Chesapeake Energy Corp (CHK) 2003 Q1 法說會逐字稿

Good day everyone.

Welcome to this Chesapeake Energy first quarter 2003 earnings release conference call.

Today's call is being recorded.

At this time for opening comments and introductions I would now like to turn the call over to Mr. Aubrey McClendon, Chief Executive Officer with Chesapeake Energy.

Please go ahead, sir.

Good morning.

Thank you for joining Chesapeake's first quarter 2003 earnings release conference call.

Before we begin I need to provide you with disclosure concerning the forward looking statements we will make during the course of this call.

The statements that describe our beliefs, goals, expectations, projections, or assumptions are considered forward-looking.

Please note that the company's actual results may differ from those contained in such forward looking statements.

Additional information concerning these statements is available in the company's SEC filings.

Our prepared comments should last 10 to 15 minutes.

Then we'll be able to take your questions after that.

As we hope you've seen from our release, Chesapeake's first quarter results were very strong.

Net income was $70 million.

Operating cash flow was $168 million.

EBITDA was $230 million.

For the record, operating cash flow is defined as cash flow provider by operating activities before changes in assets and liabilities.

Chesapeake's strong financial results were driven by an equally strong operational performance.

Oil and gas production reached the record level of 57 BCFE, our seventh consecutive quarter of record production.

That translates into 631 million cubic feet per day of gas equivalent production.

This quarter's production was up 35% from the year-ago quarter and 15% sequentially from the fourth quarter.

Because of this quarter's especially strong operational performance, we have increased our production forecast to 61 to 62 BCFE for the second quarter of 2003 and to 240 to 245 BCFE for the full year 2003.

In addition as of March 31, our estimated proved reserves has reached a record level of 2.8 TCFE, up over 600 BCFE in the past 90 days.

This is a 27% increase for the first quarter.

What drove the company's strong operational performance in the first quarter?

First, we completed two important mid-continent gas property acquisitions: $500 million from El Paso; and $300 million from ONEOK.

Those transactions brought us first-class mid-continent gas assets that were characterized by low operating costs, high margins and significant upside potential.

Both El Paso and ONEOK were reluctant sellers of these long-lived legacy assets.

We are fortunate to have planned ahead for these acquisitions, having long ago established very good relationships with both companies.

When each of them needed a quick sale, we were not only the logical buyer, but also the most prepared.

A secondary benefit of the acquisitions is that the financing for each transaction improved our balance sheet.

Many of you may have participated in one or both of these financings.

If so, we very much appreciate your investment in our company.

I'm also pleased to report that our debt-to-equity ratio is the best that it has been in six years and should further improve five% or so in each of the next two years from our projected significant earnings stream.

We have a very good likelihood of being a 50-50 debt-to-equity company by the end of 2004.

The second driver of Chesapeake's exceptionally strong operational performance during the quarter was the success of our drilling program with the drill bit we are hitting on all cylinders.

This is no accident.

During the past five years we have built an unrivaled land and seismic position in the mid-continent.

Today our drilling inventory consists of approximately 2,000 un-drilled locations, our biggest backlog ever.

We continue to increase that backlog.

Today we have almost 50 geo-scientists generating new prospect ideas and over 200 field and in-house land men buying the leases to convert these ideas into drillable projects.

In fact, this year we will devote over 100 million of our $600 million CAPEX budget to expand further Chesapeake's unrivaled 3-D seismic and lease-hold inventory.

This pipeline of existing and future prospects is one of the main distinguishing features of Chesapeake today.

With regard to the specifics of this quarter's drilling results, we successfully completed 75 wells out of 81 attempts for a success rate of 93%.

To drill these wells, we employed an average of 28 rigs during the first quarter.

Our rig count for the second quarter is running 20% higher.

We should average approximately 34 to 35 rigs drilling during the second quarter.

From our first quarter drilling activity, Chesapeake's sequential quarterly organic growth rate was about two percent, or approximately double what we had previously forecasted.

As we have stated in the past, we believe our organic growth rate from developmental drilling is about one percent per quarter, or about five percent per year when compounded.

However, when we have exploratory drilling success as we have had in the past two quarters, we are capable of posting organic growth rates of up to 10%.

