Evolution Petroleum Corporation (EPM) Q4 2020 Earnings Report, Transcript and Summary

Good day, ladies and gentlemen and welcome to Evolution Petroleum Fourth Quarter and Fiscal Year End 2020. All lines have been placed on a listen-only mode and the floor will be open for questions and comments following the presentation. [Operator instructions] At this time, it is my pleasure to turn the floor over to your host, David Joe, Chief Financial Officer. Sir, the floor is yours.

Thank you. Good morning and welcome to Evolution Petroleum’s earnings call for our fiscal year end 2020 and our fiscal fourth quarter ended June 30. We will discuss operating and financial results for the fiscal year and fourth quarter as well as year end reserves. I am David Joe, Chief Financial Officer for Evolution. And joining me on the call today is Jason Brown, President and Chief Executive Officer. 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 October 10, 2020. 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 and 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. Since detailed numbers are readily available to everyone in yesterday’s news release, this call will primarily focus on key results, volatility in oil prices and how that impacts us, our typical update on operations and our plans for fiscal 2021, including anticipated capital spending. I would now like to welcome and turn the call over to our President and Chief Executive Officer, Jason Brown.

Thank you, David. Good morning, everyone and thanks for joining us today on Evolution’s year end and fourth quarter fiscal 2020 earnings call. Overall, fiscal 2020 has been an unexpected and challenging year for everyone and to that I wish you all your families and businesses the very best and staying safe as we all move forward through these unprecedented times together. As you know, it’s been particularly difficult time in the oil and gas sector as the global COVID pandemic continues to disrupt the balance of oil in supply and demand. As I stated last quarter, we took immediate steps to ensure our employees’ safety and our financial security. We have continued to focus our efforts on implementing additional cost-cutting measures to better protect our investors and ensure long-term sustainability. We are well-positioned to take advantage of potential opportunities that arise in these turbulent markets and remain focused on creating long-term shareholder return. With that, I am pleased to announce our ninth consecutive year of positive earnings for the company. As of June 30 after funding all operations for fiscal 2020, we remain debt free at $19.7 million in cash and an un-drawn bank revolver. We continue to concentrate on cash flow and overall shareholder return. We provide an attractive cash return to shareholders as we have now paid out our 28th consecutive dividend and returned a total of $10.7 million in fiscal 2020 to common shareholders in the form of a quarterly cash dividend. This marks more than $70 million in cash dividend since the inception of the dividend program in December of 2013. As previously reported, we recently went through our annual year-end reserves process, which was impacted by the lower price environment as we expected. Our reserves were once again evaluated and determined by DeGolyer & MacNaughton, an independent reserve engineering firm. For the year ended June 30, 2020, Evolution’s proved reserves, 100%, which are all oil and natural gas liquids, totaled 10.2 million barrels of oil equivalent, MMBOE. With approximately 83% of that being PDP and the remaining 18% being PUD. That is a 13% increase from the previous year, including fiscal 2020 production of approximately 745,000 in BOE. This increase was primarily due to the strategic acquisition of Hamilton Dome field that we completed in November of 2019. Despite acquisition, we anticipated the reserve of Hamilton Dome to be a larger impact as previously stated, potentially closer to 30% of that. Responding oil – lower oil prices in March, our operator in Hamilton Dome shut-in [indiscernible] to keep deals to close cash flow positive as possible. Although many of the wells have returned to production and as prices improves over the summer, as of June 30, approximately 25% of the wells remain shut in. The lower historical production curve combined with a lower SEC average price resulted in the field reaching its economic limit sooner than it had when proved reserves were estimated at the time of acquisition. These shut-in wells will be brought back in – brought back online as commodity prices increase and so we look at these barrels more delayed rather than loss. We have been very impressed with Merit’s operational team and their focus to optimize the field to be as economic as possible. At Delhi, we have positive revisions in NGL volumes due to the change in methodology by D&M forecasting the NGL stream independently of the oil forecasts, as they are really a function of the constant recycled gas to the plant. In July of 2020, Denbury Resources, the operator of our interest at Delhi field announced that it had entered into a restructuring support agreement under Chapter 11 of the bankruptcy code in Texas. Denbury subsequently announced on September 3 that its plan to eliminate $2.1 billion of its bond debt has been confirmed by the court. This will substantially reduce its debt, it will strengthen its balance sheet and free up capital for investment in properties such as Delhi. We are encouraged by our continued conversations with Denbury and believe the Delhi Phase 5 expansion will begin later in our fiscal 2021. We further expect resumption of historically beneficial conformance expenditures to improve the CO2 flood performance. With that, I will now turn the call over to David to run through our financial highlights and then I will wrap up the call by speaking briefly about our strategy outlook and the M&A landscape. David?

