Chesapeake Energy Corp (CHK) 2009 Q1 法說會逐字稿

Good day and welcome to the Chesapeake earnings conference call.

Today's conference is being recorded.

At this time I would like to turn the covers over to your host 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, and Mark Lester, our Executive Vice President of Geoscience.

Our prepared comments should last 15 to 20 minutes this morning, and then move to Q&A.

Out of courtesy to other companies having conference calls this morning, we will try to wrap up the call by 11:30 eastern time.

Now I will turn the call over to Aubrey.

Thanks, Jeff.

Aside from the large loss caused by a ceiling test writedown under the conservatism of full cost accounting, we delivered a very solid operational and financial performance during a very challenging quarter for our nation's economy.

However, before we get into the details of Chesapeake's achievements for the quarter I wanted to take a moment to address head-on some of the recent media coverage regarding my new employment agreement.

As I think you know and can certainly tell from the details contained in Chesapeake's press releases over the years, Chesapeake prides itself on transparency and direct communication with our share holders.

For that reason, on January 7, 2009 the company filed with the SEC, a very detailed 8-K that provided a thorough explanation of why the compensation committee and the board took the actions they did at the end of last year, and why they concluded that entering into a revised employment agreement was in the best interest of the company and its shareholders.

On the same day we filed the 8-K, I e-mailed a copy of the document to approximately 45 analysts, large share holders and reporters, and asked that if anyone had any questions about the new employment agreement to call me, and I would be happy to discuss with them.

I received several phone calls and e-mails that expressed support for the new employment agreement.

On the other hand, I did not receive back a single complaint, nor I recall any reporter or analyst publishing a negative follow-up comment about the employment agreement immediately after the filing of the 8-K.

So it is a bit surprising to me that the issue has become such a hot topic four months after we initially disclosed it.

I do sincerely apologize to all shareholders for the distractions that it has caused in the past few weeks.

In addition, further information regarding the board's reasoning for the new employment agreement is included in the definitive proxy statement we filed last week with the SEC.

Furthermore, yesterday we also filed with the SEC, and posted on our Web site, a letter written by our Senior Vice President of Land and Legal, Henry Hood in response to inquiries from our local newspaper that addresses the related party transactions that were discussed in the proxy.

Both of these documents provide a wealth of direct and detailed information, and I urge any of you who have a concern about the issues at hand to review them carefully.

Next I would like to provide some operational observation, offer my opinion on natural gas prices and also explain the virtues of curtailing some of our natural gas production.

Marc will address our financial performance, cost trends in the industry, our hedging gains and strategies and I imagine we will share a thought or two about our full-cost impairment.

Let's begin by analyzing Chesapeake's production growth, during the 2009 first quarter, we averaged 2.367 BCFE per day, which on the face of it, is a 5% increase in production over the first quarter of 2008.

However, please remember that in the past year we sold 3VPPs for proceeds of $1.6 billion, sold our Woodford property for $1.7 billion, and sold 25% of our Fayetteville properties for $1.9 billion in cash and a drill and carry.

All in all, during the past four quarters, we sold producing assets for $5.2 billion, and yet we were still able to increase our production by 5%.

What makes that even more amazing is that our drilling CapEx during the past four quarters, was only $5.8 billion in comparison.

By monetizing just a few of our assets at top of the market prices in 2008, we had other companies essentially pay for 90% of our drilling CapEx during the past four quarters, and yet we still grew our production by 5% during the past four quarters.

We believe that is a remarkable achievement, and very much doubt that it could be replicated in the industry.

We have been efficient with our CapEx as well.

For the quarter we reported a drill bit finding and development cost of $1.44 per MCFE.

This includes the benefit of $269 million of drilling carries booked during the quarter.

This performance compares to our F&D costs of $2 per MCFE and the year-ago first quarter, and $2.04 per MCFE for the full-year 2008 so roughly a 25% decrease, already showing up in the first quarter of 2009.

As our carries kick in and as our drilling program becomes more and more focused on our very best shale plays, our capital efficiency should improve even more, later this year, and in 2010.

Our goal is to be the very best in the industry in capital efficiency and we believe we're well on our way to achieving it in 2009 and 2010.

Likewise our production grew sequentially from the 2008 fourth quarter, to the 2009 first quarter, by 2%.

But when both the fourth quarter and the first quarter are adjusted for the monetizations discussed above, our production actually grew by 3%, or compounded annual rate of approximately 13%.

A pretty strong growth rate we believe.

You might also have noticed in our new outlook that we have reduced our budgeted drilling CapEx by $100 million in 2009 and $400 million in 2010, and have also reduced our expected production growth rates in 2009 and 2010 to account for anticipated asset sales, expected production curtailment, and also 8% reduced CapEx.

At the margin, our slower rate of growth should help gas markets recover somewhat more quickly.

In addition to strong production growth, we also generated very impressive proved reserve growth.

In fact, it was our second best quarter ever in adding reserves to the drill bit.

Unfortunately, this proved reserve gain of 620 BCFE on a net basis after production was hidden by the temporary reduction of 820 BCFE of reserves caused by the 35% drop in natural gas prices during the past 90 days, ending March 31 of 2009.

The reserves are still there, they just don't show up as economic when they are run at a flat NYMEX gas price of only $3.63 per MCF.

However, I am confident that they will reappear on our books later this year, or next year, when gas prices recover from their currently depressed levels.

Further, on reserve growth, we believe we should be able to replace our estimated 870 BCFE of projected 2009 production with 3.4 TCFE of reserve additions for a net addition of approximately 2.5 TCFE of estimated proved reserves and a replacement rate of roughly 4 to 1.

During this year, we expect to sell perhaps 300 BCFE of these reserves.

So this would result in an increase of least two TCFE of estimated proved reserves on a net after sales basis, or about a 16% growth rate, during what we believe will likely be a very weak year of reserve replacement in the industry.

