Evolution Petroleum Corporation (EPM) Q2 2013 Earnings Report, Transcript and Summary

Good morning, and welcome to the Evolution Petroleum Announces Second Quarter Fiscal Year 2013 Earnings Release Conference Call. [Operator Instructions] Please note, this event is being recorded. I would now like to turn the conference over to Sterling McDonald, CFO. Please go ahead.

Thank you, and good morning. Thank you for listening to Evolution Petroleum Corporation's conference call to discuss our results for the second quarter of fiscal '13, which ended December 31, 2012. My name is Sterling McDonald and I'm the CFO of Evolution Petroleum. With me today are Bob Herlin, our CEO; and Daryl Mazzanti, our VP of Operations. Before we begin, let us cover the basics. If you'd like to be on the company's e-mail distribution list to receive future news releases, please see the contact information on our news release. If you wish to listen to a replay of today's call, it'll be available shortly by going to the company's website at www.evolutionpetroleum.com or via recorded telephone replay until February 15, 2012. The necessary information can be found in the earnings release. Please note that any statements and information provided today are time sensitive and may not be accurate at a later date. Our discussion today may contain forward-looking statements that are based on management's beliefs and assumptions that are based on currently available information. We can give no assurance that such forward-looking statements will prove to be correct as they are subject to risks and uncertainties that are listed and described in our filings with the SEC. Actual results may differ materially from those expected. Our discussion also may include discussions of probable, possible or potential reserves or recovery. Such unproven estimates are more speculative than proven reserves. Now we'll briefly review our results of the second quarter and I'll turn it over to Bob.

