Evolution Petroleum Corp (EPM) 2009 Q2 法說會逐字稿

Ladies and gentlemen, thank you for standing by. Welcome to the Evolution Petroleum second quarter earnings conference call. During today's presentation, all parties will be in a listen-only mode. Following the presentation, the conference will be open for questions. (Operator Instructions). This conference is being recorded today, Tuesday, February 17, of 2009.

I would now like to turn the conference over to Lisa Elliott, Senior Vice President of DRG&E. Please go ahead, ma'am.

Good morning, and thank you, everyone, for joining us for Evolution Petroleum's conference call to review the second quarter of fiscal 2009, which ended December 31.

And before I turn the call over to management, I have a few items to go over. If you'd like to be on the Company's email distribution list to receive future releases, please call DRG&E's office at 713-529-6600 and someone will be glad to put you on that list.

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 February 24, 2009. To use the replay feature, call 303-590-3000 and dial the pass code 11126478 pound.

Information recorded on this call is valid only as of today, February 17, 2009, 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 in estimating reserves; unexpected future capital expenditures; competition; government regulation; and other factors described in the Company's filings within the Securities and Exchange Commission.

Should one or more of these risks materialize or should underlying assumptions proved incorrect, accurate results may differ materially from those expected. Today's call may also include discussion of probable or possible reserves or use terms like volumes, reserve potential or recoverable reserves.

The SEC generally only allows disclosure of proved reserves and 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'd like to turn the call over to Bob Herlin, Evolution's Chief Executive Officer. Bob?

Thanks, Lisa. Good morning to everyone. Glad to have you here with us. I'd like to start with introducing Sterling McDonald, our CFO, who is with us today. He will be talking about some of the more important numbers that were involved in our 10-Q and also in our press release.

We did release our fiscal second quarter results this morning earlier, so we'll just go over a few key things from that release. I will be talking about the operating highlights with you today.

Now, revenues for the second quarter grew by 58% over the same quarter of last year. The good news is that our production was up by 250%. Unfortunately, it was offset by a 52% decline in realized commodity prices, which includes both oil, gas and gas liquids.

We produced 26,000 barrels of oil equivalent during the quarter at an average blended price of $39.78 per barrel of oil equivalent. Now, that production is approximately 26% oil, 29% gas liquids, and the balance is residual natural gas. The actual prices realized for each of those components is $57.37 for oil; $30.63 for gas liquids; and $5.82 for our premium CF for our gas.

Obviously, the growth in all of our production came from our operations in the Giddings Field in Central Texas. Last year in the same quarter, 85% of our revenue was from production in Louisiana, our Tullos field. We sold that field in March of '08. So 85% of our revenues from that quarter last year have been replaced.

In December of '07, we commenced our Giddings Field horizontal drilling program, and first production began from that operation sometime in late February of '08. So all the production that was generated has all been pretty much within the last year.

Sequentially, on a quarter-to-quarter basis, now revenue was down from the 2.9 million that we reported in our first fiscal quarter of '09. Again, that's due to the decline in both [in] prices that we realized, but as well as from production -- our initial production from the wells we drilled last spring. That was a normal and natural decline in the Giddings Field. And we didn't offset those by drilling any new wells that came online during that quarter.

As we stated before repeatedly in our filings and in our press releases and presentations, horizontal wells in the Giddings Field tend to have high initial production rates that decline very rapidly and stabilize at a lower rate, typically through the addition of artificial lift -- gas lift or pumps.

Five of the six wells that we drilled and two wells we put on production through workovers earlier in calendar '08, are now all in a stable production phase. And total gross production from those wells is about 240 barrels a day equivalent. We have one well that's currently shut in, and that's pending installation of pumping equipment.

We own 100% of the working interest in these wells. And our average revenue interest is about 80% in all those. Right now, our average production -- average net daily production during that second quarter was 290 barrels a day equivalent, which is the same as about 360 barrels of oil equivalent gross production.

