Robert Herlin - President & Chief Executive Officer Sterling McDonald - Chief Financial Officer

Phil McPherson - Global Hunter Securities [John Lucentae] - CK Cooper & Co. Richard Rossi - Wunderlich Securities John Collar - Unidentified Company Norman Kramer - Kramer Investments

Good morning ladies and gentlemen thank you for standing by and welcome to the Evolution Petroleum first quarter earnings conference call. During today’s presentation all parties will be in a listen-only mode. Following the presentation, the conference will be open for questions. (Operator Instructions) I would now like to turn the conference over to Carole Cole. Please go a head ma’am.

Thank you, Larissa. Good morning everyone. We appreciate you joining us for Evolution Petroleum’s conference call to discuss results for the first quarter of fiscal 2010, which ended September 30, 2009. Before I turn the call over to management, I have to go over the regular items. If you would like to be on the company’s email distribution list to receive future releases, please call DRG&E office, and that number is 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 and that is www.evolutionpetroleum.com or via recorded replay available until November 19, 2009. To use the replay feature just call 303-590-3030 and the pass code 4181633. Information recorded on this call is valid only as of today, November 12, 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 may contain forward-looking information which are based 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 give no assurance that such expectations will prove to be correct. Such statements are subject to certain risks and uncertainties and assumptions which are listed and described in the company’s filings with the Securities and Exchange Commission. Should one or more of these risks materialize or should underlying assumptions prove incorrect, actual results may differ materially from those expected. Also today’s call may include discussion of probable and possible reserves or used terms like volume, reserve potential or recoverable reserves. SEC generally only allows disclosure of proved reserves and securities filings and these estimates of non-proved reserves or resources are by their very nature more speculative than estimates to proved reserves and accordingly are subject to substantial greater risk. Now, with that I’d like to turn the call over to Bob Herlin, Evolution’s Chief Executive Officer. Bob.