We believe in a $6 to $7 gas price world.

These newly created reserves, should be worth around $3 per MCFE, meaning even in the challenging year of 2009, Chesapeake should be able to increase the net asset value of the company by at least $6 billion, if gas prices return to just the $6 to $7per MCF bottom end of normalized pricing.

On a per share basis, that would be at least $10 per share of added net asset value.

We believe that is very compelling math for $20 stock.

For the full year 2009, our finding costs should be significantly less than $1.50 per MCFE.

That is a testament to the quality of our assets and also the power of our drilling carries.

In the quarter approximately 18% of our drilling CapEx was paid for by our three joint venture partners and we expect that percentage to move up to average 30% for the entire year.

If there was ever a year to be handed a $1 billion check by your partners to develop reserves, 2009 was it.

Drilling costs this year should be lower than any of the past five years, and they may well be the lowest we will ever see again.

Please also remember that we still have $4 billion of these drilling carries left.

This represents approximately 3 TCFE of potential reserve editions over the next few years that will be free of cost to Chesapeake shareholders.

So what could go wrong?

Well, the main thing that is for this value to be fully realized by our share holders we will need some rebound in natural gas prices.

Not a whole lot, just a return to the bottom end of normalized pricing, which we believe is around $6 to $7 per MCF compared to normalize mid price range of $8 to $9 per MCF.

So the next question is what is the case for higher prices from here?

The first thing to observe is the most obvious.

Today's gas prices are clearly not strong enough to support a North American gas rig count,that is high enough to prevent a very severe and unprecedented decline in North American gas production.

In fact, our modeling shows that if gas rig counts stay around the 700 mark in the U.S.

and the 50 mark in Canada, during 2009, that by the end of the 2010 first quarter, North American gas production, on a year-over-year basis, will be about 10% lower and headed further south very quickly.

Once all of us figure out what LNG imports will look like this summer and once we get a better handle on gas demand trends for the rest of the year, investors will begin focusing on the inescapable reality that by the middle of the winter of 2009, and 2010, North American gas production will likely be in free fall.

I ask you to consider how many gas market investors will want to be short natural gas, in that scenario?

My view is, not many.

This will set the stage for a dramatic reversal of natural gas prices sometime this fall or winter.

In fact, in the gas markets we have come to expect the unexpected in the past year.

If oil prices begin to move toward $60 per barrel and the economy looks like it has bottomed this summer, I wouldn't be surprised to see a movement up in gas futures pricing begin earlier than most are currently predicting.

So how high will gas prices go in the recovery and rebound phase in the next cycle?

Obviously we don't know, but clearly gas prices were too high one year ago at $12 to $13 per MCF, and today, they are far too low at $3.50 per MCF.

My guess is the rebound will overshoot on the high side, just as it has overshot on the low side and producers will have to be healed financially for quite some time before they can commit to the capital expenditures needed to stabilize gas production.

If they do, Chesapeake will be willing to hedge two to three years' worth of production into this renewed gas market strength to lock in strong returns, just as we have during the past few years as our cumulative realized and unrealized hedging profits now exceeds $3.8 billion.

Our own internal work suggests that the very best unconventional plays will need $6 to $7 NYMEX gas prices to justify a increase in drilling while the more challenged conventional plays will need at least $8 to $9 NYMEX gas prices for drilling to return at sufficient levels to maintain current production.

Please remember, that the big four shale plays only produce about 12% of North American gas production.

So we have to have a gas price that can keep the vast majority of the other 88% of gas production supported, by maintenance level drilling.

It is a complicated equation, but all of our math still suggests that a long-term floor of about $8 per MCF is needed to grow North American gas production.

We believe this would require gas rig count at least 50% higher than where it is today.

One more point I would like to make on gas prices that is it is absolutely the correct decision to curtail certain gas production at today's prices.

As we previously reported, Chesapeake has about $400 million per day of growth operation currently curtailed.

I hope you take the time to study the supporting math for this decision on pages four and five of yesterday's press release.

In an area like the Barnett Shale, for example, it makes absolute sense to defer completions and curtail production in the price environment that we're in.

In fact, we believe these curtail volumes will generate a 29% rate of return if the contain go and the futures curve holds and we bring curtailed volumes back into production around July 1.

Please let us know if you have any questions regard this math, we believe it is very compelling.

With regard to operational highlights, I will just point out that things are going great in our big four shale plays.

In the Haynesville, we have three new wells capable of initial gas production rates of more than 20 million per day.

We will bring these on line around the first of June, but probably at rates closer to 10 million per day because of our current new well production curtailment policies.

In the Barnett, we have been producing two wells for at least 30 days at over 9.5 million per day.

These are the best wells we have ever drilled in the Barnett and we believe these two wells, Donna Ray number one H, and the Donna Ray East number one H are now the two best wells ever drilled in the Barnett based on first 30 day flow rates.

We chose not to curtail these we wells to get valuable reservoir information from this extraordinary area where we have extensive leasehold coverage.

In the Fayetteville, our last 30 operated wells appear to be 30% better than our 2.2 BCFE pro forma expectation.

And finally in the Marcellus, we have two recent wells producing at rates of 6 and 7 million per day and we're steadily ramping up our activity in this play.

To sum it all up all is well for Chesapeake in the big four shale amp.

Before I turn the call over to Marc, I do have some further Chesapeake operational fun facts to share for you.

Today we have 96 operated drilling rigs working, that is down 40% from a peak of 158 in August of 2008.

80% of those are in the big four shale plays and 92% are drilling horizontal wells currently in eight different formations in 7 different states.

Currently our drilling subsidiary NOMAC Drilling has the seventh largest drilling rig fleet in in America, but is the second most active driller in America.

With regard to our horizontal drilling track record, we have drilled into 23 different formations in 12 different states since we first started to drill horizontal wells.

