that from now on in our outlook we will project future leasehold acquisitions and sales as one net number.

This reflects our view that in addition to being in the business of just drilling wells and producing natural gas from them over the long term into the future, we are also in the often much more profitable business of identifying and developing big unconventional plays and selling leases in those plays to other companies who perhaps have not yet developed all of our capabilities in developing these big unconventional plays on their own.

We believe this is perhaps the simplest part of our business model but, somewhat mysteriously to us, many observers of our Company apparently find this aspect of our business model difficult to understand or appreciate.

Let me give you some numbers.

Since January 1, 2008, we have monetized approximately $12.5 billion of assets that had a cost basis to us of $2.2 billion, generating a gain in shareholder value of $10.3 billion over the past seven quarters from asset monetization.

This is about $16 per share in a company that trades at around $24 per share.

Despite having delivered these results during some pretty challenging economic conditions, some observers of our Company apparently do not believe we have the capability of monetizing other assets in the future.

Well, we beg to differ, and during the next two years, in 2010 and '11, we expect our asset monetizations to exceed our new asset acquisitions by a range of $900 million up to $2 billion.

Given this unique track record of creating $10 billion of value from $12 billion of monetizations during the past seven quarters, we believe we should be encouraged to make further leasehold investments rather than discourage from making them.

This is an important value-creating complementary business line to the traditional business of just drilling and producing wells.

We believe it highlights our singular ability to identify and develop new plays and to end up owning the top three leasehold positions in them and then creatively maximizing value and minimizing risk from these investments by selling a minority position to an industry partner.

I am happy to report that most of our competitors either do not have the capability or the desire to compete with us in this segment of our business strategy.

My final subject matter will be a brief comment on hedging.

Since January 1, 2008 we have delivered realized cash hedging gains of $1.8 billion this year, yet some are wondering why we haven't rushed out and hedged a lot of $5.50 or $6.00 gas for 2010 like many of our colleagues have done in the past few weeks and months.

The reason is that, in our view it's simply not time yet.

The art and science of hedging requires careful analysis and abundant patience, both of which we believe we possess in good measure.

As a reminder, we have the capability to hedge almost four years of future natural gas production.

We will begin hedging some of that future production when the opportunities arrive to increase shareholder value through hedging rather than limit shareholder value creation through hedging, which we believe some in the industry have done recently.

I'll now turn the call over to Marc Rowland for his comments.

Marc?

Thanks, Aubrey, and good morning, everyone.

Just a very few brief comments from me this AM.

First, I think it important to note in this very difficult gas price environment, your Company has continued to be profitable this quarter on the strength of higher volumes, excellent hedging results, as mentioned by Aubrey, and general cost reductions in many areas.

In fact, on a recurring basis we were able beat consensus estimates of earnings by about 8%.

We continue to see the third quarter be an era of decreased service cost and decreased lease operating expenses.

We do believe that we're probably pretty close to the bottom and Steve Dixon and his operating staff have worked hard to layer in numerous service company arrangements that will lock in at least 70% of our cost over the next 12 to 24 months.

Second, we continue to entertain unsolicited exchange offers for some of our convertible debt and retired $155.3 million of face amount this quarter at an average discount of about 28% to par in exchange for CHK stock that was issued at an equivalent price of just over $36 per share.

To date that brings us about $1.1 billion of debt extinguished in the last four quarters in exchange for CHK shares.

Finally, we ended the quarter with $520 million in cash and about $2.6 billion of undrawn capacity in our three bank credit facilities.

This liquidity was primarily created by the monetization of the PXP carry in September which is in our Haynesville program, and the successful completion of our CMP joint venture with Global Infrastructure Partners during the quarter.

With that, moderator, we'll turn it over to questions, please.

Thank you.

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

Good morning, guys.

Good morning.

A quick question with respect to the hedging that you outlined both in this call and previously that you're taking the fact of being offensive versus defensive with respect to laying on hedges.

Barring the attractive carries you guys have in the Fayetteville, Marcellus, would you think about that a little bit differently and regardless of those at what price would you look at considering hedging?

I don't think our hedging is impacted by our carries, our hedging is impacted by a long developed strategy that Marc and I have had -- and Jeff has joined us in recent years -- in trying to hedge prices that create value rather than limit value creation, and I think some companies that, for example, wouldn't hedge $8.00 gas in 2010 a year or two ago it's a little curious that they're eager to hedge $5.50 or $6.00 gas here lately.

And I read of the markets and Jeff has very extensive, and we think accurate, production model for the entire U.S.

and includes Canadian input, as well.

We think that leads us to the inescapable conclusion that gas production will be down significantly in months and quarters ahead and we think that will present us with ample opportunities.

And so, yes, if we wanted to just go hedge we could hedge, but we think there's more than hedging than just simply executing the hedge.

