Good morning. And welcome to the Evolution Petroleum Conference Call. All participants will be in a listen-only mode. (Operator Instructions) After today’s presentation there will be an opportunity to ask questions. Please note, this event is being recorded. I would now like to turn the conference over to Sterling McDonald, CFO. Please go ahead, sir.

Thank you, Operator, and good morning. And thank you for listening to Evolution Petroleum conference call to discuss results of our First Quarter of Fiscal 2013, which ended September 30, 2012. My name is Sterling McDonald. I'm CFO of Evolution and with me today are Bob Herlin, our CEO; Daryl Mazzanti, our VP of Ops. Before we begin, let us cover the basics. If you'd like to be on the company's e-mail distribution list to receive future news releases, please see the contact information on our news release. If you wish to listen to a replay of today's call, it will be available shortly by going to the company's website at evolutionpetroleum.com or via recorded telephone replay until November 16, 2012. The necessary information can be found in the earnings release. Please note that any statements and information provided today are time sensitive and may not be accurate at later date. Our discussion today may contain forward-looking statements that are based on management's beliefs and assumptions that are based on currently available information. We can give no assurance that such forward-looking statements will prove to be correct as they are subject to risks and uncertainties that are listed and described in our filings with the SEC. Actual results may differ materially from those expected. Our discussion also may include discussions of probable, possible or potential reserves or recovery. Such unproven estimates are more speculative than proven reserves. Now, Bob will give you some results of our fiscal quarter to start off. Bob?

