Lisa Elliott – DRG&A Robert S. Herlin – Chairman of the Board & Chief Executive Officer Sterling H.

McDonald – Chief Financial Officer

Phil McPherson – Global Hunter Securities Richard Rossi – Wunderlich Securities Joseph Dancy – LSGI Advisors, Inc.

We appreciate you joining us for Evolution Petroleum’s call to discuss the results for the third quarter of fiscal 2010 which ended March 31st. Before I turn the call over to management I would go over the regular items.

If you’d like to be on the company’s email distribution list to receive future news releases please call DRG&E’s office and that number is 713-529-6600, someone will be glad to help you. If you wish to listen to a replay of today’s call it will be available in a few hours via webcast by going to the company’s website and that’s www.EvolutionPetroleum.com or via recorded replay until May 19, 2010.

To use that replay feature just call 303-590-3030 and use the pass code 4197395. Information recorded on this call is valid only as of today, May 12, 2010 and therefore time sensitive information may no longer be accurate as of the date of any replay.

Today management is going to discuss certain topics that may contain certain forward-looking information which is based on management’s beliefs as well as assumptions made by management and information currently available to management. Forward-looking information includes statements regarding expected future drilling results, production and expenses.

Although management believes that 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 which are listed and described in the company’s filings with the Securities & Exchange Commission.

If one of more of these risks do materialize or should underlying assumptions prove incorrect, actual results may differ materially from those expected. Also, today’s call may include discussion of probable or possible reserves.

We use terms like volume, reserve potential, recoverable reserves. The SEC generally only allows disclosure of proved reserves on securities filings and these estimates of non-proved reserves or resources by their very nature are more speculative than estimates of proved resources and accordingly are subject to certain substantially greater risks.

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

Sterling McDonald, our CFO is here and will provide details on the financial results and answer related questions later in the call. Hopefully, you’ve had a chance to view the press release that we put out this morning and the numbers so we really don’t plan on going in to great detail on these opening remarks but will certainly consider any questions you might have later.

First, what I would like to do is update you on our operations out in the field. At the Delhi Field we continue to make progress and the second phase of a five phase field roll out of that CO2 based enhanced oil recovery project.

As previously announced in March the field averaged about 240 barrels per day of oil per day of gross sales even thought production began around mid month in March. Now, during April gross sales averaged an estimated 886 barrels per day in the field which is about 65 barrels a day net to Evolution.

All of that is going to our overriding royalty interest and all the production is coming from just the first few oil producing wells. Ultimately, the project is going to include over 200 wells, half of which would be producers.

We initially receive our revenue for the project through our 7.4% royalty mineral interest and those don’t bear any expenses and so the cash flow goes directly to our bottom line pre-tax. Once our 25% reversionary working interest kicks in which should be around 2013 or ’14, depending on oil price and production ramp up, we’ll than pay our 25% share of operating expenses while receiving an additional 20% of the revenue.

So we’re very pleased that the field development continues to progress ahead of the revised schedule from last fall and before our fiscal year end which should support a reclassification of a significant portion of those probably reserves at Delhi to improve category. Elsewhere we’re continuing our fiscal 2010 capital plan of testing our South Texas Neptune oil project and our Oklahoma shallow gas shale project while conducting a number of work overs in the Giddings Field in Central Texas for enhancement of production.

In Oklahoma, our focus during the quarter has been on testing the productivity of the primary Woodford Shale and the secondary Caney Shale in Wagoner County to determine the best completion practice and development plan. We’re testing the Woodford in two wells, one with a low level frac and the second without any frac at all.

We’re testing two types of frac treatment of the Caney Shale and our third well. Now, all of our gas production right now is being flared during these tests and not being sold.

The test of the low level frac of the Woodford which is at a depth of about 1,600 feet in our Henry well which is located at the western end of the leasehold, that well has already exceeded the 80 mcf a day target production rates that set at the beginning of the project some time ago. Actually, that well’s production rate continues to increase and we’re now past the 90 mcf a day range and continues to increase.

