Edge Petroleum Corp. Q4 2007 Earnings Call Transcript

Edge Petroleum Corp. (EPEX)

Q4 2007 Earnings Call Transcript

March 13, 2008 2:00 pm ET

Executives

Michael Long – EVP, CFO

John Elias – Chairman, President, CEO

John Tugwell – COO

Analysts

Joe Allman – J.P. Morgan

Kevin Wink – Polynouth Capital Management

Ron Mills – Johnson Rice & Company

Wayne Andrews – Raymond James

Robert Shakter

David Van Treuren – Maloney Securities

Presentation

Operator

Good day everyone and welcome to the Edge Petroleum fourth quarter earnings conference call. (Operator instructions). At this time I’d like to turn the conference over to Mr. Michael G. Long, Edge’s Executive Vice President and CFO, please go ahead sir.

Michael Long

Thank you Dana. Good afternoon everybody and welcome to Edge’s first conference call of 2008 which will cover our 2007 full year and fourth quarter financial results as well as both the general corporate and operational update. With me today is John Elias, our Chairman, President, CEO and John Tugwell our Chief Operating Officer.

Before we begin our review I need to remind everybody that we will be making forward looking statements today. Statements regarding any evaluation, review, assessment or process, any transaction, including the timing or effects thereof, shareholder value, continuation in or continuation of current business plans, cash flow, financial conditions, forecasted production derivatives and effects thereof, reserves, estimated volumes as well as any other statements that are not historical facts in this release are forward looking statements that involve certain risks, uncertainties and assumptions, many of which may be beyond Edge’s ability to control or estimate and are subject to material changes.

Such risks, uncertainties and assumptions include but are not limited to results of the Board’s evaluation, any process or transaction, marketing conditions, availability of financing, Board and stockholder approvals, action by third parties and our financial and operating results, the availability of terms, any alternative transaction, uncertainty costs or delays related to transactions, prices for oil, natural gas, including natural gas liquids and general operating risks within the industry. These factors are more detailed in the risk factors and other sections of Edge’s most recent form 10K which was filed a few hours ago, forms 10Q and other filings with the SEC.

Should one or more of these risks or uncertainties materialize, actual results may differ materially from those indicated. The specific term resource potential or 3P reserves is not meant to be the equivalent of the SEC definition approved reserves. With that out of the way I’d like to turn the call over to John Elias to begin the presentation.

John Elias

Thank you Mike, thank you for taking the time to join us this afternoon. If I get a little bit giddy during the course o the presentation it’s only because that I have been informed I’m a new grandfather for the first time, but with that I would first like to comment on the status of our strategic alternative evaluation process. As you are aware, we retained a financial advisor to assist the Board and management in an assessment of the various alternatives. Although no specific decision has been made at this time by the Board, it is fair to say that we are thoroughly examining the merits of a possible merger slash sale of the company but we are not ignoring other alternatives in the process.

As you might suspect, we are right in the middle of the strategic alternative evaluation process and therefore I have nothing more to add at this point. As far as our other activities are concerned, we are continuing to conduct our business activities in as normal a fashion as possible given the circumstances. We have an emphasis on several things, first, the continuing generation of new organic growth opportunities and bringing each economically viable investment opportunity to a ready state. We have a recompletion and work over program in South Texas where we plan to initially spend about $2 million over the next 90 days on ten wells.

The net incremental rate additions from this effort is estimated to total approximately 5-6 million cubic feet equivalent per day. We also have a divestiture program of underperforming or non strategic assets. Thus far we are pleased with the results of this effort. We have or will receive approximately $17.9 million or 23 properties. Our estimate of the remaining reserves on these properties is approximately 4.7 million BCF equivalent with production currently at 6.8 billion cubic feet equivalent per day but expected to follow a normal decline on a go forward basis.

I should add that we have ten other properties that we will attempt to sell after certain ownership issues are clarified. We have a balanced drilling program that will add new as well as bring unproven developed reserves to a producing state. John Tugwell will discuss in a few minutes some of the successful results we have achieved in our 2008 program to date, particularly in South Texas at our Flores/Bloomberg field and in Southeast New Mexico.

Over the last several months, we have built a sizable inventory of attractive projects, 118 of which are ready to drill. 56 of these present proven undeveloped locations and the balance, 62 projects are reserve add drilling opportunities for us. We also have approximately 46 BCF equivalent of proven non producing reserves and 150 wells that we expect to capture in the future with our ongoing recompletion and work over program. In addition, we had an identified inventory of probable, possible and exploratory projects that we estimate have a net un-risk resource potential in excess of 550 BCF equivalent.

Approximately 55% of the estimated net un-risked resource potential is in South Texas and this is considered to fall predominately in the low to moderate risk categories with a few selected projects that are higher risk in nature. About 20% of the 550 BCF equivalent net un-risk resource potential falls in the Mississippi interior salt basin where the shallow targets are considered to be moderate risk, while the deeper Hosston Cotton Valley targets offer more resource potential but definitely fall in the higher risk categories. The balance of the estimated net un-risked resource potential and projects are scattered in Southeast Texas, Southeast New Mexico and Arkansas.

