Lisa Elliott - DRG&E Robert Herlin – President, Chief Executive Officer, Director Sterling McDonald – Chief Financial Officer Lisa Elliott – Dennard Rupp Gray & Easterly, LLC

Neal Dingman – Dahlman Rose Richard Rossi – Collins Stewart Joel Musante – C.K. Cooper & Co. Richard Feldman – Monarch Capital Phil McPherson – Global Hunter Kevin [inaudible] – Kaiser Property

Welcome to the Evolution Petroleum fourth quarter and year-end earnings conference call for the fiscal year ending June 30, 2008. (Operator Instructions) I’ll now turn the call over to Lisa Elliott of DRG&E.

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 to receive future news releases please call DRG&E’s office at (713) 529-6600 and 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 web cast by going to the company’s website at www.evolutionpetroleum.com or via recorded replay available through September 30, 2008. To use the replay feature call (303) 590-3000 and dial the pass code 11119784. Information recorded on this call speaks only as of today, September 23, 2008 and therefore time sensitive information may no longer be accurate as of the date of the 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 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 estimated 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 with 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. Please also note that the press release dated September 4 put out by the company provided the company’s year-end reserves as of July 1, 2008 and contained reconciliation and definitions of CV-10 and probable and possible reserves. Now I’d like to turn the call over to Mr. Bob Herlin, Evolution’s Chief Executive Officer.

