Chesapeake Energy Corp (CHK) 2004 Q3 法說會逐字稿

Good day, everyone, and welcome to this Chesapeake Energy third-quarter 2004 earnings release conference call.

Today's conference is being recorded.

At this time, for opening comments and introductions, I would like to turn the conference ever to Mr. Tom Price, Senior Vice President, Investor and Government Relations.

Please go ahead, sir.

Good morning.

Thank you for joining Chesapeake's third quarter 2004 earnings release conference call.

With me this morning are Aubrey McClendon, Tom Ward and Marc Rowland.

Before I turn the call over to Aubrey and Marc, I need to provide you with disclosure concerning forward-looking statements that Chesapeake's management 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.

In addition, I would also like to point out that during the course of our discussion this morning, we will mention terms, such as operating cash flow and EBITDA, and we will also mention several items that we believe are typically excluded from analysts' estimates.

These are all non-GAAP financial measures.

Reconciliations to the comparable GAAP measures can be found on Pages 13 through 15 of our press release issued yesterday.

While these are not GAAP measures of financial performance, we believe they are common and useful tools in evaluating the Company's overall performance.

Our prepared comments should last about 15 minutes and then we will move to 45 minutes or so of questions and answers.

Aubrey?

Thanks, Tom, and good morning, all of you.

There are three main take-away points that I would like to highlight on today's call.

Number one, Chesapeake continues to deliver excellent financial returns to our investors quarter after quarter and year after year.

Number two, our production growth profile is right at the top of the industry, yet we do not trade with the top of the market multiple, thereby creating a great investment opportunity.

Number three, in anticipation of today's strong oil and gas prices, we made big investments during the past five years that will enable Chesapeake to continue delivering top-tier operational and financial results for years to come.

To begin discussing my first take-away point, I'll emphasize that Chesapeake has once again delivered excellent financial results to our investors.

The Company's net income available to common shareholders was $86 million, or 29 cents per fully diluted share.

Our operating cash flow was $353 million and our EBITDA was $361 million.

The net income and EBITDA numbers include the negative impact of an after-tax, non-cash $25 million unrealized hedging loss on what some refer to as recurring numbers.

Our EBITDA was $394 million and our net income to common shareholders was $111 million, or 37 cents per fully diluted share, 23 percent higher than the 30 cent First Call estimate.

In addition, I hope you've noticed that we continue to tightly control our operating costs, the cash operating costs of our business.

G&A and production expense and interest expense totaled $1.11 per Mcfe this quarter, versus the same $1.11 for the year-ago quarter.

Very few companies have had flat cash operating costs during the past year.

In addition, during the quarter, we spent only $1.02 per Mcfe to add 744 Bcfe to our proved reserves, which led to a reserve replacement rate of 789 percent.

We work hard to control all of our costs and the serious advantage we have in that regard is that our large and focused operating scale, especially in the Mid-Continent, gives us considerable negotiating power with service and equipment providers.

We believe this is a distinct competitive advantage of our company.

Moving to my second take-away point, I would like to highlight that Chesapeake's strong financial results were driven by equally strong operational results.

Oil and gas production reached the record level of 94.2 Bcfe in the quarter.

This was our 13th consecutive quarter of record production, and this year will be our 15th consecutive year of record production.

Third-quarter production was up 33 percent from the year-ago quarter and up 9 percent sequentially from the 2004 second quarter.

Of the 33 percent increase in this year's quarterly production versus last year, 40 percent came from the drillbit and 60 percent came from acquisitions.

Our annualized rate of organic growth for the first three quarters of 2004 has been 13 percent and we are projecting that our final organic growth rate for 2004 will be not less than 13 percent.

Our production growth for the entire year 2004 versus all of 2003 should be 33 percent, which we believe will be tops in the industry among large and mid-cap E&P companies.

Given that we have delivered sequential production growth in each of the last 13 quarters and given that we are now raising our production forecast for the 12th quarter in a row, we are now officially abandoning our long-term organic production growth estimate of 5 percent in favor of these specific out-year organic production growth forecasts -- 13 percent in 2004, at least 10 percent in 2005 and at least 8 percent in 2006 for a three-year forward average of just over 10 percent per year.

Looking backwards, our trailing three-year organic growth rate was consistently forecasted at 5 percent, but we actually delivered an average of 11 percent per year organic growth rate during the past three years.

So at the end of 2006, we believe that our organic growth rate for the trailing six years will have averaged at least 10 percent per year.

This will be an impressive, if not unique, accomplishment in our industry and it will have been produced by a company that will have more than quadrupled in size during those six years.

We believe this is ample evidence that our business model is scalable and capable of continuing to deliver top-tier shareholder returns for years to come.

Further on this point, we've taken production estimates up for the 12th consecutive quarter.

The midpoints of our future production forecast are now as follows -- 357 Bcfe for '04, 407 Bcfe for '05, and 438 Bcfe for '06.

That means we're taking up our '04 production forecast by 1 percent, our '05 forecast up by 3 percent and our initial '06 forecast up 8 percent from the '05 estimate.