We think you need to do it at the right time and we haven't felt like the right time has arrived yet.

Great, that's helpful.

And then thinking about Jeff's model that you highlight, if we look at the most-recent 914 data obviously we're seeing lumpy results month over month.

Any thoughts or any changes regarding the anticipated rollover that you've outlined for 2010 as the real rollover year versus 2009 and do you equate that -- the fact that it's been pushed out a little bit to efficiencies, or is there some sort of high grading of portfolios?

Just your conceptual thoughts there would be helpful.

Yes, I'll give you a couple then turn it over to Jeff for his analysis.

But I think we've been reasonably consistent for the past six months that we thought we would see declines in the fourth quarter of 2009 that you're not going to see public confirmation of that until 2010, but I think Jeff's model for some time has shown a bottoming of gas production on a year-over-year basis in the first -- let's call it the late first quarter or early second quarter of 2010, and then those declines continue throughout 2010 to get to an absolute trough of production some time the first half of 2011.

So why is it taking longer for some of this stuff to show up?

I think the same as what we saw in Canada a few years ago.

It just takes a long time for uncompleted wells to work through the system, and I think that's what's happening today, and obviously investors have been very clued into this phenomena of both voluntarily and involuntarily uncompleted or wells that have not yet been hooked up and that backlog we think has largely cleared itself.

We think it's cleared itself at our Company and suspect that it has in the industry.

So I'll turn it over to Jeff for further commentary.

Just a few other comments there.

Frankly we are still trying to reconcile the numerous revisions that came out on the last round of the EIA-914 data and it's not entirely clear if it fully represents an accurate picture.

However, if you take what's been observed in the weekly storage reports it's clear that the market has tightened over the past several weeks, and you saw a resurgence of demand through low fuel prices in September combined with some industry curtailment.

I think both of those are reversing themselves somewhat here in October but still the trend with a much lower rig count should lead to substantial declines in production as we head into 2010 and we haven't seen any new data to discourage that yet.

Well, great, thank you for the clarifications, guys.

Thank you, Dave.

Now we'll open the line up to Scott Hanold with RBC Capital Markets.

Morning.

Good morning, Scott.

Can you talk about the strategy becoming of an acreage reseller and how do you look at the value of this relative to you just focusing those dollars on potentially higher return E&P activity?

For several years, Scott, I think we've been pretty vocal saying there's at least two ways to make money in this industry.

One is the very traditional way of you just go out and drill a well and wait for the production to roll in over the next 50 years and there you have it, and that is traditional and we do a lot of that.

I think over the last couple of years, though, we've recognized that our Company has a unique ability to develop new plays and to buy vast amounts of acreage in those plays, and then seek out partners who for one reason or another aren't in those plays and place them in those plays at prices that are attractive to them and attractive to us.

If you look at -- in the last seven quarters we made over $10 billion doing that.

Well, we didn't make $10 billion during that same time just drilling and producing wells and so we view that it's a very profitable sideline of business.

And some people have a hard time understanding that, but that's what virtually every other business model in every other industry is.

You develop inventory hopefully with an eye towards doing something that your competitors can't do and then you sell it and you make a profit and that's what we've done.

One challenge for us is this model is not particularly conducive to -- or it's not particularly reported well by full-cost accounting because we don't have a line on our income statement that shows profit from leasehold sales, but you can see it in our depreciation rate and we fully disclose all the items that go into that.

So I think that it's a fantastic way and, again, we have created $16 a share of value through that process over the last seven quarters and I think it's something that we'll be able to do for years into the future.

We have the ability to know where the gas is, we have the ability to buy the leases and we have the confidence that when we sell those leases we'll be able to replace those leases in that sales process to hopefully generate a profit margin that's very substantial.

Do you all think that it's a lower risk relative to just regular oil and gas activity?

I think it is simply because once you make the sale you've got the proceeds, and when you drill a well and then you don't hedge it, you really don't know what your returns are going to be.

So I think we have a long-term value creation business and a short-term value creation business and the fact is it's unique in the industry and so a lot of people have a hard time understanding it, but it seems pretty simple to me.

Okay, and one last question then.

Relative to -- sort of on the same line on the Barnett JV, any updates in the last couple of weeks since your analyst day?

Yes, we're still in conversation with some folks and if we do anything there it'll be on terms that we find attractive, and our hope would be that we would wrap those conversations up sometime in the calendar-year 2009.

Appreciate it.

Thanks.

Okay, thanks Scott.

We'll go to David Heikkinen with Tudor, Pickering, Holt.

As you look at your Haynesville production that you just updated, it grew from 210 to 330 million a day, can you talk about -- you did talk some about exit rates.

It looks like exit rates may be exceeding your original target.

How do you think about that growth rate now going into the end of the year with a 35 rig program?

