Evolution Petroleum Corp (EPM) 2009 Q1 法說會逐字稿

Good morning, ladies and gentlemen. Thank you for standing by. Welcome to the Evolution Petroleum first-quarter fiscal 2009 earnings conference call. During today's presentation, all parties will be in a listen-only mode. Following today's presentation, the conference will be open for questions. (Operator Instructions) As a reminder, this conference is being recorded today, Thursday, November 13, 2008.

At this time, I would like to turn the conference over to Ms. Lisa Elliott with DRG&E. Please go ahead, ma'am.

Good morning and thank you, everyone, for joining us for the Evolution Petroleum conference call to review first quarter of fiscal 2009. That ended September 30.

Before I turn the call over to management, I have a few comments. If you would like to be on the Company's e-mail distribution list to receive future news releases, please call DRG&E's office at 713-529-6600, and someone will be glad to help you. If you wish to listen to a replay of today's call, it will be available in a few hours via webcast by going to the Company's website at www.EvolutionPetroleum.com, or via recorded replay until November 20, 2008. To use that replay feature, call 303-590-3000 and dial the pass code 111-22-120.

Information recorded on this call is valid only as of today, November 13, 2008, and therefore time-sensitive information may no longer be accurate as of the date of any replay.

Today, management is going to discuss certain topics that contain forward-looking information, which is based on management's beliefs as well as assumptions made by and information currently available to management. Forward-looking information includes statements regarding expected future drilling results, production, and expenses. Although management believes that the expectations reflected in such forward-looking statements are reasonable, they can give no assurance that such expectations will prove to be correct.

Such statements are subject to certain risks, uncertainties, and assumptions, including among other things oil and gas price volatility; uncertainties inherent in oil and gas operations and estimated reserves; unexpected future capital expenditures; competition; governmental regulation; and other factors described in the Company's filings with the Securities and Exchange Commission. Should one or more of these risks materialize or should underlying assumptions prove incorrect, actual results may differ materially from those expected.

Today's call may also include discussion of probable and possible reserves or use terms like volumes, reserve potential, or recoverable reserves. The SEC generally only allows disclosure of proved reserves in Securities filings; and these estimates of non-proved reserves or resources are, by their very nature, more speculative than estimates of proved reserves and accordingly are subject to substantially greater risk.

Now, I would like to turn the call over to Bob Herlin, Evolution's Chief Executive Officer. Bob?

Thanks, Lisa, and good morning to everyone with us on the conference call. With me today is Sterling McDonald, our CFO.

We released our fiscal first-quarter results this morning by press release, and so we will let you go through those numbers on your own. We are just going to review what we think are the key items here this morning, as well as operational issues and matters.

Sterling will highlight some of the numbers later, but first I would like to say that we are pleased to have reported another good quarter. Our revenues for the first quarter for fiscal '09 grew by 480% over the first quarter of last year and grew 21% sequentially over the last quarter. This revenue growth was driven by increases in production and received commodity prices.

We've produced about 34,000 barrels of oil equivalent in Q1 of '09, which is a 361% increase over production volumes in the prior-year first quarter and 25% higher than the production in the last quarter of fiscal '08.

We received commodity prices in Q1 of '09 at a level 20% higher than Q1 of '08. But we are essentially flat to the last quarter of '08. On a BOE basis, accounting for our mix of natural gas, gas liquids, and crude oil, the blended effective price that we received was about $85.50 a barrel of oil equivalent in Q1 '09.

The growth in production came entirely from our operations in the Giddings Field of Central Texas. Last year, our revenue was entirely from production in the Tullos Field, Louisiana, and about $340,000 of earned interest income on our cash.

Since we sold our interest in the Tullos Field in March of this year of '08, essentially all of our net production comes from the Giddings Field. At the end of September, we had seven wells on production. As you might recall, our fiscal '08 capital program included the drilling of five horizontal reentries, the drilling of one grassroots horizontal well, and the restoration of a seventh well to production through a workover.

Three of those wells began production in June, so we had the benefit of all of these wells throughout most of Q1 of '09. Current production appears to have stabilized at a gross production rate of about 315 to 350 BOEPD. We expect more sedate future production declines.

Although we are pleased with the early results of redeveloping in Giddings Field and have built a substantial inventory of proved drilling locations that we believe remain quite economic at current commodity prices, we have decided to slow down the drilling program in Giddings Field for the balance of the fiscal year.

