Evolution Petroleum Corp (EPM) 2012 Q2 法說會逐字稿

Good morning, ladies and gentlemen, and thank you for standing by. Welcome to the Evolution Petroleum second-quarter fiscal 2012 conference call. During today's presentation, all parties will be in a listen-only mode; and following the presentation, the conference will be open for questions. (Operator Instructions). This conference is being recorded today, February 9, 2012. I would now like to turn the conference over to Lisa Elliott with DRG&L. Please go ahead.

Thank you. Good morning, everyone. Thanks for listening to Evolution Petroleum's conference call to discuss results for the second quarter of fiscal 2012, which ended December 31, 2011. In a moment, I will turn the call over to management, but first I have a couple of items to go over.

If you'd like to be on the Company's e-mail distribution list to receive future news releases, feels please feel free to let me know. My contact information is on the earnings release that Evolution put out yesterday evening. If you'd like to listen to a replay of today's call -- it will be available in a few hours, and archived for one year via webcast -- by going to the Company's website at www.evolutionpetroleum.com, or via recorded telephone replay until February 16, 2012. That dial-in number and passcode can also be found in the earnings release.

Information recorded on the call today is valid only as of today, February 9, 2012, 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 may contain forward-looking information, which is based on management's beliefs and fullest assumptions made by management and information currently available to them.

Forward-looking information includes statements regarding expected future drilling results, production, and expenses. And while the management believes that these 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 and uncertainties and assumptions which are listed and described in the Company's filings with the Securities and Exchange Commission. If one or more of these risks materialize or should underlying assumptions prove incorrect, actual results may differ materially from those expected.

Also, today's call may include discussions of probable and possible reserves or use terms like volumes, reserve potential, or recoverable reserves. Please note that these estimates are of non-proved reserves or resources and are, by their very nature, more speculative than estimates of proved resources and reserves, and, accordingly, are subject to substantially greater risk.

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

Thanks, Lisa, and good morning to everyone. I'd like to thank you for joining us on our fiscal second-quarter call. We earlier filed our Form 10-Q, and yesterday evening announced our quarterly results in our news release. I assume that everyone listening has access to one or the other or both. Oh, excuse me. The Q is not filed, but the release is out. Since detailed numbers are available, Sterling and I are going to confine our remarks to key operating results and updates of future plans, so forth. With me today is Sterling McDonald, our CFO; also, David Joe, our controller. Sterling is going to review key financial results, and then we'll take your questions.

In short, we had another solid quarter, with a 24% increase in net earnings over the previous quarter, to about $1.3 million or $0.05 per basic share and $0.04 per diluted share. Revenues increased about 20% over the previous quarter, $4.6 million, and net production increased by about 12%, to 569 BOE per day. I'd like to especially point out, though, that our production was 72% oil and 6% gas liquids. Revenue and earnings growth continued to be driven by growing oil production at the Delhi Field, and our Louisiana light sweet pricing there for crude oil averaged $115 in the quarter, compared to about -- almost $106 in the prior quarter. In the fiscal second quarter we just completed, our net income from operations was about $2.4 million. And that's a sequential improvement of about 25% from the prior quarter.

Now let's talk about some of the specific assets that we have -- let's obviously start with Delhi Field. Gross production there increased 13% over the prior quarter, and got to a level of 4946 barrels per day, or about 366 barrels a day net to us. Gross production for the year-ago quarter was only about 920 barrels a day, so we've seen a very dramatic increase over the last year, and essentially all results of the capital expenditures of 2009 and 2010. Now that Delhi crude oil that was sold there for $115 during the quarter was a 22% premium over WTI Cushing. This difference in oil prices is creating substantial incremental value for the Company.

I would like to note that our June 30, 2011, reserves for Delhi in our SEC filing were based on a flat oil price of less than $95 per barrel, some $20 less than what we actually received this last quarter. Now, calendar 2011 capital expenditures planned for Delhi originally was to complete the project in the western half of the field; however, the operator expanded the 2011 plan well beyond the original activity level, with additional wells in the western half and initial expansion into the eastern half of the field. Consequently, production was mostly flat during the first two months of the recent quarter before substantially increasing in December.