Well, Dave, I may defer here to Steve, but I think we -- in our operational release last week we did give you a projection for year-end 2010 of 670 million gross and 500 net and for year-end 2011 that would be 930 million a day gross and 690 million a day net, so that's how we see the growth unfolding.

Did I misunderstand your question?

Yes.

Basically it looks like, given a 35 rig program, you did increase your guidance on your last operational update a little bit on your year-end target and as you think about that progression on a monthly basis it's grown roughly 120 million a day.

Just trying to get an idea of the conservativeness, or are there better wells that are built into last month's data versus your type curve?

Just trying to see how that growth of bringing those wells in that short of a timeframe led to that amount of growth versus your overall targets are.

Dave, I'd just say that we have a very conservative process of forecasting production and we consistently beat production, both as -- at the Company level, as well as at the play level, so I think those are minimum numbers that we expect to achieve.

Steve, is there anything you want to add to that?

No.

It's all positive news.

Cycle times are lower, reported results seem to be --

We've had quite an influx of non-op activity, also, that we're participating in that's really grown.

Can you take this opportunity to give update on well cost in the Haynesville?

We've had some wells come in around $6 million.

And they're just continuing to drive down per well cost, both on the drilling side through faster drilling, less days, and on the completion side.

I think last week we got to rig release on 29 days on a well that was 4,500 feet and have a number of wells that we've completed now for $6 million or less.

So your rate of return math on the difference between a $6 million well and a $9 million well - it's pretty remarkable what those differences are.

But you see, that's for a -- you mentioned 4,500-foot lateral how much stages could that be gross?

It wouldn't be over double digits.

And then thinking about as you add real estate into the Marcellus your acreage goes up, you're going to be selling some real estate.

How do you value a real estate transaction company?

I was just trying to think about, is it the same earnings stream and the same valuation metrics of how you'd value in just a straight E&P business?

I don't have an answer for that, David, I guess that's you're alls challenge and I think the answer so far has been you all are not going to put any value on it, but that doesn't bother me because we'll just keep doing what we do and we'll take the cash that we obtain from those and either go drill wells that we wouldn't have been able to drill, or repay debt, or do any number of things that create value.

I haven't seen any of your commentary or too many others, but I think it's pretty extraordinary that nobody really focuses on what these carries have done to our finding cost.

If you think about going forward, this is a sustainable, durable, competitive advantage that should enable us to achieve the highest return on capital in the business by reducing our future finding cost.

Do you think, though, from a financial modeling standpoint -- and I know this is how the Market thinks about it -- you'd get better value if you did more cash proceeds up front as opposed to the carries where then it hits your balance sheet immediately, or does that even factor into your thought process, other than just the finding costs lowering over a couple of years?

I think that the balance that we have is one of at least two elements to it.

The most obvious is that the drilling carries, the way that we've structured them are tax deficient and deductible for the paying party and nontaxable income for us being carried as opposed to cash, which would be a taxable transaction and, in fact, in 2008 we had some tax leakage that we're now recovering.

So that's one pretty solid element.

The other part of the strategy I think that's important is from an investor standpoint, our partners, they're investing in plays that are huge in size, sometimes not well defined, and so the carries actually benefit them, as well, in the sense that they get to spend their money basically to develop proved reserves as they're drilling in large areas and I think that has increased the total value to us, as well.

Okay, thanks.

And now we'll open the line up to Goldman Sachs, Brian Singer.

Thank you, good morning.

Good morning, Brian.

Wanted to follow up on Scott's question and your comments with regards to using acreage acquisitions and divestiture as a process center.

I can see in your guidance that you expect to be a net seller through 2011, but can you talk to how large the opportunity set is in the current market in terms of new plays that you may be looking at that could be a source of acquisitions now and divestitures later?

Sure.

We are developing a number of new plays, and we don't know if any of them will work out, of course, and we've publicly disclosed that one of those plays is not new to the industry but new to us, which would be the Eagleford, and it remains to be seen how big our position is.

We're taking a little different geological approach to it than maybe some other companies are, so we'll see how we do on the acreage acquisition and then decide at that point if our position has increased to a size where we want to monetize part of it.

We have some other plays around the country where we think we have the capability of acquiring more acreage and selling some of it.

But one thing for sure is, there is no shortage of companies, especially big companies -- big international companies that are looking for an entree into some of these plays, we have demonstrated that we know how to work a deal with big international companies, know how to get along with those companies, we know how to deliver results to them, and so we have people from all corners of the globe these days coming in to see us, to talk about things, and we're excited to have those conversations and believe that some of them will lead to events in the future that lead to substantial increases in shareholder value.

So I guess to quantify it then, what level of willingness do you have, then, to use the balance sheet.

