Evolution Petroleum Corporation (AMEX:EPM) Q2 2023 Earnings Call Transcript

Evolution Petroleum Corporation (AMEX:EPM) Q2 2023 Earnings Call Transcript February 8, 2023

Operator: Good day, everyone, and welcome to the Evolution Petroleum Second Quarter Fiscal Year 2023 Earnings Release Conference Call. . 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.

Ryan Stash: Thank you, and good afternoon, everyone. Welcome to our earnings call for the second quarter of fiscal 2023. Joining me today is Kelly Lloyd, our 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.

Kelly Loyd: 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 have 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 a sustainable quarterly dividend for the immediate 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 Barnett 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 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 gas pipeline. We are pleased to see the ONEOK 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 sales. 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, Merit 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 Merit began upgrading facilities to proactively reduce emissions throughout the field. Second quarter net production at Delhi Field was approximately 1,131 BOE per day. Denbury, the operator at Delhi 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.

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Ryan Stash: 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 of 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 2 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 $0.12 per share in the second quarter and declared a dividend of $0.12 per share for the third quarter of fiscal 2023, payable on March 31 to shareholders of record as of March 15. 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 6 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 on 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 Hub 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 from prior periods and reduced ad valorem and production taxes due to lower revenues in the current period. Also contributing to the decrease was lower work-over expense in the Williston Basin and reduced CO2 costs at Delhi Field associated with the decrease in crude oil prices from the prior quarter.

As a reminder, our CO2 costs at Delhi 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 noncash 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 Williston Basin, excluding the development of Pronghorn and Three Forks locations. We expect capital spending on our existing properties were continuing 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 10b5-1 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 30 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 10-Q to be filed in May. I will now turn the call back over to Kelly for his closing remarks.

Kelly Loyd: Thanks, Ryan. We continue to benefit from the targeted acquisitions that we have completed over the past few years, including 2 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 pay down 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?

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Q&A Session

Operator: . Our first question today comes from John White from Roth Capital.

John White: Very nice results this quarter. Kelly, are you settling into your CEO Chair?

Kelly Loyd: It’s — 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.

John White: On the CapEx issues, the press release and 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 where it says 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 CapEx?

Kelly Loyd: 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 bit. But — so it’s kind of a range per well, a fully completed well. And look, I don’t want to give an exact number, but I would say, just to be safe, anywhere from $7.5 million to $10 million.

John White: Yes. That’s on an basis, right?

Kelly Loyd: Right. are working in locations, every location is different. So some of them may 50%, some of them may be more like 30%, where the ultimate location goes.

John White: So you’re saying that would change the top end of the range from 9.5% to 10%.

Kelly Loyd: I’m saying you would add another depending on the working interest, right, gross $7.5-ish to $10 million per well.

Ryan Stash: Yes. That would assume that we would drill and complete the well this fiscal year, John, right? So I mean that would obviously require decision.

Kelly Loyd: That’s right, but again, that’s sort of the concept. It depends on — every location has a different sort of working interest. You’ve got — you have prices moving around significantly for the service side of things part of the world. And you’ve got permitting process timing. All those sort of issues to play with. But just on a per well base. I think we’ve advertised for somewhere in that, and it was a broad range, but we don’t want to get too specific at this time.

John White: 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 AFE?

Kelly Loyd: So as far as Pronghorn, Three Forks wells, no, we are working with them closely. They have not proposed any wells there. We have — they have proposed AFEs on the recompletions in the Bakken, up hole vertical recompletions in some old Bakken wells, and we’ve actually recently begun one. And the other part — the other thing we’re working about — we’ve spoken about the or 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 cost 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 that front, what jumped to the head of the line and we’re excited about it is the recompletion up hole vertical well, it was drilled deeper than the Bakken coming up when completing it there.

So that — those programs have jumped to the front of the line, just when all the variables into the mix. So that’s what we’re focusing on with the operator right now.

John White: Yes. 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.

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

Operator: And our next question comes from Donovan Schafer from Northland Capital.

