Evolution Petroleum Corporation, Inc.

Good afternoon and welcome to the Evolution Petroleum Fiscal Fourth Quarter 2023 Earnings Release Conference Call. At this time, all participants have been placed in a listen-only mode and the floor will be open for questions and comments after the presentation. I will now turn the call over to your host, Brady Hudson, Investor Relations Manager. Please go ahead.

Thank you. Welcome to Evolution Petroleum's fiscal full year 2023 earnings call. I'm joined by Kelly Lloyd, President and Chief Executive Officer, Ryan Stash, Senior Vice President, Chief Financial Officer and Treasurer, and Mark Bunch, Chief Operating Officer. We released our fiscal 2023 full year and fourth quarter financial results after the market closed yesterday. Please refer to our earnings press release for additional information concerning these results. You can access our earnings release in the Investors section of our website. Please note that any statements and information provided in today's call speak only as of today's date, September 13, 2023, and any time-sensitive information 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 the risks, assumptions, and uncertainties as described in our SEC filings. Actual results may differ materially from those expected. We undertake no obligation to update any forward-looking statement. During today's call, we may discuss certain non-GAAP financial measures, including adjusted EBITDA and adjusted net income. Reconciliations of these measures to the closest comparable GAAP measures can be found in our earnings release. Kelly will begin today's call with a few opening comments, followed by our operational results from COO Mark Munch, and then Ryan Stash, CFO, will review our fiscal year financials before turning back over to Kelly for closing comments. After our prepared remarks, the management team will be available to answer any questions. As a reminder, this conference call is being recorded. If you wish to listen to a webcast replay of today's call, it will be available on the Investors section of our website. With that, I will turn the call over to Kelly.

Thanks, Brandi. Good afternoon, everyone, and thanks for joining us for today's call. We appreciate everyone's interest in our reporting of our successful fiscal 2023 operational and financial results. However, before we begin to discuss our recent results, I'd first like to make some general comments related to the announcement we put out this morning with PDEVCO concerning our definitive participation agreement to jointly develop the Chavarru oil field in the northwest shelf of southern New Mexico. It's a conventional oil-bearing San Andres play in the Permian Basin located in Chavez County. We're proud to partner with Pedevco, a company that shares our values and goals of providing superior total returns to shareholders. I will let Mark go into the details of the strategic partnership later, but I want to point out the biggest highlight of this arrangement first. The deal adds a new and exciting arrow in our quiver of capital allocation opportunities. In the past, in order to grow our production and reserves, We have relied heavily on the A&D market. While we've been quite successful and plan to continue that strategy, the 80-plus high-quality locations covered by this agreement will allow Evolution to grow or maintain its production and reserves even in times where asset-level transactions are priced at what we consider to be unattractive levels. In turn, we believe this will be highly supportive to our dividend program for years to come. The wells here are 90-plus percent oil and located in the Permian Basin, which is an important market to which we want to be exposed. Now on to our fiscal 2023 results. Our results for the period were solid and continued to demonstrate our assets' ability to generate strong free cash flow. We used our cash flow to once again fund operations, capital spending, and shareholder dividends. In addition, I'm pleased to report that we repaid $21.5 million of debt, again, all from cash flow, and exited the year with a debt-free balance sheet and increased liquidity. We continue generating meaningful free cash flow from the acquisitions completed over the previous years, and we'll use these to continue to fund our strategic objectives. Of course, our ongoing success is a direct reflection of the hard work and accomplishments of our team. I want to thank each and every member of the evolution team for their contributions and continued dedication to driving near and long-term value for our shareholders. During the fiscal year, we paid cash dividends totaling 48 cents per common share. This was 37% higher than for fiscal 2022, which we view as a clear indicator of the growth and strength of our business. Our board recently declared a cash dividend of 12 cents per share for fiscal Q1, 2024 payable on September 29th, marking the payment of our 40th consecutive quarterly dividend. Since the company began paying dividends in December of 2013, we've returned approximately 102.4 million or $3.09 per share of capital to investors. As we have discussed in the past, there are very few small-cap E&P companies that can say they've consistently paid a dividend for that length of time throughout several tumultuous commodity price cycles. We believe this reinforces the strategic view our board takes as we prudently grow the business through the targeted acquisition of solid, long-life, and low-decline assets that will continue to support a sustainable quarterly dividend for the immediate and long-term. In short, maintaining and ultimately growing the payment of a quarterly cash dividend remains front and center for our board and management team. I will now turn the call over to Mark to discuss operations.