Thanks, Sterling, and good morning, everyone. Thank you for joining us. Since we did release detailed numbers in our news release last night, I’m going to focus my remarks on key results, operations and projects, as Sterling will similarly review key financial results. I’ll fellow up with the few general observations and then we’ll take your question and what that goes along to your questions. Earnings to common increased some 7% over the previous quarter to $1 million that works out about $0.03 per fully diluted share but that was on 6% lower revenues. Our results were, as now expect impacted by lower oil and natural gas prices, natural gas liquid prices I should say, but even probably more importantly the temporary restriction on Delhi production that began in the later part of the previous quarter and extended through the first two months of the current quarter. As I discussed in our last earnings call, the hot envious summer time temperatures is stronger than expected response in the field exceeded the capacity of equipment that was cooling the recycle gas coming off the compressors in the field prior to reinjection. Consequently, the operator had to temporarily restrict product in CO2 injection wells during the summer. Now as cooler weather return in the field in September the operators able to restore normal production CO2 rate and field production quickly returned to pre-summer rate. In fact, we are very pleased that the field is now exceeding the previous higher rates and the operator is reporting improved response in the field. Additional cooling capacity is implant -- this plant to be added before next summer, so we’ll don’t have a repeat. The other significant move during the quarter is pending monetization of non-core asset in the given field. This will allow us to become much more focused on our Mississippian Lime project and our GARP technology, both of which have extensive reign room and upside potential as compared to our limited upside in the given field. Now, let’s talk about some of the specific projects and we’ll obviously start with the Delhi Field. Gross production for the current quarter at Delhi decreased slightly over the prior quarter to 5,057 barrels a day gross, that’s 374 barrels a day net. The temporary restriction in production occurred in the first two months of the quarter for reasons I have already mentioned. Production going forward is already reflecting increasing contributions from the work completed in 2011. Our June 30, 2012 reserve report rejected productions in the field to gradually increase over the next five years, before flattening out in late calendar 2017 at a peak rate of 11,800 gross barrels per day. Our Delhi crude oil sold for an average realized price of $104 during the quarter and $11 premium over our oil sold in Texas in the same time period, less than $110 realized in the prior quarter. The operator continues to rollout expansion of our project into the eastern half of the field with more than $60 million expanded in calendar 2012 to date. We continue to be very pleased with the results of this EOR project, particularly the recent response increase in the rapidly approaching reversion date of our 23.9% working interest. We continue to have high confidence in the upside potential at Delhi. Let’s talk about Mississippian Lime for a second, our primary focus for redeploying cash flow this year is the Mississippian Lime play in North Central Oklahoma. This is in Kay County which is on the east side of the field or the play actually we call it east of the Nemaha Ridge, which is more oily part of the play. There we completed drilling of our first two Mississippian Lime oil wells, this is Kay County. In addition to the 45% working interest in the salt water disposal well we completed last quarter. We own a 45% working interest in the Sneath #1-24 well and 36.6% working interest in Hendrickson #1-1 well. In the Sneath, we hydraulic fractured a 3,100 foot lateral section 12 stages in late October. In the Hendrickson well we just nearly got off a hydraulic fraction at 10 stages of 4,000 foot lateral section in the Hendrickson well. Now industry experience to date shows that the Mississippian Lime formation requires some depressurization in order for oil and gas production to begin. Consequently, we really expect meaningful oil and gas production to begin in both wells sometime this second fiscal quarter that we are in right now, after we partially dewater the reservoirs. This process has already begun in the Sneath well which we fractured in the end of October. We continue to look for opportunities to expand our position in this play. These two wells are the first of 114 gross probable drilling locations identified by independent reservoir engineer. Now, capital program for this fiscal year 2013 is primarily focused on this project. Next, let’s talk about our artificial lift technology which we trademark as GARP. It stands for gas-assisted rod pump. For those of you that have installed this store, we developed this technology many years ago internationally by our Vice President of Operations. This technology has been patented last year. It consists of marring three types of artificial lift, both the gas lift and a conventional artificial rod pump, where we use the gas lift, low gas lift and the lowest point in wellbore, up to the intake of your traditional rod pump. This is applicable to both horizontal and vertical wells, both oil and gas. It’s intended to capture the tail end of production. Results then show that we can add 20% to 30% potentially of additional recovery in oil. Now, we installed our GARP in a fork well this quarter pursuant to commercial agreement. We converted the well that had no productions into a well making some barrels a day equivalent gross producer. We own a 99% working interest for payout in the oil. It’s 76.5% working interest after payout. And as of early November, combined growth production from our four commercial installations today are in the 55% to 60% BOE per day range. Net is about half of that, 27 to 30 net BOE a day as result of our commercial agreement. Now, these results continue to demonstrate, the success with potentially of technology in terms of adding both more reserves and significantly expanding the life of leases. And we are again continuing to aggressively commercialize this technology both in a Gidding field and another fields with other companies. In South Texas, we’re active at a field called the Lopez field. This is something we’ve been working on for last couple of year. It’s an old waterflood field. It as had some 33 million barrels of oil this time, it was fully plugged down and abandoned. We took leases to try and rehabilitate the field. Early efforts, who are marked by difficulties in getting adequate water injection back into the field to maintain pressure. We bought that for over some extend period of time. It actually impacted LOE last year. However, the results of that work have now starting to bear fruit. The Lopez field production continues to improve and benefit form our extensive work-over efforts from last year. The Lopez number five well is now averaging consistently -- averaging more than 15 barrels a day. Garcia 1 the very first well we drilled last year is averaging about eight barrels a day. A third producer is still in the dewatering stage. Overall, we have some 37 proved and probable drilling locations on our leases. We are evaluating the potential in this field in South Texas in general for this overall effort compared to other projects we have as far as scale, profitability and timing. After we’ve attained results from this last producer. We will compare the likely economics or other opportunities in order to determine the best option for value creation. Last is the Giddings Fields. Now production from our wells in the Giddings Fields were essentially maintained, subject to normal decline. Pursuant to our focus on our core projects in Mississippian Lime and GARP combined that with the continued low natural gas prices. We did elect to monetize much of our non-core Giddings interest and we have done so through agreements in principle that are expected to close two times during second fiscal quarter. The sales are expected to significantly lower our overall depletion cost per barrel in the future due to the removal of featured capital expenditures associated with these improved undeveloped reserves. They have the high natural gas content, high development cost for BOE and really no alignment. Our capital program for the balance of fiscal 2013 will continue to focus on Mississippi Lime play. This working capital on hand before the addition of operating cash flow and monetization proceeds is well in excess of remaining capital expenditures for the year. We have no current expectation of being in the capital markets in the foreseeable future. With that, I’ll turn it over to Sterling.

