Chesapeake Energy Corp (CHK) 2002 Q1 法說會逐字稿

Please standby we are about to begin. Good day everyone and welcome to the Chesapeake Energy first quarter 2002 earnings release conference call. Today's call is being recorded. At this time for opening comments and introduction, I would like to turn the call over to Mr. Aubrey K. McClendon, Chief Executive Officer with Chesapeake Energy.

Good morning and thank you for joining Chesapeake first quarter 2002 earning release conference call. Before we begin I need to provide with disclosures concerning the forward-looking that we make during the course of this call. These forward-looking statements have described our beliefs, goals, expectations, projections, or assumptions are considered forward-looking. Please note that this company's actually may differ from those contained in such forward-looking statements. Additional concerning these statements is available in the company's SEC filings. Our comment this morning will last around 15 minutes and then we will move to Q&A. I will begin by returning into the three topics I focussed on during our last call in February. First our geological and operation tunes are performing at very high levels and we have once increased our guidance for 2002 as a result. Second our newly unveiled Mid-Continent exploration program is likely to produce significant results in 2002 and beyond. And third we continue to have a distinctive point of view on gas markets and the appropriate strategies to the old gas price volatility. These topics will remains consistent points of emphasis for us throughout the year. Financially and operationally our first quarter results were exceptional. In a quarter when many other companies lost money and production declines the period to accelerate Chesapeake earned $17 million or $0.44 per share on an annualized basis and we reported yet another sequential quarter production growth. Year-over-year our production increased by and even larger 4.4%. Consistent production gains continue to separate Chesapeake from the majority of our peers 2002 will mark our 10th consecutive year of production growth as a public company and our 13th since inception in 1989. We also want to alert you this is the second time we have increased our 2002 production guidance in the past 60 days. If current projected production levels continue to outpace our forecast further increases in production guidance are likely as the year progresses.

In addition our approved reserves increased from 1780 bcfe at yearend to 1860 bcfe at the end of the first quarter. Adding back our production of 42 bcfe and subtracting a 30 bcfe of reserve ads we picked up from increased oil and gas prices. We replaced 220% of our production during the quarter. Virtually all of this growth came from the drill bit. We only spent $1 million acquiring 2 bcfe during the quarter through our acquisitions department. Subsequent quarters in we have reached an agreement to acquire the 100 bcfe of Mid-Continent natural gas assets owned by Canaan Energy Corporation. Combined with April's successful drilling results we believe this acquisition has moved Chesapeake's crude preserves north 2 trillion cubic feet of natural gas equivalent. In addition we believe our probable impossible reserves now exceed 1 tcfe giving Chesapeake a total corporate resource base of atleast 3 tcfe. 90% of our reserves are natural gas and 90% are located in one focused in geographic regions the prolific and highly profitable Mid-Continent region. The Mid-Continent region is the third largest gas supply basin in the US and in 2002 Chesapeake should past British Petroleum to become the regions number one gas producer. As the largest producer with an unprecedented 25% market share of current Mid-Continent drilling Chesapeake has built economies of scale that are extremely valuable and would be able to impossible to replicate by anybody else. The results of this scale are lower cost, higher revenues and one of the highest profit margins in the industry. We will continue building on this Oklahoma stronghold in the years ahead because we believe focus produces excellent while diversification too often produces mediocrity. I would now like to return the Canaan acquisition for a moment. As many of you know we announced last week that agreement to acquire the small publically held Oklahoma city-based Mid-Continent natural gas producer. Canaan was attracted because we literally drive by their wells everyday on the way to our own. Because of Canaan's small size and limited financial resources we believe that they could not exploit their undeveloped acreage in the inventory as efficiently as we could. We targeted the company for acquisition two years ago and patiently and eventually bring our reserves into the Chesapeake fold. With Canaan's production of 21 million cubic feet per day is added to our own it the third quarter we will produce over 500 million cubic feet of gas equivalent per day. A track record of creating value out of these tuck in acquisition is excellent. They offer high quality property at a reasonable costs provide no cultural or social issues can be completed quickly and offer abundant opportunities to reduce SG&A in field operating cost. Plus we can increase wellhead revenues are renegotiating oil and gas sales contracts and they also provide [_____] drilling opportunities. We are very good to tuck in to deals and will do more of them as we continue consolidating operations in the industries most ownership fragmented region the Mid-Continent. Now I would update you on Chesapeake high impact exploration program that is presently in full swing as some background we hope you recalled that our strategy in 1998-1999 was proved that we could survive. In 2000 our goal was to prove that we were the cheapest way to place strengthening gas fundamentals. In 2001, our goal was to prove that could grow our production by at least 5% per year while successfully managing volatile gas prices. We believe our company had delivered on each goal each year. We are now ready to further evolve the perception of our company.

