Evolution Petroleum Corporation, Inc.

Good day, everyone, and welcome to the Evolution Petroleum second quarter fiscal year 2023 earnings release conference call. All participants will be in a listen-only mode. Should you need assistance, please email a conference specialist by pressing the star key followed by zero. After today's presentation, there will be an opportunity to ask questions. To ask a question, you may press star and then one. To withdraw your questions, you may press star and two. Please also note today's event is being recorded. At this time, I would like to turn the floor over to Ryan Stash, Chief Financial Officer. Please go ahead.

Thank you, and good afternoon, everyone. Welcome to our earnings call for the second quarter of fiscal 2023. Joining me today is Kelly Lloyd, a President and Chief Executive Officer and a member of our Board of Directors. After I cover the forward-looking statements, Kelly will review key highlights along with our operational results. I will then return to provide a more detailed financial review, and then Kelly will provide some closing comments before we open it up and take your questions. Please note that any statements and information provided today are time-sensitive and may not be accurate at a later date. Our discussion today will contain forward-looking statements of management's beliefs and assumptions based on currently available information. These forward-looking statements are subject to risks and uncertainties that are listed and described in our filings with the SEC. Actual results may differ materially from those expected. As detailed numbers are readily available to everyone in yesterday's earnings release, this call will primarily focus on our strategy as well as key operational and financial results and how these affect us moving forward. Please note that this conference call is being recorded. If you wish to listen to a webcast replay of today's call, it will be available by going to the company's website. With that, I'll turn the call over to Kelly.

Thank you, Ryan. Good afternoon, everyone, and thanks for joining us on today's call. Our results in the second quarter of fiscal 2023 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. We used it on capital spending and shareholder dividends. In addition, I'm pleased to report that we have delivered on our commitment to eliminate our remaining debt position during the period. We have now fully integrated multiple acquisitions, paid off our debt, and are generating meaningful free cash flow to fund our strategic objectives. Of course, none of this would have been possible without the hard work of our team. I want to thank all of our team members for their continued dedication and strong execution as we remain focused on driving near and long-term value for shareholders. During the second quarter, we paid a cash dividend of $0.12 per common share. This was 60% higher than the same period 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 for the third quarter of fiscal 2023 of $0.12 per share. This will mark the 38th consecutive quarterly cash dividend paid by the company since we began our Return of Capital program in December of 2013. Since the inception of the program, we have returned more than $94 million, or $2.85 per share, of capital to shareholders. As we've discussed in the past, there are very few small-cap E&P companies that can say they have 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 businesses 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. Turning now to operations. Second quarter fiscal 2023 production of 7,250 net BOE per day was down around 5% from the 7,598 net BOE per day for the first quarter of fiscal 2023. In large part, this was due to downtime. associated with the severe winter storms we experienced and, to a lesser extent, some temporary compression issues and some downtime in the barnet associated with offset operator activity. As of now, and barring any future extreme weather circumstances, operations are back on track. Looking at our second quarter results in more detail, net production at Jonah Field for the second quarter was 1,902 BOE per day. Slightly impacting production levels in the second quarter was the decision to maximize natural gas production, thus reducing NGL recoveries during the period to capitalize on relatively higher natural gas prices, which averaged $11.00 per MCF for the quarter. The Jonah field is our most recent acquisition and we remain pleased with its performance. Similar to our other assets, the field is highlighted by long life, low decline reserves that generate significant cash flow. In addition, the asset base provides access to attractive western markets. Second quarter net production for our Williston Basin was quite flat to the first quarter at 489 BOE per day. of which approximately 76% was oil. The Williston Basin oil production was impacted by the winter storms during the quarter. However, this was offset by the reactivation of the One Oak gas pipeline. We were pleased to see the One Oak gas pipeline come back online in late September for the first time since our acquisition. This has led to increased optionality for natural gas in NGL cells. In early January, we, along with the operator, Foundation Energy Management, began operations on one of our Bakken recompletions and continue to work closely with them on high-grading opportunities in the field, such as expense workovers, additional recompletions, and sidetrack drilling opportunities. Also, technical evaluations remain underway to assess our pronghorn and three-forks drilling locations. Net production for the Barnett shale for the second quarter was 3,304 BOE per day, of which approximately 76% was natural gas. As discussed previously, impacting sequential production volumes were severe winter storms, temporary issues at select compression stations, and certain offset operator activities, all of which have been addressed. Hamilton Dome field net production was substantially flat for the second quarter at 413 BOE per day. We continue to support the operator Merritt Energy in their efforts to restore production at previously shut-in wells, adjust water injection locations and volumes, and execute on other targeted maintenance projects. Additionally, in the quarter, we and Merritt began upgrading facilities to proactively reduce emissions throughout the field. Second quarter net production at Del High Field was approximately 1,131 BOE per day. Denberry, the operator at Del High, took steps to minimize the severe weather impacts, which resulted in only minor downtime during the second quarter despite the storms. They are continuing to perform conformance workovers and upgrades to the facilities. With that, I'll now turn the call over to Ryan to discuss our financial highlights.