With me today also is Sterling McDonald, our CFO. Hopefully you’ve had a chance to review our news release that was issued this morning. Sterling will go through the numbers contained therein a little later in the call. First I’d like to point out a few of the highlights and review our operational results. To start with we are pleased to have reported net income for the fiscal fourth quarter ended June 30, 2008 and we believe we have now turned the corner on being profitable. Of course that is subject to future oil and gas price volatility and the price we have on bringing on new wells to replace normal production decline. In our fourth fiscal quarter we generated net income of almost $400,000 or a little over $0.01 per diluted share on revenues of $2.4 million. This is a very substantial improvement over the prior year fourth quarter of about $0.02 loss on revenue of about $500,000. The improvement in operating results is due directly to our drilling activity in the Giddings Field in Central Texas. Last year in the similar period our revenue was entirely from production in the Tullos field in Central Louisiana, plus our interest income of about $400,000. Since we sold our interest in that Tullos field earlier this year, all of our production since has been in the Giddings field. Sales volume in the recent quarter were about 18,200 barrels of oil and natural gas liquid and about 53 million cubic feet of natural gas or just a little over 27,000 barrels of oil equivalent. This is about 230% increase over sales volume in the fourth quarter of 2007 and 180% increase over volume sold in the third fiscal quarter of 2008 or the immediately prior quarter. Therefore, showing how much of an increase we have actually generated. In June of this year we completed the first phase of our development drilling program in the Giddings field. We brought on production the last two wells of our initial six well program. Five of these wells were re-entries into existing well bores where we drilled a new horizontal ledge within the Austin Chalk Formation, tapping into fractures that haven’t previously been developed. One of the wells was a grass roots location where we actually drilled a new vertical hole before we drilled out our horizontal leg. The six wells total combined for about 22,000 total feet of horizontal drilling section which was a little more than we had originally contemplated when we started the fiscal year with a 10-well program. That 10-well program was adjusted to a six well program and some of those six wells had multiple laterals. Our total program costs or drilling costs of $12 million turned out to be a little bit more than we had expected. This was due to higher costs of services and materials, unexpected downhaul mechanical problems in the re-entries and a little higher, actually extensively higher expected loss of drilling fluid within depleted fractures that we encountered. However, as a group the wells have performed about as expected. We have taken the information we have gained from that drilling and adjusted our second phase of drilling to incorporate that knowledge. Our goal, obviously, is to do better than expected in our next drilling program. I’d like to remind shareholders and listeners that among the reasons we targeted the Giddings field is that our team has extensive experience in this area. I led the drilling of 28 horizontal wells around 1990. Daryl Mezzanti, our VP of Operations and Eddie Schell, our General Manager of drilling have spent much if not most of their career working in that area. Although the Giddings field has produced over 1.25 billion barrels of oil equivalent today we still believe it holds substantial amounts of oil and rich gas that can be produced economically. We estimate that our drill and complete costs over the full program going forward is going to be in the neighborhood of $16-18 per barrel of oil equivalent. I should point out that Giddings production is not long lived production. It does generate good cash flows, however, and near term revenues and earnings which is appropriate while our Delhi CO2 project transitions into production in late 2009 and early 2010. Therefore, that Giddings field project is a real good balance to our Delhi long-life reserves and its slow and steadily increasing production profile as the various phases of Delhi are brought online. Again, by the end of June we had six of our drilled wells on production plus a seventh well that we had acquired through leasing that we restored to production through a work over. Due to the normal high initial decline rate and the fact that three of our newest wells produced only for a limited portion of that month including two of our best three producers, June 2008 production averaged about 580 barrels of oil equivalent per day gross. Net that is about 468 barrels of oil equivalent per day. We own 100% of that working interest in all of these wells. Going forward it is our intent to update the public and shareholders pretty much on a quarterly basis. We don’t do it on a well-by-well basis. When evaluating our Giddings drilling operations we really have the people focused on it as a program and not on an individual well-by-well result. We have seen in our first six wells and expect to continue seeing in the second phase of drilling a range of outcome; anywhere from poor to excellent results. As I noted earlier we learned from each of these wells and we applied that knowledge to improve the probability of attaining good wells and reduce the probability of getting poor wells. Each one is going to have its own production characteristics. In aggregate we are pleased with the results so far and look forward to our next drilling program. Within the Giddings field we have a total of 27 proved locations to drill in addition to the seven producing wells we have there for a total of 34 wells. This compares to the 12 locations we had at the beginning of fiscal 2008, or an increase of 22 locations total. Our goal in 2009 is to continue adding proved undeveloped locations while executing on our 10-well re-entry program. Now under SEC guidelines our independent reservoir engineer has assigned four million barrels of oil equivalent proved reserves to our interest in the Giddings field. Based on the substantial available production in offset wells, of which there are over 11,000 wells in the field, our independent engineer has further assigned 3.1 million barrels of oil equivalent of probable reserves to our interest, all as of July 1, 2008 for a total of over 7 million barrels of oil equivalent net to our interest. Now our proved reserves of 4 million included 2-4 million barrels of crude oil, condensate and natural gas liquids and 10.5 BCF of natural gas. Separate from all these reserves we internally determined that our interest in the Delhi field CO2 project in Louisiana totaled approximately 13.4 million barrels of net probable reserves. Now these are not eligible for a classification of crude reserves until the CO2 is actually being injected in the field and we have obtained a production response in the field. We think that this is going to occur some time in late 2009, possibly early 2010. Net crude reserves during the fiscal year increased altogether about 133% over the prior fiscal year total of 1.7 million barrels. This 2.3 million barrel increase is over and above replacement of reserves sold in the Tullos field totaling almost 700,000 barrels. This sale was in March 2008. It is also over and above our production during the year of some 60,000 barrels equivalent. As a result, our net crude reserve additions totaled about 3 million total barrels of oil and gas equivalent. In our news release of September 4 we reported that our CV-10 for our SEC crude reserves increased from 33 million or about $1.00 per diluted share at July 1, 2007 to $150 million or $4.83 per fully diluted share as of July 1, 2008. I really need to point out though that our NYMEX prices that we had to utilize on July 1, 2008 was $140 per barrel of oil, $84 per barrel of liquid and just over $13 per million BTU for gas. This was compared to July 1, 2007 prices of a little over $70 per barrel of oil and $6.80 per million BTU for gas. Our PV-10 calculations are net of capital expenditures of $62.5 million as of July 1, 2008 and $18.5 million as of July 1, 2007. Obviously commodity prices have come down quite a bit since July 1, 2008. We had our third-party engineers re-run the numbers using a lower price of $110 oil, $8 gas and $67 gas liquid price. On that basis the crude reserves CV-10 on an SEC basis came in about 38% lower at $98.6 million or $3.00 per diluted share. Before I discuss our CapEx plans for fiscal 2009 I’m going to turn this over to Sterling and he’ll review our financial results.

