山脈資源 (RRC) 2002 Q1 法說會逐字稿

Good day everyone and welcome to this Range Resources first quarter 2002 earnings conference call.This call is being recorded. State contained in the conference call that are not historical are forward-looking statements. Such statements are subject to risk and uncertainty which will cause actual results to differ materially from the estimated filings with the Securities and Exchange Commission. At this time I would like to turn the call over to Mr. John Pinkerton, President of Range Resources please go ahead sir.

Thank you. Good afternoon ladies and gentlemen and thank you for joining us. With me they are Tom Edelman our Chairman, Terry Carter our Executive VP, Exploration and Production, Eddie LeBlanc our Chief Financial Officer, and Rodney Waller our Senior Vice President. After reviewing the quarterly results I will turn the call over to Terry to provide an update on the company's E and P efforts and then to Tom for his concluding remarks. After Tom's comment we will open the call for question and answer section.

Earlier today we filed our first quarter 10-Q with the SEC, that is now available on our website as well as Edgar online. Now I would like to turn right to first quarter results. For the quarter revenues forward 42.4 million dollars, 32 percent 33 percent lower than the prior year period. Oil and gas sales fell 24 percent due to a 23 percent decline in realized oil and gas prices and 1 percent drop in production. Earnings from ITF fell 3 million dollars while interest and other revenues decreased 3.5 million dollars. Interest and other revenues for the first quarter 2002 included a 1.7 million dollars loss related to FAS 133 hedge accounting in the first quarter 2001 we recorded 2.3 million hedging gain. These charges again a percentage to FAS 133 and a represent while record the ineffective portions of our hedges that means the changes in our hedge as related to the basis differentials between how we physically sell that gas and how we hedge the gas on a non market. We are looking in the way to limit or eliminate the ineffective portion which will in turn help us reverse the swings in our quarterly earnings like you saw this quarter.

Turning to realized prices including the impact of hedging they averaged 3 dollars and 30 3 dollars and 30 cents per mcfe as natural gas prices declined 23 percent to 3 dollars and 26 cents per mcfe and oil prices decreased 16 percent to 22 dollars and 66 cents per barrel. Hedging increased realized natural gas prices by 99 cents per mcf and increased realized oil prices by 3 dollars 86 cents per barrel. On the production side for the quarter production as I mentioned decreased 1 percent an average of 149.1 Mmcfe per day.

Gas production actually increased 2 percent to 113.5 Mmcfe per day while oil and liquids fell 11 percent to 5,935 barrels per day. On an equivalent basis, 76 percent of our production was natural gas versus 74 percent in the prior year. I will turn to our expenses; they totaled 41.3 million for the quarter an 8 percent decrease over the prior year period. Interest expense was reduced 36 percent as a result of lower debt balances and lower interest rates. Direct operating cost decreased 27 percent acquiring the 69 cents per mcfe and that includes production taxes as well. The decline was due to a lower field labor cost lower level of work off expenses and also production taxes as well reflecting the drop in oil and gas prices. Our D&A rate D & A amortization amount declined 6 percent and the rate was a 1.30 dollars per mcfe. Exploration expense increased 4.2 million dollars due to a cost associated with our taxes as well higher seismic expenses to all our business units. Exploration expenses for the second quarter I will expect to decline roughly 2 million dollars and we don't anticipate incurring any significant dry-hole cost in the second quarter. General and Administrative expenses up 3 percent and should approximate the first quarter level for the remainder of the year. With regard to income taxes we have recorded 2.2 million dollars deferred tax benefit during the first quarter.

In terms of EBITDDAX which is earnings before interest taxes depreciation depletion amortization exploration and other non-cash charges totaled 33.1 million dollars a 29 percent decrease from the prior year period. For the last 12 months our EBITDDAX is totaled 149 million dollars. Cash flow for the quarter was 27.2 million again 27 lower than the prior year period. Due to lower prices our cash flow per share was 51 cents and for the last 12 months our cash flow per share was totaled 2 dollars and 34 cents. Net income was 4.5 million dollars a 76 decline to the prior year. Earnings per share was 6 cents before extraordinary gain on retirement of that security and 8 after the extraordinary gain.