In other words, if you're projecting currently $1 billion to $1.3 billion or so of net inflows from net divestitures, to the extent that you see opportunities, what could that swing to in terms of, at least, temporarily net acquisitions in any given year?

Are you saying how much could it go down from what we've projected?

I guess you're currently projecting cash inflows from divestitures but you're also highlighting the potential to make some significant leasehold acquisitions and then later sell so, then I guess the question then is, what could that number go to in terms of net cash outflow, at least temporarily, in a given year?

Brian, I don't think it's possible.

We've said that we're going to generate amounts of cash flow increases and cash resource increases in 2010 of $325 to $900 million overall and with regard to properties of $1 billion to $1.350 billion in 2011 on the property line and we expect to be cash positive $900 million to $1.25 billion and for the Company overall $550 million to $1.25 billion.

So we have acquisitions of acreage budgeted inside of those numbers and if we were to see some deal that would require us to go above that, then we would simply do an offsetting divestiture to balance that.

These are the numbers that we will manage the business to deliver, just as we did in 2009.

We'll do it in 2010 and 2011, as well.

Thanks, that's helpful.

I think what we perhaps didn't appreciate was the point that you just made that any additional acquisitions you would balance with additional divestitures, if I got that right.

You do have it right.

If I could ask one numbers question lastly to Marc.

I think at the analyst meeting you'd highlighted about $12.2 billion in net debt, unfortunately I don't recall whether that was an end of third quarter number or a that day number or something projected for the end of the year but it seemed like net debt was a little bit less than $11.6 billion in the third quarter and I just wondered if you could clarify?

Brian, I don't remember exactly what I said at the analyst meeting but I can tell you what it is right now as of September 30th -- and it'll take me just a second to flip to my balance sheet here in details.

Our senior notes payable were $10.4 billion and our credit facilities outstanding were $1.630 rounded, so the total of those would have been our gross debt.

And then the other cash would have -- of $520 million would have been subtracted off that to get to net debt as of September 30th.

That is 12 -- about $11.5 billion net of cash, yes.

Okay, thanks.

Perhaps I'll follow up with Jeff after.

Thank you.

And now we'll now open the floor up to Wei Romualdo with Stone Harbor Investment.

Just two clarifications.

It's not clear from the press release - the two midstream revolver, were they fully drawn or not fully drawn?

Well, I don't know about the press release being clear but what I mentioned was that we had a lot of undrawn facilities and the Chesapeake midstream joint venture was $12 million drawn out of a $500 million facility at September 30th and our other midstream facility was undrawn.

How much was it?

$250 million.

So we're $12 million drawn on a $750 million midstream facility.

Okay.

The other one is, can you give a sense of what was the prices that were used to come up with a reserve number because if you look at NYMEX the price was actually up from June to September?

If you go to page 3 of our press release you'll see what prices we used during the quarter.

Jeff, you want to go ahead and give her those?

The prices used at the end of the third quarter were $3.30 per mcf NYMEX-based prices, or basically Henry Hub based prices, and $70.21 per barrel.

Keep in mind that the price needed to calculate reserves is the price in the cash market.

I've seen several folks that had looked at the NYMEX futures price at the end of September and keep in mind that would have been for the November contract number.

So keep in mind it's the cash price that matters for the calculation of reserves at the end of each quarter.

Jeff, I think I said page 3, it's on page 5, the one, two, three, four, fifth paragraph down.

Okay?

Okay, thank you.

Thank you.

And now we'll take a question from Ray Deacon with Pritchard Capital.

Marc, I was wondering is that -- the comment you made about the reserves at the at year-end 2010 and 2011, what is -- is the gas price assumption there north of $6.00, or do you still think you can meet or exceed that if gas were in the $5.00 to $6.00 range given the low cost of climbs you've seen?

Well, I think that we are using a normalized price that's higher than what it is today, and I'm going to guess that we fully recover at something between $6.50 and $7.00 and probably -- You don't think that --

Fully recovered?

Fully recovered $5.50.

Okay.

And then --

And then remember, Ray, the price that was use at the end of the year will be a 12-month average for 2009 of which 11 months are already set.

Right.

Okay, got it.

Great.

And I guess it seems like a number of pipelines proposed in the Marcellus and Pennsylvania and can you talk at all about transportation cost and where you think that could be heading or where it is now or any kind of comments on that?

Well, we're involved in, I think, virtually every pipeline project that's being contemplated in the Marcellus, and, Ray, we don't expect any of them to change the way that our cost of transportation is up there right now, some of them might even enhance it.

So we still think the northeast would be a Henry Hub plus market for years to come and there are certainly some takeaway issues there, but there are in all plays.

But with the declining production across the system you've seeing a dramatic decline in differentials and I think I noticed last month the differentials were the lowest they've been in three years inside our Company.