Thanks, Jason. I will share highlights of our financial results for our fourth quarter and fiscal year end. Please also refer to our press release, as I mentioned yesterday for additional information and details and be on the lookout for our Annual Report on Form 10-K to be filed shortly. Our fiscal fourth quarter ended June 30, 2020 was financially challenging due to extreme oil price volatility and steep declines in oil prices caused by geopolitical factors and exacerbated by the global pandemic. Our realized oil prices were down approximately 50% from the prior quarter ended March 31, 2020, which resulted in about a 56% decline in oil revenues partially offset by a 9% decline in operating costs. This all resulted in a quarterly net loss of approximately $2.3 million or $0.07 loss per share down from net income of $3.7 million or $0.11 per share in the prior quarter. Included in the fiscal fourth quarter was a $1.4 million net loss on derivative contracts for the fixed price oil swaps entered into in April of 2020. In the quarter, we recorded realized gains on derivative contracts of $0.5 million, but also recorded an offset of mark-to-market unrealized loss on derivative contracts of $1.9 million. Although Evolution does not routinely and typically employ hedging strategies, the company hedged as a partial price protection to enable it to maintain its current financial strength through the rapidly changing and uncertain economic periods faced in the quarter. Total BOEs in the fourth quarter were 1,918 BOEs, down 11% from 2,164 BOEs in the prior quarter. Our Delhi production was impacted by the lack of new CO2 purchases, the deferral of conformance capital by the operator in normal field decline, while Hamilton Dome field was impacted by temporary shut-in of uneconomic wells due to lower realized oil prices in the field during the quarter. Few operating highlights in the fourth quarter include lower leased operating expenses by 41% to $2.3 million, down from $3.9 million in the prior quarter, primarily driven by lower CO2 costs and cost limiting strategies implemented in both field operations. Our lifting costs per BOE were $13.09, down 33% from 1,956 per BOE. This was largely due to zero CO2 purchases at Delhi for the quarter caused by the shut-in of the pipeline for repairs and also by a 26% decline in other lease operating expenses. We ended the quarter with $21 million in working capital, of which $20 million was in cash and we remain debt free as Jason mentioned. In the quarter, we also completed the remaining capital expenditures for the water curtain program and related infrastructure preceding the plan at Delhi Phase 5 development. Our G&A expenses decreased 30% to $1 million, down from $1.5 million in the prior quarter, primarily due to a true-up adjustment for reduced short-term incentive payouts and a decrease in consulting expenses. It should be noted that the non-cash G&A expenses accounts for approximately 35% of total G&A expenses in this period. Now, looking at full year fiscal 2020 results, we recognized net income of $5.9 million or $0.18 per common share. We have returned $10.7million in cash dividends to shareholders and investing an additional $2.5 million in stock repurchases throughout the year. We reported $12.4 million of cash flow from operations for the full year and internally funded all operations, including $11.8 million of capital spending, including the acquisition of the Hamilton Dome field. As we mentioned, we ended the year with $20 million in cash. Total gross oil production year-over-year was up 7% to almost 7,000 barrels of oil per day from 6,500 from a year ago. NGL production was down 6% to 1,106 BOE per day from 1,171 BOE per day. On a BOE basis, total production is up approximately 5% year-over-year. The inclusion of Hamilton Dome albeit for only 8 months attributed to the increase in oil volumes offset by lower production at Delhi for the reasons previously mentioned. Our total revenues for the year decreased by 32% to about $30 million. This decrease was primarily driven by a 32% decrease in the company’s average equivalent price per BOE to $39.74, down from $58.50 in the prior year. Full year lifting costs per BOE was $18.13 down from $19.31 from the prior year. The decrease in total production cost was primarily due to a 48% decrease in CO2 costs partially offset by 32% increase in other lease operating costs. The decrease in CO2 costs was largely due to a 39% decrease in purchase CO2 volumes together with a 14% decrease in price per MCF associated with a lower realized oil prices at Delhi. Note that, that’s a natural hedge we have at Delhi with as low oil prices – of the CO2 is priced – indexed on the price of oil. The increase in other lease operating costs is primarily due to the acquisition of Hamilton Dome field in November, while Delhi’s other lease operating expenses decreased by 6%, impacted by cost control measures, because of the recent decline in oil prices. Full year G&A expenses increased slightly to $5.3 million from the year ago primarily due to higher non-cash and stock-based compensation expenses related to new grants associated with the hiring of a new executive officer. This increase was partially offset by an overall decrease in activity as a result of the recent decline in oil prices. Again, non-cash unit expenses accounted for approximately 24% of total G&A expenses in this period. In the fiscal year, we have a net income tax benefit of $2.2 million primarily due to enhanced oil recovery tax credits related to our interest in the Delhi field. Net income to common shareholders again was $5.9 million or $0.18 per common share. Although this represents a large decrease from the prior year, this marks our ninth consecutive year to report net income to our shareholders, which speaks to the quality of our assets. Full year capital expenditures were $11.8 million and this consists primarily of $9.3 million of cash for the acquisition of Hamilton Dome field, $0.9 million of non-cash asset addition related to the Hamilton Dome asset retirement obligation, and about $1.4 million spent at Delhi for completing the existing infrastructure projects in advance of Phase 5 development. We expect to continue to fund future development cost at Delhi and Hamilton Dome with cash flow from operations in our working capital over the next 12 months. The company remains committed to returning cash to our shareholders. And as Jason mentioned, we have returned over $70 million in dividends to our shareholders since inception in 2013. Our dividend remains very attractive with a current yield of 3.8% based on yesterday’s closing stock price. Our liquidity position remains healthy with cash on hand, access to an undrawn credit facility and an effective shelf registration statement, under which the company may issue up to $500 million of new debt or equity securities. We continue to be under-levered and remain in an excellent financial condition and are uniquely positioned to pursue opportunities. This concludes our review of financial results for the fiscal year ended June 30, 2020. I will now turn the call back over to Jason for additional remarks.