Turning to the balance sheet we continued to reduce debt during the quarter total debt and trust preferred was reduced 3.9 million dollars from the year-end. Non-recourse debt dropped 3.7 million dollar while subordinate notes and trust preferred were lowered by 4.8 million partially offsetting this decrease was a 4.6 million dollars increase in apparent bank debt. The 4.8 million dollars decrease in subordinate notes and trust preferred was due to the retirement exchange for 713,000 shares for common stock and we recorded a 1.2 million dollars gain on the exchanges. Since quarter end, an additional 5.6 million dollars of subordinated notes was retired discount and exchanged for approximately 919,000 shares. We will book a 914,000 dollars gain in the second quarter on these exchanges. Including the recent exchange coming as 54.6 million shares currently outstanding.

Looking forward in terms of debt reduction our ability to continue this debt will be enhanced by a new bank facility that we announced last week. Besides reducing the bank debt from 12 day participants the new facility provides significant enhancement over the old facility and borrowing base was increased from 120 to 135 million dollars and may increase an additional 10 million dollars based on the amount of subordinate debt and trust before preferred that we retire in future. The term of the facility was extended from February 2003 to July 2005 and the interest rate spread was decreased slightly, also the restricted payment provision was enhanced. Restricted payment provision control the amount of cash that we can use for such plans as dividend, stock repurchases and early in the time of subordinated debt.

Under the old facility there was strict of payment baskets currently stood about 10 million dollars and under the new facility the baskets was set up with a astounding amount of 20 million dollars effective January 1, 2002 and increases based on the percentage of earnings, equity issuances and distributions from and ITF. Since first year when you add up all those components we estimated the basket currently be in the 26 million dollar range. The also allows for common stock dividend beginning January 1 2003. However, we don't recommending to our board directors that they consider reinstating common dividends until all the issues concerning our leverage are fully resolved.

Total debt and trust preferred at quarter end was 2.6 times the last 12 months' EBITDDAX. During the quarter our EBITDDAX covered interest by 5.7 times based on the current higher by the higher commodity prices and lower anticipated debt. We expect this credit ratios to continue improve in the course of the year. Turning to our hedging program intended impact of reducing price volatility and making our cash flow much more predictable. Due to the lower prices in the quarter hedging increased our average gas price by 99 cents and as I mentioned increased our oil prices by 3 dollars and 86 cents per barrel. For the remainder of 2002 we have roughly 60 percent of our projected production hedged at 4 dollars and 2 cents per mcf and 24 dollars and 2 cents per barrel. We also have hedges in place covering roughly 30 percent of projected 2003 production at 3 dollars 95 cents per mcf and 22 dollars and 80 cents per barrel. We also have a small amount of 2004-2005 gas hedged currently prices ranging 3 dollars and 76 cents to 3 dollars and 80 cents per mcf.

I am turning to IPF its receivable balance, receivable portfolio as you know is heavily weighed to oil and reflecting oil lower oil prices in the first quarter IPF earnings were impacted. They fell 2.4 million dollars that they pardon me. Income last year was 2.4 million dollars this year it was 601,000 dollar loss. Revenue decline was due to declining portfolio balance. As you know the portfolio is continuing to decline and we also had 850,000 dollars of lower amount of prepayment fees as well as the lower oil prices which I mentioned. The drop in oil prices also have the impact as look off when prices dropped we will view our valuation allowance this quarter had negative impact by 1.1 million dollars versus a positive impact last when oil prices were higher at 1.1 million dollars complete reversal from the previous year.

On the expenses side IPF expenses reduced by 47 percent as interest expense and administrative expenses were both reduced. During the quarter IPF debt declined by 700,000 dollars which is in line with the reduction in receivables balance. The IPF receivables and debt continue decline over time of our estimation. The rate of decline will depend largely on the future prices for oil and the performance of the profits underlined receivables. As mentioned in our previous conference call we will continue assess the alternatives relating to our ownership of IPF.

