Evolution Petroleum Corporation (EPM) Q3 2019 Earnings Report, Transcript and Summary

Good day, ladies and gentlemen, and welcome to the Evolution Petroleum Third Quarter Fiscal 2019 Earnings Release Conference Call. [Operator Instructions] At this time, it is my pleasure to turn the floor over to Mr. David Joe, Chief Financial Officer. Sir, the floor is yours.

Thank you, Tom. Good morning, and welcome to Evolution Petroleum's earnings call for our fiscal 2019 third quarter ended March 31, 2019. Today, we will be discussing operating and financial results for the quarter. Joining me on the call today is Bob Herlin, Chairman of the Board and interim CEO; and Steve Hicks, Senior Vice President of Engineering and Business Development. If you wish to listen to a replay of today's call, it will be available shortly by going to the company's website until June 9, 2019. Please note that any statements and information provided today are time-sensitive and may not be accurate at a later date. Our discussion today will contain 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 listed and described in our filings with the SEC. Actual results may differ materially from those expected. Detailed numbers are readily available to everyone in yesterday's news release, and this call will highlight key results and overall trends and an update on operations for the remainder of fiscal 2019. And I'm now going to turn the call over to our Executive Chairman, Bob Herlin.

Thanks, David, and welcome to everybody. Evolution is among the industry leaders in the pivot to the focus on cash flow and shareholder return. Consequently, we're very pleased to report another good quarter with solid earnings and cash flow even with a low level -- or lower level of commodity prices in the January and February time frame, which began recovering in March. I would like to remind listeners that the company's policy does not provide guidance. Our balance sheet remains very strong. We have some 31 million in positive working capital, most of which is cash. And we don't have any debt. We continue to provide an attractive cash return to shareholders as we now have paid over $56 million in cash dividends since we started the dividend program in 2013. That's a total of $1.71 per share. I think that's a fairly unique performance for an independent energy company. Our Delhi Field assets are performing well with the 2018 infill well program contributing meaningfully. We have 9 producing and 2 injector wells online in the quarter. We're working with the operator now on new and, we think, innovative projects that could further increase cash flows and value. And we expect to begin the next phase -- major phase of project expansion during the latter half of our fiscal 2020 year. Now since we don't have any outstanding debt, the Board has once again elected not to enter into any hedges in the current period. Therefore, our performance going forward will continued to be tied to and vary with Louisiana Light Sweet oil price that currently sells at a considerable premium to NYMEX. I think pricing as of yesterday was right close to $70. Now we review that strategy on a quarterly basis, and considering what the prices are, expectations and our financial needs. Looking forward, we're evaluating opportunities to acquire compatible developed oil and gas-related properties that meet our specific criteria and support our dividend policy. We're being very careful on that process, and we're just not going to do a deal to get a deal done. Now last, the process of selecting a new CEO is nearing completion. I'm going to turn the call now back over to David for more operating details. David?