Thanks Carol. Good morning to everybody and thank you for joining us today. Sterling McDonald, our CFO is here as well as David Joe our controller. Sterling will discuss the financial results in more detail later in the call. I would like to highlight some of the key operating results and our plans going forward. First, you might expect that we are very pleased that CO2 injection has scheduled begin this week in the Delhi field Northeastern Louisiana. Last week Denbury resources announced that the Delta pipeline which transports CO2 from Jackson Dome to Delhi Field had been completed fully pressured up and ready to deliver CO2 to the field. We expect first oil response to occur by mid calendar 2010 from the first phase of the project, and we will immediately benefit from that oil production through our 7.4% royalty interest. Our net production will ramp up as injection is extended throughout the field over the next few years. It will further ramp up when our 25% reversionary interest kicks in after Danbury would seize revenues after operating expenses of about $200 million, which is far less than their actual capital expenditures. Now, obviously this week’s news is a huge milestone that we have been pointing towards and it’s a result of the extensive work and capital investment in the field and the project by Danbury. Another important result of this first injection in the Delhi Field is the potential reclassification of our substantial probable reserves there to prove reserves on or before the end of our fiscal year. We believe that with the new SEC rule that’s titled Modernization of Oil and Gas Reporting, reservoir engineers can consider relevant factors than assigning proved reserves to EOR projects. This includes taking into account current technology, results of field pilot test, EOR project in geologically comparable fields. Now, we believe the Delhi Field demonstrates all of these characteristics. Obtaining initial production response from the current CO2 injection in the field which is we expect by the end of our fiscal year will not only further support such a reclassification under the new rule, we would also support such reclassification under the current rules now in effect. We are also progressing in our other projects and believe that we could have a number of main programs to announce during the remainder of our fiscal year due to our capital program and other initiatives. As we mentioned in the earnings release this morning, we have begun development operations in our Neptune Oil project, the first part of which is in the Lopez Field in South Texas. In our first quarter we completed our first well to a total depth of about 2400 feet. We recently completed the drilling of a second well and we expect to have both wells in operation during this second quarter. A third well is scheduled to be drilled by the end of the quarter as well and these are conventional 10 acre vertical wells that costs less than $250,000 to drill and complete. Our plan is to utilize one of these first wells, at least on a two for aid basis for reservoir pressure of maintenance through reinjection of produced water. We expect these wells to initially produce 10 to 15 barrels of oil per day at a very low decline rate in long run. Going forward we expect over the next few years to drill up to 110 or more producers in the field. In our June ‘09 reserve report, the reserves associated with the Lopez Field were primarily in the probably and possible categories, bringing the field on production should upgrade a portion of those reserves in improved category and potentially upgrade possible reserves to probable and increase the overall amount of reserves. Furthermore, in the first quarter we increased our net acreage position in the Lopez Field by 14% to some 1710 net acres on very favorable terms, which potentially add 10 to 13 additional drilling locations to our original inventory of about 100 potential drilling locations. Additionally, we are pleased that our production volumes in the Giddings Field have remained steady if not increased despite our nominal cap expenditures over the last six months. Currently we have two wells on production and they all appear to have completed their initial period of steep decline. We exited the first quarter at the rate of about 380 net barrels of oil equivalent per day. Going forward this quarter and the following we expect to hold our production client to a fairly moderate level, if any, through normal production operations and planned work overs. Sequentially our production increased 11%, however this is in part due to reduced volumes from a significant well comparison because of a mechanical problem downstream of our well in our gas purchase area. That problem was corrected this summer and we got the Pearson back to a normal production levels for the first quarter. In fact that well has stabilized at a productive rate of 1.3 million cubic feet equivalent per day of high BTU gas which is a rate that is actually very close to where its initial production rate was back in January. This well is on track to substantially over produce our reported open reserves for that well. Now, as I mentioned, we are going to be performing some work-overs during the quarter, the current quarter in Giddings Field. This includes the installation of our proprietary lift technology on a second well and work-over of a currently shut-in well that would be our 11th producer if it went online. Our capital plan does not currently include the drilling of any new wells in Giddings but the stronger gas prices that we have seen recently may allow us to consider drilling, if any, through the industry joint venture type of efforts. The production from our Giddings wells currently is averaging 22% oil, 25% gas liquids and 53% of mostly rich gas. So, our blended prices is fairly reasonable. We averaged $33.43 per barrel of oil equivalent in the first quarter. Our cash flows from Giddings operations are covering our cash overhead in operations cost as well as funding small portion of our capital expenditures which is a process that we have said how long we wanted to be doing. We have brought leased operating expenses down the field to continue to improve our economics. During the fiscal first quarter lifting cost which include these operating expense and production tax on a combined per unit of sales basis was $10.95 and our depletion rate was $17.17 per BOE, which gives us a field income breakeven point of $20.12 per BOE. This compares to a field income breakeven point of almost $31 per BOE in last year’s first quarter and $29.74 per BOE in the sequential last quarter. The fiscal second quarter, sorry about all these different quarters, we are already benefiting from a water disposal well that we drilled and completed in the Giddings Field. We expect that to lower our operating expenses by about $40,000 per month. This would be partially offset going forward as we add new wells production in the Lopez Field and in Oklahoma as well as any unscheduled work-over cost that we don’t capitalize. The Giddings Field is also serving as a great test ground for our proprietary lift technology. In our last quarter we discussed and announced the reentering of the Vanilla number one well and the use of our technology. Vanilla had become incapable of further production on a conventional log term and therefore we installed our new technology which is a dual type of lift technology. Commercial production was successfully reestablished and fluid production has steadily improved ever since going with normal ups and downs of any new process. We are now installing this technology on a second well that we own a 100% of in Giddings Field and we should have results during this current quarter. Our next step is to attach that on a third party well in the Giddings Field and then we would take it to another fuel to demonstrate success in another formation. We have initiated discussions with another operator to install the technology in exchange for interest in production. In Oklahoma we are continuing our test program to upgrade a shallow multi-pay shale gas resources in the Woodford and Caney gas shale. As you might recall in our fiscal fourth quarter we are near the end of drilling of three test wells and reentering three wells on our acreage in Wagoner County. These were vertical test with wide acid hydraulic fracturing in a very shallow depth about 1500 to 1800 feet. We are pleased with the results which showed satisfactory initial rates of gas production from both the Woodford shale and the similarly build Caney Shale. Now, originally we weren’t even targeting the Caney. So its addition is surprising in very positive project, as it could potentially double our target resource at no more than the cost of second frac treatment. Our plans going forward in the very near term are to apply larger hydraulic fracs with proppant at this time in two wells to separately test the two shale reservoirs, the Woodford and the Caney. The goal is to determine their peak initial production rates and declining profile. We expect the results will allow us to design the appropriate development program, facilities and gathering system. Later in the fiscal year, with market conditions permitting, we plan to re-enter a well in our mid-depth project in Haskell County to begin similar testing of the Woodford and the Caney Shale reservoirs at depths between 4,000 and 5,000 feet. As I said before, our level of activity in Oklahoma is so much dependent on natural gas prices. We believe that our acreage there is 17,600 net acres hold up to 160 Bcf of shale gas potential with the development cost in the $0.80 to $1.25 range per Mcf, a cost which we think we’ll be able to effectively compete in the market. Now, with those operating results I will turn the call over to Sterling to talk about the numbers.