Thanks, Kelly. As mentioned earlier, please refer to our press release from yesterday afternoon for additional information concerning our second quarter fiscal 2023 results. My comments today will primarily focus on financial highlights and comparative results between the second and first quarter fiscal 2023. A key highlight of the second quarter was our continued solid generation of cash flow, including adjusted EBITDA of $16.4 million. This was $24.66 on a per BOE basis, which was an increase from the first quarter. We have now generated $33.5 million in adjusted EBITDA for the first two quarters of fiscal 2023. As Kelly discussed, during the second quarter, we continued to fund our operations, development capital expenditures, and dividends out of operating cash flow, while also repaying all of our remaining debt. Supported by our continued strong operational and cash flow outlook, we paid a dividend of 12 cents per share in the second quarter and declared a dividend of 12 cents per share for the third quarter of fiscal 2023, payable on March 31st to shareholders of record as of March 15th. Our cash dividend program has and will continue to be a top priority as we clearly recognize the strategic importance of returning value to our shareholders. During the second quarter, we enhanced our already strong balance sheet, delivering on our commitment to paying off our debt In the second quarter, we eliminated our remaining debt position of $12.3 million. Our borrowing base remained at $50 million, and we had cash and cash equivalents of $3.7 million and working capital of $2.9 million as of December 31, 2022. The result was growth in our liquidity to $53.7 million, a 45% increase from only six months ago. This is a direct result of our targeted and immediately accretive acquisitions over the past couple of years, as well as our continued focus on cost control. We are ideally positioned for the continued execution of targeted future growth opportunities that meet our strategic vision. As a result of eliminating our outstanding debt position, we are not currently required to maintain any hedges in our production and our existing hedge positions are set to expire next month. Looking at the second quarter financials in more detail. Our total revenue of $33.7 million was 15% lower than the first quarter due to a combination of factors including lower oil revenue associated with 1% lower sales volumes and a 13% decrease in realized pricing, lower natural gas revenue due to a 5% decrease in sales volumes, and 8% lower realized pricing despite declines of almost 30% in Henry Hopp pricing. decreased NGL revenue due to 8% lower sales volumes and a 27% decrease in realized pricing. The result was an average realized price per BOE decrease of 11% to $50.49. Lease operating expenses decreased 21% quarter over quarter to $15 million in the second quarter. On a per BOE basis, lease operating expenses were $22.55 for the second quarter compared to $27.35 in the first quarter. Primarily contributing to the decrease in LOE were changes in estimates for prior periods and reduced ad valorem and production taxes due to lower revenues in the current period. Also contributing to the decrease was lower workover expense in the Williston Basin and reduced CO2 costs at Del High Field associated with the decrease in crude oil prices from the prior quarter. As a reminder, our CO2 costs at Del High Field are directly impacted by the price of oil. Therefore, lower oil prices result in lower CO2 costs. General and administrative expenses were $2.6 million for the second quarter versus $2.5 million for the first quarter. The slight sequential increase was primarily due to higher non-cash stock-based compensation in the second quarter that was partially offset by lower professional services fees compared to the first quarter. The end result is that on a cash basis, second quarter G&A was essentially flat with the first quarter. Net income for the second quarter was $10.4 million or $0.31 per diluted share versus $10.7 million or $0.32 per diluted share in the first quarter. Adjusted net income for the second quarter was $9.6 million or $0.28 per diluted share versus $10 million or $0.30 per diluted share in the first quarter. During the second quarter, we invested $1.1 million in development and maintenance capital expenditures. For fiscal 2023, we continue to expect total development capital expenditures of $6.5 million to $9.5 million. This estimate includes upgrades to the Delhi Field Central Facility, workovers at Hamilton Dome Field, the Barnett Shale, and the Jonah Field, and sidetrack drilling opportunities and low-risk development projects in the Wilson Basin, excluding the development of Pronghorn and Three Forks locations. We expect capital spending on our existing properties will continue to be met from cash flows from operations and current working capital. Of course, our spending outlook may change depending on conversations with our operating partners, commodity pricing, and other considerations. After repaying our outstanding debt and upon emerging from blackout, we entered into a Rule 10b-5-1 share repurchase plan in December that authorized up to $5 million in buybacks, subject to limitations on trading volume and stock price. The plan is effective through June 30th and can be extended or renewed by the board. The plan also had a 30-day cooling off period, so there were no repurchases made until January. We plan to provide an update on our buyback activity in our third quarter 10Q to be filed in May. I will now turn the call back over to Kelly for his closing remarks.