Now, we began our 2009 drilling program in November -- by late November, by the spudding of the first of our two horizontal reentries in the Giddings Field. In mid-January, we completed that first well, the Hilton-Yegua No. 1, in which we drilled a new vertical section from a 3,000-foot depth to a total vertical depth of 10,500 feet. And then we drilled a horizontal section of about 3,000 feet, all within the Austin Chalk formation.

Now, Hilton-Yegua really substantially exceeded our expectations on production. It actually had the highest initial rate of holding pressure of any well in the history of our Company. On the first full day of production, it flowed about 4 million cubic feet per day of gas with 237 barrels of oil in condensates.

Now, as I mentioned before, these have a high initial decline rate. The average rate over the first eight days versus the gross production rate was about 3 million cubic feet a day with 146 barrels. Now, due to the need to have to re-drill most of that vertical section, we started at 3,000 feet. The drilling and completion cost to this well totaled about $2.2 million.

In late January, we completed the second well in the Giddings program, the Pearson No. 1, which is a re-entry with a horizontal leg of about 3,500 feet within the Georgetown formation. That was the same total vertical depth at 10,500 feet.

On its first full day of production, we produced about 1.25 million cubic feet and 48 barrels of oil. The nice thing about this well is that it maintained that rate over that next eight days -- the eight-day period is the same as its initial day rate.

Since we didn't have to re-drill that full vertical section, the total cost for the Pearson [or] approximately $1.3 million, far less than the Hilton-Yegua. But still it was a number higher than what we expected, driven because we actually encountered higher pressures in the reservoir, so it was a good news/bad news situation.

We have approximately an 80% net revenue interest in the Hilton well and a 78% revenue interest in the Pearson. And again, we own all of the working interest in those two wells.

Now, the second well, the Pearson, it having come in at such a high rate, is very positive for us because we have five grassroot wells that we have leased in that same immediate area. So, it's a very positive indicator for those wells -- those locations, I should say.

Now, due to the drilling results, we factored our production in the third fiscal quarter will be substantially higher than our second quarter production, since these wells typically produce a large portion of reserves quickly. However, we really don't think it makes a lot of sense to keep drilling these wells with our liquidity during this period of low commodity prices. We are cautiously optimistic that commodity prices are going to improve over the next year, and we will be able to start drilling again in the Giddings Field.

Currently, we are limiting our capital spending and we're focusing but we do spend on projects that will add proved reserves at a particularly low cost. We want to maintain our financial strength, and we want to avoid having to raise equity capital that's going to dilute our shareholders at these depressed stock prices; nor do we want to raise debt and be forced to bear a high interest rate or all the more restrictive covenants that are being seen in industry these days.

Our balance sheet and working capital position continue to be very strong. However, since we don't know how long all this is going to last, we want to be very conservative in our outlook. Our 2009 capital budget calls for us to spend up to $10 million. And we've spent about $6.8 million of that so far.

Our plan and focus of our staff is to build intrinsic value per share. Our drilling activities, therefore, is intended to move unproved reserves into the proved reserves category. We've also leased acreage during the quarter that we think is going to add additional reserves -- that was down at our stock Texas.

In Oklahoma, our shallow Woodford Shale project is an example of what we're trying to accomplish with low cost reserves. We have some 17,600 net acres there. And during this second half of the fiscal '09, we're planning to drill up to five very low-cost, vertical wells within the Woodford Shale at a depth of about 1,500 feet, in order to potentially quantify and convert that resource into proven, probable reserves.

In the Woodford Shale, there is very shallow. It's -- in the areas that we will be drilling, so we can use air drilling as a much cheaper way of drilling to formation. In fact, we think we can get these wells drilled and completed at costs of less than $150,000 per well.

Now, we're [going to] pursue vertical development there because of the low cost per well. And we think that we'll end up developing these, this acreage, as [down on] anywhere from 10 to 20 acre spacing. So you can see that our acreage position will generate a lot of drilling locations.

The other benefit is that we think we're going to be able to develop these gas reserves at a very low cost per Mcf. In addition, this is an area of other conventional reservoirs that we will be seeing on our way through the Woodford, so it will be a cheap way to test this conventional potential.