Thanks Bob and thanks to all of you for joining us today. I’m sure you have had a chance of review the earnings release we put out this morning. So I will just hit some highlights and some key metrics for you for the first quarter. As bob mentioned, our sales volumes have been very steady with the slight upward bias increasing 3% on a year-over-year quarterly basis due to additional drilling and work-over activity in Giddings. Unfortunately our industry has suffered from steep product price declines which you know, but in our case was a 61% decline year-over-year. Fortunately, for our shareholders our lack of indebtedness, stable production base and lean organization allowed us to absorb these shocks unlike some of our industry colleagues. More recently, our top line up tick sequentially from the quarter ended June 30, ‘09 both from increased volumes and increased product prices. Sequentially volumes were up 11% and product prices improved 7% resulting in a 19% improvement in top line sequentially. Looking forward we actually had our first fiscal quarter producing about 380 BOE net per day, and as Bob said we expect that we can see small production declines from our base level production in the second quarter, partially supplemented by some of our other activities in Neptune. So far our product prices have improved during the second quarter especially with respect to natural gas but we’ll see what December brings to bring us in line for an improvement in our fiscal quarter. Hopefully, we can also begin to harvest new production in Neptune although balanced only for a portion of the upcoming quarter we will be able to get some production online. On the cost side, we continue to bring down operating cost overhead and DD&A rates. However, we believe that most of our achievable reductions are behind us leading us into a maintenance mode to hold on to our continued progress that we’ve made. As an example, our lease operating expense on a BOE basis including severance factors declined 9% to 95 per BOE in Q1 ‘010 compared to $12.38 per BOE for the comparable year over quarter despite the addition of three producing wells in the interim. However, these reductions were minor compared to our historical LOE cost of Tollus at over $50 a barrel which we have since divested. Going forward LOE should reflect the cost savings from our recently completed water disposal well in Giddings where we expended $400,000 in capital to reduce monthly LOE by about $40,000 a month. We believe that’s a good investment. Of course these savings may be partially offset by increased operating cost, new wells we expect to bring online in the Lopez Field and in Wagoner County Oklahoma. I must add here the production at Wagoner will not result in revenue in the near term as we will be vending these two test wells to establish production profiles one in Caney and one in the Woodford. We are also keeping a tight reign on our G&A expenses, and the first quarter G&A declined 1 to 1.3 million compared to 1.5 million for the Q1 ‘09 period. We had a 15% reduction in full time employees year-over-year and reduced non-cash stock comp expense from $0.52 million or 36% of our G&A to $0.4 million or 31% of our total G&A. Sequentially, G&A was up slightly in Q1 over Q4 of last year. Although we believe we are on track in achieving our fiscal 2010 budget of $3.4 million of cash G&A. When combined with our non-cash stock expense budget of $1.94 million and allocations to capital expense we expect G&A to meet our $5.1 million total budget including our non-cash charges. This compares favorably to fiscal of ‘07 on both the cash and total expense basis, declining 5% and 14% respectively. In part settlement of the Delhi litigation during the prior quarters should positively impact G&A expenses going forward, less of course any remaining share defense cost we may incur among the defendants. At September 30, ‘09, our working capital was $6.6 million and we continue to be debt free. It’s the decrease in working capital of $1 million in June 30 due to investments of $1.1 million in our oil and gas properties, not including $0.1 million incurred related to recognition of ARO obligations. Other capital expenditures during the first fiscal quarter, 44% went to development activities at Giddings mostly the 400,000 for the disposal well that we discussed, 17% went to development activities at Neptune and 32% were devoted to development activities in our shallow shale property in Wagoner Oklahoma. Cash flow from operations was positive during the first fiscal quarter coming in at $324,000 including changes in working capital. This compared to $2.2 million of positive cash flow from operations in the prior year quarter almost all of the $1.9 million difference was due to a $1.8 million drop in revenues on the top line. For our shareholders we believe we have a learning combination, and as Bob will discuss a little bit in his closing remarks and as our corporate presentation points out, one, we believe there is sufficient upside for our shareholders based on the significant underlying asset values not fully reflected in our stock price. Not just at Delhi but also at Giddings, our Neptune oil project and our considerable running room in the Oklahoma gas shale project. Two, we are debt free. Three our investments are secure, we maintain our short term investments in secure and liquid guaranteed investment funds. Four, our cash flow and working capital should be sufficient to carry us to significant production we expect to come online in Delhi, and five, for the first time in a while we believe that the market is becoming more favorable to public companies over private ones. I mentioned this last point in our public vehicle, because I think it’s been overlooked in our evaluation. Today, we are seeing a continued tightness in the private equity markets while the public markets are tending to open up. For whatever the reason we believe evaluation premium should be placed on our publicly traded vehicle. That completes my comments and I’ll turn the call back to Bob.