Thanks, Kelly. Total production for the fourth quarter fiscal 2023 was 6,484 net barrels of oil equivalent per day, consisting of 1,736 barrels per day of crude oil, 22,462,000 cubic feet per day of natural gas, and 1,000 barrels per day of natural gas liquids. Looking at our fourth quarter results in more detail, oil decreased 6% from 1,856 barrels of oil per day in the prior quarter, primarily due to downtime at the Dell high field, where production was shut in for approximately one week to upgrade the facilities and install a heat exchanger to increase plant efficiencies. Natural gas production decreased 8% from 24,489,000 cubic feet per day or 4,077 barrels of oil equivalent per day in the prior quarter primarily due to downtime in the Barnett shale properties associated with extreme summer weather conditions along with gathering line maintenance and compressor issues. NGL production decreased 13% from 1,156 barrels of NGLs per day in the prior quarter, primarily attributed to downtime at Del High Field properties to install the heat exchanger, perform NGL plant maintenance. At our Barnett Shale properties, our NGL volumes were affected by the same factors that impacted our natural gas production. Looking at our full year results in more detail, total production for the full year fiscal 2023 was 7,104 net barrels of oil equivalent per day, consisting of 1,806 barrels per day of crude oil, 24,956,000 cubic feet per day of natural gas, and 1,140 barrels per day of NGLs. Oil increased 6% from 1,696 barrels of oil per day in the prior year, primarily due to our acquisitions of non-operated working interests in the Jonah Field and the Williston Basin in the second half of fiscal 2022. This increase was offset by the downtime in fiscal 2023 at the Dell High Field, as mentioned previously. Natural gas production increased 28% from 19,564,000 cubic feet per day in the prior year, primarily due to acquisitions of non-operated working interests in the Jonah Field and the Williston Basin in the second half of fiscal 2022. The increase is partially offset by downtime in our Barnett Shale properties as mentioned previously. NGL production increased 14% from 997 barrels of NGLs per day in the prior year, primarily attributable to the two acquisitions in fiscal 2022, offset by decreases attributed to downtime at our Dale High Field, and the same factors that impacted our natural gas production in our Barnard Shale properties, as mentioned previously. Based on discussion with our operators, we expect capital work over projects to continue in all the fields. Overall, for fiscal year 2024, we expect budgeted capital to be in the range of $4 to $5 million, which excludes any potential acquisitions. Our expected capital expenditures for the next 12 months include two new drill wells at Dell Highfield drilled by our operator, Deadberry. As Kelly already said, we're really excited about our strategic partnership with the DEFCO and the Permian. The agreement covers approximately 25,000 gross acres in and around the Chavarru Field in northeast New Mexico. The Chavarru Field was originally developed targeting the San Andres Formation with vertical wells on 40-acre spacing. We view the horizontal development of the San Andreas and the Chavarru field to be very compelling based on extensive vertical well control, the data and results from previous Pedevco horizontal wells, and analog developments of other 40-acre non-water-flooded vertical San Andreas fields. We expect this project will significantly contribute to the success of Evolution for years to come. We expect our capex to increase over the $4 to $5 million budgeted for our existing assets due to drilling and completing an expected three wells in this fiscal year. The ultimate amount of capital spent during fiscal year 2024 for drilling in the Permian will depend on the schedule agreed to with our partner. With that, I will turn the call back over to Ron to discuss our financial highlights.

Thanks, Mark. As mentioned earlier, please refer to yesterday's earnings release for additional information concerning our results. My comments today will primarily focus on financial highlights and comparative results between fiscal 2023 and 2022. During the fourth quarter, we experienced extended downtime in maintenance across multiple assets and were negatively impacted by much lower realized natural gas and NGO prices. However, our fiscal year 2023 results still represented record revenue production and net income. During the past fiscal year, we had solid generation of cash flow, including adjusted EBITDA, which was $60.1 million for the current year, compared to $52.8 million in the prior year, a 14% increase. During this fiscal year, we funded our operations, development capital expenditures, dividends, and share repurchases, all out of operating cash flow, while also paying down debt drawn for our acquisitions. Supported by our continued strong operational and cash flow outlook, we paid a dividend of $0.12 per share in the fourth quarter and declared a dividend of $0.12 per share for fiscal Q1 of 2024, payable on September 29th. Our cash dividend program has been and will continue to be a top priority as we clearly recognize the strategic importance of returning value to our shareholders. We ended the fiscal year debt-free and our borrowing base remained at $50 million. On June 30, 2023, cash and cash equivalents totaled $11 million and working capital was $8.9 million. As a result, total liquidity on June 30, 2023 was $61 million, including cash and cash equivalents. This represents an increase in liquidity of 65% since June 30, 2022. This is a direct result of our targeted and immediately accretive acquisitions over the past couple of years. We are ideally positioned for the continued execution of targeted future growth opportunities that meet our strategic vision. Lease operating costs increased to $59.5 million from $48.7 million in fiscal 2022. Primarily driving the overall increase was the acquisitions of the Jonah Field and Williston Basin which occurred in the latter half of fiscal year 2022. Cash G&A expenses increased 18% to $7.9 million from $6.7 million in fiscal year 2022. The increase in expenses is due to approximately $600,000 in salary and employee benefits from the addition of personnel added since the prior year and $300,000 in professional fees associated with our search for a CEO. Also contributing to the increase are additional fees for accounting audit-related services and public reporting expenses due to the increased size of our company. Net income for the fiscal year was $35.2 million, or $1.04 per diluted share, compared to $32.6 million, or $0.96 per diluted share in fiscal year 2022. I'll now turn the call back over to Kelly for his closing remarks.

Thanks Ryan. We continue to benefit from the targeted acquisitions we have completed over the past few years, and as a result, we enjoy a larger and more geographically diverse asset base and commodity mix. This provides us with a solid platform for significant cash flow generation that we will continue to use to support and enhance our well-established shareholder capital return program. Our shareholders expect a consistent and meaningful cash return on their investment, and we remain committed to maintaining and, as appropriate, increasing our dividend payout over time. As in the past, we will maintain a conservative balance sheet and remain disciplined in our management of capital as we fully recognize the cyclicality of our business. Our ongoing commitment to remaining fiscally prudent was evidenced by our prompt pay down of our debt position following the closing of our most recent acquisitions. As a result, we are well positioned to execute on targeted high rate of return and immediately accretive growth opportunities as appropriate. We will continue to execute our strategic plan focused on maximizing total shareholder returns and optimizing every dollar that we invest. With today's announcement, we have added an opportunity to have a meaningful organic growth component. As with all of our capital allocation decisions, any drilling here must compete with dollars to be used elsewhere, and the nature of this arrangement will allow for that. We are not required to pay upfront for anything other than the acreage cost for the immediate development block which we will be developing next. This is unlike other situations where companies must pay in advance for entry into a field and prepay for well locations. This is a true strategic partnership where development will occur sequentially with the decision moved forward based on success. We and Pedevco expect that this partnership will produce positive results for many years to come. With that, I'll turn the call over to the operator for questions. Thank you.