Thanks, Sterling, and thanks to everyone for listening in this morning. As we've said in past earnings calls, since the numbers are available in the press release we put out this morning, we really won't go into tremendous detail in our prepared remarks. I'm going to focus on key results and operations and projects, and then Sterling will come back on and talk about more of the numbers and then I'll follow up very, very briefly with some general observations and then we'll get to the real part of this which is the questions and answers. To begin with, this was a record quarter for Evolution in earnings, revenues and production. Our earnings of common shareholder increased to some $0.06 per diluted share or $1.8 million. That is an 81% increase over the previous quarter and 22% over the year-ago quarter. Revenues grew 32% over the prior quarter to $5.6 million and our production sales volume, net to us, increased 20%. It's about 696 barrels of oil equivalent today -- per day. We continue to execute our strategy to focus on core projects with the highest potential that create high value in the near-term. Correspondingly, we began the process of monetizing our non-core assets. We did that with 2 sales of assets in the Giddings Field for cash and contingent payments tied to future drilling. Now, let's get on to our core projects and obviously, we'll start with the Delhi Field. It's our crown jewel, it's a carbon dioxide-based enhanced oil recovery project in the Delhi Field in northeast Louisiana. That field has resumed its strong response to CO2 injections. Following the temporary restriction of production this summer because of hot weather, production not only returned to pre-summer rates, it also began responding to prior-year CapEx. Gross production increased throughout the quarter and averaged 6,872 barrels of oil per day, and that's a gross number. And that's an increase of 36% over the prior quarter rate of some 5,000 barrels a day. And it's 20% more than our best monthly rate before we had to restrict production during the summer. In fact, production is now well above our latest engineered reserve production projections, which include both proved and probable production. As a reminder, our June 30, 2012, reserves report, which is the latest one we have, projects production to continually increase throughout calendar 2017 to a peak level of about 11,800 barrels a day, followed by essentially flat production for a period of years and then a slow decline over a 30-plus year life. Please also remember that our probable reserves are associated with an increase in field recovery from a fairly low 13% recovery of original oil in place to the more typical 17%, as well as extension of the project into 4 additional reservoirs, which is currently expected to occur at the end of this decade and therefore, outside the 5-year window that the SEC normally requires for determination of proved reserves. We continue to realize the substantial oil price premium compared to your standard WTI oil price. In fact, we averaged more than $104 a barrel for the second quarter. And we really expect to continue receiving a significant premium through the near-term. CapEx at Delhi during calendar 2013 is being directed towards further development of the previously developed western half of the field. In order to better capture the full potential, completion of the project extension throughout the eastern half of the field is now projected for calendar 2014 and '15. We continue to expect that we will be reverting into our 24% working interest and the associated 19% revenue interest during the latter half of calendar 2013, later this year. Now exactly when that happens is going to be obviously heavily dependent on what oil price is, which is our Louisiana Light Sweet price; the actual production rate going forward; and the level of CO2 purchases, which goes against operating expenses. All of our current revenues are generated by our 7.4% royalty interest, which bears no operating cost or CapEx. Let's turn to our next project, which is the Mississippian Lime. Now during the second quarter, we completed the drilling and hydraulic fracturing of the Sneath #1 horizontal well. And we began dewatering and depressuring operations at the end of October of 2012. Hendrickson, our second well, was similarly completed, and operations began at the end of November. Now these 2 wells are the first of 114 growth probable drilling locations assigned by our independent reserve engineer. We own a 45% work interest in the Sneath and a 34% interest in the Hendrickson. Now in our general [ph] area, which is on the eastern side of the play, it's actually referred to the eastern side of the Nemaha Ridge, the Mississippi limestone is a highly fractured, a highly layered fracture carbonate. It's typically with the fractures containing the salty water and then the oil and gas is typically contained within matrix porosity. In order to produce hydrocarbons, it's commonly believed that the water filling the fractures first must be produced and reservoir pressure reduced. As this occurs, hydrocarbons, being a compressible fluid, will expand out of the matrix and into the high permeability fractures and then flow to the producing wells. Both of our wells were horizontally drilled, high in formation, targeting the area just below what's called the churry [ph] top layers of Mississippi Limestone and completed with 10 to 12 stages of hydraulic fracturing. This is in accordance with best industry practice in the area. To date, the Sneath and Hendrickson wells are exhibiting the 2 characteristics that we believe to be prerequisites for a successful horizontal Mississippi Lime producer. Those being, initial volumes of saltwater production with small amount of hydrocarbons and declining bottom hole pressure. Declining pressure indicates that the well's completion is contained within the target formation, as desired, and not connected to a water-filled formation, which is unfavorable. Large amounts of saltwater production suggest a large interconnected fracture system that provides access to a potentially large oil and gas reservoir, which obviously is very favorable. Both of our wells began producing water as expected at rates of less than 3,000 barrels a day. Now our operator has gradually increased dewatering rates and reservoir pressure has gradually declined, as expected, with small but generally increasing amounts of oil and gas production. We have learned that from other nearby operators of successful wells, that de-watering at a rate of up to 10,000 barrels a day for extended period is not unusual. Accordingly, our operator is further increasing de-watering rates. We are cautiously encouraged by the high fluid production rates, the small but growing oil and gas production, the steady slow pressure decline, that suggests, but do not guarantee or confirm, that our wells are connected to large fracture reservoirs and not likely connected to separate water-bearing formations. Our joint venture agreement calls for drillings of at least 6 gross wells by mid-April of this year. Due to the longer-than-expected de-watering and depressuring phase, we expect to delay additional drilling until late this fiscal year, pending results on those first 2 wells. And we still expect significant development drilling in fiscal 2014. Moving on to GARP, our official lift technology, our growing track record of developing new reserves and asset value through installation of our GARP technology continued through the quarter, with the successful installation in the previously announced Select Lands #1 wells. Production in that well went up from an intermittent 1 barrel of oil equivalent a day to the current about 20-barrel oil equivalent per day rate. We are finalizing the agreement to expand that joint venture and our continuing discussions with multiple other operators in both the Giddings Field and other fields, including the Barnett in East Texas Cotton Valley. In addition, we began a project to acquire a band in the marginal wells that show good potential for GARP application and thereby, capturing the full incremental value ourselves. As indicated in previous earnings calls, we believe that commercialization of GARP will require an extended effort over several years. Those are our 3 main projects. Now I'll start non-core asset. As I've previously mentioned, we completed the partial sales of non-core assets in the Giddings Field, primarily near the end of the quarter. If the sales had occurred at the beginning of the quarter, our net production for the sales in the Giddings Field would have been reduced by about 75%. The sales also included most of our gassy, undeveloped reserves in the Giddings Field, for which we will see contingent payments going forward based on the number of wells actually drilled. Our overall DD&A rate per barrel equivalent is expected to significantly decrease in future quarters due to the reduction of future development expenditures in the Giddings Field. Now in South Texas in the Lopez Field, our first 2 oil wells continue to produce at better than originally expected rates and we have begun producing oil from our third oil well. In our overall capital program for the balance of the fiscal '13, we'll continue to focus on the Mississippi Lime play and commercialization of GARP. However, since most of our Oklahoma development drilling is likely to be pushed into 2014 or fiscal '14 as I mentioned earlier, then the amount of money that we'll spend this fiscal year is actually going to be reduced. Working capital on hand is well in excess of remaining planned capital expenditures for the year. And therefore, we have no current expectations of being in the capital market for the foreseeable future. And with that, I'm going to turn it back over to Sterling.