Thanks, Ryan. We continue to benefit from the targeted acquisitions that we have completed over the past few years, including two in just the last 12 months. 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. Another component of our capital return strategy is the share repurchase program that we put in place and began making purchases through after having fully repaid our revolving credit facility at the end of the second quarter. This provides the optionality to opportunistically repurchase our shares from time to time through open market transactions, privately negotiated transactions, or by other means in accordance with federal securities laws. 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. 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. Our approach of building a targeted asset base of PDP reserves capable of supporting cash payments to shareholders has served us well over the past decade and will continue to benefit our shareholders for many years to come. As we've discussed in the past, we will closely evaluate and only execute on targeted acquisition opportunities that are immediately accretive, provide long-life established production, strategically expand our base of assets, and do not result in material dilution. Any transaction must also clearly support our long-standing thesis of providing a significant total shareholder return for our shareholders. With that, we are ready to take questions. Operator?

Ladies and gentlemen, at this time, we'll begin the question and answer session. To ask a question, you may press star and then one using a touch-tone telephone. If you are using a speakerphone, we do ask that you please pick up your handset prior to pressing the keys to ensure the best sound quality. To withdraw your questions, you may press star and two. Once again, that is star and then one to join the question queue. We'll pause momentarily to assemble the roster. And our first question today comes from John White from Roth Capital. Please go ahead with your question.

Good afternoon, gentlemen. Very nice results this quarter. Thanks, John. Kelly, are you settling into your CEO chair?

You know, yes is the answer. Again, with the outstanding team we have here, it's made a good, smooth transition. So I appreciate you asking me that.

On the CapEx issues, the press release, as Ryan just reiterated, provides a range of $6.5 million to $9.5 million, and then you explain what that capital spending is going to be directed to. And then there's a phrase in the remainder of that sentence where it says it does not include any CapEx, for the Pronghorn and Three Forks locations in the Williston. Could you give us a ballpark idea of the potential magnitude that some of those wells might add to the fiscal 2023 capital?

Sure. It all depends on The pricing in there, and one of the reasons we've been really going back and forth on this, pricing in that part of the world has moved a lot, and it's moved up, and we're starting to see it ease a little bit. So it's kind of a range per well, a fully completed well. Look, I don't want to give an exact number, but I can say just be safe anywhere from $7.5 to $10 million.

Yeah, that's on an 8H basis, right?

8H, right. And locations, you know, every location is different, you know. So some of them may be as high as 50%. Some of them may be more like 30% where the ultimate location goes.

So you're saying that would change the top end of the range from 9.5 to 10?

No, I'm saying it would add another depending on the working interest, right, gross $7.5-ish to $10 million per well.

Yeah, that would assume that we would drill and complete the well this fiscal year, John, right? So, I mean, that would obviously require us to schedule that. That's right.

Again, that's sort of the concept. It depends on every location has a different sort of working interest. You've got, you have price is moving around significantly for the service side of things in part of the world, and you've got permanent process timing, all those sort of issues to play with. But just on a per well base, I think we've advertised before somewhere in that, and it was a broad range, but we don't want to get too specific at this time.