Of those 23, 13 appear to be economically successful, and we're currently testing or evaluating another five that we think could be successful.

In our reservoir technology center, we have evaluated 15,100 feet of core from April 2007 through April 2009.

That is three linear miles of rock core.

We have evaluated 23 formations in these 12 states.

The big four shale plays make up 41% of that total footage evaluated.

Currently we have a thousand more feet under evaluation.

And the Chesapeake reservoir technology center is a tremendous difference maker.

And we will continue to lengthen our technological lead in the years ahead.

Marc?

Thanks Aubrey.

And good morning, everyone.

I thought the appropriate place for me to begin, this morning, is to discuss cost trends we are seeing in our operations.

Clearly, service costs are rapidly decreasing, but have not yet reached a level reflective of today's $3.50 gas market.

We honestly doubt they will be able to decline that far, and the good news is since they can't, we won't have $3.50 gas for a long time.

Now for some examples of what we're seeing for what I consider to be equivalent wells in each one of the shale plays.

A Barnett well averaged $2.95 million in Q4 and Q1 2009.

Today, that well is $2.6 million for a 13% reduction.

Likewise, in the Fayetteville, during a similar time, we averaged $3.5 million, today, $3 million, for a 14% reduction.

In the Haynesville and in the Marcellus, where we have had a lot of science and experimentation in these new plays, the Haynesville wells were actually up to nearly $9 million of cost and in late 2008.

Today, we're spending about $7 million for a 27% reduction and in the Marcellus, again, with a lot of science and new play experimentation, we got up to $5.8 million in late 2008, today $4 million for a 31% reduction.

Every well we begin now has lower bids in most every category than the previous well.

It will take time for our larger service partners to wring out extra costs from their supply chains but this will continue to happen over the next six months to nine months in our opinion.

For example, spot prices for steel, in April, are down 25 to 30% in just one month.

We continue to wring out our own costs and capital expenditure levels are falling fast.

Although, with nearly 160 rigs in operation, in August of 2008 and 4500 leasing agents, in the field at the beginning of the third quarter of 2008, it has taken time to reduce CapEx for leasehold drilling and completion, but the numbers are falling fast.

We begin 2009 first quarter with 119 rigs operating, decreased to 113 in February and done to 106 at the beginning of march.

Today, as Aubrey noted ,were at 96 rigs a 20% reduction since January 1 and a 40% reduction from our peak in August of 2008.

Non op rig count is similar where we're participating with 76 non-ops at 1/1/2009 we're down to only 50, a 35% reduction.

This results with CapEx coming down with a 90 to 120 day lag.

In January, we expended $480 million, net of the benefits of carries from our three joint venture partners, for drilling and completion costs alone.

By March, we were down to $336 million for that month, a 30% reduction in just 90 days.

And of course, we will be headed substantially lower to well below $200 million per month, we think by the end of Q2, 2009.

An even larger change occurs monthly in our cash leasehold expenses.

In January, we expended $135 million in cash, largely as a result of 2008 deals carried forward.

We were down to $79 million in February, and then only $48 million in March.

Including one $26 million transaction that was a holdover from last year, a reduction of over 65% during the quarter.

Our current run-rate, net of partner reimbursements is less than 50% of the March rate.

We have ramped up our CapEx estimates a bit in the midstream.

In this challenging market, we're finding third parties mostly willing to invest at rates of return in excess of our desired costs.

We're examining areas where we can sell our joint venture with small deals, which we have closed one small transaction in April and have another pending.

Finishing up on my discussion of CapEx, we have been building up substantial inventories of gas line pipe and compressors as a result of the ramp-up of our drilling program from mid 2008 and the long lead times we are experiencing at that time for these items.

Consequently, the cash has gone out the door for several hundred million dollars of this inventory, which will be worked off or sold over the next 12 months or so, lowering our going forward midstream CapEx during that time period.

On the full cost ceiling test topic, I want to point out that the PV 10% at March 31, using $3.63 per million BTU, of NYMEX gas prices was only $8.885 billion, against reserves of 11.85 TCFE, this computes to a value for accounting purposes of only $0.75 per thousand cubic feet equivalent.

Obviously differentials, LOE and the discounting effect of holding prices flat and using a 10% discount factor have a large effect, but I find it remarkable in a world where many of our reserves in the VPPs sell for $5 per MCF equivalent, and even fully mature lower value properties can easily sell for $2.50 to $3 per MCF equivalent, we're required to mark-to-market our approved assets at such a ridiculously low rate.

The benefit I guess is that I guess we will be more profitable going forward as a result of the much lower DD&A rate per MCF produced.

Turning to the hedging front, it has been noted in the past 6 months or so that much of our natural gas hedge position containing so-called knockout or fade-out puts, that could render some of our swaps valueless in a lower priced environment.

We do not accept that a program has to be static, and so we worked hard to restructure virtually all of our 2009 knockouts into straight swaps or collars, and as a result we generated positive realized hedging gains in Q1 of $519 million and unrealized mark-to-market changes of a positive additional $700 million.

In fact, in working to restructure these positions, we improved our entire 2009 revenue stream, at today's strip prices, plus prices received to date by over $930 million versus having left the positions as were.

Our strategy going forward, when the time is right, will be to employ more collars and straight swaps to insure our hedging values versus those knockout and fadeout positions.

Finally, I thought it important to review with you our joint venture carry status.

For the quarter we received $269 million of drilling cost carries, excluding pre-payments and other minor accounting adjustments.

To remind you, our initial carry in the PXP joint venture entered into July 1 was $1.65 billion.

We have used only $158 million of that to date with the remaining carry of 90% or $1.49 billion remaining.

Likewise, at BP, we had a September 19 close for initial carry of $800 million.

We have used to date 46%, or $371 million, leaving $429 million to go.