We will now begin the question and answer session. To ask a question, you may press star, then 1 on your touchtone phone. If you are using a speakerphone, please pick up your handset before pressing the keys. To withdraw your question, please press star then two. Once again, that was star then one to ask a question. And at this time, we will pause momentarily to assemble the roster. And our first question comes from John White of Roth Capital. Please go ahead.

Good afternoon, and congratulations on the Pedevco deal. I agree with you. I think it looks very attractive.

Thank you, John. Hey, John, before we get to your question, can I just make one additional comment? Yes, of course. Okay. So I just want to reiterate – as I've said before, that when we in the board, we set dividends, we do so with a multi-year horizon expectation based on our production and resulting cash flow that is generated from our forecasted pricing and production levels. With this in mind, we fully expect that our cash flow, combined with our pristine balance sheet and our cash and cash equivalents, will be able to more than fully cover our dividend, which, by the way, we just reset at $0.12 per share. Not only do we believe it will fully cover our dividend, it should cover all of our capital needs up to and including any planned drilling activity. We're confident, as you mentioned, John, that this strategic partnership will be highly supportive of our dividend for quite some time.

Okay. I appreciate that add-on. So, regarding the Padevco deal, with respect to capital expenditures, Mr. offered some commentary. However, his commentary was, I would say, highly conditioned or highly qualified. Can you offer any more detail about potential CapEx at the Padevco deal? Maybe put it in terms of a minimum or a maximum or a six-month timeframe or a 12-month timeframe, whatever you're comfortable.

I can. Absolutely. Look, these are fluid, and they're plans that we're going to come up with and finalize with our partner, Padevco. Initially, I'll tell you what we're both thinking on this. We have an initial three well pad, which we're working on. It's been permitted. The expectation is that we want to get to that three well pad sooner rather than later. Again, we need to finalize all the details. In general, the way we thought about this is Basically, again, fluid can change depending on conditions, environments, all this. But essentially about eight wells gross per year is, in general, how we've started thinking about the budget on this together. So again, three wells at roughly $3 million per copy. Our half of that is 4 and 1 half. And we have acreage payments. So we have 4 and 1 half to $5 million. would be our expectation for the initial three-well pad. And then, as I mentioned, the initial goal, again, which is highly dynamic and fluid, and we'll adjust as we go, but at least our initial sort of game plan is roughly around eight wells per year together, which we'd be 50% of.

Well, that's a lot of extra detail, and I really appreciate that, Kellen. So on the maintenance or some of the infrastructure work, let's just make sure we understand. Is the work at Delhi, is that all completed? Is the heat exchanger installed and working?

John, this is Mark Bunch. And the heat exchanger is up and running. The plant turnaround was completed. And so we expect that, you know, that Delhi is back running at, you know, rated load. So we see that Delhi is performing as we would be expected to.

Okay. Thank you. And same question on the Barnett shale with the gathering line maintenance and compressor issues.

The Barnett shale, that was all obviously related to compressor and gathering stuff. we see that that is, we believe that that is kind of, you know, generally on the mend, but as of right now, we don't know whether that is, whether it is completely back up and running as it's supposed to be. Okay.

As you know, John, when it's, you know, 112 degrees in Fort Worth, compressors don't always act and they're going to run into issues, which clearly they did for much of the summer, but I think we're starting to see that get better.

Okay, I appreciate that, and I'll turn the call back to the operator. Thank you.

Thank you.

The next question comes from Jonathan Schaefer of Northland Capital Markets. Please go ahead.

Hey guys, thanks for taking the questions. I'm sure you know this, but it's Donovan Schaefer. So I want to start picking up where Don left off. So we covered the Delhi and the Barnett, but in the Wilson, and this could actually honestly be a data entry error on my part. I haven't been able to double check this, but it looks like the Wilson was down quite a bit too. Am I just wrong on that? I have the Wilson down... something like north of 10%, quarter over quarter. So was there a decline there, or is that just an error in my model? And what was the cause?

Yeah, Don, and this is Mark Bunch. And there was, during one month, we had a downtime on the compression side there, and so it affected NGLs, and it also affected gas production. And that's the main cause of that.

Well, I'm talking about, you're saying this is true for the Bakken, the Wilson?

Yes, yeah, yes, for the Williston.

Oh, really? Okay, also there's the compression issues in both. And also a compressor down in the Barnett. Okay, got it. Yeah. Okay, okay. And then I want to turn to, so for the year-over-year production, and maybe Ryan has this information, but for the full year, you know, the year-over-year production numbers were good and up. But, of course, part of that comes from the Jonah and the Williston acquisitions. you know, having a partial contribution last year and having a full year contribution this year. So is there anything you can give us in terms of to be able to kind of compare apples to apples either, you know, last year versus this year, kind of including those pro forma for the full year last year or stripping them out just like what the apples to apples change in production, presumably some amount of decline. Do you have that information?

