Chesapeake Energy Corp (CHK) 2002 Q2 法說會逐字稿

Good day and welcome to the Chesapeake 2002 earnings release conference call.

Today's call is being recorded.

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

Please go ahead, sir.

Good morning and thank you for joining Chesapeake's second quarter 2002 earnings release conference call.

Before we begin, I need to provide you with disclosure concerning forward-looking statements that we will make during the call.

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

The company's actual results may differ from those contained in such forward-looking statements.

Additionally, information concerning the statements is available in the company's SEC filings.

Our comments this morning will last about 15 minutes and we will move to Q and A. I will begin by discussing the two topics we have emphasized during our last several calls.

First, our consistent delivery of organic production growth.

Second, our first-class on-shore deep gas exploration program and the unrecognized upside it represents.

Financially and operationally, our second quarter results were very strong.

Chesapeake earned $23 million or 52 cents per fully diluted share on an annualized basis and generated cash flow of 96 million on an annualized basis.

In addition, we reported our fourth consecutive quarter of sequential production growth.

This time, we were up 4% and virtually 100% of this quarter's production growth came from drill bit growth.

Year-over-year our production increased by an impressive 11%.

Consistent organic production growth continues to separate Chesapeake from the majority of our peers. 2002 will mark our 10th consecutive year of growth as a public company and our 13th since founding the company in 1989.

We want to alert you we increased production guidance for the third time this year.

After starting the year with mid-range forecast of 164 bcfe we are projecting mid-range production of 179 bcfe.

An increase of 9% from our first estimates for the year and up 12% from last year's production level.

Moreover, our crude reserves increased from 1,780 bcfe at year-end to 1,986 bcfe at the end of the second quarter, an increase of 12%.

Our reserve replacement rate was 342% during the first half of 2002, well above our annual goal of 175%.

We project ending the year with roughly 2.2 bcfe of approved reserve and production run rate of 510 to 520 cubic feet of gas equivalent per day.

In addition, we believe our probable and possible reserves exceed 1 tcfe, giving Chesapeake total corporate reserve face resource base of more than 3.2 tcfe.

We believe Chesapeake has the most focused resource base of this size in America, with 90% of reserves consisting of natural gas and 90% located in one region, the prolific and highly profitable Mid-Continent region.

The Mid-Continent is the third largest gas supply basin in the U.S.

Chesapeake is the region's number one gas producer, having passed Apache in '01 and British Petroleum earlier this year.

As the largest gas producer with 7% share of production and an unprecedented 20% share of current Mid-Continent drilling, Chesapeake has built economies of scale in this area that are extremely valuable and will be almost impossible to replicate by anyone else.

We aggressively utilize our scale to lower costs, increase oil head pricing, generate one of the highest profit margins in the industry and consolidate other high quality gas assets.

In the past month alone, we reached agreements in four separate transactions to acquire assets that are a perfect fit for our Oklahoma operations.

You might wonder who the sellers are and what their motivations are.

The first is a small, private company that a few years ago might have planned on going public.

It is too small.

One is a large Canadian producer, selling its only Mid-Continent assets.

The other two are utility and pipeline company exiting the EMP business in Oklahoma.

Both of the events are caused by some of the turmoil in the down-streamed gas business these days.

Our track record of creating value from these tuck-in acquisitions is excellent.

They offer high quality properties at a reasonable cost, provide no cultural or social issues, can be completed quickly and offer abundant opportunities to reduce G&A and fee of operating cost, to increase well-head revenue by renegotiating gass sale contracts and provide substantial drilling opportunities.

We are good at these tuck-in deals and will likely do more of them as we continue consolidating operations in our Oklahoma stronghold.

Ideal financing for these transactions has always been two-thirds long-term debt and one-third equity.

Equity markets aren't generally in sync with the time to make good acquisitions.

So, this is a great time to be buying gas reserves, it is not a very good time to be issuing equity and so we will have patience in how we finance these transactions down the road.

Our Mid-Continent focus is especially valuable at a time like this.

Today gas in the Rockies and Canada is selling for about $1.25 per mcfe and we are selling gas in the Mid-Continent for about $2.75 per mcfe.

At these levels, most Rockies and Canadian gas production would not be generating any positive cash flow, as transportation charges and production taxes would fully claim oil head revenue.

In essence, the Mid-Continent is short gas and long infrastructure, while the Rockies and Canada are long gas and short infrastructure.

That is a recipe for low returns and that is why we continue to concentrate our activity in the Mid-Continent.

Now, I would like to update Chesapeake's high impact exploration program in full swing.

Some background for you, during the past four years we have invested over $175 million building the geo-scientific land in 3-D seismic foundation for one of the industry's most exciting programs.

Today we are drilling the 29 rigs, doubling our activity since last summer.

We were the first big producer to reduce our drilling and drilling cost stayed high and gas prices started to soften.

However, starting last winter, we began to ramp up again.

Drilling costs began to decline and now they are fully 50% off peak.