Thanks Sterling. Before we start the Q-and-A session let me just reiterate that we are very pleased with our progress and we are confident in the strategy going forward that we set out. We have managed the company and we are managing the company to maximize share value over the next few years without unduly diluting or risking the value we have created today. I want to make sure you understand how important is to us. Our core projects in Oklahoma and in south Texas are in their early stage of value growth and we are always considering our options to maximize our transitional Giddings Field Assets. Delhi is well on its way to becoming a proved long term cash cal for us cash count for us, we also have other high potential projects on our plate that fit within our expertise and track record of success. Our focus going forward is to demonstrate the value of these opportunities while preserving our strong balance sheet and ability to fully benefit what we have created so far. While our capital budget appear small, it really does not reflect our continued effort to grow the company. On the production and development side we will continue to focus more on oil production while continuing to consider opportunities to maximize value of our gas assets. Our balanced portfolio of oil and gas projects as well as our low cost low risk inventory of drilling locations positions us to be quite flexible. With Delhi project to begin generating cash flow in about 6 months and production expected to bill in our Neptune project, we should be in an increasingly stronger financial position to develop our opportunities going forward. We are also pursuing joint ventures which can provide further flexibility and opportunity for growth. Anyway we are very pleased with our new phase of growth. Now, with that I would be happy to take any questions. Operator?

(Operator Instructions) Your first question comes from Phil McPherson - Global Hunter Securities. Phil McPherson - Global Hunter Securities: Few questions, we are surprised by the gas increase that’s nice, do you think you can kind of hold back constant through the remainder of the year, that gas production number.

