Robert Herlin – President and Chief Executive Officer Sterling McDonald – Chief Financial Officer Lisa Elliott – Senior Vice President, Dennard Rupp Gray & Easterly

Phil McPherson - Global Hunter Richard Rossi – Wunderlich Securities Richard Feldman - Monarch Capital

Welcome to the Evolution Petroleum second quarter earnings conference call. During today’s presentation all parties will be in a listen-only mode. Following the presentation, the conference will open for questions. (Operator Instructions). I would now like to turn the conference over to Lisa Elliott, Senior Vice President of DRG&E.

Good morning and thank you every one for joining us for Evolution Petroleum conference call to review the second quarter of fiscal 2009, which ended December 31, 2008. Before I turn the call over to management, I have a few items to go over. If you would like to be on the company’s email distribution list receive future releases, please call DRG&E’s office at 713-529-6600, and someone will be glad to put you on that list. If you wish to listen to a replay of today’s call it will be available in a few hours via web cast by going to the company’s website at www.evolutionpetroleum.com or via recorded replay available until February 24, 2009. To use the replay feature call 303-590-3000 and dial the pass code 11126478. Information recorded on this call is valid only as of today, February 17, 2009, 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 contain forward-looking information which is based management’s beliefs as well as assumptions made by and information currently available to management. Forward-looking information includes statements regarding expected future drilling results, production and expenses. Although management believes that the 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, uncertainties and assumptions including among other things oil and gas price volatility, uncertainties inherent in oil and gas operations and estimating reserves, unexpected future capital expenditures, competition, governmental regulations and other factors described in the company’s filings with the Securities and Exchange Commission. Should one or more of these risks materialize or should underlying assumptions prove incorrect, actual results may differ materially from those expected. Today’s call may also include discussion of probable and possible reserves or use terms like volume, reserve potential, or recoverable reserves. The SEC generally only allows disclosure of proved reserves in security filings and these estimates of non-proved reserves or resources are by their very nature more speculative than estimates of proved reserves and accordingly are subject to substantially greater risk. Now I’d like to turn the call over to Bob Herlin, Evolution’s Chief Executive Officer.