The acreage in this shallow area is offset by over 50 other drilled completions that are producing in the Woodford by another operator. We are following the results of those wells, and so far, they bear out our belief that this is a very commercial area for development of Woodford gas shale reserves and a very low price.

We have a second area of the Woodford Shale. It's a little deeper, about 4,000 to 5,000 feet. Initially, we would be planning on using re-entries to keep our well costs down and tested. Our acreage there offset the very successful well that's been producing for about one year and one-half now; came online at about 1 million cubic feet a day. And after over a year of production, it's still at a 600 Mcf a day rate, suggesting so far, that it's going to make about 1 Bcf of reserves. And that was for a fairly short lateral. So we are very encouraged in the potential of the acreage.

Now, in our new moderately heavy oil project in Texas that we call Neptune, we've got about 1,500 acres leased, net acres, which is the bulk of what we targeted. Subject to oil prices, we plan to drill up to three in-field wells this year at a depth of roughly 3,000 feet. Again, these are going to be low cost, vertical wells with drilling completion costs somewhere in the $200,000 to $300,000 range, which includes a large disposal. Now we believe that the historical results of in-field drilling in the field during the mid-'90s will confirm that these are proved reserves for us.

Not only is the infill drilling program an attractive project for us, it also appears to be an attractive vehicle for us to buy the technology that we adapted over in Louisiana and tested in our Tullos Field before we sold it. The technology is designed to allow us to generate additional oil production at lower water rates. This is for heavier oil reservoirs that have substantial contact with water and therefore, water tends to come out in the oil production.

There's a lot of reservoirs on the Gulf Coast that became too expensive to produce because of this water production. And therefore, these fields have been abandoned with substantial oil left in place. We believe that this technology can help reduce the water production and make these fields profitable again. Now, regardless of the outcome of that technology elaborate, this project, we believe, will be very attractive on its own merit just as an infill drilling operation.

Last, but certainly not least, I'd like to update you on the CO2 project at the Delhi Fields. Denbury, the operator, remains very committed to and very active in keeping the project moving forward and on schedule. They're in the final stages of completing the CO2 pipeline at Delhi, and continue to state that the first CO2 injections are scheduled for sometime in the first half of calendar '09, with the first production roughly six months following that, which places first production response sometime around the end of calendar '09, or shortly thereafter.

Our 7.4% overriding and mineral royalty interest should continue or should generate potential cash flows to the Company, beginning with the first material production response. And there will be no associated operating cost to us. So those revenues from that override will fall straight to the bottom line for us.

Now, we fully expect Denbury to aggressively roll out the CO2 flood throughout the fields, given the vast amount of money they've invested in the project to date. And as a result, we fully expect to realize our 12 million to 13 million barrels of potential reserves there within the next few years, with the first booking of proved reserves within the next year.

I'll now turn it over to Sterling to review some of our financial results.

Thanks, Bob, and thanks to all of you for joining us today. As Bob has mentioned, I'm just going to point out a few items in the financials and take your questions on anything that isn't clear, and we'll have a Q&A session later. It's not my intention to read the press release to you, but we'll look forward to your questions.

Starting, I'd like to say that in our last conference call for the prior quarter, we stated that our principal strategies at that time are -- one, to maintain liquidity and cash flow; and two, to continue adding intrinsic value per share.

That continues to be our creed and what we're doing today. So I'd like to focus first on what we're doing with liquidity, and then a little bit about earnings with that, before we go on to the second point of adding intrinsic value.

If we look at our liquidity, for the six months of 2008 for prior year, our cash flow from operations was $1.3 million provided. We also look in the Company at what we call adjusted cash flow, which is basically cash flow from operations before changes in operating assets and liabilities or, if you will, before changes in working capital.

That would bring cash flow for the six months from a $1.3 million unadjusted to an adjusted negative $300,000 was provided before changes in working capital, which we view as financing activities and not what's happening to the core of the operations at any point in time. Of course, at that time, for those six months, virtually all of our production was from our Tullos Field. In the first three months of that six-month's period, Tullos was the only thing that we had, and then followed by some production late in the second quarter of '08, coming from the beginning of our Giddings production.