I would also note that Chesapeake's initial '06 production estimate is 23 percent above our estimate of '04 production of 357 Bcfe.

There will be very few companies that can deliver this level of production growth to investors during the next few years.

In addition, given the stability of our producing property base and the predictable nature of our drilling results, we now feel more comfortable than ever in estimating our likely year-end proved reserves.

We now estimate that Chesapeake's proved reserves will reach 4.6 Tcfe by year-end, '04, 5.0 Tcfe by year-end '05 and 5.4 Tcfe by year-end '06.

These proved reserve numbers reflect our belief that Chesapeake's reserve life will average 12 years during this time and that our PUD components will average between 30 and 35 percent.

These projected year-end proved reserve numbers of course do not include any probable and profitable reserves, which we now believe are approximately 4 Tcfe and are likely to grow in tandem with our proved reserves in the years ahead.

In considering these out-year growth projections, we hope you'll place them in the context of our past achievements.

During the past 13 quarters, Chesapeake's production growth has increased by 141 percent for a compounded annual growth rate of 31 percent.

This consistent track record of delivering production and reserve growth year after year should give investors great comfort that we can meet our projected production and reserve volumes.

My third take-away point is this -- we were early to believe that natural gas and oil prices were headed to sustainably higher levels.

We invested accordingly, and are now distinctively positioned to continue delivering top-tier shareholder value for years to come.

In addition to the $4.5 billion of acquisitions made during the past five years, each of which can now properly be seen as a bargain, and the $2.6 billion in drilling CapEx invested during the same time frame, which has created almost 500 million cubic feet per day of new production, we have also invested over $1 billion in unevaluated leasehold in 3-D seismics.

These are the building blocks of future shareholder value creation.

While this investment of $1 billion has been a drag on our finding costs during the past five years, today it is a series competitive advantage.

In our view, company's that are just now beginning to believe in today's price decks will find the going tough when it comes to accumulating the human capital, the lease hold and the science necessary for sustainable, future organic growth.

In the many areas where Chesapeake is the dominant player, we believe it's game over in competing with us for future growth opportunities.

I would also like to make this pitch for our company -- none of Chesapeake's growth requires a new or untested play to work.

Therefore, the risk profile assigned to our growth projections should be much lower than if we were a company with no track record of drillbit growth but all of a sudden had a new play that just might work out.

By comparison, all of our growth will come from plays in areas that have been working for us for years.

Most of these plays can be properly classified as the newly popular gas resource plays.

However, we weren't just clever enough to come up with that name for what we thought was everyday business strategy Execution 101.

Going forward, our plans remain the same.

We will deliver large increases in shareholder value by, first, delivering top-tier per-share growth in production achieved through a balance between drillbit growth and acquisition growth; secondly, exclusively focusing on finding and producing natural gas, thereby taking advantage of very strong long-term natural gas supply/demand fundamentals; and three, continuing to build dominant regional scale to achieve low operating costs and high returns on capital.

I will conclude by telling you that Chesapeake offers a truly any investment opportunity today -- visible, sustainable, high-level growth in a bargain basement valuation.

As the Company's largest shareholders, this management team is very energized by Chesapeake's competitive position in the industry today and the returns that we are likely to generate for our investors in the years ahead.

We hope to see many of you two weeks from now in either New York, Boston or Los Angeles.

Marc?

Thanks, Aubrey, and good morning to everyone.

What an exciting quarter!

Let's start by giving a little more color to our proved reserve replacement statistics and the investment that we incurred during the quarter to achieve those results.

To remind you, we began the quarter at 3.805 trillion cubic feet equivalent of proved reserves.

We produced 94 Bcf during the quarter, we acquired 380 Bcf, and we added, through drillbit and revisions, 364 billion cubic feet to end at 4.455 trillion cubic feet equivalent, a new all-time high for the Company.

Included in the 364 Bcf of drilling adds are positive performance revisions of 91 Bcf and 18 Bcf of positive revisions due to price uptick.

We are especially proud of the ongoing, multiyear trend of positive reserve revisions resulting from better-than-estimated performance.

On the cost side, we invested $292 million on drilling, completion and workover activities and 464 million on acquisitions of proved properties.

When compared to the 744 Bcf of total adds this quarter, this yields a cost-of-reserve add for the quarter of just $1.02 per Mcf equivalent.

Some analyst investors use what I call the all-in methodology, which adds the investments that we made for unevaluated leasehold acreage, both added from acquisitions and on-the-ground leasing activity, and G&G, costs -- i.e., the seismic activity.

Those categories received an investment of $253 million in the third quarter, which in combination with the previously stated investment of 756 million, would lead to a calculated $1.36 all-in finding cost number for the quarter.

Of course, these investments that we continue to make in acreage, unevaluated, seismic and so forth do not immediately add any reserves.

As Aubrey pointed out, these are investments for the future.

Not included in any of the numbers that I've just quoted are the non-cash (indiscernible) adds tax basis step-up related to a couple of our acquisitions and the asset-retirement obligations, which are non-cash future abandonment costs.