So we expect that you will see -- in an industry that now is going to be long pipe and short gas compared to long gas and short pipe over the last few years, you will see transportation or differentials get reduced to basically the true cost of transportation, or perhaps inside of that in some areas.

And I want to throw in one thing.

We'll recover about half of that 2.2 tcfe of suppressed reserves when gas prices get above $4.00, so it comes back pretty quickly and we get all of it back in the $5.00 to $5.50 range.

Thank you.

Okay, Ray, thank you.

Now we'll hear from Hartford Investment Management, Adrayll Askew.

Yes.

Can you give us some more detail related to the Bossier shale?

A lot of people are talking a lot more about this, I guess the returns in that zone have the potential impact of 175,000 acres that you have prospected there for the Bossier.

Yes, we're very excited about the Bossier.

We have -- let's see, Steve, one well that's been producing probably 90 days now -- .

A little less than that

-- and I think we have that well probably a little less than 6.5 bcfe.

What do you think, Jeff?

Yes, I think it's less than that.

Yes, maybe 5 bcfe, or something like that.

Between 5 bcf and 6 bcfe.

So let's say it's somewhere 5 bcfe and 6 bcfe on our first well.

Not a bad start and I believe we are drilling two additional Bossier wells now, or just one?

I think maybe only one is drilling.

We have one drilling.

So the reason why you're not going to see a huge ramp, at least from us, on Bossier drilling is, remember that the Bossier sits above the Haynesville and a lot of leases in Louisiana have what are called PUGH clauses in them, which allow you to hold only those rights that you drill through, and so if you were to drill a bunch of Bossier wells with leases that have PUGH clauses on them you wouldn't be able to hold the Haynesville.

And so right now we're looking for areas where we have leases that don't have PUGH clauses where we could go drill from Bossier wells to get some more information on the play and still hold our Haynesville rights.

So right now one out of our 35 rigs is working on the Bossier, but that could increase in the years -- or certainly not in the years but in the weeks and months ahead.

But it looks like it's a big time play.

I think some day we will probably start talking about the big five shale plays and I think the Bossier would be the fifth, and with 175,000 acres we think that we're probably in a position where we have more acreage in the core of that Bossier play than probably anybody else.

Okay, that's helpful.

From an incremental cost standpoint on wells that you're drilling to the lower Haynesville from an incremental cost standpoint to produce from the Bossier what would that be?

I don't think we -- you would see us develop a dual-lateral concept.

Okay.

We did that years ago in the Austin Chalk.

In fact, at some time we drilled four laterals.

We've reduced our drilling time and cost in the vertical section of the hole to such a level that to add the engineering complexity to having two horizontal laterals open in one wellbore we just don't think the additional risk and cost is worth it, so I think you'll see us follow a program of wells drilled for a specifically for a particular formation rather than any multilateral wells.

Okay, that's very helpful, and then on another topic.

Can you give your perspective on the potential for international development of shale gas, how focused are you on that in the near term and how -- and will we hear any announcements from you guys related to that?

Well, we're very focused on it, and we think it's a key to the world being able to transition to a lower carbon future and also for the world to transition away from oil as Asian demand, we think, overtakes basically the world's capacity to increase supply in the years ahead.

And so natural gas will have to carry much more of the transportation sector load than what it's doing today.

We're in a 50/50 JV with Statoil and we are scouring the world for opportunities and so while I can't tell you when you will see a press release I would imagine sometime in 2010 we will find something that's actionable and we, or they, will tell you about it when that time comes.

Okay, that's helpful.

Can you just speak to the longer-term impact that that would have on the supply side and I guess speak to anyone else that would take the other side and say that in aggregate that would tip the balance from a supply standpoint?

Well, when you think about the size of the market, we consume 85, 84 million-barrels of oil a day, that's a 350 bcf a day market for oil, the whole world market for gas right now is 280 bcf a day.

So our view it wouldn't take much in the way of market share gain in the transportation sector to have an impact on gas demand.

So we don't think shale gas is likely to be any kind of a tipping point in the years going forward.

In fact if you look at LNG liquefaction in facility construction schedule you'll see that after 2014 or so there's not much coming on.

So we think the world will continue to prefer clean energy.

We think the world would prefer energy that is distributed in its supply from more places than oil currently is and we think the future is bright for worldwide demand increases for natural gas and if the demand is there, the supply will be there and shale gas would meet at least part of that demand increase.

Okay.

Thanks, Aubrey, very helpful.

Now we'll go to David Tameron with Wells Fargo.

Good morning, everybody.

Aubrey, can you talk a little bit about operating a bit in Appalachia, is there any progress done as far as force pooling or anything along those lines that you can talk about?

Well, there's three states involved; West Virginia, Pennsylvania, and New York, and New York is still is under drilling moratorium.