At this time we’re unable to predict exactly where that peak rate is going to end up because the rate continues to increase. This test is extremely encouraging in that it brackets our leasehold.

The Henry well, the production rates that I just mentioned, is on the west end of our acreage and we have another 100 wells that have been drilled by other operators on the east end at a much shallower depth so our acreage has been bracketed on either end by productive test for commercial. Testing of the Caney Shale continues as we work on the optimum frac treatment to determine the most economic method for adding reserves and production.

All together we own leases with about 9,300 net acres in Wagoner County so we have the ability to substantially build our possession there through the forced pooling that is allowed in Oklahoma. Now, keep in mind that these wells are very cheap to drill and complete, less than $200,000 each and we expect to have low decline rates and long productive lives at a development cost that is well below $1 an mcf from these wells.

Our goal of the project from the beginning has been to develop low cost reserves that can economically compete with any other gas source and our early results suggest that we’re well on our way to achieving that goal. In Haskell County, further south in Oklahoma, we own over 8,400 net acres.

We expect to reenter an existing vertical well during the next few weeks and test the Woodford Shale at a depth of about 5,000 feet and we’ll be applying a light frac in that well for that test. Back in South Texas in Lopez Field within our Neptune project, we’ve already drilled two producer wells and reentered a third well for conversion in to a water injection well.

Now, that water injection rate has been limited due to unexpected constraints around the old well bore and we’ve had to be limited to testing only one producer at a time. While oil production has started in that first producing well, we’re going to have to conduct additional testing this month in that well and in June in our second well to make sure we have a good valuation of the field, reservoir and just quantify that potential recovery.

In the Giddings Field, we are continuing to focus on well work overs to enhance production. Currently, we have 10 wells active in the field which during the quarter produced at a rate of 315 net barrels of oil equivalent per day.

This is down about 8% from our level in the fiscal second quarter, the preceding quarter and about 33% down from a year ago equivalent. Remember though, in January of ’09 we had brought two new wells on line that we had drilled and therefore we had that initial flush production and that included our best producer in the field.

With no new wells being drilled and completed for production sales during the last nine months, we have seen our combined production rate decline and then stabilize. This is partly due to work overs we have been doing in the field.

We did try to bring an 11th well back to life via a work over that had been dormant for several years on a lease that we had taken and that well pre-dated our ownership. On that same lease we had been able to do the same thing on another well and we were able to restore substantial production and reserves and today that well continues to produce in excess of 170 mcf today with minimal decline.

Unfortunately, that work over was not successful during the last quarter. Overall, we are actively working to close a potential joint venture to accelerate development in the field and hope to be drilling in that joint venture in the next number of months.

On a related note, we also continue to work on a joint venture to apply our artificial life technology. Our planning process for fiscal 2011 is just now underway and will be subject to the full results to our test work, completion of our ongoing joint venture negotiation, ace of Delhi production ramp up and any accelerated development decision by the board of directors.

Now, with that I’d like to turn the call over to Sterling to talk about the numbers.

I’ll just do a few highlights and our expectations for the balance of the year and going forward. One of the things I might add Bob on the production decline in the last quarter, that with all that work over activity we had going on on about a half dozen wells we had a lot of downtime in the quarter as well.

I don’t know exactly how that compares to the year earlier, I didn’t look at that data but it was a contributing factor. Well, we continue to see improvement in our results and we benefitted from higher oil prices with 43% of our production coming from oil and NGLs in the third quarter.

We saw revenues rise 11% despite our decline in production. We’re hopeful that oil prices remain attractive as production from Delhi Field builds.

While we recorded only $43,000 of revenue from Delhi during the quarter, based on initial production start up in the last two weeks of the quarter, we estimate recording $160,000 of revenue at Delhi for production during April. These flows should begin providing us with additional financial flexibility going forward building further on our already strong financial structure consisting of $5.3 million of working capital and no debt at the end of the most recent fiscal quarter.