During 2011, the operator added a total of 59 newly drilled wells and reentered wells, as well as a third production collection site to complete the EOR project in that western half of the field. Some of the well work was an acceleration of the initial development, related to a fourth production collection site that was originally scheduled for 2012, due in large part to this activity -- that explains the flat production in the first two months of the quarter. Since initial oil production response from 2011 expenditures has already been observed, we expect continued production increases in calendar 2012.

As previously noted, earlier in 2011, Denbury, the operator, began re-injecting produced water back into the main producing reservoirs to help maintain pressure, instead of purchased CO2 volumes. Since purchased CO2 cost is a major factor of the economics, producing the CO2 purchases increases profitability. That's a major reason for the acceleration of the payout date we reported last summer. As field profitability increases, Denbury should reach back to find payout sooner. And, therefore, our incremental 24% reversionary work interest should kick in sooner.

We continue to be very pleased with the progress and the results of this enhanced oil recovery project. It's performing better than original expectations in production grade required volume of purchased CO2, produced CO2 rate -- and it's exhibiting characteristics of reservoirs that have either, or both, higher ultimate recovery and greater original oil in place than originally projected. All in all, our confidence level in both our probable reserves and the upside potential at Delhi continue to increase.

As to our artificial lift technology -- we refer to our trademarks as GARP -- we are very encouraged by the initial results of our first commercial demonstration of this patented gas-assisted rod pump technology. The first application was successfully installed and placed in production in the early part of December of 2011. Although production testing is still ongoing, initial rates suggest that the technology has significantly extended the life of the well, and potentially added up to 25% oil recoverable reserves. Before the GARP installation, the well was producing at an uneconomic rate.

Installation work is now underway on our second commercial demonstration, with first production expected shortly. In both demonstration agreements, we are paying the installation costs of technology; they are operating the wells in return for an equity ownership equal to 50% net profits interest in the first well agreement, and a 99% before payout, 76.5% after payout work interest in this second application. These demonstrations are expected to assist us in accelerating the commercialization of this technology.

Down in South Texas, in our Lopez Field, we are continuing the production test of two producer wells that we drilled in the recent quarter, as well as the first producer that we drilled in late 2010. Now, these wells target an oil production rate of 10 to 15 or more barrels a day, along with a large volume of produced water. Initial swabbing of the latest two producers suggests our target oil content is present, thus supporting additional development to field during the remainder of this fiscal year. We are still experiencing some challenges in maintaining consistently high re-injection rates into the associated water, but we believe that one or more of our current operational options will be successful. While we have up to 40 locations to drill in our leases, our goal in this project is to extend this concept to similar fields in the region, and therefore add hundreds of development locations.

In the Giddings Field, we focused during the quarter on maintaining our production volumes without investing significant capital. Consequently, we were able to actually increase sales volumes by 13% over the previous quarter to 198 barrels of oil equivalent per day. This was done through several planned work-overs in certain wells. A portion of our acreage that is in Grimes County, which is part of the Giddings field, is within the new Woodbine play. We are already participating through a farm-out of a portion of our lease hold, on very favorable terms to the Company.

As for the rest of our undeveloped locations, they averaged close to 50% natural gas and reserves. Therefore, the profitability in drilling these locations, or these proved locations, is really below our acceptable threshold at current and expected near-term gas prices. We believe that more attractive opportunities are available elsewhere, and we are exploring options on how to maximize our value of these assets.

With that, I'll turn it over to Sterling for some financial results.

Thanks, Bob, and good morning, everyone. As you can see, our turnaround improvement in net income was a top-line driven growth story, but most of the revenue increase is going straight to the operating bottom line before income tax expense. Looking at the six month year-over-year results, total revenues grew about 260%, primarily due to a 290% increase in crude oil sales volumes. Meanwhile, the three month year-over-year revenue growth accelerated further to 290%, primarily due to a 300% growth in crude oil volumes. Of course, we can't expect to maintain these growth rates consistently, as indicated by the solid but less dramatic 20% sequential revenue growth posted over the prior September quarter. \

In the near-term, we expect continuing production increases at Delhi from further rollout of the EOR project to provide solid revenue increases, steady oil prices permitting. In the intermediate term, however, our next step-change in Delhi revenues will come when our reversionary interest kicks in, raising our share of revenues at Delhi to over 3.5 times our current share. Of course, about one-fourth of the incremental revenue will go to operating expense then, but it's still a dramatic uptick to our bottom line.