As of September 30, at wellhead prices of $5.84 per Mcf, $48.52 per barrel of oil and $26.77 per barrel for liquids, the present value at 10 percent of Chesapeake's proved reserves reached a new record level of $10.7 billion. 69 percent of the Company's proved reserves were developed and 31 percent were proved undeveloped as of September 30.

Let's turn to some balance sheet information.

We are approaching the date -- in fact, in just three weeks -- when the Company can compel conversion of our 6.75 percent perpetual preferred stock into common stock.

With that in mind, we saw investors decide to convert early during the quarter and in fact, during the third quarter, we had 14.3 million of the preferred issue that has already converted to common.

We expect the balance of roughly 135 million to convert on November 22.

We are in the process of increasing our revolving credit facility to a $600 million borrowing base from the existing 500 million.

We anticipate that this will be completed during the month of November.

Today, we have approximately 152 million outstanding under the facility, with an additional $74 million of letters of credit outstanding to support our hedging activity.

The primary reason for us to increase from 500 to 600 million is to provide added assurance that we will have the collateral necessary to post for our hedging activities in the event that prices explode, as we anticipate that they may well do during the winter months.

Cost trends for the service providers continue higher, as has been the case for all of 2004.

We recently increased our stated CapEx targets for 2005 to account for what we expect to be cost inflation during that year over 2004 of 10 to 15 percent.

Specifically, we have seen the following cost trends -- drilling rig rates are climbing, as I compare some of the costs that we're seeing today to costs that we saw six months ago; contracts for 2000 horsepower rigs are up approximately 8 percent during the six-month period of time.

On the shallow drilling areas, we've seen similar increases, 6 to 7 percent over the six-month period of time.

Cementing and logging have been up in that six-month period of time at least 10 percent, and of course steel prices, while up earlier in the year very significantly, have actually leveled off during this quarter.

We anticipate that our fourth-quarter and first-quarter of '05 steel costs will be flat with all of the previous surcharges baked into those prices.

Now for a few housekeeping items -- capitalized interest was $10.5 million for the quarter and $23.2 million for the nine months ended September 30.

Capitalized internal costs related to drilling and acquisition activities were $12 million for the quarter and 35.3 million for the nine months ended September 30.

These numbers are included in the earlier numbers that I quoted related to expenditures related to reserve additions.

You may have noticed that we are increasing the fully diluted share count guidance beginning in fourth quarter of 2004.

This is due to a recent emerging issues task force release that instructs companies to consider any contingently convertible security as converted, regardless of whether the security is "in the money" or not.

This affects our 4 1/8 percent preferred stock, which was issued in the spring of 2004, and has such a contingent convertible feature.

Previously, that was not included in our share count.

As well, you may have noted our estimates for potential stock-based compensation for 2006.

You may remember that the rules for expensing stock options remain a very controversial point.

In fact, recently, the rules for implementation were delayed from January 1 of 2005 to June 15 of 2005.

We have attempted to be very, very conservative in our estimates for 2006, and basically, the increase in the estimates here over 2005 relate to the partial-year implementation, they relate to our expectation for a substantially higher Chesapeake stock.

Again, we're trying to guess what the actual implementation rules will be with respect to previously granted stock options that will begin vesting after June 15 of 2005.

It would be my expectation that, as we move forward, the rules may very well again be delayed or changed and this estimate will prove to be way too conservative.

Finally, Aubrey has spoken about higher production for 2005 and introduced our 2006 organic production estimate of 8 percent.

Let's analyze what this means to Chesapeake in terms of free cash flow.

Using a $6 NYMEX price for 2005 and 2006, which is significantly below the forward strip today, we estimate that we will generate operating cash flow during these two years of at least $3.25 billion.

The midpoint of our production guidance is 407 Bcf for 2005 and 438 Bcf equivalent for 2006, or 840 Bcf equivalent total.

Assuming drillbit replacement costs of $1.60 per Mcf equivalent, which is higher than the current quarter significantly, our maintenance CapEx is 1.35 billion, leaving crude discretionary cash flow of $1.9 billion in this two-year period of time.

Said another way, we can meet these very exceptional growth rates with only 42 percent of our expected cash flow.

In fact, it is entirely conceivable that, if current strip prices become the reality for 2005, Chesapeake will generate $2 billion of EBITDA in that year alone.

With that very happy thought, we can turn it back over to the moderator for questions!

Thank you, gentlemen.

The question-and-answer session will be held electronically. (OPERATOR INSTRUCTIONS).

Ellen Hannan of Bear Stearns.

A couple of questions on your production guidance, one for the fourth quarter.

It looks like you are guiding down on the oil side.

Is there anything in particular (inaudible) --?

It's really I'm going to say more rounding.

Let me turn to that real quick, Ellen.

It's down about 13 percent or so from your absolute third--quarter levels.

I wouldn't get too excited about that.

We will just say that, for right now, we are comfortable in that 98 to 99 Bcfe range and the 15.88 is kind of a fit number, a plug number to be in that range.