I would like now to make a few comments about our 2007 year end reserves versus our beginning of the year guidance of 240-260 BCF equivalent. Obviously our 2007 year end reserve of 163.4 BCF fell well short of our guidance as well as our internal approved budget expectations of approximately 245 BCF equivalent. I don’t want to get too tangled up in my own underwear with the numbers but I do want to try to give you a better understanding of how we arrived at our disappointing reserve year end reserves. I will begin with our budget expectation so f 245 BCF equivalent and work down. Four dry holes accounted for 13-14 BCF.

Wellbore performance accounted for the loss of 27-28 BCF equivalent, this was due to increased decline rates along with some mechanical problems. Shrinking and processing adjustments netted out to be about 0.7 BCF equivalent, there were positives and there were negatives. The deferral, we deferred the drilling of 30-40 planned wells, accounting for 37-38 BCF of net risk resource potential. Our actual net resource, net risk resourced potential for the deferred exploratory wells is in the range of 45-70 BCF equivalent. It should be obvious that these risked resources have not been lost but still remain in our inventory to be captured.

Proven undeveloped reserves of 24-25 BCF were taken off the books. 15 BCF equivalent of which were moved to the unproven categories, i.e. probable, possible and exploration due to one dry hole that we drilled at South Harden in Southeast Texas. As I mentioned earlier, we have processed the 3D Seismic we acquired, that we acquired after we purchased the Smith assets in Southeast Texas and our current interpretation as well as that of an outside consultant suggests that we will more than likely recapture these and perhaps more resources through further drilling which we plan to do in Southeast Texas.

Consequently, we believe that we will ultimately capture through drilling at least 75-95 BCF equivalent of net risk resource potential that we didn’t capture in 2007 for the reasons I have just stated. It may be a stretch, but had we executed our program as originally envisioned, our year end reserves may well have been in the 235-250 BCF equivalent range but the fact is we didn’t. And that is the primary reason the Board and management decided to engage a financial advisor to help thoroughly evaluate an assortment of strategic alternatives for the company so that we can begin the process of recapturing the lost shareholder value that has occurred. I will now turn it over to John Tugwell who will address our current operations.

John Tugwell

Thank you John. This afternoon I will discuss our January production and I’ll give you an update on our ongoing operations to date this year. Total estimated company net productions for January of this year averaged just about 61 million cubic feet equivalents per day. As John mentioned, we divested some noncore assets, primarily in South Texas over the first couple months of the year. We expect to close on the majority of these during the first quarter. The divested properties contributed about 2.5 million cubic feet equivalent per day to our January net production strength.

So far this year, we’ve logged eight wells with eight apparent successes for 100% success rate. Three of these wells were PUD locations and five will add new reserves estimated to be in the range of 3.5-5 net BCF equivalents for the new wellbores only. Resources associated with offset locations to several of these wells are not included in this estimate. Two of the eight wells drilled to date were in Southeast New Mexico and the remaining six wells were in South Texas, primarily in the Flores/Bloomberg complex where we’ve logged five successful wells and have one rig currently operating. Our most recent completion in the fields at Bloomberg number 63 came online at a gross rate of about 3.6 million cubic feet equivalents per day.

We’ve got a 32.5% working interest in this well. Our Bloomberg number 67 well, which we just logged found 66 net feet of apparent pay in three sands. We’re running production casing on this well which we have a 48.1% working interest in. We also have an active ongoing recompletion program in the Flores/Bloomberg field where we have a significant number of high quality behind pipe recompletion opportunities at existing wells. This recompletion work typically has a low risk profile and generates a high rate of return. In our Encinitas field, we recently drilled and completed the Lopez number 26 well a proven undeveloped location which we have a 72.5% working interest in. This well came online in February at a gross rate of about 1.4 million cubic feet equivalents per day.

We’ve temporarily abandoned the Chapman Ranch number 19 well spud earlier this year after encountering higher than anticipated [floor] pressures and significant gas in the Anderson Sands at about 11,500 feet. We experienced an underground flow in this well and plugged the lower portion of the hole before reaching our main objective at [howell height]. We followed a claim with our insurance company and anticipate that the majority of the cost associated with this well will be covered. Our original [howell height] proven undeveloped objective location remains in place and we plan to capture it with a future well. Although disappointing that we were not able to reach the [howell height] interval in this wellbore, significant potential could exist in the Anderson sands which is very prolific to the north o this area.

We’ve released the drilling rig at Chapman Ranch while we evaluate what we encountered in this well. In Southeast New Mexico, we are completing our [prairie fire] well where we have a 50.8% working interest and found 87 feet of apparent pay in the Morrow section and an additional 35 feet of apparent pay up holes in the Wolfcamp section. We’re just finishing a three stage completion in the Morrow section and have had very encouraging results to date. The first stage of the completion flowed at gross rates in excess of 3 million cubic feet equivalent per day.

The second stage flowed at gross rates in excess of 4 million cubic feet equivalents per day and the third stage which is currently flowing back after fracture stimulation is testing at rates of about 7 million cubic feet equivalents per day. We plan to comingle all three of these intervals in the Morrow and put the well to sales as soon as possible. The behind pipe pay in the Wolfcamp will be completed at some point in the future. In Mississippi, we’re reprocessing our 72 square smile data set over the Midway Dome field using third party processors who specialize in 3D seismic data around salt domes with the real goal of improving our image of the salt state on the near face.