I’d like to also thank all of you for joining us today and please note that the financial information discussed today will be filed in our 10-K some time later today. One amplification on a point that Bob covered relative to our crude reserves increasing 133%, the 2.3 million barrel increase is over the replacement of 0.68 million. I think he said 700,000 barrels of crude reserves. Those all include not only the sales of Tullos, which was 400,000 and some barrels but also net of production and adjustments all totaling 680,000 barrels. Focusing on our financial results for fiscal year ended June 30, 2008, oil and gas revenues were up 128% to $4.3 million compared to $1.9 million in fiscal year 2007. Focusing on fiscal Q4 2008 oil and gas revenues were up more than 360% to $2.4 million from $500,000 in Q4 fiscal 2007. In fact, Q4 2008 revenues represented more than 50% of our total fiscal year revenue despite no contribution from our March 3, 2008 divested production phase at Tullos prior to the fourth quarter. Fourth quarter realized prices for oil were $130 and change per barrel, up about 111% from a year ago while natural gas was $10.24 per MCF and natural gas liquids were almost $65 per barrel. For fiscal 2008 realized prices were $99 and $0.03 per barrel, up 53% from last year, while natural gas was $9.67 per MCF and natural gas liquids were $63.02 per barrel. We had no natural gas or natural gas liquid sales in the fourth quarter or the full year of fiscal 2007. On a BOE basis, realized prices increased 40% from the prior year’s comparable quarter and 27% year-over-year. Our total sales volume in the fourth quarter including natural gas and natural gas liquids increased 230% to a little over 27,000 barrels of oil equivalent compared to about 8,200 barrels equivalent in the fourth quarter of 2007. This was accomplished despite the Tullos sales in the spring. Our total sales volumes for fiscal year 2008 increased 79% to 51,614 barrels of oil equivalent compared to 28,800 BOE in fiscal 2007. In terms of cost, lease operating expenses for Q4 2008 declined 9% to $284,000 while for fiscal year 2008 they were down 7% to $1.3 million. The overall decrease in lease operating expenses in 2008 is primarily due to lower monthly field expenses incurred over four months at our Giddings field as compared to the somewhat higher monthly field expenses incurred at Tullos over eight months. However, on a BOE basis lease operating expenses decreased 47% during fiscal year 2008 and decreased 70% in Q4 2008 due primarily to much higher production volumes at Giddings as compared to Tullos. ED&A expense increased $612,000 to $903,000 for fiscal year 2008 from $291,000 for fiscal year 2007. The increase was primarily due to much higher daily production volumes at Giddings over Tullos and a higher depletion rate of $16 versus $10 for BOE. The increase in depletion is due to the higher development costs of PUDs in the Giddings field that we added in replacement of our lower cost crude developed producing reserves from our properties in the Tullos field area. G&A expenses increased 22% to approximately $5.5 million in fiscal 2008 from about $4.5 million in fiscal year 2007. Higher overall compensation expense and new hires accounted for a majority of the increase. Please note that non-cash stock compensation expense was $1.8 million for fiscal year 2008 compared to about $1.6 million for fiscal year 2007. Thus our cash G&A expense was about $3.7 million for 2008. The additional headcount that is associated with the build up of our infrastructure to execute our drilling program in the Giddings field, G&A for fiscal year 2008 declined to $1.4 million from approximately $1.5 million in fiscal quarter 2007. Let me rephrase that. G&A for Q4 2008 declined to $1.4 million from approximately $1.5 million in Q4 2007. The expense of our higher headcount in the fourth quarter was more than offset by capitalization of personnel costs associated with our Giddings development activities. Interest income for fiscal 2008 decreased $1.1 million to $850,000 compared to $1.9 million of interest income in fiscal 2007. The decrease in interest income is due to lower available cash balances averaging approximately $20 million during fiscal 2008 compared to cash balances averaging approximately $36 million during fiscal year 2007. This was combined with a lower interest rate environment in fiscal year 2008 over 2007. The lower cash balance is mostly due to cash used to pay income taxes originating from our Delhi farmout to Denbury and investments of cash in our Giddings and Oklahoma gas shale projects. During 2008 we maintained our cash liquidity by continuing to void structurally enhanced investment vehicles, option rate securities and other questionable credit instruments, instead utilizing lower yield and U.S. government agency money market funds. As the credit market issues accelerated in the summer we moved again our investments. This time into U.S. treasury money market funds to avoid potential agency exposure. As an added level of liquidity we point out we continue to remain debt free. EBITDA was approximately $1.2 million for the fourth quarter ended June 30, 2008. This consisted of income from operations of $59,000 plus the following; DD&A $530,000, non-cash stock comp expense $480,000, net interest income of $81,000. This compares to negative EBITDA in the fiscal fourth quarter of 2007. Summing it all up we reported our first positive net income in the fourth quarter without the aid of a capital gain of $377,000 or about $0.01 per diluted share compared to a loss of $474,000 or a loss of $0.02 per diluted share in last year’s fourth quarter. For fiscal year 2008 we reported a net loss of almost $1.6 million or $0.06 per fully diluted share compared to a net loss of $1.8 million or $0.07 loss per diluted share in fiscal 2007. Our 2009 capital expenditure program is expected to be funded primarily from working capital and funds from operations with a part of the balance from other sources. We recognize that the world and U .S. economies are experiencing unprecedented capital market stress and volatility which makes us even more determined to live within our means. Consequently we may reduce our capital expenditures from our $19 million budget based on a number of factors including changes in the commodity price we expect to receive, drilling and production performance results from new and existing wells, unexpected changes in our working capital, insufficient joint venture capital and such other factors as we deem appropriate. We do believe, however, that any entrenchment will be brief, only serving as a bridge to reach our expected [annuity] from Delhi production which appears to be around the corner for the benefit of our shareholders. This concludes my remarks and now I’ll hand the call back to Bob.