Our StatOil joint venture started out slower even though we started later.

November 24 was the initiation of that venture with an initial $2.125 billion of carry.

And we have used up a mere $11 million so far, with the remaining carry of $2.114 billion, or 99%.

So in total, out of the initial carry of $4.575 billion, we have used up about $0.5 billion, leaving just over $4 billion remaining carry, or 88%, of the total.

This is another excellent reason our CapEx will come down substantially in the future.

As we ramp up in the Haynesville and Marcellus plays, a substantial amount remains to be paid by our partners.

In fact, in all three plays -- having only used 12% of the carry.

So the combination of 80% of our CapEx being spent in the best four plays in America with a substantial portion of that CapEx being paid by our partners, will enable us to lead the industry, we believe, in low finding costs in 2009 and 2010.

I will conclude with reminding you that carries will go about 30% further, than we originally anticipated, because of lower service costs, so it is entirely possible that our original $4.5 billion of carries could end up creating the value of $6 billion at today's costs.

To give you some context for that, that is equal to 100% of what Chesapeake will pay for drilling CapEx, in 2009 and 2010 combined.

This is an enormously valuable asset our share holders are only beginning to see the benefits of.

Much more to come in the years ahead.

Moderator, with that we will turn it over to the question session, please.

Thank you, sir.

We will take our first question from Michael Hall with Stifel Nicolaus.

Please go ahead, sir.

Quickly on cost reductions, you mentioned you don't think costs can come in enough to kind of correct for the price decline.

What are the stickiest parts of the cost equation in your view, and how much can cost declines and reset the break-even price the industry needs?

Sure, well, let's -- my comments were directed of course to a price environment in the third and fourth quarters of 2008 that built up to reflect a 1,600 plus drilling count on gas side and over 2,000 on total rigs when we were seeing prices in July that were in excess of $13 on NYMEX.

Now with $3.50 that percentage reduction of course is much greater than the 35 to 45 or 50% that we're seeing across the service sector.

There is a lot of equipment out there but a lot of it is being laid down and cold stacked particularly on the drilling and fracture stimulation equipment side of things.

Some equipment being stacked, though, doesn't necessarily reduce the operating cost of the rest of the equipment.

And until layoffs are seen and salary cost reductions, actually of course diesel costs for all of our field operations including those of our service providers are down by about 50% but it is just unlikely that it will go down further.

Putting it in the context of seeing prices decline 75 or 80% and seeing the ability probably for the service guys to get their costs down 50%, or transferred into pricing down 50%.

You see the gap.

That that is why my comment about $3.50 gas prices on NYMEX today with field prices much lower than that.

It just doesn't yet reflect in the service costs what has happened more dramatically in the revenue side.

Now, we're going to continue to push our costs down, I mentioned steel prices coming down.

There is some belief around our shop that steel prices will continue to come down some.

But obviously there is a limit, with iron ore costs and transportation costs to get the steel out in the field as to what that can be.

Great.

Thank you.

That helps.

And then, on -- thinking about, supply side of things.

Just industry wide.

And in particular, the backlog of completions and or just kind of a backlog of activity that is out there.

Can you talk about Aubrey, how quickly you think that sort of backlog completion can come back on to kind of hamper declines of supply.

Michael I'm not sure it is really knowable what is out there in terms of backlog wells, for example, ourselves we have, let's call it 300 wells that haven't been completed, but 200 of those are waiting on pipelines and only 100 are really been kind of voluntarily curtailed.

So we don't think is nearly as big an issue as I have read about, but more importantly, we just think that by the end of the first quarter of 2010, gas production will be down 10%, in North America and so whether or not it happens, by the end of the fourth quarter is not -- we don't spend a lot of time thinking about that.

We just believe that by the summertime the EIA 914 data will clearly show a trend that cannot be interrupted, and once it starts to dig in, will kind of accelerate on itself and I think will bring us back to some more reasonable pricing probably more quickly than most people think.

Very good.

Appreciate it.

Thanks gentlemen.

We will take our next question from Shannon Nome with Deutsche Bank.

Good morning,.

Hi, Shannon.

Marc on the 2010 hedge positioned you mentioned 2009 but it looks like 2010 moved considerably lower and you still have a slug of knockouts.

What is your rationale or strategy there?

We took off some of the 2010 back-half of the prices or back half of the positions, Shannon, when the prices fell here just the last couple of weeks.

Our belief is consistent with what Aubrey mentioned by the back half of 2010, we could see remarkably higher prices than what we are shown on the curve today.

We moved some of those positions forward, protecting our Q1, but you're right overall, and for the year it has moved down.

My belief in working with these kickouts over a long period of time is that there is an ideal time to sort of approach those, as it gets closer to the expiration date.

We're a long way off so the puts have a lot of value with respect to the way they are structured, and that makes taking the position off and restructuring a lot harder.

Most of the 2009 positions that we took off, for example, I did in the November-December period for the first two quarters of 2008.

I took them off in December and November of 2008 just to be clear, and then worked our way from the back half of 2009 out in the first quarter of 2009.

So -- my view is, that is we will by the second half of 2010 be able to put on prices a lot higher and we will continue to work those into either collars or swaps that are on there.

So I wouldn't be at this point in May of 2009 we have got many, many months before the first one comes about.

And I think you will see us act consistently with what we did in 2009.

Okay.

Thank you.

And then just a follow-up.

On the Barnett Shale joint venture.

I know it is a smaller piece of business in relevance to your last three JVs, but just curious what type of industry participation you're seeing in these discussions.

A lot of your peers have designs on either selling assets or doing joint ventures akin to what you all have done.

I am wondering, is there any interest from non-industry investors in these types of assets, or is it really just mostly just the usual suspects that we have seen do these before?

Thanks Shannon.

There is some financial interest.

What we have tried to do is target a part of our Barnett shale assets.

We think our total base is worth about $10 billion.