In addition, the visibility of better gas prices in '03 and '04 is before us, as well.

As

We like to drill when our competitors are nervous about the future and drilling costs are low.

Now is such a time.

The results are starting to roll in.

Most importantly, after being hopefully months about the significance of our Comanche Lodges prospect in the deep Anadarko Basin in western Oklahoma, we now have confirmation of its success.

On Monday of this week, we announced gas sales had commenced from the Cat Creek 1-19 in the secondary objective of the well Upper Hunton.

Within the next few months, we plan to add more perforations, complete the middle Hunton and co-mingle the middle-Hunton and the upper-Hunton.

The timing will depend on how quickly we can work out gas transportation capacity.

It is still early, gross reserves for this well should total 25 bcfe and for the prospect should total about 250 bcfe.

That would be about 130 bcfe net to us from the Hunton alone.

We believe full development will require drilling 7 more wells, 2 of which will get under way in the next 30 to 60 days.

The pleasant recent surprise for us at Comanche Lodges had been the success of our first two Morrow Springer wildcats.

Drilled at 20,000 feet, these wells confirm the existence of a significant secondary play for us in the Comanche Lodges area, which could lead to 100 bcfe of additional net reserves at Chesapeake from this area.

We plan to develop our extensive lease hold in this area with 2 to 4 rigs, giving us overall 4 to 6 rigs commitment in the greater Mayfield area for at least the next year.

Additional Chesapeake exploratory efforts are under way in deep Anadarko Arkoma, Bray, Cement, Chitwood, Knox and Watonga-Chickasha areas.

Of our 29 wells drilling right now, 13 are targeting depths below 15,000 feet and of those, 6 are heading to targets below 20,000 feet.

We expect to report additional exploratory successes as the year rolls on.

None of these wells can individually make more than a 1% addition to our reserves or 2% reserve to production, collectively they can make a big impact.

Our success today in many of the exploratory project areas is why we have been able to deliver four consecutive quarters of production growth, while the overall industry is in the process of delivering its fourth consecutive quarter of declines.

Stated most simply, we are a prospect-rich company in a prospect-poor industry.

This is our most important competitive advantage and we think it bodes well for our company's future evaluation in the equity markets.

I would summarize my comments by reiterating Chesapeake's distinctive.

We are focused, both in products, with gas in the Mid-Continent region.

We have low cost and high return on capital.

We are growing production and reserves at a time when the industry production is declining.

We are skilled in both drilling and acquisitions and we believe we can continue delivering meaningful exploration outside in an '02 and beyond.

I will now turn over to Marc for his detailed commentary on our financial results and outlook.

Thanks, Aub.

Good morning to everyone.

I would depart from my normal review, by first addressing certain market-induced questions.

Over several days I have received numerous questions relating to CHK's exposure to Williams ,

and similar companies.

I can assure you we have no hedging exposure to any of these companies.

In fact, 100% of our hedges today are with Morgan Stanley, as historically most of our hedging activity has been.

A small portion is with Goldman Sachs and we occasionally use

.

As the largest producers of gas in Oklahoma, we, of course, must have counter parties that purchase our product.

Our largest purchasers today are CMS, about 29% of our revenue;

Reliant, about 24% of our volumes and revenue;

ONEOK, 13%,

and Duke, 11% combined.

Together, nearly 80% of our total monthly sales.

We do not sell to Williams, Dynegy or Calpine.

Next, we have received some inquiries related to our universal shelf filing and the announcement made on Monday.

We have been working on this filing for sometime, viewing this as excellent corporate fiscal housekeeping and very routine.

To provide more timely and easier access to capital markets and provide for opportunistic acquisitions and financing of those acquisitions, this is very standard practice in our view.

That being side, my timing was rotten and our Houston-based attorneys were evidentially tied up with Enron and we didn't get it filed several weeks ago, when markets were more stable.

Obviously we didn't expect the market meltdown and the timing was my fault and clouded the success of the Comanche Lodges release.

Our capital formation plans have not changed at all.

We plan to conduct drilling and development program, funding from operating cash flow.

Our larger acquisition program will be funded by combination of debt and equity, which typically averages two-thirds debt and 1-3rd equity.

Our bank facility, not viewed as a permanent capital resource, will be used from time to time as a temporary capital source, to be funded out with long-term debt similar to notes outstanding today.

Some portion of equity issuance only at the right time.

Obviously, today is not a favorable time for equity additions and we will not consider issuing equity security at this time or price.

During the last six months we, have retired approximately 43 million of our seven and seven-eighths note, bringing the 11 of the note issuance down to approximately $107 million.

Our bank debt June 30 was $45 million, a wash with the notes retired in the previous six months.

So, we have increased reserves by 12% and production significantly in the last 6 months while debt remains essentially flat in equity gross, excluding impact of market to market FAS 133 requirements, which are irrelevant to this calculation.

In conjunction with risk management program, we recently entered into $300 million of fixed to floating interest rate swaps to take advantage of the low and falling short-term rates.