This compares to $5.7 million of working capital at December 31st and $7.6 million at June 30, 2009. Year-to-date we’ve incurred approximately $2.8 million in capital expenditures, virtually all of which was dedicated to developing our oil and gas properties.

About 65% of our capital expenditures were apportioned to our proved concept test wells in our Oklahoma gas shales, our South Texas oil projects and our artificial lift technology at Giddings, 27% elsewhere at Giddings leaving only 6% expended for land and 3% for ARO. Of the Giddings amount approximately half was spent on a salt water disposal facility early in the year at the Pearson well, that’s our best well thereby dramatically lowering our disposal costs on a currently projected pay out of a little over a year on that expenditure.

On the cost side LOE was substantially higher at $14.12 per boe in the current quarter over an unusually low $6.88 per boe during the prior year quarter. The increase per boe was mostly due to the higher production volumes associated with the initial production in two new Giddings wells in Q3 ’09 and unusually high work over activity during Q3 ’10.

For the current nine month period LOE was $12.37 per boe versus $10.22 in the prior year’s nine months. This is more in the range of our $12 per boe bogie including production, taxes, marketing and indirect expenses.

G&A’s continued to decline due to tight cost controls and lower non-cash stock based compensation expense. G&A was down 25% over the comparable prior year quarter and down 22% for the nine months comparables.

This reduction was fairly across the board including lower staff, administrative and non-cash stock compensation expense. On liquidity, we continue to be debt free while cash flow from operations was positive during the third fiscal quarter coming in at $2.2 million.

That included a non-recurring $2.1 million tax refund from a tax loss carry back. Without it, we were essentially flat.

Looking forward, it’s our intention to begin reinvesting our increased cash flows expected from the ramp up of Delhi to further build shareholder wealth in one or more of our other current field prospects. As an example, we look forward to testing both of our Oklahoma Shale prospects and our artificial lift technology with a view towards showing solid proof of concept profitability at $5 gas prices which we believe should allow us to move in to full scale development.

Of course Neptune has its own set of possibilities and we look to possible joint ventures to develop our puds at Giddings as gas prices allow. Although we haven’t yet set our fiscal 2011 budget, we hope to fund a higher level of activity and escalate the development of our projects through joint ventures, project financing, financing from the capital markets and/or higher operating cash flow.

It should be an exciting time for us. We’re moving out of a period where we’ve consolidated our operations, Delhi is flowing and we look forward to developing our other projects.

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

With that we’re done with our prepared remarks and are open to taking any and all questions related to Evolution, the oil and gas industry and so forth.

On this huge increase in the Delhi production is astounding and I was wondering, last time we talked it was indicated that three wells were producing approximately 200 barrels a day so with this jump up to the 800 plus is that an increase in wells or is it actual production through those existing wells?

Well, the first thing I need to point out is that 240 barrels a day is based on a 31 day average however, those wells were only on for half a month so on an actual day rate of when the wells were on the productive rate was substantially higher than that 240 so it’s not an astounding increase necessarily, it is a steady increase. In terms of where the production is coming from it is still from the first couple of producing wells.

There are quite a few other producer wells in the test zone for phase I. I don’t want to go in to a lot of detail of operations because that really is the providence of Denbury and we’re subject to constraints on what we can talk about.

But, I think clearly everybody is very pleased with the level and pace of response today.

Maybe you might not want to answer this one but on your most recent presentation you talked about a first year average of 1,000 barrels a day. Is that a low ball estimate?

If we’re already at 800 is that potentially we could be higher than that or am I getting too excited about it?

Well, the numbers in my presentation are numbers that are pulled straight out of the DeGolyer and MacNaughton Report and those are not necessarily year one, two, three, four, five and so forth. Those are representative years pulled from years 2010 through 2015 I think it was.

That 1,000 barrel a day rate is reflective of the level projected by D&M towards the end of this calendar year. So in that perspective we are ahead of that report and that level of production.