Our drilling remains two-thirds developmental focused mainly on targets between 7,000 and 15,000 feet deep located throughout the mid-continent and one-third exploratory focused primarily on deep and ultra-deep gas below 15,000 feet below southern and western Oklahoma.

Presently we are drilling on average the deepest wells in the United States and are also drilling four of the ten deepest wells currently being drilled in the US, including the deepest two.

One of these two is in Mayfield.

The other is in Bray (ph.).

We've drilled deep gas wells for the simple reason that that is where the gas is.

We believe that our skill in, and commitment to deep gas exploration is a key competitive advantage of our company.

We know that many of you would like us to share more details of our deep gas exploration program.

However, we still have seismic to acquire and land to buy throughout this very expansive play in the deepest portions of the Anadarko Basin.

Although we would like to tell you more about the upside of this program, we have not been able to figure out how to do so without also educating our competitors.

For now all we plan to do is continue delivering strong operating performances in the quarters ahead and let the results speak for themselves.

I would also like to add that our recent acquisitions have in all likelihood have obscured some of the strength of Chesapeake's underlying organic growth story.

There is no doubt that $850 million of acquisitions in one quarter is an unusually large amount for Chesapeake.

However, ONEOK and El Paso gave us rare opportunities to acquire legacy assets at great value.

We seized the moment in each instance.

These transactions continue a trend we have established during the past five years as the most active player in the mid-continent gas market having purchased $2.7 billion of assets during that time at an average cost of $1.12 per MCFE.

These acquisitions have enabled Chesapeake to build a unique scale of operations in the mid-continent.

We intend to leverage these efficiencies further as we pursue other attractively priced mid-continent gas acquisitions in the future.

One more thought on the subject of acquisitions.

It is important to realize that the successes of our drilling and acquisition program are inseparable.

Drilling drives acquisition ideas.

Acquisitions drive drilling ideas.

The synergy and efficiencies of scale between these two programs work in tandem to improve Chesapeake's margins, enhance our returns on capital, increase our proved reserves and production, and create significant growth in per share net asset value.

As a reminder of how significant Chesapeake's NAV growth can be this year, consider that our net asset value growth in 2003 should exceed 30%and our return on equity should exceed 25% if gas prices stay at or near current levels.

Those returns are in addition to the stock market valuation that currently values Chesapeake as if gas prices are and will always be $3.75 per MCFE Not only do we trade at a significant discount to reasonable NAV presently, but we also expect to increase our NAV this year by at least 30%.

We believe these very strong returns, Chesapeake's steadily improving balance sheet, and the company's deep gas prospect inventory will increasingly distinguish Chesapeake as a have in a US gas industry that has many more have-nots.

One final comment before I turn the call over to Marc.

You may have noticed that we have lifted about one-third of our 2003 gas hedges during the last several months.

We are now hedged for about 30% of our estimated remaining gas production for 2003 at an average NYMEX price of almost $5.

We lifted these hedges because of our belief that today's gas prices will need to rise further this summer to reduce enough demand to refill storage adequately by November 1.

We would not be surprised to see a $6 summer and fall strip this year.

With about 70% of Chesapeake's gas un-hedged for the remainder of '03, we will be in a great position to capture these higher prices should they occur.

On the other hand, if they do not occur, we still have about 30% of our gas hedged at about $5.

One more hedging note.

To protect our traditional mid-continent basis differentials - 15 cents to 25 cents off Henry hub - from possibly widening because of Rocky Mountain gas issues, during the past year we have hedged over 600 BCF of gas production through 2009 at an average differential of only 17 cents.

This move has been an astute one.

We are already up about $33 million on this hedge.

On that pleasant thought, I will turn the call over to Marc.

Thanks Aubrey.

Good morning to everyone.

I suspect everyone is now worn out with detailed explanations of FAS-143, which is the accounting for us of retirement obligations.

Let us throw our two cents in by briefly discussing the effects on Chesapeake this quarter.

When you see the detail in our 10Q, which will be filed shortly, you will see the following non-cash effects to our balance sheet and income statements for Q1.

Our oil and gas property account will reflect an increase of $39.4 million.

Our ARO or asset retirement obligation liability will be booked at $46.4 million.