Thanks Lisa good morning to everyone. I’m glad to have to here with us. I’d like to start with introducing Sterling McDonald, our CFO, who is with us today and will be talking about some of the more important numbers that were filed in our Q and also in our press release. We did release our fiscal second quarter results this morning earlier, so we’ll just go over a few key things from that release. I will be talking about the operating highlights with you today. Now revenues for the second quarter grew by 58% over the same quarter of last year. The good news is that our production was up by 250%. Unfortunately, it was offset by 52% decline in realized commodity prices, which includes oil, gas, and gas liquids. We produced 26,000 barrel of oil equivalent during the quarter at an average blended price of $39.78 per barrel of oil equivalent. That production in this is approximately 26% oil, 29% gas liquid and the balance is residual natural gas. The actual prices realized for each of these components was $57.37 for oil, $30.63 for gas liquid, and $5.82 per MCF for gas. Obviously the growth in all of our production came from our operations in the Giddings Field in Central Texas. Last year in the same quarter 85% of our revenue was from production in Louisiana, our Tullos Field. We sold that field in March of ’08. So 85% of our revenues from that quarter of last year have been replaced. In December of ’07, we commenced our Giddings Field horizontal drilling program and first production began from that operation some time in late February of ’08, so all the production that we’ve generated has all been within pretty much the last year. Sequentially on a quarter-to-quarter basis, our revenue was down from the $2.9 million that we reported in our first fiscal quarter of ’09. Again that’s due to the decline both in prices that we realized as well as from our initial production from the wells that we drilled last spring. That was a normal and natural decline in the Giddings Field, and we didn’t offset those by drilling any new wells that came on line during that quarter. As we’ve stated before repeatedly in our filings and our press releases and presentations, horizontal wells at Giddings Field tend to have high initial production rates but decline very rapidly and stabilize at a lower rate typically through the addition of artificial lifts, gas lift or pumps. Five of the six wells that we drilled and two wells we put on production in calendar ’08 are now all in that stable production phase, and total gross production from those wells is about 240 barrels a day equivalent. We have one well that is currently shut in, and that’s pending installation of pumping equipment. We own 100% of the working interest on these wells, and our average work revenue interest is about 80% in all those. Our average net daily production during the second quarter was 290 barrels a day equivalent, which is the same is about 360 barrels oil equivalent gross production. Now we began our 2009 drilling program in late November by starting of the first of our two horizontal re-entries in Giddings Field. In mid January, we completed that fist well, the Hilton-Yegua, in which we drilled a new vertical section from 3000 foot depth to a total vertical depth of 10,500 feet and then we drilled a horizontal section of about 3000 feet, all within the Austin Chalk formation. Now the Hilton-Yegua has really substantially exceeded our expectations on production. It actually has the highest initial rate of oil pressure of any well in the history of our company. On the first full day of production, it flowed about 4 million cubic feet per day of gas with 237 barrels of oil and condensate. As I mentioned before, these have a high initial decline rate. The average rate over the first 8 days versus gross production rate was about 3 million cubic feet a day and 146 barrels. Now due to the need to have to re-drill most of the vertical section where we started at 3000 feet, drilling and completion cost of this well totaled about $2.2 million. In late January, we completed the second well in the Giddings program, Pearson #1, which was a re-entry, with a horizontal rig of about 3500 feet within the Georgetown formation. That was the same total vertical depth of 10,500 feet. On its first full day of production, we produced about 1.25 million cubic feet and 48 barrels of oil. The nice thing about this well was it maintained that rate over the next 8 days. The 8-day period rate was same as its initial day rate. Since we didn’t have to re-drill that full vertical section, the total cost for Pearson was approximately $1.3 million, far less than the Hilton-Yegua one, but still it was a number than what we expected for drilling because we actually encountered higher pressures in the reservoir, so this was a good news/bad news situation. We have approximately 80% net revenue interest in the Hilton well and a 78% revenue interest in the Pearson. Again, we own all of the working interest in those two wells. Now the second well, the Pearson, having such a high rate is very positive for us because we have 5 grassroot wells that we have leased in that same immediate area, so it’s a very positive indicator for those locations. Now due to the drilling results, our production in the third fiscal quarter was substantially higher than our second quarter production. Since these wells typically produce a large portion of reserves quickly, however, we really don’t think it makes a lot of sense to keep drilling these wells during this period of low commodity prices. We are cautiously optimistic that commodity prices are going to improve over the next year, and we will be able to start drilling again in the Giddings Field. Certainly we are limiting our capital spending, and we are focusing what we do spend on projects that will add proved reserves at a particularly low cost. We want to be playing to our financial strength, and we want to avoid having to raise equity capital that’s going to dilute our shareholders at these depressed stock prices nor do we want to raise debt and be forced to a very high interest rate or all the more restrictive covenants that are being seen in the industry these days. Our balance sheet and working capital position continue to be very strong; however, since we don’t know how long all this is going to last, we want to be very conservative in outlook. Our 2009 capital budget calls for us to spend up to $10 million, and we’ve spent about $6.8 million of that so far. Our plan and the focus of our staff is to build intrinsic value per share. We’ve also leased 8 acres during those quarters that we think is going to add additional reserves. That was down in south Texas. In Oklahoma, our shallow Woodford shale project is an example of what we’re trying to accomplish with lost cost reserves. We have some 17,600 net acres there, and during the second half of fiscal ’09, we are planning to drill up to 5 very low-cost vertical wells within the Woodford Shale to a depth of about 1500 feet in order to essentially quantify that resource into proved and probable reserves. The Woodford shale is very shallow, the area that we’re drilling, so we can use air drilling, a much cheaper way of drilling through a formation. In fact, we think we can get these wells drilled and completed at a cost of less than $150,000 per well. We’re going to pursue vertical development there because of the low cost per well, and we think that we’ll end up developing these. There acres are anywhere from 10 to 28 per spacing, so you can see that our acres position will generate a lot of drilling locations. The other event is that we think we are going to be able to develop these gas reserves at a very low cost per MCF. The acreage in this shallow area is offset by over 50 other filled completions that are producing in the Woodford by another operator. We are following the results of those wells, and so far they bear out our belief that this is a very commercial area of development, the Woodford gas shale reserves, at a very low price. We have a second area at the Woodford Shale that is a little deep at about 4000 to 5000 feet. Initially, we would be planning on using reentries to keep our well costs down and test it. There is a very successful well there that’s been producing for about a year and a half now, came on line at about 1 million cubic feet a day, and after over a year of production, it’s still lot of 600 MCF a day rate, suggesting so far that it’s going to make about a BCF of reserves and that was a fairly short while ago, so we’re very encouraged in the potential of that acreage. Now in our new moderately heavy oil project in Texas that we call Neptune, we’ve got about 1500 acres leased, net acres, which is the bulk of what we’ve targeted. Subjective to oil prices, we plan to drill up the three infill wells this year at a depth of roughly 3000 feet. Again these may be low-cost vertical wells, with drilling completion costs of somewhere in the $200,000 to $300,000 range, with includes water disposal. Now, we believe that the historical results of infill drilling in the fields during the mid ‘90s will confirm that these are proved reserves for us. Not only is the infill program an attractive project for us, it also appears to be an attractive vehicle for us to apply the technology that we adapted over in Louisiana and tested in our Tullos Field before we sold it. The technology is designed to allow us to generate additional oil production at lower water rate. This is for heavier oil reservoirs that have substantial contact with water. There are a lot of reservoirs along the Gulf Coast that became too expensive to produce because of this water production, and therefore these fields that have been abandoned with substantial oil left in place. We believe that this technology can help reduce water production and make these fields profitable again. Now regardless of the outcome of this technology, however, this project we believe will be a very attractive on its own merit just an infill drilling operation. Last but certainly not least, I would like to update you on the CO2 project at the Delhi field. Denbury, the operator, remains very committed to and very active in keeping the project moving forward and on schedule. They are in the final stages of completing the CO2 pipeline in Delhi and continue to state that the first CO2 injections are scheduled for sometime in the first half of calendar ’09, with first production roughly 6 months following that which slices first production response sometime around the end of calendar ’09 or shortly thereafter. Our 7.4% overriding and mineral royalty interest should generate substantial cash flows to the company beginning with the first material production response, and there will no associated operating cost to us, so the revenues from that project will fall straight to the bottomline for us. Now we fully expect Denbury to aggressively roll out the CO2 flood throughout the field given the vast amount of money they’ve invested in the project to date, and as a result we fully expect to realize our 12 to 13 million barrels of potential reserves there within a few years with the first booking of proved reserves within the next year. I’ll now turn it over to Sterling to review some of our financial results.

