Sterling H. McDonald - Chief Financial Officer, Principal Accounting Officer, Vice President and Treasurer Robert Stevens Herlin - Co-Founder, Chairman, Chief Executive Officer and President Daryl V.

Mazzanti - Vice President of Operations

Gabriel Daoud - Sidoti & Company, LLC Hoshang V. Daroga - MLV & Co LLC, Research Division Michael Kelly - Global Hunter Securities, LLC, Research Division Jeffrey Connolly - Brean Capital LLC, Research Division

Good morning. Thank you for listening to Evolution Petroleum's conference call to discuss results for the third quarter of fiscal 2013, which ended March 31.

My name is Sterling McDonald, and I'm 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 evolutionpetroleum.com or via recorded telephone replay until May 23, 2013. 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're 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 let's briefly review the results of our third fiscal quarter, and I'll turn the mic over to Bob.

Thanks, Sterling, and thanks to everyone for being with us this morning. Since the detailed numbers are readily available to everyone in the news release last night, I will focus my remarks on key results, operations and projects.

Sterling will similarly have his view on some financial results, and then I'll close with a few general observation, then we'll take your questions. To begin, this was a second record quarter in a row for us as to operating earnings and revenues.

Earnings to common increased to $0.07 per diluted share or some $2.2 million. This is an increase of 24% over the previous quarter and 71% over the year-ago quarter.

Revenues grew by 6% to $6 million, and our net sales volumes declined 10% to some 626 barrels of oil equivalent per day. That decline is due to the sale of most of our Giddings production at the end of last quarter.

Since the bulk of the Giddings production sold was gas, the higher oil price we received at Delhi more than offset the lost revenues on the Giddings sale. So let's take a look at some of the key assets.

Starting with Delhi Field. It's our crown jewel, the CO2 enhanced oil recovery project, and it continued its very strong performance.

Gross daily volumes increased 11% to an average of 7,645 barrels of oil per day or 566 barrels of oil per day net to Evolution. As a reminder, our June 30, 2012, reserve report projects production to increase through calendar 2017 to peak level of about 11,800 barrels a day.

That's at gross level, followed by essentially flat production for a period of years and then a slow decline over a 30-plus year life. Our probable reserves are associated with an increase in field recovery from 13% of original oil in place to 17%, as well as the extension of project into 4 additional reservoirs sometime around the end of this decade and, therefore, outside the SEC 5-year window to be declared proved reserves.

We continue to realize a substantial oil price premium compared to standard WTI. We averaged more than $111 per barrel at Delhi for the quarter, compared to the $98 we averaged in all of our other production.

Due to the continued strong performance, we now expect that our 24% working interest will revert back to us somewhat sooner than was projected in our last summer's reserve report, up to 1 to 2 months earlier altogether. And we now expect that to be sometime on or about the start of the fourth calendar quarter 2013, which will be our second fiscal quarter.

Obviously, this is subject to production rates, operating costs and oil prices. Capital expenditures during the calendar 2013 at Delhi are being directed towards further development of the previously developed western half of the field.

This is in order to better capture the full potential of the multiple test [indiscernible] reservoirs. Completion of the project throughout the eastern half of the field is now projected to occur in calendar 2014 and '15.

All of our current revenues are -- and our past revenues have been generated by a 7.4% royalty interest. Moving on, let's talk about the Mississippi Lime project.

We drilled the first 2 of our 114 gross probable drilling locations last quarter, and we've been dewatering ever since. We're now producing small amounts of oil and gas, but with high levels of water.

We and our partner have been analyzing results in comparison to wells drilled by other operators in the immediate area, both good and bad wells. And the one significant difference that we've identified is that the 2 core wells nearby were completed low in zones.

The wells with good reported results were relatively high in zone, and our 2 wells were drilled pretty much in the middle, and that was intended in order to allow us to more fully frac the full reservoir. In our 2 wells, the completion method that we applied was clearly not particularly effective.

In other words, we really haven't demonstrated the best completion method on our leasehold. And someone earlier said to us that we really haven't cracked the code on our leasehold.