If you look ahead, Ellen, you essentially see flat guidance on oil all the way through 2006.

If you contrast that with our prior guidance, what we have done is kept oil generally flat.

It varies mostly with acquisitions and the true growth is being generated in the gas area, which is 89 percent, 88 to 89 percent of our total mix.

All right.

A quick question, Marc, on your balance sheet -- the increase in deferred taxes from last year into now, do you know off the top of your head how much of that is step-up on the basis of the assets that you purchased?

I know what it is for the quarter.

Let me see if I've got that number for the year end here, or for the total year.

As I flip to that, if you've got another question?

I do.

I have one other.

Unfortunately, it's for you too but if you can just think about this.

You spoke quickly;

I may have missed your comments on collateral that you needed to keep aside for your hedging purpose.

Today, the number of letters of credit we have out on just hedging arrangements is $74 million.

It varies daily by the movements in the price deck.

I think that the total amount, if we were maxed out at every single hedging arrangement that we have, is about $200 million.

That would require double the amount of hedging that we have on today and require mark-to-markets that would move against us pretty significantly.

Okay, thank you.

Ellen, I will come back to the answer as soon as I find the tax basis step-up for the year.

Great.

Thank you.

(OPERATOR INSTRUCTIONS).

Ken Beer, Johnson Rice.

(technical difficulty) -- my question, let's stick with the balance sheet for a moment, maybe we'll slide it in in a second but the balance sheet -- you are now under the 50 percent debt-to-total cap.

You've got what looks to be 3, $400 million -- soon to be available on your revolver.

As you look at the acquisition market and if you find an acquisition in the 3 or 400 $500 million range, would we look for that to be primarily ,if not 100 percent financed by debt as opposed to what you've done over the last 13, 16, 18 months, which is layer in kind of 50-50 debt equity?

I mean, are you at the point where you can go back to use your balance sheet as opposed to needing to go to the equity markets?

Yes, and also the other thing we can use, Ken, is our very considerable free cash flow that will be generated through 2005, 2006.

So, as you know, we tend to keep our appetite small on a per-deal basis, and so at this point, we would rely on cash on hand and cash flow and our debt facilities to handle anything that we might be interested in.

Fair enough.

I will limit it to one.

I might come back. (multiple speakers).

I have the answer to Ellen's question.

Ellen and everyone else, the quarter tax basis step-up -- and remember, this is a non-cash item that is kind of an accounting convention -- was $177 million, and that's the quarter only.

For the year-to-date, the number is $377 million.

I might also add that, in many other companies active in the acquisition markets, those numbers would not have been (indiscernible) in a depreciable cost pool and instead would be called goodwill, which we do not use.

Dan Morrison, Aperion Group.

On the reserve adds for the quarter, what is the -- on the acquisition component, how does that split out to proved, developed and PUDs?

On the acquisition component between proved developed and proved undeveloped, I don't have that number off the top of my head, Dan.

Okay, I'll get back to you on that.

I will look it up but I don't have it.

Okay, thanks.

Van Levy, CIBC World Markets.

I'm sorry, I attended late so maybe this question was asked.

But on your reserves, could you break out the CapEx required to convert the 4.5 Ts?

Could you break it up between oil and gas and rough-cut between PUD and VDs (ph)?

You're talking about the 4 -- did you say the 4 Tcfe of probable and possible?

No, no, your existing -- didn't you just raised your --?

Yes, to 4.5 Tcfe, so you want the division between oil and gas.

Oil and gas, PUD and PD (ph), and the amount of capital required to convert the PUD to producing status.

4.455 Ts -- 69 percent is proved developed and 31 percent is proved undeveloped, 88 is natural gas and 12 percent is oil.

I will get the exact number of capital expenditure necessary to convert that and answer that in just a minute.

Okay.

Just kind of a broad question -- obviously you've been one of the largest or highest growth rate companies in our sector, Aubrey.

Any -- I don't know -- thought to maybe slowing down a year or two and just paying down, trying to -- a lot of other companies are slowing down, generating a lot of free cash flow, paying down debt.

Philosophically, you know, how do you view the market place and would you consider doing that at some juncture?

We want to invest, Van, in the highest-return projects that we possibly can.

So, for starters, to go pay down a bunch of debt right now that trades at 110 that's not due for an average of eight or nine years and would generate an implied return to the Company of about 6.5 percent, but doesn't strike me as probably the best way to go create shareholder value.

On the other hand, we are operating 70 rigs right now; we are, on average drilling, wells that are paying out within six months, many of them paying out in three months.

We drilled a well the other day that paid out in 13 days;

I've never experienced that before it.

That was from a well that was at 7,000 feet, not 17,000 feet.

So we are in a time period where a combination of extraordinarily high oil and gas prices and relatively modest service costs and investments we made in the past that are now paying off lead us to want to spend a great deal of our free cash flow into drilling, because it generates the highest returns on investment.

We do have opportunities over the next two or three to contemplate what to do with well over $1 billion of cash flow above and beyond what we think we will spend on our drilling programs.