If we look at our six months '09 and contrast that, our cash flow from operations unadjusted was $6.4 million positive. If we look at our adjusted cash flow before changes in working capital, the core of our operations provided $1.2 million in cash.

All of this came from Giddings, and about $3.6 million came from an income tax received from recoverable taxes from a prior year that we discussed last quarter. Basically, we had excess IDC last year in the 2008 year, and we were able to carry it back to the gain and -- taxable gain that we had at Delhi in 2006 and 2007.

If we look at the six-month period, of course, our first quarter of '09, our cash flow was about $2.2 million. Adjusted cash flow, though, was about $4.2 million. This was based on advancing production and we had expanded pricing going on at the time. Compare that to the second quarter of 2009, our unadjusted cash flow was $4.2 million, but our adjusted cash flow from the core of our operations was a negative $400,000. This was due to the core decline of $4.2 million to negative $400,000 was due to declining production combined with the present pricing at that time.

So if we look forward to Q3 '09, what are we to expect? Well, as Bob mentioned, we're going to be advancing production over Q2. At the same time, we may have depressed pricing that's going to tend to offset that. Any recovery in pricing obviously would help us, but we would see that the expectations for any burn in our operations, we expect to be diminished.

If we look at this on more of a global basis in terms of what has the Company done to date, since its inception? I went back and took a look at our adjusted cash flow before changes in working capital or changes in deferred tax liabilities. And the number I came up with was, is that we've earned about $2.5 million in cash over that period. I think it's about $2.2 million, was the number that I got.

And interestingly enough, that was mostly interest expense or it could be attributed to about $2 million plus of interest expense over the period, which was related to prospect loan. So, basically, what this shows is that we have continued to not burn cash at the corporate level over and beyond our cash flow.

So, this leaves us with currently about $7.6 million of working capital, which is down considerably from our working capital in the prior quarter. So, where does that capital go?

We used -- for those six months of fiscal 2009, we've invested $6.8 million in oil and gas properties, which is over half of our fiscal 2009 capital budget of $10 million. And we used about $0.9 million to repurchase the Company's common stock. Throughout both periods, the Company remained debt-free.

Our net loss in Q2 '09 was about $1 million or $0.04 a share compared to a net loss of $770,000 in the comparable Q2 '08. Our results for Q2 '09 include about $1.1 million of non-cash charges related to stock comp expense, depreciation, depletion and amortization, and accretion of asset retirement obligations, compared to about $0.6 million of comparable non-cash charges in the Q2 '08 quarter.

Let me take a minute to discuss the ceiling test potential in the future. Now, we had no ceiling test write-down in the current period. But basically we have no question at this point. We expect that, if prices at March 31 would be 10% for all products below those of December 31, '08, that our -- we would have a non-cash write-down of about $2.6 million.

Of course, that assumes that we don't have additional reductions in capital expenses related to the significant proved undeveloped reserves that we have in the full cost pool; any dollar reductions in capital costs would be a dollar-for-dollar reduction in the amount of write-off that we might have due to declining product prices.

Operationally, and in addition to the 58% revenue growth discussed by Bob earlier, our lease operating expenses declined 72% over our prior year -- the $12.54 of BOE. And this is due to moving from our Tullos operation to our Giddings operation, where operating costs are much less.

Sequentially, LOE was only up slightly, from $12.35 in the first quarter to $12.54 in the second quarter. Our G&A expenses increased 7.5% to $1.7 million from Q2 '09 as compared to $1.5 million in Q2 '08. Our higher overall compensation expense for estimated bonuses and news staff, including non-cash stock expense, accounted for the majority of the increase.

The new staff is associated with the build-up of our infrastructure to execute our drilling program, and G&A expenses for Q2 '09 include non-cash stock compensation expense of about $0.6 million compared to about $0.4 million for the prior comparable period. Netted for non-cash stock compensation expense, or cash G&A, if you will, was flat between the two periods.

As we look forward relative to our working capital and our liquidity, we've got advancing production this coming quarter to support our working capital. We also note that under the current legislation that's being passed in Washington, that additional recoverable income taxes may be in our future. For small companies, they can carry back for five years instead of two years.