Yeah, Don, we haven't done a full pro forma. We tend to look at it sequentially, right, quarter to quarter. And so we can try to come back with you on that for trying to pro forma out those acquisitions or as if we own them the full year. But, I mean, ultimately, I think the, you know, at the end of the day, right, we have seen declines in the assets for natural reasons. But this last fourth quarter, unfortunately, we got hit with maintenance and three of our fields, which are our major asset fields, extended downtime. combined with pretty much the lowest prices we've seen realized in two years. So, you know, unfortunately it hasn't, it hasn't, it wasn't, it wasn't great timing for all of us, but we can certainly get back to you on, see what we think. If you're trying to get to what the actual field decline is, field by field.

Well, we're just getting into kind of your blended decline, you know, factoring out those step function increases from transactions. So I guess you could, if that is something you feel like, you know, the answer to, are we still sitting at a, I don't know, 5% annual decline rate in a business-as-usual situation without incremental acquisitions, or where do you think is the decline rate standpoint?

I think we've got it before to high single-digit to 10% sort of annual decline. Oh, yeah, yeah. I don't think that that's necessarily changed, but the fourth quarter obviously is going to throw some things off when you're looking at decline rates.

Sure. Yeah, okay. And then I also want to, yeah, go ahead.

Just a quick deal, and I want to make sure you understand, like the Williston, that compression issue was resolved also during the quarter. It was just a one-month downtime, and it's back up.

Okay. And so then from a kind of, I mean, I know you don't give guidance, but maybe does it, is it reasonable for us to think there will be kind of like a reversal of things where there's kind of a, I don't know, pop might be too strong of a word, but a movement back up in terms of total production numbers going from this quarter to the next quarter just because a lot of that stuff's been fixed and there's a little bit of an upward movement just to get back onto a normalized decline path. Is that a fair expectation?

Yeah, Don, in order to avoid guidance, we won't say a whole lot on that, but, you know, I think you understand that there were some unique events that happened, so.

Okay. And then I think John did ask about the Epidepco costs associated with that. You may have asked this, too, and maybe I missed it, but just kind of the timeline of when that would start to contribute some amount of incremental production.

So, again, that's something we are working with them on. I think both parties are incentivized and excited to get those initial three-well pad anyway going as soon as is practical, and we're both comfortable doing that. So I'm not going to give you any specific timing, but look, I'm hopeful it will be sooner rather than later and expect that.

And this is similar conceptually to what you guys did in the Williston, right? I mean, there might be some differences to the terms, but the same idea of having a way, an avenue through which you can drive growth when it's not an attractive market for M&A. Is that... appropriate to kind of put the two in the same bucket?

It is, and in our mind, you know, those are, they will compete for capital just like everything else we do with our next marginal dollar. We, at this time, look, we think the economics are very attractive in the Shavaroo field with Pedefco, so that's Absolutely, yes. These are just, it's gone to a point where they've moved to the front of the line. We think they're very good economics.

Okay, okay. That's good. And can you talk about how you sourced the deal? I know that sometimes there can be some interesting nuggets there. Did this come in through any atypical channel? The relationships you already have, they came to you and knew you'd be interested in some conventional stuff. I know this isn't technically EOR, but you kind of

understands you're familiar with this type of taking a second pass at things so yeah how did this kind of come about well um you know it it mostly came about i uh i got a call from uh doug schick at uh at padefco whom i've known for several years we actually used to coach peewee football against each other and i i've known doug and we've we've spoken over the years about various uh business deals, and I believe Doug had an advisor looking in to do something. It was the Roth guys who have been very good for them. It made natural sense. It's nice to do business with someone you can trust.

Okay, that's helpful. All right, I'll take the rest of my questions offline. Thanks, guys.

Thanks, Donovan.

The next question comes from Jeff Robertson of Water Tower Research. Please go ahead.

Thanks. Mark, one question on the downtime. Are you aware of any service interruptions that you expect over the next couple of quarters from your midstream providers at the Barnett Shale?

No, not really.

No. I wish they'd let us know when they're going to do that, but they don't. They unfortunately don't. I mean, I think we talked about this before, right? So, M-Link took over for Crestwood, right, when Crestwood sold the system. And, you know, they've had extended growing pains of trying to optimize, you know, the way they run the area. You know, our operator and partner Diversified has certainly, you know, talked to them a lot. And so, we certainly hope and are expecting them to do a better job going forward. But, unfortunately, they're not going to give us any insight as to when they're going to have downtime or issues, unfortunately.

thanks i've partially read through the operating agreement that i think was filed in an 8k by padevco this morning kelly with respect to the the initial three wells i think it said the goal would be to spud the first one by the end of this year would your expectation be to drill all three of those back to back and then complete them back to back or would it be one well drilled one well completed can you can you talk about how you think about that that initial pad development

I'll let Mark talk a little bit more to that, but look, just from an economic standpoint, drilling them on a pad as a package is a better deal, so that's certainly our expectation.

Yeah, no, they'll be drilled back-to-back and then completed back-to-back. That's the expectation right now because that makes the most economically viable way to do it, and then they'll be brought online at the same time.

In terms of infrastructure, Mark, I know you all would share, I believe, in any infrastructure costs related to the production facilities. Can you just talk about what's in the area that you can move oil into? I know it was developed initially with vertical wells.