This work is expected to be finalized during the second quarter of the year. We have a number of both shallow and deep leads and prospects at Midway Dome which we plan to refine with this enhanced data set. Pending success at Midway, this reprocessing effort to be extended to other 3D data sets in the basin. As John mentioned, our technical staff is continuing to indentify new opportunities in many of our core operating areas and we are securing leases where required to add these opportunities to our inventory to bring them to drill rig status.

These new opportunities are coming in large part from areas where we acquired new 3D seismic data in 2007 and from 3D seismic reprocessing efforts on these and other shoots we have in our data library. On the call side of the ledger, rig rates seemed to have stabilized after coming off their highs seen in 2006 but are still double what they were four or five years ago. Other oil field services which have risen along with rig rates over the past couple years also appear to be flattening as we go through the first quarter this year. With that I will now turn the call over to Mike Long.

Michael Long

Thank you John. Revenue for the year totaled $160.9 million on production of 24.1 BCF equivalent at an average price of $6.67 per MCF equivalent. Excluding the noncash unrealized hedge losses of $17.5 million in 2007, revenue totaled $178.4 million at an average price of $7.40 per MCF equivalent. This is 43% higher than the previous year at $124.7 million which also excludes unrealized hedge gains and losses. On a standalone basis, production for the year was 40% higher than the previous year.

Revenue for the fourth quarter was $35.9 or $45.5 million excluding the noncash unrealized hedge losses compared to $24.9 or $27.6 with the hedged taken out for the same period a year ago. Production for the quarter was 5.8 BCF equivalent, a 45% increase over the same period a year ago. LOE for the year was 87% higher than year ago levels due to higher levels of production, a significant increase in expensed work overs, overall sector cost inflation and higher water disposal costs. Severance taxes were 31% higher than a year ago, attributable directly to the higher levels of revenue. Or depletion rate for the year averaged $3.77 per MCF equivalent compared to $3.51 a year ago.

And in the fourth quarter our depletion rate jumped up to $4.83 per MCF equivalent compared to $2.90 a year ago. In the third quarter of last year you may recall we took a pretax property impairment charge of $97 million. For the full year we reported a net loss to common shareholders of $1 million or basic and diluted loss per share of $0.04. Pro forma for the noncash unrealized hedge losses, net income was $10.4 million or $0.38 basic and $0.37 diluted.

Cash flow from operations for the year totaled $124.9 million compared to $93.1 million last year and after changes in working capital, cash flow provided by operating activities totaled $122.9 million compared to $97.4 a year ago. Our capital spending excluding acquisitions came in at $141.4 million in 2007. We borrowed a net total of $131 million and raised approximately $276 million from a early in 2007 common preferred share offering. Our acquisitions totaled approximately $376 million during the year. At year end 2007, our outstanding debt was $260 million.

It stands today at $250 million. Some of the asset sales that have previously been talked about have closed and funded with the balance expected to fund shortly. At year end, our debt to total capital ratio was 37.4%. We’re monitoring our derivative position closely, just a point of reference at February 29^th, the mark to market exposure we had as a result of all of our current derivatives was a negative $20.4 million. All but $5 million of that exposure is in calendar 2008 transactions. With that brief review of financials, the update on both corporate and operating activities, we’d now like to open the call for questions.

Question-and-Answer Session

Operator

Thank you sir. (Operator instructions). And we’ll take our first question from Joe Allman of J.P. Morgan.

Joe Allman – J.P. Morgan

Hi everybody. Just on terms of operations in Southeast New Mexico, if I’m not mistake you had a few issues there in Southeast New Mexico in 2007 but you’re back to drilling, you’ve completed two wells. You know could you kind of relate what you’re doing right now just on the issues you had in 2007?

John Tugwell

I guess I’m not sure Joe what you’re referring to in 2007. We drilled 11 wells there in 2007 which was right on target with what our plan was for that area. We were drilling the [Prairie power] well which I mentioned we were drilling over year end and reached TD in January and have been in the process of completing that well. We found a much better than expected Morrow section in this well and are real excited about the potential that it’s got and also the potential to offset the well.

Joe Allman – J.P. Morgan

Yeah if you just, I thought maybe you had some disappointing results in 2007 in Southeast New Mexico, is that right or?

John Tugwell

I don’t think so Joe, actually you know we’re pretty much right on target and actually exceeded slightly our expectations that we originally had in New Mexico.

John Elias

Joe you may be reflecting back on the fact that we had an exploration agreement that covered all the [shed is ed] in Lee County with two private entities scheduled to expire here I think next year. And they as well as we were looking for ways to separate ourselves from one another. They wanted, one of the parties wanted to sell some of their assets. That was causing some delays in some of our planned efforts and conflicts of interest and we had now resolved that.

That exploration agreement has been terminated and we’re moving forward on a standalone basis in that area ourselves and I think one of those parties did ultimately sell their interest in a selected area. And another thing you may be thinking about, there was a transaction that they did with another party without our agreement and we got in some discussion into what ownership we were to have in the position that they exchanged for and we ultimately worked out. So those would be only two things that I can reflect back on that we may have mentioned and that you may be alluding to.

