Evolution Petroleum Corp (EPM) 2017 Q4 法說會逐字稿

Thank you for standing by. This is the conference operator. Welcome to the Evolution Petroleum Corporation Full Year Fiscal 2017 Results Conference Call. (Operator Instructions) And the conference is being recorded. (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'm 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 1/3. 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 costs 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 tracked very well compared to the prior year.

We believe that some of the costs we have seen getting the NGL plant up and running over the past 2 quarters are associated with start-up 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 costs. We have not settled on the level of CO2 injections for fiscal 2018, so we may see those costs 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 costs of the NGL plant may result in LOE costs that are closer to $15 per barrel over the next year.

I should remind everyone that our CO2 costs are tied 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 costs has trended down as well with the drop in oil. But if we see higher oil prices going forward, we will have an increase in CO2 costs as well. And fortunately, 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 healthy at $27 per barrel, and our costs 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 of the progress we've made on 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 targets. As I've mentioned several times over the past years, we have focused a lot of attention on reducing and controlling these costs 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 4 years since we began the dividend had 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 carryforwards, 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 carryforwards 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 carryforwards, 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 reserves 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 NYMEX WTI reference price. We -- in the field, we receive NYMEX plus 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 1.5 years, but we'd like -- 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 reserves reflect only the incremental recoveries associated with different engineering assumptions about the CO2 flood over the course of its life.

We've seen the Delhi field significantly outperform expectations over the past 2 years. The majority of this outperformance has been attributable to selected improvements in the CO2 flood through conformance efforts and other relatively low-cost production enhancement projects. Our reserve report reflects this improvement as the expected ultimate recovery of our proved plus incremental probable, or 2P, reserves has increased from 17% to 19.5% over the past 2 years. And the timing of recovery has 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 2-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 6 months, the plant has been producing at less than 75% of capacity, which has not yielded the results we were initially expecting.

New processing plants 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 had 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've 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 the 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 1/3 of the products in high-value pentanes and heavier liquids. Those have a pricing of 90% of the WTI price, give or take. We also have about 1/3 of the products in butane, with the balance in propane. And our net pricing in the first 2 quarters was seasonally strong at $21.28 per barrel. These NGL prices will fluctuate over time and will not always be correlated to WTI pricing.

And despite these early start-up issues, the NGL plant has met our 3 main goals for the project: we're 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 2 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 infill drilling program consisting of 8 wells, and it's within the current boundary of the producing area of the flood. Three of the wells are for CO2 injection, and there were 5 production wells scheduled. The wells -- we're 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 5 of the flood in the eastern part of the field. At this point, these are primarily, like I said, front-end costs, water injection wells, a pipe to deliver the CO2 -- water and CO2 to the field. And we think the remaining development of that will occur in late 2018 or 2019.

And both these projects were authorized and initially scheduled to commence in July of this year. However, they were electively deferred until early '18 -- 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've reported positive net income for the sixth consecutive fiscal year, an 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 start-up 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.

(Operator Instructions) Our first question is from John White with Roth Capital.

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. We -- starting in the beginning of this year, we're -- really starting late last year in 2016 and ramping up in the January, February time frame, we have retained a qualified petroleum engineer on a basically full-time contract basis to assist us with our evaluations of transactions I refer to as the traditional A&D market. These are properties that are being divested. They are primarily mature cash flow PDP properties that are being divested by the -- a number of different brokers and people that market those properties in the industry. We have seen a significant deal flow, and we've looked at a lot of different transactions. We've found that market to be -- 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 seen anything that was compelling to us at this time. So I think we've focused most of our attention in what I've described as the traditional A&D market to acquire producing properties.

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 we would like to buy but not at the prices they ultimately transacted at.

The next question is from Jeff Grampp with Northland Capital Markets.

Was hoping Randy to maybe get a little bit more commentary as best as you can with the information you got today with the infill drilling project, kind of general timing of how that's going to play out throughout the fiscal year and maybe when you guys could potentially see some incremental production. And could you just remind us of the general expectations for kind of production uplift you may get from that?

Certainly. So we were notified by the -- 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 viewed that as an attractive project, an economic project that had a good rate of return but that they simply had to defer 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 5 producing wells. We think those 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're dealing with the potential for unswept zones in a very large area. You 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 purchased 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 plants? 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 look to evaluate in the next quarter or 2 or just kind of how we should expect purchase volumes to trend?