Yeah, the plan right now is really not to use any of the vertical well facilities because the horizontal wells are so much more prolific than the vertical wells. So the capital costs that we're looking at are actually involved putting in new infrastructure, putting in new tank batteries also. And we'll optimize that for being horizontal wells.

Mark, from what I've read about horizontal San Andres wells, it's not an unconventional formation in most areas. So the initial decline rate is not as steep as more – as a shale formation. Is that true in this area as well?

Yeah, I would say that typically in a wolf camp, say like in the Delaware part of the Permian where you have the wolf camp, those decline rates are probably above 95%. Here, it's going to be less than that.

Okay. And then just lastly on funding, Kelly, you mentioned in your remarks, or maybe Ryan, In terms of funding the capital program, funding the drilling program with available liquidity, it appears you still will have the flexibility or could have the flexibility to continue to fund the dividend. And so that really shouldn't be at risk at this point.

Yeah, look, dividend is first. So I don't want to put that in the opposite order. So, yeah, for sure.

Okay. I just wanted to make sure that was out there. Thank you.

The next question comes from David Lockoff of Old Mammoth Investments. Please go ahead.

Hey, Kelly and Ryan. How are you guys doing today? Been better. Hey, so I think you've kind of answered these questions, but I just want to ask them again for clarity. So as it related to the downtime, particularly at Delhi, but also in the Barnett, Would you expect that those compression issues being fixed would get production in those particular areas back to where they were in March as we go forward?

So, listen, we do expect as those compression issues get better, you will see better results. So, I'll say that.

Okay. And then for some clarity on the Permian assets, I'm just trying to triangulate a few things that you said. So four gross wells a year is the expectation. And you think you can fund, sorry? Eight gross wells. Yeah, four net. Oh, I'm sorry. Did I say four? My apologies. So four to you. Yes. So you expect that you can fund that and the dividend out of free cash flow under sort of the, if we look at the forward curve for oil and gas today?

That's right. Yeah, no, that's right, David. I mean, when we look at where pricing is, like you said, in the forward curve, you know, obviously assuming oil has already increased from what we saw in the fourth quarter, so have NGLs. And, you know, just kind of an aside, right, NGLs in the fourth quarter were about as low as they've been in a long time, and so that certainly impacts us too. But when you take prices into consideration, free cash so that our other assets generate, plus cash that we're going to get, you know, from drilling the padefco, right? There is some delay there, but we do, you know, we do think this asset becomes self-funding pretty quickly. You know, we don't see any issue covering the dividend, plus funding our proportionate share of eight walls per year.

Yeah, and honestly, that's, just to reiterate, I mean, that's one of the things that, you know, we're excited about with this deal is the money we're spending is goes into the ground and drills wells. We're paying for acreage to get in on a block-by-block basis, but that's a relatively small number. The rest of the money goes into the ground and starts producing oil, again, probably within about, Mark, 60 days? MARK MCQUEEN, Yeah, longer than that, but somewhere, a very reasonable timeframe, maybe three months. MIKE BOYLE, For when the money gets spent to when you start getting revenue from the oil from the wells you drilled. It's not a huge multi-year payback. You've got to pay up front, and then you get payback. We in Pedevco are excited about the fact that the money going into this goes into the ground and starts making oil for both of us.

So under the understanding that there's a delay between when you spend the money and when the oil starts coming, would you expect – that the expenditure of this capital on a pro forma basis would at a minimum offset the declines in the other assets in the portfolio?

So, I'm not sure I'm prepared to go into that level of detail, but look, you're certainly not on the wrong track. Okay.

If I could sort of cycle back to the Williston assets, which I guess you guys have owned for the better part of 18 months now, or maybe that's the date of announcements and not the date of closing. That's pretty close. You know, we had talked several times on previous conference calls about, maybe putting development capital into those assets. And well, again, we're sitting here 18 months later, and that really hasn't happened. So why has development capital not gone there? What's holding it up? What makes these Permian assets look superior to you? Because if I didn't misunderstand, you said a few minutes ago that they've kind of jumped to the line.

Okay. So, yeah, I mean, when, again, this was primarily, like, first and foremost, the Williston acquisition was evaluated in primarily in a large, large way purchase because it was a great PDP purchase. We really like the existing assets and how they're producing. It also had drilling locations, which At the time, when we evaluated them, the drilling and completing cost was, I don't remember what it is, but let's just say it was a certain number. Very shortly after, that number moved up 20, 30%, which again, it makes the returns pretty good, but the risk associated with drilling them and in the return you got It's still something that we think is attractive. It just didn't jump out at us that we need to go do now. There's been plenty of inflation across the service sector. So if we could see those prices abate some, then that project becomes certainly more attractive. But at this point in time with the current drilling costs that are out there in the world today in a very modern AFE, which we reviewed, the returns here are just, like I said, superior to the wells there.

Okay, so would you consider that those wells, the Williston development opportunity to still be in sort of like a theoretical backlog subject to some combination of oil price and service costs then?

Absolutely, yes.

Okay, and then So, again, it's been the better part of 18 months now since you guys have done any acquisitions. You kind of implied, so I guess I'll try to get you to state it outright, that PDP acquisitions feel a little bit too expensive to you still, and that's why you're looking at some more organic stuff.