As Bob mentioned, I’m just going to point out a few items in the financials and take your questions on anything that isn’t clear in the Q&A session later. It’s not my intention to read out the press release to you, but we look forward to your questions. Starting, I’d like to say that in our last conference call for the prior quarter, we stated that our principal strategies at that time are, one, to maintain liquidity and cash flow and, two, to continue adding the intrinsic value per share. That continues to be our creed, so I’d like to focus first on what we’re doing with liquidity and then a little bit about earnings with that before we go on to the second point of adding intrinsic value. If we look at our liquidity, for the six months of 2008 in the prior year, our cash flow from operations was $1.3 million provided. We’ve also got in the company what we call as adjusted cash flow, which is basically cash flow from operations before changes in operating assets and liabilities or, if you will, before changes in working capital. That would bring cash flow for the six months from $1.3 million unadjusted to an adjusted negative $300,000 was provided before changes in working capital which we view as financing activities and not what’s happening to the core of the operation at any point in time. Of course at that time, for those six months, virtually all of our production was from our Tullos field. In the first three months of that six-month period, Tullos was the only thing that we had and then followed by some production late in the second quarter of ’08 coming from the beginning of our Giddings production. If we look at our six months ’09 and contrast that, our cash flow from operations unadjusted was $6.4 million positive. If we look at our adjusted cash flow before changes in working capital, the core of our operations provided $1.2 million in cash. All of this came from Giddings, and about $3.6 million came from an income tax receipt from recoverable taxes from a prior year as we discussed last quarter. Basically we had excess IDC last year in the 2008 year, and we were able to carry it back to a taxable gain that we had at Delhi in 2006 and 2007. If we look at six-month period, of course the first quarter of ’09, our cash flow was about $2.2 million. Adjusted cash flow though was about $4.2 million. This was based on advancing production, and we had expanded pricing going on at the time. Compare that to the second quarter of 2009, our unadjusted cash flow was $4.2 million, but our adjusted cash flow from the core of our operation was a negative $400,000. The decline from $4.2 million to negative $400,000 was due to decline in production combined with depressed pricing at that time. So if we look forward to Q3 ’09, what are we to expect? Well, as Bob mentioned, we’re going to be advancing production over Q2. At the same time, we may have depressed pricing that is going to tend to offset that. Any recovery in pricing obviously would help us, but we would see that any burn in our operation we expect to be diminished. If we look at this on more of a global basis in terms of what has the company done to date since inception, I went back and took a look at our adjusted cash flow before changes in working capital and before changes and deferred tax liabilities, and the number I came up with was that we burn about $2.5 million in cash over the period. I think about $2.2 million was the number that I got, and interestingly enough that was mostly interest expense or could be attributed to about $2 million plus of interest expense over that period, so basically what this shows is that we have continued to not burn cash at the corporate level over and beyond our cash flow. This leaves us with currently about $7.6 million in working capital, which is down considerably from our working capital in the third quarter, so where does that capital go? For the 6 months of fiscal 2009, we’ve invested $6.8 million in oil and gas properties, which is over half of our fiscal 2009 capital budget of $10 million, and we’ve used about $0.9 million to repurchase the company’s common stock. Throughout both periods, the company remained debt-free. Our net loss in the Q2 ’09 was about $1 million, or $0.04 a share, compared to a net loss of $770,000 in the comparable Q2 ’08. Our results for Q2 ’09 include about $1.1 million of non-cash charges relates to stock-comp expense, depreciation and amortization, and accretion of asset retirement obligations compared to about $0.6 million of comparable non-cash burden in Q2 ’08 quarter. Let me take a minute to discuss the ceiling test potential in the future. We had no ceiling test brought down in the current period. Basically, we have no cushion at this point. We expect that if prices at March 31st would be 10% for all products below those of December 31, 2008, that we would have a non-cash write-down of about $2.6 million. Of course, that assumes that we don’t have additional reductions in capital expenses related to the significant improvement and development reserves that we have in the total cost pool. Any dollar reductions in capital cost would be a dollar for dollar reduction in the amount of write-off that we might have due to declining product prices. Operationally, in addition to the 58% revenue growth discussed by Bob earlier, our lease operating expenses declined 72% over our prior year to $12.54 BOE, and this is due to moving from our Tullos operation to our Giddings operation where operating costs are much less. Sequentially LOE was only up slightly from $12.35 in the fist quarter to $12.54 in the second quarter. Our G&A expenses increased 7.5% to $1.7 million in Q2 ’09 as compared to $1.5 million in Q2 ’08. Our higher overall compensation expense for estimated bonuses and new staff including non-cash stock expense accounted for the majority of the increase. The staff is associated with build up of our infrastructure to executive our drilling program, and G&A expenses for Q2 ’09 includes non-cash stock compensation expense of about $0.6 million compared to about $0.4 million to the prior comparable period. Netted for non-cash stock compensation expense, or cash G&A if you will was flat between the two periods. As we look forward relative to our working capital and our liquidity, we’ve got advancing production in this coming quarter to support our working capital. We also note that under the current legislation that’s being passed in Washington that additional recoverable income taxes might be in our future. Small company can now carry it back for five years, instead of two years. These will leave the window open for gains that we still have from our Delhi 2007 and 2006 gains and the $15 million of proceeds we took in 2006 has been depleted through carry-backs. Some of the $35 million of proceeds we received in 2007 has been depleted, but much of it still remains. Moving to our second point of additions to shareholder value, as Bob mentioned, we’re looking at increasing shareholder value in two ways, first by using our working capital to make smaller incremental investments in areas such as our continuous resource play in Woodford and to pick up larger slots of reserves. The same strategy applied in a different way is also underway at our Neptune project in South Texas. We also consider bringing in partners on our projects in Oklahoma and Texas in order to accelerate the development with the ultimate goal of increasing share value. Secondly, although we have current plans to repurchase more common shares, we retain that option as another way of looking at our capitalization in order to increase value to our shareholders and as our changes in working capital may allow us to look at that option again. That completes my comments, and I will turn the call back to Bob.