Well, the reason for that gas production increase is as we said during the prior quarter our big well, the Pearson was adversely held down or suppressed by the downstream gas purchaser, they are having issues with their compressor on their main line and therefore limited our production. We have since gotten that resolve. We lost a few days this current quarter while we were installing our disposal well line and so forth, but that is now all lined up and ready in producing and, you hate to adjust so well by saying how good it looks or it’s not declining anything, but it’s a really strong well and we are very pleased with it. We are doing some other work-overs to its normal course of action. As you go through any kind of normal production operations. The other well that we drilled back in January Hilton-Yegua, we’ve known since day one that it had some obstruction in it, so that has held down rates. So we have got that schedule to be cleaned out. One of our better wells is the one that we have decided to go ahead and install the artificial lift technology to go ahead and get it back to a better rate. So, we have a number of things we are doing as to whether or not they have hold up production going forward. We are cautiously optimistic that they will, but these wells do have some decline and we are also always at risk of things out of our control, such as the downstream compressor going down or something of that nature. But, yes, we are cautiously optimistic Phil. Phil McPherson - Global Hunter Securities: Yes that’s great. And on the Lopez Field you talked about increasing your working interest, did you buy out partners or did you actually get more acreage, can you give us a little more color on that?

Sure. We turned off our leasing program last fall when oil prices were crashing, we just we are not going to buy any more acreage. We had already bought most acreage at the points that we are willing to pay and the remainder it said, well, now we really, really want a higher lease bonus or a better royalty or whatever, so we said fine, we are not interested. What happened is that a couple of months ago they came back to us and said, hey, we really would like to lease to you what we would take, and on that basis we were able to get terms or form where appropriate and reasonable for a lower oil price scenario since then oil prices have come back quite a bit. So, we got this extra 208 somewhat acres at a very favorable price compared to what we would pay for the original 1500 acres. Phil McPherson - Global Hunter Securities: And so, what is your working interest and net revenue interest in Lopez field?

It’s a 100% working interest, and approximately 79.7 or so percent net revenue interest. Phil McPherson - Global Hunter Securities: You talked about the wells coming on the 10 to 15 barrels what are you looking at and can you remind me of URs?

Yes. The reserve report that we have, when you look at both the combined probable and possible reserves it was about 28,000, a little over 28,000 gross barrels, about 22,500 net barrels to us, and that was based on the assumption of 10 barrel a day initial rate. Phil McPherson - Global Hunter Securities: And when you look at the Woodford, you talked about flaring these wells. Can you give us an idea of what would you model or think about going forward as far as LOE in the Woodford right now and are you guys far from infrastructure kind of talk about the cost involved to build an infrastructure on a development plan?

Sure. The way we look at the infrastructure up there is, it’s okay, what is the likely well density which right now we are assuming 40 acre spacing for vertical development, and what would be the necessary gathering system, what will be the cost of installing that and then divide that by the number of wells, and doing that combined with the drill and complete cost of the wells, it’s how we got that $180,000, $190,000 per well number. A portion of that is for the gathering system. There is a significant opportunity to connect into a major pipeline there for transportation, the amount of pipe that would have to be laid to get to that is not considerable at all, well within the economics and we assume all that into our overall economics. Well we are not at all concerned we obviously, there is a fair amount of capital required but then there is also a fair amount of capital involved in drilling 200 plus wells anyway. So, within this grand scheme of things it’s not an inconsiderable number relatively speaking. Phil McPherson - Global Hunter Securities: Liberty tells for pipeline is. They give away too much.

I just can’t remember we say that publicly. I mean ONGC is the one that’s dominant lines that area. So I don’t think it’s any grand secret that that is one of the lines that we would easily get a gas to and provide some transportation to market. Phil McPherson - Global Hunter Securities: Okay great. Well congratulations on a good quarter, it’s nice to see Delhi finally coming, when I review my notes I guess it’s been about 6.5 years since you acquired it, so, a long time waiting.

Well, you are right, its 6.5 years since we first bought it. I mean when we first bought that thing it was making, what, 18 barrels a day from six wells, it’s been 3.5 year since we did our deal with Danbury and so this project is a 3.5 year effort on their behalf that they have spent on the order of some $300 million or so to-date. So, it’s turned into a big project for them. I know they are counting on being able to book a big chunk of those 33 or so million barrels net to their interest and their fiscal year coming up. Phil McPherson - Global Hunter Securities: In 2010 or?