Thanks Bob. And thanks again those of you participating in this morning’s conference call. I’d like to address several topics today including some key financial metrics as well as some corporate governance matters. Now, the feedback on our side, I apologize, if you’ll are hearing this. I’ll also address several topics today including the key financial metrics as well as some corporate governance matters. But first I’d like to summarize our production that’s resiliency. As reported, our overall net reduction in the most recent quarter average 581 net BOE a day which was up a little more than 1% sequentially and 14% over the year-ago quarter. So we have started increasing production performance sequentially and over the year-ago quarter, despite Delhi’s temporary but meaningful drop off during December and despite normal depletion to client’s we expect in our non-GARP getting field well. I’ll point this out because the production that’s filled in for this temporary and permanent respective declines, now we’re beginning to gain traction on our GARP and Lopez field initatives. When taken together are currently contributing about 45 net BOE a day much of it oil. Now, as Rob as pointed out, we plan on monetizing our Giddings and non-GARP production which was recently running about 175 net BOE a day. So the potential lack of this production going forward may not be immediately replaced by expected production coming online in our two newly completed Mississippi line wells, strengthening production levels expected at Delhi and potential ads to our GARP and Lopez field activity. Really it’s a good segue in our financial results especially with respect to our expenses. Although revenues decline 6% sequentially while increasing 11% over the year ago quarter. Total operating expense declined only 4% sequentially but increased 26% over the year-ago quarter. This is due mainly to two times. First, although LOE dropped 26% sequentially, it was up 56% over the year-ago quarter. The increase was mostly due to seven new wells coming online in our GARP and Lopez fields project with relatively high operating costs, especially when compared to the large amount of Delhi production that currently there is no operating cost. Although -- and secondly although G&A was up only 1% sequentially, it increase 21% over the year ago quarter and some of the increase here is due to higher personnel cost while much of it is due to corporate governance, new accounting controls and professional service expenses related there too. To give you flavor for this as some of you may have notice, we recently instituted additional governance policy to strengthen our company. Specifically our Board recently adopted the stock retention policy that affects all Board members and all of our employees. Secondly, since our CEO is also our Chairman, the Board has pointed Mr. DiPaolo as our lead Director. And he sits on three committees currently including his chairmanship of our corporate governance committee. Thirdly, our Board has adopted the majority voting policy for the election of director. All of these actions have increased the amount of committee meeting expense and expenses related to outside council and other professional service providers in implementing these policies. Additionally, we have recently become subject to new regulatory roles. It requires still electronically tag, our financial statement using XBRL, which requires use of professional services to setup and maintain this very specialized expertise. Also for the first time we were required to include a compensation discussion and analysis in our proxy, a CD&A, requiring much additional compensation committee meeting expenses along with legal compensation and other professional service expense. On this point, you may be interested in reviewing our proxy and the CD&A therein. And we now show where we rank ourselves within our peer group relative to compensation and the recap of our bills. Last point, I would like to make, it concerns our overall financial strength and dedication to increasing per share values for the benefit of our shareholders including all of our employees. Our current working capital was amply sufficient to fund our 2013 capital program plus some. We expect to increase our liquidity through meaningful cash flow from operations. We expect to generate during fiscal '13 through expected record production at Delhi, new production from our Mississippian Lime and additional focus on bringing new gas production to bear. Through this, we expect a near-term cash gain in the monetization of our non-GARP Gidding assets that would exceed the loss production revenue, net revenue there for few years. All this is allowing us to remain debt free of management’s discretion. So, our future continues to look bring. With that, I will turn the call back to Bob.

