Thank you for standing by. This is the conference operator. Welcome to the Evolution Petroleum Corporation Full Year Fiscal 2017 Results Conference Call. As a reminder, all participants are in listen-only mode, and the conference is being recorded. After the presentation, there will be an opportunity to ask questions. [Operator Instructions] I would now like to turn the conference over to David Joe, CFO of Evolution. Please go ahead.

Good morning and welcome to Evolution Petroleum's earnings presentation for our fiscal year ended June 30, 2017 and our fiscal fourth quarter. We will discuss operating and financial results for the year and the quarter, as well as year-end reserves. With me today is Randy Keys, our President and CEO. Please note that any statements and information provided today are time-sensitive and may not be accurate at a later date. This presentation contains forward-looking statements of management's beliefs and assumptions based on currently available information. These forward-looking statements are subject to risks and uncertainties that are described in our filings with the SEC. Actual results may differ materially from those expected. I am now going to turn the call over to Randy Keys, President and CEO.

Thank you, David. Evolution had a number of important milestones for the fiscal year ended June 30, 2017. We reported our sixth consecutive year of positive net income, stretching back to 2012. We reported the highest revenues in the history of the company at $34.5 million, which was higher than last year by almost a third. As previously announced, we increased our quarterly dividend to $0.075 per share, which is $0.30 per share on an annual basis, effective with the dividend payable at the end of this month. This represents a 50% increase from the annual rate of $0.20 per share at this time last year. And we accomplished several important financial objectives including the redemption of our preferred stock, the funding of our capital program and payment of our cash dividends while ending the year with substantially the same balance sheet strength as we had when we began the year. Results for the quarter were down a bit from the March quarter with earnings per share of $0.05 and our revenues dropped about 7% quarter-over-quarter. Almost all of this decline resulted from lower average realized prices, which dropped from $47 per equivalent barrel last quarter to around $43 per barrel this quarter. Our production volumes were essentially flat compared to the prior quarter. We also saw slightly higher operating cost with both CO2 and other field expenses up quarter-over-quarter. Our LOE per equivalent barrel was above our trend line at $16.59 per equivalent barrel. By comparison our average for the year was slightly over $14 per equivalent barrel, which track very well compared to the prior year. We believe that some of the cost we have seeing getting the NGL plant up and running over the past two quarters are associated with startup of the plant and will likely…

We will now begin the question-and-answer session. [Operator Instructions] Our First question is from John White with ROTH Capital. You may go ahead.

Good morning. And thanks for taking my question. I was wondering I know you've been really occupied with the NGL plant and the conformance program, but any comments on what potential acquisition activity has been like what kind of deal flow? How would you describe the deals that you've been seeing and evaluating?

Yes good talking to you John. We starting in the beginning of this year, we're really starting late last year in 2016 and ramping up in the January-February timeframe. We have retained a qualified petroleum engineer on a basically full-time contract basis to assist us with evaluations of transactions I referred to is the traditional A&D market. These are properties that are being divested they're primarily mature, cash flow PDP properties that are being divested by the number of different brokers and people that market those properties in the industry. We have seen significant deal flow and we've looked at a lot of different transactions. We found that market to still be fairly competitive and we are trying to position ourselves to try to take advantage of good opportunities without overpaying. We have been somewhat cautious in our approach to our bids. And we do see continuing deal flow in that area and are continuing to evaluate it. At the same time, we have looked at other potential alternatives for the company, but none of those have -- and those would be more corporate or larger transactions, but we've not seeing anything that was compelling to us at this time. So I think we're focused most of our attention and what I've described is the traditional A&D market to acquire producing properties.

Thanks. So plenty of deal flow, just haven't really found anything that you’d be able to buy at a valuation you're comfortable with.

That's exactly right. We have found some things that we would like to buy, but not at the prices they ultimately transacted at.

Okay. Well thanks very much.

Thank you, John.

The next question is from Jeff Grampp with Northland Capital Markets. You may go ahead.

