Evolution Petroleum Corporation (EPM) Q2 2012 Earnings Report, Transcript and Summary

Good morning, ladies and gentlemen. Thank you for standing by. Welcome to the Evolution Petroleum Second Quarter of Fiscal 2012 Conference Call. [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 for 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 email distribution list to receive future news releases, please feel free to let me know. My contact information is on the earnings release that Evolution put out yesterday evening. And 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 through recorded telephone replay until February 16, 2012, and the 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 reply. Today, management is going to discuss certain topics that may contain forward-looking information, which are based on management's beliefs as well as assumptions made by management and information currently available to them. Forward-looking information include statements regarding expected future drilling results, production and expenses. Though 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 underlining 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 reserve. 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 risks. 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 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 and news release and I assume that everyone listening has accessed one or the other above. Excuse me, the Q is not filed, but the release is out. Since detailed numbers are available, Sterling and I are going to combine our remarks to key operating results and update some future plans so forth on -- 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 of 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 to $4.6 million and net production increased by about 12% to 569 BOE per day. I'd like especially point out though that our production was 72% oil, 6% gas/liquids. Revenue in earnings growth continue to be driven by growing oil production at 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 just talk about some of the specific assets that we have, which would obviously start with Delhi Field. Gross production there increased 13% over the prior quarter and got to a level of 4,946 barrels per day or about 366 barrels a day net to us. Gross production for the year ago quarter was only 920 barrels a day. So we've seen a very dramatic increase over the last year and since it all resulted in capital expenditures of 2009 and 2010. Now at Delhi crude oil that was sold there for $115 during the quarter was a quaint 22% premium over WTI Cushing. This difference in oil price 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 in this last quarter. Now calendar 2011 capital expenditures plan 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 supposed to be flat during the first 2 months in 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 prior to a fourth production collection site that was originally scheduled for 2012. Due in large part to this activity that was explained, the flat production in the first 2 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, early in 2011, Denbury, the operator, began reinjecting produced water back into the main producing reservoirs to help maintain pressure instead of purchased CO2 volumes. Since purchased CO2 costs is a major factor in economics, producing the CO2 purchases increases profitability, that's major reason for the acceleration of the payout date we reported last summer. As fuel profitability increases, Denbury should reach that defined 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 rate, required volume of purchased CO2, produced CO2 rate and is exhibiting characteristics of reservoirs that have either, or both, higher ultimate recovery and greater original in plays 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 technologies we prefer to trademark 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 is 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're paying the installation costs of technology and operating the wells in return for an equity ownership equal to 50% net profit interest in the first well agreement, and a 99% before payout, 76.5% after payout working interest in the second application. These demonstrations are expected to assist us in accelerating the commercialization of this technology. Down in South Texas, our Lopez Field, we are continuing the production test of 2 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 2 producers suggest that our target oil content is present, thus supporting additional development in field during the remainder of this fiscal year. We are still experiencing some challenges to maintain consistently high reinjection rate into the associated water but we believe that one or more of our current operation options will be successful. While we have up to 40 locations to drill on our leases, our goal in this project is to extend this concept to similar fields in the regions and therefore, add hundreds of development locations. In the Giddings Field, we focused during the quarter on maintaining our production volumes but not investing significant capital. Consequently, we were able to actually increase sales volumes by 13% from the previous quarter to 198 barrels of oil equivalent per day. This was done through several planned workovers of 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 form out of a portion of our leasehold on very favorable terms to the company. As for the rest of our underdeveloped locations, they averaged close to 50% natural gas in the reserves. Therefore, the profitability enduring in these locations or these proved locations is really below our acceptable threshold at current and expected near term gas prices. And we believe that more attractive opportunities are available elsewhere, and we're 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 is a top-line driven growth story but most of the revenue increase is going straight to the operating bottom line for income tax expense. Looking at the 6-month year-over-year results, total revenues grew about 260% primarily due to a 290% increase in crude oil sales volumes. Meanwhile, the 3-month year-over-year revenue growth accelerated further to 290%, primarily due to a 300% growth in crude oil volumes. First, 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 roll out 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 at over 3.5x our current share. Of course, about 1/4 of the incremental revenue will go to operating expense spend 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 grow double-digit increases in sales volume there. Meanwhile, increases in G&A were largely being driven by increased legal and personnel cost. On the wage front, the Board of Directors approved across-the-board salary increases in September to partly make up for forgone wage increases during the credit crisis. On the legal front, we continue to defend property interest on 2 separate matters we have previously disclosed to you and consider minor at worst. Ultimately, it seems that success for each frivolous legal entitlement complaints. Lastly, increased income tax expense is the price we also paid for increased success. So I guess we're 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. The 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 some 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 is good retail and institutional demand for more of this product due to the birth [ph] of yield product in the market. Especially considering our lack of debt placing [ph] the notes 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 both from operations before changes in the 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 in drillable projects focused towards oil, something we've been spending considerable time on over the last 6 months. We believe that market of 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, no debt -- with no debt, growing cash flow, cash on hand, we believe that we're 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're actively engaged in such evaluations at this time that we believe would provide a great fit with the projected increase in cash flows from Delhi over the next couple of years. With that, I will be ready to take some questions. Operator, please open the line for questions.