Now, I think it would be not appropriate to necessarily try to expand from that and make some big jump on what may or may not happen. All we can say right now is that we’re very pleased, it’s ahead of schedule, it’s performing better than expected but production is going to be up and down as we steadily increase the roll out of the program.

You can get in to a lot of trouble with yourself trying to get too much information on a one month to next month level production. It’s going to be in bits and starts as we move forward but so far it’s just going very well, we’re very pleased.

Then you guys talk about the PV 10 of it and adjusting it for inflation and the tax holiday. When you book these reserves at the end of your fiscal year here in June will that PV 10 be adjusted then for the tax holiday?

It should be adjusted for the tax holiday because that was approved by the state last summer after our report had been done so we couldn’t include it in last year but it should be included in this year’s report. Obviously, the oil price it will use is going to be the oil price that is the average of the 12 months preceding July 1st.

On this tax holiday, does it ever get phased out at a certain oil price or does it not have any type of a trigger mechanism like that?

No, there’s no phase out of it Phil, it’s based on a project payout and the payout is defined, I can give you the code reference at the Louisiana statute, I can look it up here in a minute and give it to you before we get off the call but basically it provides that all of the production is exempt until the project pays out so it takes all of the capital costs and then allows a capitalized interest to be computed. That’s a pretty liberal capitalized interest number.

The last two years I saw, one was 14 something percent and the other was 8.5% so it was kind of a real wide cost of capital kind of looking number. Then that’s compared against all the production that comes out of the field.

I’d like to point out that that is an actual payout as opposed to our deemed payout, those are two totally separate numbers. The actual payout is what Denbury has actually paid on the project.

Our deemed payout is a fixed $200 million of revenues less direct operating expense and so our deemed payout is going to occur far sooner than the actual payout for purposes of the severance tax holidays.

This might be a silly question, I probably should know this but on an overriding royalty without a tax holiday would you be paying severance tax holidays on a royalty?

Yes. You pay severance tax on any production.

One last question and I’ll jump back in, I was writing while you were talking, you were talking about a JV that was progressing, was that in relation to the Giddings properties?

Yes. We’re working on several JVs, obviously some are further along than others but those are all to either accelerate our development activity in Giddings or to apply our artificial lift technology and it’s with multiple different parties.

I know that you guys would never take this type of risk but with all talk in the industry with the Eagle Ford and the Giddings area, is that bringing more people to the table to look at things because they’re interested potentially in that also?

I’m not sure I’m willing to speculate on the motives of people that are interested. The Eagle Ford is primarily to the Southwest of our acreage position.

It’s starting to creep closer to where we are and actually there is an expanded Eagle Ford play going on in and around our particular acreage that we have down in the far Southwest part of the Giddings Field. So I’m not going to say that at the end of the day we won’t be involved I’m just hesitant to make any claim that we have Eagle Ford potential right now.

It may at some point in the future but I think that’s real speculative.

I actually had one other one on the Woodford. I was kind of surprised that when you talked about the water production and incline of the production it almost sounds like a cold bed methane type of play.

Is that the kind of thought process as far as how that production would look during the incline period or was it always going to be like that watery or was this expected or a surprise?

This is very similar to a cold bed methane or a New Albany or [inaudible] play where you have to dewater the shale in order to lower the pressure sufficient for the gas to come off of the rock and out of the formation. So yes, this is all expected and in fact, the common wisdom is that the more water production you have initially the better gas well you end up with and that actually appears to be the case which is always nice.

This well started out at a very high water rate. That water rate has steadily declined and it’s down probably 30% to 40% water rate and while that water rate has been going down our gas rate has been steadily going up.

This is the first time I’ve ever experienced with a well that has an exponential incline. It’s hard to believe but that’s what we have right now.

Obviously, at some point it will level off but we just don’t know at what level it is going to level off and be flat at.

Usually the only down side with the water is just disposal. Do you guys have a disposal well already there that you can just reinject it lower?

Yes, you definitely have to have a disposal well. You couldn’t handle hauling water off, the cost would be too high so yes we have our own disposal well.

