Evolution Petroleum Corp (EPM) 2022 Q2 法說會逐字稿

Good afternoon, ladies and gentlemen, and welcome to the Evolution Petroleum Second Quarter Fiscal Year 2022 Earnings Release Conference Call. (Operator Instructions) It is now my pleasure to turn the floor over to your host, Ryan Stash. Sir, the floor is yours.

Thank you, and good afternoon, everyone, and welcome to Evolution Petroleum's earnings call for our second quarter of fiscal year 2022. I'm Ryan Stash, Chief Financial Officer. Joining me today is Jason Brown, our President and Chief Executive Officer. After I cover the forward-looking statements, Jason will review key highlights along with our operational results. I will then return to provide more in-depth financial review. And finally, Jason will provide some closing comments and details about our 2 recent acquisitions before we 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, and actual results may differ materially from those expected.

Since 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 replay of today's call, it will be available by going to the company's website or via recorded replay until May 11, 2022.

Now with that, I'll turn over the call to Jason.

Thank you, Ryan. Good afternoon, everyone, and thanks for joining us today on Evolution's Second Quarter Fiscal 2020 Earnings Call. As Ryan mentioned, we will discuss our 2 recent acquisitions in the Williston Basin and Jonah Field after our financial results.

We posted a presentation on our front page of our website if you would like to download it. In the meantime, I will use this slide deck to discuss our acquisitions in more detail.

We've been pretty busy since our last update in November. I'm happy to say that the team's efforts have been fruitful for our shareholders. As always, we appreciate your continued interest in our company and welcome any questions that you might have regarding our business and recent acquisitions.

We were pleased with our overall results in the second quarter, which were highlighted by continued free cash flow generation. This supports our long-term strategy of operating within cash flow and paying an ongoing meaningful cash dividend to shareholders. We've also continued our plans of expanding our geographic footprint through executing on targeted transactions that promote our ability to further increase our return of capital to shareholders.

In the last 3 weeks, we have announced 2 accretive acquisitions we believe will increase the longevity of our dividend payout program through the next decade. I will discuss the collective transformative nature of these transactions for -- during my closing comments.

For the second quarter of 2022, we had net income grew 31% to $6.8 million or $0.20 per diluted share from $5.2 million or $0.16 per diluted share in the previous quarter. We continue to benefit significantly from higher commodity prices as we are unhedged during the quarter, which resulted in an adjusted EBITDA of $10.2 million, which was a 20% increase from the first quarter. In addition, we were able to grow our cash position to $13.6 million at quarter end, which was 71% higher than our cash balance at September 30, 2021.

During the second quarter, we produced 49 57 net BOE per day, which is down from 58 43 net BOE per day for the first quarter of fiscal 2022. Included in our second quarter production results was a downward adjustment of approximately 400 net BOE per day due to the production mix adjustments by the operator in the Barnett Shale to reject ethane and capitalize on the higher natural gas prices in the first and second quarters, thereby improving cash flow generation.

Also included in the second quarter production was the receipt of past oil royalties from accumulated over a period of approximately 3 years associated with an overwriting royalty interest owned in 2 wells located in Giddings Field in Burleson County, Texas.

Now let's look at our operating results in more detail. Net production in Delhi for the first quarter was 108,245 BOE or 1,177 BOE per day. That's an 8% decrease compared to the prior quarter. Oil production in Delhi continues to be impacted by the 9-month suspension of CO2 purchases during calendar 2020 and due to repairs to the purchase supply line. The result has been lower reservoir pressure and Denbury who operates the field and owns and operates the CO2 purchase line and has worked diligently to restore pre-2020 levels.

I would note that CO2 purchase increased to approximately 100 million cubic feet per day in the second quarter, which has assisted in arresting the decline and restoring some of the reservoir pressure previously lost. Also impacting Delhi production in fiscal 2022 second quarter was planned and unplanned compressor maintenance in November and December and temporarily reduced daily production.

At Hamilton Dome, we saw a sequential quarter increase in net production of 2% to 30,021 a barrels or 413 barrels of oil per day. It's primarily due to continued restoration of previously selling wells and strategic adjustments to water injection locations and volumes. Our operating partner, Merit, remains focused on maintenance projects at Hamilton Dome.

Net production from the Barnett assets for the second quarter of fiscal '22 were 285,761 BOE or 3,106 BOEs per day, which is about 25% lower than the first quarter. As I mentioned earlier, the production of our net shale was impacted by Diversified Energy's decision as the operator to maximize the overall field cash flow by capturing the most favorable commodity price. Diversified adjusted the production mix in both the second and the first quarter of '22, which resulted in an adjustment being booked in the second quarter to true-up past results.