Thanks, Bob, and good morning, again, to all of you. I'm going to be brief this morning to allow more time for questions. So I'll touch on only 3 points concerning our operating leverage, our asset sales and our tax rate. The most important thing I'd like you to take away today is the considerable amount of operating leverage that's built into our company. We've mentioned this before, but I think our current results are a prime example of how our operating leverage is working for our shareholders on a per share basis. Looking at the big picture, you may have noticed that we achieved an 81% increase in earnings per share, but that was on 20% higher sales volumes and 32% higher revenues. There are 2 things at work here. First, higher top line revenue growth is passing through to the bottom line, burdened only by very small increases in expenses. And second, our product mix is trending more to oil with its attenuate larger margins than natural gas and NGLs allowed today. All of this is being accomplished without the use of financial leverage. Thus, we maintained financial control of our assets for the benefit of our shareholders. And my next point concerns our recent Giddings asset sales, which is closely related to my first point regarding operating leverage. The pretax field income on the producing assets we sold at Giddings, which excludes our GARP wells, was $22 per BOE using our corporate $5.24 of BOE depletion rate. Had we applied the actual development cost of the Giddings assets that we sold, that margin would have shrunk by another $10 or $12 of BOE or so, dropping the pretax field income on these assets down to the $10-plus per BOE range. On a company-wide basis, if you add back D&A to our $3 million of income from operations in the current quarter and divide it by our 64,000 BOE of sales volumes, the comparable company pretax field income was $75.60 per BOE. Obviously, that margin will be hard to replicate in the future, but we do believe we have higher usage for our capital and limited staff than is provided with our gassy Giddings assets. Speaking of the gassy nature of those assets, I point out that the divested property's natural gas and NGL content was 80% of production volumes in the current quarter. Moving to my last point, deals with our tax provision. As you may recall in past periods, our corporate tax benefit when we incurred losses was considerably below the statutory rate and was somewhere in the 20% range. This was due to non-deductible stock comp expense related to stock option expense that's not deductible for tax purposes. Alternatively, when our net income turned positive, this same expense magnified our tax rate in the opposite direction, causing it to be considerably higher than the statutory rate. Note that going forward, all stock options have been completely expensed now. Therefore, this phenomenon will disappear in the future, assuming we continue to award restricted stock that is deductible in lieu of non-deductible option awards. Looking a bit deeper in our tax rate, I expect it to stabilize in the 36-and-change percent area, I think it was 36.8% for our 6 months results in our first 6 months of fiscal 2013. Although the federal rate is 34% to 35% and the Louisiana rate is 8%, bear in mind that we're able to take statutory depletion in Louisiana of 22% without a production limit. In other words, there's no barrel limit on the statutory depletion rate in Louisiana. Also, Louisiana allows us to take our federal tax liability as a deduction in their return. And of course, Louisiana tax expense filters back into our federal returns as a deduction, so you have to iterate to get to the appropriate tax rate. That concludes my comments. So I'll turn it back to Bob.

Thanks, Sterling. The strong oil production growth rate at Delhi during the quarter really underscores the value of that asset and the near-term step change increase in cash flow that we expect with the reversion of our work interest layer in 2013. With no debt, growing cash flow, cash on hand, proceeds from the non-core asset monetization, we believe that we'll continue to be well positioned for reflowing near-term cash flow and taking advantage of other opportunities within our defined business that may arise. Our overall strategic goal continues to be growing per share value and transferring that created value to shareholders in the most efficient manner we can get. With that, we'll take questions. And operator, you can, please, open the line for questions.

[Operator Instructions] The first question comes from Joel Musante of C.K. Cooper & Company. Joel P. Musante - C. K. Cooper & Company, Inc., Research Division: On the reversion, how do you keep track of that exactly?

Well, there's 2 ways we keep track. Number one, our Controller, David Joe, works with Denbury on a monthly basis and to show -- we get the report on what the gross revenues are, what the royalties are, what operating expense is, what's the CapEx and so forth. And so we track that every month. In addition to that, we have the very highly detailed model of the field and this operations economics that was developed with DeGolyer & MacNaughton, our outside reservoir engineer, and we're able to use that, which shows expected or projected operational results on a monthly basis for the life of the field. So we can use those 2 to track where we are, where we should be and where we think we're going to be, and we can roll into that actual results of production, expense, pricing and so forth. It's a fairly complicated model. Joel P. Musante - C. K. Cooper & Company, Inc., Research Division: Okay. So you'll have a pretty good idea like within a few days of when that happens. And then, but ultimately, you'll probably find out for sure after the fact, after the quarter ends for that period?

