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 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 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 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 acquisition and divestiture 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 exploration and production 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 and 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 Shale properties as mentioned previously. Based on discussions 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 the Delhi Field drilled by our operator, Denbury. As Kelly already said, we're really excited about our strategic partnership with 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 capital expenditures to 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 down 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 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 start the question-and-answer session. 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.

I want to emphasize that when the Board and I set dividends, we do so with a long-term perspective, considering our production and the cash flow generated from our projected pricing and production levels. Given this, we are confident that our cash flow, along with our strong balance sheet and cash reserves, will more than sufficiently cover our dividend, which we have recently adjusted to $0.12 per share. We believe it will not only cover the dividend but also meet all our capital requirements, including any planned drilling projects. We are optimistic that this strategic partnership will provide robust support for our dividend for an extended period.

Okay. I appreciate that add on. So, regarding the PEDEVCO deal, with respect to capital expenditures, Mr. Bunch 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 putting 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 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. The heat exchanger is operational, and the plant turnaround has been completed. We expect that Delhi is back to running at its rated load, and we see that Delhi is performing as we anticipated.

Thank you. I have the same question regarding the Barnett Shale concerning the maintenance of the gathering line and compressor issues. The challenges we faced in the Barnett Shale were primarily linked to compressors and gathering lines. We believe this situation is generally tied to demand, but at this moment, we are unsure if everything is fully operational again as it should 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 Schafer of Northland Capital Markets. Please go ahead.

Hey guys, thanks for taking the questions. I'm Donovan Schafer. I want to start picking up where John left off. We covered the Delhi and the Barnett, but in the Williston, it seems there might 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 mistaken about that? I have it recorded as a decline of over 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. We experienced some downtime on the compression side during one month, which impacted NGLs and gas production, and that's the main reason for the decline.

Well, are you saying this is true for the Bakken and 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. I want to discuss the year-over-year production numbers. For the full year, the production figures were positive and increased, partly due to the Jonah and Williston acquisitions having a partial contribution last year and a full year contribution this year. Can you provide any information to help us make a direct comparison between last year and this year, whether that includes adjustments for the full year last year or excluding those? Essentially, what is the direct change in production, likely indicating some decline? Do you have that information?

Yes, Donovan, we haven't completed a full pro forma. We typically evaluate things sequentially, quarter-to-quarter. We'll follow up with you regarding the pro forma analysis for those acquisitions as if we owned them for the entire year. Ultimately, we have seen declines in the assets for natural reasons. However, in the last fourth quarter, we faced maintenance issues in three of our main asset fields, which led to extended downtime alongside the lowest prices we've experienced in two years. So, while the timing wasn't ideal for any of us, we can certainly provide you with an update on the actual field decline on a per-field basis.

We're starting to analyze the overall decline while excluding any significant increases from transactions. So, if you have an idea about this, do you think we're still at around a 5% annual decline rate in a typical scenario without additional acquisitions, or how do you see the decline rate evolving?

I think we've previously indicated a high single-digit to 10% annual decline. I don't believe that has changed, but the fourth quarter will obviously impact the decline rate significantly.

Sure. Yes, okay. And then also, 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. Given that you don't provide guidance, should we reasonably expect a potential reversal where there might be a slight increase in total production numbers from this quarter to the next? This expectation is based on the fact that many issues have been resolved, leading to a gradual return to a normalized decline. Is that a fair assumption?

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 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, we're collaborating on this. I believe both parties are motivated and eager to get those initial three well pads started as soon as possible and once we are both comfortable with it. I'm not going to provide specific timing, but I'm hopeful it will happen sooner rather than later and I 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 appropriate to kind of put the two in the same bucket?

In our view, these will compete for capital just like everything else does with our next marginal dollar. We believe the economics in the Chaveroo field with PEDEVCO are very attractive. So, absolutely yes. They've moved to the front of the line, and we think they offer strong 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 started when I received a call from Doug Shick at PEDEVCO, someone I've known for several years. We used to coach against each other in PW Football, and we've talked over the years about various business opportunities. I believe Doug had an advisor looking at potential options, possibly the ROTH group, who has been beneficial for them. It made sense to pursue this deal, especially working with someone I 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 talked to them a lot. And so we certainly hope and expect 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, they will be drilled consecutively and then completed consecutively. That's the current expectation since it's the most economically viable approach, and they will be brought online simultaneously.

In terms of infrastructure, Mark, can you talk about the infrastructure costs related to the production and what options you have for moving oil into the area? I know it was initially developed with vertical wells.

Yes, the plan right now is really not to use any of the vertical well facilities because the horizontal wells are much more prolific than the vertical wells. The capital costs we are looking at are actually related to putting in new infrastructure and tank batteries, which we will optimize for 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 that more like a shale formation. Is that true in this area as well?

Yes, I would say that typically in the Wolfcamp, particularly in the Delaware section of the Permian, decline rates are likely above 95%. Here, it will be lower than that.