On the expense side, I'd like to highlight a few variances of note. Absolute quarterly LOE almost doubled sequentially, while increasing 33% year over year. Although improved sales volumes at both Giddings and Delhi provided a decrease in LOE on a BOE basis, the absolute increases in LOE were primarily due to work-over expense in South Texas and Giddings, which drove double-digit increases in sales volumes there.

Meanwhile, increases in G&A were largely being driven by increased legal and personnel costs. On the wage front, the Board of Directors approved across-the-board salary increases in September, partly to make up for foregone wage increases during the credit crisis. On the legal front, we continued to defend property interests on two separate matters we have previously disclosed to you and consider minor at worst. Ultimately, it seems that success breeds frivolous legal entitlement complaints.

Lastly, increased income tax expense is the price we also pay for increased success, so I guess we are happy to pay our share there. On the liquidity front, we have a great balance sheet, no debt, and a number of options to increase liquidity going forward. Examples are, our working capital increased almost $10 million since June 30, standing at almost $14 million at December 31. Part of the increase was due to $6.9 million in net proceeds from our Series A preferred offering.

We like this vehicle, because it leaves us in financial control of our assets with no covenants or due date. ATM offerings at yesterday's $28 market price provides a current yield of under 7.6%. And we believe there's good retail and institutional demand for more of this product, due to the dearth of yield product in the market, especially considering our lack of debt leading to no senior claims over the preferred.

We did suspend our aftermarket offerings in early October and keep that on the shelf, as plans dictate. The other main increase in working capital came from $5.1 million of cash flow from operations before changes in working capital. As mentioned earlier about our revenue growth prospects, these internally generated funds should continue to grow. Additional liquidity is also available to us through IDC tax shields, as we develop additional properties. To this, we have discussed placing a small revolving line of credit, the terms of which would be unsecured, and only as a bridge to other permanent sources of funds.

So the challenge before us right now is the reinvestment of our funds, and drillable projects focused towards oil, something we've been spending considerable time on over the last six months. We believe that market opportunities exist to find partners that meet our parameters.

With that, I'll turn it back to Bob.

Thanks, Sterling. As Sterling said, we have excellent liquidity, and we continue to generate net cash each month going forward. With no debt, growing cash flow, cash on hand, we believe that we are well-positioned to consider new external and internal projects and joint ventures that have a high oil content, as well as continue to develop our Lopez Field in South Texas and to continue to commercialize our GARP technology.

We are actively engaged in such evaluations at this time that we believe would provide a great set with the projected increase in cash flows from Delhi over the next couple of years.

With that, we'll be ready to take some questions. Operator, please open the lines for questions.

(Operator Instructions). Phil McPherson, Global Hunter Securities.

Great job on the quarter. A couple of questions. At what point on this -- I'm going to call it the Delhi retirement clock, because it's kind of like ticking down here. At what point will you be able to give us a figure? I know, at one point, there was actually costs being incurred in early CO2 injection -- where the $200 million number was actually, for lack of a better term, increasing, and now it's starting to decrease. Will you start giving us where they are at on a yearly basis, or a way for us to monitor that?

Well, clearly we don't want to do that, just because it kind of gets into the details that Denbury doesn't like us to provide. We started retiring that payout balance -- oh, shoot, when was it? Last May, May of last year? And since then, we have really produced that, quite a fair amount. As we reported earlier in our reserve report as of last June 30, based on an oil price less than $95, the projected payout was around November of 2013, which is roughly a year and a half from now.

I think it's a reasonable expectation to say that, absent any other change other than oil price, that we will see that payout point accelerated by a number of months. Now exactly when, I can't say, and wouldn't say, even if I had an estimate -- but just say, earlier in 2013. But in terms of giving you a number every month or quarter or whatever, I really would rather not do that. I think that the safest thing to do is just take a linear line between now and then, and that would be probably as good an estimate as anyone else.

