Evolution Petroleum Corporation (EPM) Q4 2017 Earnings Report, Transcript and Summary

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 be nonrecurring. Likewise the operator has been experimenting with higher CO2 injection levels with a recent increase in our purchased CO2 volumes and cost. We have not settled on the level of CO2 injections for fiscal 2018. So we may see those cost come down as well. I believe we will see our LOE cost per barrel move closer to our long-term trend line, although some of the new cost of the NGL plant may result in LOE cost that are closure to $15 per barrel over the next year. I should remind everyone that our CO2 costs are tried directly to oil prices. This has been a significant silver lining during this downturn in oil prices as one of our largest components of operating cost has trended down as well with the drop in oil. But if we see higher oil prices going forward, we will have an increased in CO2 cost as well. Unfortunately that would be a high class problem as our revenues and operating margins would increase at the same time. The good news is that the operating margins in the Delhi field are still very health at $27 per barrel and our cost were only 38% of revenues, which yielded a 62% gross margin in the field during the quarter. This is almost $5.5 million in net cash flow from Delhi from the quarter on a field basis. I'm very proud on the progress we've made on the G&A expenses over the course of the year and this quarter was right in line with our expectations. We ended the year with $5 million of G&A, $1.2 million of that during the fourth quarter which met our target. As I've mentioned several times over the past years, we are focused a lot of attention on reducing and controlling lease call and have achieved very successful results. We will remain vigilant with these costs and will attempt to drive them lower if we see opportunities to do so. Last quarter we announced an increase in our quarterly dividend to $0.075 per share effective with the September dividend payment. Including that payment our cumulative distributions to our common shareholders over the past four years since we began the dividend have been over $37 million or $1.135 per share. And this does not include the $1.6 million of share repurchases that we've done over that same period. At our closing stock price on yesterday, our dividend yield was 4.3%. In the current year we had an effective tax rate of 37.6%, but our cash taxes were only about 6% with the other 31% of that effective tax rate being deferred. The largest factor in these deferred taxes was bonus depreciation equal to 50% of the cost of the NGL plant, which was put in service during the year. This was a $13 million tax deduction, which offset a large percentage of our taxable income. We ended the year with $7.2 million of percentage depletion carry forwards, which can be used to offset up to 65% of our taxable income in any profitable year. We currently expect to use a substantial part of these carry forwards next year and we may see an effective tax rate of less than 20% as a result. This is all highly dependent on oil prices next year and is also significantly affected by the level of our capital spending. But if we were able to utilize $5 million of these carry forwards, which I think is a reasonable expectation under the current price environment it would translate into approximately $0.15 per share to EPS next year. So we should see a significant benefit from that and it would also continue our low percentage of cash taxes for at least the next year and perhaps partially into 2019. Bottom line despite a slight dip in the fourth quarter, we had an outstanding year with $0.21 per share of net income and we are very well positioned heading into fiscal 2018. On the reserve front, for the year ended June 30, 2017, our proved reserves in the Delhi Field totaled 10.1 million barrels of oil equivalent. Substantially all of the change from the prior year resulted from production and our net revisions to proved reserve were negligible. Our trailing 12 month average oil price as specified by SEC guidelines was $46.65 per barrel and that was based on a $48.85 per barrel NIMEX WTI reference price. We -- in the field we receive NIMEX plus and an LLS premium less a transportation differential. And that -- we’ve recently seen that LLS differential increase dramatically because of the hurricane in the -- it had been a very large premium in prior years has been narrowing some over the past year and half, but as I said we've seen a nice increase in that here recently. And the NGL price we used in the reserve report was $20.48 per barrel. Our probable and possible reserves both increased very substantially. Probable was up 18% to 5.3 million barrels from 4.5 million barrels last year and our possible reserves increased 19% to 3.2 million barrels from 2.7 million in the last year. Of particular note, our probable and possible reserves do not require any additional capital expenditures to develop and are 82% and 89% developed currently. These categories of reserve reflect only the incremental recoveries associated with different engineering assumptions about the CO2 flood over a course of its life. We’ve seen the Delhi field significantly outperform expectations over the past two years. The majority of this outperformance has been attributable to selective