Okay. Lastly, regarding funding, Kelly mentioned in her remarks, or perhaps Ryan did, about financing the capital and drilling program with available liquidity. It seems you will have the flexibility to continue funding the dividend, so that should not 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.

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, I think you've already addressed these questions, but I want to ask them again for clarity. Regarding the downtime, especially in Delhi and also in the Barnett, do you expect that fixing those compression issues will restore production in those areas to the levels seen in March as we move forward?

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

Okay. For clarification on the Permian assets, I am trying to understand a few points you mentioned. The expectation is four gross wells a year, is that correct?

The eight gross wells, yes, four net.

I'm sorry. Did I say four? My apologies. 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 correct, David. When we assess the current pricing in the forward curve, we see that oil prices have risen since the fourth quarter, and NGL prices have also increased significantly, which affects us as well. In the fourth quarter, NGLs were at a low level, and that certainly impacts our situation. However, when we factor in pricing along with the free cash flow generated by our other assets and the cash expected from drilling the PEDEVCO, we believe there is some delay, but this asset should become self-sustaining fairly quickly. We don't foresee any difficulty in covering that, and we have been able to fund our proportionate share of eight wells each 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.

The time from when the money is spent to when we start generating revenue from the wells isn't a long-term payback. You receive an initial payment and then see a return. We and PEDEVCO are enthusiastic that this investment will lead to oil production for both parties.

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 have discussed in previous conference calls the possibility of investing development capital into those assets. Here we are 18 months later, and that investment has not materialized. What is preventing the deployment of development capital there? What makes the Permian assets appear more attractive, especially since you mentioned that they have taken priority?

The Williston acquisition was primarily assessed as a significant investment because it presented a valuable PDP opportunity. We appreciated the existing assets and their production performance. Moreover, it included drilling locations that, at the time of our evaluation, had a specific cost associated with drilling and completing. Shortly after that, those costs increased by 20% to 30%, which made the potential returns quite appealing. However, the risks tied to drilling and the returns we've assessed still make it an attractive option, though it didn’t seem urgent for us to pursue immediately. There has been considerable inflation in the service sector, and if we see those costs stabilize, this project would become even more appealing. As it stands now, with the current drilling costs and a thorough review of a modern AFE, the expected returns are significantly better than those of 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 months 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?

Sure, let's clarify that it was never an either-or situation. We always aimed to have the possibility of investing capital. In years like the last one, the criteria we need for acquisitions to be significantly beneficial were simply not met. We follow the same established process for screening, evaluating, and offering on numerous candidates as we have for years. However, the expectations from sellers didn't align with what we needed for a favorable acquisition. This strategy remains active; we are currently evaluating multiple deals. We still aim to pursue highly beneficial PDP acquisitions as well. I want to emphasize that this is not the only focus we have.

It's fair to say that the acquisition market has been unpredictable. We aim to source deals through connections, negotiations, and marketed processes. There was a period at the start of this year when we saw fewer quality deals. However, we have noticed an increase in potential deals recently, though initially, there wasn't as much deal flow as we would have liked.

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 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, especially for the oil asset, if you're facing a backwardated commodity curve in oil, you would prefer to drill now to boost your cash flow rather than buying into a declining curve. It simplifies the process, and we would like to accelerate that now while 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 M&A 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?

We have actively pursued equity, and while developing the Permian Basin opportunity, we were also looking at other acquisitions and making offers. I don’t think we were significantly out of the market, so I expect we will continue to pursue similar opportunities. Our goal is to reduce our dependence on acquisition activities.

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?

They started their activities in either 2018 or 2019. While it's a better question for PEDEVCO, we characterized their approach as starting with Generation 1 wells, which involved experimenting with different landing zones, fracking methods, resins, sands, and cluster placements. They then moved on to Generation 2 fracking, where they built on successful techniques and tried new approaches to determine potential improvements. Their research has led to a production plan that they believe can be enhanced further. Even if we only achieve the performance levels of Generation 2 completion designs with the insights we've gathered, we anticipate a strong return. However, both we and they are optimistic about the potential for further improvements. This extensive analysis has been conducted over four months, utilizing our experienced in-house staff along with industry experts we consulted. We are confident in what can be achieved and expect to exceed those baseline expectations.

They are progressing well on the learning curve and seem to be at a stage where they can maximize the knowledge they have gained. Their drilling targets will be planned and selected with greater care.

One of the key lessons learned is determining the right zone for well placement. Like any other situation, we explore various options, such as placing the well in one area to access multiple San Andres pay zones. The team made all the necessary efforts to maximize their learning. We've gained significant insights from this experience, and it's clear they have too, developing expectations and strategies to progress from what we refer to as Gen 2 to Gen 3. There has been extensive research and valuable learning throughout this process.

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

Okay. That's good. Good luck with that process; it sounds very promising. The other question I have is, as we near the end of the first fiscal quarter of 2024, oil prices have significantly increased since the last quarter. Natural gas prices seem to have improved as well. Can you provide an estimate of the percentage impact this might have on your cash flow in the first quarter, in broad terms?