Keep in mind, there's a lot of numbers that go into that. It's not -- it's production rate, it's a rate of CO2 purchases, it's oil price, and so forth. Those are the three main factors that go into it.

I might add to that that one of the things that -- all these numbers are audited, and we only audit them once a year. We'll be going into an audit with Denbury in the next month or so for what's occurred -- is it the last 12 or 24 months? The last 12 months. Also, bear in mind that as we've discussed before -- and as you just mentioned, Phil -- that the payout actually increased over $200 million by a pretty substantial amount. I think it peaked out at about $230 million or $235 million, somewhere in that range. And it has worked its way down since. I will say that as a starting point, we are probably, unaudited, $200 million or a little less at this point. And that's being chipped away at every month now. Sorry we can't be more specific than that right now, but I think as we come through our audit, it will make it more clear for us, as well.

That helps. You've kind of highlighted this part about them re-injecting water and lowering the CO2. Any quantifiable number there, from an operating -- an LOE standpoint?

No. (laughter) Sorry. (multiple speakers) That reduced CO2 purchases was reflected in our reserve report last June. And that was a major factor in the two-year acceleration of the payout date. And so what we are seeing today is a continuation of that reduced CO2 purchase, relative to the original plan. Obviously, higher oil prices increases the cost of the CO2 purchases that we are incurring. But I guess, the point is that we are continuing to see a lower level of purchases than the original plan, as reflected in our reserve report. So, going forward, the main factor in any further change is going to be primarily in a combination of oil price and actual oil production rate.

Great. And just switching gears, it sounds like the GARP is working. And you say in the press release, you talk about a 25% increase in the reserves. Is it a big enough number to matter at this point? Or how do we think -- the way that the deal is structured, can you eventually be able to book reserves related to the GARP? Or is it not going to flow through the Company that way?

Well, GARP is an interesting business opportunity for the Company. It is a service business, and we are not -- really a service company. We are an oil and gas producer, operator, and developer. Eventually, GARP is going to have to take wings on its own, either as a spinoff or as a sale, or some other JV. And I think we've been real careful to say, all along, that GARP has got fairly long maturity cycle. This is not something that, years from now it's going to be the predominant source of revenue. It's going to be a slowly developing acceptance by industry.

And as you probably know, and most people in the business know, the oil and gas industry, especially out in the field, is one of the most conservative businesses around. They just hate new things, because when you're out in the field, if something works you don't get credit for, and if it doesn't work, you get blamed for it. So there are people very reluctant, and understandably, about trying something different. So we're going through an education process. The first thing we did was show that it works to our wells; next step was to show that it works in other people's wells; and the third step was to show that it works on other people's wells in other fields outside of Giddings.

This is a multiyear process. We are generating net value from these initial applications. We're very pleased about that, but in the grand scheme of things, if you use Delhi as a comparison point, it's a small number. We think the potential is, over the next couple of years, it could become very material relative to Delhi. But that is going to take time, and it's going to take hard work and a lot of marketing on our part. So is it going to be a preachable material? Yes, it is, but not this quarter, not next quarter. We are talking probably several years.

Okay, that's helpful. And since you kind of led me into my next one about moving the needle a little bit -- I know you're talking about the Giddings, and there's been a lot of industry activity out there, looking at other things like the Woodbine and Eagle Ford. Is this something, with deep liquidity position that you guys have, and Delhi performing way above expectations, does your risk appetite increase at all, and you guys want to take more of some of these higher-risk kind of frontier plays?

Well, I couldn't have scripted that question any better. (laughter) Appreciate that, Phil. We are very focused, as you can well imagine, on what to do with the cash flow out of Delhi. I'm sure that's probably the number one question that people have looking at our Company. You know, great, you have all this cash flow coming off of Delhi, but what are you going to do with it? So we are very focused on that question.