Since these wells typically produce a large portion of their reserves relatively quickly, we believe that it's in the shareholders' best interest to defer most of this drilling until commodity prices are higher or drilling costs respond to the changing market dynamics. We do actually see some of that occurring now.

Our balance sheet and working capital position continue to remain strong, but we think it is prudent to budget and operate more conservatively until the financial market stabilizes. Therefore, on October 31 we announced that we had revised downward our capital expansion budget for fiscal '09 from $19 million to less than $10 million. Now, this is going to allow us to retain more liquidity so that we can be better positioned to take advantage of opportunities that may arise over the next year, while still adding incremental value production and cash flows.

Our revised '09 budget is focused on building intrinsic value per share. Our drilling activity is primarily intended to move existing resources into a proved reserves category, or lease acreage with reserves that we believe will be categorized as proved undeveloped, as well as other opportunities to increase share value such as selective repurchase of common shares.

Our revised budget provides for drilling up to three reentry horizontal wells in the Giddings Field, which is a production from the previous 10-well reentry plan, subject to future changes in commodity prices and market conditions, of course. One of these reentries should allow us to move one or more of our probable locations into proved reserves.

The first Giddings Field reentry in fiscal '09 capital budget will be spudded shortly. In fact, the rig is on location as we speak. For your information, most of our reentries produce a combination of natural gas, gas liquids, and crude oil. We incorporated the results of our drilling in the spring of this year in Giddings Field into our program. As a result, we replaced a number of lower potential locations with those with higher potential based on those drilling results.

In Oklahoma, we now have some 18,000 net acres leased in our shallow Woodford Shale project. We planned initial drilling of up to five low-cost vertical wells within the Woodford Shale in order to potentially quantify and convert that resource into proved and probable reserves, particularly in light of new rules governing proved reserves in continuous resource reservoirs that have been proposed by the SEC.

The drilling will also test shallower conventional objectives that produce in the area, and our leases have been offset by another operator, with more than 50 wells drilled and completed in an even shallower portion of the Woodford Shale. Now their apparent drilling success would suggest the likely commerciality of our acreage project and well.

We selected the shallow Woodford as a vehicle to generate repeatable gas reserves drilling locations, utilizing low-cost drilling technology such as air drilling. Deeper shale reserves generally require more expensive drilling methods and massive hydraulic fracturing to overcome higher pressures.

Now we also plan to complete leasing and drill up to three low-cost wells in our new Texas project, which we call Neptune, to establish proved reserves of moderately heavy oil associated with water at shallow depths. Now, we are not really ready to disclose the exact location, because we are still in leasing mode. But we are well on our way in our leasing activity. We expect to have our lease position secured sufficiently to allow us to drill these first wells during the fiscal year of '09.

We believe that historical results of infill drilling in this targeted field during a previous period at a much lower oil price will allow our independent reservoir engineer to categorize these as proved reserves. Even better, this reservoir is ideally suited for the application of our well completion technology that we developed and tested in the Tullos Field property in Louisiana. The technology as tested appears to improve the mildly heavy oil portion of production and reduces the water portion in an economic manner. However, the project economics and attractiveness does not depend on the successful application of this technology.

Now, late last month, we completed a block repurchase of some 788,000 shares of our common stock from an unaffiliated institution in a negotiated transaction. That was at an average price of about $1.10 per share, plus nearly $0.02 of transaction costs. This is an example of utilizing our liquidity to take advantage of specific opportunities.

In this case, we bought shares for total cost of $1.12 that we believe have an intrinsic value of some $9.50 per diluted share, based on $65 oil and $6.50 gas. This is a return of 8.5 to 1, and we think it's a great deal for our shareholders. We don't have current plans to repurchase more shares at this time, but we do keep that option open.

On a somewhat related note, my cofounder and a Director on our Board recently sold almost all of his holdings in the Company, some 6.7 million shares. As he stated in his press release, the sale was necessary to meet other financial commitments and did not reflect his strong belief in the Company's future and value. About 70% of his shares were purchased by two existing institutional shareholders of our Company.

Now I will turn this call over to Sterling to review financial results.

Thank you, Bob. I would also like to thank all of you for joining us today. As Bob mentioned, we aren't going to read the numbers to you this time, but I would like to point out a few items.

Financially there are two principal drivers of our strategy that we think is appropriate in this unsettled environment. First, to maintain our liquidity and cash flow; and second, to continue adding to intrinsic value per share.