A couple of weeks ago we announced that our capital budget for fiscal 2009 expected to be $19 million subject of course to commodity prices and drilling results, we expect to allocate about $3 million of that to leasing and $16 million to drilling. Now drilling activity is going to be composed of ten horizontal re-entries within the Giddings field and initial drilling in the Woodford shale in Oklahoma, plus up to three wells in a new development project in Texas. That program of $19 million compares to $21.5 million incurred in the prior year of fiscal 2008 of which $13 million was used in drilling and the balance in leasing in Texas and Oklahoma. Our first well will be drilled is expected to start within the next month and the program will consist of drilling 3-4 wells and then a pause to review results, incorporate the information gained and then commence the next set of wells. Again, initial rates will tend to decline rapidly as each well is independent of the others and well results will vary around a program mean. Austin Chalk and Georgetown reservoirs typically produce half of their reserves within the first two years or so and then produce at a much lower rate for another 10+ years. We expect to also initiate drilling in the Woodford shale in Oklahoma later this fiscal year. Originally we intended to start with a testing program to determine best completion practices and likely production rates. Now we have been fortunate in that other operators in the area are drilling and completing wells into the Woodford shale around our acreage. Some 50+ wells to date. The publicized results of those will provide us with a lot of the information we were looking for from those tests. Therefore we can pretty much skip the testing phase and go directly towards development drilling. At this point we haven’t quantified the projected gas reserves potential from our acreage. We do believe that our net interest position will eventually yield us up to 200 net drilling locations. Now we are still leasing in Oklahoma and we currently have over 17,600 net acres leased to date. Also in fiscal 2009 we anticipate drilling three wells in a new development project that is located in Texas. We really aren’t going into any details on that project since we are in the early leasing phase and we prefer not to disclose anything about that in a competitive leasing environment. It is an oil play and we will be applying leasing technology that we developed in the Tullos field, Louisiana. Our CO2 project at Delhi continues moving forward. After a little bit of a regulatory delay, Denbury has reported they have secured the permits to complete the second half of the CO2 pipeline in Delhi. They have acquired the necessary pipe and the construction is underway. They are also working in the field adding infrastructure and preparing wells to take on the CO2 and go out for production. They announced their plan to begin injection in the second quarter of calendar 2009 and anticipate that first production will be about six months after first injection occurs. I’d like to point out that Denbury has invested to date over $123 million in the project through calendar 2007. They have another $80 million budgeted for 2008, obviously a large portion of that has already been spent. Denbury has further quantified that its Delhi interest represents 33 million barrels of net probable oil reserves as engineered by their outside engineer. With less than three quarters to go before injection of CO2 begins and with future capital outlays of less than what they have spent to date, we think that a major delay or change of heart at this stage is highly unlikely so this is a project that is going forward. To date our company has demonstrated we have the ability to identify development projects and to implement those projects to grow shared value. We think that our recent financial results demonstrate that we are converting that value into revenue earnings and cash flows. We continue to develop new projects while maturing our existing portfolio and with a strong balance sheet in these quality assets and experienced staff we believe we can continue this success. Now with that I’ll be happy to take your questions.

(Operator Instructions) The first question comes from Jason Wangler – Dahlman Rose. Neal Dingman – Dahlman Rose: You did touch a bit on service costs and I’m wondering what you are seeing on costs now? Obviously what you have going on now with Giddings and two of the other new plays, will you kind of keep your I guess style the same going forward as far as contracting rigs or are rigs tight enough now especially with Giddings do you have to lock that rig in for awhile and I’m just wondering what you are seeing more on the costs there.

The service costs are definitely elastic to what is going on in the oil and gas commodity price but there is a time lag involved. Obviously we like to see service costs come down. We haven’t seen that yet. I anticipate they will as long as gas prices stay down in the $8 or $7.50 range. The type of rig we use for our re-entry program in the Giddings field is not the same rig that is in high demand, for example, up in the Hanesville play so we haven’t seen a lot of rig-on-rig competition. We are confident and actually have our first rig lined up and ready to go. We don’t anticipate entering into a long-term contract. We don’t think at this point in time it is a benefit to us or necessary and we like to retain the flexibility to try and reap maybe some future reductions in service pricing. Neal Dingman – Dahlman Rose: I know you all are always looking at a lot of different things with your staff. The market, obviously we are in a volatile commodity market, and I’m just kind of curious what kind of plays you are looking at? Costs out there you are looking at, are they still the same as they were three months ago? Are they still looking up? Are we seeing a lot of difference if you are looking at Giddings area versus your Oklahoma area? Are you seeing a lot of variance in sort of costs of different plays? I’m just kind of curious as to the overall M&A market as you are seeing it out there?