Turning to production, as I mentioned the first quarter production average a 149.1 Mmcfe. It was 1 percent lower than the prior year period. Gas production increased 2 percent to a 113.5 million dollars a day while oil and liquid declined 11 percent to 5935 barrels per day. 11 percent of 732 barrel drop in oil and natural gas liquids (NGL) production was due to the normal decline of oil and gas properties or oil properties as to say. Recently, we have two wells Texas these two wells was tested for 620 barrels per day gross 480 barrels net on the one well. It is on production with the second scheduled turn later this week. With the addition of these two wells we anticipate our second quarter oil and natural gas liquids productions which reached 6000 barrels per day in the second quarter as a result our 11 percent first quarter year-over-year decline is expected to abate to about 3 percent in the second quarter. Natural gas production, as I mentioned rose 2 percent during the quarter, however, our production was lower than we originally anticipate due to a failed workover in the Gulf of Mexico as we discussed on year-end conference call we began the operation of Matagorda 519 was attempting to recomplete the all four well and they had a down-hole mechanical failure which caused the well to seize production. Since then beeping has been unsuccessful and several attempts to fix the problem although they continue analyze the alternatives we are currently assuming that the well will not return to production this year. We have projected the to produce 2.8 million day net the range of interest in 2002. While this first quarter shortfall us behind we expect production of rebounding in the second quarter and assuming to continue to success on a growing program we anticipate further increases in production in both the third and fourth quarters of the year. For the second quarter we currently project production to be in 150 to 154 million per day range depending on how quickly we will get some of the new growing well on production.

Now I would like to turn to capital expenditures. For 2002 our current capital budget the 100 million dollars, this represent a 10 million dollar increase over what we spend in 2001. As we discussed on our year-end conference call the 2001 capital program focused bringing improved under well for reserves on to production. In 2001 only as roughly as third of our capital is spend on new projects for discussion new projects we refer to those projects were no persevere is currently booked. As a result of the prospects we initiated in 2000 and 2001 roughly two-thirds of our 2002 growing program is attributable to what we call new projects. For 2002 we are spending more than twice the capital on new projects versus the prior year. Assuming we achieve the anticipated risk results anticipate replace over 110 percent or more of our 2002 production with new reserves. Out of the 100 million dollar capital budget for 2002 86 million dollars manage attributable to drilling and recompletion, 11 million dollars for land and seismic, and 3 million dollars for pipeline and facilities. The current program is currently includes the drilling of 285 gross 148 net wells and 34 gross 25 net recompletions. We currently have a capital allocated roughly 50 million to the southwest, 25 million in each of the Gulf coast and units. Approximately 18 percent of the capital was spent in the first quarter. Funded in the drilling of 44 wells and 8 recompletion and out of that two of those were successful. Capital spending is projected to total roughly 25 million dollars in the second quarter. As one would expect the programs imposed will make substitution changes based on drilling results and we have done that so far this year. One thing the capital budget does include a material acquisition component if and when acquisition will be completed we will review the capital budget and make the appropriate adjustments. Based on the current future prices or capital program is expected to be fully funded with our internal cash flow currently somewhere between 80 percent to 85 percent of our cash flow. As we discussed again in our year-end conference call our primary E&P objectives for 2002 are continuing expand inventory of drilling projects, increase production by 5 percent and achieve greater than 110 percent reserve replacement. So far we are on track with spending on inventory of drilling projects and achieving the 110 percent plus reserve replacement. Given the difficulties of Matagorda Islands we are currently behind with regards to our production increase goal of 5 percent. While we anticipate reaching the 5 percent growth rate some time in the second half of the year it is in likely we have increased production by 5 percent for the entire year.

At this time I would like to Terry to give us an overview of our E & P objectives. Terry.

Thank you John. Welcome our E & P perspective with the significant exception of some operational problems we had in the first quarter especially with Matagorda Island and recently satisfied our first quarter results. Obviously, that is a fairly good the first right think about Matagorda Island is that we are not the operator and therefore rely on the operator BP Amoco. While Matagorda Island 519 is a high-quality property. BP's performance to date has been very disappointing particularly in this some past work is previously done. Our challenge is to mitigate a loss production from Matagorda Island and I believe in which we will make and get head away and doing that however, as John said I am not optimistic that we can makeup for the loss and still meet our 5 percent year-over-year production growth target. still remains my challenge. As John mentioned we did believe on track to reach 5 percent production growth rate in second half of the year and mere reserve replacement goals that we have established for ourselves.