As a reminder, we purchased our non-operated interest in the Barnett Shale in May of 2021. The acquisition materially increased our exposure to natural gas through the addition of another long life low-decline asset to our portfolio. In addition, the transaction was particularly well timed considering the sharp increase that we have seen in natural prices over the past few months.

Diversified began operating the Barnett Shale assets as of July of 2021 after purchasing their interest from Blackbeard operating. Based on our discussions, Diversified is planning to run 1 workover rig continuously throughout the calendar of 2022. We look forward to participating with them in a number of high rate return projects in the coming months and years.

During the second quarter, we once again generated operating cash flow in excess of capital expenditures, which supported payment of our 33rd consecutive quarterly cash dividend. Given the continued improvement in our business and economic environment, we are pleased to declare a third quarter dividend of $0.10 per common share that will be paid on March 31 to shareholders of record of March 15. Our third quarter dividend represents a 33% increase from our second quarter dividend of $0.075 per share. This was an important milestone returning our dividend to pre-pandemic levels. With the third quarter dividend evolution, will have paid out approximately $80 million or $2.50 -- or $2.50 per share back to the shareholders as cash dividend since the program began in December of 2013.

With that, I'll now turn the call back over to Ryan to discuss some of our financial highlights.

I'll now share some additional details regarding our financial results for the second quarter of fiscal '20. Please refer to our press release from yesterday afternoon for additional information and details with some of the key highlights include: adjusted EBITDA increased 20% to $10.2 million from $8.5 million in the first quarter of fiscal '22. Second quarter adjusted EBITDA was $22.32 on a per BOE basis, which is 41% higher than the first quarter. Now excluding the impact of the adjustment related to the operator production mix changes in the Barnett Shale that Jason discussed, the second quarter adjusted EBITDA would have been $28.88 per BOE.

We once again funded all operations, development CapEx and dividends out of operating cash flow, and we maintained our strong balance sheet with $13.6 million of cash on hand, less $4 million of debt resulting in net cash of $9.6 million as of December 31. As Jason mentioned, we paid a dividend of $0.075 per share for the second quarter, marking the payment of our 33rd consecutive quarterly dividend. Also, as he mentioned, supported by our solid operational and cash flow, we increased -- we declared an increased distribution to $0.10 per share for shareholders of record on March 15, 2022, to be paid on March 31, 2022.

Working capital was $22 million at the end of our second quarter of fiscal '22. This was $6.4 million higher than our working capital at September 30, 2021 with $5.6 million of the increase due to our improved cash position. Our liquidity at December 31 was $49.6 million, which included $13.6 million of cash and $36 million of availability in our credit facility.

As a reminder, on November 9, we amended our credit facility to reflect last year's acquisition of our Barnett Shale assets. The result was the redetermination of our borrowing base to $50 million, which was a $20 million increase from our previous borrowing base of $30 million. And we elected a $40 million commitment amount resulting in the availability I disclosed of $36 million.

As Jason will discuss in more detail in his closing comments, on January 14, we closed on a transaction to acquire non-operated assets in the Williston Basin in North Dakota for a total purchase price of $25.9 million net of preliminary purchase price adjustments. Funding for this acquisition was provided by cash on hand and a $16 million draw on our credit facility. As a result, we currently have $20 million drawn on the credit facility, which includes a previously mentioned $4 million balance as we ended on December 31.

Yesterday, we announced that we entered in a definitive agreement to acquire non-operated natural gas assets in the Jonah Field in Wyoming. The purchase price of this acquisition was $29.4 million, subject to customary purchase price adjustments and closing conditions. We expect to fund this transaction with cash on hand and borrowings from our credit facility.

Pro forma for the closing of these 2 acquisitions, we expect that our net debt will be below our stated maximum leverage target of 1x pro forma and -- 1x pro forma adjusted annual EBITDA.

Now as I discussed on our last earnings call in November, the amended credit facility added a covenant where we must hedge certain percentage of future production based on the utilization percentages outlined in the credit facility agreement. On February 7, we entered into the ninth amendment to our credit agreement that modified the definition of utilization percentage related to this required hedging covenant, such that for the purposes of determining the amount of production to hedge, utilization of our credit facility will be based on a calculated collateral value to the extent it exceeds the borrowing base than in effect.