Since the employees of the Company own roughly 20% on a beneficial basis, we are probably more focused on that issue than anyone else. Because that money in our pockets, as well, from our equity ownership. And so we're looking very closely at opportunities to reinvest that pair with the Delhi growth in cash flow, and types of projects that are very, very oily, that they are in areas that we can reasonably get to -- for example, we're not going to be doing North Dakota, we are not going to be doing California, so forth and so on. And it has to do with wells that are reasonable in cost.

We're not a Company that can go out and drill $9 billion and $10 billion wells. That just doesn't make any sense. So within those parameters, we are looking at a number of deals that make sense in the Texas, Mexico, Oklahoma, Kansas regions. We have some great opportunities that we're looking at. And I would say that we are in discussions on one or two projects that we think would be outstanding fits with the Company, with our business model and, equally important if not more importantly, they are a great fit for redeploying the cash flow from Delhi to take advantage of that tax position there, the taxable income we're generating, IDCs, and so forth. So we are very excited by these opportunities. We think they're a great fit. And, hopefully, we'll be in a position to talk more about it on our next earnings call. (multiple speakers)

I just want to say that we can afford to be patient to find the right deal. And if the terms don't fit our parameters, then we'll continue to look. But we're very focused in that area at the moment.

And I'd like to also add to that, that if we don't think that we have the right projects that can substantially accrete value to the shareholder for redeploying that cash flow, then we're going to get that cash flow to the hands of the shareholders in the most efficient way possible.

And I was going to ask that for Sterling -- with the preferred, is there any restrictions in paying dividends to common shareholders, and is that approved currently in the -- I don't know if you call it the charter or whatever. Are you approved to give to dividends if you wanted to? Or do you have to take that to a shareholder vote?

If I understood the question, do we have control of issuing more preferred without going to shareholders?

No. Issuing dividends, common stock to shareholders (multiple speakers)

Dividends to common without going to shareholders -- I believe that the Board of Directors has control over that.

And there's no provision in the preferred that restricts that?

No. There is nothing in it that would restrict. (multiple speakers) Except not paying the preferred dividend -- that would restrict it.

I know that one person -- someone has already asked separately about the Giddings area, the Woodbine play -- we are participating in that. We do have a significant -- we have a couple-thousand-acre position in Grimes County that is part of that Woodbine play. We are already participating in that with an initial deal on one well, on extremely attractive farm-out terms, and we hope to do more with that in the future.

Joel Musante, C.K. Cooper & Company.

Most of my questions have been answered, but I still had a couple. On the GARP, you said that it could increase reserves by 25%. Is that reserves like the EUR number, or is that like what's left? You mentioned it was uneconomic.

Let me -- one explanation and one answer. First of all, I want to make sure people understand that I didn't say increases by 25% -- I said up to 25%. We don't have enough data to get a real hard number on that increase. What we are doing is we're looking at production rate at the moment, we're looking at historical cumulative production versus current rate. Our plot, which is in the Giddings field, these harmonic decline wells, it's typically a straight line. We look at where that production is today that we've restored, put it on that curve and run that out, and that kind of gives us an estimate.

But until we have more than the 45 days or so of production history that we have, all I can really say with certainty is that we have restored the well to very economic, very profitable production. We have extended the life of the lease for, I would think, at least a couple of years if not longer, and that we believe that we have expanded reserves substantially. And it could be as much as 25%, based on the current production rate and the rate (inaudible) curve profile. This is, when I say up to 25%, that's a reflection on the cumulative production to date. So, for example, if the well had cumulatively produced 200,000 barrels of oil equivalent, then the target would be up to 50,000 BOE of incremental reserves. So does that answer your question?

Yes.

We are starting production of these wells, we are getting the rate back up at a point where the decline on that particular well was pretty flat. So it's that long tail at low decline that you normally see on these kinds of harmonic or hyperbolic decline wells, that typically come on at the higher rates, decline rapidly, and then over a period of time the production rate decline changes dramatically, and it turns into a low decline rate well, but at low rates. And so what we're doing is we're trying to restore the tail to that production decline.

Okay, makes sense. With respect to Lopez, maybe I missed this before. You mentioned that water being an issue that you're having some challenges there. Can you just -- is it permitting, or what is it?