Joe Allman – J.P. Morgan

Okay that’s very helpful. And then John when you were going through the un-risked resource potential, what was the percentage you said that was South Texas?

John Elias

The resource potential in South Texas that, well let me first tell you that what we had in there for PUD reserves we took off the books after the drilling of the South Harden which represented about 3.8 B’s, correct that for me John, I think that’s right. Then we took off another 14-15 B’s in that area because of the similar type of ABO type anomalies. And then we bought seismic and went back in and reinterpreted, had a consultant reinterpret it.

We reaffirmed because interpretation is a little bit different faulting, the quality of the prospects in addition to other exploration opportunities as well as an outside contractor just bought in some additional targets for us and so we believe and I mentioned a while ago the number that I highlighted for you that we’re looking at something that’s probably going to be in the neighborhood of probably 30 plus B’s of resource potential on an un-risk basis and on a net risk basis in the 245 that I was mentioning you for last year. That was about 5-6. Have I gotten you tangled up in my underwear?

Joe Allman – J.P. Morgan

So I think like you were talking about that you were going through kind of your portfolio. I think you might have said 50% of your un-risked potentials in South Texas and I think you said 20% in Mississippi, but I’m not sure, I just want to make sure I got that percentage out of the…

John Elias

55% of the total company are in South Texas.

Joe Allman – J.P. Morgan

So you said 55%?

John Elias

In South Texas.

Joe Allman – J.P. Morgan

Okay thanks and then also John I know you don’t want to comment on the strategic process right now but could you give us any just data on you know what kind of timeline we’re looking at in terms of decision, what to do. Are we talking about over the next month or two, like have you set kind of a deadline for, kind of a data room to close or can you just kind of give us some…

John Elias

Without being too specific I will say this is that we’ve had a real high level of interest and we are working with the financial advisor to accommodate all of these parties to access the information that we not only provided in the executive summary but also on our website as well as data room visits and so on. And that process is ongoing. And we have not as yet set a specific date for the annual meeting.

We typically have that in May but we have held off on that until you know this process has a little bit more closure on it. And so you know, I can’t believe it’d be beyond midsummer and the hope is that it would be earlier before we bring some closure on this process. And that’s about the extent of what I can tell you right now.

Joe Allman – J.P. Morgan

Okay that’s helpful and then just two quick ones. This is for John Tugwell. That Chapman Ranch well, so what’s the cost on that net to you guys?

John Tugwell

The net cost there is about $3.6 or $3.7 million.

Joe Allman – J.P. Morgan

Okay and then for Mike, do you have handy your pre-hedge realized prices for gas and oil for the fourth quarter?

Michael Long

No but I can get that for you.

Joe Allman – J.P. Morgan

Okay, I’ll circle back.

Michael Long

I’ll respond to one little, on the Chapman Ranch 19 well, essentially we expect all of those costs with $100,000 deductible I think to be reimbursed to us from our controlled wells insurance policy. So we will not be out that capital for a particularly long period of time and we do have the opportunity still to re-drill that PUD and look at the up-hole reserves in the Anderson.

Joe Allman – J.P. Morgan

Okay that’s helpful, alright thanks guys.

Operator

And we’ll take our next question from Kevin Wink of Polynouth Capital Management.

Kevin Wink – Polynouth Capital Management

Maybe I missed something in one of your comments but depreciation and amortization goes, 23.8 to 28.3 from Q3 to Q4 on a production decline. What was that attributable for?

Michael Long

The change in reserves as we did the year end reserve report the numbers came in below where we’d been originally anticipated was the basic driver of that change in depletion.

Kevin Wink – Polynouth Capital Management

Okay and as we look forward into 08, what looks like a reasonable depletion amount for at least the next couple of quarters?

Michael Long

It’s a little difficult right now with the asset divestitures that are ongoing but I would think a 450-470 estimation rate for depletion would be a pretty reasonable estimate.

Kevin Wink – Polynouth Capital Management

Okay and this is a question which I don’t know maybe you don’t want to address but of the negative reserve revisions in 07, how much was attributable to the Smith properties?

John Elias

Okay, we’ve got that.

John Tugwell

Kevin, approximately 43 BCF equivalents.

Kevin Wink – Polynouth Capital Management

Okay and then.

John Elias

Kevin, let me amplify just a moment. In Southeast Texas that was all Smith and the one dry hole we drilled that there at number 2 accounted for 3.8 B’s and then another 15 plus or minus that we had on the Smith properties for PUDs we took off the books then we reprocessed seismic that we purchased in there and our interpretations suggest that we will recapture all of those reserves we took off the books [not that] related to the Barrett 2 as well as perhaps more than that.

Kevin Wink – Polynouth Capital Management

Well this is actually what I’m trying to explore. You know in retrospect, relative to the size of the acquisition and wanting to show investors maybe quick results, I mean are there things that you did in attempting to exploit the Smith assets that you know maybe you would have taken more time to do in another setting or from another perspective?

John Elias

Well we might have, I think if you take a point in time, let’s just go back to after we drilled the dry hole at South Harden and you take stock of the Smith acquisition I think it would be fair to say that one would assume we paid too much. We then as we reprocessed our seismic and begin to do more drilling in the Flores/Bloomberg, which has been better than we anticipated going in there, we begin to think that you know in time it may not look as bad as it did.