Returning to the first quarter production just wanted to give a run down of our production comes from 65.8 million Mmcfe per day or 44 percent comes from Southwest which includes our Midcontinent and South and East Texas. 49. 2 Mmcfe per day or 33 percent was from the Gulf Coast and 34.1 Mmcfe per day or 23 percent was from Appalachia. On a year-over-year basis our Southwest production including Midcontinent grew accordingly from first quarter of 2001 to 2002 9.4 percent and Appalachia production grew 9.1 percent. But more than offsetting this increases was a 17 percent decline in the Gulf Coast. Decline in the Gulf Coast is larger result of the high intrinsic decline rate and the relative as modest capital expanded over the last few years. Lot of our strategy has been to expand in the Texas Panhandle, East Texas to help offset this decline. However, the number of projects slightly later in this year that could mitigate the decline even in the Gulf Coast. I will speak to those later in my comments. As you can see when we are going to bit of a transition while several long-lasting projects have been executed but are not yet to the level where they fully offset the decline we have in the Gulf of Mexico. As I usually do in this conference call I would like to give you a few updates on some specific projects. In the Texas Panhandle we continue to increase production. During the first quarter we are building completed the Pioneer #2 which was deeper offset to the Pioneer #1 drilled late last year. The Pioneer #2 commenced production in February a 6 Mmcfe net per day. In addition to the producing pay we also have pay behind pipe in Pioneer #2. We are currently releasing additional area and expect to spread our next well sometime in July. For the year we currently anticipate drilling 3 to 5 additional wells and initiating at least two recompletions. Currently we have 55,000 gross acres and 27,000 net acres in the play and I would be disappointed if we don't double our expositions during the year. The success of the play depends on immigrating geo-physical interpretation, regional geology, and engineering. We are also adding to our technical team that is what in we can generate and pursue additional opportunities to go forward and increase the pace. In East Texas we are currently focused on developing a Travis Peak discovery we drill and put on production in the first quarter. Our discovery is never one which is initially drilled to test the Bossier sand and was unsuccessful on the Bossier. However we came up hold approximately 8100 feet and found gas in the Travis Peak. The initial production was 2.7 Mmcfe net per day. We have recently drilled the first two offsets the Linda number two and the Linda number three both of which founds similar pay as a number one well and we are currently completing both wells and should have them on production by the end of this month. Assuming the initial production at number two or number three what we expect we anticipate spreading two additional offsets beginning sometime in late July. As you recall from our year-end conference call our second Bossier test the kartis number one was not in the same area as the Linda and it was unsuccessful. We haven't plugged the kurtis yet that we elected the charge of dry-hole expense in first quarter. Our technical team is now looking for additional Travis Peak with there some petite valley opportunities on lease old position which covers 22,000 net acres 37,000 gross. Also in the East Texas we are pursuing James Lime horizontal carbonate play that we have discussed before last year we drilled two successful wells as we doubted previously that have combined initial production rate of 13 Mmcfe per day. However, we only own 12 percent and 25 percent in the wells respectively. This year we had plan to drill at least five wells where we have 50 percent or greater interest. problems the first well is scheduled to spread in late June. Currently we have 27,000 gross 20,000 net acres in this play. I see the play as an interesting opportunity in their light to Texas Panhandle it is successful we have lot of range drilled to expand our position. And we have a pretty competitive position to start.

West Texas, we have recently drilled two wells at Powell Ranch. The Powell Ranch 20-C recently started production; 118 net wells per day and 230 gross and 150 gross mcf per day 120 net mcf per day. The Powell Ranch 11-F was recently drilled and tested at higher rates that is going to be constrained as well as our commission rules and we will only have a lovable rate of 330 gross barrels per day or 265 net barrels per day. This should be place on production by the end of this week or next week. The new productions from these wells will add on most 10 percent to range as current old production right away. Our technical team is currently reviewing similar old projects in West Texas which we will pursue at late initial drilling in the third quarter.