This will leave the window open for gains that we still have from our Delhi Farmout in 2007. The 2006 gain, and the $15 million of proceeds we took in, in 2006, has been depleted through carry-backs. Some of the $35 million proceeds we received in 2007 has been depleted, but much of it still remains.

Moving to our second point, additions to shareholder value, as Bob mentioned, we're looking at increasing shareholder value in two ways -- first, by using our working capital to make small incremental investments in areas such as our continuous resource play in the Woodford to prove up larger swaths of reserves.

The same strategy applied in a different way is also underway at our Neptune project in South Texas. We also considered bringing in partners on our projects in Oklahoma and Texas in order to accelerate the development, with the ultimate goal of increasing share value.

Secondly, although we have no current plans to repurchase more common shares, we retain that option. It's another way of coming at our capitalization in order to increase value to our shareholders. And as our changes in working capital may allow, we'll look at that option again.

That completes my comments, and I'll turn the call back to Bob.

Thanks, Sterling. Before we go to the Q&A, just wanted to go over one or two points. We believe that we, in summary, just have the opportunity to continue adding a lot of value in quality assets at very low cost throughout calendar '09. And because of our substantial working capital -- in fact, we have no debt, no near-term material expiring leases -- we can pretty much control our needs for cash. We don't really have to go out and raise capital to continue our efforts and programs, then to carry it through, as we realize these projects.

In some of the conversations I've had with folks over the last month or so, we've gotten the question -- why did we do all these other projects? And why did we spend the capital that we had at that time?

It kind of flows into -- are we really more than just a call option on 12.5 million barrels of net oil? And I would like to point out that we have used about two-thirds of our capital that we got from that sale to Denbury. We used that to create a substantial amount of proved reserves, probable reserves, and value in getting to fields that we think, even at current prices, is at least worth about $1.00 a share.

We've also developed a [tremendous] resource play in Oklahoma that we think exposes us to hundreds of Bcf of gas reserve potential there, and that we're going to move it to a proved category over the next year or so. We developed our South Texas project that we think is going to allow us to add about 1 million barrels of oil -- depending, obviously, on oil price -- and allow us to extend that to other opportunities.

And in addition to all that, we still have Delhi sitting right there, which is not driven by oil price; it's not driven by drilling success. It's really driven by time -- the time meaning a completion of that C02 pipeline, which is nearly done; the first injection of C02; and then first production response. So this is just a time-driven value creation.

So, these are all the elements that I really think that the shareholders need to keep in mind.

With all that, I want to thank you for your time this morning and would certainly welcome any questions that you have. Lisa?

Thank you. (Operator Instructions). Phil McPherson, Global Hunter.

Nice work on the quarter in these tough times. Just a couple quick questions.

Sterling, on the balance sheet, it shows -- it said $9 million in cash of $1.5 million in certificate of deposit; but in the press release, it said you had $8.5 million in cash or something like that. Can you just clarify that?

The balance sheet shows $8.5 million in cash and $1.5 million in CD's -- I'm looking -- let me look at the press release.

Yes, $8.5 million in cash -- I'm sorry, you had $1.5 million in the CD.

Right. And what's your question, Phil?

I thought that -- did the press release say $8.5 million or something? Or is there a reason you're not including -- is there anything there to -- any reason the certificate of deposit is not considered cash or --?

It's a technical accounting issue. It's not considered a cash and cash equivalent because it's not negotiable and it's over three months. However, with most of these, we've worked out that we have no pre-payment penalty to deduct out. There was a question as to whether we ought to keep it in cash.

But it's still a short-term asset. Those are earning about 2.9% -- no, 2.5% to 3% -- by the end of the year. They're all insured under the $250,000 [lemon], which is set to expire at the end of this year, although my expectation is I don't think the government is going to have the guts to let it expire. But we'll see.

Just like the plan -- we've got another $300,000 CD in a long-term asset at the bottom of our asset list there that -- a long-term CD, but it is for $300,000 or so of cash. Does that answer your question?

Okay. (multiple speakers) So, you're sitting on about $10 million?