So we have or peeled out about $1 billion subset and a discrete geographical area that is reasonably kind of rural so that there are not too many concerns about some of the operational hassles of being closer in to town.

We think the structure of that might appeal to some financial folks.

The most obvious candidates would be companies that are seeking to get their feet wet in shale and I think we have previously discussed that those would likely be international energy companies.

And I think there is a lot of appeal to working with Chesapeake, our track record of working with other companies, size of our asset base and I think our technological lead is something that bigger companies than us based overseas find attractive.

So -- these talks, they move slowly.

And just as ours did in 2008, but we do feel like it makes some sense for us to try to do one of these and establish another JV partnership with another company so we won't be in the second quarter but more likely in the third or fourth quarter before we get anything done there.

Thanks Aubrey.

Thank you, Shannon.

And we will take our next question from Brian Singer with Goldman Sachs.

Thank you, Good morning.

Hi, Brian.

You now have some of your Haynesville wells that have reached or are near their 1-year anniversary and I was wondering if you could provide some color on what decline rates you've seen and whether and when you have seen production leveling off.

Yeah, Brian we have a pro forma decline curve that I will let Steve Dixon go through with you I think the first year decline rate is close to 80%.

Over 80.

About 86.

And Brian, I really haven't looked at, or have numbers here with me on particular wells.

We only have I think, two wells that are over a year old, and those would have been our very early wells with not very many stages and not long laterals.

Really don't have a well set yet to a have full-year's decline -- as everyone knows, the Haynesville produce is -- now is a very steep first year, and how that will break, is still a little early yet.

Steve, you want to go through -- do you have second and third-year declines for the Haynesville compared to say, the Barnett?

Well, our pro forma now is 29.5 in the second year, and 20.5 in the third year for the Haynesville, but again, that is just pro forma -- we don't have that knowledge today.

Okay.

Compared to Barnett --

Brian, we're going to try to give you a comparison to the Barnett but go ahead with your question and we will look that up.

Ok great,I guess can you talk in a little more color on the quarterly trajectory of capital expenditures, just given the material decrease versus the first quarter for the remainder of the year, you did highlight wells that are being drilled for you with your carries.

I guess what is the risk or what would have to happen between drilling midstream, leasehold acquisitions you would end up spending either higher than your guidance or lower than your guidance.

Well, I think, the -- the quick answer on that is that our guidance is what we believe is going to happen.

I tried to highlight the very strong move down, in the trajectory, of both rig count and of course resulting expenditures noting the lag.

When we move a rig count at 158 in August, I guess, started that trajectory down throughout the last half of the third quarter and the fourth quarter down to 119, to begin January and now, on down to 96.

These wells take anywhere from 15 to 75 days to drill depending on where we are and then the completion expenditures start typically when we do a service in the field, the invoice doesn't come to us until 30 days to 45 days later.

By the time it goes through our system, it is another 30 to 45 days and so what we're seeing from the beginning of a rig, being laid down, to the actual money changing hands and the invoice hitting our books so to speak, is at least 90 days, and in some cases 120 days.

So the wave of drilling that we built up in the third and fourth quarters sort of started peaking out from a cost standpoint in December and January.

In fact, I think January was our high month.

So -- in looking forward, I don't expect there to be anything from a drilling rig standpoint other than the possibility if prices were to stay low, we would reevaluate whether our estimate of the number of rigs we need to run needs to be further lowered.

It is hard to imagine a drilling scenario where we would ramp up in this year, given where we think prices are going to remain for the remainder of the year.

Our carries are solid with people that are paying, and -- as I noted also we're just beginning really to see the advantage of the Marcellus joint venture, I think, Steve, we have just billed them one time have we not?

Maybe we have a second bill out to them but it is a very low activity rate.

Just started yeah.

I hope that answers your question, Brian.

I think we will be close on to what we're doing and the acreage area, which has always been a question of expenditures, I noted how far we have come.

Our current budget for the remainder on a run-rate basis is $250 million on the carries.

So very -- what we might have spent last year in one month we will spend in the next 12 months.

Thank you and if I could ask one last numbers question.

Were all of the realized gains or losses related to -- I guess they would be gains, related to the 2010 hedge restructuring booked in the first quarter, are there any one-time gains or losses, cash gains or losses that we fixed back in the second quarter with regards to 2010 hedge restructuring.

Brian the way those work is that none of those gains flowed through either the first quarter or the second quarter.

If a restructuring is done for 2010, the cash is either still a receivable, from our counter party or perhaps some of it is paid to us, but the accounting gain for whatever happened in that remains a deferred gain, and will only be recognized in the month of production, that the original hedge, was booked against.

Thank you.

So -- the $519 million of hedging gains,.

All related to January, February, March of 2009 only.

Thank you.

We will take our next question from David Heikkinen with Tudor, Pickering, and Holt.

One quick question on 2010 hedging.

Can you give us a rough idea for quarterly splits for percentage hedged?

I will look that up David.

I don't have it right in here front of me.

Let me see if I can dig that up.

We might have to get back with you David.

Do you have any other questions?

Thinking about your joint ventures and having to deal with BP and Stat Oil.

Can you talk about the impact of having the succunded Stat Oil employees in your operation, impact on operations and then kind of the BP counter point to that of are they just still writing checks or how active are they in the Fayetteville?

Yeah all of our partners are very engaged.

StatOil is the only company that we have succunded employees working here.

Steve, we have a dozen or 10 or --

No, we have six and they really are just started, we only have three of them in place.

I think.

So --

First of all, it is not the easiest thing to get somebody into the USA these days unfortunately.

I thought we were ramping up to around 10.

That is in year two.

What will be the peak.

I think 12.

So six this year, twelve next year.

BP is engaged, very much with us.

We have monthly to other periodic meetings with their teams.

Same with Plains.