With another 112 gross drilling locations remaining, we have proposed to our partner the drilling of a third well but higher in zone, similar to those wells with the good reported results by other operators in the area. Following the end of the quarter, we elected to reduce our share of the joint venture in undeveloped leases to 34% from 45%.

And this will save us about $1.2 million that we will use to pay for our share of the third evaluation well. Moving on to GARP.

We reached agreement to install our technology on a third well with one partner in the Giddings Field. This well is called the Appelt #1G.

As we announced last quarter, we began acquiring leases for an existing but previously abandoned well that have good potential for GARP, we believe. During the fourth quarter of this year -- fourth fiscal quarter, we expect to install GARP on the first of these opportunities, which is called Philip 1G.

This is also in the Giddings Field. Earlier, the Select Lands #1 well in which we installed GARP with great success last quarter was recently temporarily abandoned after an offset well was hydraulically fractioned by another operator and water and sand from that frac has apparently impacted our Select Lands #1.

We are continuing discussions with several candidates for installing GARP, either as a full program or as demonstrations, not just in the Giddings Field but in other fields, both vertical and horizontal wells. Additional information and results of all of our installations to date can be seen in our new website, which is www.garplift.com.

As far as our other non-core assets, we have entered into a tentative agreement to sell the balance of our non-GARP producing assets in the Giddings Field, retaining our royalty exposure of some 2,500 acres. Our first 2 oil wells in the Lopez Field continue to produce at better-than-expected rates, and we have now begun producing oil from the third well there.

While our results are meeting our expectations, or meeting or exceeding, the longer lead time for development there than what was originally expected has resulted in that property being designated as a non-core asset and, therefore, a candidate for divestment. Overall, our capital program, there's quite a bit left than what we originally thought.

For the fiscal 2013 balance of the year, we really will be focused on the 2 GARP installations and the initial costs of drilling a third Mississippi Lime evaluation well. Since working capital at hand is well in excess of remaining planned capital expenditures for the year, in fact, in excess of what we need to meet our needs for next year in Delhi as well, we have no current expectation of being in the capital markets for the foreseeable future.

And with that, I'll turn it over to Sterling.

Thanks, Bob. I really don't have much to add on the numbers today.

They pretty much speak for themselves. Later, we'll be glad to answer your questions in the Q&A.

But in the meantime, I'd like to address our views on value creation in the oil and gas space. As most of you know, we attend and present at the major oil and gas conferences, and often, we sit in on another company presentations.

One of the things we continually notice is that many of these presentations speak to growing production to show tall bars on a slide presentation, as one analyst notes, or just the growing of market capitalization. What continually surprises us is the focus on production growth over what we consider more important factors such as capital efficiency, increasing value per share and controlling risk, particularly financial risk.

In a piece that was distributed last month by Global Hunter, who covers us, and penned by their NDM, who is [ph] Mike Kelly, Mike focuses on "2 of our favorite measures for evaluating E&P's corporate performance and efficiency." Those 2 measures are: the recycle ratio, which Mike calls a solid proxy of return on capital for an E&P company; and the debt adjusted production growth per share metric, which Mike sees as a better assessment of growth versus the top line absolute figure.

We would agree with this analysis. And as we look at the recycle ratio, it essentially shows the cash earned per barrel of oil equivalent produced versus the investment, which is composed of not only drilling completion and infrastructure but also leasing, seismic and all of the costs to get that barrel out of the ground.

This is a quick way to gain a good sense of whether a company is making a solid return on its investments, according to Global Hunter. To calculate the recycle ratio, one merely divides the operating margin per BOE by the DD&A rate.

And to calculate in EPM's case, we were off the charts, literally. For the most recent quarter, Evolution's recycle ratio was 9.7 against a mean for 60 E&P companies of 1.7.

EPM was the highest, and the next highest from EPM's 9.7 was a ratio of 2.8. Now turning to the second measure, debt adjusted production growth.

This ratio translates top line production growth into a per-share figure. It shows how the company grows production for the shareholder versus growing production to show tall bars on a slide deck.