I think the view there is that there’s lots of places to spend that and we will spend it in the place that generates sized returns.

Okay.

The last question -- $1.02 finding costs -- fantastic.

Is there anything unusual that shaped that number?

Is that -- you know, how repeatable is that, if that number is going to go up?

We are still sticking with the number for the year of $1.60 and that's an all-in.

The all-in number you probably heard for the quarter was $1.35, so we did have a very nice quarter on reserve adds.

I would say that $1.02 or $1.35 are not sustainable numbers but nevertheless, we want to -- on the occasion when we handle it deep, our projection for what our reserve adds will be we sure want to highlight that.

For the year, we are still sticking with $1.60 and think that you should as well.

Great.

Excellent quarter.

Thanks, Aubrey. (Multiple Speakers).

And I have an answer to your questions.

Actually, one was from Dan and one is from you.

For our PUD development as of September 30, future development costs we have estimated at $1.471 billion, okay, 1.471 billion.

Back to Dan's question, the acquisition reserves for the quarter totaling 380 Bcf were 227 Bcf of PUDs and the balance were proved developed for the quarter.

Have you done a PV-10 (ph) on that number based on, say, 6 or $5 gas prices?

Fixed number, the full reserve report?

Yes, the new 4.55?

I'm dying to tell you this number.

The five-year strip yesterday settled at 6.55, okay.

If you use 6.50 and you use just $40 oil, Chesapeake's proved reserves are $10.859 billion.

We believe we could sell our investments in other companies and in drilling rigs and in our midstream assets for $200 million.

We believe, if we wanted to go sell our probable and possible reserves, which are 4 Tcfe, we would get at least $1 billion and probably 2 billion.

We have a NOL value of $180 million.

We have $2.7 billion of debt and if you subtract $850 million from our preferred stock, you get common shareholder value of about $8.7 billion to be shared by 267 million shares of stock; that's $32.54 per share of NAV. (indiscernible) prices stay exactly where they are for the next five years.

That's 103 percent potential upside in our stock price.

Now, wouldn't you have to convert this, your 267, just your fully diluted and knock out your 850 because you are in the money (indiscernible) liquidation value, the preferreds would convert, right?

At that price, you would be in the money on all issues and you would take an add-back preferred amount that we subtracted off and then divide it by -- (technical difficulty) -- million shares, which is the fully diluted -- (technical difficulty).

What is that?

When you do that, what is that number?

Let us come back to you.

We will do that while we answer the next -- (Multiple Speakers).

I think it will be materially different but --.

Jeff Mobley, Raymond James.

Good morning, gentlemen.

Great quarter.

A lot of my questions have been asked; just a couple of quick questions.

Is there any new information you can share with us on your deep Delaware Basin gas play in terms of any new acreage?

I think your first well is due to be decision around Thanksgiving.

Then as a follow-up, I was just curious if you could give us the status of when you expect additional Mayfield wells to be TD-ed?

I think you have five in progress, if I'm not mistaken, and another long lead-time.

I didn't know if that's a second-quarter event next year or a first quarter.

Okay, let's see.

The play that you are speaking about isn't -- for those who aren't familiar with it -- is a play that Anadarko kicked off in Loving County, Texas and it involves drilling wells to 15 to 18,000 feet.

Anadarko's best well, I guess, (indiscernible) recall the name of it -- (inaudible) 30 Bcf well -- we're drilling our first well called the J. A. Haley, 1-31 (ph).

We will be down around end of December on that well.

We have been very aggressive in competing for acreage in the area.

Anadarko was on their own for a while; they have not been for the last year or so.

We now have about 50,000 net acres that we've put together or the equivalent of two townships.

We remain an active acquirer of new land in that area and expect a material ramp-up in our activity level in 2005.

One of the highlights for us, Jeff, something that we think is pretty neat -- you know, a lot of people are wondering what we saw in the Permian Basin, a mature, played-out oil basin, and wondered why we had such a high level of interest in the Permian.

Well, 5 years ago, when we had no assets in the Anadarko Basin, people said that was a played-out basin as well, and we've now going out there and in five years put together a company that, were our Anadarko Basin division to stand by itself, it would be a top 20 producer of gas in the U.S.

We've built that in just five years.

We are into year two basically in the Permian Basin, and we see there are a lot of deep gas plays that are beyond the imagination and the scope, operational scope, of many people who have been there for years. (technical difficulty).

This can be a material play for us going forward, and we believe we can transfer some other things we do well in the deep Anadarko into the deep Permian Basin gas plays.

Thank you.

Just on the Mayfield wells, when will those be decisions?

Your next (indiscernible)?

Well, let's see where we are.

I thought somebody might ask that.

We have 16 wells that are in production at this time.

Our EUR for those wells on a gross basis is 19.6 Bcfe to date, ranging from a low of 1.1 Bcfe to a high of 44.

We have had initial production rates of 16.4 million from those wells.

That's average per well.

Average per well, thanks.

We now have 11 wells drilling in the area, of which 1, 2, 3, 4, 5, 6 are sprayer wells and others are Marrow and Atoka wells.