New York does have a force pooling law.

It has some favorable attributes to it, it has some negative attributes to it.

We expect to come out from under that moratorium at some point, hopefully later this year or in 2010.

In Pennsylvania, everything we do is on a voluntary pooling basis and the pooling that we can do, which is -- for those of you not familiar with the concept, pooling is simply the amalgamation of leases into one spacing unit from which all royalty owners and working interest owners share proportionally in the production from any well drilled in that unit.

We are voluntarily forming those units and some of our leases have no limits on the size of units we can create, others limit us to 640 acres, others 640 acres plus 10%.

Same in West Virginia.

We actually there have a lot of legacy leases that actually don't allow pooling or are very restrictive on pooling and we have to go back and reform those leases to be able to drill the lateral links that we need.

So it's a laborious and tedious process, but we've got a lot of people that work on it and we have lots of good will with our with mineral owners.

And we don't see that really as -- if you're asking if that's a stranglehold or impediment on development of our assets up there we don't think that it will be.

Okay.

Yes, that's some good color.

And then, can you talk about, as far as Chesapeake or the industry is concerned are there currently infrastructure constraints, whether it's gathering processing, pipeline?

Some of the issues we saw August, September, have those gone away?

Can you give me a snapshot of that?

Well, I'll let Steve Dixon handle it.

A lot of it is greenfield and so there will always be some construction and infrastructure that needs to be built, but there's lots being done.

And so there will always be some lag and some need for years to come in the Marcellus.

But as far as currently, are there current constraints out in the field that you guys are experiencing, whether it's Appalachia, Marcellus -- or whether it's Haynesville, Barnett, whatever?

Well, nothing more than usual, Again, with our activity level and build out some back east where gas coming in and out of storage can create higher line pressures that could back some gas out, but there's no good projects or not a lot of gas backed out right now.

We have -- and a lot of our north Ft.

Worth -- or northwest Tarrant county gas won't be coming on until second half of 2010 as a result of some big projects we have there, but that's related to trying to lay big pipe inside an urban environment and it's just an everyday challenge to get that done, but there's nothing out of the ordinary.

Okay.

Good, thanks.

Now we'll take our question from Lewis Ropp with Barrow Hanley.

Good morning, guys.

Good morning, Lewis.

I apologize if I missed this but in your new format for your cash flow projections I was curious what you have lumped into the other category that looks like it's about $600 million to $800 million for this year and next year.

Jeff will take that for us.

Good morning, Lewis.

Hey, Jeff, how you doing?

Good.

The easy way to think about it is if you'll just lay Schedule B from the prior guidance next to it and cross reference line items, but the specific items that are in any other category would be the geophysical costs, the midstream infrastructure cost, the other PP&E, along with the items that were previously in the inflow section of the prior guidance, which would have been midstream equity financings and systems sales, as well as midstream credit facility draws and repayments.

Okay, great.

I was just thrown off a little bit by the change in the sign convention on some of that stuff and trying to do it while we were on the call but that clarifi --

Hopefully the simplicity will make it an easier to follow going forward.

No, I agree, I think it will.

The other thing I wanted to ask, Aubrey, at the end of the second quarter you had talked about the excess cash generation and increasing proved reserves, getting you to an investment grade credit metric by the end of next year.

Now I'm not so much worried about the movement in the reserves just based on the commodity price at a point in time, but I've had some conversations with you about that excess cash generation and just if you could comment on where you think you stand now and if that's still a goal and how you think we can get there, if it is, for 2010?

Sure, I'll take a whack at it and then let Marc look at it, as well.

So let's start with net debt is $11.5 billion and we have previously projected to be -- to finish the year '09 at 12 -- sorry, at 14 tcf of proved reserves.

Based on what we think gas prices are going to be we probably will end the year at about 13 tcf with 1 tcf or so suppressed.

So if you skip forward to 2010, and assume we -- sorry, to the end of 2010 and assume that for some reason we don't pay back any debt and we've still got $11.5 billion of debt, you would be at about 16 tcf for proved reserves then, and so that would result in a deleveraging on a relative basis by about 25% per mcfe, and so that's the way I look it.

And one final -- and then I'll turn it over to Marc but one final thing is, just a real simple way to think about our business is that going forward we're going to produce about 1 tcf a year and we're going to find about 3 tcfs per year, so that is 2 tcfe a year of a minimum amount of net reserve additions and we think we can do that indefinitely.

So if you just say what's $12 billion over 2 tcfe you can begin to see that we'll de-lever by $0.15 to $0.16 in mcfe every year adding some items.

And then one other way to think about it in context is to say what companies today have proved reserves of about 2 tcfe.

Well, as of 12/31/08 that would be companies like Southwestern, companies like Plains, companies like EXCO, we have companies like Sandridge, Cabot.