Oh, no, that's perfectly acceptable, and I understand. And what's the status of some of these locations? Have wells been proposed by the operator and have they sent you an AFV?

So as far as new Pronghorn Three Forks wells, no. We are working with them closely. They have not proposed any wells there. We have. They have proposed AFVs on the recompletions in the Bakken, uphold vertical recompletions in some old Bakken wells, and we've actually recently begun one. And the other part, you know, the other thing we're talking about, you know, we've spoken about the BRRRS or NISQ in the past. And, I mean, John, basically the way this all jumbles together, they all have their own pros and cons, and they have their costs associated with them and expected results and risk. And so you're putting them all in there. We're working together, coming up with, at this time, what makes the most sense to do right now. And on the front, what jumped to the head of the line, and we're excited about it, is the re-completion uphole vertical well. It was drilled deeper than the Bakken, coming uphole and completing it there. So those programs have jumped to the front of the line just when you throw all the variables into the mix. So that's what we're focusing on with the operator right now.

Yeah, we can get some production growth from those sidetracks and the recompletion. Okay, well, thanks for all that detail and putting some numbers around it. I really appreciate it, and I'll pass it on to the operator.

Okay, I appreciate your time and your interest as always, John. Thanks.

And our next question comes from Ludman Schaefer from Northland Capital.

Please go ahead with your question.

Hi, guys. Congratulations on the quarter. I want to start off by talking about the average daily production decline. It's about 5% quarter over quarter. I just want to go through the causes of that. I know you discussed it on the call, but, you know, so... And kind of a little bit of my thinking kind of just running it by you. So, you know, oil was down just the 1% while gas and NGLs were down much more at 5% and 8% respectively. In my mind, that kind of squares my understanding of how I think natural gas sometimes can be impacted more because of sort of pressure changes that have an impact and liquids can fall out and freeze. So sometimes I think that can in some ways almost counterintuitively be more vulnerable the oil, and then, of course, there's the compressor down and the barnets. So I guess the first question is just, am I right about the general impact of freezing weather with oil versus, like, flowing? You know, I know operations are hard no matter what, like trying to drill a new well. But in terms of flowing, am I accurate on that in terms of oil versus gas? And then the follow-up there would just be, You know, would production have been up quarter over quarter or just flat without any of these sorts of disruptions, you know, the weather and the compressor? Would it have been up if you could kind of quantify, like, what kind of path you were on and if we should expect things to bump back next quarter, you know, get a production bump? Sure.

So I'll talk a little bit about the first part of your question. In general, oil is liquids, right? And they have a tendency to be able to freeze. However, it depends on where you are. Like our operator foundation in Williston, they're very used to and very good at handling and winterizing the wells. Now, the biggest impact there on the oil side, honestly, was if you get three feet of snow, you can't drive down the road to get to the well, right? But as far as their equipment goes, they've done a great job of winterizing it, so it wasn't affected too much. And in Delhi, there were some problems in Delhi, as we alluded to, in the first quarter. So the fact that we're flat, some of us were covering the issues in the first quarter. We did have to shut down because things were confusing there a little bit in the Delhi side. So I would actually argue – probably oil, which is liquids, is more susceptible to the freezing storms. But everything, you can freeze a valve. When you get storms that bad and everything is up, it can impact anything you're doing.

Okay, that's helpful. And on the sort of if you can quantify our ballpark, would we have seen increases this quarter based on just kind of the path you were on if we didn't get the weather or the compressor shut down? Should we see a bounce back next quarter with things cleared up and the compressor coming back online? Just trying to kind of get a normalized idea of how to think about production going forward.

Yeah, that's – so I'm not going to – I don't want to say too much as far as going forward. Now, looking backwards, what I can say is, Overall, the net impact was about 5%. We have a corporate decline rate which is lower than 5% per quarter. So, yeah, I think you can kind of understand the impact there. I don't want to get too specific, and I don't want to give guidance, but we were lower than we ought to have been due to impacts of these things, for sure.