[Operator Instructions] Our first question comes from the line of Phil McPherson with Global Hunter Securities.

A couple of questions. At what point on this -- I'm going to call it the Delhi retirement plot 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 cost 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 kind of where they're 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 detail that Denbury doesn't like us to provide. We started retiring that payout balance -- oh shoot, when was that? Last May -- May of last year. And since then, we have really reduced that quite a fair amount. As we reported earlier on our reserve report as of last June 30 based on an oil price less than $95, the projected payout was like from November of 2013, which is roughly a year and 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'm not -- I can't say and wouldn't say even if I had an estimate, but just to say, early 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's. Keep in mind that a lot of numbers do go into that. It's not -- its production rate, it's the rate of CO2 purchases, it's oil price and so forth. Those are the 3 main factors that go into it.

I might add that to that, one of the things that -- all these numbers are audited and when do we audit them? Once a year. And 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?

12.

The last 12 months. Also bear in mind that as we've discussed before the -- and as you just mentioned Phil, that the payout actually increased over 200 by a pretty substantial amount. I think it peaked out at about 230 or 235, somewhere in that range. And it has worked its way down since. I will say that as a starting point, we'll probably not audit it 200 or a little less at this point and that's being chipped away out every month now. So, sorry we can't be more specific than that right now, but I think as our audit -- come to our audit, it will make it more clear for us as well.

It helps and I mean, you kind of highlighted this part about them reinjecting water and lowering the CO2. Any quantifiable number there from an operating and LOE standpoint?

No. Yes, that reduced CO2 purchases was reflected in our reserve report last June and that was a major factor in the 2 year acceleration of the payout date. And so what we're 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're continuing to see a lower level of purchases than the original plan as reflected on our reserve report. So going forward, the main factor at any further change is going to be primarily in a combination of oil price and natural oil production rate.

And just switching gears, it sounds like the GARP is working and you said in the press release, you talked about 25% increase in the reserves. I mean, is it a big enough number to matter at this point? Or how do we think -- like we -- 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 based really as a service company, we're an oil and gas producer, operator and developer. Eventually, GARP is going to have to take wings on its own either as a standoff or as a sale or some other JV. And I think I've been real careful to say all along that GARP has got a fairly long maturity cycle. This is not something that a year from now, is going to be the predominant source of revenue. This is going to be a slowly developing, acceptance by industry. And as you probably know and most people in this 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 it's something that works, you don't get credit for it and if doesn't work, you get blamed for it. So the people are very reluctant and understandably, about trying something different. So we're going through an education process. First thing we do, we'd show that it worked on our wells. Next step was to show that it worked on other people's wells. And the third step was to show that it works on other people's wells and other fields outside of Giddings. This is a multi-year 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. Now we think the potential is over the next couple of years is that it could become very material relative to Delhi. But that can take time and it's going to take hard work and a lot of marketing on our part. So either is it going to be appreciable material? Yes, it is, but not this quarter, not next quarter. We're talking probably several years.