We will reverse previously deducted DD&A by debiting our DD&A account by $10.2 million.

We will have an increase in our deferred tax liability of $1.5 million, all non-cash charges.

For the current quarterly income statement, these entries resulted in a non-cash after-tax effect gain of $2.4 million.

There was $650,000 of additional DD&A on a pre-tax basis reported in our oil and gas DD&A expense.

Oil and gas DD&A is where this charge will be included each quarter.

Our current forecast of D&D&A per MCFE includes our expected FAS-143 costs.

Let me go over a few housekeeping notes.

Our capitalized costs for the quarter are as follows.

Interest expense capitalized during the quarter was $1.9 million.

That compares to $1.1 million for the quarter in 2002.

Other capitalized internal costs related to our drilling and exploration activities were $6.3 million for this quarter compared to $5.0 million in the quarter ended March 31, 2002.

Our capitalized expenditures for the quarter were as follows: acreage and seismic costs, $33 million; drilling, work-over, and related costs $107 million; our total oil and gas acquisitions for the quarter $834 million - for a total cash expenditure of $974 million.

You will see an additional $49 million of non-cash debits to the oil and gas account.

This is principally the effects of FAS-143 as previously outlined plus some small adjustments for previous purchases.

The total roll, therefore, for our account will be $1.023 billion.

Volumes by area are consistent with what we reported last quarter: 86% of our production by volume came from the mid-continent; the Gulf Coast, including Louisiana and Texas, nine percent; all other areas, principally New Mexico, five percent - for a total of 100%.

With regard to our first quarter reserves, out of the 2.8 trillion cubic feet equivalent of proved reserves, 74%were proved developed, 90% were natural gas.

Present value on an un-escalated basis or SEC case at 10% was estimated at $5.3 billion.

That was based on NYMEX prices of $5.01 per million BTU NYMEX and $31.12 per barrel of oil, again NYMEX.

By area, our reserves were distributed as follows: 89% of our proved reserves by volume are in the mid-continent.

Only five percent are located in the Gulf Coast areas and six percent for all other areas of the country.

We ended the quarter with zero drawn on our $250 million revolving bank credit facility.

Obviously our liquidity position is very strong at this moment.

Cost trends are set forward in our revised outlook, which is provided with this press release and will be posted on our website today.

Of note, we have reduced our estimated book tax rate from 40% to 38% and continue to estimate a 100% non-cash income tax rate for 2003.

On the service company side, overall costs quarter-to-quarter are flat or marginally higher.

To discuss cost trends, we first have to frame our situation, which is different than many other companies.

We are the dominant mid-continent driller by a wide margin, giving us pricing leverage.

Further, we are able to use our own six drilling rigs to adjust our drilling schedule and therefore modulate costs further.

That being said, let me give you some components of what we're seeing on the cost side.

With regard to tubulars, on the casing side, we locked in our casing prices earlier this year for a six-month period beginning January 1.

Our understanding is that casing prices otherwise have moved up five to seven percent industry-wide.

We are flat given the lock-in that we entered into with one vendor.

Cementing and logging have generally been flat to up five or so percent quarter-over-quarter.

Diesel costs are down reflecting the recent declines in oil prices.

On the drilling rig side, we're seeing flat prices for virtually all the bids on a quarter-over-quarter basis.

Finally, we have set forward our significant basis hedges as our outlook at this time.

All of those are detailed on the last page of our outlook.

To give you a little bit more color on that, for example in 2003, 2004, and 2005 we have locked in 65%, 71%, and 49% respectively of our mid-continent gas basis at prices of minus 18, minus 17, and minus 16 cents.

As we look forward to price changes in the future, we've taken the additional steps of not only hedging our NYMEX prices, but also a significant of our mid-continent basis.

With that, I'd like to turn it over to the moderator to take your questions please.

Thank you, Mr. Rowland.

Today's question-and-answer session will be conducted electronically.

If you would like to ask a question, please press the star key followed by the digit one on your touch-tone phone at this time.

That will be star one for questions today.

We will pause for just a moment to give everyone a chance to respond.

Thank you.

That will be star one for questions today.

We'll take our first question today from Mark Meyer at Simmons & Company.

Morning gentlemen.