Yeah, it's hard to say, Donovan, I mean, if – Barnett was, as you can probably see, the most of the impact quarter to quarter. It's hard to say with any degree of complete certainty where we would have been if the issues hadn't have occurred. We certainly would have been closer to last quarter than we are today, but it is on decline. Diversified has done a great job reactivating wells, but at this point, they've reacted most of what they're probably going to. you know, we're probably going to expect to see some decline going forward, but we would certainly hope that there would be some bump, to your point, next quarter from this quarter with some of these issues hopefully being rectified, assuming nothing else crops up, right, as you know can happen in the field.

Okay. Okay. That's helpful. And then I'd like to dig a little bit deeper into the production costs since, you know, from my perspective, that was kind of a major driver behind the EBITDA beat. I think, you know, can we talk through that some more and help me think about how to model it going forward? So, you know, one of the key things looked like the change. I understand sort of, you know, ad valorem and all that stuff. But the biggest driver, you said, was the change in estimates from prior periods. And I think in the past you've said that has to do with a lag in commodity price changes, right? And that impact on LOEs, you know, something like, you know, if you're consuming gas on site to drive the compressors or something like that, then, of course, that sort of, quote, unquote, you know, cost is going to be tied very closely to commodity prices. And then it's sort of a billing cycle thing that creates the lag. Is it a pretty straightforward one-quarter lag where I could do, you know, if I did, say, like, a correlation analysis where I took – you know, commodity prices, but it did a one-quarter lag versus forecasting. Would that, you know, hone in on a good prediction there, or would that kind of lead me astray? Is it not really one quarter, but it can vary?

It was that easy, right? So, I mean, a lot of the costs we have in the – and we'll talk about that somewhere. You know, we tend to see – we see more variability here. Most of our costs, a lot of the LOE is in gathering, right? And we get billed on a two-month lag for that. So it's really not one month, that's two months. And there is impacts there from commodity prices on the gathering and processing side. And so, you know, as we've seen, as I mentioned last quarter, as we've seen prices go up, you know, that does filter through, and our estimates have updated throughout. And so while we had a negative impact this past quarter, we had an official positive impact this quarter in the Barnett. And so we reported around $15 a barrel, and you can see in our press release for this quarter on LOE for the Barnett, You know, I think last quarter I said a range of $20 to $25, and I still think that's a good range for the Barnett. Now, you know, some of that, obviously, as you mentioned, depends on pricing. And if pricing is lower, I would certainly put it at the lower end of that range, then not higher. But I still think the $20 to $25 barrel for the Barnett is probably a good, you know, longer-term way to model that. And on the other areas, you know, we've seen, you know, those have been pretty consistent, really, if you look on the other areas kind of. area to area, with the exception of sort of the Williston, you know, having some, you know, less work over activity this quarter, which we saw a little bit of drop in that area specifically.

And if you recall, Donovan, last quarter we spoke to Williston. Foundation was doing a really good job of pulling strings completely and changing them out, getting ahead of the curve, which should have the effect of keeping them on longer and having less downtime. So we front-loaded some of that LOE workover costs at Williston last quarter, and you see the effect of it this quarter.

Yeah. I see. Okay. And the last question, and I'll hop back in the queue, but since you paid off the debt and – You know, you've got the buyback, but this also means that, you know, all things considered, it means you're in a great position to be considering or, you know, more actively looking at deals as a possibility, kind of seeing where can you get the cheapest barrels, and maybe that means buying back your own shares, but, you know, that also means comparing against what opportunities are out there. So how actively are you guys looking at deals right now? And are they more in the form of, you know, potential asset purchases or things where you're looking at maybe, you know, picking up an entire company?

Okay. So you can – the answer in a theoretical answer is we're open to whatever is the best deal and what makes the most sense at that time. Honest answer for what we've actually had – dug into has been more acquisitions of assets. That's not for any reason. Over the past, we consider all sorts of deals and what's the most accretive and what's going to be the best return for our shareholders. In the last few months, what we've had, we've been able to go meet with people about has been more assets, but that just happens to be the case. We're not opposed to that. I'll just say Acquisition front, we're competitively looking all the time for acquisitions, and I don't want to get too into the weeds on expected pricing and all that. But I think I've said this before, and you've seen it the last couple of quarters, no deal is better than a bad deal. And sellers have been pricing in high front month pricing forever. when the curves were severely backwardated. And we've seen those strips start to change. And I think we're going to fairly quickly be able to see sellers' expectations, see if they move as well. I can say that we're somewhere along the commodity price curve, certainly with natural gas. I think we're a lot further from the top than we were a couple months ago. I agree. We're starting to – we have been, but we're digging in as much as ever on the acquisition front.