Yes, it's about $10 million all together.

Okay. That's what I was trying to figure out.

Did that answer your question?

Yes, that's great. Operationally, guys, in the Woodford, you said that you want to drill six wells for -- was it about $1.5 million? So you're just going to drill verticals, about $250,000 a piece, is what that works out to?

Well, actually it's five wells up in Oklahoma and three in South Texas. So that's a total of eight wells for a total of $1.5 million, roughly. Those five up in Oklahoma, we think are going to cost us somewhere in the $120,000 to $150,000 range. That would include drill, complete, a light, acid frac, and then gathering line. These are real cheap wells, as you can see.

And are you -- are the wells being (multiple speakers) --

(multiple speakers) is a little more expensive because we're at 3,000 feet, you have oil hammering equipment and water handling and so forth.

And the South Texas, that's in the Neptune field, right?

Right. Well, it's not Neptune Fields, our Neptune project.

Sorry, project. Okay. First, on the Woodford -- are you spreading these wells out across your acreage in a kind of trying to lock up and hold acreage? Or what's the kind of -- the game plan there?

That is a correct way of looking at it. We're really trying to accomplish two things. One is hold as much acreage as possible with those wells. The second thing is that we want to demonstrate the commerciality across the whole acreage swath.

Our acreage is actually fairly confined -- I mean, it's not like it's spread over a vast area, like a little checker board. It's pretty solid, but still we want to spread out and demonstrate that all the acreage is commercial, and that we can develop reserves at a very low cost -- which we're targeting about $1.00 an Mcf. We figured a $1.00 in CF finding and developing cost, we can make money at current gas prices.

And are you at liberty to tell us what counties you're drilling in?

Sure. The real shallow stuff is in Wagner County and the deeper is in Haskell.

Okay, great. And I assume you're just using one rig, and just kind of run and gun, and get 'em done real quick, kind of?

Yes. I mean, these are like one-day wells, as in Wagner. It's 1,500 feet. I mean, you'd probably measure it in hours.

And would you expect these wells to contribute to -- I've got to think here -- third quarter fiscal production? Or would (multiple speakers) --?

No, we won't get any material production out of any drilling that we do between now and June 30 -- we won't get any material production in the fiscal '09. And even like those shallow wells, those wells are going to -- the biogenic gas play and they won't come on -- your initial max rate. They're going to come on at 20 Mcf, 30 Mcf a day and then they'll increase over a couple of months to a peak rate, which may be as only 70 Mcf a day.

The good thing is these wells, is that they don't decline precipitously like the typical gas shale wells. They'll maintain a very high -- well, I won't say high -- they'll maintain that rate with a very low decline and last forever and ever.

Okay, great. And how deep are we drilling here? About 2,000 feet, 3,000 feet or --?

1,500 feet on average.

In Wagner.

And that's in Wagner. Haskell is 4,000 to 5,000 foot depth. And that's more thermogenic typical gas shale type production. However, the difference there is that at 4,000 or 5,000 feet, the frac pressures are still very, very moderate to mild. You don't need the real fancy hydraulic fracturing equipment. We're not competing with Haynesville or Barnett Shale for equipment.

We can still air drill, at least the vertical section of the hole. Drilling costs are a whole lot less. Rig requirements are a lot less. And also it's an area that is not as heavily fractured. So we don't have to -- we don't expect that we're going to have to shoot 3D seismic to help guide our drilling process.

And of these five wells, how many are going to be the shallow or how many going to be the deeper?

All five of those will be in the shallow area, and that's in fiscal '09. I don't really anticipate that we're going to do anything in Haskell until after the end of the fiscal year.

Okay, great. And then on the Neptune wells, can you give us kind of the same type of -- like what the production you're looking for and what that -- how that kind of tails out?

We have a lot less information to work with there. I mean, those wells, historically, the infill wells -- this is a field that was originally developed down to, I think, about 20 acres spacing. And then in the '90s, they came in and they did a handful of wells on 10 acre spacing and they were able to -- they averaged about 25,000 barrels per well. Very solid numbers.