Well, we generally get production estimate -- estimates of production and price for a month around the middle of the following month. And so that's the kind of raw data, which we can immediately stick into our model and say, "Okay, where does that put us in terms of the payout balance and so forth." In addition to that, on a monthly basis, we get, later on, an update on the payout balance that Denbury calculates and we look at it and make sure that we agree with it. And then of course, every year, we go through a very exhaustive detailed audit of the numbers, we go down at a very deep level checking, to make sure that we agree with them on what they're calling expenses and where the revenues are and what they should have been and so forth. And then we go through a process of challenging and so forth. And we've been doing this for a number of years and I think we've got it down to a pretty good process. Joel P. Musante - C. K. Cooper & Company, Inc., Research Division: Okay. So about how far are you away from it right now in dollar amount, I guess?

Joel, this is a Sterling. We have intentionally not published what the payout balance is. And the reason we don't do that is because it's all subject to audit. And we, as a matter fact, we're getting ready to go through an audit in April. David Joe and our outside joint interest auditor that represents us will be in Plano office of Denbury for about 3 weeks in April. And then of course, we have to write up our sections and document them and they have to go back to Denbury and they have to respond to them. We just now received responses for kind of the second volley or so from last year's audit and we're narrowing the differences. But there's always differences there and so, we just decided it's not -- we can't give an exact number. The differences that we have, have narrowed over time.

And as we get closer to the payout point, obviously, the volatility around that date will narrow as well, but everything that we've seen and that's confirmed by the outside engineer, it's been confirmed by Denbury, is that reversions or payout is going to happen some time, has been some major change, some time in the last half of this calendar year.

I think Denbury has said so much in some of their communications as well. They're saying third or fourth quarter. I'll have to check on third quarter. I don't know.

I just spoke with them the other day and they changed their tune.

I don't know. He said third or fourth quarter. Sometime later this year. Joel P. Musante - C. K. Cooper & Company, Inc., Research Division: Okay. All right. And then just moving on, Mississippi Lime, does the higher water rate indicate maybe better permeability in the formation? And is there some correlation between water production rate when you're de-watering and well performance?

That's an excellent question, Joel. And at this point, there hasn't been a tremendous number of horizontal wells drilled in the area. And so it's anything you say is going to be not a theory, it's going to be more of a hypothesis of what's going on. Daryl, you want to answer that?

Yes. Joel, you could conclude, the more water that you make, the bigger the reservoir is. The question is how much oil is entrained in the reservoir. And that's what we just don't know at this time. It's a good sign that you're making a lot of water, that means you have a huge reservoir that you're drawing from.

You have to be a little careful though, because one of the things we watch for is that just because you have a wall-high [ph] fluid rate, that may be good, but also could be bad, because it may mean that you're connected to a huge water reservoir through some fault that you don't know about. And so that's one of things we look at is well, fine, you're making a lot of fluid, which is good, but what's the pressure doing? Is the pressure flat or is it going down? If the pressure is flat, it would suggest that you're connected to some ocean somewhere and you're never going to get pressure down, therefore, you're never going to get oil and gas liberated from the matrix. If the pressure is declining, then that suggests that there is a tank, it is limited in some size and therefore, we are able to get pressure down, which means we are able to get oil and gas eventually liberated. And so we're just following it. It's our first 2 wells, so we don't really have a lot of track record to draw on here. Everything that we've seen so far is -- makes us cautiously optimistic. Kind of a standard euphemism in the industry, but we just have to watch and wait and be patient. Joel P. Musante - C. K. Cooper & Company, Inc., Research Division: Okay. And actually the last question just had to do with just trying to get an idea what Giddings production or kind of a normalized post divestiture production rate for Giddings, you have?

That's a little hard to say right now because although we did cut our production by about 75% for the quarter from the sales, we are in the process of selling the balance of our non-core assets there. And non-core means anything in Giddings that isn't related to GARP. So Sterling, do you have a number?

Yes. Anything not related to GARP or not related to the interest we own in the Woodbine that we farmed out for somebody else to drill. Well, the numbers were in the quarter that there was about 125 net BOE per day spread across the quarter that belong to the sold assets that were booked into our financial results. And the larger of the sale didn't close until the 24th of December. So virtually all of the production revenue and so forth was contained within our financial results. And so we produced 167 net BOE a day. So if we drop 125, would be a 42 net BOE a day. On the other asset, as Bob points out, some of those assets may be sold. Although I think for the most part, our stronger remaining assets are probably our GARP assets. Okay, so the other way to look at is, is that in our press release, in our other field section, there's a discussion about the $255,000 of estimated pretax well income that was associated with the sold production that was included in our financial results. So that will be less than $100,000 a month of pretax field income that we would have given up. And on the other hand, we took in a little over $3 million of proceeds. Joel P. Musante - C. K. Cooper & Company, Inc., Research Division: Does that $100,000 reduction reflect the change in Giddings A-rate [ph] going forward though?