Okay. That's helpful. And since you kind of led me in 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 Eagleford and is this something, with the 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. I appreciate that though. We're very focused as you can well imagine on what do with the cash flow out of Delhi. I'm sure that's probably the #1 question that the people have, looking at our company. A great amount of cash flows come up at Delhi but what you can do with it? So we're very focused on that question and since the employees of the company own roughly 20% of beneficial basis, we're probably more focused on that issue than anyone else because that's money in our pocket as well from our -- it's with the ownership. So we're looking very closely at opportunities to reinvest that pair with the dyed [ph] growth in cash flow and types of projects that are very, very oily that's there in areas that we can reasonably get to. For example, we're not going to be doing North Dakota, we're 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 million and $10 million wells. That just doesn't make some sense. So within those parameters, we're looking at a number of deals that make sense in the Texas, New Mexico, Oklahoma, Kansas regions. We have some great opportunities that we're looking at and I would say that we are in discussions on 1 or 2 projects that we think would be outstanding fits with the company, with our business model and is equally important, if not, more importantly, the 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're very excited about these opportunities. We think they're a great fit. And hopefully we'll be in position to talk more about it in the next earnings call.

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 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 shareholders for redeployment of cash flow, then we're going to get that cash flow into the hands of the shareholder 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 chart or whatever. You approved it to give dividends if you want it to or 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 to common stock shareholders.

I'm sorry. In 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 at it that would restrict it. Except not paying the preferred dividend, that would restrict it. And another one person or someone has already asked separately about -- in 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 an extremely attractive form out terms and we hope to do more with that in the future.

Our next question comes from Joel Musante with C. K. Cooper & Company. Joel P. Musante - C. K. Cooper & Company, Inc., Research Division: 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? I mean you mentioned that was -- it was on economics so I...

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 the increase. What we're doing is we're looking at the 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 is typically a straight line. We can look at where that production is today that we've restored, put it on that curve and then round that out and that kind of give 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 wells 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 that could be as much as 25% based on the current production rate and the rate you see in curves profile. This is, let's say, up to 25%. That's a reflection on the cumulative production to date. So it's -- 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.

When we're starting production to these wells, we're getting the rate back up at a point where the decline on that particular well was pretty flat. So if that long tail at low decline that you normally see on these kind of harmonic or hyperbolic decline wells, it 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 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. That make sense. And 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?

Well 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 by the Railroad Commission and relative regulatory bodies have added more people. That really is not an issue. And now it's one of -- we're trying to stuff -- I mean, we're producing these wells high rate pump in 2,000 to 3,000 barrels a day of fluid, which is 99% water. This is not fresh water, it's grinding water. It's not usable for anything. And 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 out fluid easily but putting the fluid back in has been somewhat of a challenge placed well on us and so forth. And so what the challenge has been how to get that water back in at that high rate of -- and we -- it's been somewhat difficult to get the rates as high as we want to, to have the most economic level of production. You can put water in but if you want the highest, high rate possible to produce a number of disposal wells. And so that's been the challenge. We've been working with service companies on this. We've been doing some tests and open lab and in the field and we've come up with a number of options that were fairly kind of an any one of them will work fine. If what we're doing right now is trying to find 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 that 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 was expecting we'll be able to report on 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 a ramp up in activity levels can you foresee at Lopez? I mean how much...

Lopez. I think that my expansion plan that we had there was on the ore, maybe 2 producers a month. So that's 2 producers, 2 injectors a month that could be as much as a $2 million CapEx per month rate. Obviously, we own 100% of that, so all that goes to our bottom line.

All right. And then my last question was on the workovers. How much do you estimate the workovers contributed to the LOE cost just to get a run rate?

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

Okay. So it was more or less of -- the previous quarter was about -- it was closer to 5 and now it's like 7.60 or something on a barrel basis?