We create a new one of those inside our own Company every year, and we do so without really any risk and we do so in generating positive cash resources.

So that's the way I think about value creation is any number of well-respected, highly-valued companies we create a new one of those every year and also create positive cash in that process, Marc?

Yes, I agree with all of that, and the bars have moved around from time to time depending on the price outlook at the rating agencies and certainly in this low-price environment, given some of the issues that the rating agencies have had with their own business I think it's safe to assume that they're much more conservative these days.

But generally, historically anywhere in the $0.60 to $0.65 total proved reserve to debt, if your proved undeveloped, it's not more than 35% to 40% has traditionally been viewed as being near investment grade and certainly we'd be there on the other standards.

The other parts of our balance sheet, though, that are going to have an important part, too.

We've talked in the last quarter extensively about the Chesapeake midstream business and the potential ultimately to establish some value marks there that could add a few billion dollars of value to our business without adding any net debt.

And so historically the rating agencies have had a little bit of a challenge trying to assign value to things like proved undeveloped acreage, drilling rigs, building real estate and our midstream businesses, but certainly that's a component and we're driving the car in the right direction, and I'm sure that we'll end up in the right city.

Don't know when that might be.

Okay, guys.

Well, thank you very much.

That helps a lot.

That was beautiful.

Now we'll move on to Energy Equities Incorporated, David Snow.

Can you talk about extension of the Haynesville into the deeper direction going to the south, I guess, and the west, is it?

Yes, it's been the Saint Augustine County and southern Sabine -- I'm sorry, southern Shelby, as well, and we haven't really played that.

There have been some nice wells that have been brought in down there.

I would point out that we report our Haynesville wells on .22/64th choke, other companies on the 24 and there was a pretty flashy result in the last couple of days that was reported on a 37/67th choke, so you can get these 15 million,20 million a day wells up to some pretty big numbers if you want use a big choke.

But that's about 2,000 feet deeper than where we were playing it and so we have some leasehold down there, a lot in central Shelby County.

So we're watching it carefully and I think at least one of those wells had a reported well cost over $15 million, so you have to -- when you see the well results you don't often see the cost associated with them.

But we view that it looks like it's going to be a good area and if there's any leasehold to be had down there we hope to be competitive with it, but right now we like the sweet spot where we're at.

Okay.

And are you still pursuing any more oily plays?

Every day in every way.

Any color on that?

Other than the stuff's hard to find, and we're working at it hard, and our Colony Wash play's got 100 million barrels of oil net to us, we think, and we're doubling our rig count in that area to get some more of that.

We have a number of oil plays underway.

We have a significant share in the Cleveland sand play and the Anadarko Basin and developing plays in the Tonkawa and some other traditional Pennsylvanian age formations that sporadically produce across the Anadarko Basin.

And we've had some success in the Permian Basin, as well, and we've got a prospect in the Rockies that I think most people are aware of that we're working on and it's oil, as well.

So more to come on that in 2010, we hope.

Great.

Thank you very much.

Thank you, David.

Now we'll go to Dan McSpirit with BMO Capital Markets.

Gentlemen, good morning and thanks for taking my questions.

On your Haynesville shale well costs update of $6 million or less, one, how low can you go?

I ask that in light of the earlier comment on lifting costs and services-related costs maybe having bottomed here.

And then two, can you speak to similar drilling complete cost reductions elsewhere, say, in the Marcellus where you illustrate an average drilling complete cost of, I think, $4.5 million per well?

Sure, I got a couple of thoughts and then turn it over to Steve.

The $6 million is not a level that we are at across the board.

Some of our rigs are capable of doing that, but the vast majority are not there yet, although I think we're pretty routinely inside the $7 million number.

So rather than focus on trying get below $6 million I think Steve and his team is just trying to get more of our existing 35 underneath $7 million and driving it towards $6 million.

And then I'll let him talk about things that we're doing in the Marcellus that could enhance -- could reduce our cost there.

To finish up on Haynesville, we're just continuously improving performance.

We are still doing that in the Barnett and the Fayetteville even though we've been there for years now, so that will continue to happen in the Haynesville.

In the Marcellus, still a lot of science there and still a lot of exploring various areas, still getting our service industry up to speed and so those costs are not where we want them, but are moving the right direction and will continue to do so.

Very good.

Thank you.

Now we'll take a question from Ryan Kelly with Prudential.

Good morning, guys, thanks for taking my questions.

I apologize, you may have addressed this question already, but any update on the new structured hedging facility that you guys talked about on the analyst day and I think it was included in some of your recent filings.

Is that facility up and running?

It is, Ryan.

We have a $10.4 billion structured or secured hedging facility with 13 counter parties.

It is fully up and operational.

We are just in the last weeks of moving over some additional collateral that will allow us to go to the full amount, but we can hedge today quite a lot and it's ready to roll.