Donovan Schafer: Congratulations on the quarter. I want to start off — yes, I want to start off by talking about the average daily production decline of about 5% quarter-over-quarter. I just want to go through the causes of that. I know you discussed it on the call, but — so — and kind of a little bit of my thinking kind of just running it . So oil was down just 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 back in some ways, almost counterintuitively be more vulnerable to oil. And then, of course, there’s the compressor down in the Barnett.

So I guess the first question is just am I right about the general impact of freezing weather with oil versus like flowing. I know operations are hard no matter what, like trying to drill a new well. But in terms of flowing, my accurate on that’s just oil versus gas. And then the follow-up there would just be would production have been up quarter-over-quarter or just flat without any of these sorts of disruptions, the weather and the compressor. Would it have been up if you could kind of quantify like what kind of path you are on? And if we should expect things to bump back next quarter to get a production bump.

Kelly Loyd: 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 the Williston, they’re very used to and very good handling and winterizing the wells. Now the biggest impact there on the oil side, honestly, was if you get 3 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 . 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 those recovering the issues in the first quarter, we did have to shut down because things were there a little bit in the Delhi side.

So I would actually argue probably oil, which is liquids is more to the freezing storms. But everything you can freeze a valve. When you get storms that bad and everything goes up, it can impact anything you’re doing.

Donovan Schafer: Okay. That’s helpful. And on the sort of — if you can quantify or ballpark just would this have been — would we have seen increases this quarter based on just kind of the path you’re on? If we didn’t get the weather or the compressor shutdown, should we see that — 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.

Kelly Loyd: Yes, 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 lower than 5% per quarter. So yes, 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 when we ought to have been doing the impacts of these things.

Ryan Stash: Yes, it’s hard to say, Don, if the Barnett was, as you can probably see the most of the impact quarter-to-quarter or to say with any degree of complete certainty where we would have been if this hadn’t have occurred, right? We certainly would have been closer to last quarter than we are today, but it is on decline. And Diversified has done a great job reactivating wells. And but at this point, they’ve reacted most of what they’re probably going to. And so 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 have been rectified. Assuming nothing else crops up, right, as you know, can have in this field.

Donovan Schafer: Okay. Okay. That’s helpful. And then I’d like to dig a little bit deeper into the production costs since from my perspective, that was kind of a major driver behind the EBITDA . I think — could we talk through that some more and help me think about how to model it going forward. So one of the key things look like — I understand sort of 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 said that has to do with a lag in commodity price changes and that impact on LOEs, something like if you’re consuming gas on site to drive the compressors or something like that, then, of course, that “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 — if I did say like a correlation analysis, where I took commodity prices, but it did a one quarter lag versus forecasting, would that hone in on a good prediction there? Or would that kind of lead me astray? Not really 1 quarter, but it was…

Ryan Stash: it was easy, right? So I mean a lot of the costs we have in the — let’s talk about the where we tend to see — we see more variability here that most of our costs, a lot of the LOEs in gathering, right? And we get built out a 2-month lag for that. So it’s really not 1 month, that’s 2 months. And there is impacts there from commodity prices on gathering and processing side. And so as we’ve seen, as I mentioned last quarter, as we’ve seen prices go up, that does filter through in our estimates have updated throughout. And so while we had a negative impact past quarter, we had a official positive impact this quarter in the Barnett. And so we reported around a barrel you can see in our press release for this quarter on LOE for the Barnett.

I think last quarter, I said a range of $20 to $25, and I don’t think that’s a good range for the Barnett. Now some of that, obviously, as you mentioned, depends on pricing. And if pricing is lower, we certainly at the lower end of that range, and not higher. But I still think the $20 to $25 a barrel for the Barnett is probably a good longer-term way to model that. And on the other areas, obviously, we’ve seen, those have been pretty consistent, really, if you look on the other areas, kind of area to area, with the exception of . So the Williston having some less workover activity this quarter, which we saw a little bit of drop in LOE in that area specifically.