I mean we are all very pleased with it considering… Phil McPherson - Global Hunter Securities: In fiscal 2010 they will be able to book and not in 2009 right?

Correct. I mean I guess there is an argument that you could try and book it, using the new rules to take effect, but I don’t think they are going to do that, they are fairly conservative, I suspect they are going to go ahead and just wait for response later in 2010. Phil McPherson - Global Hunter Securities: And you guys would be like right on the fence about being able to do it in your fiscal year ending June 30, just depends on the time.

Well, like I said in my remarks we think that we have two different ways of getting it to approve category for us by the end of our fiscal year either under the new rule as it is, or under the current rule just on the basis of production response. So, we feel constantly optimistic or cautiously optimistic that we will get a book in some portion.

Your next question comes from [John Lucente] - CK Cooper & Co. John Lucente - CK Cooper & Co: Just had a couple of questions; you drilled one well already at the Neptune project, and I mean where you are and completing it or in terms of production. But I mean do you have any kind of results from that well?

Well, keep in mind that these wells are in field wells within our field and the reservoir that produces a lot of water. So you can’t just completely produce, okay, we are going to start producing because you got to have a home for the water. You don’t want to hold water, it’s far too expensive. So, going forward what you do is you drill a couple of producers and you drill a disposal or a injection well to go with it to mainly maintain the pressure in the reservoir. So although we had the first well, there is not much you can do with just one well we had to have at least a second well which is what we have done, and so, now that we have two wells we can actually put one on production, one on injection and start to generate production from the field. So, I don’t have any. So, I don’t have any results to tell you right now, but everything we have seen so far is in line with what we expected. John Lucente - CK Cooper & Co: Alright, in terms of the EURs, I think you said it was 22,000 barrels per well from the reservoir part of your end, and I certainly remember it was about $300,000 in PV ten value per well if you just take the average. I think it was like $8 million per 25 wells, just using those metrics, these perspective locations that you have is it pretty uniform over the entire field?

Our expectation will be somewhat uniform, obviously wells will vary around the main, depending on where you are on the reservoir, you are higher, you are lower, you are thicker, you are thinner and so forth. Yes, we are pretty much expecting fairly uniform results, the way we would produce is we will produce a number of wells to attain batter on a lease, and so, we’ll actually track individual wells to production test once a month, so we’ll actually collect production on at lease basis. This field produce some 32 million barrels of oil historically from 380 wells that works out to about 80,000 barrels per well originally on 10 acre space. The operator back in the 70s drilled approximately 11 in-field wells down the 5 acre space and which is what we are doing. Well, obviously it looks like what we have and those wells produce on the order of 50,000 to 60,000 barrels per well. We are not saying we are going to get 50,000 to 60,000 but getting 28,000 gross barrels seems imminently doable and on that basis it’s highly economical. Like you said $8 million PV 10 on just 20, actually four of those locations were reentries and 21 were infields and those 21 infields were like 7.5 million net PV-10, and so, okay, 21s were 7.5, we’ve got another 90 or so, 80 or 90 locations, actually like 9 locations to drill on top of those 21. So, you could add that up and it’s what four or five times that 7.5 million with PV-10 based on $67 collateral price. John Lucente - CK Cooper & Co: Okay. And now the 10 barrels a day; I mean what was the difference between the wells that produced that were on 10 acres that produced 80,000 or 85,000 somewhere around there, and wells that were, the infield wells that they drilled that produced 50 to 60, did they come in similar IP rates or was it declined different what was?

Declines are the same; the difference is the infield wells didn’t get the IP plus productions that the original well has got. This originally was 21 gravity balls sitting on an ocean water, and the original wells got the benefit of that flush solid oil production infield, we already had water moving into and throughout the reservoir. So they came starting off at a fairly high water cut, and so if you look at a typical decline curve on this type you have a high initial drag and then a long low decline, the infield wells would come in at that long low declines, the lower IP rate, and that’s the difference between the two. John Lucente - CK Cooper & Co: What do you need to do to prove this up, you talked a little bit about it before, but in terms of how many producers do you need to prove how many wells will each producer potentially prove up I guess.