We are really not in the M&A market. Our mode of operation is to develop projects where we can acquire acreage at a low price. We don’t get into competing with other people in Hanesville or [Barnett] or whatever paying $15,000 or $20,000 an acre. We like to get in at much, much cheaper costs. I did allude to our latest project. It is an oil based project. It represents an area where we can acquire leases at a very low price and the price of oil that we need to be successful is far, far lower than current prices. So whether or not oil is $100, $110 or $120 or $90 really does not impact the economics. So we are somewhat indifferent in terms of going forward on these projects. Obviously it does have an impact in terms of what cash flows are generated going forward that we can use to fund projects but I think like a lot of people we have projected lower oil and gas prices in terms of tackling or estimating what kind of cash flows we have to work with. Neal Dingman – Dahlman Rose: As far as now when you are looking at sort of going forward on CapEx and where your stock is do you consider, especially given to me how cheap I think your stock is with some of your cash flow would you consider buying back shares or is it more you still see better return on some of your plays? I’m just wondering if Sterling has allocated some of the cash and what the thought process is there.

We are continuing to try to convert our kind of static reserve values into more dynamic production. We have looked at that, gosh our stock when we closed with Denbury our stock was down in the $1 range and we looked at it. We just don’t have enough cash to stock it all up and we’re going to continue our operating plan and continue…bear in mind we are just now turning the corner on earnings and cash flow and we need to make sure we see ourselves for the day of the Denbury annuity beginning. I think that is probably the most important thing for this year.

Another way of looking at it is obviously we read our stock prices as extremely discounted in the market. Let’s say it should be four times higher. So you buy a share of stock for $1 and it is worth $4 in our minds. Another way of looking at it from our perspective is okay in the Giddings field we invested $4+ million in leasing plus a year and a half of our time and generated CV-10 of proved reserves of $100 million. So that is a 15 or 20 to 1 return on investment. As long as I can take my cash and invest it and get those kinds of returns I’m going to do that as opposed to buying stock in the market.

Also, a follow-up on your service costs, Bob isn’t it true we are bringing back the same rigs?

We are using the same drilling rig that we used on three of our first six wells. This is a rig that is especially usable for re-entries and has worked for 20 years in the Giddings field. We traded this rig back and forth with a couple of people we know and hopefully we can keep it friendly out there and we can continue to have it when we need it and they have it when they need it. I checked on rig rates. As it relates to this particular rig our rate is flat. This coming development program we are beginning the rates are flat with what we experienced six months ago when we used this rig for our first play. We just checked with Eddie, our general manager of drilling, and apparently the deeper stuff the rates have continued to go up but that is now where we are focused at this moment.

The next question comes from Richard Rossi – Collins Stewart. Richard Rossi – Collins Stewart: Did you say that 13 million barrels of oil probable reserve at Delhi goes into proved late 2009 or 2010? Or we are just beginning to see some proved out of that 13 million barrels?

The terms we have at Delhi, the 13.4 million barrels are currently labeled through internal valuation to be probable reserves. It just so happens when we do back calculation that ties directly into the numbers that Denbury has published as being their net reserves as evaluated by their outside engineer. Under SEC rules and guidelines as currently promulgated, those reserves are not eligible for categorization as proved reserves until we have CO2 being injected and a production response which we believe will occur, both of those will occur by the end of calendar 2009. Now, how much of that is converted into proved and how much is retained as probable is going to be subject to what the outside reservoir engineer determines. We would expect and hope that the majority of those reserves will be classified as proved but that is going to be up to the engineer.

To follow up on that also you might be aware that the SEC has proposed new rules. We have actually made our comments as it pertains to reserve accounting and one of the areas we delved into pretty deeply was the concept of analogous fields that have had recoveries demonstrated, etc. could be categorized as proved reserves. If that occurs I’m not sure that those rules are going to beat us to the finish line here in getting our field up and running. It may not provide us additional latitude in making our probables proved but going forward it might. Richard Rossi – Collins Stewart: Giddings is still relatively early but what is your hedging philosophy going forward?

Typically you hedge to protect financial obligations of the company. Since we don’t have debt we don’t have a fixed obligation that we have got to hit other than our overhead and we are covering overhead right now fairly easily, both with cash flow from operations and capital programs. I think philosophically when I have a well established production that I can project forward confidently in a substantial amount combined with oil prices or gas prices I believe are much higher than our reasonable expectations then I might consider hedging. Other than that I would not be inclined to hedge.