Now we currently estimate that this collateral value is approximately $125 million, which will result in a current utilization of 16%. However, as we have stated in the past, we would look to enter into hedges to protect the balance sheet if we took on debt for an acquisition. As a result of the debt related to the Williston acquisition, as part of the ninth amendment to the credit facility, we have agreed to enter into hedges covering 25% of our expected oil and gas production for a period of 12 months.

We still anticipate using primarily costless collars in order to retain upside to commodity prices and we do continue to maintain our strategy of retaining exposure to commodity prices, which has benefited us recently. However, as we utilize debt for potential acquisitions, we may look to hedge a portion of our incremental production to lock in cash flows, maintain compliance with our credit facility, ensure a quick paydown of any debt we may incur and protect our dividend.

Looking at our second quarter fiscal 2022 financials in more detail. We grew total revenue to $22.3 million, which was an 18% increase from the prior quarter. Oil revenue increased to $10.6 million due to 12% higher sales volumes, primarily as a result of the additional royalty income and production received from our Giddings Field interest and also a 6% increase in realized pricing. NGL revenue decreased to $2.6 million, primarily due to the production mix adjustments made by the operator in the Barnett Shale that Jason previously discussed.

These were designed to capitalize on the most favorable commodity prices and maximize overall cash flow. This helped drive natural gas revenue to $9.2 million for the second quarter. LOE increased to $10.7 million in the second quarter. Contributing to the increase was $1 million in higher CO2 costs at Delhi compared to the prior quarter, primarily due to the suspension of CO2 purchases from July 15, '21 to August 20, '21 and in order to perform preventative maintenance on the CO2 purchase pipeline. In addition, oil prices increased from the prior quarter, leading to an increase in CO2 cost per Mcf as the CO2 purchase price is based on and tied to the price of oil.

The $1.1 million increase in other LOE was primarily a result of increased production and ad val taxes -- ad valorem taxes due to higher commodity prices. Changes to estimates in the Barnett Shale, electrical costs at Hamilton Dome following injection well activation and costs associated with repairs at the Enzo plant in Delhi. Total LOE for the second quarter was $23.40 per BOE compared with $16.05 per BOE in the prior quarter. However, excluding the impacts of the Barnett Shale adjustments, LOE would have been $21.22 per BOE.

General and administrative expenses were $1.8 million for the second quarter compared to $1.9 million for the prior quarter. This decrease was primarily due to lower salaries and benefits costs, which were partially offset by an approximate $100,000 increase in noncash stock-based compensation.

Net income for the second quarter grew to $6.8 million or $0.20 per share from $5.2 million or $0.16 per share in the previous quarter. However, when adjusting for the previously mentioned Barnett Shale changes in estimates, net income would have been $7.3 million or $0.22 per share.

For the 3 months ended December 31, 2021, we invested $300,000 in CapEx, which were primarily associated with Delhi Field capital maintenance activities. And we currently expect that operators at Delhi and Hamilton Dome will continue conformance workover projects, and likely incur additional maintenance capital expenditures as oil prices remain strong.

As Jason discussed, at the Barnett Shale, we expect to see diversify, continue to do workover rig work during calendar year 2022. Now based on discussions with the operators at Delhi, Hamilton Dome and Barnett, we currently expect total CapEx for the remainder of fiscal year '22 of $500,000 to $1.5 million. Additionally, for discussions with the operator of our recently acquired Williston Basin assets, we expect additional capital expenditures of $500,000 to $1 million during the remainder of our fiscal 2022.

So with that, I will now turn the call back over to Jason for his closing remarks and a discussion of our recent acquisitions.

Thanks, Ryan. As we've discussed consistently in the past, maintaining and ultimately growing our common stock dividend remains our top priority. And as such, we continue to look for accretive acquisition opportunities that meet our requirements of long life established production with disciplined growth opportunities, both of which support the value creation for our shareholders.

Over the last 3 weeks, we've announced 2 significant transactions to acquire additional non-operated oil and gas assets located in 2 prolific producing basins in the United States. This includes last month's announcement, an announcement that we closed on the acquisition of oil-weighted assets in the Williston Basin of North Dakota. In this week's announcement that we've entered into a definitive agreement to acquire natural gas assets in the Jonah Field located in Sublet County of Wyoming.

If you are able to view the presentation on our website, we encourage you to reference it while I make some remarks. If you're unable to review the presentation at this time, we invite you to review it later and reach out with any questions that you might have.

In short, since late calendar of 2019, we've seen great success in our efforts to increase immediate and long-term cash generation for the benefit of our shareholders through strategic expansion of our geographic footprint of assets and production mix directly as a result of the hard work of our dedicated employee team. I'm happy to report that over the last 2 years, we've increased both net daily production and PDP reserve by approximately 400%. Equally important, we've accomplished this without the growth -- this growth in value creation without materially diluting shareholders or any onerous debt or a material increase to G&A.