Okay. Makes sense. I'll pop back in the queue.

And our next question comes from John Bear from Ascend Wealth Advisors. Please go ahead with your question.

Thank you. Good afternoon. Happy New Year to you.

Thanks, John.

Thank you, Ryan and Kyle. So I have a couple questions. Number one, it was rather interesting pricing that you got from Jonah Production, and just wondering if those elevated prices for gas are still out there, or has that come down with the overall decline in gas prices?

Yeah, so it's interesting, right? So when we bought the property, you know, I wouldn't say we predicted what – we could have predicted what happened, but we were bullish on California and kind of pricing in the West, and the winter sort of held true to an extreme nature, right? If you know – if you follow California weather, it's been a very cold – you know, maybe unusually cold winter out there, and with kind of the energy policies in the state, you know, they're short natural gas, and you get these phenomenons in the winter that we saw here in December. We actually saw it in, you know, we've seen it in January as well a little bit, and some in February prices are coming down a little bit, but, you know, I'd say it's definitely surpassed our expectations. I think we had been hopeful that we would see this winter premium, which we had seen in the historical data we reviewed when we bought the asset, just not to this extent. It's hard to say, are we going to see this again? It's certainly possible for abnormally cold winters, but whether it's going to be a big driver of that along with hydroelectric power and lots of other variables, but we've certainly been really pleased this winter.

Basically, the pricing tightness there, the spread versus Henry Hub is still a pretty big spread there, right? In other words, in your press release, you said you were getting like $11 per MCF for the gas, right? That's for the core. Yeah, so it's still kind of up in that range. Obviously, probably not exactly, but is that a fair statement? Observation.

Okay, so I don't want to give too much. I will say factually there have been days this quarter where we received gas prices that were at least in that range. How about that?

Yeah, I mean, I think of all, you know, it's been if you follow, you know, we sell a lot of kind of opal, right, of the tailgate there. So if you follow the daily pricing, yeah, it was high in January. It's come down a little bit in February, right? It's still at a premium to Henry Hub, but it's certainly come down. So we're hopeful. We don't know how this quarter is going to end. We're hopeful we'll have strong pricing again this quarter, but, you know, we're not even halfway through this quarter yet.

And, John, look, I don't want to say anything that sort of falls into the political spectrum, so I'm not going to comment on why California is in the situation it is, But I can say, yeah, clearly there's insufficient natural gas being delivered to California because all the roots are maxed out, and yet they're still record high prices.

Yeah, that's fine. You don't have to go – I'm with you on that end of it. So as far as the two birdbear wells you mentioned – side tracks, are those testing new geographical areas, like new units, or is it more kind of infill type?

So the birdbear itself, and this is something we're continuing to do work on, and the question is, is it a conventional play, is it a non-conventional play, or is it just very chopped up and so you need to make sure you go out and encounter some variety along the way. And the answer is, yeah, they're both infill, and yeah, they're both new. It depends on how small the drainage pocket is that you're going into. And you may encounter several of these across a wellbore. And let's put it this way. From a close ology perspective, they're close.

Okay. And then I think I kind of missed this, but you mentioned on the vertical recompletions, Are these new zones within the wellbore, is that right, or not?

That's correct, yes. These opportunities, you know, there's several of them, not as many as we'd like, but there are, you know, at least a handful where they were drilled deeper and bypassed by the Bakken or Duperow. And so you go uphole and put a big single vertical stake back on it.

And then if the pronghorn and three forks, if those were to come up, would you possibly tap into your credit facility if the dollars were more than what you had cash on hand, or would you work it out of cash flow, or kind of what's your thoughts on that?

I mean, it's kind of more, really more of a working capital, right, decision. I think we wouldn't drill the well unless we thought they were going to be cash flow positive, right? So obviously incurring cost up front, but Given that we're now debt-free and we have good cash flow, certainly we would hopefully do them out of cash flow, but it just depends where we are in the cycle from a working capital standpoint. But I would say we're not going to borrow long-term capital to drill the wells.