Before we go to the Q&A, I just want to go over one or two points. We believe that we have an opportunity to continue adding lot of value and quality assets at very low costs throughout calendar ’09, and because of our substantial working capital and the fact that we have no debt, no near-term material expiring leases, we can pretty much control our need for cash. We don’t really have to go out and raise capital to continue our efforts and program and carry through as we realize these projects. In some of the conversations I’ve had with folks over the last month or so, we got the question why did we do all these other projects and why did we spend the capital that we had at that time. It kind of flows into are we really more that just a call option on 12.5 million barrels of net oil. I would like to point out that we’ve used about two-thirds of our capital that we got from that sale to Denbury and used that to create substantial amount of proved reserves, probable reserves and value in Giddings Fieed that we think even in current prices is a least worth about $1 a share. We’ve also developed a tremendous resource play in Oklahoma that we think expose us to hundreds of BCF of gas reserve potential that we’re going to move into proved category over the next year or so. We’ve developed our south Texas project that we think is going to allow us to add 1 million barrels oil depending obviously on oil price and allow us to extend that to an opportunity, and in addition to all that, we still have Delhi sitting right there which is not driven by oil prices, not driven by drilling success. It’s really driven by time, meaning completion of that CO2 pipeline which is nearly done, the first injection of CO2, and then first production response. So this is just time-driven value creation. So these are all the elements I really think the shareholders should keep in mind. With all that, I want to thank you for your time this morning, and we would certainly welcome any questions that you have.