Thanks, David. It is a priority for us to invest in the working relationship we have with our operators. I am pleased with the substantial dialogue we have been able to engage in with both Denbury and Merit regarding a proper balance on reservoir integrity and cost control in both fields, especially these past few months. Looking at the future of our current assets and based on recent discussions, our expectations are the emergence of Denbury from the restructuring process will bring about the resumption of conformance work-over projects, which we are very happy about and will likely incur additional maintenance capital expenditures. Although, these will primarily be at Delhi field, we anticipate Merit also easing back into economically viable projects through the remainder of our fiscal year. Such amounts are not known or approved yet. However, we expect expenditures to run in the $750,000 to $1 million range over the next 12 months, net EPM. In addition, the company has planned for expenditures of approximately $1.9 million again net to EPM in fiscal ‘21 to begin the development of Phase 5 at Delhi field, which is expected to commence in the company’s fourth quarter. Phase 5 development costs net to Evolution are expected to total approximately $8.6 million. Again, that’s us with $3.7 million of that to be incurred in fiscal ‘22 and the remainder over the next couple of years. These projects all focused around the strategy to continuously extend the life of our reserves and have been very successful over the past few years largely interesting the natural decline. Finally, although we are very pleased with the forecast of much needed additional capital investment in our current assets, we continue to selectively look for opportunities where we can take advantage of our financial position and add additional assets that will further grow and diversify the company. The acquisition of Hamilton Dome last November was a complimentary asset at Delhi field that strategically diversified our asset base. It fits with our strategy of having long-life low decline assets and also represented an important step toward our goal of growing our business. We continue to look for additional low production decline long-life reserves to add to our assets and will contribute to our dividend for years to come. I am excited about the potential that we are beginning to see in the marketplace and confident in our strategy moving forward. We are in a great position and I look forward for the future of Evolution Petroleum. With that, I think we are ready to take questions. Operator, please open the line for questions?