Aubrey, a question about your current rig count.

Are all the company-owned rigs working?

Yes sir, they are and have been since we've owned them over the last two and a half years or so.

OK.

A question about hedging.

You talked about the possibility of seeing a six-to-higher strip fall and summertime.

As it relates to your thoughts on '04, how do you think about criteria for perhaps going the other way on your hedges and layering in some for '04?

We still don't see an attractive '04 price for us.

Depending on what kind of summer weather we get and what kind of winter weather we get will depend a lot on where '04 is.

The '04 strip, at this point, does not offer enough value for us based on our view of where gas supply is headed and all the things that need to happen for the gas market to get closer to being in balance than it has been in the last year or so.

OK.

Thank you.

We'll take our next question today from Kenneth Beer at Johnson Rice & Company.

Hi.

Obviously a very strong quarter.

I think you have noted on your [inaudible] on the deep gas obviously might have been part of that. [inaudible] what percent of the volume is coming from the deep gas production?

I can address it from a rig count perspective.

We have about a third of our rigs drilling to targets below 15,000 feet, which is our cutoff for what we consider deep gas.

Ultra deep gas is what we consider below 20,000 feet.

We do not expect those numbers to change during the course of the year.

I'll let Marc address the production side of it.

We don't track production by depth.

We track it by region and then by area.

The deep part of our entire program across the mid-continent, with mid-continent representing the vast majority of our reserves - about a quarter of those reserves in the mid-continent are in the deep areas.

In terms if you look at the 600 and whatever-612 or so million-600-yes, 12, 15 million a day amount of volumes coming from a deep wells, you don't have that broken out?

A gas molecule is a molecule.

We have never seen the need to track whether it comes from 7,000 feet or 17,000 feet.

It is doable, but we just haven't seen the----

Fair enough.

It seems like that is where you are getting more volumes than expected.

I was just curious.

Yes, there is no doubt about that.

It hasn't led us to feel like we need to track that.

Although certainly we can.

If it is important enough to you, I think you can get back with Marc.

I am sure we can get you that number.

OK, thank you.

I appreciate it.

We'll go next to Gary Stromberg (ph) of Bear, Stearns.

Good morning.

Aubrey, can you give us a sense-give us some color on what you're seeing in terms of acquisitions in the mid-continent.

As a follow-on, can we expect additional large acquisitions?

How do you think you would finance it?

Something similar to what you did for El Paso or something a little bit different?

First of all, we never expect big acquisitions.

The ONEOK and El Paso acquisitions came to us somewhat unexpectedly.

Those were companies that, had they not encountered balance sheet issues, would of course have kept those assets.

There are no more troubled assets sellers left in the mid-continent either from the public company E&P side or from the tower marketing and pipeline utility side.

What's left?

Traditionally you will continue to see smaller packages cut loose by the larger independents.

That has always been a feature of this area, I think.

As we establish more and more dominance in this area, I think it will force some other people to reconsider their commitment to this basin.

It is difficult to be a part-time player here and generate reasonable returns compared to what we can do.

You'll also see more private companies sell.

That has been a feature of the basin and I think across the nation during the last few years.

A higher degree of technological sophistication is needed today to be successful in this business.

Human capital is an issue as well.

I think the aging of the ownership base of private assets is such that we'll continue to see a good stream of those come towards us.

Being native Oklahomans, we know virtually every owner of any meaningful position of private assets in the state and remain always in conversations with people that have high-quality assets.

The final area where you'll probably see some divestitures is from the majors.

Ranking in order of importance in the mid-continent you have BP.

You have Chevron-Texaco.

You have Conoco-Phillips.

You have Exxon-Mobile.

We haven't seen any of these companies announce wholesale departures from this area.

This is still a very profitable place to blow down your reserves.

None of these companies with the possible exception of BP, has shown any interest in trying to maintain production volumes in the area.

We would definitely be very interested in buying any assets that come up in the mid-continent from major sellers.

That is always where you want to try to buy your assets from.

If anything were of meaningful size, I would expect we would finance it in the same way that we did El Paso and ONEOK, which would be a combination of debt and equity.

If it happens later in the year, we shall have built up cash balances along the way as well.

OK.