Well, OK, so let's be clear. It was never either or, right? We were always going to look to have the potential for us to be able to put some money into the ground. And when there are years, like this past year, when the criteria that we require to make sure that acquisitions are really highly accretive to us just aren't there. I mean, just so you know, We use the same proven screening and processing and evaluation sort of process we have for years. We screen, evaluated, and even offered on many candidates. But like I said, the seller's expectations just weren't in line with what we required to make it a good acquisition for us. That strategy has never gone away. We're still doing it as we speak. We're evaluating several deals. So it's something we very much still want to do, and we think this complements those very well. And anyway, so I want to make sure I'm not leaving with the impression this is all we're going to do. Our goal is to go find highly accretive PDP acquisitions as well.

Okay.

Go ahead, Ryan.

Yeah, I think it's fair to say, you know, that You know, the acquisition market has been choppy, maybe, as a way to describe it. You know, we look at, we try to source deals through connections, through negotiated, and also through marketed processes. And, you know, there was probably a lull towards the beginning of this year of really quality deals that we saw come out. We have seen that pick up, to be honest. We have seen a lot more deals that might fit as pick up here in the near term. But, you know, there was a portion of we didn't just see as much deal flow as we would have liked to.

And I'd like to follow up with what Ryan just kind of on top of it. We look at this as a way to flatten out our, you know, our ads. I mean, it's a low-risk area. We know there's oil there. And, you know, the problem with acquisitions, if you just 100% rely on those, it tends to be kind of lumpy because they come kind of in groups, you know, and this way it kind of helps flatten out our production profile as we go just because we're developing organically. We're not having to go out and bid for it every year.

Yeah, I mean, when you're, especially for the oil assets, right, if you're in a backward-dated commodity curve in oil, you'd much rather drill now to accelerate your cash flow than have to pay, you know, then sort of buy on a curve that's declining. It makes it a little bit easier, and we'd rather accelerate that right now when we see those prices.

Yeah, and with current prices, we would really love to drill these wells as soon as possible because, you know, obviously the prices have picked up lately.

So is stuff happening in the A&D market? And you guys, as I don't think I'd be insulting you by calling you value buyers, just sort of aren't there. Is there still like a big differentiation between bid and ask and deals just aren't happening?

Well, it's a little bit. It's a little early to say. So like I said, we haven't stopped that process. So I don't want to say too much because I don't know who's listening on the phone. We're excited about opportunities that are out there. We think the market has become a little more realistic from the seller's perspective. How about that?

And we've actively gone after acquisitions. We had Even while we were developing this Permian Basin opportunity, we were actively looking at other acquisitions and making offers on them. And I don't feel like we were wildly out of the market. So I'd expect us to still be able to do those type of things too. We're just trying to make it so we're not totally dependent upon acquisition work.

Okay. And then we've talked on a couple prior conference calls about just like the general notion that growth cap would come from internal cash flow and acquisition probably gets funded through the credit facility to then be paid down over the course of the next couple of the couple following years. Is that is that still sort of like an accurate high level description of the strategy?

Yes, that is that's our base plan for sure. You are dead on.

All right, gentlemen, I'm sorry for monopolizing time, and I'll turn it over. Thank you. Appreciate the call. Thank you.

The next question comes from Bruce Brown of Brown Capital. Please go ahead.

Hi, fellas. Appreciate all the color you've given us. On the Pedesco deal, how long have they been active in that field, and how many wells have they drilled, and what has their success rate been?

The timing of that, I'm not... They started in, I think, 2019, or maybe 2018.

It's a better question for Pedevco than for me, but the way we sort of characterize it, they had their Generation 1, more science-y kind of wells where they were trying different landing zones, different frac sort of I don't know resins and different kind of sands in different ways and how the size of the clusters are spacing between the clusters and trying different things then they went on to what I would call their generation two sort of style of frac which they tried and experimented with some of the things that worked and tried some more stuff to see if they could expand or is this going to work better or worse and and through that science that they did, they've come up with a plan and a style and a way to produce these that certainly they and we also think can be improved upon. But as a base case, we don't do any better than what we would call sort of the Gen 2 sort of completion design and where to land and all those sort of learnings that have been gained. I think we still have a very attractive return. But both they and we expect there to be plenty of room for upside, which, again, this isn't something we just walked into. This has been four months of detailed technical analysis and looking at all the science we can. Again, our staff in-house has experience in this and is excellent at this. And we did a lot. I think you even had an industry expert we consulted with. And so where we've become comfortable is what we know can be done, and we're also very strong expectations that we'll beat that. Anyway.

Well, so they're well up on the learning curve, as you probably would put it. So they're at a point, it sounds like they're at a point where perhaps they can maximize the knowledge they've accumulated and a target, their drilling targets would be more carefully planned and selected.

I think that one of the biggest learnings is really what zone you want to land the wells in. You know, like anywhere else, you're going to try, hey, maybe if we put it here, we might get two of the different San Andres pay zones. If we put it here, we get it. And so they did all the right stuff you should do when you're trying to learn as much as you can. We'll walk away. Again, we've learned a lot from that, as have obviously they have, and they have expectations and ideas and ways to move from that sort of Gen 2, as we call it, just sort of the Gen 3. There's been a whole lot of science and learnings.

Yeah. We're excited. Just so you know, they've drilled 10 horizontal wells out there.

Okay. Yeah, exactly. So that's good. All right. Well, good luck with that whole process. It sounds very promising. The other question I had is since we're almost done with the first fiscal quarter of fiscal 24, oil prices have risen substantially during this period of time from where they ended the last quarter. And natural gas prices appear to have improved some, but can you quantify what percentage impact, what kind of range percentage impact that might have on on your cash flow in the first quarter. I mean, just in a very broad sense.