And in doing this adjustment, basically, the debt is converted to equity on total, so that you get a full flavor of what the shareholders' return is. EPM again is off the charts, coming in at third at 193%, while outdistanced by a 300-plus percent growth rate by 2 other companies in the 60-company universe.

Meanwhile, the median growth rate was 10.3%. But an excess of 25% of the companies actually showed negative share adjusted growth.

So what does this mean to Evolution shareholders? Historically and currently, our performance has been stellar based on these 2 metrics, but what about the future?

Let me say that with the additional equity generation that is again about to be supercharged with our reversionary working interest that will soon kick in, I'll just say that the company you see now will look quite a bit different 1 year from now. Either we'll be redeploying capital under the ground via drilling in the Mississippi Lime or installations of GARP, or we'll redeploy the cash in assets and other ways for the optimal benefit to our shareholders.

As we've repeatedly said, our directors and employees are beneficially about 24% in the company, and that's where our focus always is, in addition to staying in the game, if you will. So with that, I'll turn the mic back to Bob.

Thanks, Sterling. The continued strong performance of Delhi during the quarter underscores the value of that asset to shareholders and the increasingly near-term step change of cash flow that we expect, with the reversion of our working interest, which is really only a matter of a few months away.

With no debt and rapidly growing cash flow, substantial cash on hand and continuing proceeds from our non-core asset monetization, we believe that we are continuing to be well positioned to perform on our overall strategic goal of growing value per share and transferring that value to shareholders in the most efficient and timely way possible. With that, we are ready to take questions.

Operator, can you please open the line for questions?

Just a few questions on Mississippi Lime. So regarding the third test well, it looks like the plans are to drill higher in the formation, targeting the Chat section.

Right below the Chat.

Right below the Chat? Okay.

Well, I guess, if you could just maybe speak to that a little bit, provide some more color on that.

Sure. I'll be happy to.

Keep in mind that there is no hard theory about what's going on here, what we have are hypotheses. And we compare what we did in our well in our results with other people's wells that had both good and bad results.

Then we said, "Okay, what was different?" And what was different in our wells both in geology in terms of location, in terms of how we completed, where we completed.

And the one thing that was strikingly different was the location of the wellbore. We originally had placed -- we had seen what other people done with poor wells that had drilled low in sections, and we wanted to avoid that.

We didn't want to get too high in section, because we were worried about the fracs not penetrating through the full matrix and being lost into Chat section. And so we elected to go right in the middle so that the fracs would extend throughout the formation and get maximum exposure.

Obviously, in our area, that didn't work, at least not very well. So we said, "Okay, what are other people doing that did have good results that they reported?"

And they were consistently about 40 to 50 feet higher than we were on a relative basis. Not in the Chat, but a little below the Chat, and so we're thinking, "Why?"

Theoretically, how does this work? Why does it work?

And one of the hypotheses that my engineers speak because there's a big difference between the -- a theory's actually got proof or empirical evidence to support the hypothesis. But one of the hypotheses that we have is that this reservoir has tremendous streaks of permeability in it, and when you frac the well, you connect all those, and what could be going on is that you have, through the frac have created this huge tank, and the oil and the water is separating.

And so if you're too low in section, you're getting all the water coming to you and the oil is going up. That's the -- that's one postulation of what could be going on.

And to test this, we wanted to go a lateral higher to get above that water that's been separated. We don't know that's the answer but we think that's one possibility, and we want to test that.

We know that other people are successful in doing what we're doing in general, and this is the one difference. So we're going to find out.

Okay. And then in terms of completion, are we looking at the same 10 to 12 stages as the first 2 wells or that will be adjusted as well?

I suspect that we will do something very similar, try and go out about 4,000 feet, look for about 12 stages of frac. I think that the frac mechanisms that we've been using are fairly similar to what other people are doing.

Daryl?

With one well, we did frac point, which is a series of packers that we individually frac-ed individual zones. The other well was plug-and-perf, and that's the standard procedure in the industry for horizontal wells.

Okay. And then finally, just in terms of when the drilling will actually commence, and, I guess, when can we expect some results from the third well?

