EPM - AMEX

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 floor will be open for questions and comments after the presentation. I will now turn the call over to your host Brandi 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 Loyd, 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 Investor Relations section of our website. Please note that any statements and information provided in today's speak only as of today's date September 13th, 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 statements. 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 closet 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 Bunch; 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 Investor 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 PEDEVCO concerning our definitive participation agreement to jointly develop the Chaveroo 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 this 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 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 $0.48 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 $0.12 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 thousand 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 Delhi 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 our Delhi 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 interest 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 Delhi 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 interest 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 Delhi Field and the same factors that impacted our natural gas production in our Barnett Shell properties as mentioned previously. Based on discussion with our operators, we expect capital workover projects to continue in all the fields. Overall, for fiscal year 2024, we expect budgeted capital to be in the range of $4 million to $5 million, which excludes any potential acquisitions. Our expected capital expenditures for the next 12 months include two new drill wells at Delhi Field drilled by our operator, Denbury. As Kelly already said, we're really excited about our strategic partnership with the PEDEVCO in the Permian. The agreement covers approximately 25,000 gross acres in and around the Chaveroo Field in Northeast, New Mexico. The Chaveroo Field was originally developed targeting the San Andres formation with vertical wells on 40-acre spacing. We view the horizontal development of the San Andres in the Chaveroo 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-waterflooded vertical San Andres Field. We expect this project will significantly contribute to the success of Evolution for years to come. We expect our CapEx increase over the $4 million to $5 million budgeted for our existing assets due to drilling and completing 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 Ryan 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 and maintenance across multiple assets and were negatively impacted by much lower realized natural gas and NGL 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 flow outlook, while also paying debt drawn for our acquisitions. Supported by our continued 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 30th, 2023, cash and cash equivalents totaled $11 million and working capital was $8.9 million. As a result, total liquidity on June 30th, 2023 was $61 million, including cash and cash equivalents. This represents an increase in liquidity of 65% since June 30th of 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 our 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 paydown 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're 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. [Operator Instructions] 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 was 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 we -- when we and the Board we set dividends, we do so with a multiyear 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. It -- 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 PEDEVCO deal, with respect to capital expenditures, Mr. Bunch [ph] offered some commentary. However, this commentary was, I would say, highly conditioned or highly qualified. Can you offer any more detail about the potential CapEx at the PEDEVCO 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 in their plans that we're going to come up with and finalize with our partner, PEDEVCO. 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 or 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, and 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 or half of that is 4.5 million and we have acreage payments. So, 4.5 million 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.

That's a lot of extra detail and I really appreciate that, Kelly. 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 has -- was completed and so we expect that Delhi is back running at rated load. So, we're -- 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 generally on the demand, 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?

As you know, John, when it's 112 degrees in Fort Worth, compressors don't always act properly 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 [ph] Schafer of Northland Capital Markets. Please go ahead.

Hey guys, thanks for taking the questions. I'm sure you know this, but it's Donovan Schafer. So, I want to start picking up where John left off. The -- so we covered the Delhi and the Barnett, but in the Williston -- 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 Williston was down quite a bit too. Am I just wrong on that? I have that Williston down something like north of 10% quarter-over-quarter. So, was there a decline there or is that just an error in my model?

Yes, Donovan, 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 also affected gas production and that's the main cause.

Well, I'm talking about -- are you saying this is true for the -- that this is the Bakken, the Williston?

Yes, Yes. For the Williston.

Oh, really? Okay. Also there - so, yes, the compression issues in both and also compressor down in the Barnett? Okay. Got it.

Yes.

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, the year-over-year production numbers were good and up, but of course, part of that comes from the Jonah and the Williston acquisition being -- 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 last year versus this year, kind of including those pro form for the full year last year or stripping them out just like what is the apples-to-apples change in production, presumably some amount of decline? Do you have that information?

Yes, Donovan, 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 -- 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 in 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, unfortunately, it hasn't -- it wasn't great timing for all of us, but we can certainly get back to you on -- what we think -- you're trying to get to what the actual field decline is field-by-field kind of--

Well, we're just getting into kind of your blended decline factoring out those step function increases from transaction. 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 for -- in a business as usual situation without incremental acquisitions or where do you think this does from a decline rate standpoint?

I think we've guided before to like high single-digit to 10% sort of annual decline. We don't -- 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 rate.

Sure. Yes, okay. And then also -- yes, go ahead.

Yes. 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 this 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 like from this quarter to the next quarter just because a lot of that has been fixed and there's a little bit of an upward just to get back on to a normalized decline? Is that a fair expectation?

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

Okay. And then I think John did ask about the at the PEDEVCO 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 I -- 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 Willow then, right? I mean, there might be some differences to the terms with 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 are they is it appropriate to kind of put the two in the same bucket?

It is and in our mind, those are they will compete for capital just like everything else do with our next marginal dollar. We -- at this time, look, we think the economics are very attractive in the Chaveroo field with PEDEVCO. 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 source the deal? Just I know that sometimes there can be some interesting nuggets there. Did this come into any atypical channel or just the relationships you already have? They came to you and you would be interested in some conventional stuff. And I know this isn't technically EOR, but you kind of understand you're familiar with this type of taking a second pass at things. So, yes, how did this kind of come about?