Thanks, Sterling. Resumption of normal production in growth, in the production of Delhi during the quarter was a very positive step currently and bodes well for strong fiscal year. With no debt growing cash flow, cash on hand and pending proceeds from monetization non-core asset, we believe that we continue to be well-positioned for much more focused on growing Mississippian Lime oil project in our GARP business as well as taking manage many other opportunities within our define business that may arise. Our overall strategic goals continue to be growth of per share value and transferring that great value to shareholders in the most efficient manner. With that, we’re ready to take questions. Operator, can you please open the line for questions.

(Operator Instructions) Our first question is from Jeffrey Connolly. Please go ahead.

Hi, good morning. If you can give us some color on the GARP installation process and how the performance on the first four wells compare through expectations?

Sure. The GARP installation ideally is targeting the top two quartiles of wells that are out there. Because what we do is we think we can add anywhere to 10% to 30% additional recovery to what’s already been produced and so obviously you want to do, target wells that made a fair amount to start with. Ideally, it’s a well. They already is fully equipped with the broad pump and tubing and rod string so forth. In that case, in the GARP installation is pretty reasonable, it primarily installation of its small compressor that can generate a small volume of high pressure gas, a second string of tubing to deliver that gas, so specialized tool downhaul to handle all this and then what we do is we’re injecting gas at the very lowest point in the horizontal well or vertical well, which then mobilizes the fluid but not up to the surface but it si going to mobilize it up everywhere from couple 100 feet to most of 1000 feet the intake of the rod pump. By doing this we are able to recover a far more oil and gas seeing with otherwise we achieve. A lot of people that have drilled wells in the new plays over the last 5, 10 years there are peak they are accounting very high reserves based on high MISO, rate rapid decline stabilizing into a long life tail production. And what’s going on in many of these is that when the reservoir pressure falls to certain level then the fluid if it’s an oil well in the fluid level falls below rod pump intake and you can’t stick that rod pump very four times a curve, but then you have issues with mechanical failures. And so once the fluid falls that point, the pump is no longer effective, but you’re still leading quite a bit of oil behind. In the second case in terms of gas wells, you have a case where you a gas well is making sustention on gas but as reservoir compressors, you start dropping out fluid in the well and start pulling water in that fluid level slowly build and sink down the fluid level building a pressure, dropping in a some point those two kinds of cross paths and the amount of pressure is not sufficient see consistently move gas through that level of water. So there is no way you get that fluid out of the hole to again our process eliminates that and allows you to achieve that tail production. We have installed this number of our own wells and then the last year we’ve installed it in four third-party wells subject to commercial agreement. And we’re very pleased with results. They have -- the technologies done exactly what we borrowed with you and have advertised. So we are very pleased with it. I think our typical wells we installed it on have been making no more than maybe a barrel a day to get that and now they are making -- is about 15 barrels of oil equivalent a day on average. And they are making on a very stabilized rate. So we are very pleased. It’s very cost effective. We can add substantial reserves at a very low cost that not only adds reserve and value, but the lower LOE cost per bill and even more importantly they extend the life of those leases for many, many years to come, which is important because of all the serendipity that is out there. Other formations that you may not know about, now back in year 2005, whatever, all of sudden it becomes very economic and attractive that you lose your lease and get excess to that. So we are very pleased with it. It didn’t take very long to install this technology. It’s a simple work over and we have a variety of different commercial arrangements for doing these deals. We are still early in infancy of the business, have or what we have done is we have somewhat restructured our company. We now have subsidiary whose sole focus is the commercialization and marketing installation operation, other technology. We now are vacating a portion of our staff to doing nothing more than working on building this business. So does that answer your question?

Yeah. And then when you install a unit, about how long until it starts to see an increase in production?