Just one more question on the mid-continent.

What are basis differentials today excluding your hedges?

Excluding the hedges, since January the basis differential has been between 38 cents and 55 cents for most of the pipes varying month-to-month.

I think in January it was 38 cents.

February and March it went to 50 to 55 cents.

April was in that same 48-to-50-cent range.

NYMEX went off yesterday.

Indexes have not yet been set either at Henry hub or any of the other selling points for May.

What was the April price?

The April price I can get for you.

I don't have it.

Hold on a second.

We'll get it for you.

Thank you.

That's all I had for today.

Thanks.

Gary, hang on.

We've got it.

Just to remind you, NYMEX was set at $5.14.

Our overall April realized price for gas was $5.03.

That had a 10-cent gas hedging effect negative in it and a 40-cent company-wide differential in it.

Historically we've counted on 15-to-25-cent differentials in this area.

They have been as low as-in the last three or four years, probably a nickel and 50 cents has kind-of been the highest.

We've studied Rocky Mountain gas issues.

We understand that there is considerable interest in trying to get Rockies gas into the mid-continent grid.

We have felt like that would likely influence differentials.

We took a bet to give up maybe a nickel on one side to protect ourselves against a 30 or 40 cent move on the other side.

We feel like this can be a relatively permanent feature of the mid-continent because we feel like gas over-production in the Rockies is likely to last for awhile as well.

That is why we went out to as far as 2009.

Mark, you might mention that these basis hedges did account for about 70% or so of our risk management income.

That is a good point.

FAS-133, which causes us to mark-to-market our "ineffective/non-effective" hedges, the basis hedges do not count for being effective.

As basis flew out after we made the trades in late '02-all during '02 and even into '03, a good portion of the gains that we're now reflecting in risk management income this quarter came from the value increase in our basis differentials hedges.

We'll go next to Ellen Hannan at Bear, Stearns.

Morning.

Most of my questions were answered.

On the closing out of the hedges that you've done, were there any costs associated with this?

No.

The way our hedges work is that as you-from an accounting standpoint, the gain from the hedges-and we do have an embedded gain in those hedges - is not reflected until the month of oil and gas sales that correlate to the month that the hedging were originally put on for.

If we have a $1m gain to make up an amount for September of '03 hedges that we've lifted, that $1m is simply put on the balance sheet as deferred revenue and then is rolled into oil and gas realizations in the month of September.

That is the accounting side of it.

From a cash standpoint, the same thing happens with our counter parties.

If we've shorted gas-in other words, they've taken on the risk of gas going up and we've taken the benefit if it goes down, we have a contract that, in September of '03, is settled at the end of August of '03.

If we eliminate that or take the hedge off, we actually enter into a second contract that mirrors the first contract in terms of tenor, but is the opposite direction.

That also is settled in August for that September hedge.

Nothing happens from a cash standpoint until both contracts are closed in August.

OK.

Just one other thing.

I did come in a few minutes late.

Aubrey, can you reiterate how many wells you drilled.

I think you said 74 this quarter.

Or is that how many were successful?

I think it was 74 out of 81-[75] out of 81.

Pardon me, Ellen.

That is where your 82 BCFE from drilling comes from?

From your 74 wells?

Partially.

We also are active non-operators as well.

I didn't include-that was only operated wells.

It is going to be the bulk of it because the operated reflects our greatest working interest, Ellen.

OK.

In terms of positive revisions, any one particular area or performance-related?

It's a very small number.

It's 14 BCF.

I think either 10 or 12 of that actually was price-related.

Two or four BCF was performance-related out of a 2.8-TCF basis.

I wouldn't have even included that number expect it was the amount necessary to roll to get to the accurate number that we reflected.

OK.

Every little bit counts, right?

The trend is the right way, for sure.

Good.

Thanks very much.

We'll go next to Jeff Robertson at Lehman Brothers.

Good morning Aubrey.

You talked about financing acquisitions a little earlier.

I am curious to know in terms of your capital budget, which is now 600 million.

You all have raised that once this year and look to have some additional free cash over the course of the year.

Is that-if prices stay the same, I guess, is that about as fast as you all can go from an operating standpoint and keep the kind of quality control that you are looking for?