I am pleased to tell you that today we traded out of those position for $8.6 million cash gain, which will actually be received today.

The book effect will be to reduce interest expense over the period of the hedge, which was 2 years.

This gain effectively on a cash basis reduces current year interest expense by about 8%.

We expect to be able to reenter into similar swaps as the equity and debt market settles down.

Let me turn to the more routine disclosures we normally make regarding financial and operating results.

First, on the capital expenditure side, in this quarter, we invested $70 million in drilling and routine work-over that was capitalized - recompletions, et cetera.

During the quarter, we expended $16 million for lease hold, $8 million for seismic activity and processing, and capitalized $6 million of other field-related expenses for a total of $100 million on the drilling- lease seismic budget.

Acquisitions during the quarter were $136 million, of which $132 million was

, which closed on June 29th.

While Canaan was closed on June 29th, the acquisition cost and the related cash decrease and debt realized at that time, no production at all was booked for the second quarter related to Canaan.

During quarter 2, we capitalized interest of $1.1 million, which is essentially the same run rate as the previous quarter and lower than the previous year.

So, for the total 6 months of 2002, we capitalized $2.3 million of interest cost.

Internal costs primarily payroll, related to exploration and development program was $2.8 million for the quarter, again about the same run rate as previous quarter.

For the total of 6 months in 2002, we capitalized $5.3 million in costs.

Production volumes by area.

In the Mid-Continent, we produced 32.3 bcfe of gas in the quarter, 479,000 barrels of oil, for total equivalent production of 35.2 bcf equivalent.

That is 81% of production volumes.

Gulf Coast represented 5 bcf of gas, 125,000 barrels of oil, for an equivalent of 5.7 bcf or 13% of our total production volumes.

All other areas of the company were 1.2 bcf of gas, 219,000 barrels of oil, 2.5 bcf equivalent or 6% of overall volumes.

Let me turn to our hedging.

We have released complete hedging schedule to you effective with the release last night.

In it, you will see for the remainder of '02, we are about 95% of expected oil volumes hedged, or 1.47 million barrels in Q3 and Q4 combined, at NYMEX average price of $25.23.

For '03, yesterday we entered into trades for 360,000 barrels of oil for Q1 at a $25.10 average or about 45% of expected volumes during that quarter.

In the remainder of the next two quarters for '02, we had 51 bcf - 51-and-a half exactly, 63% of expected volume for the remainder of '02, still on cap swaps and collars.

In addition to that, we closed out 44-and- a-half bcf for 7 and a quarter million dollar gain, which should add 9 cents for gain on all volumes during that 6-month period of time.

Looking into '03, we are relatively unhedged, complimenting our view that prices are likely to rise in '03 and '04.

We have 5.4 bcf of gas locked in January at $3.79.

However, we have $16 million of gains that we have taken or will take - locked in.

About 9 cents again, realization for all volume expected during 2003.

While we did not have the unbelievable basis blow-out for Mid-Continent gas that has recently been seen in the Rockies and Canada, we were negatively affected in the quarter primarily in the month of June.

We began to see that basis change as early as quarter one, where we had about 28 cent company wide average differential.

By June, our average differential was 47 cents, significantly above that level.

To be specific, one of our major delivery hubs is Panhandle Eastern Pipeline, a gas basis noted in most publications.

Negative differential in April was 11 cents to Henry Hub.

By June, that had moved to 35 cents to 24 negative change for us, which affected a significant amount of volumes.

This, of course, had the effect of offsetting revenue generated by significant production increases basis, which is a function of liquid prices in gas markets, has come back to normal levels.

We have taken action to hedge Mid-Continent basis at very attractive levels starting 2003 and through 2009.

In fact, in 2003 through '05, we have almost 100 bcf per year hedged at 15 to 16 cent negative differential to Henry Hub.

Additionally 20 to 30 bcf is hedged for 2006 through 2009, at 16 to 17 cents.

It is our view that as gas competition comes from the Rockies could increase the basis differential in Oklahoma during that time.

Our all in cash cost structure was 76 cents in 2001, including lease operating expenses, production taxes and general administrative costs.

This was the second lowest cost structure in a peer group comparison of 15 companies that we regularly present in compared to average of those pier groups of 99 cents, we were 23% lower than the average.

This quarter, our cash costs were 83 cents, up 7 cents for mcf over the 2001 average, or about 9%.

The fact is operating costs are up, as costs for labor primarily health and Workmen's Compensation costs, general liability insurance costs and general field costs increase.

Added to the cash operating structure is the fact that we are not cash taxpayers and have more than overcome any small cash cost increase with revenue and interest expense hedging gains and the value of net operating losses allows us to not pay any cash taxes.

Our severance taxes were already low relative to industry.

As pointed out Monday in Cat Creek we received reductions for drilling in Oklahoma and production taxes over the next year.

Our G&A remains low as our focused acquisition strategy allows us to increase reserves and production without any cost increases in the G&A area.