As you also may recall is that we had bought into some exploration opportunities, one being the Yates/Hostetter are in South Texas where Smith had acquired options on some 82,000 acres and we elected to drop out of that, yet we had painted to everybody that represented an area of potential definable growth for us in 2009, 2010 and so on and in the resource numbers that I talked about earlier in our budget, we only had 1 B that we might add from efforts there but after we convinced ourselves and Smith they ought to shoot the area 3D, we saw no prospects and we exited and we recouped all of the dollars that we had invested in that area.

Smith went forward and drilled the initial obligation wells, both of which are dry holes and we extracted ourselves from those as well as an ongoing 180 day continuous drilling program that probably would have required $30-$40 million of investment on our part on a go forward basis over the next few years. So that’s out of the equation, but that piece of it is what’s future growth for the company so when you look at that, it’s not there but that was one of the expectations and so the balance of it lies in the producing assets that we bought and exploit in that both in the Flores/Bloomberg the Mission Mary Grande in Southeast Texas.

Kevin Wink – Polynouth Capital Management

Okay that’s helpful. There’s another comment earlier in the call that, unless I’ve misinterpreted this or misunderstood it that you feel that you get 70-80 B’s back, I don’t want to say pretty easily, but maybe you could give us an operating plan and a timetable for how long it’ll take you to work through what you need to do to try to get that back.

John Elias

Well I would say that the 75-90 that I was referring to about 20-25 of that is reflected in the Southeast Texas area where we are in the process of acquiring acreage now and drilling is through this year into next year. The balance of that is predominately in South Texas on exploratory and exploitation projects we have and in New Mexico and over in Mississippi.

We are right now operating pretty much an interim program ensuring that we are within our cash flow and that we have a good balance of wells that are exploratory and new reserve adds in addition to the PUDs as opposed to all PUD type locations and so we’re really not in a position to define an exact capital expenditure program for the year or exact production but we are moving forward and as this thing plays out we’ll have a better handle on that. But I would say it’s fair to say that my guess of the 75-95 that I’m talking about, that’s over a two year period. But if we had a significant capital investment we’ve got the inventory to do a hell of a lot more.

Kevin Wink – Polynouth Capital Management

Well I mean that brings another question. If you’re reasonably confident in being able to add that back over the next two years and then somewhat confident about the 550 B number that you mentioned earlier on the call, why put the company up for sale?

John Elias

Well that is a good question and we have, we lost significant shareholder value as we all know. And how to do we go about restoring that? And I think it’s fair to say that we can’t restore that value in one year. Can we do it in two years or three years or longer? And we felt it was very important for us to assess the alternative opportunities available to us to see if we can accelerate that process to do something more. Now we sit here with five areas of operations. But the predominant position is in South Texas and its short lived reserves and we’re basically on a treadmill there.

We expect the other areas to ultimately be able to generate a solid revenue for us and profitability and stand on their own but I don’t think any of those are going to be of that nature within the next year or two. And we would like to have four or five areas that can’t stand on their own that can provide sustainable growth and reserves and production and profitability and allow us to capture all the other kinds of opportunities that we see out there on a daily basis. And so that’s been some of the motivation to look at these alternatives. But as I mentioned earlier, the final decision has not been made but we do feel that this push is an appropriate thing for us to do.

Kevin Wink – Polynouth Capital Management

Alright, thanks for your help and your answers John.

Operator

And we’ll take our next question from Ron Mills with Johnson Rice.

Ron Mills – Johnson Rice & Company

Good afternoon. Mike can you walk through on the derivatives side the net impact of the position of being over-hedged given the lower production volumes than anticipated. Is that roughly a $9-$10 million potential, is that roughly about half of the $20 million you talked about of mark to market losses?

Michael Long

Let me do it in a couple of ways. First of the mark to market value at the valuation date of November 29^th which is the latest valuation date we have, of that, a little over $20 million, roughly $15 of that is tied just to our oil and gas contracts covering 2008. So the bulk of it is near term. It will decrease over time as volumes drop through the course of this year but will increase or decrease depending on the change in commodity prices. Oil prices and gas prices are both higher today than they were at February 29^th, that measurement date. But as you get to the end of March, you’ll also have lower volumes offsetting that to some extent.

When we talk about total volumes in a general sense that we expect to produce this year in our hedges, we are over-hedged on our oil based on the significant changes in our forecast of production of oil and very modestly over-hedged on our gas for a total of a little under 150% over-hedged if you just look at those two commodities. However we produce about twice as much volume of natural gas liquids than we do of oil and our natural gas liquids have traded historically at a very consistent percentage of oil price. Its past few months has been ranging between 55-57% of oil if you just look at it on about an 18 month average of 50% of the oil price and consider those hedges on oils if you will an ineffective or dirty hedge on the liquids, you know we’re less than 100% hedged of our expected total volumes for 2008.

And if you were to do some event strategizing around oil prices and you know say oil prices spike to $150 a barrel for three months or so and you have the little change in gas going along with it and you play that out on average for the course of the year, even though the losses we incur on our hedges go up, we still have an increase in total revenues in that scenario over the course of the year because of our significant liquids production.