I think we meet every month with Plains and it is a very cooperative relationship, and those guys have a lot of input and so, we're thrilled to have partners that are obviously financially stable and capable, but also are willing to get engaged technologically and offer their opinions as well, so extremely proud of the quality of our partners and they are far from just check writers, they are active and engageed nonoperators with us in the whole process.

So no operational inefficiencies or any impairments as far as how you would like to run things versus how any of your partners would?

No, I think -- we're all on the same page and we have certainly discussions about what is the optimum level of rigs certainly when they are paying a disproportionate share.

But, for example, in our BP deal it is contractually written how many rigs we have to run and StatOil and PXP.

We have requirements to spend a certain amount of money either in total over a period of time or per year, so, those things were all pretty heavily negotiated during the negotiation of the contracts themselves.

And any indication from any of the parties as far as desire to continue leasing, kind of updates on status of leasing arrangements with Stat Oil, BP and Plains.

Yeah I -- think is a little a little bit of a mixed bag.

I think it is well known that each of our deals does contain a promote, and so I think for competitive reasons and fairness to them, I will let you do a little work to see who wants to buy more acreage and who doesn't.

Those that have decided not to, I think are doing so, only because the level of the promote they might consider too high.

But others see the value in that so --

Okay.

It is a mixed bag at this point.

But we are in all three areas, continuing to buy new leases regardless of whether our partners are choosing to participate in those purchases, we are buying acreage at values that we think are extremely valuable, and are happy to own the additional acreage 100%, if our partners don't want it.

Status of any of the equity leasing?

Any additional thoughts, about the amount of shares that could be issued, status there?

Yeah, we have still got a things out there that might be settled in that way, I think in the first quarter, around $250 million of our leasehold was in settlement of troubled transactions from 2008, so the of ability to use stock was kind of a way to share some upside with some of those guys and in return, we were able to reduce the purchase price, there are still some situations out there that we're working on and a couple are in litigation and those will just resolve themselves out over time.

Out of your cash for leasing and acquisition, or your expected capital, for the year, should we think about similar split of the total amount.

Kind of 50-50 for 2009 and 2010 goes out with equity and the rest is cash?

Nothing in 2010 would be equity.

And --

Okay.

There is only a couple of possibilities for 2009 from here for equity so.

Pretty much from here on, with the exception of a couple things, it will be cash only.

Okay.

And then your rig count ramping in the Marcellus and Haynesville, Marc's comments about not ramping rig count overall.

Where do you end up reducing rig count in 2009 or do you see an exit rate that is higher than your current 96 rigs?

I will let Steve address this, but basically what we continue to do is peel rigs out of kind of conventional areas and areas that are held by production and put new rigs to work in the Haynesville and the Marcellus.

Yeah, as I said we're taking it out of the Midcontinent, Permian, South Texas, and adding into those areas though we do think we will be up just over 100 by the end of the year.

100 total rigs, right.

Yeah.

Of which how many will be in the big four, something like 80 -- -- 80 something, 92.

Okay.

By the end of the year we will have close to 90% of our activity in those four shale plays whereas, David, when we were at 158 rigs, I believe we had about 50 big four shale wells, so we will have reduced our conventional drilling by about 90%, in the course of one year.

And I think that is a huge testament about really two things.

One, the attractiveness of the shales and the unattractiveness of most everything else, and why we remain more convinced then ever of production declines to come that will more than balance the gas market in the next 12 months.

Okay.

Thanks for all the answers.

And David, it appears that about 32, 33% of our volumes for the entire year are located in Q1.

And then, similar slightly less amount in Q2, so, I am going to estimate that 60 to 65% of the entire volumes hedged as we have listed are located in Q1 and Q2 with the balance of roughly a third or 35% distributed into Q3 and Q4.

2010.

This is 2010 volumes.

Thank you.

And we will go next to Tom Gardner with Simmons & Company.

Aubrey I wanted to get your thoughts on the assumptions embedded in your gas macro outlook with respect to gas demand and LNG imports.

Perhaps if you could speak to it in terms of 2008 demand in LNG, I can understand it better.

We don't have any special information on gas demand.

We read the same stuff that most everybody else reads.

Some of it written by guys like you.

I am always nervous when you all admit you don't know where gas demand is going to go.

But I will say that it appears to us that the economy is probably in a process of bottoming, and we find that encouraging.

But we just account for that lack of knowledge by saying, we know that these declines will set in, and we know this market will be balanced within the next nine months or so, by the end of the first quarter of 2010.

If the economy picks up, our intuition would tell us that we will see signs by the end of this year, but to be safe and conservative, we're satisfied to say 2009 will be bad and 2010 will be a lot better given that the gas market always surprises, it would seem to me that the surprises are likely to be that gas prices would move more quickly in 2009 once you get past the summer of 2009 and past LNG imports.

We know that you can't fill up storage more than X, and so whether it fills up on October 1st or November 1st, it kind of is irrelevant.

You can't put more in there than around 4TCF, so at that point it is just a matter of how unbalanced the market will be in 2010, and we think there will be a very powerful self correcting mechanism underway in 2010 so --

We just kind of stay focused on 2009 being bad and 2010 and 2011 being quite a bit better with the -- if you had to put a bet down it would be that it heals more quickly rather than more slowly.

Got you and I appreciate your comments on the drilled uncompleted wells.

I am trying to understand the delay from rig move off to when a well is placed on sales.

Can you give me an estimate of what the average figure for Chesapeake might be?

I will let Steve talk about that because it will also involve a comment about multi-wells on single pads as well that's a big component.

Tom, probably average first sales, from rig release, close to 60 days and so then you put the accounting and dollars paid, delay that another 30 or 60 days so, the dollars don't quit coming in until 120 days after rig release on average.

So that's that part of that rolloff from our higher rig counts.

Got you.

One last question sort of an accounting question if will.