These facts, when combined with our still high revenue per unit, result in superior margins, which allows higher reinvestment, which has been reflected in true organic production growth, such as seen in the first 6 months of 2002.

We are very proud of these results.

Comanche Lodge, while a very significant discovery, is by no means the only pony in our tent.

The acquisitions we are making, based on gas price estimates, will be in all likelihood be exceeded in 2003 and 2004 are accretive in all matters to shareholders.

When considering the integrity of our financial statements, one needs look no further than the goodwill on pier company's books.

Yet, Chesapeake has never booked any goodwill associated with even one acquisition and does not believe their exists such a thing in the oil and gas production sector.

Had we followed industry practice, we would have over $500 million more book equity, resulting in book equity of net capital of 50%.

Our strategy of purchasing long-term Mid-Continent-based natural gas reserves financed by earnings and appropriate level of long-term, unsecured debt, we think is a strategy that will result in superior common shareholders returns, as it has over the last 2-and-a-half years.

When combined with pricing making hedging strategy, we believe the risk profile of our business plan is very, very low.

I would like to turn it over to questions and answers now.

Moderator.

The question-and-answer session will be conducted electronically.

If you would like to ask a question, press the * and 1 on your touchtone telephone.

Again, to ask a question, that is * 1 on your touchtone telephone.

We will pause for a moment to assemble the roster.

We will take the first question from Stephen Smith with Stephen Smith Energy.

Great quarter, Aubery.

Just wanted to ask about the protected 2.2 for the end of the year, in terms of keys.

How much would that probably include of the Comanche Lodge-Hunton discovery?

My guess is by the end of the year we will have probably 50 or 60 bcfe booked, Steve, out of a total potential of really close to 200, we include the Springer in there.

So, kind of 130 from Comanche Lodge and Hunton.

I suspect by the end of the year, we'll have probably one producing well and 2 wells drilling and 4 wells will qualify as such.

Probably qualify now and I suspect it will be in the numbers.

Do outside engineers at Hunton give you the immediately adjacent offsets?

Is that the pattern?

Yes.

The spacing here is a little different because we are on a 1440 acre unit, which is kind of a legacy from the earliest days of exploration in western Oklahoma, when you had the massive units.

But, yes, based on the 3-D we have, you can probably book the whole structure, but I am sure we won't choose to do that.

You mentioned 6 wells drilling deeper than 20,000 feet.

I assume all 6 are wildcats?

Could you mention at least the 2 or 3 most imminent and what they are going after?

Let me clarify one thing.

I did say 6 going to target below 20,000 feet.

It may not be below 20,000 feet right now.

Steve, I would say an area like Bray will be very important to us.

We have significant well underway right there.

That will be down in the next 60 days on.

Cement continues to be a great area for us.

In the last six months, we drilled in some lower Springer sands that have not produced anywhere in the structure yet.

And I think out of over 1000 penetrations in Cement, they are only 5 or 6 wells that have even penetrated these lower Springer sands.

We actually have a 20,000 foot well planned for the area in the Springer sands are at 15 to 16,000 feet.

That area, which we require through DOB, through Gothic and Anson and lease acquisition on the ground, continues to be a great performer.

Watonga-Chickasha continues to be an area where we - our 3-D there that was acquired through Gothic transaction through Amoco and continues to give us results we are drilling to 310 objectives in a field produced 4.14 tcfe.

Basically, the 310 has been completely unexplored.

Most of the 3-D is proprietary.

Finally, we have an Arbuckle well underway there, targeting the big structure we see on 3-D and we are 18,000 feet - we are at about 17 or 18,000 feet and on our way to 19,000 feet there.

So, really we think this quarter and pretty quick succession in the next 60 days, will have more wells down.

It really does highlight this is our specialty.

We have the people and prospects, the land and seismic inventory for a foundation.

None of this is factored in our production forecast.

I know for some people it may look like we are overly conservative on the production forecast, but it is really the way we choose to run the company and the way we like to put our guidance, which is to give guidance that you can absolutely take to the bank.

Then, if we can be successful in the some of this exploratory activity, then you have production upside on top of that, which we have been able to beat our estimates for four quarters in a row.

Thanks, Aubrey.

Our next question comes from Ken

with Johnson Rice.

Few questions.

One on the financial side.

Marc, on the bank debt line, you said $45 million out at the end of the quarter.

With the $165 million in acquisitions - if I remember correctly, your bank line is $225 or $250.

Where does that settle and do you have additional flexibility above and beyond that number?

Sure, our bank line as it exists today.

Our borrowing base is not the limiting factor there.

We have chosen to be at $225 million level.

We do have flexibility, obviously, to increase that obviously significantly the indentures would prevent up to $400 million today or maybe a little more with the acquisitions of secured bank debt.

It is just not our style to use short-term secured bank debt like that for any long period of time.

We can obviously fund these acquisitions pending and will close in July and August, out of our bank line and we have adequate liquidity and cash resources to do that.