We believe this perceptional change will be accomplished through delivering successful results from our significant exploration programs in 2002. During the past four years we have quietly invested over $150 million building the geo-scientific land and 3-D seismic asset base to support an onshore exploration inventory that today exceeds I tcf on un-booked possible reserves. As [_____] we will be drilling these well when drilling costs are at a two year low and if successful we will be bring new production in the time of rising gas prices later this year and in 2003. Our projects are ambitious. The average potential reserve side meant to Chesapeake is just under 100 bcfe in the average depth of these projects is close to 20,000 feet. To reduce risk all of these projects have been generated in the areas of established productions and are supported by 3-D sides and a great heel of which is proprietary to Chesapeake. With regard to our exploration program you may recall we reduced our drilling program by 40% late last summer from 25 rigs to 15 rigs. As we saw gas prices headed down and drilling cost headed up. We simply decided to hold our fire and wait for joint cost to decline and forget price fundamentals to change. Starting several months ago we began lifting our gas hedges to lock in some very attractive gain and began putting the rigs back to work. We are now back up to 23 rigs and plan to be at 25 soon. You might notice that this strategy is its odds with many in our industry. Nevertheless with production declines accelerating in the industry drilling cost at two year lows and gas market fundamental strengthening. We believe now it is absolutely the right time to be drilling aggressively. Most important of these exploration projects is our Comanche Lodge prospect in the Deep Anadarko Basin in Western Oklahoma. We drilled a 24800 feet well in accountable we believe we will be significant pay in the Hunton formation. Completion operations will begin later this quarter. In the meantime we have started drilling several Morrow and Springer test in the Comanche Lodge in Mayfield areas. Here are the Morrow's and Springer is located at a depth of 20,000 and has been equally prolific to the Hunton in the two offsetting field as many fields in northeast remaining fields. The other Chesapeake exploratory are underway in the Deep Anadrako, Watonga-Chickasha, Chitwood, Bray and Arkoma basin project areas. This company specialty is deep gas drilling. 12 of our 23 active rigs are drilling to targets below 15,000 feet and seven of these are headed even deeper to depths of between 19 to 23,000 feet. We drill deeply for two reasons. First of all as were the gases, secondly we have much less competition below 15,000 feet. There are truly only a handful of companies in this industry that have the ability to explore as deeply as we did. My third point of emphasis is to comment on gas markets. I will begin repeating by what we said to you in February that the die is absolutely cast for the next both cycles on gas prices. Recent quarterly reports confirm that large production declines are kicking in this industry. In our views these are likely accelerate throughout 2002 and in 2003 as the rig count remains well below with required to maintain production. In fact we would not be surprised to see industry gas production decline by more than 5% this year or about 2.5 bcf per day.