We will now begin the question-and-answer session. (Operator Instructions). Our first question comes from the line of Phil McPherson with Global Hunter. Phil McPherson – Global Hunter: Nice work on the quarter in these tough times. Just a couple of quick questions. Sterling, on the balance sheet, it says $9 million in cash and $1.5 million in certificates of deposit, but in the press release you said you had $8.5 million in cash or something like that. Can you just clarify that?

The balance sheet shows $8.5 million in cash and 1.5 in CDs. I’m looking. Sorry, what’s your question Phil? Phil McPherson – Global Hunter: Did the press release $8.5 million or something, or is there any reason the certificate of deposit is not considered cash?

It’s a technical accounting issue. It’s not considered cash and cash equivalent because it’s not negotiable and it’s over 3 months; however, with most of these, we’ve worked out that we have no pre-payment penalty to duck out, so it was a question as to whether we out to keep it in cash, but it still a short-term asset. Those are earning about 2.5% to 3%. They’ll mature by about the end of the year. There are insured under the $250,000 limit which is said to expire at the end of this year, although my expectation is I don’t think everyone is going to have the guts to really expire it. I’d also like to point out we’ve got another $300,000 CD in the long-term asset at the bottom of our asset list there. It is $300,000 or so of cash, so it’s about $10 million all together.

Operationally, in Woodford, you said that you want to drill 6 wells for about $1.5 million, so you’re just going to drill verticals at about $250,000 a piece. Is that what it works out to?

Actually it is five wells in Oklahoma and three in south Texas so that’s a total of 8 wells for a total of $1.5 million roughly. The five wells in Oklahoma we think are going to cost us somewhere in the $120,000 to $150,000 range, so these are real cheap wells. South Texas is a little bit more expensive because we’re at 3000 feet. You have oil hammering the equivalent and water hammering and so forth. Phil McPherson – Global Hunter: The South Texas stuff is in the Neptune field, right?

They’re not Neptune fields. They’re Neptune project. Phil McPherson – Global Hunter: First on the Woodford, are you spreading these wells at across your acreage trying to lock up and hold acreage or what’s the game plan there?

That’s correct way of looking at. We are truly trying to accomplish two things; one is hold as much acreage as possible with those wells. The second thing is that we want to demonstrate the commerciality across the whole acreage. Our acreage is actually fairly confined. It’s not like it’s spread over a vast area. It’s pretty solid, but still we want to spread out and demonstrate that all the acreage is commercial and that we can develop reserves at a very low cost. We’re targeting about $1 an MCF. We figured at $1 MCF in find and development cost, we can make money at current gas prices. Phil McPherson – Global Hunter: Are you at liberty to tell us what counties you’re drilling in?

Sure. The real south one is in Wagoner County, and in the deep, we’re in Haskell. Phil McPherson – Global Hunter: I assume you’re just using one rig and run and gun and get them done real quick?

These are like one-day wells in Wagoner. It’s 1500 feet. You can probably measure it in hours. Phil McPherson – Global Hunter: Would you expect these wells to contribute to your third quarter fiscal production?