We'll be looking to take those into the debt market sometime in the near future and put them on long-term, unsecured notes.

Okay.

Effectively, kind of reload the gun to get the bank line down to virtually nothing?

That is correct.

We have no maturities other than the $107 dollars of 7-8ths, which mature in March of '04, until well well-out in the future.

We think the matching of the long-term structure, along with equity we have described, is the right capital structure for the long-life assets we have.

Got you.

Shifting gears for a moment.

On the Cat Creek well, as well as the Springer wells, kind of the thoughts - the well is producing in at around 17 or 18 million a day.

Kind of where do you think once you commingle with the upper Hunton, if I remember correctly, there is physical constraints on that well, which limits you at 20-odd million per day.

Where do you think maybe some new drill Hunton production might come in if successful?

Also, the Springer formation, what kind of production rates might we expect from those types of wells?

Marcus Rowland: Okay, Ken.

Let me clarify a couple of things.

The well did test over the weekend at 17 million a day.

We pinched it back on Monday afternoon to 1864 choke.

We have been producing 15 million per day on higher flowing tubing pressures.

That's really where we want to keep the well.

We may choke it back a little more.

These are very different wells from what you might be thinking about on the Gulf Coast, where you have wells come in at very, very high rates and very high pressures.

They are over pressured.

Here, we are in an area where three of the nearest offsets to us came in at rates of 10 to 15 - I say offset, I mean in northeast Mayfield somewhere, to be more precise.

Came in anywhere from 7-and-a-half to 15 million a day in all between 25 and 50 bcf.

These wells have been on line for 25 years or so.

So, we would expect when we get the middle Hunton on, to have a well that can do somewhere between 20, 25 to even 30 million a day, depending on the middle Hunton's capability and where the upper Hunton is at the time.

We think we will be ready for the gas - for those kind of gas turnings at that time.

Our two new wells won't be down for another 8 months or so.

During that time, we will be working to make sure that we have multiple outlets for our gas.

Keep in mind, that our upper Hunton gas, which again - we are wanting you all to recognize, we produce from a secondary zone that only produces in a measured quantity in one other well in northeast Mayfield.

This is a real surprise for us and allowed us to be overly conservative to think about on the middle Hunton.

But, any rate, by the time we get the wells down in 8 months, we will have the capacity to take away gas that will probably be somewhat sour from the middle Hunton.

This upper Hunton gas is sweet right now.

It is running at 1 part per million and we expect the middle Hunton to come in at 300 parts per million, compared to northeast Mayfield Hunton gas that runs 1500 parts per million.

There is an Exxon plant in the area.

There is a shutdown of the British Petroleum plant in the area, that we are interested in.

So there's going to be lots of different ways to go with gas.

We have been fortunate this upper Hunton is sweet as it is and can go ahead and put it on-line.

In terms of Springer in the area, you can certainly drill dry holes in marginal wells and drill 20 bcf wells also.

Initial production rates in this area can be as low as 5 million a day or as much as 15 million per day and so, our first two wells will probably be somewhere in that range and we have additional wells.

A third well drilling right now and will be drilling additional wells in that area.

We plan to keep two rigs on Springer and two rigs on the Hunton for the foreseeable future.

Okay.

One last question and then I will hop off.

If you just do the math on your second quarter production, you add roughly 18 or 19 million a day for Canaan.

Then, just roughly add the four acquisitions at the end of the third quarter - you looked at another 28 million a day.

That would suggest that you would be well above the odd 10 to 520 that you talked about in exiting the year.

Is that kind of the - if I do - I wonder did I do the math right?

Number two, is your guidance just as you are giving yourself a little wiggle room?

Yes, your math is right.

We averaged 477 million a day during the second quarter.

It is 19 million a day that you can add from Canaan, plus 28 million.

Keep in mind, the 28 million won't all come on effective July 1st.

Right.

I am exiting the fourth quarter.

If you are thinking about exit rates safely assume that we have been very conservative in our guidance and we hope to be able to continue to deliver surprising like we have in the past four quarters on production.

Okay.

I think you mentioned this.

The volumes on exploration size, whether Springer wells, those should be added to the numbers; is that fair?

That's fair to say.

Thank you.

Our next question comes from Adam Lee, with Credit Suisse First Boston.

Good morning, guys.

Follow-up on the timing of the expenditures that are out in the course of the rest of the year, particularly on exploration program and when you expect other acquisitions to close?

Also, on the acquisitions what is the overlap with your existing properties, versus new areas?

I will take the first and last and let Marc take to the middle.

The overlap is perfect.

There are four different transactions.

One is a private company that actually was a sister company at one time to Canaan and so, not only do they add to the property's overlap hours, but almost a complete overlap on Canaan.

They separated ways about 10 years ago.

The property sets are almost identical and almost the same size, as well.

The second acquisition is a Canadian company that acquired assets as a result of buying Montana Power, which owns North American Royalties and had assets in western Oklahoma, that again, are a good fit for us.