Believe both of these strategic drivers are consistent with the unprecedented crisis affecting domestic and world financial markets. It's also presenting incredibly deep value opportunities for those fortunate enough to possess cash.

Taking this first point on liquidity and the earnings that drive it, with respect to liquidity we finished Q1 '09 with about $12.9 million of working capital and we still have no debt. This is not materially different from the $13.6 million of working capital we had at June 30, especially when you consider that we used $4 million of cash to invest in our oil and gas properties during the quarter, including relieving payables from the prior quarter associated with our oil and gas properties.

Helping to drive this liquidity, net cash provided by operations for Q1 '09 was about $2.2 million. It has been the highest in our history, ex capital transactions, and it was a substantial increase of $3 million over the $800,000 we used in operations during Q1 '08.

Sequentially, net cash provided from operations increased $1.9 million from the approximate $300,000 provided in Q4 '08.

Q1 '09 working capital was also supported by a $1.1 million increase in net operating assets. I might also add that our working capital consists of $14.3 million of cash and near cash. This consists of $9.5 million of cash invested in a short-term U.S. Treasury fund; $3.6 million of recoverable income taxes; and $1.2 million in revenue receivables.

Of importance, the $3.6 million of recoverable income taxes is to mostly to excess IDCs we generated in 2008 which couldn't be used in the current year's return; and therefore we are carrying them back to our fiscal 2006 return. The 2008 and amended 2006 returns are expected to be filed this week, with collection expected in early calendar '09 of the $3.6 million recoverable.

The net income component of cash provided operations a penny a diluted share in Q1 '09 compared to a net loss of $0.02 for Q1 '08. Sequentially the current quarter matched Q4 '08's net income of $0.01 per diluted share.

Operationally, in addition to the 480% revenue growth Bob discussed earlier, lease operating expense per BOE for Q1 '09 declined 73% over Q1 '08 to $12.22, due to our sale of the Tullos Field and its high lifting costs and the lower costs associated at Giddings. Sequentially, LOE was almost flat, with $12.11 per BOE experienced during Q4 '08. When combined with increased production, our Tullos redeployment into Giddings appears to be paying off with much higher economic value.

On the general and administrative front, G&A expenses increased 10% to $1.5 million in the current quarter as compared to $1.3 million in the prior-year quarter. Our overall comp expense for estimated bonuses and new staff, including non-cash stock compensation, accounted for the majority of the increase. The new staff was associated with the buildup of our infrastructure to execute our drilling programs.

One final observation about our liquidity as it relates to G&A. Our working capital, adjusted for the subsequent $883,000 stock repurchase, was about $12.1 million on a pro forma basis at September 30, 2008. This exceeds about 11 times our quarterly G&A rate before non-cash charges, based on about a $1.075 million in the most recent quarter. Although this approximate three-year overhead coverage ratio can be reduced by capital expenditures and other unexpected expenses that may not be fully offset by cash flow from our field operations, we're encouraged that this coverage will provide a sufficient bridge to reach production expected from our Delhi field without any expected need for further additions to our liquidity. In summary, we expect to survive a nuclear winter should it persist.

On our second point and our second strategy as it relates to our financial management, relates to our additions to shareholder value. Although we have no current plans to repurchase common shares at this time, we retain the right and flexibility to do so as opportunities may occur and changes in our working capital might allow. We also may consider bringing in partners on our projects in Oklahoma and Texas in order to accelerate their development, with the ultimate goal of increasing share value, as Bob discussed earlier.

That completes my comments. I will turn it back now over to Bob.

Thanks, Sterling. I would like to add that the CO2 enhanced oil recovery project at the Delhi Field in Louisiana continues to move forward. There is every indication that Denbury is moving at full speed to complete the CO2 pipeline to Delhi, along with gas processing facilities and other field work. Denbury has continued to state that its first CO2 injections are scheduled sometime in the first half of calendar '09, with first production response later that year.

The Delhi project is their major CO2 addition in calendar '09 for adding proved reserves. At this point, we believe that the amount of additional capital expenditures to complete the project is probably far less than that which has already been spent to date by Denbury. Our overriding and mineral royalty interests will generate substantial net cash flows to us as soon as first production begins. We continue to agree with Denbury as to the potential recovery of oil from the Delhi Field.

I would like to remind you that we have approximately 13 million barrels of net probable reserves associated with that project. This compares to the 33 million net barrels that Denbury has publicly stated that has been assigned to them by their outside engineer.