We won’t get any material production now of any drilling that we do between now and June 30. We won’t get any material production in fiscal ’09 from that, and even the shallow wells, the biogenic gas play, at your initial max rate, they are going to come on at 20 to 30 MCF a day and then they’ll increase over a couple of months to their peak rate which may be 70 MCF a day. They don’t decline precipitously like the simple coal gas shale well. They’ll maintain that rate with a very low decline and last for ever and ever. Phil McPherson – Global Hunter: How deep are we drilling here? About 2000 to 3000 feet?

1500 feet on average in Wagoner. In Haskoll, it’s 4000 to 5000 feet, and that’s more thermogenic typical gas shale type production; however, the difference there is that at 4000 or 5000 feet, the backpressures are still very moderate to mild. You don’t need the real fancy hydraulic fracturing equipment. We can still air drill, at least the vertical section as a whole. Drilling costs are a whole lot less. Rig requirements are a lot less. It’s also an area that is not as heavily fractured, so we don’t expect that we’re going to have to create any size mix and help guide our drilling process. Phil McPherson – Global Hunter: Of these five wells, how many are going to be the shallow or how many are going to be the deeper?

All five of those will be in the shallow area, and that’s for fiscal ’09. I don’t realty anticipate that we’re going to do anything in Haskell until after the end of the fiscal year. Phil McPherson – Global Hunter: On the Neptune wells, can you tell us what the production you’re looking for and how that tails off?

We have a lot less information to work with there. Those wells historically, the infill wells, this is a field that was originally developed. I think about 20 acre spacing, and then in the 90s, they came in and they did handful of wells on 10 acre spacing and they were able to average about 25,000 barrels per well—very solid numbers. So even at 25,000 barrels, depending on oil price, we think that this is very economic program just on its own face. Now with the technology that we are going to apply, we are hopeful that we can generate higher reserves. If we do get the higher reserves, it goes from being a nice little project to a great project, but it depends on the technology to work. Phil McPherson – Global Hunter: Each of these wells is 250,000 or maybe a little less?

We have a little less certainty on that number because we just haven’t drilled one of those yet. On the shallow wells, we have already done a lot more scoping work on that and we have a better idea. For every couple of producing wells in south Texas, we’re going to have to have an injector. You have to factor that into your cost, so well costs are actually going to be a little less, but you have to factor in the cost of the share of an injection well. Phil McPherson – Global Hunter: You are still below $10 a barrel on an S&D basis, something like that?

Well, I wouldn’t want to say that. I would say we are in that $10 to $15 range. $40 oil is kind of a dividing point for me in terms of how aggressive I get with that project, and I don’t think that we are going to see oil below 40 on a long-term basis, and this is a long-term project. This is kind of like a gas shale project; drill all your wells in 6 months or a year; it’s a 5-year project. Our Neptune project is very similar in characteristics.

Our next question comes from the line of Richard Rossi with Wunderlich Securities. Richard Rossi – Wunderlich Securities: Just a couple of questions: I know these wells aren’t terribly expensive, but have you seen cost coming down over the last six to nine months?

We have seen cost come down considerably in our drilling activity in the Giddings Field. Our rig rates were actually dropping while we were drilling. We are fairly confident that if we were to drill another well at Giddings today that our rig cost would be substantially less, and all the related costs have come down as well. As far as what we’re going to be doing, we haven’t actually bid out the numbers. We’ve done from ASP investigations in order to get the numbers to do our planning work, but what we now is that the services that we’re going to be utilizing are not services that are in demand for the only really hot drilling area left in the industry, which is Haynesville. Even then, I’m not sure we would really call it hot, might get warm. We are fairly confident that we will get the lowest possible prices on services that we need, yet we are seeing a substantial decline, and when I talk with my opposite numbers at other oil and gas companies, I’m hearing the same thing, that they are starting to see substantial reduction in costs. Richard Rossi – Wunderlich Securities: On the G&A side, your non-cash comp was 30% to 35% of G&A. Is that what you think it will be running at going forward?

I want to state two things. First of all, I still think this is a start-up company. We’ve been around now for 5 or 6 years, but in order to bring on quality staff from established companies, I had to offer them something more than just a salary. That will include having a piece of the action going forward, and so I used options and I’ll go in more to restricted stock as a major components of that compensation, but that compensation vests typically over a 4-year period, each of those awards, so as you can imagine, we have a fairly high amount of that non-cash stock compensation expense running off over a 4-year period, and so the current level is a level that we will maintain, but it will be dropping rapidly over the next two to three years, and awards going forward will be more along the lines of restricted stock in smaller amounts so that the amounts we add on will be far less, so it is a number that will be running off rapidly.