We are buying assets from utility and assets from a pipeline company, both of which are exiting the Mid-Continent because they have small positions here.

So, these are exactly what we are in business to do.

It is what we have been doing the last four years.

It is what we will be doing for at least the next four years.

In terms of when they come on, let's see -

I have it.

The smallest $15 million acquisition will be closed hopefully this next week.

That will be a July acquisition.

The other three acquisitions will be late August, the largest of which is a split acquisition closing which will close August 20th and August 26th.

It is possible that one of the acquisitions could lap into the first part of September, but most likely, Adam, it will close all three in September or August.

And you operate all these properties?

There are three types of properties.

One is they are properties that are non-operated interests in wells we already operate.

The second type of property is a well that the acquire operates and then third type of well is a non-operating interest that the - neither us - we don't operate and a third party operates.

So, we like those almost as much as we like the operated properties because it gives us a wedge into the section from which we can propose additional wells and end up acquiring additional wells.

Okay.

End of the year reserve estimate, just to sum

as to undeveloped might be?

Undeveloped, I am sure it will be, where it has been consistently for the last two years, around 30%.

Thanks.

with Investment Management of Virginia.

What do you think about the affect on short-term gas prices when Canaan brings in new production from Canaan express, does that in itself cause a blip down or is everything going to be ready for it and other factors will influence gas prices in the next couple of months?

Hi, Freddie.

We don't follow the exact timing of big platforms that come on or in this case Canaan express pipeline.

I thought that was spring '03 completion.

What we do is focus on supply.

We know that the depletion rates are running 25 to 30%.

We can look at the last 16 quarters of production and see that 11 of those 16 quarters production have been down.

We think Canada now is falling off pretty quickly and we will assume the decline curve will be pretty close to what we have.

So, we are clearly in a lower priced environment today than we were two or three months ago.

Actually, we think that makes us a lot more confident about '03 and '04.

Because tcf overhang that existed last winter is down to 350 bcf and we expect to get worked off through the fall.

We probably will end up with over 3 tcf in storage and maybe as much as 3-2 or 3-3.

The supply trends will continue to be negative.

I think even with the occasional big slugs of gas that can come from deep water plays, the decline curves are so well established on-shore and on the shelf, they simply can't overcome the system of production declines that the industry is facing.

So, we think it will continue to see quarterly sequential production decline throughout the year and think into '03.

That is what will cause a substantial rise in gas prices in '03 and '04.

Wildcard, of course,is somehow the stock market performance in the last couple of weeks is predicting some national economic depression, which is so obviously, we would be negative on demand side.

I don't know the odds of that, but given - not zero, but we don't think they are strong, either.

Thank you, Aubrey.

We will go next to Ellen Hannan with Bear Stearns.

Good morning.

I just had a couple of questions.

One, on the forecast for your '03 production gross, Marc, can you give us a feel as to how much will be organic versus the tactical acquisitions that you have been doing?

The production growth forecast right now is consistent with our overall way of calculating or estimating what we are going to be doing.

Virtually all of the production growth if you think about annualized exit rate, and then compare that to the production forecast, virtually all of it, Ellen, will come from drilling.

Our tuck-in acquisitions have been running $20 to $50 million spread out over the entire year.

So, they don't tend to have a great effect on annual - on mid-point basis throughout the year.

We don't at all forecast for any production growth from theoretical acquisitions.

We have increased guidance based on the drilling and based on the acquisitions we actually have in hand.

We don't look forward into '03 and say we make $100 million or even a $50 million acquisition.

That is not budgeted at all.

The other question.

On the cost of basis insurance you purchased for Mid-Continent, how do you account for that and what does it cost you to do that?

Actually the cost of those is like a costless color.

It is a swap-up basis, where we are fixed and the counter-party is going floating on that.

How they do that with the various utilities and so forth is really transparent to us, but it is costless.

We have locked in a fixed - call it 15 cent basis, where we will be paid - it is all done on derivative or cash settlement.

There is no physical to this.

We will look at NYMEX and we will calculate it to the various Mid-Continent delivery points that we have estimated, based on volumes that we are selling.

For example, in Panhandle eastern, there will be an index set for that like an index set for Henry hub and if it is 15 cents in the middle of 2003, no cash changes hands.

If it is 20 cents then we get paid a nickel.

If it is 10 cents, we pay a nickel.

Okay.

It is not off on the Henry hub or NYMEX, it is one of the industries out in the field?

It is all related to Henry hub for NYMEX.

The two elements in hedging are to get the price level right based on NYMEX contracts and to get the basis right and basis for western producers has been the most difficult probably to handle.

If we were to sell $4 gas contract on NYMEX for June '03, with our 15 cent basis swap, we have guaranteed ourselves a Mid-Continent delivered price of $3.85.

Okay.

And, Ellen, the rational is when we look to the rocky accident, we see gas infrastructure not adequate to take gas out.