Initially, the first go around a year ago, the issue was the huge backlog at the Railroad Commission for issuing permits. Now that's been somewhat cleaned up, the Railroad Commission, relative regulatory bodies have added more people. So that really is not an issue. And now it's one of, we are trying new stuff -- we were producing these wells at high rates. We are talking 2000 to 3000 barrels a day of fluid, which is 99% water. This is not freshwater; it's brining water. It's not usable for anything. So part of the deal is getting that water back into the reservoir to maintain pressure, and also to dispose of the water in the most economic way possible.

And these wells can give a fluid easily, but put the fluid back in has been somewhat of a challenge. The clay swells on us, and so forth. The challenge has been how to get that water back in at that high rate, and it's been somewhat difficult to get the rates as high as we want to have the most economic level of production. You can put water in, but you want as high a rate possible to produce a number of disposable wells. And so that's been the challenge.

We've been working with service companies on this; we've been doing some tests and, both in the lab and in the field, and we've come up with a number of options that we're fairly confident that any one of them will work fine. And what we're doing now is trying to decide which is the best one to use. In the meantime, the actual production test, the initial swabbing of the wells, suggests that the oil content is as projected. So the oil is there, and the economics are there. As long as we can handle this water injection issue -- and like I said, I think we've got solutions for that issue, and we're just having to prove it out in the field.

All right. So how long do you think that might -- I'm just trying to think in terms of --

I would expect that we'll be able to report whether or not this is going to work or not by the next earnings call -- that we'll have that resolved by then, and hopefully be drilling new wells.

All right. So what kind of ramp up in activity levels can you foresee in Lopez?

Lopez? Well, I think my expansion plan that we had there was on the order of maybe two producers a month; so that's two producers, two injectors a month. That could be as much as $2 million CapEx per month rate. And obviously, we own 100% of that, so all of that goes to our bottom line.

All right, nice. And then my last question was on the work-overs. How much do you estimate the work-overs contributed to the LOE costs, just to get a run rate?

Well, probably the best way to describe that is what Sterling said. It doubled our LOE over the prior month. We didn't add that many additional wells, so the bulk of that increase is related to those work-overs.

Okay. So it was more or less the previous quarter -- it was about closer to five, and now it's like 760 or something on a barrel basis?

Yeah, you've got to be careful with that per-barrel basis, because that's obviously influenced by production rate at Delhi, which we don't even have any OpEx related to that production. So really, to evaluate our LOE, you need to look at the absolute numbers.

(Operator Instructions). Kim Pacanovsky, MLV and Company.

Hi. Good morning, everybody. I had a couple more questions on the GARP technology. The two installations -- the one that is currently running and the one that you're putting in now -- are they for different operators or the same operator? And can you disclose who that is?

They are two different operators, and no, we can't disclose it. They both prefer not to be identified.

That's fine. When will you actually be able to release some numbers on what the production was, when you installed GARP and where it came up to?

I would suspect that the next earnings call, we'll be able to give you specific numbers. Because, at that point, we'll have several months of production data and, therefore, we can be far more confident of what the increase is, what the benefit is.

Stirling, the last time you and I met, one of the points he made was that this unit really needs to be reliable, and not have down time. And I know that it hasn't been installed for a long period of time with this third-party Operator. But can you comment on any downtime issues with it?

It's a good point -- it's a good question. The one that we installed on December 2 has had excellent utilization. It was -- we did have a rod parted -- the beam pump that came with the well bore. And we use the utilized the beam pump in our application. The downhole assembly, the sucker rods, everything, were old. And we had a parted rod. So we were down -- since December we were down, I think, about nine days getting the rods pulled and replaced. It was in no way a reflection, nor was it caused by the application of our technology. It was strictly the old technology of the beam pump that had separate wear.

Actually, that's not quite true, because before we put in GARP, the pump was having to move very small amounts of fluid. When we installed GARP, we substantially increased the volume of oil and associated water, which just put more stress on those rods. And that would be -- probably would accelerated the rod part, that was going to happen probably at some point, and we just accelerated it because now we are moving a lot more oil and water. But it still doesn't reflect on the technology in that the pump is able -- should be able to move what it can move without breakage.