Now you got to be careful by that per barrel basis because that's obviously influenced by production rate at Delhi in 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] Our next question is from the line of Kim Pacanovsky with MLV & Company. Kim M. Pacanovsky - McNicoll, Lewis & Vlak LLC, Research Division: I have a couple of more questions on the GARP technology. Did you install a -- 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're 2 different operators and no, we can't disclose it. They both prefer not to be identified. Kim M. Pacanovsky - McNicoll, Lewis & Vlak LLC, Research Division: 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. Kim M. Pacanovsky - McNicoll, Lewis & Vlak LLC, Research Division: Okay. And Sterling, the last time you and I met, one of the points you made was that this unit really needs to be reliable and not have downtime. 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've installed on December 2 has had excellent utilization. It was -- we did have a rock parted. The beam tops that was -- came with the wellbore and we utilized the beam pump in our application. That whole assembly, the downhole assembly, the sucker rods, everything, were old and we had a parted rock. So we were down, since December, we were down, I think, about 9 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, the beam pumps that suffered 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, the substantial increase of volume of oil and associated water, which has put more stress on those rods and that would be -- probably would accelerate the rod parts that was going to happen probably at some point in which it accelerates because now we're moving a lot more oil and water.

But it's going to reflect on the technology and that the pump is able to -- should be able to move, what it can move without breakage. But, so, the bottom line out of all of it is, is that other than maybe 1 or 2 days since December other than those 9, were we down for any reason and so, I mean utilization has been excellent.

By the way, Kim, we are operating both of those installations. Kim M. Pacanovsky - McNicoll, Lewis & Vlak LLC, Research Division: 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 mean, I know Bob, you did a really good job of explaining how long of a timescale 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 to sell it, things like that?

Well there's actually one more interim step I should have mentioned. With these operators, there are hundreds of other potential applications with them. And so really, if we are able to demonstrate that it's working successfully and the value creations have virtually no cost to the operator then the next step would be to go to them and say, hey look how we've added all these reserves, we extended the light of their 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 once other operators, other players in the industry see that 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. Kim M. Pacanovsky - McNicoll, Lewis & Vlak LLC, Research Division: Okay. All right. And then I just have a couple of modeling questions. Why is the tax rate so high? Your overall tax rate.

Well there's no severance tax on this, current severance tax holiday to the end of the decade. As far as the income tax, we have our corporate income tax, the federal rate and we also pay a state tax rate. The combined effective rate is...

About 42%

I thought it was 38%. Kim M. Pacanovsky - McNicoll, Lewis & Vlak LLC, Research Division: You were 43% in the first quarter and 41.5% almost in this quarter.

All of that is correct. Bob is correct too. 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 book rate that you're looking at, the 41% to 43% is a result of non-cash stock comp expense. And it's interesting because if you look back in our historicals where we had 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 were -- had losses, part of the loss was not deductible so it drove our effective tax rate down. But once we're taxable, it drives our effective tax rate up because that expense can't be deducted for income tax purposes.

We'd like to point out however, that as our revenues increased rapidly and our earnings increased rapidly, the effect of that non-cash stock comp will be far reduced and start pulling down that effective tax rate closer and closer to the 38%.

That's correct. Kim M. Pacanovsky - McNicoll, Lewis & Vlak LLC, Research Division: And then would you care to give production guidance for the next quarter?

Kim, you know we can never do that. Good try though. It's hard for us to give guidance on something that we don't have control over. Where the -- Denbury operates that project and they have a different set of parameters and what's important to them. They have far many other projects. They're operating Delhi in order to maximize its reserves. And so if they do something that cuts production or keeps it flat for a couple of months in order to install -- like in this recent year, they decided to substantially increase their capital program in 2011. So they ended up drilling a whole bunch more wells than was originally projected. Well, the effect of that was to hold down production increase because you don't want to be injecting gas or producing in the same area that you're drilling the well. And so that would hold back production. We had flat production for a couple of months in the recent quarter. Since we're 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...

We evidently can't say that we exited the quarter on an uptick.

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

Thanks, I appreciate it. Thanks to everybody for participating this morning. Obviously, we're more than happy to take questions by telephone to reiterate what we've talked about and 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. If you'd like to listen to a replay of today's conference, please dial (303) 590-3030 and enter the access code 4512322. We'd like to thank you for your participation and you may now disconnect.