Just waiting on recovery in gas prices.

When we think about the collateral and naturally the banks don't use PV10s, but -- they use their own price decks, but the values have been going down.

Is there any risk that the collateral requirement in the hedging facility can crowd out the collateral for the credit agreement or the bank facility, or do you have plenty to go around?

Structurally there is protection at the bank level for doing that.

We have to maintain 15% of our reserves in an unpledged, or super collateral negative pledge, if you will, to protect the bank's situation.

Having said that, though, we just went through our collateral re-determination with the banks.

Although we didn't have a formal reserve re-determination we do that annually.

We did provide a collateral update package and the banks accepted it as it was.

So today we're sitting there with several billion dollars worth of unpledged collateral at either place, either the hedge facilities or the bank, and I guess we could choose to reduce the hedging facility since obviously $10.5 billion right at the moment is about $10 billion more than what we've got on it.

Sure, sure.

The bank covenant leverage at quarter end was?

The bank coverage ratio?

The covenant leverage for the credit facility.

As to the debt per EBITDA test?

Yes.

I don't have the exact amount.

We'll have that in our Q this next couple of days.

That's calculated in our treasury and not in our finance department, so I didn't have that.

Sure.

Thanks guys.

Okay, thanks, Ryan.

Now we'll open the floor to Biju Perincheril with Jefferies.

Hi, good morning.

I was hoping you could give us an update on the two wells that you drilled in Harrison County here recently and how those wells are holding up, maybe a 30 day rate if you have it?

I don't think we have it but the rates were flashy because the wells had been shut in for six months or so.

It has not changed our opinion that East Texas is not likely to be as good as the core, which I think is -- hopefully it's not a surprise to anybody.

One of the things that we will do, Biju, is that we have started a process of selling -- or offering for sale, I should say, a portion of our acreage in the Haynesville that we're not going to be able to get to.

Other companies will like that very much, and a lot will be in Texas and some of it will be north of Shreveport.

So it's just what we do all the time, basically trim some things that either don't look good to us as they might to other people and some things that perhaps we are not as focused on or just can't get to.

So I'll say that it wasn't our intention for those wells to create a stir.

We think that they will produce about the way that we had projected East Texas Haynesville wells to produce.

Okay.

And you had mentioned, I think, at the analyst meeting that you were seeing pretty significant pressure drawdowns, is that -- has the pressure stabilized, or are we still seeing pretty significant drawdowns there?

When you say pressure drawdowns are you talking about in those two wells, or in general?

No, in those two wells.

They have big initial decline rates and probably would not have come in at 15 million a day if they hadn't been shut in for a while, so we don't report individual production rates and certainly won't for those two wells.

But I'd just say that they are performing as we would expect them to and we think that's going to be encouraging for some and maybe not for others.

Okay, that's helpful.

Thanks.

Now we'll hear from Brittany Capital's Bob Clements.

Good morning, guys.

Aubrey, the Obama administration doesn't seem to fully appreciate natural gas as part of their long-term menu of energy sources.

The gas industry's kind of has been out-lobbied by the coal industry in the past, as well.

What's the industry doing to change this?

I think we're engaged across the board in a way that we never have before.

We're communicating in ways that we never have before.

I think most visually we have formed something called America's Natural Gas Alliance.

This is 29 of the 30 largest independent producers of natural gas in the US and Canada, and we have committed $0.01 in mcf of production, which is, I guess, around $80 million, $90 million a year, and we will use that money to drive home our point of natural gas abundance.

And when you realize that there is natural gas abundance then you can begin to think about environmental and energy and national security issues differently.

Our problem isn't so much the coal industry.

The creditability factor of that industry is pretty low, and I think what our biggest challenges are just simply history.

Remember, this is an industry where we haven't been able to say our product is in abundance for most of the part 20 years, and today we now say that and it takes a lot of people time to catch up to where we are from where we were three or four years ago where we used to talk about natural gas and the scarcity.

The other thing is some traditional users of natural gas are not particularly helpful to us.

They do not want to see new markets for natural gas develop, and we have our work cut out to convince those folks that there is plenty of natural gas for them and there is plenty of natural gas to begin to convert our transportation system away from oil to natural gas in a way to reduce our reliance on coal and the power sector so all those things take time.

I would love it if our President were as conversant about the advantages of natural gas as he is with some other technologies that are neither affordable nor scalable or even in some cases existent.

So we've got some work to do there, but we'll stay after it.

Okay.

Thanks Aubrey.

Okay, very good, thank you.

I think we're all done.

We appreciate your questions, look forward to further conversation.

Please get hold of Jeff if you have any follow up.

Thank you.

Ladies and gentlemen, that does conclude our conference for today.

Again, thank you for your participation.