Good morning guys. I was hoping Randy to maybe give a little bit more commentary as best as you can with the information you got today with the infield drilling project, kind of general timing of how that's going to play out throughout the fiscal year. And maybe when you guys could potential see some incremental production. And could you just remind us for the general expectation for what kind of production uplift you may get from that?

Certainly. So we were notified by Denbury, the operator in I guess late July or early August. And they put out some information in their earnings call for their second quarter results back in early August. And at the time they said that they view that as an attractive project and economic project that had a good rate of return. But as they simply had to differ certain projects based on capital availability. At the time, they said that they expected that project to effectively be at the front of the line for their 2018 calendar capital budget. So we are expecting at this point that that project would be kicked off in early 2018. We've done a lot of analysis and we actually brought in a CO2 expert with -- engineering expert with experience with Kinder Morgan and Texaco to assist us in trying to evaluate our expectations for that. It is a fairly broad range, we're going to have five producing wells, we think those producing wells could easily have 100 barrels a day on average on a gross basis. They could have significantly more than that. And so I think we’re saying 500 plus barrels on a gross basis from that spending, which is fairly modest to us and I think has good economics even at that level. And we do see some potential upside above that, but it’s actually very difficult to quantify this because you are dealing with the potential for unswept zones in a very large area, it could have some oil banking, which would yield some very nice initial production, but we just -- until we go drill those wells we won’t know for sure what we’re likely to get out of that.

Okay, that’s helpful. And on the higher purchase CO2 volumes, can you maybe talk a little bit about, is that merely I guess replacing, I guess some of the things related to the NGL plant or is that kind of above and beyond trying to get some either acceleration of reserves or higher recoveries or just kind of wondering I guess the rationale for that kind of test I guess. And then timing of when maybe is this something that you will look to evaluate in the next quarter or two or just kind of how we should expect purchase volumes to trend?

That’s a very good question and I think answer -- the short answer is, is the combination of both. There is some component of replacing some of the volumes that are being removed from the CO2 plant, the CO2 plant gets about $155 million on the input. We lose about $4 million a day of methane and we lose some volumes associated with the NGLs. So it’s not the majority of the net change in injections, but it is a factor it’s a part of those. And then I think we expect that they will evaluate this over the next quarter or two, it is related to performance, I wouldn’t necessarily say acceleration, I think it’s just optimizing performance and trying to see they can calibrate the effects of additional injections on production, they have done this in the past, they did it about a year and a half or two years ago. And I think it’s a time it lasted for two or three months and ultimately they brought those injections back down. There are two competing objectives within Denbury, I mean; they want to minimize the use of CO2 in all of their existing fields so that they can retain additional CO2 for future use because they view it is a valuable and scarce commodity. But at the same time they are trying to maximize current production as well. So I think they are looking to balance those two objectives as well. We are supportive of that effort and I think you will see this last for some period of time, but and we will kind of see if it has a meaningful benefit, it may continue for longer than that. And if not, if we are able to achieve similar results with lower CO2 injections as we have over the past couple of years than I think you will see those comeback down.

Okay, perfect appreciate the color, Randy and I’ll let someone else hop on.

Our next question is from Brian Corales with Howard Weil.

Good morning guys. A question more on the -- you had a nice increase to probable and possible reserves. What do you really need to see I guess to get those into the proved category, is it just continued strong production or is there a kind of an event we should look for?

Okay, well we spend a fair amount of time analyzing that question as well. The way this is done with CO2 is, there is a different kind of plot that is unique to CO2 production is called the dimensionless curve and it relates to the number of times that CO2 is being recycled through the hydrocarbon pore volume, which is an estimate of the hydrocarbon space in the field. So it’s a somewhat abstract concept, that’s why they refer to it as dimensionless because it’s too kind of soft variables that you are trying to compare. The field and may refer to this as multiples as hydrocarbon pore volumes that have been recycled through the field. And the Delhi field is a little over one time hydrocarbon pore volumes recycled. And Denbury talked about these fields taking four -- minimum of four complete recycles and often up to five and six. And really many of these CO2 floods even some of the more mature ones in West Texas on are not -- we haven’t really seem what that effect is when we go out to four and five and six times hydrocarbon pore volume. The issue we face is that those curves, the proved curve, the probable curve and the total possible or the 3P curve are all very similar in the early stages of that pot. And it's only after you get pretty far along in that curve overtime that you get -- that you see a clear trend in favor of one dimension or the other. And so I'll go back to the position of reserve engineering on proved reserves they want a 90% confidence case. And with the P2, or the proved plus incremental probable they’re at a 50% probability case and then on possible, there is 10% or greater. So, their bias is to be conservative to hit that 90% confidence levels in the early stages and it’s only over a fairly lengthy period of time that you start to see separation in those curves. Now, we've seen progress, we've seen gains, but there isn’t going to be a single events that gets us clearly on to one curve versus another. I think we'll continue at least for the next perhaps year maybe two to see incremental gains rather than kind of a step function adjustment to that.