We suspect there will be projects that try to bring that gas to the Mid-Continent.

In fact, Williams had one called Western Express that was going to bring I believe 600 million a day into the Oklahoma Panhandle and into the pipes going north to Chicago.

One of the fall-outs of the Williams debacle, that project was cancelled this week.

So, nevertheless, we still suspect Rockies gas will find a way to the rich prices we are getting in the Mid-Continent.

We don't want to lose the great - the small differential our gas has historically traded at here.

It has been as little as a dime.

Theoretically, we are giving up a nickel, but we think that was insurance against maybe a 20 or 30 cent move against us.

Great.

One last question, Marc.

Your interest expense, we assume you have borrowed money to make the acquisitions in the second half of the year.

You look like you are going flat down.

Is this a result of the swap or are you -

It appears the way we modeled it.

It is a result of the swap.

We realize a lot of the 8.6 million over the next couple of quarters on a book basis.

You know, again, we get back into cash and book.

We receive the cash today for the swap.

It will be amortized on market-to-market basis.

The shortest part of the curve is the most value we are collecting today so a lot will roll into the third and fourth quarter.

That is one factor.

The second factor is we initially plan to borrow under bank borrowing.

That is modeled in the rates right now.

To remind you, our bank borrowing is LIBOR plus 150 basis points on the lowest launch and LIBOR plus 225 on the highest crunch.

So, blended all together, looking at sort of today's 3 and 3 3/4 to 4% borrowing rate.

Very good.

Thanks.

Our next question comes from Ray

with RBC Capital Markets.

Good morning.

How you doing?

Question on the - Aubrey, you talked about acquisitions in the past at looking on pro forma basis.

What does this do to your debt bcfe?

I haven't done the math.

Is this similar to other acquisitions you have made?

I think so.

The characteristics are all the same.

We are trying to buy properties at a mid-teens rate of return, just on what we see and then when we do our lack-backs, which are generally at a year or two years later, here is the things that typically happened.

We have been able to lower lease operating expenses if we integrated the properties into our own pumper routes and into out own systems and these are scaled to reduce cost.

We generally have been able to go out and renegotiate oil and gas contracts.

We are the third largest oil seller in Oklahoma and the largest gas seller.

It gives us stroke with the mid-stream guys and the interstate pipelines to renegotiate .

Then, we start working the property and look for recompletions and the additional drill sites.

When we are all said and done, on a year or two later, we think we will be looking at 20 to 30% type return acquisition.

They are exactly like what we have done in the past.

In terms of what it does on debt for mcfe, every time we make an acquisition or a group of acquisitions, it temporarily moves up our debt per mcfe.

These are pretty small.

We are talking about pennies.

Then, if we are able to grow the reserve base and stay within our cash flow on drilling, we can never make another acquisition, these acquisitions would then start to contribute to the process of the de-levering of the company, which just to remind you over the last four years or so, has gone from about a buck 15 per mcfe down to -

64 cents prior to acquisitions.

Yeah, bump it up and then work it back down again.

Again, because of the high revenue we enjoy in the Mid-Continent and the low cost, we can carry more debt than most companies.

We will.

We are always going to pursue the strategy that we have right now, which is drill bit growth and company by acquisition growth and over time, the left hand side of the balance sheet will grow more rapidly than the right- hand side.

And the consequence will be lower debt per mcfe.

We still have a target out there of low 50s for mcfe.

Okay.

The properties in terms of undeveloped component, is it much higher than 30 percent?

[55]

It would be less than 30%.

I don't know if I have the exact number.

Marcus Rowland: I have got the exact number.

Canaan was 75% developed and so 25% undeveloped.

The largest acquisition is again the lay down of that 75% developed and 25.

The Canadian seller is 17% undeveloped, so very high PDP component.

The other two are 74 and 75% for weighted average of 76% developed.

Okay.

Just anything - you still see up beat about Canaan.

Nothing there?

It hasn't closed yet?

Canaan closed on June 28th.

We did not book production for the second quarter.

They are located four miles from us and we have hired a handful of their people and the property is fully integrated.

These other acquisition when is we next talk to you in October, will have been fully integrated, as well.

Okay.

Just on the deep drilling in the Mayfield area drawing deep wells right now?

Do you see rates becoming an issue if we start to get closer to $4 gas.

Do you think we might have a harder time?

I don't think so.

Although, clearly when we get back into the $4 price rates will be more expensive.

It is the reason we increased rig count from 15 in December and January to 29 or 30 today.

The other operators drilling out there are British Petroleum, would be St. Mary's and the

, a private company.

It is four companies primarily that have dominated this play.

Existing production, Exxon, Chevron, still have position out there.

In terms of deep rigs, I know - neighbors are bringing in a rig from California for us to use.

Probably given gas prices in the Rockies and the west, Oklahoma will continue to attract more rigs.

Keep in mind, we own 6 of our own rigs.

So, we always keep those busy and that helps us modulate some of our activity in terms of being able to keep rig rates lower than we otherwise would have been.