Well, it mostly came about -- I got a call from Doug Shick at PEDEVCO whom I've known for several years. We actually used to coach PW Football against each other and I've known Doug and we've spoken over the years various business deals. And I believe Doug had an advisor looking in to do something. I think 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 that you expect over the next couple of quarters from your midstream providers into Barnett Shale?

No, not really

I wish they'd let us know when they're going to do that, but unfortunately don't. I mean, I think we talked about this before right. So in length took over for Crestwood, right. Crestwood sold the system and they've had extended growing pains of trying to optimize the way they run the area. Our operator and partner diversified is certainly talk to them a lot. And so we certainly hope and expecting them to do a better job going forward. But unfortunately, they're not going to give us any insight as to they're going to have downtime or issues, unfortunately.

Thanks. Partially read through the operating agreement that I think was filed in an 8-K by PEDEVCO this morning. Kelly, with respect to the initial three wells, I think you 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 talk about how you think about 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.

Yes, no, they'll be drilled back-to-back and then completed back-to-back. That's the expectation right now because that's most -- that's the most -- 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 there's -- you all would share, I believe, any infrastructure costs related to the production, 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.

Yes, the plan right now is really not to use any of the vertical well facilities because the wells -- the horizontal wells are much more prolific than the vertical wells. So, the costs that we're with -- 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 a unconventional formation in most areas. So, the initial line rate is not as steep as more as a shale formation. Is that true in this area as well?

Yes, I would say that typically in a Wolfcamp -- say like in the Delaware part of the Permian where you have the Wolfcamp, 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 program the drilling program with available liquidity and it appears you still have -- 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.

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

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

The next question comes from David Locke 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 to answered these questions, but I just want to answer -- 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 -- sorry?

The eight gross wells, yes, four net.

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. Yes, no, that's right, David. I mean, we -- when we look at where pricing is, like you said in the forward curve, obviously, assuming oils already increased from what we saw in the fourth quarter, so have NGLs and just kind of in the side, right, NGLs in the fourth quarter were about a long time and so that certainly impacts us too. But when you take prices into consideration, free cash flow that our other assets generate plus cash that we're going to get from drilling the PEDEVCO, right, there is some delay there, but we do think this asset become self-funding pretty quickly. We don't see any issue covering that have been plus funding our proportionate share of eight wells per year.

Just to reiterate, I mean, that's one of the things that we're excited about with this deal is the money we're spending 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 March 60 days.

Yes, longer than that, but somewhere -- very reasonable, maybe three months.

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 multiyear payback. You get a pay upfront and then you get payback. We and 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, we're certainly not on the wrong track.

Okay. And then, 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.

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, yes, I mean, when -- again, this was primarily like first and foremost, the Williston acquisition was evaluated primarily in a large, large way purchase because it was a great PDP purchase. We really liked the existing assets and how they were producing. It also had drilling locations, which at the time when we evaluate them, there was a -- 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've got, it's still something that we think is attractive. It just it didn't jump out at us that we need to go do now. If you see some -- 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 and 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 again, it's been the better part of 18 now since you guys have done any acquisitions, you kind of implied. So, I guess I'll try to get you to-date 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 -- okay, so let's be clear, it was never either or, right? It was -- 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, evaluate it, 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 leading with the impression this is all we're going to do. We -- our goal is to go find highly accretive PDP acquisitions as well.

Okay. So, -- go ahead, Ryan.

Yes, I think it's fair to say that the acquisition market has been choppy maybe as a way to describe it. We look at -- we try to source deals through connections, through negotiated, and also through marketed processes. And 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 us pick up here in the near-term, but there was a portion of we didn't just see as much deal flows as we would have liked too.

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 adds. I mean, it's a low risk area. We know there's oil there. And the problem with acquisitions, if you just 100% rely on those, it's tends to be kind of lumpy because they come kind of in groups. 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.

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

Yes. And with current prices, we would really love to drill these wells as soon as possible because obviously the prices had 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 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 is listening on the phone. I would just say, we are excited about our 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 equity. 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 like 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 like 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 CapEx 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 following years. Is that still sort of like an accurate high level description of the strategy?

Yes, 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.

No, 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 PEDEVCO deal, how long have they been active in that field and how many wells have they drilled? And what's their success rate been?

Timing of that -- they started in, I think, 2019. Maybe 2018. So what -- and look it's a better question for PEDEVCO than for me, but the way we sort of characterized it, they had sort of -- they had their Generation 1, more sciency kind of wells where they were trying different landing zones, different frac sort of, I don't know, resins and different kind of sands and 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 2 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 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, if 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. And again, our staff in-house is -- has experience in this and is excellent at this and we did a lot, as 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, 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 and like anywhere else, you're going to try, hey, maybe if we put it here, we might get two of the difference San Andres pay zones. If we put it here, we get it. And so they did all the right stuff you do when you're trying to learn as much as you can. We 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.