Combine that with some amount recovery may be one to two bcf per day and you can do the math something we will have to give later this year or in 2003. We believe that is something would be price. It should now be obvious that the North American supply base south of the 60th peri loom can no longer provided significant supply increases no matter what the price of gas is. Prices will have to rise the level sufficient to destroy enough dominion so that supply and demand can reach a new equilibrium. We suspect that will require price well north of today's gas price. I would like to ramp up our remarks on gas markets for the comment about volatility. In a nutshell we believe gas price volatility is good and excessive volatility is even better. Why?. It is really easy for. We don't like to sell things for what they worth. We like to sell things for more than they what they worth. Spikes and gas prices caused by volatility will give us that opportunity every few years. Likewise consumers can do the opposite to protect their interest. Like it or not gas price volatility is here to stay and like any other risk in our business producers and consumers will have to start managing it their advantage as we have. Our goal is to sell the volatility challenge in our favor and generate returns on capital that remains significantly above the industries average. To summarize, let me reiterate Chesapeake distinctiveness. We have focus both on the product, which is gas and in the region, which is the Mid-Continent. Through this focus we have low cost and high returns on capital we are growing our production and reserve at a time when many other are shrinking. We are reducing our leverage per unit of approved reserves, we are skilled both drilling and acquisition. We believe we can deliver meaningful exploration outside in 2002 and finally we understand gas prices are volatile and we will use the volatility to our competitive advantage. I will now turn the call over to Mark for his more detailed commentary on our financial resources and results.

Thanks Aub and good morning everyone. I would like to begin today's financial and operating analysis while talking about some thing of interest to our debt investors, which are our improving balance sheet fundamentals. During the quarter our debt per mcfe are proven reserves decreased significantly into a new record low. With the companies nearly 1.9 tcf of proved reserves as of March 31, 2002 our long-term debt net cash is now just over $0.64 an MCF equivalent. With the ProForma use of cash to complete the announced Canaan acquisition this number will stay about flat and remain at record low number for the company. We have recently visited the rating agencies to update them on our operating strategies and progress and are hopeful that our long-term debt ratings will be positively reevaluated in the near terms. Looking to the numbers for the quarter I would like to highlight the continued low operating cost and significant cash margins enjoyed by Chesapeake this quarter. cash cost including LOA , SG&A interest expense were $1.39 per MCF equivalent. We generated net cash margins of $2.02 per MCF. Our guidance for cash cost remains unchanged for 2002 and with our open and locked hedging positions for this year we are anticipating we are anticipating industry leading margins to continue. We have recently increased our drilling program and I would like to review with you the drilling cost and completion cost that we are currently experiencing. Looking back to March 2000, which was recent industry low in cost we highlighted in February the cost that basically doubled to July 2001 at the point in time when we significant reigned in our drilling program. In February we pointed out that the cost had decreased significantly and we are almost back to the base that we enjoyed in March 2000. I can report today that the shallow wells continue to decrease slightly in cost and to give you an example of that our 75,000 feet Sahara type well we are currently enjoying it day rate of the footage of about a $11 per feet contrasted with the $11.75 in February. Similarly the completion cost for cementing and logging services is down slightly and I would estimate that it is down another 10%.

In our deeper drilling 16,000 feet type wells in the Anadarko basin, Cement field basically rates are unchanged from February maintaining the lower rates that we have enjoyed in the last six months. Again in that field completion services cementing, stimulation, open hole logging are continuing to trend down slightly from February and have nearly returned to their base rates as of March 2000. Drilling contracts rates are flat with what they we in February and overall we are seeing the shallow wells be about flat with our March 2000 base number in terms of total service cost and the deeper wells because of greater consolidation service industry up 10-20% from that March 2000 base. We expect to the next several months that the trends will be flattened service side an excellent time to drill and achieve much lower finding cost and further evidence of why we have increased our rig rates. And we carry on to our prime hedging position and explain the details. The complete details of this are attached to our April 29, 2002 outlook which is now posted on our website and all of the activity is posted by quarter for 2002 and 2003. But in summarizing the oil is pretty easy we have 1.3 million barrels of oil hedged in 2002 for the remaining nine months April through December this represents about 50% of our oil pricing and we have an average NYMEX price on that oil 2542. Also we have closed positions for that time $1 4 million which would add another $0.50 per barrel to the price for all of our oil. We have no oil hedged in 2003.