There was a bit of interference when you were going over the LOEs so I didn’t catch it all. I heard the $12 bogie and I was wondering did you talk about the work over costs specifically as how much they accounted for in the third fiscal quarter?

We did not. We could break that out for you but it was meaningful because we had five or six wells that we worked on over that period and that’s very unusual activity in any one period.

What’s the norm?

Well, for the nine months we’ve been at $12 and what I said is our bogie is that. Our bogie is actually –

I’m sorry, what is the norm for work overs?

Well, it depends, it depends on what you’re doing. I mean whether you’re having to pull everything out of the well, whether you have a beam pump and rods in it or whether you have gas lift on it and depending on what your remediation is it can run all over the landscape.

But, I can tell you that those jobs are about $40,000 average depending on the operation. $40,000 a month is what we spent for the last quarter in work overs.

That’s a little over $100,000 higher in this quarter.

You mentioned you’re obviously in various stages on these joint ventures or joint venture negotiations and I know there’s no finite time schedule but if I were to look at the end of the calendar year, would you expect to have at least a couple of those in place?

I would expect that we would have at least two in place by the end of the calendar year. At least on in the artificial lift and at least one for our basically a partial farm out in the Giddings field.

We have quite a few ongoing but it’s just like anything else, you have to have a lot of deals under way in order to get the best deal done in a timely framework. I think we’re pretty close on one of those.

Then remind me on the artificial lift the type of joint venture agreement you’re going for? I presume they’re all a little bit different but is there a share in the cost of doing a program or is the joint venture partner taking on the costs?

Well I first want to remind you what the overall process is there. First, what we had to do was to prove the technology worked to us.

In order to do that we had to do it on a well that we owned and controlled 100%; we’ve done that. The next thing to do is prove to someone else that it works and they’re not just going to say, “Okay, here’s 40 wells go do it.”

They’re going to say, “Prove to us it works on one or two wells and do it at your cost and then you get obviously a share of the well for doing that.” So that is the level that we’re at right now, how can we demonstrate it works to a third party and then once they’re convinced of that and demonstrate and have numbers to show it then we can say okay let’s go to the next level which is okay have a limited program of doing 10 or 20 or so wells.

Then, you’re sharing the costs and sharing the results. That’s the process we’re following and we’re doing it both in the Giddings Field and we’re also with multiple candidates and we’re also starting to look at doing this in other fields.

Is this in part a function in these early on joint ventures and the lift, is it a function of having to drag the people in to this because they’re somewhat reluctant to do something new?

Well, it’s a function of a lot of things. Keep in mind that the industry has been through a very volatile tough time and costs are tough, revenues are low and so forth and so they’ve been asking staff to do more with less.

A typical operating engineer may be looking after 100 wells, 200, 300 wells, he’s got rigs to look over, he’s got wells going down, plugging, he’s got all this stuff going on and he’s working 60 to 70 hours a week. He’s got to hit a certain target for costs and revenues and production.

So where we come waltzing in and say, “Hey, we’ve got a great deal. We’re going to help you but it’s going to take time and effort on your part.

We think it’s going to work. We can’t prove it’s going to work and the upside is down the road.”

He’s looking at it saying, “I’ve got a lot of priorities.” You have to work your way in, get their trust and confidence and show how you’re going to make it helpful for them so it’s a process, it’s an education.

It’s not something that you can just force your way in to and that’s what we’re doing right now. We’re trying to demonstrate why this is a good deal, why it’s going to be helpful for them and how can we do it in a way that makes it easy on them.

I think we’re well on that process. We’re getting there but it’s not something you do quickly, you can’t jam it in.

Let me add that on Phil’s question the statute in Louisiana is RS 47-633.4. That’s RS 47-633.4 and then we also have an exemption certificate that was awarded under a state order number 96G7 in July.

Phil covered most of what I was interested in but I did have a couple of questions on the Delhi Field. As I recall, the sensitivity of our returns to Evolution is high leveraged to the price of oil, is that right?