So the bottom line out of all of it is, other than maybe one or two days since December, other than those nine, were we down for any reason. So utilization has been excellent.

By the way, Kim, we are operating both of those installations.

Okay. And at what point do you take this data outside of Giddings and try to get other operators? I guess I'm just wondering how many -- I know, Bob, you did a really good job of explaining how long of a time scale this project is, and I get that. But I'm just wondering how many data points do you need before you really make decisions on the next step and then the final decision, whether you joint venture, whether you sell it, things like that.

Well, there's actually one more interim step I should've mentioned. With these operators, there are hundreds of other potential applications with them. So really, if we are able to demonstrate that it's working successfully in the value creation, there's virtually no cost to the operator, then the next step will be to go to them and say, hey, look how we've added all these reserves. We extended the life of the leases by another 10 years, or whatever. But that was on one well. Let us do it on 40 or 50 or 100 of your other wells or similar.

That would be really the next step. And then other operators, other players in the industry see someone that they know and respect is jumping into this wholeheartedly, and making money and adding reserves, then that helps us with the credibility issue of the technology. And now the risk for those operators to take on that new technology is a lot less. It's kind of a herd instinct.

And then I just have a couple of modeling questions. Why is the tax rate so high? (multiple speakers) to the overall tax -- your overall tax rate.

Well, there's no severance tax on a current severance tax holiday through the end of the decade. As far as the income tax, we have our corporate income tax at the Federal rate and we also pay a state tax rate. The combined effect of rate is -- I thought it was 38%. (multiple speakers)

You were 43% in the first quarter and 41.5% almost in the this quarter.

All of that is correct. (multiple speakers) Bob is correct. Let me sort it out. We have a 35% Federal rate; we have an 8% Louisiana state tax rate, which, in Louisiana, the Federal tax can be taken as a deduction against the income on Delhi. So when you work that down, it winds up being about a 38% tax rate. Now, the bulk rate that you're looking at, the 41% to 43%, is a result of non-cash stock comp expense in the back.

And it's interesting, because if you look back in our historic roles, where we have net losses, our tax rate was real low. It was in the teens. To the 20s. And it's the same phenomenon, just the other side of the coin. When we had losses, part of the loss was not deductible, so it drove our effective tax rate down. But once we are taxable, it drives our effective tax rate up. Because that expense can't be deducted for income tax purposes.

I would like to point out, however, that as our revenues increase rapidly and our earnings increase rapidly, the effects of that non-cash stock call will be far reduced, and start pulling down that effective tax rate closer and closer to the 38%.

To the 38%. Okay, super.

That's correct.

And then would you care to give production guidance for the next quarter?

Oh, Kim. You know we'd never do that. Good try, though. It's hard for us to give guidance on something that we don't have control over.

Right. I realize that.

And Denbury operates that project. And they have a different set of parameters and what's important to them. They have other projects -- they are operating Delhi in order to maximize reserves, and so if they do something that cuts production or keeps it flat for a couple months, (inaudible) to install -- like in this recent year, they decided to substantially increase their capital program in 2011, so they had ended up drilling a bunch more wells than was originally protected projected.

Well, the effect of that was to call down production increase. Because you don't want to be injecting gas for producing in the same area that you're drilling that well. And so that would hold back production, and we had a flat production for a couple of months in the recent quarter. Since we are not the operator, we aren't exactly aware of that on a month-to-month basis what they're doing. So for us to give guidance is kind of high risk for us, because we don't know what's going on.

Okay. That's fair enough. (multiple speakers)

We can say that we exited the quarter on an uptick area.

Thanks for answering my questions.

There are no further questions in the queue. I would like to turn the call back over to Mr. Bob Herlin for closing remarks.

Thanks. Appreciate it. Thanks to everybody for participating this morning. Obviously, we are more than happy to take questions by telephone to reiterate what we've talked about or clarify. And with that, we look forward to our next earnings call and expect we'll have continued growth story for you to listen to. Thanks again, and good morning.

Thank you. Ladies and gentlemen, that does conclude our conference for today. (Operator Instructions). We'd like to thank you for your participation, and you may now disconnect.