The gas situation is a little more complicated. We have 12 bcf of gas swapped in 2002 an average price of 328. additionally we have 64 bcf gas swapped in an average of 454. These are cap swaps and are fitting on your estimate for natural gas prices for the rest of the year some of these may be capped at NYMEX plus a dollar premium. We have callers for about 10 bcf of gas with a $4.4. I have run NYMEX prices as of last evening on our hedged position with our production forecast and can give you these well hedged realization estimates for the rest of the year. Based on well head realizations and NYMEX pricing as of last night our quarter number two pricing would realize $3.66 per mcf our Q3 would be 380 and our Q4 would be 391 because of the nature of the colors in our cap swaps most of the up sight would be preserved for prices if they continue to rise above last nights NYMEX price. In 2003 we have reversed all the 5.4 bcf of gas, which is still hedged in Q1 and that has locked in a $3.79. Our hedging games from those positions that were originally put on and now are locked out would be $10 million. So for those projecting 2003 realizations have simply added $10 million of revenue to our base case pricing. In reviewing our capital expenditures for the quarter our total GAAP booked PP&E increase was $84 million, breaking net down $1.5 million was acquisition related activity, we invested $7 million in leasehold, $65 million for drilling in work overs and had various capitalized cost including prepayments to non operators and other financial adjustments is about $10 million. 85% of our capital expenditure was spent in the Mid-Continent, 9% in Texas and the Louisiana Gulf Coast areas and 6% in all other US areas. Capitalized internal cost for the quarter interest was 1.1 million capitalized G&A related to drilling was 2.5 of total capitalized cost, which was included in my $84 million number of $3.6 million. Production trends continued as we have seen in the last several quarters of course we are our of Canaan to announce to all our production as US, 79% of our gas comes from the Mid-Continent, 17% from the Gulf Coast, and 4% from other areas. Oil 51% from the Mid-Continent, Gulf Coast is 18%, and our other areas from which are much earlier at 31% of contribute to oil production. So on a total mcf equivalent basis just over three quarters as from the Mid-Continent 17% from the Gulf Coast, and 7% from other areas. Little detail on our reserves at the end of the quarter. We were 71% developed and 29% undeveloped at a total 18,060 bcf equivalent. Gas was 90% of that total. The Mid-Continent reserves by volume were 85% of our estimates the Gulf Coast is at 7%, other areas 8%, and the values are roughly inline with them. The prices that we used at the end of the quarter were 319 mcf equivalent and 2632 for oil, which is up slightly from 1231. With those details I will turn it over to the moderator for question and answer session.

Thank you sir. Today's question and answer session will be conducted electronically. If you would like to signal to ask a question please do so by pressing the * key followed by the digit one on the touchtone telephone. Again that is *1 to signal to ask a question. If you do find your has been answered and will like to remove from the queue year may do so by pressing the pound sign. Once again *1 to signal and pound to remove yourself. We will pause just a moment to assemble [_____]. We go first to Phillip Z. Pace with Credit Suisse First Boston.

Good morning Aubrey and Marc. How are you doing? It is probably early to say but curious to know that you view as a likely outcome from drill bit reserve additions in 2002. What sort of range would you feel good about.

Okay this is marc good morning. It looks like to me that we are continued probably the current pace we were just over 200% drill bit ads in Q1 compared to production of course that excludes any type of significant exploration result that might come from Comanche Lodges some of the bigger projects. So it is just on that basis you know if you are looking at around 175 bcf production I think we will be somewhere between 300 and 350 bcf of ads in the drill bit section.

So nothing is booked yet for the results that Comanche Lodged.

Nothing is booked at this time out of the 100 zones.

That is correct, nice quarter guys.

Thank you Phil.

We go next to [Stephen Smith] with [Stephen Energy Associates].

STEPHEN SMITH]: Yes Aubrey in the past you have given some guidance as to finding and the expected findings cost and now things have been all over the place on service cost, but is there any guidance you can give you in terms you say atleast for the next year in terms of what kind of planning should we hopefully target.