In summary, we've got great assets. We have the opportunity to continue adding value within our budget through our expertise. We have substantial working capital, no debt, no near-term expiring leasing. Thus we can remain very flexible. We can adjust our capital budget as necessary, and we can pursue selective opportunities as they arise for the benefits of our shareholders.

With that, we will be happy to take your questions.

(Operator Instructions) Phil McPherson, Global Hunter Securities.

Good morning guys. How are you doing?

Good, how are you, Phil?

Doing well. Weathering the storm. It sounds like you guys are doing the same. I know you don't want to tell us too much about the Neptune project, but can you tell us what degree oil the heavy oil is; and what method is it going to be? Are you going to have to inject steam or something to get this out? How heavy are we talking?

This is what we call moderately heavy. It's like around 20 gravity oil. It flows on its own. It doesn't require steam whatsoever.

It is just that whenever you have oil in conjunction with water, always has a problem because water has a much higher desire and ability to flow through a rock than oil does. When you get a little heavier oil, that difference is magnified.

So, what we have all across the Gulf Coast, there are lots of reservoirs where you have oil in direct contact with water, particularly an active water drive. As a result, you get [cony]. Wells that you drill initially have very high oil rate; but then the water pokes through and dominates production. Then you have your water cut goes to a very high level.

Thus, the only way you have of getting the oil out is to drill lots and lots of wells in very narrow spacings. Actually what happened in our Tullos Field, they actually got that spacing down to about two acres, believe it or not, and were able as a result to get a lot of that oil out.

What we did was we ran across some technology about a way of producing the oil with a lot of what we call jewelry in the hole, that allows us to substantially increase that oil cut and therefore reduce the amount of water production.

We actually drilled a well in the Tullos Field; we applied this technology. We had to do some adaptive work with the downhole equipment, develop these techniques and tools, and were very successful in that it did exactly what we thought it was going to do.

We played with it, we tested it, we did all kinds of different things with it, and it pretty much did everything it was supposed to do. It is always nice when actual results kind of flow along with the theory.

As a result of that, we wanted to apply this technology. Tullos was not a good place because it was already so thoroughly infill drilled. So what we did was say -- where can we find a similar reservoir, but on a far less densely drilled basis?

And in Texas, we have found a number of these opportunities where well fields were drilled back decades ago, infill drilled, down to certain spacings. We have a lot of really good historical information which shows exactly how much oil they produce on an infill basis. But because of oil prices declining in the '90s, the infill drilling was not completed.

Therefore, there is substantial opportunity to go in, first, just conventionally and just drill more wells on a reduced spacing. We know exactly what kind of reserves we can expect because of the past drilling.

On that basis alone, the project is very economic, very profitable, and we think will allow us to add proved reserves just with leases. Now, we will also be applying this new technology; and if that works as we think it will and has been demonstrated in the Tullos Field, then that would add even more reserves.

So we are very excited about it. It's a very nice upside potential. It flows with our whole strategy of using technology to add incremental reserves at low risk, at low cost. (multiple speakers) there is no steam involved.

When would you expect first production to be material as far for us modeling it out?

I think that our capital budget plans for us to spend the money to drill the wells, but it does not provide for any revenues during the fiscal year. Again, we're trying to be a little on the conservative side in expectations.

So I mean, by the end of the fiscal year, we think we will have initial rates. I don't anticipate it being a material contributor to production revenues in fiscal '09, however.

Okay, great. Well, I will let somebody else jump on and I will requeue. Thanks, guys.

Joel Musante, C.K. Cooper & Company.

I just had a few questions for you. You seem to allude or allude to the fact that you might -- if market -- if the lower prices make rig rates come down you might accelerate your program some. Is that -- was that the case, or did I --?

The program that we have in the Giddings area, we could drill those wells now and we think that they will generate value of, I don't know, $2 to $3 for every dollar we invest. Which is -- there is nothing wrong with that.

We just think at this current time we can do better. Alternatively, we really don't want to convert those reserves into production at the current oil and gas prices. We would rather hold off until we get better value.

Now, the offset to that is if drilling costs come down sufficiently, then the economics improve; and instead of a 2 to 3 to 1, it's 3 or 4 to 1, then that might encourage us to go ahead and drill maybe another well or two reentry this year.

But we are real flexible on this. We are going to do whatever is in the best interest of the shareholders, which also means we want to maintain a very high level of liquidity, just to make sure that we have the ability to operate and function over the next couple of years.