Ron Mills – Johnson Rice & Company

Okay, but if your gas is 110% over-hedged I guess I was just trying and that caps out at roughly $9.00 on your $40 million to date that you have hedged, it seems like if you had to go out and buy volumes at $10-$10.50 that that portion of your impact is $8.5 or $9 million of a potential loss that you have to go out and satisfy by buying on the open market, is that the correct way to look at it?

Michael Long

Well in a sense the mechanics aren’t you’re buying it on the open market. It’s a financial trade but the effective end result is very similar. On the price stack that we have used for budgeting and planning since the beginning of this year was a flat $7.50 gas and $80 oil. As those prices go up from that level, the hedge gain or loss increases but again because of the liquids production, there’s no question the dollars going out the door is a reduction of opportunity in that revenue but as prices go up from that price stack I gave you to a current strip kind of price stack, the firm’s total revenues still increase because of the un-hedged liquids even though the payout monthly on a basis goes out under the hedges gets larger such that we still have growing liquidity, growing cash flow and increasing revenues.

Now theoretically if prices went to $200 a barrel for a period of time and stayed there, that probably wouldn’t be the case, but under any realistic scenario, planning for the change in commodity prices, clearly we’re losing an opportunity of lose revenue relative to an un-hedged position but I don’t see it in any material way financially threatening to the firm.

Ron Mills – Johnson Rice & Company

Okay and then you talk about January production at 61 million a day, did I hear correctly that you sold 2.5 million of that 61 million?

Michael Long

That’s right Ron.

Ron Mills – Johnson Rice & Company

And so as you look ahead to say a March 30 exit rate, if all the properties are sold, was that 6 million a day gross or net?

Michael Long

The 6, John got a little excited with that 6 million with his new granddaughter and thinking about the rates on the [Prairie Fire] well I think so that was just a misstatement.

Ron Mills – Johnson Rice & Company

Okay and so when you look ahead to a March 30^th exit rate, so here in a couple weeks, is the outlook for production to remain roughly in that 58-59 million a day range?

John Elias

I would think so Ron.

Ron Mills – Johnson Rice & Company

And then as you look to the other sales that you mentioned. You know you have probably another $10 million of properties that.

John Elias

No, no, another ten properties.

Ron Mills – Johnson Rice & Company

Another ten properties, any color in terms of what the potential production impact for that is? I’m just trying to get a sense as to how to build a production profile as we look at 08.

Michael Long

I think those a pretty slight Ron, we’re still negotiating on those properties, don’t know exactly which ones are going to be in or out yet, so it’s hard for us.

John Elias

Ron, on those properties, one of them [Hemp Collums], a number of them are just a one well concentrated position. And whether somebody wants to come in and pick up that interest is some question. We’re trying to determine what the ownership is and there’s some reversionary positions with overrides to working interest after payout of going so all that’s got to be worked out and whether we can really find somebody that’s interested at the level we like is still a question.

Ron Mills – Johnson Rice & Company

Okay and then Mike, have you all given 2008 production guidance just based on your lowered capital program as you go through this process, is the hope that you can just pretty much maintain production at these levels with potential upside if you have a well like this Morrow well in Southeast New Mexico, can obviously be a surprise. But is the plan really to hold production fairly flat?

Michael Long

It’s really the focus of our activities, I mean it is, you know we’re trying to serve several masters all at the same time here and yes we’d like to try to hold production at a relatively flat level and yet we would like to do our best to enhance the evaluation of alternative processes as we go through here as well. So it’s a constant balancing act.

John Elias

Now we could, if we had the capital we have an awful lot more that we could spend and would see increases we think in production and reserve ads but we do have that constraint and then of course the requirement of our staff in the strategic alterative evaluation process and additional ongoing operation is quit taxing and stressing on the entire workforce.

And so we’re trying to make sure that we do things efficiently and not trip all over ourselves and we have a very strong effort as I mentioned in my comments to bring as much of the opportunities that we’re identifying when we complete the technical interpretation, quality acreage and bring it to a ready state so that it’s all the sudden somebody said hey let’s move forward that we’re in position to do so. And we’ve got a lot of that that’s going on right now.

Ron Mills – Johnson Rice & Company

Okay, thank you guys.

Operator

And we’ll go next to Wayne Andrews of Raymond James.

Wayne Andrews – Raymond James

Good afternoon gentlemen. Hey John could you, Tugwell, please go over again the Chapman Ranch, I’m not sure I caught all exactly what happened when you mentioned the well and maybe you could just sort of review what the current level of activity forecast there for the remainder of the year and what sort of hopes you have for the field remaining.

John Tugwell

Okay Wayne sure, Wayne the well that we started that I talked about is one that we spud right after the first of the year, Chapman Ranch number 19. Our main objective was the [howell height] interval which is you know the main producer in the field there. This well was on the southern end of our field. There’s some really good Anderson production up on the northern end of the field of the [howell height] field and further north, there’s some wells up there that produced over 15 B’s each. We have not seen any Anderson production or have not realized any Anderson production on the south end of the field where we were drilling this well.