Specifically, I would just say, if these wells take about six months to drill and with six rigs drilling springer wells, one well per month is a pretty good estimate, or three wells per quarter.

Okay, fantastic quarter.

Thanks a lot.

Returning to Van Levy's question about as fully converted and what the difference in valuation, back to Aubrey's strip-pricing estimate of approximately 650 unconverted, the value was 32.50 assuming full conversion of the preferred, adding back the 851 million of value and then using a higher share count of 348 million shares, the value is $27.50 per share.

Any follow-up to that?

If not, we can move onto the next question.

Joe Allman, RBC Capital Markets.

Aubrey, besides what you just talked about in terms of operations, was there anything really noteworthy in any of the other areas that stand out amongst your portfolio?

I would say the most noteworthy thing is that there really is nothing that stands out.

I think this is clearly the most distinctive thing about our growth.

It's not dependent on one play or one region working.

It's on a balanced approach geographically; it's balanced from a depth perspective, and its balanced between exploratory and drilling.

So, one of the reasons that Tom and I continue to buy stock in the Company and continue to like holding what we have is that the risk profile of our growth, going forward, while not zero, is quite low because we're not betting on any new thing.

If we have new things -- and I just mentioned one of them in response to Jeff's question about our deep Permian Basin gas play in Loving county -- that's all incremental.

We don't count on those kind of things.

So that's why we have been able, over the last three years ,to so consistently beat our estimates (indiscernible) for 12 quarters in a row we've had to raise production guidance.

We are constantly at work in new plays, whether it be in eastern Oklahoma, in the Arkoma, in the Anadarko, in the Permian or in South Texas or in the Ark-La-Tex area.

We are constantly searching for new places but only tell you about them after we've brought them online.

when you guys are doing an NAV analysis like you did just a few minutes ago, when you're talking about your probables and possibles, if I'm not mistaken, you're actually holding the value per Mcfe constant.

I think, in your latest presentation, you were using 25 cents.

So, I mean --.

That's correct.

So I mean, really to do a fair valuation with the higher gas price, you increase that?

You know, what we could do -- and I thought about this and actually Van's question makes me want to make a couple of changes here -- but really what we could do is take those probable and possible reserves, model them at a PV 25 or a PV 30 number, which would change with different price decks over time, and that might be something we do.

If we did -- and one of the reasons we haven't is the number ends up becoming even more ridiculous than it is now, the gap between our stockprice and the gap between NAV (ph), because it would be worth a lot more than 25 cents per Mcfe.

My guess is, at a PV 30, you would be talking still probably at close to $1 now in value.

All right, thank you.

Edward Okind (ph), Basil (ph) Capital.

I was just wondering if you would comment on your dividend policy, going forward.

I know you raised the dividend level at a time but with all of this cash coming in, what are the plans?

The plans are to review it every summer, which we have done every in the last several years since we reinstated the dividend, and we raised it to 18 cents per common share last summer.

While it is an item of discussion at every Board meeting, we really only formerly act on it once per year, and we would take another look at it summer.

Typically, we've tried to keep it somewhere between the 1 and 1.5 percent yield range compared to our common stock.

Okay.

I just wondered maybe if you could just go over your calculation of the NAV just very quickly one more time.

I just missed the first part of it.

The question is what is the NAV at, say, 650 and I said that's convenient because the five-year strip closed yesterday at 655.

The number to make the math a little easier -- about $10.9 billion.

The math becomes really exceedingly easy if you think about it this way -- every 50 cent change in gas prices, holding oil flat, creates a $1 billion change in our NAV.

So using fully diluted metrics, every 50 cent change changes our NAV by $3 or about $3 per share -- or about 20 percent on our existing stockprice.

So, we've continued to see the five-year strip move up.

If you want to do the reverse and say, what are you trading at today?

We can go backwards and see that, right now, the Company is trading as if gas prices will be about $4.25 forever versus the $6.55 that we see in the forward five-year strip.

Okay, then the other (indiscernible) I believe NOL (ph) and I believe one (indiscernible) equity value.

Oh, the other asset value was $200 million for our midstream assets, our drilling rigs, our investments in Pioneer Drilling and miscellaneous assets.

That's 200 million.

Then we have 4 trillion cubic feet of gas equivalent probable and possible reserves.

We have very conservatively valued those at 25 cents per Mcfe.

Certainly, if we were a buyer, we would pay more than that, and my discussion about PV (ph) 25 or 30 would lead to a higher valuation that 1 billion, but that's what we used.

Then our NOL is about $500 million and using our tax rate of 36 percent, we've given that a value of 180 million.

I'm not sure Marc pointed that out but it does lead me to another point, which is we are one of the few companies today not paying current taxes.

If I'm not correct, we paid no current taxes or accrued no current taxes in this quarter.

That is, again, a distinctive characteristic of us, going forward.

Did that get to your NAV questions?

You bet.

Thank you.

Jeff Robertson, Lehman Brothers.

Could you talk a little bit about the investment you all made recently in Greystone and how you see that playing into your overall exploration program as a way to find new opportunities?