Steve your right it is a little bit difficult to guess with the service cost situation we are seeing, certainly we will not be any worse than who are last year and I think without revisions we are sort of a $1.50 number of the drill bit side. Right now we are budgeting in the $1.20 to the $1.25 range and again that would exclude any extraordinary results from Comanche Lodge for example.

The other thing I would add is just Mark gave you same of the drilling cost number and he compared them with February would you compare them with the high water mark last summer that $11 of Sahara would be, so we really do think some aspects of what we are doing or down by 40-50% other components of the cost of drilling are not down as much, but one of the things that we do notice is that our cost as a percentage are down more in the Mid-Continent that they are in the Gulf Coast they are and we will assume and New Mexico areas mainly because the service industry here continues to remain less consolidated than it is in other areas and that simply reflects the kind of the history of the Mid-Continent. I am very optimistic that we can bring drilling cost somewhere in the $1.20 we are below range which we think would be a great achievement this year.

STEPHEN SMITH]: One followup question. You talked about playing the volatility of the cycle. One way you could do that would be the sort of this in the past is walking in some way some component of lower drilling cost today is that in your plans.

Steve we can really only do that through actually spending money when cost are low. Service companies see the same continued natural gas pricing curve that we do and they can guess that in 2003 and 2004 their businesses are going to be in better shape than they are today. All of them in good enough financial shape that they can wait for that time and so we have been able to extremely gather a number of two or three well commitments we were able to kind of keep people going through this track, but in terms of being able to lock in today's rate for year two would be really difficult. Instead what we do is go from 15 rigs to 25 rigs and be spending that much drilling dollars if we prudent we can during the trough of drilling cost.

Hold on Steve that we have taken the additional strategic move of adding our own rigs, we currently have 5 I cn see that may be increasing one or two and that does provide with a pretty hefty hedge against increase prices those prices are locked in, we run in that our own labor rates has company employees and really that significant part of our Oklahoma drilling program does allow us to control cost quite well.

STEPHEN SMITH]: I guess that sort of what I have thinking of a little bit, anyway thanks very much.

Thank you. Steve.

We go next to [Adam Wright] with Credit Suisse First Boston.

ADAM WRIGHT]: Good morning guys. With the finding cost you are talking about and the amount of money your spending on drilling it seems to me that the production guidance you are giving is either got some timing issues into or looks very conservative. Can you provide a little color on the ramp for the rest of the year.

I think the later part of your question the conservative nature of our guidance is probably the color would like to give. We have tried to very conservative and lay our targets that we will be able to exceed and I think that is just good in present corporate management on our part. We have a lot of up sights in projects we are working on right now. We could increased guidance coming in the next week, few weeks or months.

Further questions sir.

ADAM WRIGHT]: I don't have anything else that is it.

We go next to Kenneth H. Beer with Johnson Rice & Company.

Yeah hi guys, couple of questions were answered. Specifically that the cost side which I though was we are impressed on the [LOE] announced that just that the drilling cost remaining it low in terms of just exploration exposure obviously you are going the completion process right now, Cat Creek is there anything so far that would dissuade you from feeling like this has the potential to be the 600 bcf type of [_____], number one and then number two just on the production side if you do have a successful play here correct me if am wrong that is an area where you got infrastructure and you can bring that production on relatively quickly and I am assuming that is not in your numbers at all.

Ken I think that is right. Let me after come up to the start. Technically we are not completing the well right now. We still have drilling rig over the well. We have tied back our final string of component after filings. We have got new pipe all the way up and down the hole now we will be running we got power shocks and liners it is kind of a lot of a internal plumbing that need to occur lets it call it an x four week. It is actually one chrome tubing with the drilling rig and then break it down and then bring on a completion unit and then actually at that point we will start the completion process. As I think year may know we were not able to open whole logs over the Hunton we were able to get a good case stool log and like very much what we see in the Mid-Continent which is the pay there of a choice you may feel in Northeast may feel that is what the offsetting well produces from as well. So we don't expect to see any gas there until late this quarter or may be even in the start of third quarter. We will have it will be slightly slow that we believe it treat at the well head more volumes are very significant and we can take an Exon plant nearby it is only about 50% full if this develops into the kind of play that we think it will then we might even have the opportunity to build our own processing system. We do not have anything extraordinary built in our production estimates for this area and mainly for this reason and again as Marc said we are trying to be conservative on production guidance and we do not feel like we need to aggressive given the organic growth story here that is underway and now we would emphasize the diversified nature of the production growth and it can be the last time where is the growth coming from it is honestly coming from in all areas that I have mentioned there in my prepared remarks it really a engine that is hitting on our [______]. I feel like it is a forgotten one in the aspect of your question.