Thanks, Bob. Evolution Petroleum continues to be in great financial shape with a pristine balance sheet anchored with $30 million in cash and no debt. In the quarter, we continue a long trend of consistent financial results with earnings, free cash flow and continued buildup of our working capital, all the while maintaining a quarterly cash dividend. We reported 9.5 million in top line revenues despite double-digit decreases in commodity prices in both the sequential quarter and the year ago quarter. This result is largely due to stable 100% liquids production from the enhanced oil recovery CO2 flood project at Delhi Field and the continued strength in the premium Louisiana Light Sweet oil, which is sold into the Gulf Coast market. Looking forward, the April 19 realized oil price came in about 9% higher month-over-month, and it appears that the LLS premium will continue to remain positive through our fiscal fourth quarter ended June 30, 2019. The company is on track to once again post very nice full year financial results for our fiscal year ending June 30, 2019. In the current quarter ended, total production volumes tallied 2,016 BOEs and were essentially flat compared to the prior quarter and a 7% increase compared to the year ago quarter. As expected, the oil production from the infill drilling program had contributions from all 9 of the producer wells and 2 injector wells at quarter end. Furthermore, as a result of minor modifications at the Delhi NGL plant, the resulting improvements have increased daily rates in the quarter and into our fourth quarter. Average realized oil prices were $59.12 a barrel, an 8% decrease from the prior quarter. Average realized NGL prices were $16.30 per BOE, a 27% decrease from the prior quarter. As Bob mentioned in his reminder, we elect to remain unhedged, which bodes well currently in the current strengthening oil markets we're seeing today. Total CO2 cost at Delhi, which accounted for 49% of total production costs this quarter, increased 25% to 1.9 million compared to the prior quarter. This was due to higher injections of CO2, which led to a 36% increase in purchased CO2 volumes quarter-over-quarter. We're up to approximately 103 million cubic feet per day. We anticipate the operator will maintain this level of CO2 purchased volumes into our fourth quarter. Somewhat mitigating these costs was the 8% decline in realized oil prices, which is contractually tied to our cost of purchased CO2. Other lease operating expenses were essentially flat quarter-over-quarter at 1.9 million at quarter's end. Total lifting cost for the quarter was $20.91 per BOE, an increase of 13% from prior quarter, largely due to the aforementioned increase in CO2 costs. The Delhi Field, our foundation asset, with revenues in excess of $52 per BOE continues to generate high operating margins for us of over $31 per BOE in the current quarter. Capital expenditures at Delhi was modest at just under $700,000 net to us, the majority of which was for trailing infill drilling costs and for workover and conformance projects, which are always ongoing. The anticipated CapEx for the remainder of our fiscal year is estimated to be $0.5 million. The operator has announced very modest capital development plans for the balance of calendar year '19, subject to increase based on oil prices. We continue to manage our G&A expenses reporting a 5% decrease to $1.2 million for the current quarter. The company remains committed to returning cash back to our shareholders as the Board of Directors declared this week a $0.10 cash dividend for the June quarter. The dividend rate is currently $0.40 per annum, which computes to a robust 5.6% yield based on yesterday's closing stock price. Also, as a reminder, we do have in place a share buyback program, which may be utilized when market conditions warrant. Our liquidity position remains excellent with working capital increasing to over $31 million at quarter end. Our undrawn reserve base credit facility is set at an elected amount of $40 million, which was recently reaffirmed by the bank. The company remains well positioned to fund future development of Delhi, fund the dividend program and to pursue new growth opportunities. This concludes our review of financial results and operations for our fiscal third quarter ended March 31, 2019. In summary, we remain focused on delivering a sustainable dividend yield to our shareholders while seeking opportunities to maintain and grow production. I would like to now turn the call back over to Bob for some closing remarks.

Thanks, David. As we discussed and I've repeated in past calls and investor conferences over the last year, the company is actively seeking to acquire additional long-life, mostly developed, producing reserves that will provide diversity while supporting and growing our dividend. Now, this effort is very disciplined. We're not going to take any undue risk or excessive leverage. We're only going to pursue those opportunities that fit our very specific criteria of location, fit and appropriate risk/return ratio. With our cash resource and untapped credit line, we're uniquely positioned to pursue these kind of opportunities. And with that, I think we're ready to take questions. Operator, you can open the line.

[Operator Instructions] We'll take our first question from Bruce Brown with Brown Capital Management.

I wanted to -- if you would be willing to make some comments on the undrilled part of the Delhi Field in terms of what the -- I'm assuming the operator is going to drill in the more productive parts of the Delhi Field. I don't know if that's correct or not. But are there -- what is the upside going forward or potential upside going forward, looking out 4 or 5 years?