Again, the big prize at the end of the line is the Delhi project. So we really want to make sure the Company is in a position to take advantage of that.

Okay, all right. Given your liquidity situation, I know you have talked about it in the past, possibly being in the M&A market. I was just wondering if there is anything you have seen there that looks attractive, and what you might be looking for.

Yes, our stock.

Yes, Sterling's point is well taken. The company we know the best is our own. That is why we bought those 800-some-odd-thousand shares a week or so ago at basically buying reserves in the ground for about $1.20 a barrel.

That would be -- the competitor for doing a deal with some other party is -- can we do even better than that? So we are always looking at opportunities. We think that the opportunities aren't there yet. The market has still got a ways to go before those opportunities may come to the surface.

Okay. Well, that's all I had. Thanks.

(Operator Instructions) Neal Dingmann, Dahlman Rose.

Good morning, guys. Say, Bob, just wondering on the Neptune, you mentioned about when drilling and all. When do you think then, it would be around that same time when you could start seeing some credit for some reserves there?

Well, our goal there, obviously, is to get credit in our reserve report that would come out in August of next year as of July 1. So, that would be the target for getting the leasing completed and first wells down.

We actually think that we will get credit just for leasing alone. Now what we would like to do is get credit as well for the enhanced technology impact. To do that, we have to get the wells drilled and producing at a substantial rate for some period of time.

So, whether or not we get credit for the uptick in value of the technology, then that is pretty subjective at this point. We definitely think we are well positioned to get credit just for the leasing component alone, for the PUDs based on historical infill results.

Okay. Then lastly, Sterling, it sounded like -- unlike some other guys that I guess would have maybe what I would call higher maintenance CapEx, for lack of a better term -- it sounds like you all can really scale back. How would you or what would you say is your minimum or -- when I use maintenance CapEx, basically just the cost to run your existing assets and to hold your leases. What would you say on a quarterly basis? How low is that for you all?

That's a good question. As far as lease maintenance is concerned at this time, we are not particularly close to expirations. Yes, we do have re-ups that we can pay additional bonus to extend those leases.

So certainly, time eventually works against one there. But currently, we have no maintenance requirements.

I guess that was kind of the point about as far as capital maintenance is concerned, other than possibly leases, our capital maintenance is pretty much our overhead.

Just a bit of the G&A then?

Yes, I guess it's not capital. That's expense, but the point being that our biggest charge is right here in the corporate office; and of course, it could be adjusted some, maybe. But, I think we are in pretty good shape.

We are looking at almost three years of coverage there, assuming our operations can carry our working capital, our capital expenditures over the same three-year period.

Just to expand on that, the two to three reentry well program at Giddings, that is intended to sustain our current revenues on an average basis during the course of the year. So to that extent, you could say that is kind of like our maintenance capital to maintain our current level of revenues.

That's a good point.

Then the additional expenditures are directed for value growth.

Got it. Got it. Thanks, guys.

Phil McPherson, Global Hunter Securities.

Just going off the production comment you just made, so then you would expect fiscal second quarter to be down slightly from the first quarter; and then third quarter to come back up to first-quarter levels? Is that a good way to think of it?

We definitely expect that Q2 revenues will be down strictly due to oil and gas pricing. The current level of production that we have, we think is a level that's a sustainable level with declines on a much, much lower or modest decline level. We have already experienced the bulk, if not most of, the [flash] decline that is typical of the chalk wells.

So going forward, it should be pretty low decline rates; and therefore, production should be very sustainable and predictable. So our exposure on the revenue side is really on commodity prices.

So in order to maintain or increase in revenues, it will be coming from the drillbit.

Okay, great. Just one other bigger-picture question. With the other founders now selling most of the stock, the Chairman, do you anticipate him staying on as Chairman? Or have you thought -- is that a question that is kind of going on in the Board room?

Laird still maintains an ownership position of a small amount of stock. He has affiliates that still own a substantial amount of stock, a couple million shares. So Laird, if you have read our proxy, has been renominated for our Board elections that will be held or shareholder elections in the first or so week of December.

Laird is on the Board not just because of an owner or because of a cofounder; but also because he brings knowledge of the financial side of Wall Street. So everyone on our Board is there because they have specific expertise, whether it be upstream operations, oilfield services, public company audit, and then financial expertise.

Now, we have added a sixth member to the Board, or we have proposed adding a sixth member. That person is [Kelly Lloyd]. He is affiliated with JVL Partners, one of our large institutional shareholders. And he will be joining the Board subject obviously to shareholder vote that is going to be held here in early December.