Well, keep in mind that when we first looked at this and leased an interpreter engineer we didn’t have any of our own wells. The only thing we can show are wells that were drilled and completed back in 1970s and that actually was 30 years ago. So as you might expect and the engineer said, well that’s all nice and well and good, show me that you can do it in current market, current cost, current everything and then I will take a lot more seriously. So that’s what we have to do is we have to demonstrate what we think and have said, actually demonstrated we can do it at the current cost, and that’s what the engineer is going to be looking for. Now, how many wells did that take, I couldn’t tell you. You were obviously planning on having about three wells this fiscal year which may scale up depending on results and other factors. But, we feel pretty good that that would be a good start to get the engineer on board to start calling this substantially proved. John Lucente - CK Cooper & Co: Okay alright, and then just, I know you talked about this technology that you have for getting oil out from I guess underneath the pump or in the section of the Giddings wells, I know there is another company out there what they do is they put soap or I guess soapy water into the well and it displaces the oil and then they pump it out, is it something like that or?

No, it’s totally different. Putting soap in like that or surfactant, that’s a common approach. What you are trying to do there is lighten up the fluid and allow that fluid to be moved more easily by the amount of gas that’s bubbling up. That is a little bit of good in terms of getting more covering up, but what we are doing is actually kind of a dual lift system, where we are actually mobilizing fluid through from the lowest spot in that horizontal well bore up to the point that the rod pump is located. Because you only think that rod pump is down so far you can’t put it into the curve. So we are actually able to capture an extra couple of hundred feet of vertical difference which doesn’t sound like a lot but it actually is, you can get considerable additional reserves and we are targeting 20,000 to 40,000 BOE per application. Again, that in fact is a huge number but when you consider that the cost is as well as it is, that’s in the order of say $5 per BOE total cost. But it’s totally different, it’s something that we have actually put in the patent application and that application is that part is pending.

Your next question comes from Richard Rossi - Wunderlich Securities. Richard Rossi - Wunderlich Securities: Yes. First just a couple of statistical things, I missed your field break even at Giddings, you said it is a little over $23, but I had missed what the fourth quarter was?

You missed what Richard? Richard Rossi - Wunderlich Securities: What the field break even was at Giddings in the fourth quarter.

It was $28.12 per BOE. Richard Rossi - Wunderlich Securities: Great. And the other thing, what was that Delhi litigation cost in the fourth quarter that shift the G&A line?

Well, that’s g to be; well I’m still having issues with this computer. Richard Rossi - Wunderlich Securities: And then I have just a couple things on Delhi.

All right. Go ahead he was looking that number up. Richard Rossi - Wunderlich Securities: Okay, you start to see production at the end of June, certainly ‘011, any idea of what are you looking for and how fast the ramp up we see, and when do you think you might get to your working interest your 25% working interest?

Well, the first thing you would have to do and its last one first, because it’s a lot more fun number. First what we do is we look at our Galior Magnotten (ph) report and one that they did for us for the fiscal year end and on their calculations using a flat $66.67 oil price, the pad occurs in the year 2014. Danbury’s plan of attack has accelerated over the last year and it appears according to the plan they filed with state that they will roll out the whole project over a three year period. So, they will have the full flood installed in the year 2013 or so it appears. So production should ramp up accordingly to reach a peak level probably by the year 2014 I would think. And that peak grade is in the order of 10,000 barrels a day growth. So, 7.5% over ride means that we would be netting 740 barrels a day from our over ride in our over ride alone, and then another 2000 barrels a day from our backend working interest. Richard Rossi - Wunderlich Securities: Okay, Sterling did you have a look at?

I would send that off. Richard Rossi - Wunderlich Securities: We can do it offline, we can do it offline then.