The remaining number is about $4.2 million. It runs off in 2.8 years. Richard Rossi – Wunderlich Securities: 2.8, did you say?

Yes. Because of the way the company has been formed, the higher expenses are probably in the front of that period and declining at the end, until it gets to zero. Richard Rossi – Wunderlich Securities: Are there any significant technical issues left for Denbury to finish up that pipeline?

I’m not aware of any. To the best of my knowledge, they have all their permits. The bulk of the line has been laid. They are just finishing up, I think, one remaining small section. They have made every indication to me that there is no hitch and that everything is on schedule as planned to get the pipeline completed in the second quarter of calendar ’09. So I’m always looking to hear what other people hear when they talk to Denbury obviously, and so I’d love to hear anything else that you might even have.

(Operator Instructions). Our next question comes from the line of Dick Feldman with Monarch Capital.

Solid quarter and good strategy. I have a question about Oklahoma. How does your acreage, I think you mentioned something like 17,600, break down between the shallow area and the deeper zones?

There is about 9300 acres in the shallow are, which is the Wagoner County, and 8300 acres net in the Haskell or the deeper area. The 9300 acres we anticipate drilling the vertical wells on 10 to 28 per spacing. In the Haskell area, that’s going to be more like a horizontal development, and that’s going to be anywhere from 40 to 88 per spacing. Of course, in the Barnett, they are down to 20 acres on their horizontal wells.

Potentially, that’s a lot of wells, particularly in the shallow acres, and you think you could do half the deeper well or is that too high?

That’s too high. I think you need to scale that back, to about maybe 200 MCF per vertical well in Wagoner. That would be a much more realistic number based on an IP of 50 to 70 MCF a day and then shallow decline. Keep in mind that we are talking about a well cost of less than $150,000, so that’s why we are cautiously optimistic.

You also mentioned one of the things that you were considering would be bringing in a partner, and I wonder if you could explain your thinking.

Obviously it’s a big project. 400 wells times $150 is still a big number. 100 horizontals in Haskell times $1.5 million is a big number, and is it better for us to go ahead and bring in a partner to accelerate it and instead of it being a 5 or 6-year or 7-year program for us to make it a 2- or 3-year program? We are always evaluating what is in the best interest of our shareholders. I’ve made no secrets to anyone that this company is set up and designed around the concept of adding and generating value per share with the goal of some sort of monetization in the not too distant future, not too distant being 2 to 5 years. We’ve never set this company up as one where we are a long-term EBITDA growth story where people come in and say we’re going to value you at 6 or 10 times EBITDA. We are a company to be looked at as what is the value on a per share basis. That’s our goal, that’s our strategy, that’s why we’ve put cut back our drilling activity in Giddings. We want to maintain our value per share and keep it in the ground until we get more attractive pricing instead of producing and getting a low price.

In today’s somewhat depressed market, are you seeing new opportunities that tempt you to get into another region?

We are always keeping our minds open. We’re always looking. We want to make sure that everything that we do come together for our overall strategy. We don’t want to be in a position where we have apples and rutabagas. We want to have apples and oranges at the most. We want to stay in areas where we have a high comfort level that will keep us to all particular stream which are a project development, horizontal development, etc., so that’s what we’re focused on. We’re always looking, but we’re trying to be very disciplined in how we do it. We want to maintain our liquidity over the next two years, because we still don’t know what’s going to happen.

When will you report the results of the Okalahoma drilling?

Our goal is to get those wells drilled in fiscal ’09. Again it’s a biogenic play. Your gas rate is going to increase over time, so it may take until the end of the summer before we’re already to announce the results.

At this time, there are no further questions in the queue. I would like to turn the call back over to Mr. Herlin.

Thanks to everyone for listening in this morning. We appreciate your time. We look forward talking to you the next quarter. We hope to be trying some new things in the feature, videoconferences on line, and hopefully we’ll be talking with you about setting those up.

Ladies and gentlemen, that does conclude the Evolution Petroleum second quarter earnings conference call. You may disconnect at this time.