Well, we've made the proposal. Our partner has a certain timeline to accept or go nonconsent.

Once that acceptance or nonconsent has been received, then we have to get a rig that we would like -- that we like and is appropriate and cost-effective. That could take a little bit of time.

It's typically a 30-day process, once the rig is mobile. And then you got to get in line for your frac and get the frac, and that typically is only a couple of days, but you have to get in line for that frac crew.

And then you have to make -- get your flow lines laid. We'll be utilizing the same water disposal well to keep our costs down.

So a lot of this is going to be done in parallel paths. Some of it is going to be done sequential.

And then, there will be -- we'll put in a higher-capacity pump in the get-go, so hopefully, that will allow the dewatering to occur rapidly. And if this is -- does what we think it's going to do, then we should have results, I think, fairly -- we'll know fairly quickly.

This shouldn't be like these other wells where it goes on month after month of dewatering. I think we'll know far sooner if this works or not.

So when all that comes, it'll be sometime this fall, I think, is the best way to describe it.

I understand that you guys are 6 months away from the reversion of your working interest and -- or maybe 3 or 4 months. But have you thought about how you would deploy this cash flow in terms of doing buybacks or increasing value using -- paying out dividends?

Because the Mississippi Lime is taking time and what's Plan B? That's what I was wondering.

We'll have to be quite honest, the Mississippi Lime was never intended to be the redeployment of all the Delhi cash flows. It was really only sufficient in its full scope to redeploy, really, the cash flows that we're getting now from Delhi.

Once the reversion occurs, we're talking $50 million, $60 million a year after tax so that is far in excess of what we had in mind for Mississippi Lime. So clearly, we are looking at a variety of options and that would include dividends, that would include stock buyback, that would include company sale, that would include new projects.

There is nothing that is off the table this time, I think. So the best way to describe it is to remember that management and employees own 21% of the company.

Directors plump that up to 24%, if you exclude our largest institutional shareholder, who has employee on our board. I can assure you that whatever we do is going to be what's in the best interest of the shareholders because we're shareholders and that's far more important to us than any other factor.

So we're looking at how do we best use that cash for the benefit of the shareholders.

To follow up on that, you've mentioned new projects, and I kind of have the saying the world turns on square wheels, there's nothing continuous about it. And I envision that there are a number of balance sheets that are overcommitted to some of the plays -- the current plays that are going on, and I think there's going to be opportunities there.

Now whether those plays fit our screening and our economics and the terms of those trades, that would remain to be seen. But I do think there are going to be further opportunities that come up.

But I also think, as Bob points out, that within the next year that we're going to be making some decisions about how to optimize shareholder return, and I can't tell you exactly what that's going to look like. But there's only so many things you can do with your cash; paying down debt is one of them, and we really don't have any other than a $7 million preferred or $8 million.

That's all I have.

Okay, great. And one last question.

I'm not sure if you guys can answer, but I will take a stab at this. Do you have the number or how much of net revenue interest has been generated from Delhi?

Because I believe that they have to reach 200 in order for your reversionary working interest to kick in. So how much is...

I'm not sure I follow you.

Are you asking what the payout balance is?

Yes, what the payout balance is right now.

Well, look, that's not publicly -- that's not a number that went out publicly. So it's ...

It's -- I think the best way that we've been able to position that is tell you kind of the order we expect that to occur. And to try to follow the pieces of it, I mean, some of it is open to audit, as we've -- audit adjustments, as we've discussed in the past.

And certainly, as we get to the reversion date, those audit adjustments are going to have to be closed out in order to get to the number that you're after, which is that $200 million number. But based on what we see at the moment, and this has been corroborated by the operator, that we think later this year, that reversion will occur.

And Denbury has been fairly specific about that as well, and of course, as it relates to them, the production that we pick up is production that they admittedly say that they're going to lose, and they've been pretty transparent about it because it affects their financials, not as much as ours but in a different way. So I think we just need to leave it at that.