Well, no. And actually -- but that's a good point. The $255,000 of pretax is really kind of an overstatement to those assets because I used the overall corporate depletion rate of $5.24 on the production of those assets. The fact of the matter is, is that these assets, although competitive in the industry at the time that they were developed for the pricing deck at the time, I think our development cost were probably $16, $18 of BOE on these assets or at least our Giddings assets as a whole, I can't say about these specific ones. And so the real margin loss is really less. And Bob makes a good point, when we pulled these future development costs on these more expensive assets out of our full cost pool, our DD&A rate next quarter will drop from $5.25 to maybe what, $4.50 or...

$4.60, $4.70, something like that.

$4.60, somewhere in that area. So thus, indicating that there may not actually even be an impact on earnings per share due to the sale because of the change in DD&A rate.

Good point. But we don't know for sure. But there's a lot of things we have to do, go through the calculation. The PUD that we sold, as Sterling said earlier, although they represent a large PV-10 number, they also represented about $25 million, $28 million of future CapEx at a very high cost per BOE for reserves that are very gassy. We don't have a great deal of comfort that gas prices in the future, when I say future, we look to the future as what's going to happen in the next 1 or 2 years, to be high enough to justify drilling those wells, not with the other opportunities that we have. And so although we're giving up PV-10, we think it's a net add to the company because we are able to redeploy, not just the capital, but the staff required into more profitable areas instead of $16 to $18 per BOE gassy reserves. We've been struggling with that issue for the last 2 years and that's why we haven't really drilled any new Giddings wells, because we kept coming up with better places to put the money.

Yes, remember that $18 a BOE for gassy assets means $3 an ounce. And so that's just hard to justify.

As I keep reminding people on all this, management owns 20% of the company on a beneficial basis, so everything we do is on the basis of -- some of it has come out our own pocket. Do we want to use our own money. So go ahead.

The next question comes from John Fox of Fenimore Asset Management.

I have a handful of questions. They're all short. Mississippi Lime you mentioned on the call 114 gross locations. And then in the press release in the last sentence says, "Independent reserve engineer has assigned 112 additional gross drilling locations to the JV." So should I add those 2 numbers together and get...

I'm sorry if that wasn't really clear. There's 114 gross locations, of which 2 have been drilled, leaving 112 left to be drilled.

Okay. So the 114 is the starting number?

Yes, that's your starting total number associated with our gross leasehold position.

Okay, terrific. And then on the GARP, how do see that in the financials, is that coming through production or do you get a fee?

It's a production number. Right now, we benefit from application of GARP through a property interest in the wells in which we install it. So that may not be the future of GARP, but that's where it's going on right now. And I'm hopeful that in the not-too-distant future, we're going to be able to start breaking out the GARP results separately, in separate line item.

Okay, great. And then the wording was a little confusing to me on the Lopez, is that non-core now or?

Yes, that's a non-core asset for us. Kind of goes back to the whole concept of, we want to focus our staff and capital on projects that will deliver material value in the near term. And on the Lopez, although it actually end up being exactly what we thought it was going to be, but it's also clear that that's not something that you can generate a lot of value from quickly. It's a multi-year process to making that work wherever you apply it. And so while it has been successful, we don't see that in the near -- going forward, that's probably a good place for us to be putting our time and effort and capital.

Okay. So part of the Giddings and net Lopez could be sold in the future?

Correct.

Okay, and on the Giddings that you sold, the 125 BOE per day, how much of that was just nat gas?

All of our reserves, but if you look both production, as well as the PUD, it's approximately 80% natural gas and gas liquids. Now it's not as much gas liquids as you would think because one of our major wells that we sold, the gas that's being sold is not being processed. And therefore, it's being sold as high BTU, or on BTU basis. And so we don't get that liquid upgrade. So basically we look at it as being 80% gas, although somewhat rich gas, but still gas.

Okay, so when you reported 680 a day gas in the December quarter production, a lot of that is going away then?

That is correct.

I mean, 125 BOE, multiply by -- divide through the conversion and then 80% of that is basically...

I don't know about your specific number. I do know that the bulk of the gas production in sales for the quarter has been sold. And to the extent in the future -- to the extent we have gas production that's likely to be strictly from, or primarily from our Mississippi Lime play. We do have -- some of our GARP wells do make gas. We do sell gas there. John, what was your question again?

My question is really, Sterling, milling production going forward. The natural gas production line is going down by a very large percentage?

Yes, that would be correct. And the opposite or the mirror, the other side of that is our oil mix is going up. And not only just in percentage terms, but that absolute amount of oil is going up with record oil production being posted at Delhi. And then on top of that, when we revert this year, we're going to get another huge step change in that whole metric, which is all the oil at Delhi.