Trying to understand this capitalized interest expense.

Specifically the fluctuations from quarter to quarter.

Can you walk us through why the big increase, relative to total interest expense?

Sure.

I can illuminate the way we're required to account for that.

This is a function of our average interest rate costs, applied against the unevaluated leasehold that has not been evaluated and put in our full cost pool.

And under full cost accounting, any increases to that require us and result in an increase in the amount of capitalized interest, and likewise, going forward, with less acreage being acquired to begin with, more of it being paid by our partners and third, more of it being evaluated as a percentage I think we moved a couple of billion dollars of unevaluated leasehold, this quarter, for example, into the full cost pool, resulting in less unevaluated acreage, in dollars at the end of the quarter.

So going forward, actually, it will kind of reverse from what has been the trend the last couple years.

We will have less capitalized interest and more GAAP income statement interest, which is why we projected a increase in interest costs, in our outlook, for GAAP purposes on the income statement going forward.

Thank you, that was very well done.

He's our Chief Financial Officer, what about that?

That's all, guys, thank you.

And we will go next to Biju Perincheril with Jefferies and Company.

Hi, good morning, couple of quick questions.

On the last call you mentioned you were close to having results on East Texas Haynesville well.

Anything more you can say on that today or generally what you're seeing in East Texas.

Yeah, actually we have completed two wells there, Biju that are waiting on pipeline and they had very successful tests.

We have not been willing yet divulge what those results are, but we're pleased with them and are building pipelines to them, and I think we're probably another 60 days away, though, most of the gathering infrastructure and these are in Pinola or Harrison.

Harrison.

Sorry these are in Harrison.

Most of the local gathering infrastructure is set up for wet gas and of course these are dry gas so we have to lay our own pipelines in there.

The third well we drilled is a well called the Harvey down in Shelby County.

And that well is I think just about finished up drilling, and it is in a new area as well.

So we will probably keep results there pretty tight as well.

I will say that, I will stand by what we have said in the past, which is that we do view that kind of a center of the universe is a area in DeSoto Parish and part of Red River Parish, and parts of southern Caddo, and as you get further out from that area, you're not going to see the 20 million a day type completions so we have never thought that Texas and say Harrison and Pinola Counties would be as good as say, across the river into Louisiana.

They are successful wells.

They will be successful wells but they are not 20 million day type wells.

Fair enough.

Would you say the results that have been coming out of east Texas, that results have been published, those are representative or, or there is operators still coming up a learning curve.

There have been a lot of companies report troubles with drilling these wells and completing them.

It is just a reminder that if you have not spent a lot of time drilling horizontal shale wells it is not the easiest thing to get the hang of.

We have not had any trouble given our expertise in the area.

I can't really tell you that what you have seen to date means too much.

I would say that there are a lot of companies struggling to come up the learning curve and they will get there it will just take some time.

In the meantime we will be running 30 to 35 rigs completing a new well every two days, in the Haynesville and we will have a pretty significant headstart.

Okay.

And then one question relating to your joint ventures.

Are there any provisions there, you talked about the benefits of service costs coming down, but is there any provisions tied to activities or somehow index to service costs the drilling carries amount.

No, that is one of the great benefits of course to us is that those dollars were arrived at during a time of peak asset value, yet they are going to be spent during a time of low cost.

And so, as Marc mentioned in his spiel, we think that $4.5 billion of carry, will end up acting like about $6 billion of carry, which, in fact, is our entire drilling CapEx budget for 2009 and 2010.

I wouldn't be surprised at the end of the day, for those carries to end up creating for us as much as 4 TCF of free gas, which would by itself be a top 10 company in the U.S.

in terms of proved gas reserves so it is a very, very powerful asset.

Frustrating that we can't put it on a balance sheet and showcase it but it will certainly come in over the next couple of years and I think we will end up leading the industry in finding costs and maybe right up there in terms of growth rate as well.

That's all I had, thank you.

Okay.

We will go next to Ellen Hannan with Weeden and Company.

Thank you.

One follow-up on the Barnett shale with the 20 rigs or so you're running there.

What is your outlook for production out of the Barnett by the end of this year?

Steve you want to handle that.

Pretty much flat to where we're at.

We're close to a BCF gross, 660 net.

And we really don't grow production at least in the short term, 20 rigs rolling off of 40.

I think the growth returns in 13, 14, 15, something like that once you get the base.

And once we get through the hump coming off the 40 rigs.

You come down in a little bit of a dip Ellen and start to build in the mid teens.

So, we should look for something slightly below the 660 by the end of the year.

No, I think we just said it would be flat.

Okay.

The other question, in terms of the drilling that you plan in 2010, versus 2009 in the Fayetteville, the decrease, is that because you're being carried?

Oh, we have been discussing that with our partner.

We're at 20 rigs today.

They have expressed a preference in 2010 to run fewer rigs, so we have budgeted 16 for 2010.

Really, we would be happy to run 20 but in deference to BP, we said we would run 16.

We will go next to David Tameron from Wachovia.

Following up on Ellen's question in the Fayetteville, it looked like your gross production kicked up for the year but your working interest was significantly higher.

Was that just a function of wells in the JV or can you talk about that?

Where are you picking up the working interest reference to Fayetteville?

I was looking at gross versus net.

Net is higher because of Seeco's activity.

They've really kicked it up, so our net production is up --

Yeah, not related to working interest.

It is related to how much gas is coming from our nonoperated wells, mainly by Seeco which gets added to our net production --

Okay.

Our gross operated wells and so, you get that --

Okay so a non-OP.

We continue to kind of average probably oh, with BP at 25%, my guess is our working interest averages between 50 and 60%.

Right at 60.

Right at 60% on the Fayetteville.

Okay, thanks.

And then Aubrey, I think last year you guys mentioned horizontal granite wash wells, obviously Penn-Virginia has come out, Newfield has drilled some.