Okay, great. Thanks, guys. Good work.

Dick Feldman, Monarch Capital.

Good morning and a nice quarter. I've got a question about the Woodford Shale. What is the timing of your drilling there? Do you think you will be able, if you are successful, to recognize reserves? And is the drilling --

Dick, can you speak up?

What is the timing of your drilling in the Woodford Shale? Do you think if you are successful, do you think you will be able to recognize reserves in this fiscal year? And are you doing any drilling in the deeper portion of the acreage? Or will it just be limited to your shallower acreage?

Good questions, Dick. We are planning and our capital budget provides for the drilling of up to five vertical wells in the shallow portion of our Woodford program where we have some 9,500 net acres. That is the area that we have over 50 wells offsetting us by another private operator.

The goal there is, as I have discussed in various presentations, is to convert that from a resource into a proved/probable reserve base.

Now obviously, under current definitions of the SEC, you are limited to your PDP plus one offset in each direction of your fracture trend. The proposed new SEC rules for a new type of resource proved reserve, if adopted -- which every indication is that it will be -- would allow us a more expansive quantification of those reserves. That is one of the goals of that drilling.

We anticipate that the drilling will commence sometime in the second half of fiscal '09. There is a process involved that requires various amounts of regulatory permits and so forth, hearings, to capture acreage to be included in drilling units. However, we do believe that we will be able to get that program going.

These are fairly cheap wells to drill, about $120,000 to drill and complete, plus maybe another $20,000, $30,000 of gathering cost.

So yes, we do believe that we will be able to add proved reserves as a result of this program at the end of fiscal '09.

In terms of our deeper project there, we have tentatively identified that we want to try and get a well drilled. Now whether or not we get that well drilled, completed, and producing by the end of fiscal '09 is open to question. There has only been one offset drilled to date. Albeit a highly successful well, but still just one well. So there is a lot of reasons to go ahead and let other people continue to prove up that area for us.

If the SEC changes its rules, that would still allow us to capture that benefit in that acreage because of the offset. But at this time, I can't tell you for sure that we will drill a well on that deeper acreage in fiscal '09. It probably would be maybe first quarter of fiscal '10 would be probably a better or safer guess on the timing of that.

If you did drill a deeper well, would it be a vertical well, or horizontal well?

I can't tell you for sure. We may drill the first one as a vertical just to have a comparison. It is a cheaper way to test it. We may -- that isn't likely to be more of a horizontal play, because of the depth and because that is what the offset did very successfully.

It still is at a depth that allows a fairly low-cost hydraulic fracturing multistage process. But I can't tell you for sure.

We actually -- the one thing that might allow us to accelerate that is if we did a reentry through an existing wellbore; that would allow us to cut the cost quite a bit. We may try and do that earlier -- or sooner than later. But yes, that would more than likely be a horizontal play.

How long -- does it take much time, going back to the shallow wells that you plan to drill, after you drill them, for them to clean up? What kind of fracs do you use, if any?

These are -- the shallow wells there and the practice that is being seen in that immediate area is a fairly mild light frac that is being done just to clean up the near wellbore area. So, therefore, in the acreage that we have leased, we deliberately chose to stay away from contact with water-bearing reservoirs.

So, we think that we will be able to get a fairly quick response. Until we do it ourselves, I can't tell you for sure. All we can do is look at what other people have done in that area.

But we are expecting a fairly initially high response. It might take a month or two of inclining production to get to your peak rates. And then you have a fairly low decline from that point going forward.

Now these are not high-rate wells. We are looking at from a vertical well we may only get 60 or 70 Mcf a day. The key there is that, while it's not much per well, we've got over 400 of these locations that we can drill and at a fairly low cost. $120,000-plus per well, 70 Mcf is not a bad number at all. Very economic even at the current gas prices.

So, this could contain 50 to 100 Bcf of reserves?

That is a very good possibility that that is the resource number we are looking at.

Well, okay. Good luck.

(Operator Instructions) We have no additional questions at this time. I would like to turn the conference back to Mr. Herlin for closing remarks.

Thanks. Certainly appreciate everyone's time this morning and we look forward to talking to you next quarter.

Thank you, sir. Ladies and gentlemen, this does conclude the Evolution Petroleum first-quarter fiscal 2009 earnings conference call. ACT would like to thank you for your participation. You may now disconnect.