Right, of course. And then my last question. Have you -- this is significant in the G&A, you mentioned some litigation, some legal cost and some deal cost, have you broken that number out or is it significant...

We haven't broken it out yet. I'm trying to break it out for the Q so I hope to be able to offer something there. I think under current divestiture rules on the accounting literature, we have to expense the transaction cost now, which is kind of -- I got to tell you, of all these rules, nobody ever thinks about full cost company. We have to take the, unless it's really significant, we have to take the proceeds and credit them against our full cost pool. We don't run that through the income statement on a gain or loss, but our transaction costs have to be expensed under the rules. Well, that's kind of silly, but that's the way it is.

The other part of that, we do have litigation going on. It's all -- so we have a couple of frivolous cases there that our counsel has determined that are not material -- they're not likely, they're, what's the word, they're not [indiscernible] the exact word that is. But anyway, even though they're frivolous, you still have to defend them. And when your company our size, any kind of litigation cost is painful and you have to do it. You always are looking at, well, is it cheaper to settle. Then there's the principal at stake. If you settle, then does that just encourage somebody else to do the same kinds of frivolous claims.

Right, sure.

And so it's -- I hate, it's unfortunate part of our current legal system that anybody can file a lawsuit for any reason or any basis and not even have to prove or basis for it and try to extort money out of a company. And that's just the way it is and we've got to leave within that system. And unfortunately, it's a material number for -- a significant number, not immaterial. It's a significant legal cost to our G&A that we have to deal with.

And it's the price of success.

Yes, and whenever you're successful, somebody is always trying to figure a way to take it away from you.

Okay. Well, I'll wait for the number, how is that?

The next question comes from John Koller [ph], private investor.

I think the word you were looking for is without merit.

That's it.

Without merit. There you go.

And I'm not a lawyer, just for the record.

Okay. John, what was your name again?

Koller, K-O-L-L-E-R.

I thought that was John Koller.

No, that was John Fox.

Okay.

Sorry about that.

Well, I thought it sounded familiar but I guess not. Hi, John Koller.

My question, I'm glad to see the news on the GARP. I think buying wells for your own account and installing, it could prove quite lucrative. I don't want you to tip your hand because I know if you express an interest in certain areas, things are going to go. But I'm curious as to whether you think you can buy sort of in bulk or singly, whether they would be plugged, whether you have access to well logs and whatnot and just what you're thinking as far as returns on capital there. I think that's my only big question.

It's a new area for us. Right now, our focus is on wells that have been abandoned by the prior operator and so we're actually going and taking new leases. These are wells that are currently not plugged. Another type of well would be one that's not only been abandoned, but it's been plugged, and that obviously raises the cost a bit. There is an opportunity to go to companies and to buy their marginal wells. But for -- GARP is best applied to subset of marginal wells. It's the ones in the top 2 quartiles. But when you go to somebody and say, I want to buy your marginal wells, they're going to say, "Well, I don't want to sell you my top 2 quartiles marginal wells. I want you to buy all of my marginal wells and take me out of the whole area." Because that's part of the cost savings for them is to get out of an area and to cut that fixed cost. And so that's part of the consideration that you have to look into, is the value that you're going to generate a sufficient to justify that additional liability. In terms of the rate of return, quite honestly, we're not at the point yet where we actually use that as a tool or how our metric that we consider. The typical deals that we're doing now, we're adding reserves anywhere from $1 per BOE to maybe as much as $10 per BOE. And when you get that lower cost per BOE, then your rates of returns are so high that they're not really valid numbers to use. For me, anytime you get an IRR more than about 40% or 50%, it ceases to become meaningful as a metric. So we start looking at well, okay, how much present value are we adding for $1 of investment, because that's more of a risk calculation. You don't want to risk $1 if all you're going to get is $1.50, even though it might be a high rate of return. We really want to look at opportunities where we can add $2, $3, $4, $5, $10 of value for every dollar we invest.

The next question comes from Gabe Daoud of Sidoti. Gabriel Daoud - Sidoti & Company, LLC: Just a quick question on the Mississippian Lime project, I guess with the dewatering stage maybe taking a little bit longer than anticipated, does that affect the JV picking up additional acreage that's up for grabs?

Well, we certainly have held back and we've actually passed on some opportunities to pick up acreage, but that's just kind of the nature of the way we are. We're a very conservative company and we're not going to jump out and spend all of our capital buying a bunch of acreage before we have a good idea, first of all, is it going to be economic? And second, is that something that we can get to in a timely fashion. There's not much point in buying a lease if you're not going to be able to develop that lease within the term that the lease provides for. So we're being very cautious about it. And so far, I think it's panned out for us. When we have a greater level of comfort in our particular area, then we'll look at expanding our position. And obviously, we have spent a lot of G&A time and effort on identifying opportunities and where we would go once we're ready to pull that trigger. Gabriel Daoud - Sidoti & Company, LLC: Okay. And I guess, maybe if you could just speak to what really drives a difference in the economics between, I guess, what you guys estimate and maybe what Range Resources is estimating?