Yes, so it's we're excited. Just so you know, they've drilled 10 horizontal wells out there.

Okay. Well, so they, yes -- so they -- yes, exactly. So, that's good. All right. Well, a good luck with that 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 2024, oil prices have risen substantially during this period of time from where they ended the last quarter. And natural gas prices have -- appear to have improved some, but can you quantify what percentage impact -- what kind of range percentage impact that might have on your cash flow in the first quarter? I mean, just in a very broad sense.

Yes. 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 just talk on more on the gas side, right? The gas side was really 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 Barnett and then Opal up in the Rockies. And so both of those indices are on average, call it, maybe $0.40 to $0.50 higher this quarter-to-date than they were last quarter. So, 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 $2 to $3 gas, the Barnett less than $2 gas last quarter if you're adding $0.40 on to that. So, certainly, we expect to see some improvement this quarter on the gas. Also NGLs, right? I talked about that earlier, but NGLs 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 price is -- I think those are the two pieces. You mentioned oil, but I think NGLs and natural gas are two where it might be more noticeable on realizations.

Sure. That's -- obviously, the bulk of your production is in those two areas. So, as a company, yes, yes, yes, 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 Christy, a Private Investor. Please go ahead.

Hello. Yes, good afternoon gentlemen. My question is about the future development potential of the Delhi Field, assuming the acquisition of Denbury by ExxonMobil 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.

We appreciate that. So, yes -- 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, that they're not dumb. They're going to do the smart thing. They're going to do the right thing. So, I -- look, I would anticipate operations will be as good or better. I think Denbury has 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. And we -- honestly, we -- I still don't have any way to tell you whether Delhi will get that permit. So, there could be some kind of benefit for that. But look, Denbury was planning on working on that and pushing towards it. And I would just suggest if Denbury can do it, I don't see why Exxon couldn't do it just as well.

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

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

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. As you or Kelly or Ryan, as you model the Permian wells, can you talk about what kind of impact you think those -- that asset could have on Evolution's realized oil price and also LOE? I mean Permian pricing, this receives WCS sour, right?

Yes, it's about $3 deduct to WTI. Yes, it's about a $3 deduct to WTI, maybe a little bit more than that. It kind of $3 to $4. And I don't expect these will be particularly expensive to operate. So, yes, you would expect -- I would expect that overall the margin for company would be better just because, the lot of the other stuff we have is either waterflooded or CO2 flooded, which typically is low margin -- is a lower margin type of operation. So, yes, 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 it's like whenever you have new wells, you're drilling new wells, you're going to be higher rate wells and that's typically translates into higher margins.

Thank you.

Thanks Jeff.

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

Thank you and good afternoon gentlemen.

Thanks John.

Just to be clear, 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?

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

Right. So, other 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 $0.12 and have long made that a very, priority. And so I'm just -- I'm a little baffled at the extent of the reaction that's going 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 10-K later to confirm that, but the stock buybacks were honestly really limited for the prior -- we did a lot more, let's just say that in the March quarter that we already published. 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 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. So, keep on doing what you're doing.

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

I'm fully convinced with that. Thanks very much.

Thank you.

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

David, are you there? Maybe he's on mute.

Sorry about that.

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 is it regarded the prices that you got in Jonah 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. But in 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. 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 really high prices and spikes out air. 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 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 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 $2.50, $3, 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, I think I've talked about this before, we sell gas, since we take our gas and kind in Jonah and we market it ourselves, we sell it on kind of seasonal contracts of winter and summer contracts and winter contracts, we get a pretty healthy premium even to what you can sell at Northwest Pipeline or [Indiscernible]. So, we would also expect that premium coming up this winter.

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

That's right. So, yes, so we basically sell as much gas as we're comfortable selling firm, if you will, in the wintertime at a fixed price, Northwest Pipeline. First a month, Northwest Pipeline plus a spread, right, 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 heads. We're subject to the movements of Northwest Pipeline, but we'll 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, not the base price.

Correct.

Yes.

Okay. I understand. And then sort of cycling back to capital allocation a little bit and acknowledging what's going on with the stock price this afternoon as low $6s looks an awful lot different than high $9s. 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 to the Permian assets?

Well, it's -- it would -- again, it would compete for dollars. So, again, everything's on the table at all times. And again, we are very excited to be in this, but -- 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, that everything is fair there.

Yes, I think the way we might think about it and obviously, we have to -- the Board has authorized sort of the overall share buyback plan, but we do authorize -- generally we enter into 10b5-1 right on kind of quarterly basis. But I think as we think about capital allocation, I think if you saw -- obviously the dividend we've now said is very important, which we've always said and we've said it at $0.12 and so the dividend obviously is a base dividend we're certainly going to pay. Above that and above any capital from the PEDEVCO Permian asset or any other assets, if we some more outperformance in commodity prices with excess cash flow, especially if our stock stayed as you mentioned below $6s versus high $9s, there might be a reason for us to take another hard look at possibly buying some shares back with sort of outperforms our excess cash flow. Does that make 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 Loyd for any closing remarks.

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