Thank you. [Operator Instructions] And our first question comes from John White from ROTH Capital. Go ahead, John.

Good morning, gentlemen.

Hi, John.

Good morning, John.

On the 2021 CapEx, is that all going to be directed at the Phase 5?

Well, we anticipate about $1.9 net to us within our fiscal ‘21. Again, I think they are going to start that project in about April or May. So, we are anticipating $1.9 million of that to be net to us. I think on top of that $1.9 million between Merit up in Hamilton Dome and Delhi, there is probably going to be about another $1 million net to us of conformance work and that sort of thing. So, all-in kind of in the two 9s, somewhere sub 3 for total CapEx for ‘21?

Thanks. And will there be some new PUD locations drilled in Phase 5 during your fiscal 2021?

Yes, we anticipate the drilling to begin like I said, in May and June, they generally take. They do that kind of in phases. So, we anticipate the drilling kind of happening through the full calendar of ‘21 in to our fiscal ‘22. Again, fiscal ‘22, we think probably around 3.6 to 3.7, net to us, so, but yes we anticipate them starting drilling in ‘21 in May or June.

Okay. And on the CO2 pipeline, are you going to be responsible for any of the repair costs on that or is that all going to be borne by the operator of the line?

No, I appreciate you asking that. I am not sure that we have made that clear. So thank you for that. That CO2 line is operated and owned by Denbury. So we don’t actually purchase anything until it gets to our field. So that’s all operated and owned by them. So there is no costs associated With the repairs that are going to be paid by us. Now we did go they are anticipating that is coming online around October 1, somewhere in the first couple weeks of October, we actually went out there and to see how they were doing in progress, because some of these projects slide and we think it’s going to be July and then it goes to August and then it goes to September, but we are very pleased that they are out there on Saturday and had multiple crews working and it looks like they are making a lot of progress. So we are pretty confident that is going to be back up and running shortly, but again, no cost to us.

And it is on management, I like it. Alright, I will turn it back and may come back for a follow-up.

Yes. Thanks, John.

Next question comes from Jeff Grampp from Northland Capital. Go ahead, Jeff.

Good morning guys.

Hey Jeff.

Jason for Phase 5 can you remind us kind of production expectations that you have for that, understanding that, I imagine it is going to be kind of a slower ramp to a peak of any kind of incremental not, a shale well type of profile, but what kind of, I guess gross or net production response do you expect? And do you have a sense either based on your own work or conversations with Denbury, kind of the oil price that you would need to see for that to move forward? It sounds like you guys have good confidence that project is going to happen here. But I guess just to kind of prepare ourselves in terms of sensitivities to oil prices for in that project may or may not make sense.

Sure. Well, first of all, production, it’s probably going to make sense over time as we get closer to get a better sense of that. It will be a slow ramp up, like you said. So as John asked when does the drilling start? Drilling is going to start in May or June and when there is 15 wells involved in this. Some injectors some producers and that would probably be through the course of at least full calendar ‘21 and into the start of calendar ‘23. They generally don’t, as soon as they start drilling it, they like to kind of get through the program before they really start ramping it up because the overall process is the combination of injecting new CO2 in different places and you don’t want to start producing without the injection, you don’t want to start injecting without the producers. So it’s a little bit more of a batch process. And then once you start injecting, you are basically increasing pressure support and it kind of slowly ramps up over another six months, so we wouldn’t anticipate much of any production to be added from Delhi in calendar of ‘21, but really, we would expect that to be starting in the calendar of ‘22. So the overall peak we have seen several 100 barrels a day net to us over the previous test programs and we would anticipate this to be – it’s a pretty substantial – Phase 5 is pretty substantial, we would expect it to be quite a bit, but again, that’s going to kind of ramp up over about a 6-month period and then get to a peak and then sort of falloff in kind of single-digit decline. So it will be a nice arc over the 2 to 3-year period.