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

Donovan Schafer: I see. I see. Okay. And then last question and I’ll hop back in the queue. But since you paid off the debt and you’ve got the buyback, but this also means that all things considered, it means you’re in a great position to be considering or 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 that also means comparing against what opportunities that are out there. So how actively are you guys looking at deals right now? And are they more in the form of potential asset purchases or things that you are looking at maybe picking up an entire company?

Kelly Loyd: 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. And that’s not for any reason. Look, 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. I’m just — in the last few months what we’ve had, we’ve been able to go meet with people about has been more , but that’s just happens to be the case. We’re not opposed to that. And 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 on expected pricing and all that.

But I think I’ve said this before, and you’ve seen it in the last couple of quarters, no deal is better than a bad deal. And sellers have been pricing in high pricing forever when the curves were severely backward dated. And we’ve seen these 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’t say — I can say that we’re somewhere along the commodity price curve. Certainly, with natural gas, I think we’re a lot further top than we were a couple of months ago. So I agree. We’re starting to — we have been, but we’re digging in as much as ever on the acquisition front.

Operator: And our next question comes from John Bair from Ascend Wealth Advisors.

John Bair: So I have a couple of questions. Number one, is 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?

Ryan Stash: Yes. So it’s interesting, right? So when we bought the property, 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 followed California weather, it’s been a very cold — maybe unusually cold winter out there and with kind of the energy policies in the state, they’re short natural gas. So you get these phenomenons in the winter that we saw here in December. We actually saw it in — we’ve seen it in January as well a little bit. and some in February, prices are coming down a little bit. But 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. So I mean it’s hard to say or are we going to see us again. It’s certainly possible for abnormally cold winters, but one is 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.

John Bair: So basically, the pricing tightness there, the spread versus Henry Hub is still ruled 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? So still kind of up in that range, obviously, probably not exactly, but is that a fair statement, ?

Kelly Loyd: 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, that.

Ryan Stash: Yes. I mean I think of all, it’s been — if you follow — look, we sell out of kind of Opal, right, of the tailgate there. So if you follow the daily pricing, yes, it was high in January. It’s come down a little bit in February, right? They go 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 we’re only — we’re not even halfway through this quarter yet.

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

John Bair: Yes. That’s fine. You don’t have to go — I’m with you on the — on that end of it. So as far as the 2 Birdbear wells you mentioned, sidetracks, are those testing new geographical areas like new units? Or is it more kind of infill type?

Kelly Loyd: 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 nonconventional play? And — or is it just very chopped up and so you need to make sure you go out and count or along the way. And the answer is, yes, they’re both infill and yes, they’re both new. It depends on how small the pocket is that you’re going into, and you may encounter several of these across the wellbore. I’d say, let’s put it this way. From a closeology perspective, they’re close.

John Bair: Okay. And then I think I kind of missed this, but you mentioned on the vertical recompletions, are these new zones within the wellbore set rate or not?

Kelly Loyd: That’s correct. Yes, these opportunities . There’s several of them, not as many as we’d like, but there are at least where they were drilled deeper and bypassed the and so you go up hole and put a big single vertical back on it.

John Bair: And then the , 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?

Ryan Stash: I mean it’s kind of more — really more of a working capital, right, decision. I think we wouldn’t drill the wellness we thought they were going to be cash flow positive, right? So obviously, cost upfront. But given that we’re now debt-free, and we have good cash flow. Certainly, we would hopefully do them out of cash flow. It just depends where we are in the cycle from a working capital standpoint. But what I would say, I’m not going to borrow long-term capital to drill the wells, right?

John Bair: I didn’t mean to imply long term, it was more if you need short-term bump, yes.

Kelly Loyd: I don’t want to — philosophically, I just — I really don’t want to borrow money to drill wells.

John Bair: Right, right. Got it. Last question. There was a recent article in the journal about kind of highlighting Denbury 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, would that — 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?

Kelly Loyd: So that’s interesting. Yes, it does. I mean 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? And 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 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 Denbury’s Jackson. projects.

John Bair: Yes. 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 Delhi operations? In other words, would you be able to capitalize on that, would cause renegotiation of the contract or whatever that you’re in right now, given that you’re paying CO2 costs based on the price of oil barrels and so forth?