It's not as fast as we could go, but it's as fast as we want to go.

We are in a range that-I think this morning, Tom, we have 35 or 34 of----

34.

34 this morning.

We will bounce around between 33 and 36 or 37 - something like that.

That is plenty for us.

Our organization is built for that.

Could we ramp it to 40 or 45, I think we probably could and keep prospect quality.

We would feel like we were participating and creating pressure on service costs.

We definitely don't want to be a participating factor in that.

We'll hold the line.

If we see people try to increase drilling costs on us, we're just as likely to lay over rigs as to do anything else.

I do want to reiterate Mark's point.

We are responsible for 25% of all the drilling in the mid-continent.

We have 30 rigs in the mid-continent versus a total of 124 up.

There is no other place in the country where there are a 120 rigs active where a quarter of them are operated by one company.

That gives us enormous leverage over our suppliers.

We're not scared to use that leverage to keep our costs in line.

We also use that leverage with the people who buy our gas.

That is another benefit to scale in our area.

We're a quarter of the drilling, but by our calculations, we think we're as much as one-third to 40% of all new gas molecules that are produced in this area.

We use that as well to extract lower gathering costs and higher entire well-head prices.

We are where we would like to be and don't anticipate much change.

In terms of the total rig count, the 30 to 35 operated rigs out of those 120, how many non-operated wells are you also participating in, in terms of all activity in Oklahoma?

Typically we are in as many or slightly more on a non-op side.

Last count I saw, we were in 55% of all drilling in the mid-continent.

We would believe that nobody else in any other basin, nor would we expect anybody else in the history of this basin, has ever had access to 55% of all the information that is being generated through the drill bit.

Our challenge, which is an enormous one, is to gather all that information and get it processed and get it distributed back to the asset team so they can react to it.

That is why we have over 200 land men right now in-house and out in the field buying leases.

They are reacting to this enormous flow of information that comes into this company every day.

Lastly, I think you all were looking at selling some assets in the Permian Basin.

Can you provide an update on that?

Yes.

We announced, I guess back in February in the yearend release that we had suspended that process for a couple reasons.

One, oil and gas prices have gone up.

We didn't think anybody would honor those in their bids.

Plus we drilled three nice wells in a row that gave us reason to believe that although we can never matter in the Permian in the way we matter here in the mid-continent, there are a couple play types in a couple of counties specifically in New Mexico where we think we can be highly competitive.

We intend to continue concentrating our efforts in those very specific areas inside the Permian Basin.

OK.

Thank you.

We'll go next to Art Gray (ph) at SunTrust Capital Markets.

Just a couple macro questions.

Would you give me your company's thoughts or management's thoughts on depletion and what you see there?

Our view is that depletion rates have increased over the past 10 years.

We believe they will continue to increase.

It is one of the things that we feel like people fail to do in looking into the future of this business and where gas prices are likely to head. [They] forget that there is no reason for depletion rates to do anything but accelerate unless the industry were to make a 180-degree turn away from developmental drilling towards exploratory drilling.

We see no indication of that occurring.

You have more drilling in existing fields, which tends to lead to high decline rates of the new wells plus probably the great unspoken trend-or un-discussed trend in the industry, [which] is the impact that developmental drilling has on the decline curves of existing wells.

You can only drill so many rate acceleration wells before the depletion rate of all wells accelerates.

We view it as the key-it will be the key determinant over the next two to three years of where gas prices are headed because of the industry's inability, I think not only to keep up with depletion rates, but probably even realize how quickly depletion rates have accelerated during the past few years.

I think it's an extraordinary move that many companies still don't have their hands around or there wouldn't be so many missed production targets in this industry as [there are].

Do you believe there is negative production growth in the US and Canada?

Definitely and believe that that is not a trend that can be turned around.

What do you think your production growth will be without acquisitions?

I mentioned that our developmental drilling can provide us with a one percent per quarter organic growth rate.

When you compound that, that is five percent.

We don't budget for exploratory success.

When we get it, as we've been able to do in at least the last couple quarters, we get a higher organic growth rate, which for this quarter was two percent.

If you compound that, you get about 10%.

That would be on the high side and an amazing achievement for a company of our size.