Then secondly, would you look for similar investment opportunities in South Texas or some of the other new areas that you all have entered over the last year?

Yes, great question, Jeff.

The last five acquisitions that we've made of size have been from management teams that were backed by private equity.

Each of the teams was backed by a different provider of private equity.

So in those processes, we got to know these management teams pretty well, got to know what private equity players give, and also what they get.

Our view was that we might be able to construct a business model that would be more attractive to these management teams on a go-forward basis than the traditional one, where the management team keeps 10 or 20 percent of the equity and the equity provider puts up all the costs of G&A and also deals.

We and the guys at Greystone, Joe Bridges and Mike Geffert sat down and they said we really don't want to give up equity, and we really don't want to go back to New York to get our money.

What if you guys provided us with G&A support and in return, we provided you with First Call on our ideas?

You know, would that be he a win-win?

That way, we don't have to wait until they build the reserves and go buy them at an expensive price, or have to participate in an auction; we can be acquiring the reserves on the ground floor as we go forward, both from acquisitions and from the drillbit.

For the management teams, they get to keep 100 percent of the equity.

We think it's a great business model.

We are pleased that we and the Greystone fellows came up with the model, and we do think it has applicability to other situations where management teams are considering whether they go back for private equity or whether they do a deal like that with us.

And so, in areas where we think they can be helpful -- it's not going to be in the Anadarko Basin or the Arkoma Basin, but in some areas where we're not yet fully where we want to be and Ark-la-Tex is one of those areas, we definitely believe some affiliations like this can be very value-added for us.

Reserves under that situation then, Aubrey, they will not be on your books until you actually acquire them, right?

Yes.

All we're doing right now is writing monthly checks for G&A.

If they come up with an acquisition idea, then -- and it's one where we're not independently pursuing -- then we would buy it with them 50-50.

If we go drill a well -- and by the way, of course then we would book reserves if we bought 50-50 along with them -- if we went and drilled a well, we would pay 50 percent of the cost and they would pay 50 percent, and we would book the reserves.

There is a small promote on the first two wells drilled and each prospect that they bring us but after that, it's heads up.

David Pickens (ph), Deep Haven (ph) Capital Management.

Good morning.

Could you talk a little bit about how this increasing strength in your organic growth profile might impact what you do in terms of making acquisitions as we look forward?

Has it changed at all, kind of your outlook or your appetite?

I don't think so because actually all we've really done is express, going forward, our views about organic growth that we've achieved in the last three years.

If you look backwards, our organic growth rate has been about 11 percent.

If you look forward, we're now estimating that it will be 10 percent.

That's a doubling of where we've historical been.

So in my view, we really haven't done anything other than just acknowledge the overwhelming weight of evidence that piles up here every day, which is our organic growth rate is considerably above 5 percent and we view now 10 percent and I would probably put the words "at least" in front of that 10 percent.

In terms of the impact on acquisitions, we really don't separate acquisition success from drilling success because we think that they work together.

Today, we're drilling wells on leasehold that we generated ideas on ourselves, as well as leasehold that we bought in acquisitions.

So, our view is that drilling success leads to acquisition ideas, and acquisition success leads to drilling opportunities and they really work hand-in-glove together.

I would anticipate, going forward, that they will as well.

The difference is, with our expanded cash flow ability and debt-carrying capacity, that you would see a lot less equity issuance going forward than what you've seen in the past couple of years.

Okay, thank you.

Brian Grad (ph), B&T (ph) Asset Management.

Hi.

Could you just go over a little bit -- are you calling the 6.75 percent preferred?

Has it been called or have you not issued a call notice yet for that?

The way that works, Brian, is that of the common stock trades at $10.01, which was 30 percent above the conversion price when originally issued three years ago -- if the stock trades at that level for a month, after a certain date, then the Company can compel conversion automatically.

So it's really not a call; we just deliver a notice to the trustees saying that we've met the requirements of the stock trading above the required threshold and we've met the timing deadline, which was a three-year (indiscernible) call or no conversion.

That will happen near the end of this month;

I believe the exact date is November 22nd, assuming that the stock price stays where it is today or remains above $10.01.

We simply deliver it, and any holder of that 6.75 percent on the day before that call owns preferred, the day after owns the conversion amount of common stock.

Are there any additional dividends paid?

There are not required to be any dividends paid at that time.

John Berringer (ph), Loomis Sayles.

Yes, just a question regarding your organic production number.

The my math suggests that your organic production number fell from about 63 Bcf to 51 in Q2 to Q3 -- (technical difficulty).

Is that correct?

You are up year-to-year, but down (inaudible).

No, in fact we talk about -- I'm not sure.

I completely understand the question, but on the first paragraph of Page 2, we mention that our production in the 2004 third quarter was 7.7 Bcfe greater than the -- or 9 percent greater than what we produced in the 2004 second quarter.

We didn't provide a breakout of that between organic and acquisitions, but given the very small amount of acquisitions in the third quarter, most of that would've had to come from the drillbit.