It is just the production being able to come under quickly you pretty much address.

I just wouldn't, we do not have anything modeled to come until the third quarter in that point we have modeled for 15 bcfe well average in the area has been in the mid 30s and has done well as it has done well in the 63 bcfe and that is from the Hunton only. We do have more Springer wells out there that are drilling right now to the relatively I guess in this area shallow depth of 20,000 feet.

When do you expect those to be down Aubrey?

Those will be down in the 90 days now first part of the third quarter.

And again those if successful infrastructure there and can be brought on tracking impact kind of late third or early fourth quarter production?

That is a standard Oklahoma gas and we have got planning of infrastructure out there and I would like to remind everybody that may be you are seeing what has happened of [Rockies] gas prices in the last month or so. We are in a basin that is long infrastructure and short gas and we have been in Canada and we know the Rockies are like this and places a long gas and short infrastructure and the difference is profitability and really it is one of the key features of the Mid-Continent. So, we will drill wells quickly and get them on quickly.

Right and thank you guys.

Okay thanks.

We are next going to Barry Sahgal of Brean Murray Company.

Aubrey you talked about your exploration program and the profiling by depth. Due you think you can elaborate a little further in terms of what percent of your budget is below 15,000 feet and what percent of your production is you know in the deep and super deep category and just some color as to what we should be looking at year to two years down the road?

Barry, I do not think that we have the breakdown for year production by depth that is an regional question and I really never been asked about that and actually we have not thought about ourselves and either but we get certainly obtainable. On the drill bit side I have mentioned that we had 23 rigs up and 12 of them going below 15,000 feet and I would suspect that we again going to have this exactly calculate and I would expect that it would be approximately 75% and that our total dollars would be below 15,000 feet.

And what percent might be below 20,000?

And that would be and I may call it 19 because we have a couple of wells by towards 19 and that is 7 out of 23 so this amount is that will be about 30% and think about those well being more expensive and my guess is that probably at 40%.

If you would have to jump forward two years and how sort of guess out to how your reserves might be distributed by depth? Can you give us some kind of early readers what we should be we looking for?

Well we will anticipate having an increasingly deep buyers to them and I do not think the most important categories that we think about are they are there 90% gas and we would not expect that to be different and the next important is where are they and would expect that to be different at 85% Mid-Continent amount and suspect that would probably creep up to 90% overtime. I have really given all thought to you before now to your question about how many of those reserves will below 15 and 20,000 feet.

No. I am just trying to get the vision thing.

If it is the vision thing that we are going what the gas is and if I can paraphrase really you know that is what is left to do and we have built a company that has always been comfortable drilling difficult wells and we are now drilling in an area where predictability results is much easier and the predictability decline is much easier and we really are competing at depths were no other public company really spends a lot of time focussed and it just requires a different mind set as most people have to have district office appear rather than headquarters. The companies that really do well and is below 15,000 feet category are some private companies and those are guys we are always in discussions with to try to buy them and had been in the past as well in the future.

Good enough and thank you.

As the sale prices go up the shallow wells end up having better rates to return especially once we get up to $4 plus and in the future if we see in the year 2003 and 2004 gas a little bit higher, we can increase our growing activity there also.

And the drilling cost does not tend to go up as much at least now to shallow areas because of the diversity of the service providers. Most of the few product companies are developed companies.