The other there that we talk about here internally a lot and have for the last two years is counter-party risk. If you look at when hedging has been used for financial transactions it has basically been in an up commodity market where the bigger issues obtained at the well head and the producer out of just stream. The concern we have is if the market goes the other direction and we have no collateral against the counter-party and as a matter of fact you may have seen [Glen’s] announcement this week that they have got a little $60 some million hickey they will be looking to Lehman to reimburse them for because they moved out of those contracts and replaced them with another counter-party. Well that is an executory contract and they’ll probably get nothing for that play. So we’re already starting to see some of it. That makes you kind of heads you lose, tails you lose.

The next question comes from Joel Musante – C.K. Cooper & Co. Joel Musante – C.K. Cooper & Co.: I remember back in I believe June you guys indicated you would be evaluating the Giddings program before you lay out your 2009 plan. I was just wondering what you found in that evaluation and how it influenced your 2009 plan.

What we learned from our drilling program this spring is that certain areas of the Giddings field are more amenable to this re-entry program than others. We found one area that had a little more depletion and problems in terms of absorbing drilling fluid that you then had to produce back before you could get meaningful oil and gas production. So that area of the field is de-emphasized going forward in terms of our locations. The locations that we retained in the program and are focusing on adding new locations are more in the areas we have had much better results in. We have also determined that we got better results whenever we had a little more spacing from offset wells and so we have incorporated that as well. We are focusing on proved locations that have greater spacing between our proposed lateral and the offset well. The other thing we picked up on is in terms of how we actually drill the wells. We have seen that in the service industry right now it is best to make sure that you don’t run into complications. The service industry has been stressed in terms of graphic growth so getting quality equipment and tools combined with quality people at the same point is difficult. If you have any kind of a problem down hole combined with the service issues that can quickly turn into an extensive problem. So we are going to try and keep our program as simple as possible to avoid those kinds of issues and keep our costs under control. Joel Musante – C.K. Cooper & Co.: Is that why you are doing re-entry as opposed to grass roots wells mostly?

No, we have focused on the re-entry program when we are using 100% of our own money because of the cost per well. We want to keep that at a reasonable level to allow us to drill enough of the wells to make sure the program reaches its target. The Austin Chalk is a statistical play. Each location is totally independent of the next one and each one varies around a means. I mean, when you are drilling a horizontal section in an naturally fractured reservoir you might get two fractures swarms, you might get ten. It just varies depending on where you are in the rock and you can’t really predict that well. What you can do is project you are in a good area and then you are going to have a reasonable probability of getting a certain amount of recovery but it is still going to be a varying around the means and so you need to make sure you drill enough of those wells to get the good wells to offset the poor wells. You never know which is going to come first.

We can drill a lot of $1.5 million wells to get to the average but we can’t drill many $4-5 million wells to get to the average. We don’t have enough money yet.

They both generate reserves at the same cost in our program it is just there is not a lot of room for error at $4-5 million per well. Joel Musante – C.K. Cooper & Co.: Just to go to Woodford, you said some of the other operators were having encouraging results. Is there anything you can add there that might help us quantify there or understand the potential of the play better?

What I can do is relate to you the results that we are seeing in the offset wells. Keep in mind we have two projects. We have one called a shallow Woodford project which is typical depth of roughly 1,500 feet and then we have a play that is in the 4-5,000 foot depth range. We call that our moderate or medium depth Woodford shale project. On the shallow one we have had offset operators have drilled over 50 wells in and around our acreage. Almost all of those have been vertical wells with limited hydraulic fracs on them. Based on those wells we believe that horizontally drilled wells with fracs will likely produce in a general area of anywhere from a couple hundred MCF a day to maybe as much as a half million cubic feet a day. We are looking at substantial reserves somewhere in an appropriate range that goes with that. I don’t know what that means but maybe half billion cubic feet or maybe a little bit more. The medium depth we have one really good offset test right off our acreage, a well that was horizontally drilled and completed and it came on at roughly 1 million cubic feet per day this spring and based on reports today is continuing to make that level of production indicating that the width for that depth is very commercial and very perspective. So we are very excited really about both areas and we are very pleased. We are especially pleased because we didn’t have to drill the wells to get those results.

The other thing that is significant about the shallow and mid-depth Woodford’s compared to the deeper ones again it puts us in a window much less drilling costs per well as opposed to what is going on in the traditional cores of the southwest which is much deeper and those wells are as much as $7 million?