I can tell you right now that it was probably on the order of about 200,000 to 250,000. Richard Rossi - Wunderlich Securities: That’s fine, that’s all I need, I wanted a general size.

A good 26, this is the fourth quarter.

This is the fourth quarter, does that include settlement?

It’s everything.

It’s on top of that, the $30,000 settlement. So anyway, it’s some 228 for the quarter of legal expense, and that’s not all.

Yes, that was mostly litigation. Now, as you might expect we are ramping up, there are a lot of third party charges, while our legal charges related to getting ready for going to trial as you might expect you have to play the whole game all the way through.

And there was Rich, about 50,000 shared defense cost that hit the books in this quarter. That may be the end of it. We made a comment that that should go away except for any third party cost that we might share, but I think we are fairly well done with that too. You are saying all in all about 450.

450, I think was our total resolved that over a three year period.

It really was a bargain given that our counsel was so plugged in over there, went to school with the right parties, played tennis with the right parties, it didn’t affect it, I don’t think but it didn’t hurt us and our billing rate over there was $1.75 an hour which is unheard of in Houston. Was up in your neck of the wood, $1000?

(Operator Instructions) Your next question comes from John Collar – Unidentified Company. John Collar – Unidentified Company: My first question relates to the artificial lift technology. I was wondering if you were unsolicited interest from other parties or how you are going about sort of letting people know that you have this?

Well the first thing we are doing is we are soliciting interest because this is not something that we are broadcasting in detail to industry yet. What we are doing is we are talking to those people that operate similar way and therefore would have an interest, and yes there is interest and yes we are in conversations with those folks. John Collar – Unidentified Company: Another question, and I know you have an awful lot on your plate, but it seems to be that you have got based on our presentation you made earlier in this release that there are several phases of Neptune I am wondering if you’ve identified other areas if I am misreading that.

No, you are not misreading that. Neptune refers to a series of opportunities, the Lopez Field is just the first of those that we have actually initiated leasing in fuel operations. Yes we have the other targets as well that we are moving forward on in a very deliberate manner. John Collar – Unidentified Company: Okay. I am guessing that I don’t want to get too much information. But I am guessing still you have a fairly long run away you don’t need to move immediately on those or you will loose them, right?

We are not concerned. Again, this is a project it’s very economic, very profitable, but it’s not sexy, it’s not drilling a Balkan well for 1500 barrels a day, of course it’s a 1000 barrels tomorrow and 500 the day after. But still you get to make a PR release about a huge IP rate. And so, we don’t have a lot competition for this kind of a project. We are perfectly happy to drill 10, 15 barrel a day wells and capture 30, 35% 40% rate of turn on it.

Your next question comes from Norman Kramer - Kramer Investments. Norman Kramer - Kramer Investments: I had another question about Lopez and Neptune also. Is it just a candidate possibly down the road for CO2 flooding?

I would suspect that in the future, and the future means over the next 50 years. All of these fields are candidates for CO2 because they are going to be looking for places, it’s a clustered CO2, and obviously the best place to put it is in a reservoir that might actually get you some serendipity value through an increased oil production. Yes, you are correct these are excellent candidates for CO2 flooding. At this particular depth in Lopez field it would be an admissible flood because the pressure wouldn’t be high enough to allow admissibility to occur, but you would still get a benefit. But, yes, you could stuff a whole lot of CO2 in that reservoir and you would mobilize additional oil out of the ground. So yes, you are correct those are the good candidates. Now when it’s going to occur is another issue, because with CO2 the critical issue is the transportation CO2, getting the CO2 where it is produce to where it needs to go.

And management there are no further questions at this time. Please continue with any closing remarks you may have.

Well after all of this, and these are good questions, I think we covered our situation and I would like to thank everybody for joining us this morning and feel free to join us in any of our conferences coming up in the next quarter thank you very much.

Ladies and gentlemen this concludes the Evolution Petroleum first quarter earnings conference call. This conference will be available for replay, you may access the replay system at any time by dialing 303-590-3030 and entering the access code of 4181633. Thank you for your participation you may now disconnect.