I didn't mean to imply borrowing long-term was more if you needed a short-term bump. Philosophically, I just

I really don't want to borrow money to drill wells.

Right. Right. Got it. Last question. There was a recent article in the journal kind of highlighting Denberry and the fact they had the CO2 pipelines. And we talked about it a little bit a few months back. And I was just wondering if there's been any progress in the utilization of that pipeline system to gather industrial CO2 gases and so forth. And if so, how might that benefit evolution if industrial producers of that were to utilize the pipeline? Would that help you all out? Would that affect the contract that you have with the oil prices and the use of CO2?

Does that make sense? Yes, it does. I've had people ask if they get the green pipeline certified and you have a tap on the green pipeline, are you going to be able to get carbon credits and all that? Honestly, I don't know the answer to that. We have some smart people looking into it, but I think they're sort of waiting for more guidance from the governmental types. But as far as if we're taking, I always get this word wrong, anthropomorphic, rather, so new, like CO2 created from big machinery complexes and all that, man-made CO2. If you take that and put that in the green pipeline and we can get some of it allocated to Delhi versus the other fields, then I would assume it's probably going to come at a cheaper cost than what we're getting from Denver's Jackson Dome Project.

Yeah, I guess where I was kind of going with that in the bigger picture is would that help to lower the overall cost for your Deli operations? In other words, would you be able to capitalize on that? Would it cause renegotiation of the contract or whatever that you're in right now, given that you're paying, you know, to cost based on the price of oil barrels and so forth.

Right. You know, it potentially is the answer, but we're not We're not at that. So if there's a way for we and Denberry to come to a better contract that benefits both parties, I'm sure we'd both be up for it. But at this point, we're not far enough along to speculate.

Right. Okay. Very good. Thanks a lot. Appreciate the questions. Keep on going. keep on producing.

Yeah, thanks, John. I really do appreciate your continued interest.

Thanks a lot for taking the time. Thanks, Sam.

Once again, if you would like to ask a question, please press star and then one. To withdraw your questions, you may press star and two. Our next question comes from Jeff Robertson from Water Tower Research. Please go ahead with your question.

Thank you. Good afternoon, Kelly. You mentioned... You mentioned when you were discussing acquisitions some of the impact of the pricing volatility. Can you provide any real color on what impact the drop in natural gas prices over the last six months is having on seller expectations? And also, is it having any impact on the types of properties that you're seeing in the market?

So, yeah, good question. And I think the answer is, I mean, this rundown has really been fairly rapid. And it's what we're going to see, at least this is my expectation, you'll see some of the sellers' expectations start to move more in line with. If you recall, they were extremely backward-headed, right? So sellers... generally wanted to get the high front month and keep that flat forever and sell it to you on that kind of a quote unquote strip. Uh, whereas, you know, a conservative prudent buyer, you're going to have to use a discount to the actual strip. So now that we've come back where the front and the back are a lot closer to equal, I think you're going to see start to come to the realization that this is the real price they're going to get. So we expect to see some, some movement there. And, uh, We expect it to be helpful from a buyer's perspective. As far as types of deals coming to the market, not particularly yet. I think we will. Again, we had a production response to high prices. I think we're going to see a production response to low prices. But there's always a lag. So I think in the months or whatever time period that we're going to be down here, I think we'll have some new assets hit the market and we'll have some real opportunities.

Secondly, on Jonah and the Barnett, are you seeing much from the operators as far as what their plans are for, let's just say, the rest of your fiscal year over June? kind of over projects to enhance production or have they slowed work over activity or put some things on that they otherwise might do in mothballs just given where prices have fallen to?

Yeah, I mean, I think from the Barnett specifically, right, so they've pretty much reactivated most of what they had on their market. what their list was when they bought the asset. So at this point, they're more just fixing things as it comes up. So, you know, I don't know if we're going to see any more proactive activations there. I think Jonah's is probably pretty similar. I mean, there weren't a lot of reactivations to begin with. You know, they were one recomplete that I think they I think they did finish that, but there's really not a lot of other activity, at least in our portion of the acreage that we own in Jonah that they've sort of hinted. So, you know, we haven't heard a lot that prices, other than, like I said, for the Barnett, sort of no longer proactively reactivating wells. There hasn't been a lot of impact yet to that.