We drilled into the Anderson and experienced a much higher pore pressure there than we had designed the well for and had a heck of a lot of gas there. So you know we have indications that we got into a new fault block down there at the Anderson level that appears to be gas charged. We had an underground flow in the well, you know flow from the Anderson up to the shoot, the casing shoot which was between 10,500 and 11,000 feet. We hit the Anderson at about 11,500, so because of that underground flow, the most prudent thing for us to do was just to abandon the bottom part of the hole, you know get that under control and temporarily abandon the well and move off and evaluate what we wanted to do out there next.

Wayne Andrews – Raymond James

So was that a fill the bottom of the hole with cement, is that what you mean?

John Tugwell

Essentially yes.

John Elias

But we temporarily abandoned that well as John just mentioned, Wayne and we can sidetrack out of that. Or we can drill another well. We’ve spent about $2.5 million on a $4 million plus AFE at that point in time and the staff made an excellent recommendation and decision, let’s stop here because we could all of the sudden spent $4 million, $6 million or a whole lot of money just to get this well under control and so we’re looking at it, we drill wells to the Anderson to develop that and other wells down to the [hennet] to develop that. So we’re encouraged by what we’ve seen but as John said the Anderson on the north side of the field is another lucrative target.

John Tugwell

The rock quality in the Anderson sand is really good. It doesn’t need to be fracture stimulated. Most of the wells were completed as natural flowing wells in that zone. So you know I think we just found something that appears to be a new fault block gas charged. We had a heck of a lot of gas coming out of [seral] on that well and we really hadn’t seen that on the south end of the field anywhere else.

Wayne Andrews – Raymond James

So what’s the next step here at Chapman Ranch?

John Tugwell

Well the next step is to, we aren’t drilling right now but as John and Mike mentioned, as part of our ongoing process here we’re bringing things to drill ready status and you know we’ll pull the trigger here at the right time. We’re starting our program up.

John Elias

Wayne, obviously the Anderson is resource potential in Chapman Ranch that we hadn’t envisioned so that’s a pleasant surprise. Two, as a result of all of the additional seismic interpretation that we’ve done in here, we see a sub-biplane opportunity out of which could be a piggyback exploration well on one of the [hennet] wells but we’re looking at that as a standalone as well as piggybank and looking at the Anderson and looking at the [hennet] on the south side of the field so there’s a whole number of things that we’re trying to come to grips with.

John Tugwell

And I’ll just amplify a little bit Wayne, part of the dilemma that we’ve talked about here a little bit of serving different masters right now in terms of our operational planning is we have, we’re constantly being brought numerous good opportunities to expand our program in this interim basis we’re trying very carefully to live within our cash flow and we’re picking and choosing which ones best fit with the success on the [prior fire] we’re looking very hard as an offset to the [prairie fire] right now and because of that do we move, do we defer something until later in the year that was originally planned now to take advantage of offsetting a well that’s had these tremendous flow rates. In a normal operating environment for us right now, we’d still be drilling at Chapman Ranch, looking at that opportunity and doing other things at the same time. But we’re just being a little more cautious for an interim period now.

Wayne Andrews – Raymond James

Certainly and I understand that. Maybe could you just give us a little detail on sort of what at least the drilling program is maybe for the, what do you plan to do for the next say three months?

John Tugwell

Well we plan to have a continuous program at Flores/Bloomberg, we’ll have a program of [overlay].

Wayne Andrews – Raymond James

That’s one rig?

John Tugwell

Right now we have one rig running out there. That could change as we move on through the course of the year. We do still plan to drill some wells in New Mexico, as Mike mentioned we’re looking hard at an offset to the [prairie fire]. There’s some shallow drilling that will take place out there and you know and potentially in some of the other areas in South Texas we’ve got drilling there.

John Elias

And we’re looking to put a leverage transaction to drill our Santa [Lena El Fortunado] prospect which is a deeper higher potential type opportunity and our land department is closing on the major lease purchase, how much acreage is that John?

John Tugwell

Just under 9,000 acres.

John Elias

Just under 9,000 acres in the South Texas area, an extension of our plays down there and embarking on a 3D seismic program. We’re in the final stages of interpretation through an outside party the soft sediment interface over in the Midway Dome in Mississippi and the initial feedback that we have is encouraging and if so we’ll be looking into what we need to do there. But it’s all being balanced by the strategic alternative process Wayne.

Wayne Andrews – Raymond James

Of course, great thank you very much.

Operator

(Operator instructions). We’ll go next to Robert Shakter.

Robert Shakter

Good afternoon gentlemen, I’m a private investor. The huge drop in the price of our stock I think Wall Street blamed on the lower amount of reserves that we were reporting. And listening to this conversation, it’s my understanding that it was a timing problem, mostly. You’re talking about being able to recapture which I guess means to be able to get those reserves back when you drill.

And if that in fact is the case, if we dropped out I don’t know it was 60-70 billion cubic feet on reported reserves and a good part of those reserves can be recaptured when you drill, I just think that this wasn’t made clear to Wall Street. And if in fact those reserves are really there but not drilled, I think the huge drop in our stock was not warranted and I think if I’m correct I think that should be made clear to Wall Street.