Sure. It's probably not totally correct to say they've been drilling the best part of the field. They've mostly been drilling on -- developing the field on a consistent basis from southwest to the northeast. There's been four major phases of development to date. The last phase was done a couple of years ago, then we did conformance infill over the last year or two. We have one more phase to do, which we're now projecting to be in our fiscal 2020 period, probably more like the spring of 2021 calendar year. That's just within our proved reserves. As under SEC rules, you can only call undeveloped reserves proved if they're in your plans and funded over the next 5 years. And so on that restriction, we only have one more major phase left. However, we have three areas of additional development that are not proved because they're not within that 5-year window. And they're not in the 5-year window because they -- if we did it now, we would have to expand our plant facilities. And neither we nor Denbury think that's efficient and economic use of our capital to do that. We'd rather fold those other projects in overtime as we get additional capacity within the plant. There is the far eastern part of the field, which is on the other side of the town of Delhi. Now that's going to probably require a steady oil price north of $60 that we can count on, maybe in the $70 range. In addition to that, we have the Mengel unit, which is actually real close to the existing plant facility to separate reservoir and unit that we and Denbury acquired a couple of years ago. And that's a nice little addition. And then we have some thinner reservoirs on the south side of the field that on their own aren't economic to develop if you had to develop -- if you had to add the plant facilities for it. But as an add-on, they appear to be quite attractive. So that is also in the expectations. But I think the safest way to look at those -- as I say, those are projects that are all going to be more likely added in the next decade, say, sometime in the mid-2020 time frame. So from that perspective, what we're really looking at is those kind of projects would be weighed to maintain production in the current range for -- at a very extended long period of time, well in the 2020s and pushing to the end of that decade. If we could do that, I think we and Denbury would be pretty happy with that. So we think there's a lot of upside, but there's only one major phase development that's in our proved undeveloped bucket.

I have one other question. Denbury was quite interested in getting into the Eagle Ford because of the potential EOR that they could apply there. And I'm wondering what, if any -- have you looked at any potential deals in the Eagle Ford? And is that acreage just high priced at this point? Or are the prices coming down a little bit because everybody is focused on the Permian? And some -- I think my sense is some companies are willing to sell their Eagle Ford acreage to move more into the Permian. I don't know if that's correct or not. But what's your assessment?

My assessment is that the Eagle Ford is still a very hot commodity, and the reason being that it's location close to the coast line mean that you don't have the severe price discounts both on oil, but especially on the gas. Because right now, gas coming out -- natural gas, which is associated gas coming out of the Permian, in some cases, companies have to pay the traders and the pipeline to take the gas. That doesn't do much for your economics on drilling. So as a result, the Eagle Ford is, I think, is still considered to be a very attractive -- one of the better places for companies to invest money. And you have some very large players in that area. We're not going -- as a rule, our focus is on acquiring assets that are currently developed for the most part, some additional upside through drilling with the idea of being that it's HBP, or held by production. Therefore, there's no ticking clock on leases where we can control, to a large extent, as much as possible the drilling pace. We don't want to get into any kind of a project that has a huge CapEx program and then wait -- you have to wait years for it to pay off. We're just not in that. We're -- our focus is on what does the deal do, what does the transaction do for our dividend, which means we need near-term cash flow whenever we expend capital. So getting into a pure play, development play, whether it be an EOR or whether it be a shale play where you're primarily drilling wells, that isn't our cup of tea.

All right. One last question, which I just thought of actually. What do you think will happen to the LLS premium when all this pipeline capacity comes on that will take oil out of the Permian to the Gulf Coast? What's going to happen to -- what do you -- what's your best guess on what happens to that premium?

Well, when people ask me what the price of oil is going to do, I tell them I'm absolutely positively confident that the price of oil is going to change. The premium, I think, is in a similar vein. I think we'll always have premium for the most part, except for very short-term anomalies, but we have a very unique position. We're close to multiple markets. We're attached to market by pipeline, our oil done truck. It's high-quality crude. It's 43, 44 gravity. It's light sweet. It's something that is in demand. And we compete against imported oil. So the oil that you're talking about out in West Texas, that isn't necessarily the highest quality, and that oil has to go, what, 500 miles to get to market by truck, by rail, by pipeline or whatever. So we're always going to have a transportation advantage. We have generally a quality advantage over most of the close crews, a lot of those crews. So I think we'll always have some premium. Now is that going to be the current wide premium? That will eventually likely go away. But keep in mind that those premium or the discount that West Texas has is driven by that last barrel compared to capacity of the pipeline. So if production is slightly -- is approaching the pipeline capacity or excess by a barrel, that drives your price down or the discount up. We don't have that issue. So I think we're going to be in good shape. I feel pretty good about it. Are we going to maintain the current, what, $8 premium? Probably not, but I think we'll maintain a nice premium over the long term.

Mr. Joe, there appears to be no further questions at this time. I'd like to turn the call back over to you for any additional and closing remarks.

I'd like to thank everybody for listening in today, and feel free to contact us with any questions at any time and look forward to seeing you guys out on the road in the near term. Thank you.