So even at 25,000 barrels, we think that this is, at current prices -- well, at $40 oil price, we think that this is a very economical program, just on its own face.

Now, with the technology that we're going to apply, we are hopeful that we can generate higher reserves. If we do get the higher reserves, it goes from being a nice little project to a great project. But it doesn't depend on the technology to work.

Okay, so each of these wells are like 200,000 -- 250,000-ish, kind of? Maybe a little less?

Correct. In the ballpark. We have a little less certainty on that number because we just haven't drilled one of those yet. Now, the shallow wells, we've already done a lot more scoping work on that and we have a better idea.

We also -- for every couple of producing wells in South Texas, we're going to have to have an injector, so you've got to factor that into your cost. So, well costs actually are going to be a little less, but you've got to factor in the cost of a share of injection well.

But you're still below like $10.00 a barrel on an F&D basis, something like that?

Well, I wouldn't want to say that. I would say we're in that $10 to $15 range, which is -- $40 oil is the kind of a dividing point for me, in terms of how aggressive I get with that project. I don't think that we're going to see oil below $40 on a long-term basis. And this is a long-term project. It's kind of like a gas shale project -- you know, drill all your wells in six months or a year, it's a five-year project. Well, this is -- our Neptune project is very similar in characteristics.

Great, guys. Well, keep up the good work and I'll let somebody else jump on. (multiple speakers) All right, thanks, guys.

Richard Rossi, Wunderlich Securities.

Just a couple of cost questions. I know these wells aren't terribly expensive, but have you seen costs coming down over the last six to nine months?

We have seen costs come down considerably in our drilling activity in the Giddings Field. Our rig rates are actually dropping while we were drilling. We're fairly confident that if we were to drill another well in Giddings today -- in fact, we've gone out and gotten new AFCs -- that our rig costs would be substantially less. And then all the related costs would come down as well.

As far as what we're going to be doing, we haven't actually bid out the numbers yet. We've done some AFB investigation in order to get the numbers to do our preliminary work, but what we know is that the services that we're going to be utilizing are not services that are in demand for the only really hot drilling area left in the industry, which is the Haynesville. And even then, I'm not sure if you'd really call it hot; you might call it warm.

We're fairly confident that we will get the lowest possible prices on services that we need -- if we are seeing a substantial decline. And when I talked with my opposite numbers in other oil companies, oil and gas companies, I'm hearing the same thing -- that they're starting to see substantial reductions in service costs.

All right. And on the G&A side, your non-cash comp is -- I don't know, 30%, 35% of G&A. Is that what you think it will be running, going forward?

Well, as you might well imagine, I want to say two things. First of all, as a -- I still think of us as a start company, although we've been around now for five or six years -- that in order to bring on quality staff from established companies, I had to offer them something more than just a salary. That included having a piece of the action going forward.

And so I used options and going more to restricted stock as a major component of that compensation. But that compensation vests typically over a four-year period, each of those awards. So, as you can imagine, we have a fairly high amount of that non-cash stock compensation expense running off over a four-year period.

And so, the current level is a level that we'll maintain, but not for -- it will be dropping rapidly over the next two to three years. And awards going forward will be more along the lines of restricted stock in smaller amounts. So, that the amounts we add on will be far less. So it is a number that will be running off rapidly.

The remaining number is about 4.2 million -- it runs off in 2.8 years.

2.8 did you say?

Yes, sir.

Okay, all right. And then (multiple speakers) --

I meant to tell you that probably the way -- because of the Company has been formed, the higher expenses probably in the front of that period and declining at the end, until it gets to $0.

Right. And then just one other question. And are there any technical -- significant technical issues left for Denbury to finish up that pipeline?

I'm not aware of any. To the best of my knowledge, they have all their permits. The bulk of the line has been laid. They are just finishing up, I think, one remaining small section. They have made every indication to me that there is no hitch, that everything is on schedule, on plan to get the pipeline completed in the second quarter of calendar '09. So I'm always looking to hear what other people hear when they talk to Denbury, obviously, so I'd love to hear anything else that you might hear about them.

Okay. All right. Very good. Thanks very much.

(Operator Instructions). Dick Feldman, Monarch Capital.