Sterling, I'm glad somebody read that efficiency report. I think Stephane finally feels vindicated that all that -- those long night's doing some intense number crunching is actually -- you made it worthwhile for him, so I thank you for that.

All right. Well, good.

Well, we do read a lot of stuff, and you've also got the F&D study, too, that we follow pretty closely. I think it will be coming out here pretty soon.

Yes, you'll likely look real good on that one, too. You'll like that report and definitely, when this reversionary interest kicks in, in the Delhi Field, I don't think anyone should be able to hold the candle to you in terms of that debt adjusted production growth per share metric either, so I think you'll take the top slot in the calendar Q4 on that metric for sure.

So my question for you is just a little bit more on just the screening and economics. If you did decide to move forward, and I think most E&P companies, that would be their first course of action is, "Okay, where are we going to redeploy this cash to get those production bars higher in our slide deck here?"

But it's interesting to hear you guys, I'm not surprised, talk about buybacks and other ways of creating value. But if you do go that route on the project side, just curious to hear just if anything right now stands out as a great way to create value and just what that screening process looks like for you guys.

Thanks for the question. I think to a certain extent, this kind of points at what we've done in the past, which is that we try to stick to areas that we have an area of confidence in and knowledge in, so we're also very careful that whatever we do, we don't bet the company on that particular avenue that we take.

We did get involved with a shale gas project in east Oklahoma a couple of years ago, back when gas prices are up around $10, $11, $12. And we were careful to make sure that our project worked at $5 gas.

Well, of course, gas flew through $5 pretty quickly, and even though we thought we're being pretty conservative, the project really didn't make a lot of sense, it wasn't sufficient, equally economic, at $3 gas. So we shelved it, but it didn't cost us that much.

We didn't bet the company on it; we didn't go out and borrow $100 million and buy leases and go out and just drill well after well without regard of the economics. We were very measured, and we've cut our losses early on.

In south Texas, that project, we thought had great upside potential, very oily. Technically, it has done exactly what we thought it was going to do.

It is making oil at the rates or more than what we originally had projected. We're very pleased with that.

We didn't risk a lot of money though. We didn't bet the company again, and now we're -- we made that non-core for us because we're really -- the project looks like it is about a 3- or 4-year project in order to create value, and that's just outside the timeline that I'm willing to put a lot of capital into.

So again, we've cut our losses on that one, even though it's successful. But it's not successful if it takes you longer than you want to get that value.

So we're looking at some projects, some ideas. Obviously, Mississippi Lime was our first -- our most recent one.

The jury's still out on that. We're still working on -- we're still on the learning curve, but we still have high hopes for it.

It has got great potential, but once again, we're not going to bet the company on it. We're not going to tie our future to that working and not working.

We're taking a very measured approach. Our total capital exposure at this time is still in the single-digit million-dollar exposure.

If it works, we can still rapidly grow that, if we so desire. But we're being very careful about it.

We are looking at some other opportunities, and plus, we have the GARP thing, which we think has got great potential. I couldn't tell you today if it's worth a lot, but I think, in the future, it has the potential for being very significant.

So we're working on that. And then we're looking at some other ideas as well, but they're all within our particular wheelhouse of competency and interest and experience.

We're not going to be in California. We're not going to go build well sites on the sides of hills and forests in Pennsylvania.

We're going to stick to areas that we know, and we're going to do it in a very measured way.

Yes. And Mike, we had a slide and it's not in our presentation, I don't know what happened to it.

It's our screening criteria. But I think, on the current presentation on Slide 19, we talked about Mississippi Lime and what some of the field selection was.

That talks about many of those screenings. One, horizontal drilling is something that we would prefer.

It's not required -- onshore U.S. is required.

So we're looking for known resources, something that's successful, has running room, repeatability, engineering-oriented, not geophysical-oriented. Those are kind of some of the things that we look at.

And of course, then, we have screening criteria for economics if we -- some of those other things. So we're kind of looking at it operationally first before we start screening out the economics, and how it's going to be financed and so forth.