improvements in the CO2 Flood through conformance efforts and other relatively low cost production enhancement projects. Our reserve report reflect this improvements as the expected ultimate recovery of our proved plus incremental probable or 2P reserves has increased from 17% to 19.5% over the past two years. And the timing of recovery hasn't accelerated as well and both our probable and possible do have very significant net present value associated with those categories. Our proved reserves have also increased from 13% to 14.3% over this two year period that's an ultimate recovery estimate. We believe this bodes very well for the long-term ultimate recovery from the field and provides a good foundation for future increases in proved reserves. With the NGL plant, we commissioned that plant at the end of December 2016 and commenced operations in January. For most of the first six months, the plant has been producing at less than 75% of capacity, which has not yielded the results we were initially expecting. The new processing plant of this complexity often require a period of adjustment to reach full operating capacity and efficiency. During this period, we identified certain factors which needed to be corrected in order to reach full capacity and many of these were corrected by the end of the fiscal year. We have one significant issue, which required an engineered solution to modify the inlet of the CO2 processing at the recycle plant and this had a gross cost of around $1 million, which was about $230,000 net to us. This modification was implemented in mid-August of this year and we have seen positive results from that so far, subsequent to that -- to those modifications, we have seen the NGL plant operating at substantially 100% of capacity, our CO2 purity goals have been met and our NGL production rates have increased significantly from between 1,000 and 1,100 barrels a day on a gross basis to 1,400 barrels or better on a day -- per day on a gross basis. Also our methane production has increased and we are now meeting substantially all of the requirements for the electric turbine in the field, which is now producing sufficient power to cover part of power requirements of the recycle plant. And we think this is going to be reflected in lower operating costs going forward. The plant produces a very rich mix of liquids, this is in line with our expectations, actually perhaps even better, we have about a third of the product in high value pentanes and heavier liquids those have a pricing of 90% of the WTI price give or take. We also have about a third of the products in butane with the balance in propane. And our net pricing in the first two quarters was seasonally strong at $21.28 per barrel. These NGL prices will fluctuate overtime and will not always be correlated to WTI pricing. Despite these early startup issues, the NGL plant met our three main goals for the project. We are extracting the methane and ethane for power generation, we’re cleaning up the CO2 stream for reinjection, which we believe will result in greater efficiency of the CO2 flood and we are producing a meaningful yield of higher value NGLs to generate incremental revenues. On the capital budget side, we recently approved expenditures totaling approximately $6 million net to our interest for two projects in the Delhi field. Both of these projects are for development of our proved undeveloped reserves. The first project estimated at 3.2 million is an infield drilling program consisting of eight wells and this was in the current boundary of the producing area of the flood. Three of the wells are for CO2 injection and there were five production wells scheduled. The wells were targeting oil zones within the current producing area, which we believe are not being effectively swept with the current flood. So we expect these wells to add both production and to increase the ultimate recovery of reserves. The second project, estimated at approximately $2.8 million, consisted of primarily some infrastructure related costs in preparation for the development of Phase V of the flood in the Eastern part of the field. At this point these are primarily as I said front-end costs, water injection wells pipe to deliver the water and CO2 to the field and we think the remaining development of that will occur in late 2018 or 2019. And both of these projects were authorized and initially schedule to commence in July of this year. However they were electively deferred until early 2018 by the operator based on its allocation of funds available. So this concludes our review of financial results and operations for our fiscal year ended June 30, 2017. In summary, we reported positive net income for the sixth consecutive fiscal year and increase in cash dividends on our common stock to $0.30 per year on an annual basis. Strong financial performance with excellent balance sheet strength and the completion and startup of the NGL plant in the Delhi field. Our liquidity position remains very strong with working capital of $23.4 million at the end of the quarter substantially all of which was cash, we have retired all of our preferred stock and have no debt on the balance sheet. We are in an enviable position to look at new opportunities for growth in cash flow and diversification. Thank you very much for your interest in Evolution Petroleum.

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.