In our Gulf Coast area we drilled two wells in the first quarter in the successfully drilled Galveston Bay State Tract 126 #1 8700 feet lowest kind of production at top level rate of 2.2 Mmcfe or 0.4 net we have a low interest and we are non operating in the well. An offset is being considered for the third and fourth quarter this year. Onshore in Southeast Texas is Stephenson #4 which is successfully drilled to the hot berg formation this is a continuation of the hot berg play that we have been involved in there for well over a year at the rate of 5 million a day or 450 mcf per day net. Two additional wells are planned in area later this year. Looking forward in the Gulf Coast and Gulf of Mexico we have the Louisiana which expired in July ranges the operator has a 44 percent working interest in this 11000 final test. The Gulf of Mexico should surely expect the spread in August a 9000 foot test for that we have a 25 percent working interest will be the operator of that well. Our net risk reserve potential for those two wells is approximately 10 bcfe. The project which we have spoken about in which is going to have a significant impact on our production reserves in the Gulf of Mexico, West Cameron 45/56. As a recall we initially have 75 percent working interest in this expensive test. Till now we have obviously formed our interest in major oil company range will be care-to-case in the first well this equates to 7.5 million dollars of dry-hole cost will be assumed by the major company. Range will retain a 25 percent working interest that may increase to 37 percent if certain productions targets are achieved. The initial test well should spread within two weeks. It will likely take 90 days to drill. I need to note that the discoveries made will be initially limited to what we can disclose given a confidentiality provision on the existing operating agreement. We would be able to say that we are satisfied with the results of I guess some general information like that but no specifics until such a time that the operators agree or the data is made public. Each year we will be looking to generate one to two what we call home run projects that is what is our plan and West Cameron 45/56 exploration project clearly fits into that category. In all we have exploration prospects that we now expect to drill or participate and during 2002 which expose us to over 200 bcfe of net unrisked reserve potential. As noted earlier our capital budget does not include any acquisitions, however, as we discussed in the year-end conference call we are now looking at acquisition opportunities in core areas with focus on small transactions which we expect to be less competitive than we believe that we can add value from operational improvements and our technical teams can add production rate and reserves. Our operating close at least one or two of these transactions by year-end. Obviously this would be incremental to any kind of production forecast or guidance that we have given today. Over all I am disappointed in the first quarter production results especially the impact of Matagorda Island. Our objective obviously is to create opportunities for operational promise like we had in the first quarter more easily overcome. As I have stated before my goals have been to add 5 percent issue to production and achieve at least 110 percent reserve replacement. I am optimistic because of initial grilling reserves so far to date looks solid and we are making good progress towards our reserve replacement goal. As John mentioned the problems in the first quarter will make a 5 percent year-over-year production growth difficult to achieve. However I expect to achieve a 5 percent growth rate for the second half of the year and we are working to accelerate our exploration program as much as we currently can and as mention we have several expiration prospects will be drilled later this year, if successful could have significant impact on our results. This concludes my comments and now turn the phone over to Tom.

Thanks Terry. Well as both John and Terry stated obviously the first quarter results were not on a qualified success by any means. We were disappointed despite having done extremely well on the expense side in terms of continued deleveraging of the company and subsequent to quarter end. The restructuring of our bank facilities at the parent company but the dry hole and the Bossier sand on expensive dry hole they need to be add to the bad debt reserve once again at IPF and most dramatically because of the significance of increasing production to our overall turnaround plans of the company of the fiasco at Matagorda Island 519 turned this into a very mixed series of results in terms of our long-term plans. The encouraging part is that several, at least of the underlying trends remain intact. You can tell from Terry's outline of the slate of projects that have pursued since the start of the year and that will be pursued for the remainder of the year. But the rate of drilling and development of new opportunities is essentially unparalled in Range's history. Even in the earlier stages of Range's growth and profitability we were primarily driven by acquisitions. I think, in my own view this is by far the healthiest slate of growing projects that we have had in the entire 14 years' history. I am certain they are only going to matter if their results contribute substantially to our production and reserves. But the early indications as Terry mentioned are quite favorable.

On the deleveraging, we continue to make headway of shrinking of the burden of particularly a higher cost subordinated instruments and trust preferred including the exchanges done. After the end of the quarter we eliminated almost 10.5m face amounts of the subordinated claims that has doubled that impact in terms of our leverage because since they are being eliminated through the issuance of the equity that reduces the debt by the 10.5 and increases equity by 10.5 helping close the gap to the kind of one-to-one ratio that is a corporate target to achieve within the next 12 to 15 months of the company to put it solidly back in the middle of the fairway in terms of the leverage of the company. The other aspect of this was again touched on the presentation is the Great Lakes' and Appalachian operations are now working extremely smoothly. They have got a higher than expected growth rate and production. They seem to be adding attractive projects on a regular basis and many of the challenges that we faced early in the formation of that joint venture seem to be behind us. Similarly in the mid-continent, we have moved to a gross in terms of projects and in terms of the projection. The challenge really comes out of the gulf and the gulf coast area, frustratingly in the Gulf of Mexico itself where we are generally not the operator of the properties and therefore have only limited info over what goes on. But I think, my own feeling despite the disappointments in the quarter, we have continued here to really march forward not as fast as we would like, not as successfully as would like but we have continued to move forward in terms of rebuilding Range into a company that we can all be proud of and that can provide the kind of returns to our shareholders that we historically recorded and think the shareholders are entitled to and I think in that respect we have continued to move ahead and we will make every effort to accelerate that rate of progress in the remainder of the year. Certainly that will be aided by the sharp recovery in the oil and gas prices that have happened since the end of January and that will increasingly benefit our results particularly in comparison to last year once we move through mid-year and the spike in prices of early 2001 are behind us in terms of a comparison. So with that, operator if we can open the call up to questions, I would appreciate it.