Can you talk about if this was the same play you were drilling.

I think you mentioned these last summer.

I could be off on the timing, could you talk about what you guys have done as far as horizontal granite wash?

I will let Mark Lester take that.

It is a little bit of a frustrating situation in that these granite wash plays actually for us can compete with the shales but they really don't get the attention that the shales do.

We discovered for example, a field called Colony Wash in Washita and Custer Counties,Oklahoma two years ago.

I think we drilled more than 50 wells, Mark will have numbers for you in a minute.

This is actually our highest rate of return area in the entire company.

We have started to drill horizontally in the Texas panhandle and in other places in the Anadarko Basin for these wash plays.

We think all in all it has more than two TCF of net exposure to us but it just unfortunately doesn't get as much play as the shales do.

I will let Mark Lester, who is our Executive VP of Geoscience take it over from here.

Yeah, David.

The Colony Wash has been an outstanding play for us unfortunately it doesn't cover the geographic extent of some of our more higher profile plays like the Haynesville and Marcellus but an outstanding play nevertheless.

We currently have reached TD on 52 wells.

Have 47 wells producing at a combined rate of about 31 BCF and 2,100 barrels of oil.

From those 47 wells produced so far, current daily rates about 74 million per day and 5,700 barrels of oil per day.

We currently have I believe five rigs.

Four to five rigs dedicated to that play..

And just in addition to that, those statistics are last, more recent flow wells in that play have all IP'd at rates between 15 to 20 million cubic feet equivalent per day and there is a pretty large oil component to that.

The finding cost approach close to $1 per MCF on those most recent flow wells.

That has been an outstanding play and just an example of some of the other things that we have been able to do here at Chesapeake as we continue to test additional formations, across our asset base.

Okay.

How big is your position there?

Well, I think he's referring to Colony Wash --

There it is -- 60,000 acres in Colony Wash and Jeff what else do we show for our other?

About 285,000 acres in our other wash plays.

Not including colony.

Not including colony.

Colony does appear to be the clash of all the other granite washes.

We have been successful drilling some of the other washes, also, but Colony has been the star so far.

That 2 TCF number, is that you referring to the 60,000 -- is that Colony Wash or --

That is gross for the whole Colony Wash area.

Okay.

All right.

And then one more question.

CapEx split over last three quarters, of the total budget.

Can you talk about what that looks like.

Ramping down a little bit or -- how should we model?

Over the next three quarters is it kind of linear or does it continue to peel off from the first quarter?

Yeah, no, that -- that is the question I'm asking.

Okay.

For 2009.

For 2009, yes.

Well, the Q2, ramp down is going to start with drilling CapEx, as a point of reference for the March month was $337 million.

And I mentioned that we think by the end of Q2, certainly by the beginning or so of Q3, that that will be approaching and go below 200.

So generally we have been moving down between 50 and 75 to $100 million of expenditure per month, in the last three months, and our projection would be to continue that trend, slowing and then our rig count, Steve, I began -- I think is beginning to look up a little bit right now, at the end of Q3, is that approximately right?

We're projecting three and four to basically be flat at under 600.

Okay.

Jeff just said that Q2 would be $650 million, drilling CapEx and then Q3 and Q4, both 575.

All right.

Thanks.

Moderator, we have time for one more question.

Thank you, sir.

We will move to our last question.

It comes from Rehan Rashid from FBR Capital Markets.

Good morning, everybody.

As a structural question, maybe, and using Fayetteville as an example, if I use risk 3P reserves and call it expected 2009 production in the Fayetteville area, your RP ratio on that 3P basis is about 70 years.

How do think about this RP ratio, is there an optimal lower number that you want to be gearing towards, maybe just thoughts on this longer RP ratio.

I think we would like to have it all produced in one day and just get paid for it and we'd be done.

But that's not the way the earth works.

And so when you look at our acreage inventory of 440,000 acres and you look at a well every 80 acres you have room for about 5500 net wells there, and I don't know how many net wells we have drilled so far, but my guess is, not more than Jeff may have it exactly, but probably not more than a thousand.

And so it is just a matter of how much money do you have, to apply to a play.

And then, how much gas can a market take at any one time so -- clearly, you know I think what happened overtime Rehan that the conventional plays in the US slowly dry up or get elbowed aside by the shale plays in that this production continues to increase over time and that that RP comes down.

Right now the RP doesn't really -- the reserve side of it doesn't get bigger over time, except if technology improves and we have already disclosed and Southwestern has as well that we're running 30% better than our 2.2 pro forma.

So we're somewhere between 2.8 and 3 these days.

And so that number kind of stays out there, and as your production grows obviously that RP shrinks over time.

As you're able to afford more drill and as the market can absorb more gas than you can accelerate.

Jeff tells me that our net drilling so far in the Fayetteville has been 313 net wells --

Net PDP wells.

Net PDP wells out of a potential of about 5,500.

So, we have only drilled 6% of our potential wells in the Fayetteville today.

Just to echo that Aubrey, just adding to that we show about 25,000 acres drilled to date out of the entire acreage position.

And really to think about a true RP ratio on proved reserves and not try to expand it to the whole universe of what might ultimately be drilled, we have just over 800 BCF of proved reserves books, so I'm not sure how much we'll produce this year, Steve, in just the Fayetteville on a net basis.

Current is 200.

I don't know what the year is projected.

That would give you a truer indication of what really the RP that most people think before production versus booked proved reserves.

On the CapEx one really quickly, the 575 for 3Q-4Q is that before reimbursements from the JV or net of it?

That after, that is net of.

Okay.

Thank you.

Okay, thank you.

And looks like that is the end.

So, we appreciate it very much.

And -- if you have any follow-up questions for us, please give Jeff or Marc a holler, thank you

This does conclude today's conference.

Thank you for joining us and have a wonderful day