One of the things that Sterling mentioned earlier, I think, is a good description of what opportunities are -- we think may be coming up. And that is that there's a lot of opportunities being developed by companies that really stretch themselves out financially, both with debt and in lease terms and declining primary terms, and we think that's going to create some opportunities for people that are capital-wealthy to come in at a fairly reasonable cost into the establish development areas.

So that's an opportunity.

Yes. I agree with you on that, and thanks for the color.

My follow-up on it would be just taking a step back and looking at the GARP technology from just a higher-level view. Just what do you think is -- if you could -- I don't know if you want to quantify or qualify the ultimate potential of this technology, do we just talk about what inning we're in right now in terms of actually realizing this potential?

How long do you think it will take to actually get there?

Boy, we think the sky's the limit. There are thousands of horizontal wells being drilled every year.

This also, as a technology, can work on vertical wells. What's going on out in west Texas, where you have multi-reservoir completions that are being co-mingled, long pay sections, deep wells that you can't put artificial lift down below 9,000 or 10,000 feet effectively.

And then, of course, the horizontal wells. You immediately say that your target is the top 1 or 2 quartiles.

That's still probably approaching 1,000 wells a year, I would think, just in the U.S. alone.

So we think this is tremendous potential. Now obviously, there is going to be growing competition.

There's going to be other technologies going to come around. There's other ways of trying to do this that the industry has used.

And it's going to be an education process. We believe that the GARP works and of course, the key is to show other people that it works.

And that's part of the education process we're going through. It's a steep learning curve.

We think that we're making good progress on it, and over the next year, we expect to see a fairly rapid commercialization process, but we've got to do that. We've got to perform.

I mean, it's going to be something that's going to take a whole lot of work, effort and attention and so to speak, love by the people that are doing it. I mean, they've got to really believe and push it, and I think that will make it work.

A couple of housekeeping questions on Delhi. Can you guys remind me what your share of CapEx is for fiscal 2014?

Fiscal '14, well, our CapEx exposure, obviously, will start once reversion occurs, and so I suspect that -- fiscal '14 goes from July 1, '13 through June 30, '14, which, again, Denbury is on a calendar year, so calendar '13 CapEx probably will be pretty much mostly done by the time reversion occurs. So our exposure will be -- will happen in calendar '14.

So our share of what gets extended there will be some 24%. So 24% of calendar '14, we think, it's probably going to be somewhere around $18 million -- say, $15 million to $20 million so that's during the full calendar year.

So in terms of fiscal '14, it'll be probably some amount less than that.

Well, and I think, too, that upper number, $20 million, would indicate like a $80 million spend, and I don't think -- I think that's a little high for them. I think, on gross, they're spending $40 million to $60 million probably, right, per year.

They'll just take 1/4 of that. And then the timing issue, to which fiscal year falls in, you just have to adjust it.

But they tend to spend more in the front of the year and are done well before the end of the calendar year.

But what's, I think, the key issue is that we have in our hands today the financial resources to meet all of those CapEx obligations at Delhi for calendar 2014. So we don't even need to generate any more cash in order to meet our obligations.

And obviously, once reversion occurs, our cash flow will skyrocket and vastly exceed any CapEx obligation.

Great. That was helpful.

And then, when do you guys expect that results from the remapping of the field will be available?

As soon as they're made available to us. We don't control that.

That's something that Denbury is doing. We're hopeful that it will be done in a timely fashion.

We are hoping that it will be included in our midyear report, and we don't control that process.

Great, okay. And then with summer right around the corner, do you guys feel confident in the additional cooling capacity that was the result of Denbury, at Delhi?

Daryl, you want to answer that question?

Yes, they're underway fixing those cooling problems, and they should be finished by now. It's May so that should be finished.

This is a slight follow-up. We do know that they're doing some turnaround maintenance work in April, and that probably had some impact on production, just while they're doing routine work in the facility there.

Thanks again to everyone for participating. Feel free to follow up by phone or e-mail for any clarifications.

Obviously, we're very pleased. We've had 2 record quarters in a row, and we're shooting for a third one.

And we look forward to talking to you. I guess, that would be in September for our year-end earnings.

Thanks.