Yeah, and so, I mean, Jonah in the first quarter did some sort of consolidating of compression, but that's already been done, so... We're seeing the benefits of that now, but I don't know that they have a whole lot else other than normal kind of wear and tear. Okay. Thank you for taking my questions.

Yeah, really appreciate it.

And our next question is a follow-up from Donathan Schaefer from Northland Capital. Please go with your follow-up.

Sure. Hey, guys. I'll just do two more quick ones. The first one is just, For the natural gas pricing west of the Rockies, are there any kinds of lags at all in terms of revenue recognition, just if we're following that spread and trying to anticipate each quarter based on how that does relative to Henry Hub and everything? If there's a price blowout near the tail end of December, does that spill over at all into the next quarter? you know, that last week or something, or is it pretty cut and dry? It all falls into, you know, whatever you look up in terms of spot pricing. That kind of lines up one to one.

So, yeah, a couple of things, right? So, you know, the way that we market our gas, and we're not unlikely to have operators, that we sell probably the majority of it on what they call inside FERC, if you're familiar with that, inside FERC sort of pricing. So a lot of the pricing gets set, actually, at the beginning of the month. But, you know, unless you subscribe to Platts and the publication or you have Bloomberg, it's kind of hard to find that pricing necessarily. But a lot of it does get sold at that. The remainder gets sold on a daily basis. So, you know, you're going to take the average of the month that, you know, we're going to sell over the whole month, and that portion of it, you know, less than half is sold on a daily basis. So it's a little bit twofold. as to the price. So in your example, if you had a run-up in prices at the end of December, we would see some of the benefit that in December for the daily pricing, but not as much from, you know, what we call the baseload volume we sold. But at the end of January with the run-up, right, obviously that would benefit us in January from that first-of-month pricing, if that makes sense.

Okay. Yeah, that's interesting. And then the last is just I was feeling the need to kind of check in on the conventional assets, you know, Dow High, Jonah, and Hamilton. when you're in a sort of sustained higher price environment, you know, I know gas has come down a lot, but a lot of times the operators will sort of circle back around and think or ask themselves, you know, can we turn this up somehow to another level or another phase or anything like that? And so I know there's the heat exchange project at Valhalla, but just have there been any sort of incremental conversations or incremental interest in, you know, doing other types of, additional phases or investments or things in those fields? Maybe not a decision yet, but just increased interest in, like, hey, we might want to do that.

Let's see. So, you know, that's a really good question. I'm thinking one of the – I had an answer in mind, but it's not really a choice we made. In the Westin, the One Oak Pipeline – coming on has really been helpful with natural gas and NGL sales. And this is, we're just starting to see the benefit of that. I mean, it hadn't really been on the whole time we've owned it. So that's not really a capex, right? It just, you know, it was down. Now it's not. So we'll see some benefit there. Hamilton Dome, look, Merit's done a great job of, adjusting their production injection rates and going from there. And they've been able to keep that pretty flat. So it's not just sort of one big thing, let's do it. It's constantly adjusting and moving and tending to things. So it's kind of never-ending. I think we've seen really good benefits from that. And Delhi, yeah, I mean, here's the biggest thing at Delhi that, we're pushing for is getting Test Site 5 back on, right? So that's one we think economically it for sure is a very good economic project that merits being on the books. So that would be the big impact, honestly. Heat exchanger, too. But, you know, it's a lot of barrels if you get Test Site 5 back on.

Well, yeah, that's kind of the type of thing I was thinking about. So that's some great color. Thank you very much, and I'll take the rest offline. Thanks, guys. Great.

Thanks again, gentlemen.

And, ladies and gentlemen, at this time, in showing no additional questions, I'd like to turn the conference call back over to Kelly Lloyd for any closing remarks.

Great, thank you. Thanks again to everyone for taking the time to listen and participate in today's call. As always, please contact us if you have any additional questions. We appreciate your continued support and look forward to updating you on our ongoing efforts when we report our third quarter results in May. Have a good day.

Ladies and gentlemen, that does conclude today's conference call. We do thank you for joining. You may now disconnect your lines.