Yeah. So, I mean, obviously the challenge of being non-op is we're still delayed on getting actual prices in the field, which can sometimes differ than what we estimate. But if you're just looking, and I'll talk on more on the gas side, right? The gas side was really, you know, some of the lowest prices that we've seen, right? Quarter over quarter, sequentially, right? So on the gas side, Q4 was a trough, right? And so if you look at what we've seen pricing for, Houston Ship Channel is one of the pricing hubs that we sell our gas to in Barnett, and then Opal up in the Rockies. And so both of those indices are, on average, call it maybe 40 to 50 cents higher um, this quarter to date than they were last quarter. So, you know, I, I don't have the exact percentage, right. But you can, but it's not a small percentage, right. That's a pretty material move. If we're talking about, you know, two to $3 gas, you know, the Barnett less than $2 gas, um, last quarter, if you're, if you're adding, you know, if you're adding 40 cents onto that. So certainly we expect to see some improvement this quarter on the gas realizations, also in NGOs, right. I talked about that earlier, but you know, NGOs were. kind of falling off a cliff if you look at it from April down to June, June being kind of the low month, they traded down quite a bit. Ethane itself is up 50%, 60% since last quarter. The Barnett has quite a bit of ethane. Some of the heavier components are up as much as anywhere from 5%, 10% to 30%, 40%. So overall, NGL prices, I think those are the two You mentioned oil, but I think NGLs and natural gas are two where it might be more noticeable in realizations.

Oh, sure. Yeah, obviously the bulk of your production is in those two areas. So as a company, yeah, yeah, yeah, I understand. So that's great. Okay, I appreciate the color. I think that does it for me. Thank you so much.

No, thank you. I appreciate your interest.

The next question comes from Joseph Christie, a private investor. Please go ahead.

Hello. Yes, good afternoon, gentlemen. My question is about the future development potential of the Dell High Field, assuming the acquisition of Denberry by Exxon Mobil closes. Do you anticipate any positive operational changes in the development cycle of the field or changes in asset structure as a result of this transaction due to the size and scale of Exxon flowing through to the per barrel cost structure? Or is it too soon to begin thinking about this? And that's it. Thank you.

Appreciate that. So, yeah, and that's a question we've had to think about. And I would just say one thing you need to know about Exxon is that they're not dumb. They're going to do the smart thing and they're going to do the right thing. So, look, I would anticipate operations will – be as good or better. I think Denberry's done a terrific job. I think Exxon has the scale and capability to do just as well and perhaps get prices even cheaper. One of the things we've been asked about in the past is the carbon capture permitting and all that. Honestly, I still don't have any way to tell you whether Del High will get that permit. So there could be some kind of benefit for that. But look, Denberry was planning on working on that and pushing towards it. And I would just suggest if Denberry can do it, I don't see why Exxon couldn't do it just as well. So.

Yeah, I mean, the only thing I would add. Much appreciated. Yeah, the only thing I would add is, you know, one thing we've had in the past with Denbury is capital constraints at Del High. And so while we don't know what Exxon's plans are specifically for the field, the one thing Exxon is not is capital constraints, right? And so, you know, whereas Denbury went through bankruptcy, they went through a period of not, you know, spending much money at all. That shouldn't be an issue here from a capital perspective.

Oh, very good. Thank you. I'm a very happy shareholder, gentlemen. Thanks for being such prudent stewards of capital.

Thank you. Appreciate that. Thank you. Very important to us.

The next question is a follow-up from Jeff Robertson of Water Tower Research. Please go ahead.

Thank you, Mark. If you or Kelly or Ryan, as you model the Permian Wells, can you talk about what kind of impacts you think that asset could have on Evolution's realized oil price and also LOE?

I mean, Permian pricing, this is WCS sour, right?

Yeah, it's about $3 deduct to WTI. Yeah, it's about a $3 deduct to WTI, maybe a little bit more than that, $3 to $4 deductible. And, you know, I don't expect these will be particularly expensive to operate. So, yeah, you know, you would expect, I would expect that, you know, overall the margin for the company would be better just because, you know, a lot of the other stuff we have is either water flooded or CO2 flooded, which typically is, you know, a lower margin type of operation. So, yeah, I would think the margins would improve.

I definitely think it, well, I mean, the work we've done, it certainly stacks up to be a fairly high-margin, low-cost, operating-wise oil play.

Well, and, you know, it's like whenever you have new wells, you're drilling new wells, they're going to be higher-rate wells, and that typically translates into higher margins.

Thank you.

Thanks, Jeff.

The next question comes from John Baer of Ascend Wealth Advisors. Please go ahead.

Thank you and good afternoon, gentlemen. Thanks, John. Just to be clear, a real simple question. I guess as you move forward to develop the drill, the three-well pad, and your other operations, all that should be paid for through cash flow. Is that correct? In other words, you've ended the quarter and the year debt-free with cash on the books and so forth. So I'm just kind of curious if I'm reading this right or hearing this correctly.

Yeah, John, that's the plan. Obviously, you know, pricing aside, but at where prices are right now in the forward market and where we expect, yes, we would plan And it's always our goal to drill those out of cash flow, right? We wouldn't need additional funding to drill those.

Right. So your other operations, other fields and so forth. So I'm just – I'm a little – I guess I'm a little stunned at the reaction today and obviously a lot of questions about and I think inferring that the dividend payment might be in jeopardy and yet you've confirmed the 12 cents and have – long made that a very priority. And so I'm just, I'm a little baffled at the extent of, you know, the reaction that's gone on here today. And I don't know if you would care to comment on that at all or... Well, okay.