Yes, the traditional Woodford is about 8-10,000 feet deep and their massive, multi-stage fracs are getting 9-15 stages. They are costing $5-7 million. They are generating a fine development cost of roughly $2 per MCF. Our goal is really not much different in terms of MCF, it is just that we are doing it on a far cheaper cost per well because the cost per well is far, far less. I would like to point out if you go to our website and pull up our most current presentation I believe slide 19 gives you a little more detail about the Woodford shale project in terms of our acreage position, location and offsets that have been drilled relative to the main Woodford shale trend. The bottom line is we think this has tremendous up side, tremendous potential but we are not quite yet ready to start putting numbers in terms of what it is other than if Woodford shale is traditionally developed on 80 acres or less then that same number could be as many as 200 wells on our acreage. That is on a net well basis. Obviously our acreage position will grow through forced cooling which is allowed in Oklahoma so we will likely end up with far more acreage and far more gross wells.

I just wanted to point out that the actual slide presentation doesn’t have that slide. You have to go listen to the web cast for the Wall Street Analyst forum which is the first link under presentations. So you will find it there on slide 19.

We will go ahead and post those most recent presentations shortly and that will be slide 19 once it gets posted. I apologize for that.

The next question comes from Richard Feldman – Monarch Capital. Richard Feldman – Monarch Capital: I have some further questions about the Woodford. You have spoken in the past about a restraining resource for your company being people. Several hundred wells takes a lot of people. I wonder if you could comment on that situation.

A couple hundred wells is a program that will be done over a many-year period. Right now we are just slowly edging into it. We are finishing up our leasing and our capital program I will say we should start our drilling towards the end of the fiscal year which will be some time in the spring of calendar 2009 or later. That will be a slow process. We’ll drill our first well or two or three. We have our leases typically allow us as much as five years on them so we have plenty of time to conduct this in a very profitable manner. What we are doing is we are continuing to allow offset operators to prove up our acreage and then once we are ready we will start our own program. In terms of our ability staff wise to handle that obviously we are continuing to add people. We have added our third engineer this summer and I expect we will add another engineer after the first of calendar 2009 whose sole focus would be in that area. Staff resources continue to be an issue for industry. We have been very careful that when we add people it is someone who fits well within our team and our framework and what we do. We want to be very slow to add people in terms of adding to our overhead burden and we do look long-term in terms of when we add those people. We believe the resources are there and allow ourselves plenty of time to add them the right person at the right time. Richard Feldman – Monarch Capital: Earlier in the question answer today you talked about your success in leasing up acreage in the Giddings and the very high returns you were able to earn by doing that. Are you finding acquiring Giddings leases more competitive? Do you think that perhaps returns going forward will be a lot less?

At this point in time we have not seen a significant increase in our leasing costs in the Giddings field. Now I will have to point out that our leasing component for fiscal 2009 is down to $3 million as opposed to a much higher number in fiscal 2008 so we will be spending more effort on drilling and less on leasing. The leasing we are doing is starting to move into other projects and at this point in time we see no difference in what we are able to do. In terms of being able to deploy capital at a fairly low cost per acre and add substantial proved and probably reserves in that process. So at the moment I would say that I think we can continue to large extent what we have been doing in the past. Richard Feldman – Monarch Capital: The Texas new project, is that one that deals largely with heavier oils?

Yes, it deals with using that technology we developed over at Tullos for producing heavier oil. Not heavy but it is heavier. There is a difference. Heavier means 20 gravity type oil as opposed to…it is not stuff that requires steam to move. It is just something that it is oil in a reservoir that is hard to get out of the ground especially when you have water in the area.

The next question comes from Phil McPherson – Global Hunter. Phil McPherson – Global Hunter: Most of my questions have been answered. Just one in particular, when you talked about 27 booked PUD locations in the Giddings field, correct?

Yes. Phil McPherson – Global Hunter: And if I can use your PUD locations that you put in your reserve report it looks like they are about 0.8 a piece kind of taking that number as is, right?

Yes. Phil McPherson – Global Hunter: Then you talk about 3.1 probable reserves in the Giddings field. The question is, are those probables related to upside revisions to those booked PUD’s or are those another 23 locations to potentially drill?