All right, that's helpful. And then one more, I mean, maybe comment on your confidence factor that the $6 million the infield program and I guess the beginning of Phase V that spent in your fiscal year ‘18, and if it is not, if those projects get deferred a little bit is that just -- do you just bank the extra cash, what do you do with the capital at that point?

Well, first off, I think we're pretty confident based on what we understand now that Denbury will execute those two projects.

Okay.

But, we can’t be certain and the answer to your question is we would continue to bank that just bank that cash, right now we've accumulated a fair amount of out of resources of working capital and we view that as available for opportunities for the company whether we are successful with finding opportunities to grow our cash flow or expand diversify into new property or whether we find another way to return that to shareholders as we are doing with the dividend is the challenge that we face right now. We believe the shareholders would be well served by adding to our growth and diversification, but we have to successfully execute that. So I think that answer your question, the $6 million, I think we're pretty confident that does get spent. And in fact just to give a little color on that, I mean, that was we've sign the AFE they had a rig scheduled, this was ready to kick off in July when they pulled the plug fairly abruptly on this project.

Very helpful, Randy. Thank you.

You bet, good talking to you.

Our next question is with John White with ROTH Capital.

Randy you were sounding like a reservoir engineer there for a little bit?

Sorry, hope I didn’t get too far down in the leads on that, but it's unfortunately from my standpoint it is a very complicated process to estimate these reserves and expected results from new activities. But anyway.

No I appreciated the detail. You had -- in the press you mentioned some impact on production and LOE from nonrecurring items from the NGL plant. Regarding LOE, would you want to talk about what you think those the magnitude of those nonrecurring LOE items are from the NGL plant?

Well, I tried to address that in my comments, where I indicated that I felt we’re going to move toward our longer term trend line on LOE per barrel. It’s -- we're encouraged, we are very encouraged by the fact that change over to the plant appears to have been successful, we have got the plant up and running at 100% capacity and we are just going to need a little bit of time to see how those cost stabilize. As Jeff asked on the call, part of the increased CO2 is makeup volume on the NGL plant, there is some power cost that we thought we were going to be saving that we haven’t yet seen significant savings. But I think we are in a position where we expect to see those now that we have got the plant up and running, we were also buying some additional methane to run that turbine, buying some outside third-party gas which is expensive, typically when you are buying it back from a pipeline. So we have got a lot of moving parts and I wish I had a better answer for you John, I believe that a meaningful portion of these are going to prove to be non-recurring, but I don’t have a way to accurately estimate that right now. And all I can do is report it, we just continue to keep investors updated as we see those costs stabilize.

Okay. Well you pointed this toward your historical long-term LOE per BOE, so we will use that and thanks again, appreciated.

You bet. Thank you, John.

This concludes the question-and-answer session. I would like to turn the conference back over to Randy Keys for any closing remarks.

I just want to say thanks everyone for your patience and attention during this call, it’s been a trying week and a half here in Houston. David is going to mention a couple of conferences that we’re attending in the next month.

We will in New York for the Sidoti Conference on September 28th, and then Randy will be in Chicago October 3rd for the IP, I think it’s the inaugural IPAA conference in Chicago. So stay tuned for those corporate events. Again thank you for listening in.

This concludes today's conference call. You may disconnect your lines. Thank you for participating and have a pleasant day.