We can give you that exact number.

I'm not exactly clear what you're talking about on the 63 Bcfe versus 52, unless Marc understands that.

I don't get it.

Let's see, just to read from the press release ,over 71 Bcfe produced in the 2003 third quarter and an increase of 7.7 Bcf or 9 percent over the 86.5 Bcf produced in the second quarter of 2004.

So I guess -- I think that your reference to the 23.2 Bcfe that's produced -- or increase in production for the third quarter relative to the year-ago number included 9.3 Bcfe which was generated organically.

Right.

Does that get you to about a 51 million Bcfe number for organic production for the quarter?

I tell you what -- it is not often we get stumped on these calls, but I think we're stumped.

Why don't we ask that we have a chance to call you back and work through that with you.

I'm sorry that we're just not following you.

We thought we had laid out pretty clearly that our year-over-year growth was 40 percent organic and 60 percent from acquisitions.

To me, the only mystery is, in the 9 percent sequential growth, how much of that came from acquisitions and how much came from the drillbit.

I think we can get that -- (multiple speakers).

(Multiple Speakers) -- off the top of my head.

I'm sorry, who are we speaking with?

John Berringer (ph).

What is your phone number?

617-346-9889.

I'm sorry for being a little obtuse.

Our final question from Van Levy, CIBC World Markets.

One last question -- Aubrey, we've all been through these presentations and people throw probable reserves around 1, 2, 3, 10 Tcf and they generally look alike and they look big.

Can you go through your probable reserves in terms of risking -- for instance, if you risk-adjust them, what percentage do you think would be successful -- convertible?

How likely would these be converted in, say, 4 to 5 years?

Kind of give us a sense of what your probables are -- higher or lower risk than a lot of this other stuff we've seen (inaudible).

First of all, let's start with it's all risk, okay, in the sense that if you look at the plays where we are building out 4 Tcfe from, we are using per-well reserves that are risks.

For example, Sahara -- we have 2500 locations to drill up there.

That's on land we already own and we know what the outcome is going to be because we've already drilled 600 wells up there at an average 0.6 Bcfe.

That includes wells that will do two and that includes wells that will do 0.1, okay?

So what we did is looked at a 0.6 number as being appropriately risked.

We went and risked another 16 percent and backed it off to 0.5 Bcfe and said, 2500 locations times 0.5 Bcfe, times 80 percent working interest on average times 80 percent net revenue interest.

That's a Tcfe of gas.

Now, that Tcfe, compared to a Tcf that somebody claims to have in some shale project somewhere, - whether it be the Barnett or the Fayetteville or the Caney or the Woodford (ph), -- it's very different.

Because we've already drilled 600 wells; we know what these next 2500 are going to do.

So, I've seen the same calculations that you've seen;

I've seen the same back-of-the-envelope math.

I've seen it done on our company ten years ago.

It's very, very different, our probables and possibles, from somebody else's, because they all have to do with plays that are already successful today.

The same with whether it be the granite and Cherokee Washes, where we think we have half a Tcf, or Sligo, where we have 300 Bcf of probable and possible, or the Hartshore (ph) (indiscernible) Woodford (ph) where we've already drilled over 300 Hartshore (ph) and coalbed methane wells in eastern Oklahoma.

We know, horizontally, now that we're going to find half a Bcfe per well, and that we've got half a Tcfe sitting there.

Again, very different from drilling wells in Goode (ph) county or (indiscernible) county or Summerville or wherever people are now talking about being able to do things.

So we're not saying those areas won't work; we're just saying the risk profile or the risk adjustment that you put on ours versus those can be very low because we've already done it through our drillings.

What we haven't included in our probable and possible band are plays like the deep Atoka play that I mentioned in Loving County, Texas.

I haven't mentioned some of our other projects in the Mid-Continent and in the Permian and South Texas areas that are not yet to the point where we think we can bring them to investors and say, we can predict outcomes with a sense of predictability.

So, that's where I would distinguish us from some other companies that now believe they have platforms for growth, after having not growth for years and years.

In say three, four, five years (indiscernible) this 4 Tcf, roughly what percentage do you think would be converted?

I hope -- I think it will all move in over time but I think it will be more than replaced by additional probable and possible.

Keep in mind, this is a company that spends as much money on leasehold and seismic as any company onshore in America.

We have almost 10 million acres or so.

I understand;

I'm just trying to validate this obviously of two years -- if you convert a T, T and a half to proved categories, then again it captures the risking discussion that you just talked about.

I think there will be a steady movement in and a steady replacement of the probable and possible and you'll see an increase in tandem, going forward.

Okay, thank you.

I think that was our last question, and we very much appreciate your participation today.

I hope you did read through the press release and notice that we will be giving a five-hour presentation in New York, in Boston and in Los Angeles.

If you are interested in attending, space is limited so we hope you will e-mail Robin Evans (ph) -- revans@chkenergy.com (ph), and we would love to see you on either the 16th, 17th or the 18th.

Take care and once again, thanks for participating in our call today.

Goodbye.

Thank you, gentlemen.

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