We instead like to think about a five percent rate as being one that we are comfortable with.

That in itself is unusual in an industry that is likely, in our view, to shrink by another two to four percent this year.

A few more quick questions.

How does that stack up with all your peers, not just large, but all your peers - your organic well production growth.

How does that stack up, do you think, in the industry based on what you can see?

Last year public mid cap and large caps, including majors had organic growth rate of negative eight to nine percent.

There are acquisitions and divestitures in there.

We think overall the industry probably shrank at five to six percent.

The top companies shrunk at rates higher than that.

Several of the super independents shrunk at rates between 15% to 20% in US gas production last year.

That is despite having been aggressive drillers during that time.

You also shouldn't forget that 30% of all gas production reserves are still held by the majors.

It's our view that they are playing a global gas game, not a North American gas game.

They are harvesting North America and investing around the world.

These companies, we think, correctly realize that their highest returns on capital are not to go for one BCF or 10 BCF in Oklahoma, Texas, or Louisiana, but to go find one, five, ten, 100 TCF around the world, liquefy it and transport it to the US.

That is what the majors should be doing.

The good news for us is that it going to take two, three, four, or five years for that gas to make any meaningful impact in the US.

If base decline rates in the US are what we think they are, we are likely to see further shrinkage until that time in base gas production.

I would say the industry has a negative organic growth rate of anywhere between two and five percent on a structural basis.

How does this feel different to you than 2001 felt at this same time?

There was a lot of euphoria, if I remember correctly, going into the summer.

We had an economic downturn, fuel switching, and a cold summer.

How does this period feel different to you?

A couple things are different.

First of all, we're coming out of a faster adjustment down from $10 gas this time than before.

We had $10 gas in January of '01.

Then you had, I think, $6.50 in February and close to six in March.

You had more than just one instant of massive demand destruction.

It came down so quickly here a week later that we don't think you are likely to see the demand destruction that you saw in '01.

Plus the demand that you are trying to destroy should, by definition, be more resilient than the demand that existed in 2001.

It has been toughened up over the last couple years.

On the supply side, I don't think-clearly you've seen a slower ram-up in drilling.

We all can speculate on why that is.

It has a myriad of reasons, not the least of which is declining prospect quality.

It's harder to hedge.

Basis differentials are up.

You've had a lot of capital removed from the market because of the mezzanine players from the power marketing side are out of it.

I think managements today understand they've got what they've got.

They can't just go double their drilling schedule and expect to get great returns.

I think one lesson from 2001 that nobody has forgotten is that when you take your worst prospect and put your most expensive rig staffed by your least experienced crew, you are very likely going to have a hat trick of value destruction rather than value creation.

We believe in everyone in this industry remembers that.

Thank you.

We'll take the next question from Scott Hanold at RBC Capital Markets.

You talked about 2,000 un-drilled locations.

Could you provide a little bit more color into that?

Where are you seeing the most upside potential in those areas?

The most upside is clearly going to be in our deep programs, which would extend from south-central Oklahoma area that we call Bray up through Cement through an area we call Mountain Front into the deep and darker portion of the basin of which the Mayfield area would be the most important for us.

That whole trend would have a number of locations that would not be in the majority in that 2,000.

The majority of that 2,000 are going to be in developmental locations located in the shallower portions of the Anadarko Basin, in the northwest shelf area of the Basin in an area we call Sahara, and then back into the Arkoma Basin as well.

OK.

Where have you seen your best success as far as the drilling that you've been doing?

Our best wells in the last six months have clearly been in two areas: in the Mayfield area.

It's mainly in Beckham County-exclusively in Beckham County, Oklahoma and in the Cement area in Caddo and Grady Counties, Oklahoma.

Both of those are characterized by very deep drilling efforts of anywhere from 18,000 to 25,000 feet deep.

As far as rig availability, have there been any issues-more specifically with specific types of rigs.

What have you seen, as far as costs are concerned, with those wells?

We have plenty of rigs available to us.

We are very aggressive when it comes to rig cost control.

We will not accept increases in rig rates at the moment.

We see no justification to it.

We know of many more rigs that can be brought into this market and brought out of cold-stack into the market.

We take a very hard line.