Well, Range is using a very high reserves per well, which is, what, they're up to 600,000 BOE per well, which is, I assume, it's a fairly long lateral. Range is right there on the top of the Nemaha Ridge, as well as on the eastern flank covering most of the Western half of Kay County, which is really offsetting us to the West in southwest and northwest. Geologically, what we see their formation is no different than ours. There should be no difference between our 2 positions. Now our outside reservoir engineer has assigned about 311,000 BOE per gross well or gross reserves per well. We're comfortable with that number. In fact, we use a lower number in our economics in terms of justifying what not to even get involved in the play. We're comfortable with that number until proven otherwise, it should be higher. Because when we look at a play in a project, we want to make sure that we include all the warts, along with all the good stuff. You can't just look at the good wells, you got to look at all the wells until we know for sure that we should have a higher number, we think that, that 300 number is what we should be using in our decision process. Clearly, we would love to be proven wrong in a sense that it should be a higher number. I mean, we'd be ecstatic, obviously, because the economics would go from merely good to exorbitant.

The next question comes from Jeffrey Connelly [ph] of Green Capital.

You guys mentioned that Denbury is going to develop the western half of the field. Is this new? Was the plan go to east first?

Well, they've been developing the field since 2009. They started kind of in the middle and then they gradually, each year, they worked to the left or to the west. And then they completed that pretty much in 2011. And in 2012, they started developing from the center to the east. Now, this year, they announced, because it's January, that they actually were planning on focusing capital this year on going back to the western half of the field on the basis that from the production performance of the field, from all of the analysis and work that they've been doing and they are working on remapping the field based on all the 3D. But based on all of that, that they thought that they had opportunities to capture more value by going back in and spending a little bit more money where they had already developed the project. So as a result, the balance of the project, which is finishing off the eastern half, really will not be completed until 2014, '15. And then we have 4 smaller reservoirs that are on the south side of the field that's within the unit that were developed originally as primary or secondary production. We anticipate those will be added to the project. But right now, that's not scheduled to occur until the end of the decade, which is just, at this point in time, right on the edge of the 5-year window, slightly outside the 5-year window the SEC requires.

Okay, and does that change your CapEx expectations once the interest kicks in?

Yes, obviously, we'll have some impact and that we will be picking up our share, our 24% share CapEx when reversion occurs this fall. Now I think by this fall, this year's CapEx will probably be primarily spent. So I don't know how much exposure we have this calendar year. But yes, we do anticipate paying our 24% share CapEx in '14 and '15. They typically run $50 million to $60 million gross CapEx a year to the project. So our exposure would be 24% of that in 2014 and '15. And obviously in the end of the decade, there will be another $50 million or $60 million gross CapEx so we'll pick up our 24% share of that to add those smaller reservoirs.

Okay. And just one last one. With the cash that you guys have, would you ever consider buying back the preferreds or buying back some additional common stock?

One of the questions that we are always dealing with is what is in the best interest of the shareholder, in terms of our available working capital. First, and foremost is we don't want to do anything that's going to put the company at risk. So we're not going to leave ourselves short of working capital to meet any and all obligation particularly when it comes to Delhi Field and Mississippi Lime opportunities. But beyond that, then the question becomes, what do we do with excess cash flow, which actually will start growing very, very rapidly this fall. And we are looking and the Board is considering a variety of options, which is anywhere from new projects to expand the Mississippi Lime to buying back stock to a dividend. I mean, we will consider any and all options that are in the best interest of the shareholder. I can assure you that's a keen interest of me as well and everybody here since we're all shareholders.

[Operator Instructions] The next question comes from Mike Kelly of Global Hunter Securities.

This is actually Stephane Aka. Mike had to run to a meeting. So first off, I was hoping you could maybe quantify production at Delhi. You mentioned it was about 36% quarter-over-quarter and it's actually trending higher than you had modeled. So I was just hoping that if you could maybe just provide a little more color as to where it's currently at.

Well, that's a constant source of discussion between us and Denbury. Their preference, and they have very good reasons for it, is to not make public production on a monthly basis. They prefer to lend it to a quarterly discussion. And obviously, anybody can go get monthly production from the state website a couple of months after the fact. The reason being that production's month-to-month can vary for operational reasons because of what goes on in the reservoir itself, sometimes you get production that kind of surges and then it lapses and so forth. An example of that would be what happened this summer. We had to -- the operator had to cut back production because of cooling issues that has actually, or since been corrected. So we won't run into that again, but I think all I can really tell you is that production increased steadily across the quarter, but it averaged 68, 72 for the quarter. It is a reasonable expectation in calculation and derivation from that, that production ended the quarter at a higher rate than the average. But I'm afraid I really can't give you any more details on that.