That is really fine and I would time in with this that you know that kind of characterizing the deep well is only being the deep well and looks like everything we drill in Oklahoma is multi and will progress to a lot of shallow and deep well and it is not a single target that it was unsuccessful that the well is not completed and we get somewhere money back or a profitable well over the shallow is on. So, it is another reason not to kind of think about 19,000 per gas versus 14,000 per gas and we are likely to have and hope soon in many of the holes.

Thanks guys.

RAY DECAN]: Hi and good morning guys. I had a question on the in terms of the increased budget. Where would you expect most of the emphasis will kind of evenly spread throughout the three areas or mostly focused on the Mid-Continent at this point?

Well of course it almost exclusively focused on the Mid-Continent as is our overall budget. You know we are spending 65% of our 98% and about 70% of our budget is developmental in nature and about a third is exploration or at least is targeting an exploration component to a pretty much the way that we are writing down this quarters expenditures would be below that we would see going forward and today's budget is about 80 plus percent, 85% Mid-Continent oriented, and 15% in all other areas of the company.

RAY DECAN]: Okay and if you look at the full year production guidance that you raised and how much that would be due to the acquisition Canaan versus?

We have added 40 bcf assuming that Canaan has acquired in July 1, 2001 counting purposes at $21 million a day. So, of the 7 bcf increase, 4 was for Canaan and 3 are basically improved production performance and drilling results in all other areas of the company.

RAY DECAN]: Okay great and when you say you may add one to two rigs you know with that just there may be a little bit of elaboration on the first question and do you think you walk those in for a period of time or?

If you want two rigs that we might add to our own five rigs of the 23 that were working and cannot use in terms of one or two rigs in both way. One or two we add to our overall fleet and those may be rigs that we buy as well. So you can by them we will clearly be more or less locking in rates and though there were adding right now again we are providing a good slog of incremental business to the contractors and they are responding with competitive pricing.

RAY DECAN]: May be just one more question on your hedging philosophy. I mean where would you start to relay on some hedges in 2003 and does not look like gas above $4 is too sustainable is too sustainable what are just you thinking there.

I think it may be bit different from that. I think that would require $4 a gas to either cost rig counts go back up and add some supply or above $4 a gas to chase away some demand. If would you have said $5 a gas we might be agreeable. So we are not hedge or out of fear that prices really want to go down we only like the hedge we think prices are clearly over done and basically we don't think that is the case. We will require a number of at least for the four in front of it and suspect we have give opportunity that look at some strong for our plus pricing within the next six months or so.

RAY DECAN]: Okay great thanks a lot.

We go next to [Terry Hoe] with [Provident Investment Management].

TERRY HOE]: Good morning guys. You typically have about a $1 million or so of capitalized interest is that pay you again this quarter.

Yes it was 1.1 million this quarter and that has been the same amount basically for sometime plus or minus a little bit. We have very little in the way of undeveloped acreage given the company and the size and that is the only source of capitalized interest of curing cost on that $60 plus million evaluated undeveloped acreage is just capitalized at our overall capital cost of which is just above 8%.

Terry let me clarify. We actually have a huge inventory of undeveloped acreage which is very aggressive on that went into the forecast tools so we manage the number that our balance sheet and we are trying to keep it more or less under $75 million just out of corporate conservative it isn't, but the undeveloped acreage inventory continues to expand market. I think you said we spent $7 million just on adding new acreage this quarter along on a pretty strong run rate that we will be adding acreage at a time when most other companies are not active in the field like we are buying releases.

TERRY HOE]: Okay and then also apparently the $79 million risk management income is a non-cash item. Is that correct?

That is right FAS 133 requires us to mark like everyone else is certain of our positions that don't qualify for hedge accounting treatment to market every quarter. And the last quarter and the quarters before that we had most of the amount as required in some of those positions of course a prices started to recover and have gone up substantially in the last eight weeks, it became less valuable for me hedging perspective if you will and so I think all analysts if not all analyst and certainly most companies because of the unpredictable nature of that FAS 133 treatment are clearing their earnings estimate in certain cash flow and EBITDA which aren't affected by that without regard to FAS 133 swings.