Clearly if a contractor can get a guy who only drills wells every two years and when gas prices go above $5 and can get that guy to pay more, we're all for him.

He should be charged more.

To require a drilling contractor to just keep a rig available for him to drill a well every once in awhile - there is a big cost to that.

On the other hand, we provide steady work, high-quality work to all of our vendors.

We remind them of that constantly.

OK.

Thank you.

Now we'll go to Keith Bachman (ph) at Deutsche Asset Management.

Morning.

You listed a fraction of your hedge book in the quarter and on into the second quarter.

You mentioned in your press release that you may reinstate some of those hedges if prices move in the right direction.

My question is, would you lift more hedges if we see some further weakness?

How close to zero would you go?

We would go to zero if we saw gas prices continue to fall off from here.

What we see happening is if gas prices, for whatever reason, continue to decline in the weeks ahead, we will probably lift as well because we see no change in the fundamental situation.

We see no likelihood of increases in supply.

We're clearly sensitive to decreases in demand.

We have clearly seen the oil prices decline.

We are willing to take the chance that gas prices go below $4 and stay there for a long time or that oil prices go below $18 to $20 and stay there for a long time.

We are willing to take that chance because we think it has very little probability of being sustainable.

Aubrey, you talked about demand destruction necessary to bring things into balance.

Are you concerned that some of this destruction may be permanent or secular as opposed to cyclical?

I think I'd be concerned if it weren't permanent because I feel like it has to be permanent-measuring permanency by at least the next two to three years.

You can't demand more gas than there is supply.

You've got Mexican gas demand up.

You've got Canadian gas supply down.

You've got US gas supply down.

Demand has to go down as well.

You can use the words however you want.

Destruction is always a rough word to throw around.

It's not that we want it so much as is has to happen because there won't be enough supply to go around.

It's got to be rationed by price until either enough demand is destroyed on a permanent basis or we get a permanent increase in supply.

To me the only way that can occur is through significant imports of LNG.

When you are working from a base of one BCF a day of LNG imports and you are working from a base of 50 BCF a day of US gas supply that can decline at two to four percent a year, you've got to be increasing the LNG base over the next three to four years to probably somewhere in the six-to-10-BCF-a-day range just to make up for declines in domestic gas supply.

Demand is going to be affected.

I do remind the friends that I have on the gas demand side, that there have been long stretches of time when this industry earned sub-par returns because we had to sell gas at unrealistically low prices.

We may be in a period for a couple years where people have to not make much money on the demand side because of high gas prices.

There are enough analysts out there telling them the gas prices will return to $3.50 or $4 soon enough so hopefully they will maintain hope and hang through the tough times and wait for that $3.50 gas to come back.

Thanks.

We'll go next to Mark Meyer at Simmons & Company.

Hi, Aubrey.

One follow-up.

There has been a lot of emerging interest recently from some of your Oklahoma neighbors and some outsiders in CBM Cobalt Methane in the region.

What are your thoughts?

We've been active in I guess the largest CBM project in Oklahoma for the last two years.

We're a joint venture partner with El Paso in a 2.2-million acre CBM project covering most of the Arkoma Basin.

That project has worked reasonably well-reasonable finding costs.

The lyophilic ability (ph) is always an issue.

We don't like to drill 10 to 100 mcf-a-day wells.

It's not our specialty.

Our specialty is to drill to 20,000 feet and try and find 20 million-a-day wells.

However, there are some advantages to us to learn more about CBM in this area.

There were advantages to us having a relationship with El Paso.

There was a reason for us to want to buy a lot of leases in the Arkoma Basin that also could have some deep potential.

We are aware of some of our colleagues in the mid-continent that have established a presence in what is known as the Cherokee Basin or Cherokee Platform - northeast Oklahoma and southeast Kansas.

We've watched that play carefully and believe it's probably marginally effective at $5 gas.

It doesn't hold much interest to us given all the other things that we can do--$5 gas that we believe generate much higher returns on invested capital.

Great.

Thanks.

Having no further questions, I'd like to turn the call back to Mr. McClendon for any additional closing remarks.

We certainly appreciate your all's attention to our call today.

If you have any follow-up questions you can call Marc or me later today.

Thanks very much.

Goodbye.

Thank you.

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