All right. And then I think someone might have...

Mike, can you speak up a little bit?

I was saying, this is actually Stephane because Mike had to run to a meeting. Now in the Mississippian Lime, if you look at other industry wells that have had high initial water cuts, kind of how long does it take on average to get the oil production to actually ramp up?

Every well is really unique and has its own story. We originally thought that we would only have to produce a couple of thousand barrels of water a day for a couple of months at most. Subsequently in talking with other operators that have drilled far more wells and have the successful wells in our area, they have told us that, no, you can -- the good wells you may have 10,000 barrels a day for a couple of months. So on that basis, then we still have a ways to go. Other than that, I really couldn't tell you. We're watching production. We are pleased at what we're seeing, but we're obviously disappointed that we haven't had Oil & Gas at the levels that we were projecting sooner than we have. Now, does that mean, is that good or bad news? I don't know. It could be good news. It could be bad news. We don't know. We're just having to wait and see and so far everything is suggestive that we're going to have good wells. But until we actually have those good wells, we just have to play out and wait and see what happens. It's a great big I don't know. We started off slower, apparently, and hit 2,000, 3,000 barrels a day and found out other operators were pulling on them at 10,000 barrels a day. So it's going to take us longer, but we've stepped out the pace. The operator has moved in equipment that will allow us to produce higher water volumes. And of course, another key here, the economics of the whole thing is, is that you can efficiently and economically handle the water and we're doing so with our own salt water disposal well that the joint venture drilled for its own use.

Okay. All right. And then lastly, if I could. If you could maybe comment on kind of your current leasing efforts and just kind of where you're focused and what you may be looking at in the near future here?

Are you talking about the Mississippi Lime or altogether?

Just overall, just in general.

Okay, right now our active efforts are really toward GARP effort, where we're out there attempting to lease around abandoned wells for us to go and install the GARP. We have identified opportunities to expand our Mississippi Lime position, but we're not pulling the trigger on that until we have higher comfort level on what we've done today. And that really are the only 2 areas that we're positioned to do any kind of activity.

The next question comes from John Fox of Fenimore Asset Management.

Bob, can you just give an update. I'm actually looking at a map of the Mississippi Lime, where actually your wells are?

Yes, our wells are almost right dead in the middle of Kay County. We're a little North of Ponca City and extend up to the border of Kansas, right?

With the acreage, right [ph]. He's asking where the wells are.

Oh, the wells are. The lower part of our acreage. Maybe 5 to 10 miles north of the Ponca City. The 2 wells are actually in the southern part of our leasehold position and therefore, closer to, say, the range and the triple diamond wells that we're modeling after that were successful.

But it's all Kay County. You don't go down to Noble County?

No, no, we're right in the middle of Kay County.

The next question comes from Jeffrey Connelly [ph] of Green Capital.

A follow-up on the Mississippian Lime. Can you tell us what kind of pump you guys installed, is it a jet pump that's down-hole?

What kind of pump you said?

A jet pump?

It's electric submersible.

Do you want the brand name or?

No, just a little bit of color as far as, is it the same pump that you're using before or is there any difference?

We've gone through several sizes of pumps and we've increased the volume capacity each time we done of work over.

So we started off with a pump that was cable of doing about 2,500 to 3,000 barrels a day and then obviously in kicking off that rate, we started off at lower rate and kind of slowly edge our way up, because you don't want to pull in the sand by rapidly changing the pressure down-hole. And then we pulled the lower pump and then we put in a bigger one and so forth. And we've done that on both wells. So it's been a gradual process of increasing production rates and I think we're up to, what, 6,000 barrels a day maybe on one of them and we're still with about...

And increasing it to probably 8,500.

Increased to 8,500 on...

Probably [indiscernible] 5,000.

We're less than 5,000 on Hendrickson. We're well below the 10,000 rate that a certain other operator, whose name has an R in it, is using.

Seeing that there are no other questions, this concludes our question-and-answer session. I would like to turn the conference back over to Robert Herlin, Chairman and CEO for any closing comments.

We really don't have any closing remarks. I think the questions pretty much covered everything. But we are very pleased with the results. We're very pleased with how Delhi is ramping up with oil price and so forth. So obviously, please feel free to give us a call. We'll be more than happy to go back over our public comments. And with that, we look forward to talking to you next quarter. Thank you.

The conference has now concluded. Thank you for attending today's presentation. You may now disconnect your line.