Solid quarter and good strategy. I have a question about Oklahoma. How does your acreage -- I think you mentioned something like 17,600 -- break down between the shallow area and the deeper zones?

There's about 9,300 acres in the shallow area, which is the Wagner County, and 8,300 acres net in the Haskell or the deeper area. So, of that 9,300 acres, we anticipate drilling that on these vertical wells on 10 to 20 acre spacing.

On the Haskell area, we -- that's going to be more like a horizontal development, and that's going to be anywhere from 40 to 80 acre spacing. And of course, in the Barnett, they're down to 20 acres on their horizontal wells.

So that potentially -- that's a lot of wells, particularly in the shallow acres.

Five-year program, easy.

And do you think you could do, let's say, half a [B] per well, or is that too high?

That's too high. I think you need to scale that back, to maybe 200 Mcf per vertical well in Wagner. I mean, I think that would be a much more realistic number based on an IP of 50 to 70 Mcf a day in a shallow decline. Keep in mind that we're talking about a well cost of less than $150,000. So, that's why we feel confident in saying -- reasonably confident -- that we -- how about cautiously optimistic?

I like that, Bob.

(multiple speakers) we could achieve an F&D cost of about $1.00 an Mcf.

You also mentioned, one of the things that you were considering would be bringing in a partner. And I wonder if you could explain your thinking.

Well, obviously, it's a big project. 400 times -- 400 wells times 150,000 is still a big number -- or 100 horizontals in Haskell times $1.5 million is a big number. And so, was it better for us to go ahead and bring in a partner on a promoted basis to accelerate it, instead being in five or six-year or seven-year program for us, to make it a two or three-year program? We're always evaluating what is the best interest of our shareholders.

I've made no secrets to anyone that this Company is set up and designed around the concept of adding and generating value per share, with a goal of some sort of monetization in the not-too-distant future -- not-too-distant being two to five years. We've never set this Company up as one where we are a long-term EBITDA growth story, where people come in and say, oh, we're going to value at six or 10 ten times EBITDA.

We are a company that's to be looked at as -- what is the value on a per-share basis? That's our goal. That's the strategy. That's why we cut back our drilling activity into getting. We want to maintain our value per share and can keep it in the ground until we get more attractive pricing, instead of producing it, and getting a low price.

One last question. In today's somewhat depressed market, are you seeing new opportunities that tempt you to open up in another area? You know, getting to another region or (multiple speakers) --?

We're always keeping our minds open. We're always looking. We want to make sure that everything that we do all ties together for our overall strategy. We don't want to be in position where we have apples and rutabagas; we want to have apples and oranges, at the most.

We want to stay in areas where we have a high comfort level that lend themselves to our particular strengths, which are in project development, horizontal development, artificial lift. So, that, we're focused on. We're always looking, but we're trying to be very disciplined in how we do it. We want to maintain our liquidity over the next two years. And we just don't know what's going to happen.

When will you report the results of the Oklahoma drilling? More precisely, when would you spud the wells?

I think -- I mean, our goal is to get those wells drilled in fiscal '09. Because of the nature of those wells, they don't lend themselves (inaudible) -- we put the well online yesterday and the rate is [this]. Again, it's a biogenic play; your gas rate is going to increase over time, so I suspect it may take until the end of the summer before we're ready to pronounce a result that mean anything.

Okay. Good luck and keep up the good work.

Thank you. And at this time, there are no further questions in the queue. I'd like to turn the call back over to Mr. Herlin. Please go ahead.

Thanks to everyone for listening in this morning. We appreciate your time. We look forward to talking to you the next quarter. We hope to be trying some new things in the future -- videoconferences online and hopefully, we'll be talking with you about setting those up.

Thank you, and I'll turn it over to the Operator.

Thank you. Ladies and gentlemen, that does conclude the Evolution Petroleum second quarter earnings conference call. If you'd like to listen to a replay of today's conference, please dial 303-590-3000 with the pass code of 11126478 pound. Once again, that's 303-590-3000 with the access code of 11126478 pound. Thank you for your participation and at this time, you may now disconnect.