It really varies. It can be anywhere from immediate to, it might take about a month. I think the month is the long has it taken for its technology to start producing substantial oil and gas. A lot of times, they’ve all been sitting here for a long time. We have to produce a lot of water that’s accumulate in the near well bore area. Another time, it’s been fairly rapid. So every well is a different story.

Okay. Thank you, guys.

Yeah.

(Operator Instructions) We have a question from [Hasing Draga] from MLV Company. Please go ahead, sir.

Hi, guys. How you doing?

Good. How are you?

I’m doing well. Just about a question on Mississippi line. I hope these wells come out really well and if these wells come out well, would you consider levering up and speeding up operations in Mississippi line?

Well, we have to keep in mind that in our current joint venture, we are not the operator. Our partner who we acquired the position from is the operator. We have an agreement in terms of how many wells they have to drill. It’s max or minimum. We do have – let’s see, are proposing wells if they don’t do the minimum number. So at the moment we don’t anticipate that being an issue. We are on the same page. We are working very closely with them. We are both interested in maximizing our value, but we are also – I guess something, we’d say extremely cautious or conservative that we drilled these two producers. We wan to see how they operate and how they create. We want to try and learn from what we’ve done. We look forward to start doing new wells, so we can apply that knowledge. I mean, we are paying a hefty price to get this information. So it will be kind of silly not to take advantage of that information. We’ve already been fitted from looking at what other people have done in terms of focusing on where we drill in the formation. Apparently, the March study and talks with various other competitors and service providers makes a big difference varying the line. You actually put your horizontal, in the property zone or the bottom zone or whatever. It makes a big difference in terms of kind of results we get. So we have a plan that we learned so far. We’ve actually utilized a new form of fracturing. And in one of our wells, we are very pleased with those results. But have also noted that complex act, you have to drill with certain way to avoid too many circum time, up and down motions in the drilling. So we are planning all that. But that’s the stake we don’t really drill our next well until probably after the first of the calendar year. Hopefully, at that point, Joe, we will be in a very aggressive drilling mode with the one rig program and that would be basically one well per month, which for us is a pretty aggressive approach because that would be 45% of the $3 million well. I’m pleased that our costs have actually come in extremely closed to what we originally projected and apparently less than what industry is averaging current from wells, wet and herd, just another company. So we are very pleased with that our wells that we have been drilling, which are fairly long lateral. And actually end at very attractive costs. So far, is what they were. The important thing is that they didn’t raise the reserves and that part obviously we are still waiting on as we do water our west well. And our second well, we should have within the next couple of week and start their rewarding progress.

Okay. And could you remind me if what the minimum and maximum number of wells could be relive at?

Minimum was six wells and the first two months of the program and the maximum was 12 wells.

Okay.

14 maximum wells that include disposals wells and so we’ve already had – we’ve already drilled 3 wells to date. So by sometime around mid year, next calendar year would be the end points of that program. So at minimum we have to drill eight more wells. In the case, it could be more than that. And I suspect there is probably more like five or six wells, I actually expect that we would drill during our peak.

All right. Tom, good. Thank you, guys.

Thank you.

(Operator Instructions) We are showing no further questions at this time. So, I will turn the conference back over to Management for closing remarks.

Like I said, I’d like to thank you everybody for joining us. We are very pleased on what’s going on the field today. We are very pleased with what’s happening in Delhi. We have to tell you more hovered by prior agreement with Denbury. We try -- we have to limit our discussions on results out there. But we are very pleased with where the company is. We are extremely pleased that in this uncertain and volatile times but we have no debt. I’m pleased that I’ll have to report hedging lockies and derivative lockies. We are trying so. I hope shareholders are pleased and we think that things are going to continue to improve and we look forward to an excellent fiscal year. Thank you and again, if you have any questions of like clarifications, I will say, please free to e-mail us and call us. Thank you and I hope you have good day. Bye.

The conference has now concluded. Thank you for attending today's presentation. You may now disconnect your lines.