Okay, perfect. That’s really helpful. And my follow-up kind of on the acquisition side, you guys ended the years, as David said $20 million of cash, but then you have this Delhi CapEx that you will be incurring over the next couple of years. So I guess just kind of wondering as you guys kind of think about the dry powder, are you effectively I guess earmarking a portion of your cash for that CapEx or would you really be that is kind of unencumbered, investable, liquidity. And I guess just ultimately trying to figure out, how the size of your acquisition universe has maybe changed, given that you have Hamilton Dome, obviously, we are in a newer world today versus 9, 12 months ago, but any thoughts on that would be great?

Yes, sure. We are going the use the cash to the CapEx for sure. I don’t think that widely limits our acquisition size. We were really looking to put the capital to work and I didn’t quite answer your first question there on the CapEx in terms of what price makes sense. I do want to say that according to Denbury, Delhi has one of their lowest, if not the lowest lifting cost field in all of their portfolio. So as they try to recover sort of emerging from this restructuring, I would think that Delhi is going to be pretty top priority for them. So even in the $40 range, it makes sense it makes money at Delhi. So if that’s any indication on Delhi but along that same lines if we have cash sitting in the bank, it definitely makes sense for us to use that for these CapEx programs. And I wouldn’t – I don’t really think of it in terms of being set aside, per se, we are more than willing to go into a revolver to make acquisition deal size. I think a revolver right now is $27 million now, and $19 million in cash. So that’s about $47 million to $50 million of liquidity there to do all of these operations. This covenants there with the bank, so depending because the price depending on where we are at with those covenants, I am not sure that we can draw the full $27 million dollars at this time, but if we were looking at making an acquisition that would be brought into the evaluation as well. So it is on table, David, do you have any thoughts on that.

Got it. That’s perfect. And if I can just sneak one more in here, as you guys are expecting the Co2 line to get repaired and back up and running here, not too shortly. Should we expect injections maybe in kind of a near-term to maybe go above from normalized levels to kind of play a little catch up or re-pressurize the field? Or do you guys have any sense I guess as far as what purchase Co2 volumes could be once that gets back up and running?

Yes, I think before we went down, we were kind of in the 82 million to 83 million cubic feet a day, 88. And I would anticipate seeing closer to 100 range, at least in the 90s. It would make sense for us to do a little make up pressure support. We are anticipating that I don’t have a real good number for you, but it’s not going to be any sort of crazy amount, but I think they will definitely be buying a little bit more than normal in the short-term to kind of make up some of that.

Okay, got it. That makes sense. That’s it for me appreciate taking.

Yes.

And our next question comes from David Snow from Energy Equities Incorporated. Go ahead, David.

What oil price would you bring back to your remaining shut in Hamilton Dome production?

Merit has got a list of wells that kind of – and they make their decision based on that back receive price. And so right now we are at a kind of a $35 net back received price because the differential based off of the WCS is somewhere around $10. It’s actually shrunk a little bit as prices have gone down. When we were in the $55 range, we were anticipating a differential somewhere in the netback receive price around $12 under WTI, including all our transportation fees and whatnot. But that shrunk a little bit, which is good news. So that I think that’s kind of in the $45 range, which $43 range WTI gets us to where we are cash flow positive for those wells. There’s about 25% of the wells that are still shut in. So I think you are probably going to need to see 50, somewhere in the 48 to 50 range to get it fully back up and running. but again, we see those as more delayed barrels, we are – we will get them doesn’t make sense to produce them.

What do you just say shut in currently? How many barrels

30 wells currently shut in making up about 25% of the 88 production.

Okay. Okay, thank you.

Yes.

And our next question comes from Andrew Bond from AGP Alliance Global. Go ahead, Andrew.

Hey, good morning, guys. Thanks for taking my questions.

Hi. Andrew.

Hey, first of all, I just wanted to get some clarity on that Phase five development CapEx number you are budgeting is that total $8.6 million number inclusive of the $1.9 million budgeted in fiscal fourth quarter ‘21?

That’s right. Yes. It is about $1.9 in our fiscal ‘21, about $3.6 or $3.7 in ‘22. And then the remainder over the following two years after that but net total around $8.6.