Yes. The challenge of being non-operational is that we are still experiencing delays in obtaining actual prices in the field, which can sometimes differ from our estimates. Focusing on the gas side, we observed some of the lowest prices last quarter. In Q4, gas prices reached a low point. Currently, pricing for the Houston Ship Channel and Barnett, along with Opal in the Rockies, are on average about $0.40 to $0.50 higher than last quarter. While I don't have the exact percentage, it's significant, as an increase of $0.40 on gas priced between $2 to $3, and Barnett gas being less than $2 last quarter, indicates a material improvement. We anticipate better results this quarter for gas. Regarding NGLs, they saw a sharp decline from April to June, with June being the lowest month, but since then, ethane prices have surged by 50% to 60%. The Barnett has a considerable amount of ethane, and other heavier components have increased by 5% to 40%. Overall, NGL prices and natural gas are where we might see more noticeable changes in realizations.

Sure. The majority of your production is in those two areas. As a company, I understand. That's great. I appreciate the information. I think that covers everything for me. Thank you very 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. Yes, that's a question we've had to consider. One thing to know about Exxon is that they are strategic in their approach. They will take the right actions. I expect operations will be at least as good as before. Denbury has performed excellently, and Exxon has the resources and capacity to match that and possibly lower costs even further. We've been asked about carbon capture and permitting previously. Honestly, I still cannot tell you whether Delhi will receive that permit. There may be some benefit there. However, Denbury has been working towards that goal, and I believe if Denbury can achieve it, Exxon can do so 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, Denbury 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 and Kelly or Ryan model the Permian wells, could you discuss the potential impact of that asset on Evolution's realized oil price and also on LOE? I mean, Permian pricing is influenced by WCS sour, correct?

Yes, there is about a $3 deduction from WTI, possibly a bit more, ranging from $3 to $4. I do not anticipate that these will be particularly costly to operate. Therefore, I expect that overall the company's margins will improve, especially since much of our other production is derived from either waterflood or CO2 flood operations, which generally result in lower margins. So, I believe that margins will indeed enhance.

I definitely think the work we've done certainly represents a fairly high-margin, low-cost oil operation.

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.

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 need additional funding to drill those.

I'm a bit surprised by today's reaction, especially with the concerns about the dividend payment possibly being at risk. You've confirmed the $0.12 dividend and have consistently prioritized it, so I'm puzzled by how intense the response has been. I'm wondering if you would like to share your thoughts on this.

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 release our 10-K later to confirm that, but the stock buybacks were actually quite limited before; we did significantly more in the March quarter that we've already published. We'll issue our 10-K after we close today.

Well, I want to express my appreciation for the progress you've made. I hope you can demonstrate to those who have sold that their decision was a mistake. So, continue with your current strategy.

Thanks for the sentiment. As you know, we operate this company with a long-term perspective and consider multi-year horizons in our decisions. While it’s disappointing to see the current performance of our stock, we will not make hasty decisions based on this. We will always act in the best interest of our shareholders for the long term.

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.

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 as 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 a clear prediction for the future. However, last winter was colder than usual, particularly on the West Coast and in California due to La Nina effects. California has minimal natural gas storage, which forces them to rely on the spot market. When cold weather hits, residents will pay whatever it takes to get gas for heating their homes since they can't draw from storage. This leads to high prices and spikes, similar to what we've seen in Texas power markets during heat waves. Interestingly, we also experienced some price spikes last summer in July and August due to heat. Anytime there's a demand for power, whether for cooling or heating, price increases are likely. Looking ahead, the forward market currently shows hedging prices for this winter at about a $2.50 to $4 premium over Henry Hub. The market seems to expect a potential shortfall in supply. If this winter is unusually warm in California, we may not see as much demand as in previous winters, but typically, there's still an increase in demand during winter months. Additionally, we market our gas from Jonah with seasonal contracts, and for winter contracts, we receive a substantial premium compared to sales at Northwest Pipeline or other locations. We anticipate that premium increasing this winter.

Okay. So, you're kind of hedging, but not in the futures market specifically, just based on 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.

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 will compete for funds. Everything is always on the table, and we are very excited about this drilling partnership and want to move forward with it. However, our priorities will focus on making the best use of every dollar to ensure fairness.

Yes, I think we should consider that while the Board has approved the overall share buyback plan, we typically engage in the 10b5-1 program on a quarterly basis. Regarding capital allocation, the dividend remains a crucial aspect, which we have confirmed at $0.12. This dividend is definitely a base amount we will pay. Additionally, if we receive any capital from the PEDEVCO Permian asset or other sources and if commodity prices outperform expectations, leading to excess cash flow—especially if our stock stays under $6 rather than reaching high $9s—we may seriously consider repurchasing some shares using that 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.

The conference has now concluded. Thank you for attending today's presentation and you may now disconnect.