I think I saw something on your website to that effect?

It is leveraged to the price of oil but keep in mind it’s over an extended period of time so it’s not the price goes up or down tomorrow and next quarter doesn’t have an overall impact. What is important is what is the overall price of oil.

The other thing that I like to remind people is that even if you use a flat $66 oil price, which is what was used in our DeGolyer and MacNaughton Report, at a flat $66 oil price over the 25 to 30 year life of the project and before the severance tax holiday, the PV 10 it’s still on the order of almost $200 million which is $6 per fully diluted share. Even if you add in that severance tax holiday that PV 10 goes up by about 15%.

If you add in any kind of inflation, a couple percent a year it goes up another 20% or so, 20% to 30%. So yes, it is very sensitive to oil price however, even on a low level of expectation you have a very substantial value as is so the sensitivity is getting from $6 to $10, $12, $15 a share on Delhi alone.

Does that help?

On these wells also, once they start to ramp up and show some response, how long until they maintain their ultimate or maximum production level? I mean they don’t have a decline curve anything like we see in shale wells or anything, these are pretty consistent is that correct?

That is a correct statement. If you look at the overall project production is expected to ramp up over the next couple of years, actually peak production on our D&M report isn’t actually reached until 2015 or so and then is really flat for a couple of years and then you have a low level decline, maybe 10% a year or something along those lines.

So it is a substantial amount of oil production that’s very stable and very low decline for a long time. There is absolutely no comparison whatsoever to the typical shale gas well that you see in Barnett or Haynesville or Eagle Ford or something like that where you see a decline on a daily basis.

I want to tell you I appreciate you going out and speaking to the IPAA Conference to the institutional investors or whatever conference I think it was last month and posting it on the website. I think that’s very helpful for guys like myself trying to figure out what you are doing and where you are going.

Just a question on that, did you get any feedback from any of the attendees formal or informal as far as to your presentation and what they thought of the company and your strategy?

Well, I have to admit I really enjoyed the fact that even though I was the next to last speaker of the whole conference, that we had 55 or 60 people in the audience which is a high number. But, even more enjoyable was the fact that half of them followed me in to the breakout and filled the breakout room which is the first time that’s ever happened.

There were a lot of new faces that I’ve never seen and they were all asking lots of questions and furiously taking notes. So that was a very fun experience for me so I take that to mean yes, we’re getting a lot of new attention and people following us.

Obviously it helps that our stock price is over $5, it helps that obviously Delhi is producing and starting to increase so yes, it’s all a good experience for us.

One thing I might add, you were talking about our presentation, if you look at slide 30 of our presentation it’s showing PV 10 per fully diluted share. One of the things that I think people can easily miss is that our PV 10 actually increases until peaking at about 2015 before it rolls over.

We have a depleteable reserve but what’s going on here is that the 10% discount rates are being knocked off as the years go by, are over powering the more minimal depletion of the reserve. Kind of the exciting thing for is as time passes that PV 10 inclines without anything else happening.

At the same time, we’re getting cash flow off of Delhi that we can reinvest in some of our other projects to continue to build shareholder value through that means as well. It’s kind of a double accelerator affect that we’ve got in our favor here for a while.

I want to add that on our shale gas program, it is not a typical shale gas, we are playing a shale that is more like the [inaudible], it’s more like the New Albany, it’s more like a cold bed methane in which case we have a gradually increasing productive rate that’s probably flat for a while and then you have a slow decline which is another reason why we were entranced by this opportunity, that these are reserves that are stable and can build a company for productive rate. It’s not something you get on a treadmill and you have to keep drilling fast and furious just to maintain a level production.

Thanks everyone for joining us today. These kinds of conference calls are fun for us because we have good news to talk about and every indication is that we should continue to have good things to talk about over the next couple of years.

We’re pleased, we’re excited about what’s going on and with that feel free to call us and we’ll tell you again anything that’s in the public domain.