So here's our goal. We're going to make sure we do everything we can to make Everyone who sold regret it and buy it back. How about that?

Right. Understood. Did you do any stock buyback in the last quarter at all?

We'll obviously come out with our 10K later to confirm that. But the stock buybacks were, you know, honestly really limited for, you know, the prior. We did a lot more, let's just say that, in the March quarter that we already had. We'll publish out our 10-K after we close today.

Right.

Okay.

Well, very good. Well, I would echo the previous or one of the previous commentators that I've been pleased with how you've moved forward, and I hope that you do prove everybody that have been dumping this thing today in error. Keep on doing what you're doing.

Thanks for the sentiment. As you know, and I think it's pretty obvious, we run this company for the long run, and we think about things with multi-year horizons. So while nobody likes to see what's going on in the stock market today with our stock, we're not going to let that make us make any rash decisions. We're always going to do what's in the best interest for our shareholders in the long run.

I'm fully convinced of that. Thanks very much. Thank you.

The next question is a follow-up from David Walkoff of Old Mammoth Investments. Please go ahead.

David, are you there?

Maybe he's on mute.

Sorry about that. I was on mute.

There you go. Is there a way to do sort of like a quick recap for civilians of what went haywire in California last year, at least as it regarded the prices that you got in Jonah and and what you're sort of thinking the situation looks like over the course of the next nine months.

I wish I had that crystal ball going forward. And going past, if you recall, so last winter was unusually, I wouldn't say unusually, but probably more colder than the normal, right, if you look at sort of the weather maps on the West Coast and California, a lot due to La Nina. Yeah. Um, so the issue you have in California is very, very little natural gas storage. And so they have to buy everything on the spot market. And when cold weather strikes, people will pay what they need to get the gas to heat their homes. Right. And they can't pull it out of storage. And so you tend to get these, you know, really high prices and spikes out there. Not unlike we've seen right in the power market in Texas, when you've had heat waves. you get that in California during the wintertime. Now, interestingly, we saw that in the summer a little bit too, where we saw prices in July and August spike a little bit with the heat out there too. So anytime there's a power demand, whether it's to cool your home or heat your home, you're going to see probably spikes. If you look out in the forward curve, it depends on the day, but this winter, the last time I looked, you could hedge prices for probably around $3 premium to Henry Hub. It may have gone down a little bit here in the last couple of days, but call it $2.53, maybe even as much as $4 premium hedging in the forward market right now for winter out in California. So I think the market is still sort of expecting to potentially be short barrels out there. If we saw an unusually warm winter, in California, then we might not quite see the demand that we've seen in the past winters, but historically we have seen at least some pop over the winter months. And I'll also say, you know, I think I've talked about this before, you know, we sell gas, since we take our gas in kind in Jonah and we market it ourselves, we sell it on kind of seasonal contracts, so winter and summer contracts, and, you know, winter contracts we get a pretty healthy premium even to, you know, what you can sell at, you know, Northwest pipeline or a pal. So we would also expect that premium coming up this winter.

Okay. So you're sort of, you're kind of hedging, but not, but not like in the futures market per se, just, just given the nature of the way your contracting works.

That's right. So that, yeah. So we basically sell, um, As much gas as we're comfortable selling firm, if you will, in the wintertime at a fixed price Northwest Pipeline. It's first a month Northwest Pipeline plus spread, which I'll tell you in the wintertime is a fairly healthy spread. And so we do have a physical contract. Like you said, it's not really hedge. We're subject to the movements of Northwest Pipeline, but we get a premium to whatever that price is during the winter.

But to be clear, we locked in the premium we're going to get. Yes. Not the base price.

Correct.

Yeah.

Okay. I understand. Um, and then sort of, um, cycling back to capital allocation a little bit and acknowledging what's going on with the stock price this afternoon. Um, as low sixes looks an awful lot different than high nines. Um, How do you guys think about stock buybacks? Where would the capital come from for a stock buyback to the extent that you now have functionally committed a fair amount of cash flow to the Permian assets?

Well, again, it would compete for dollars. Again, everything's on the table at all times. And again, we are very excited to be in this drilling partnership. And we want to go forward with it. But our priorities are going to be the best use of every dollar. So everything is fair there.

Yeah, I think the way we might think about it, and obviously we have to, you know, the Board is authorized for the overall share buyback plan, but, you know, we do authorize, generally we enter into 10b-5-1s, right, on kind of quarterly basis. But I think as we think about capital allocation, you know, I think if you saw, you know, obviously the dividend we've now said is, you know, is very important, which we've always said, and we've said it at 12 cents, and so the dividend obviously is a base dividend we're certainly going to pay. Above that, you know, and above any capital from the Pedevco Permian asset or any other asset, if we saw more outperformance in commodity prices with excess cash flow, especially if our stock stayed, as you mentioned, low sixes versus high nines, you know, there might be a reason for us to take another hard look at possibly buying some shares back with sort of, you know, outperformance or excess cash flow, if that makes sense.

Okay. Thanks for that, guys.

Thank you.

This concludes our question and answer session. I would like to turn the conference back over to Kelly Lloyd for any closing remarks.

Just quickly, I want to thank everyone for taking the time. As you know, we are always here to answer questions. So anyway, appreciate your interest and your time. Thank you.

The conference is now concluded.