John Elias

Well we have tried to be clear there but let’s go back at the beginning of the year and look at this. We went out and created expectations and one might say that we were unrealistic, we were too optimistic, whatever, but we talked about 240, 60 B’s we talked about production levels of 28 B’s for the full year. And then we move into the end of the second, first quarter and into the second quarter and each period we were lowering our expectations, so consequently our credibility was diminishing to the fact that it wasn’t there.

Then we came forth and said that the Yates/Hostetter areas as I mentioned earlier which was a large area surrounded by a very sizable field that we were extracting ourselves from that yet we had communicated that that could be potential definable growth out there in 2009 and beyond and now we were coming out of it. Well we didn’t have any resource potential projected of any substance of this in 2007 but that’s gone. When you look back at it as a solid decision, we avoided spending $12 million on an 18,000 foot gross basis, half of that to ourselves on a well that turned out to be dry. We avoided spending a lot of money on another well and future drilling in that area. So hindsight, that’s good but that potential in the eyes of Wall Street and everybody is gone.

Then we go over in Southeast Texas and two wells brought on stream by Smith right at the end of 2006 it came on I think what 4-5 million a day something like that John. And we jumped in between to drill a well that turned out to be a dry hole. And it just dumbfounded us. So we took all of those reserves off the books and all the associated PUD locations that were similar type prospects and so there that was, that comes back. And as I told you earlier, we think those are re-capturable now based on our work. But the interpretation, the trap interpretation is a bit different and then we think the exploratory wells that were deferred and those are risk numbers that we’re giving you, those are in our inventory.

And we will capture that. Now will we capture that or a whole heck of a lot more, that’s just the risk in the business but our portfolio is very attractive, do the shareholders have the patience to let us work over the next two or three years to establish that fact? Some do, some don’t. Mike Long and I get beat over the head about everyday of all the phone calls coming in here and so we’ve taking this path to look at these alternatives to try to determine what is the best thing for the shareholders.

And as I’ve said earlier, if we really can establish a meaningful position in three or four other areas, just like South Texas, then we’re going [justly] well beyond what we are right at this point in time. Now can that be done? I don’t know. But we feel confident that the portfolio that we’ve built, the ready to drill one is has a lot prospectivity and I would highly recommend if you haven’t already to go under our website and look at the information and detail that we have provided there on our inventory, the technical interpretation there and if you want us to address any aspect there just pick up the phone and give us a call and we will. So I understand where you’re coming from and we’re trying to educate every, we try to always be honest and up front.

What we’re doing well, what we’re doing bad and most of last year was telling you things that were downward spiraling of what the expectation we built there and from that we’re not left with much credibility.

Michael Long

Bob, just a couple of cautionary, I appreciate what you said and how you looked at it. Two things, I’d just like to remind you from a cautionary standpoint is that it’s non proven reserves, exploratory reserves and reserves or resources subject to future drilling are a riskier category of reserves than existing proven reserves. And then you mentioned recapturing it. Certainly something we believe has some potential for us but as Wall Street correctly looks at it, we paid for it once, maybe in the acquisitions, if we have to drill again to recapture it, you could have to pay for it again. So it becomes not only just a change in resource estimates, it’s the capital availability or cost of bringing it all to fruition.

John Elias

We did pay for it in the sense that is was highly risked and in the transaction the dollars associated with drilling for that are not built in.

Robert Shakter

Now as a practical matter, the prices of other gas companies are exploding upward. I’m sure you’re aware of it. And a gas company would understand the acreage that we have and the proven and unproven and risk and so forth. And I would think that if today in today’s market with gas at $10 and prices of other gas companies selling where they are now, some almost at new highs that it should be fairly easy to interest some other gas companies in acquiring us with their stock which would really means that they’re getting our company for a huge discount because of the right that they’ve had. Do you see it that way?

John Elias

We can see that scenario, yes.

Robert Shakter

Okay, I guess that’s all.

Operator

And we’ll take our next question from David Van Treuren of Maloney Securities.

David Van Treuren – Maloney Securities

Hi I just wanted to ask a question, discussed this with Michael a little bit but, in any kind of deal and it could be many different kinds if you went that way, what would happen to the preferred to clarify that for the group here.

Michael Long

It is not an easy answer unfortunately so you’re probably not going to be satisfied. There is one simple break in scenario and that is if there is a transaction where the purchase of the common stock in Edge is funded with more than 10% cash. By the terms of the preferred stock there is a fundamental change defined to have taken place and in that event we are obligated to offer par value to the holders of the preferred and that par value is $50 a share times the number of shares outstand, it’s about $143 million.

Now, they are not obligated to take our offer, but we’re obligated to offer it. If the transaction is less than 10% cash, there is not a fundamental change and the terms of the what happens to the preferred in that case becomes a negotiated event that is not well spelled out. It is not spelled out in the indenture.

David Van Treuren – Maloney Securities

So it could be more or less than the current market price?

Michael Long

I presume, yes, that would be a possibility.

David Van Treuren – Maloney Securities

Okay, thanks.

Operator

And gentlemen we have no further questions at this time, I’ll turn the call back over to you for any additional or closing remarks.

Michael Long

Very good, Dana thank you, everybody thank you for taking the time with us and we’ll be interested in how we do this again at the next quarter.

Operator

And that does conclude today’s conference call. Thank you for your participation. You may disconnect at this time.

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