Today's question and answer session will be conducted electronically. If you would like to ask a question, please press star followed by one on your touchtone telephone. Again press star one if you would like to ask a question.We will pause for a moment.

We will go for it. , RBC Dain.

Hi guys, question is on the Texas panhandle. The additional wells that you are drilling there, can you give me some insight into what kind of costs are associated with drilling those kinds of wells? What production would you get if they were successful? And also what kind of potential production could result if they are successful? Are they the same kind of high impact projects that Pioneer 2 appears to be or they are going to be little less may be?

This is Terry Carter. It is a good question. The cost of those wells in that particular area are around $1m each gross. In this particular case, most of the areas we own a 100% working interest, so the range costs, of course we are trying to get the benefit. It is probably unreasonable for us to expect that all the wells are going to perform as well as Pioneer #1 and #2, but we certainly expect to have significant performance somewhere in the neighborhood of 1-5 million per day on successful wells. I am going to be disappointed if we get to the end of this year and roughly 10% of our total corporate gas production doesn't come from that area.

When was Pioneer #2 put on production?

In late February.

Next question is on West Cameron. You know I see that you have the timeframe that is going to be spread this month. When can we realistically expect to get some kind of initial report on sort of, what the well is going to test, etc.?

As I said before we are going to be prohibited from our confidentiality agreement relative to the operating agreement of West Cameron from discussing specifics, but we should have some sort of internal idea within 90-100 days of spud. This will be up to the parties involved as to have some released discovery information if we have a discovery. I believe that the public information is available some time 90 days or so after first production. That is a long relative way of saying. I can't give you definitive answer. But we'll certainly release the results as soon as we can.

To kind of to simplify that perhaps it sounds like some time around the end of 3Q we can probably tell you whether we're pleased or disappointed with the results. And it may well be another three or four months after that unless we happen to get the consent of Star and which is not likely before we can give you any specifics.

Does the lease operating agreement that you have also preclude you from advising us on any results on some adjacent blocks?

Does your lease operating agreement preclude you from advising us on results on

adjacent blocks if you have such knowledge?

I assume you're referring to the already drilled Chevron offset.

Yes.

Absolutely, we can't say a word on that subject. We have no interest in that well.

And finally on lease operating expenses. The trend looks pretty good in terms of 1Q, where should that be trending going forward?

Our lease operating cost trends, I really expect that we will continue to see good trends on lease operating costs. The only there is production taxes. Obviously with the up tick in commodity prices recently, we could see an overall increase, but on direct lease operating costs I expect to continue to see a positive trend of about $0.03 to a nickel may be and if we go the other way it is just as easily depending on workover expense. It is quite a good trend. We expect it to continue.

Okay. Okay thanks. Thanks a lot for your assistance and I look forward to both the results from West Cameron and also the Texas panhandle, which looks pretty good.

We will go next to Joe , RBC Capital Market.

Hi good afternoon. A follow-up on West Cameron 45/56. Can you tell us what you think the chance of success of that is?

You are going to get risk expected. It is somewhere between 1:3 and 1:4.

And then how about on the Galveston Bay and elsewhere on the Gulf Coast? Are there opportunities that pick up some additional interest there and if so are you interested in doing so?

We have a partnership, that is a CCR partnership, which is an exploration partnership in the Gulf of Mexico with two other operators. We could feasibly pick up incremental interest and it is obviously our desire to do so if it's economic. But the opportunities in the Gulf to do in a cost effective manner are fairly limited.