That's a very good question. And I think the answer -- the short answer is it's a 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 factor, it's a part of those. And then I think we expect that they will evaluate this over the next quarter or 2. It is related to performance. I wouldn't necessarily say acceleration. I think it's just optimizing performance and trying to see if they can calibrate the effects of additional injections on production. They've done this in the past. They did it about 1.5 or 2 years ago. And I think at the time, it lasted for 2 or 3 months. And ultimately, they brought those injections back down. There are 2 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 as a valuable and scarce commodity. But at the same time, they're trying to maximize current production as well. So I think they're looking to balance those 2 objectives as well. We're supportive of that effort. And I think you will see this last for some period of time, but -- and we'll kind of see if it has a meaningful benefit. It may continue for longer than that. And if not, if we're able to achieve similar results with lower CO2 injections, as we have over the past couple of years, then I think you'll see those come back down.

Our next question is from Brian Corales with Howard Weil.

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 kind of an event we should look for?

Okay. Well, we've spent a fair amount of time analyzing that question as well. The way this is done with CO2 is there's a different kind of plot that is unique to CO2 production. It's 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 2 kind of soft variables that you're trying to compare. The field -- and they refer to this as multiples of hydrocarbon pore volume that have been recycled through the field. And the Delhi field is a little over 1x hydrocarbon pore volume recycle. And Denbury talks about these fields taking 4 -- minimum of 4 complete recycles and often up to 5 and 6. And really -- many of these CO2 floods, even some of the more mature ones in West Texas, are not -- we haven't really seen what that effect is when we go out to 4 and 5 and 6x hydrocarbon pore volume. What we -- 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 plot. And it's only after you get pretty far along in that curve over time that you get to -- 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, they're -- it's 10% or greater. So their bias is to be conservative, to hit that 90% confidence level 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 event that gets us clearly onto the one curve versus another. I think we'll continue at least for the next, perhaps, year, maybe 2 to see incremental gains rather than kind of a step function adjustment to that.

All right. No, that's helpful. And then one more. I mean, maybe comment on your confidence factor that the $6 million -- the infill program and, I guess, the beginning of Phase 5, if that's spent in your fiscal year '18. And if it is not, if those projects get deferred a little bit, what -- is that just -- do you just bank the extra cash? What do you 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 2 projects. 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 resources, of working capital. And we view that as available for opportunities for the company, whether we're successful with finding opportunities to grow our cash flow or expand, diversify into new properties 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 answers your question. The $6 million, I think we're pretty confident that, that does get spent. And in fact, just to give a little color on that, I mean, that was -- we've signed the AFEs. They had a rig scheduled. This was ready to kick off in July when they pulled the plug fairly abruptly on this project.

Our next question is with John White with Roth Capital.

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

I'm sorry. Hope I didn't get too far down in the weeds 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 release, 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 mean, I tried to address that in my comments where I indicated that I felt like we're going to move toward our longer-term trend line on LOE per barrel. It's -- we're encouraged -- we're very encouraged by the fact that this changeover to the plant appears to have been successful. We've got the plant up and running at 100% capacity. And we're just going to need a little bit of time to see how those costs stabilize. As Jeff asked on the call, part of the increased CO2 is makeup volumes on the NGL plant. There's some power costs that we thought we were going to be saving that we haven't yet seen significant savings. But I think we're in a position where we expect to see those now that we've 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're buying it back in -- from a pipeline. So we've got a lot of moving parts. And I wish I could -- I wish I had a better answer for you, John. I believe that a meaningful portion of these are going to prove to be nonrecurring, but I don't have a way to accurately estimate that right now. And all I can do is report it. We'll just continue to keep investors updated as we see those costs stabilize.

Okay. Well, you pointed us toward your historical long-term LOE per BOE, so we'll use that.

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

Well, I just want to say thanks to everyone for your patience and attention during this call. It's been a trying 1.5 weeks here in Houston. David is going to mention a couple of conferences that we're attending in the next month.

We'll be in New York for the Sidoti conference on September 28. And then Randy will be in Chicago October 3 for the -- 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.