The probables are a combination of additional locations and reserves assigned to PUD locations. The reason for that is partly due to the new SEC rules on how proved, undeveloped reserves are assigned in fractured reservoirs that was issued in the fall of 2007 where the SEC engineers came out and said they are not going to agree with only proven, developed location on a fractured reservoir they are going to allow are two locations each directly offsetting a producing well but within the same fracture trend. What that does is that substantially cuts the number of proved locations you might otherwise claim. We don’t necessarily agree with that position. In fact we would argue that a location that is a direct offset without a fractured trend of that given direct offset but within the fractured trend of other production that may be several locations away may actually be a better location because you have less risk of depletion. However, regardless you have to do what the SEC says and as a result much, not much but some of our locations were scaled back by our outside engineer in terms of the lateral link which reduced the demand that extended out of the fractured trend or whatever. Those reductions were moved from proved to a probable category. In addition we had I think one or more of our locations moved entirely from a proved to a probable location for that very reason. That would be the explanation for the probable reserves. Phil McPherson – Global Hunter: Sterling what do you think for fiscal 2009 G&A costs?

G&A? Phil McPherson – Global Hunter: Yes.

I don’t expect G&A to vary that much in the coming years. Bob said we may bring on another engineer. Our capitalization program probably will be similar in that we are going to continue to drill and as we drill we have direct personnel costs. Not Bob or me or the VP of ops, but our general manager of drilling and field personnel that are properly allocatable to capital. Phil McPherson – Global Hunter: Flat basically then from this year?

Pardon me? Phil McPherson – Global Hunter: Keep it flat then for modeling purposes?

Yes. I think as an inflation factor I might put… Phil McPherson – Global Hunter: 10% or something?

7% or something on it which probably sounds kind of high but I think inflation is high. I might do that. That would be across all services. Bear in mind we also have a probably disproportionate degree of legal expense relative to SEC matters. Yes, we are a small company but we have to deal with everything a large company has to deal with in terms of that. Our audit fees are going up. Everything is kind of going up. I don’t see big infrastructure additions but I do see some inflation in our numbers.

Probably the largest single component of our G&A is our staff and because we outsource most of our operations that we can our staff is disproportionately higher end salary. The people we have are the ones that are where the values created are on the control side and the industry is incredibly competitive right now for people. As a result our cap costs have gone up higher than maybe other industries may be.

I know you know this, but a high proportion of our G&A cost is in stock compensation expense and that is non-cash. You have to strip that out. Basically right now we are running probably $300,000 a month in cash costs. Phil McPherson – Global Hunter: I know it is hard to model and you don’t give guidance on production but from the sound of these drilling plans it looks like fiscal first quarter 2009 it should be up pretty well from this quarter and then we’ll probably have a slight drop fiscal Q2 and then we’ll resume that upward curve. Is that a fair statement?

Well as you point out I don’t like to give guidance. I’m not going to argue with you on your numbers.

The next question comes from Kevin [inaudible] – Kaiser Property. Kevin [inaudible] – Kaiser Property: My question relates to the dell head project. As far as the estimated recovery of that are we going to know pretty soon about the percentage whether it is going to be on the low side or the high side or is this just something that once we take over 11% we’ll just keep going up to the 20% if that happens?

That’s an excellent question. CO2 plugs have been around for decades now and engineers who model them have gotten a pretty good handle on how they work and what the important variables are. In this point in case Denbury has done over a half dozen CO2 plugs in that general area including some in the exact same reservoir rock but just across the border. We have got some really good analogs to compare against. Typically a CO2 plug covers between 10-20%. Denbury has averaged I believe 17% incremental recovery if not higher. We have tried to be conservative in our expectations. I think Denbury has also been conservative in their projections of recovery going forward. In terms of how you project what recovery is going to be that will just take time. I don’t think you can just come out and say now we have production and it is going to be this percent or that percent. The ultimate recovery is just going to take some time and what the reservoir engineers will do is they will say since we have shown there is recovery then we will apply what we consider to be the low end of recovery and that will be our proved reserves and then you have to earn in to the balance so the balance will start off as possible and then over time you will earn in and higher and higher recoveries. Kevin [inaudible] – Kaiser Property: The payout to Denbury, is that just the $200 million or is that based on the margin you are making on the barrels you are pulling out of the ground?

The answer is really both. The amount that is to be paid out is a fixed amount of $200 million. How they get paid out is obviously depending upon the margins we net in the field which is driven by what is the crude price in the field less the direct operating cost in the field. So whatever that gross margin is goes against that $200 million number. We estimate a gross production of somewhere in the 5-7 million barrels of oil out of the total of 50+ million barrels in the project. So we think payout will occur early in the life of the project and therefore we will have our quarter interest in the project throughout most of the life of the project. Of course from day one we have our separate 7.4% over riding royalty interest right off the top.

Is Kaiser developing CO2 projects? Kevin [inaudible] – Kaiser Property: No. I’m just a small investor in your company. I’ve just been interested in the Delhi project.

Just an FYI, I’m from Tulsa.

Management there are no further questions at this time.

I’d like to thank everybody for participating and listening this morning. We look forward to talking with you next quarter.