And lastly different operating areas. How about Appalachia? Could you just talk about what you saw for Appalachia?

As Tom mentioned we were making very good headway in Appalachia. We had a 9.1% YonY growth in 1Q02, which, quite frankly, surprised us. We thought we are going to be more than the 5-6%, I don't think we are paying that all year but we are fairly pointed at it. I think we would be 5-7% for FY02. That is essentially coming from what we call just the granted out Joe are large Chile development wealth which we have got in the inventory so that that growth is coming from there the upside obviously in Appalachia is the Twin Black River where we drilled one deep and unsuccessful well, we had a minor interest in. Then we got a shallow well, we are being able to say that was not great but can be productive. We have got five additional twin wells we are going to drill this year. Three deep ones. , and then two 7000 to 8000 per well somewhere between 15-100%. Still we are in deep phase with significant discoveries in areas. We have 1m acres under lease. So the to some degree will likely come to us. But we are drilling the well a bit. I think our growth, you will see this year. What has been historically great and good which is at grinding through the inventory of shallow development projects and

get relatively quickly QoverQ, month over month increasing in production.

Where are the Twin Black River wells in particular?

We are going to have one in West Virginia, one in Pennsylvania, and one in New York State. The recent very good wells have been up in New York State. It is about 10,000 foot wells that come on at say 1m a day, anywhere from 1-3 bcf, very good finding costs. We do have three projects there up there, one of which will be drilled this year, and the other one we may or may not get it drilled. Currently not on budget but if we get a good partner, we would actually drill it. So it should start the trend that has gone into The Roman Trough there that goes from New York all the way to Tennessee. It is where everybody is focused on, so it is a big area, there is a lot of people playing on it now, a lot of big companies have come in. It's primarily a horizontal twin well up in Pennsylvania about 10 miles from one of our prospects. So there is a lot of kind of new interesting things going on. But I would caution you, I still view it as we are in the R&D stage but it is starting to grow. It has started to do something.

You are unsuccessful. How many TBR wells have you drilled to?

We have only drilled two.

One was deeper and one was more shallow?

Right.

Where were they located?

The deep one was in West Virginia all set and , from a CNR seige discovery. We actually made gas but it wasn't commercial enough. We actually haven't broadened it here. We are trying to make it horizontal. But we are going to call that clearly unsuccessful. The other was in the middle of Ohio on a shallow trend. This is a leased well as well, it is not going to be but it is not going to be the exploration type return of 50-100% that you would expect.

Again it is star one if you would like to ask a question. We are on Tian , Banc of America.

Just a couple of questions featuring the L-4. Just wondering if you guys were expecting on what you can produce later this year. Just wondering what's the reserve amount associated with the L-4 well?

The reserves will be impacted. The reserves of the Matagorda Island reserves won't be impacted; we believe that most of the reserves are still developed and will be recovered over a longer period of time in offset wells. The reserves are still developed; if they are not going to be PDP reserves, they will still be economic to develop at some point. You

shouldn't see a reserve impact whatsoever.

And I guess going over to a far off date what exactly is the amount of sub debt and trust deferred when you are retired to get the incremental 10 million?

Under a bond basic agreement, to the extent it is basically is 35 cents on the dollar to the extend that if we retire 1million of trust worth that bond makes it go up to 350,000 dollars.

What's kind of shooting over the common dividend. You mentioned that as the kind of leverage levels as far as your leverage goes, what is that?

It would be unlikely we would unlikely we would take up consideration of a dividend with a greater than 50 percent debt to cap ratio.

Well then that is excluding the tides what you consider the ties of equity in that scenario - the convertibles?

We consider the trust preferred debt.

Thanks a lot.

The next is Jim Dorsey from Private Investor.

My first question is that any idea when first production from West Cameron might be successful?

There is an optimist. Forget about whether the wells are successful. We need to find the oil and gas first before we try and schedule the production.

That's right. I mean are there developmental problems or would that be fairly easy to bring online?

It really depends on the size of the discovery. Initially the production would be probably taken over

on an existing platform that is operated by one of the partners. That is the case and it could be within 90 to 120 days after

discovery. If it happened to be significant enough to have its own facility, obviously it would become from next year.

My next question is about the Trentham Black river, do we have deep rights under the all of our million lakes or Great Lakes?