Kelly Loyd: Right. It’s — it potentially is the answer, but we’re not at that. So let’s — if there’s a way for and Denbury to come to a better contract that benefits both parties. I’m sure we’d both be up for. But at this point, I just — we’re not far enough along to speculate.

Operator: . Our next question comes from Jeff Robertson from Water Tower Research.

Jeffrey Robertson: You mentioned when you were discussing acquisitions, some of the impact of the pricing volatility. Can you provide any real color on what impacts the drop in natural gas prices over the last 6 months is having on buyer — or I’m sorry, seller expectations? And also, is it having any impact on the types of properties that you’re seeing in the market.

Kelly Loyd: So yes, 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 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 “strip” whereas a conservative prudent buyer, you’re going to have to use a discount to the strip. So now that we’ve come back with 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 movement there, and we expect it to be helpful from a buyer’s perspective.

And as far as types of deals coming to the market, I just — not particularly yet. I think we will. If — again, we had a production response to high prices, I think we’re going to see a production response to low prices but there was a lag. So I think in the months or whatever time period that we’re going to be down there, I think we’ll have some new assets in the market, and we’ll have some real opportunities.

Jeffrey Robertson: Secondly, on your — 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 next — the rest of your fiscal year over kind of other projects to enhance production or have they slowed workover activity or put some things on that they otherwise might do in just given where prices have fallen to?

Ryan Stash: Yes. I mean I think from the Barnett specifically, right, so they’ve pretty much reactivated most of what they had on their — what their list was when they bought the asset. So at this point, they’re more just fixing things as it comes up. So I don’t know if we’re going to see any more proactive reactivations there. Jonah, I think Jonah is probably pretty similar. I mean there weren’t a lot of reactivations to begin with. They were one recomplete that 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 we haven’t heard a lot that prices, other than, like I said, for the Barnett sort of no longer proactively reacting well on a lot of impact yet to that.

Kelly Loyd: Yes. And so 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 wear and tear.

Operator: And our next question is a follow-up from Donovan Schafer from Northland Capital.

Donovan Schafer: Sure. I’ll just do 2 more quick ones. The first 1 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. Is there like there’s a price blowout near the tail end of December, does that spill over at all in terms of into the next quarter, that last week or something? Or is it a pretty cut and dry, it all falls in whatever you look up in terms of spot pricing, that kind of lines up 1:1.

Ryan Stash: So yes, a couple of things, right? The way that we market our gas, we’re of operators that we sell probably the majority of it on what they call inside FERC. If you’re familiar with that, sort of pricing. So a lot of the pricing gets set actually at the beginning of the month. But it’s — unless you subscribe to the publication or you have Bloomberg kind of hard to find that pricing necessarily. A lot of it does sold at that. The remainder is sold on a daily basis. So you’re going to take the average of the month that we’re going to sell over the whole month, and that portion of it, less than half is sold on a daily basis. So it’s a little bit 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 the — what we call the baseload volume we sold.

But again, in January, with the run up right, obviously, that would benefit us in January from the month pricing, if that makes sense.

Donovan Schafer: Okay. Yes, that’s interesting. And then the last is just I was feeling need to kind of check in on the conventional assets, Delhi, Jonah and Hamilton. When you’re in a sort of sustained higher price environment, 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, 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 Delhi, but just have there been any sort of incremental conversations or incremental interest in 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.

Kelly Loyd: Let’s see. So 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 , the 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 just it was down, now it’s not. So we’ll see some benefit there. Hamilton Dome, look, Merit has 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 thing. Let’s do it. It’s constantly adjusting and moving and tending to things. So it’s kind of never ending.

But I think we’ve seen really good benefits from that. In Delhi, yes, I mean, Here’s — the biggest thing at Delhi that we’re pushing for is getting 5 back on, right? So that’s one we think, economically, it for sure is very good economic project that Merits being on the books. So that would be the big impact, honestly. but a lot of barrels if you can side in.

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

Kelly Loyd: 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.

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