TERRY HOE]: Okay Thank you.

If you would like to signal to ask a question please press * 1 in your phone at this time. We got next to [Dave Zimmerman] with [Eden _____].

DAVE ZIMMERMAN]: Hi on the Canaan acquisition again is the operating cost of same as your average $0.55 somewhere in that range.

David it is a little higher low 60s, but our experience with these things has been it we can generally over the course of the first year of ownership lower that by a nick or so as we go in and combine the properties with ours and operate the wells more efficiently through provide pump or out and better overall field management practice.

DAVE ZIMMERMAN]: Price real us is going to be NYMEX plus the dime or something like that.

Well that is NYMEX minus the dime just gets you delivered in the Oklahoma pipes and really that number is probably 12 to $0.13 and then you had gathering charges and I think our overall corporate differential this quarter was basically $0.30 or so. There properties are no difficult than ours. They may actually they have a little wider differential and because again they don't have the stroke that we have with the midstream guys and we will also try and go in and re-negotiate oil and gas contracts and typically we are able to get about a nick up on realizations as well. so I think give us the year with these properties and more or less look like ours today.

DAVE ZIMMERMAN]: Okay and also you got two or three of drilling inventory that you have fought with his company we tread also be comparable to just speak generally.

We don't think anyone has the exploration outside that we have but in terms of other acquisitions that are available out there we got Canaan outside with pretty normal for what we find so call it a lesser up sight than the average we just stated. Well not for the average acquisition, but not certainly they haven't what we have spent building the exploration inventory that we have, but it is nice developmental drilling and you see that kind of type game stuff that we do everyday. We don't buy these things for the exploration outside. We buy them for the stability as a reserved base and for the development and drilling opportunities that they provide. We rely ourselves on our core efforts here to develop a big exploration outside place.

DAVE ZIMMERMAN]: Are you continuing to use the same mixed cycle number you have used in the past or is there any change in your thinking there.

When you say mid-cycle number in terms of making acquisition. We tested against about four different price decks all the way from 250 price deck or we make sure we are still making money on a 250 flat all the way out strip pricing and so it is matrix, but we have not increased our basic pricing formulas that were used over the past three years to be successful with acquisition.

DAVE ZIMMERMAN]: Okay great. Thank you.

Thank you.

We go next to [Eric Dybeslan] with Lehman Brothers.

ERIC DYBESLAN]: I guess the only question that really had has not been answered, but I had the $22 million of notes that you seeing us repurchase, which notes were those.

Eric those were the 7 and 7/8 notes entirely and we did have cash that was sitting on our balance sheet that was in excess of what we though our needs would be short-term and I had some notes offered to us and we did retire to those notes. So the 7 and 7/8 issue which is due in the spring of 2004 not only has $128 million outstanding.

ERIC DYBESLAN]: Okay I guess you don't pull those simply because of the maturity.

Simply because of the maturity you are right.

ERIC DYBESLAN]: Thank you.

We go next to [Evan Templeton] with [RBC Capital].

EVAN TEMPLETON]: Hi guys just a little quick question most of mine have already been answered, but as far as on the summary of the balance sheet it looks as if the other long-term liabilities went from the $4 million to $43 million. I was just wondering what is going up and what is the competition is?

We are looking for that. Competition of that is related to our hedging that those are marked-to-market positions some of which are negative and they are in the long-term category because they are in 2003.

EVAN TEMPLETON]: Okay and that is line to be driven.

Yes virtually all of it.

Gentlemen we are seen by with no further questions signal at this time. I would like to conference back for any closing or additional comments.

Okay great. Thanks for your participation today. We will be here all day. If you have additional questions for us just give us a call. Thank you. Bye bye.

This does conclude today's Chesapeake Energy first quarter 2002 earnings release conference. There will be a rebroadcast of this conference available today at 11 central time running through May 13, 2002 at Midnight central time. To access simply dial 719-457-0820 and use the pass code 563-827. Thank you for your participation you may now disconnect.