We have deep rights under roughly 90 percent of the acreage that we own in Appalachia. Historically people have not severed the shallow rights to the deep rights. Only in a very few cases we don't have the deep rights. In fact we're working on transaction to get that 10 percent back; the company that owns it has approached us to offer a sale. It is somewhere between 90 and hopefully a 100 .

And the answer is very simple. No one ever thought there was anything deep.

So that's somewhat a hidden asset, isn't it?

It is not very hidden. As John said in all of the million acres it almost doesn't matter what we do in terms of Black river or some of these other zones if this is figured out by anyone out there. Our acreage is our acreage and either have to come to us to make a farm-out deals or we use the closology [phonetic] to exploit it. We have a long-term option on about 1 million acres of deep rights.

But you don't have the seismic to assess what's viable and what is not as well as the understanding to do the same, right? I am sure not all those deep rights are prospective.

We have about 3,000 miles of seismic and five geologists, 1.5 of which work on nothing but deep prospects. We've farmed out three or four prospects in addition to the ones we're drilling. But we don't want to be the leader of the pack. We are going to take our time and do it with discipline and we are not going to run out this because of 10 million dollars when there is a when we don't fully understand the technical situation. But the goodness is that a lot of others are drilling things and the data is coming more and more shared within and there is a lot of well growth this year that we will be able to offset and analogy so the learning curve is going to go dramatically. We didn't do anything in front of it.

What sort of interest is being carried with the farm-outs?

The strategy is two-fold: one is we're actively leasing on some prospects which we developed with our technical staff that we've developed using 2-D and 3-D seismic. We got 5 out of 6 of those that cover 200,000 acres which we are here in the process of developing. We own 50-100% interest and want to end up with somewhere between a quarter on the low side, on the top side with more than 50 percent. So that process is going on. We should drill three of those prospects this year.

Those prospects will be partially carried?

Yes. Then 10 or 12 prospects are where people have come to us on B or C acreage that we've farmed out. In most cases they do most of the seismic work and own half interest. If we don't like the risk, we'll sell off part of our 50 percent interest and reduce our interest from the risk effect.

At the IPAA conference, there was guidance and a footnote that was based on the 328 future prices that we would probably be looking at our 65 cents per year and of net and 2.30 cash flow. Are those numbers still in the ballpark given the hedges?

Well just to give you the variable since then, prices have increased and we've hedged some of that. That is good news. the bad news is 1Q did not turn out like this. So probably on balance we are still pretty good. If prices fell, those numbers aren't great, but we have so much production hedged that those should be decent numbers.

John are those our numbers or the analysts numbers?

The analysts numbers consistent with the consensus.

Jim you said the cash flow isn't 2.30, the number is on the website.

I am doing this from memory. I did not check the 3.48.

It is on the website.

Okay thank you very much.

We will go next to Howie Flinger from Flinger and .

Hello everybody.

How are you?

I have got a question about your production expenses, what was the cause of the decline in production expenses other than taxes?

Declining cost of services, declining well servicing costs, and declining workover expense. Also there is an component of Energy costs, energy from the first quarter of last year to the first quarter of this year is quite a bit less expensive because of the change in commodity prices. With our initial 1 million budget, we're getting more done with fewer dollars; we won't spend the 100 million or find additional projects because of the rig rates and every thing else and pipe and everything else are the same as rigs rates were down pretty dramatically when we did the budget. That really helped us in terms of we've been able to add additional projects.

Okay gentlemen, there appears to be no further questions at this point. I will turn the call over to Mr. Edelman for any remaining additional or closing remarks.

Thank you operator. We appreciate you all joining us again. We were pleased with certain aspects of the first quarter results. Obviously disappointed with others. There is some underlying trends here that we think could be critical in this company entering its long-term goals and we simply have to demonstrate and trends in the months and quarters ahead. So we very much look forward to reporting back to you several months from now on the second quarter results. We certainly hope to know the equivalence of the Matagorda Island problem as John indicated, we do not have any wells drilling that could result in the dry hole expense. So we expect that those results with those factors plus the horizon and the prices will be quite gratifying and hopefully we will look forward to a continuation of some of the developments and exploratory success that Terry and his technical teams have been able to put together in the first couple of months. Hopefully its continued progress and exhilarating rate of progress as we go through the year. Thank you all very much again.

That ends the conference. You may now disconnect.