Okay.

Do you think you will keep that amount of activity 29-30 rigs fairly constant?

Yeah.

You know, through the remainder of the year that is what we are expecting.

We think that will put us in great shape to be delivering big new volumes of gas and '03.

I can't tell you when gas makes the move in '03, it really depends on winter weather.

If we get some, it will happen early in '03.

If we have another warm winter, I think it will take into the summertime, to work off inventory of overhang that we have.

But, we have a serious supply problem in the industry and the fly in the ointment is if demand continues to go down over time more quickly than supply does.

Certainly there has got to be a scenario for that.

We think it is certainly incompatible with $3 gas prices for gas demand to go down as quickly as gas supply.

If gas prices stay low, will you see yourself doing more acquisitions?

People may get frustrated and decide to sell?

This is a frustrating business at all times and cycles.

Yeah, I think - there is just lots of turmoil right now in terms of the down stream side of the gas business.

I can't predict where that is going to head with some of the companies.

These down stream guys have significant assets in this area.

We will watch that and continue to do what we do, which is pursue private companies and asset packages always come up when companies rationalize operations.

Can't see much change to it.

The flow tends to be kind of spasmodic, rather than even, so we just have to be always ready.

Okay.

Thank you.

Next to Phil Pace with Credit Suisse First Boston.

Good morning, Aubrey, can you hear me okay?

I thought it was a real strong quarter and I think you have addressed most of the issues.

At the purchase price you are paying for the acquisitions - I don't know buck 30 in mcf, could you walk me up to the net margin out of those?

I think so.

Keep in mind that we really don't allocate much to probably or possible and don't do any goodwill booking, as Marc talked about.

We always throw in high percentage immediately into the full cost pool.

Even though we know that each of these projects or acquisitions has unidentified upside.

If you basically look at an LOE of - 55 cents severance taxes around 20 cents, you have - if you are paying buck and a quarter, let's say.

You're really at a cash break even of $2.

No additional G&A.

Depending on how we finance it, you will be somewhere in the 60 cent per mcfe overall interest rates.

We look at it at overall 260 break even number, including full financing, assuming we don't use any of our home-grown equity to finance

, but otherwise you can look at it around 240.

So, that is the way we look at it.

In a $3 plus environment will give us mid-teen rate of return and obviously in a $4 environment, gives us higher than that.

Then, we go to work.

This assumes we acquire them and don't do anything with them.

We never acquire anything that we don't already have pretty good work plan already lined out for.

Also, any sense of the big owners in the basin are ever going to decide to consolidate elsewhere?

We talk about that quite a bit.

Number two behind us is BP.

Number three is Apache.

Apache at one time was 100% Oklahoma company.

They have a significant operation in Tulsa and have become more active in the last quarter after having not been active very much the last 6 months.

Neither of those two companies look for acquisitions in this area, at least to our knowledge.

We lose a fair amount, would be the company sponsored by

equity players.

The guys sponsored by MGP and Endcap and Yorktown, those guys.

Then, they turn around if they beat us, they turn around and offer companies to us a couple of years later.

So, we continue to see this kind of cycle play in other big drillers in the area and producers in the area would be Dominion, El Paso, EOG and Quest Star.

So, I just - when I see the trends play out, it seems to me over time, more of these companies probably care about other parts of the world than they care about Oklahoma, which we think bodes well for us.

That is great.

Thanks, Aubrey.

We will go next to Todd Wilson with Bret Smith Energy Group.

Hi, guys.

Just wondering what the relative reservoir pressures are between the middle and upper Hunton?

Since we haven't completed middle Hunton, we don't know.

We know while drilling that we saw greater pressures in the upper Hunton than middle Hunton.

That is why we completed upper Hunton first.

Okay.

What sort of pressure did you see in the upper Hunton?

The pressure differential was 3 to 4000 pounds.

As indicated by drilling weight needed.

Sure.

Is there any issues related to co-mingled the two zones?

No regulatory issues.

There will be gas quality issues.

We have to make sure the mid-stream will definitely not qualify for interstate transmission, which is four parts per million.

We will have to make sure we have well site treatment or we have a deal worked out with one of the gas plants in the area that has h2s- treatment facilities on site.

Sure.

Just to complete the middle Hunton, what all do you need to do to get it on stream?

We need to perforate it and then treat it in our treatment, we only have 20 perf holes open in upper Hunton.

We are very careful when we go in and perf the middle Hunton, we wanted to make sure we could fall off the middle Hunton or fall off the upper Hunton curve to get treatment over to middle Hunton.

Over the next two to three months, we hope to be able to complete that activity.

Sure.

Okay.

Good.

That is all I have for questions.

Mr. McClendon, there appear to be no further questions at this time.

I would like to turn the call back over to you for any additional or closing remarks.

That's great.

We appreciate your participation today.

And as always, if you have additional questions, please give us a call.

Thank you.

This does conclude today's conference.

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