Okay, got it. Thank you, and then maybe just touching on M&A. Obviously, Evolution has been historically liquids focused and you guys have 100% liquid assets. As you look in M&A opportunities that diversify the asset base and continue to support the dividend. Are you also considering maybe gas to your assets? Can you provide a little color about how you are thinking about your reserve of production mix going forward?

Yes, we are definitely looking at gases actually we are looking at several gas fields now. I guess the overarching thought for us there, there’s a lot of gas that we really like we like to commodity and we also like its nature for our business strategy, meaning gas is a lot cheaper to lift. And so it gets into a very flat long-life production mode. And if you think about the economics of physically lifting all the fluid from oil versus gas, it’s just everything’s a lot cheaper. So there’s a lot we like about it. However, gas is kind of a midstream marketing play you have got that can really make you or break you, as many companies have found out. And so we are probably going to focus our efforts close to take away capacity – take away and market. So what does that mean? We like these Texas close to the Carthage pipeline coming straight down to Sabine Pass. We think our differentials there will be probably better than if we were to move up in Oklahoma or move out west, to compete with a lot of the gas coming in from the Permian associated gas. That’s lower right now and it’s ease back. But Corpus and Houston are going to get jammed up. If drilling resumes in the Permian, which we assume that it will, as soon as prices get back to any sort of reasonable level. So we would like not to be competing with all that associated gas coming in from the west. So we like East Texas, we like Louisiana. We like close to sales markets. So it makes sense?

Yes, that’s great color. Thanks, Jason. That’s it for my side. Thanks for taking my questions.

Thanks, Andrew.

And our next question comes from Rich Howard from Boiling Point Resources. Go ahead, Rich.

Good morning. I would like to ask you about the derivatives contracts. Do you have any after January of 2021?

We know – they end 12/31/2020, so just another few months.

And assuming the current level of WTI should we assume approximately $1.5 million loss each quarter for the last – for the next two reporting periods?

That’s a good question. Rich. This is David. So the out months contracts for September, October, November, December those are – those prices haven’t settled yet. We have liabilities owed for July and August. We don’t report interim numbers, but clearly the oil prices are above our fixed price swap that we entered into 32 settlement in July and August is a bit higher than that. So we have liabilities due for July and August and out March and September forward or remain to be settled. If you have seen the last couple of days the oil price volatility we have got several dollars on WTI. I know that helps you or not?

Sure. So I am using a $1.5 million each quarter for the next two quarters. That doesn’t sound silly.

For the year I can’t speak to the out months from September on but for July and August. We have got two months settled in it’s not $1.5 million.

Okay, great. And were there any unpaid bills from Denbury? Obviously you have a royalty on the field. I don’t know exactly how it’s structured. When they declared bankruptcy, did they not pay a payment or anything of that nature?

No, it’s been business as usual with Denbury. We receive our share of revenues as scheduled each month, twice now since their announcement of bankruptcy. And similarly, we have paid our share of – our bill our jib to them. So we have seen no disruption from Denbury’s operation since their announcement of bankruptcy.

That’s an important thing on oil companies. If it goes through that they have got to have a what they call Day 1 motion, because a lot of times if you file, it triggers an automatic stay of accounts and that was of particular concern for us on the 31st of July. Before we paid our jib, we wanted to make sure that they were still going to be able to do that and they are sure that they weren’t trying to get out of midstream contracts or going to shortchange any vendors and it’s been flawless. So, that’s worked really well.

Thank you very much. That’s very important. Okay, thanks. Thanks for taking my questions.

Great. Thank you.

Our next question comes from John White from ROTH Capital. Go ahead, John.

Thanks again. Just wondering in previous years, have there been any PUD locations drilled on the Phase 5 acreage?

No. We did some advanced work with the water curtain to be able to control the – that was a setup pre-Phase 5 to make Phase 5 more efficient to keep the Phase 5 production from going where we wanted to, but that’s all – those aren’t producers.

Okay, thank you.

Thank you. This was the last question. At this point, I would now like to turn it back over to management. I am sorry. [Operator Instructions]

Any questions? Okay. Well, thank you for your participation. Please feel free to contact us with any other questions. I look forward to providing you with an update in December.

And that does conclude today’s conference. We appreciate your participation. You may disconnect your lines at this time and have a wonderful day.