So let's look at the slide deck now going through a few slides of the acquisition. Slide 2 shows some disclaimers there that these are forward-looking statements. It's important to note that.

On Slide 3, this will look pretty familiar to you because it's part of our IR deck. It's important to us that we do what we say we're going to do, what we've been communicating that we're going to do and be consistent. We look at these assets, and they're both long life, long-lived and dominated by PDP value. That's what we feel like we bought them on. Williston has upside, but -- and so does Jonah, but the main point of what we focused on was the PDP-heavy. They're accretive immediately to cash flow. They support the dividend and kick off cash flow immediately. There's low ongoing capital requirements or investments. They're located in well-established basins with stable regulatory environments and takeaway capacity and they're high margin.

Now one thing that does look different, I will say this, I've said many times that we probably wouldn't be pursuing gas that wasn't pretty close to the coast down here in Texas, either on the Katy pipeline coming down the Houston Ship Channel or in the Carthage pipeline on East Texas coming down to Sabine Pass thinking that, that's where the prime markets are.

But this is a really good lesson. It was a good lesson for our team that our opinions aren't good enough, including mine, and we've got to be driven by the data. And I was happy to tell my team that I was wrong here. We found a portion of coming out of Opal going west where they're getting pretty good prices. And we like that. We think there's premium access to markets up there.

And so we're happy to be willing to change if the data suggests that, so I think that's an important culture that we're building.

Slide 4, I think this kind of shows what we've been working on. It shows that we're starting to see results of our efforts moving -- diversifying a little bit away from Delhi. It's going to be a great asset that contributes to our dividends for multiple decades, and we all love Delhi. But we've also added on and added some diversity. And I think that's going to be important for the health and the strength and the security of our business and our dividend.

So it's important to note on this that this is a 6:1 ratio in terms of BOE. So the oil -- the gas assets show a little better on production and BOE-wise. The oil assets that we purchased are still very valuable. It's important to note on the foundation that the 5 96 in production, we like that, and we feel like we get a good buy on that, but we also have a tremendous amount of upside that really has us excited about that.

Slide 5, I think, shows what we're trying to do here. If we kind of start at the upper left, production, it shows us to be fairly gassy right now, but we've got a nice commodity mix. We'll get exposure to all 3 commodities. But if you move from production to reserves, because we've got now some upside locations that are more oily, we start to look really balanced in the 40% oil, 38% gas, 21% in shale. That's the kind of company that we want to put together. We feel like there's resilience there in commodity mix diversity.

In (inaudible), continuing over to the upper right, looking at (inaudible) previously, we've been kind of high 90% of PDP. We're now starting to get into some PUD, which is some opportunity in (inaudible) differentiation. And that leads to the lower right where you've got showing some geographic diversity, which gives us some strength, different parts of the country experiencing freezes or hurricanes or different things, we're not all tied to one place or our concentration or our cash flows aren't in one place.

So with that, you get a little bit of operator diversity. We learned within Barry, who's doing very well right now. But a couple of years ago, they went through some financial situations where they couldn't spins the amount of money that we would have liked them to on our assets. And this gives us a little bit of diversity and security away from a concentration on a single operator.

So let's take just a little bit deeper dive on Slide 6 into what we feel like is a tremendous amount of value kind of nestled in this Williston Basin acquisition. Now we're not interested in becoming a big driller. We're not going to run up a bunch of CapEx spending. This for us was about optionality. And again, we feel like we bought it on a PDP-type valuation and got a good purchase, but we really like having these options.

And the options are these wells that are held by production that are out there. Now I think there's 400 locations. We will dovetail this into our reserves at the end of the year -- our fiscal year in the summer in our reserves process. But so our company engineered reserves right now. We think probably there's about 150 of these locations that would pass the qualifications of being an SEC PUD proved reserves. That means they're kind of one space off of a drill producing well.

But we don't really need that. I think there's 40-something locations built. And so we kind of -- the ones that we're calling PUD right now that we're thinking about internally are 50 locations because to be a PUD, you've got to be able to drill it. They've got a 5-year rule by the SEC. So putting out a small program like there of a couple 5-well PUDs a year, 10 wells a year over a 5-year period, that's 50 wells. So anything above that, we kind of call probable or possible.

So even though if you look at the reservoir calculation on -- or the reserve calculation in the upper left-hand side, that (inaudible) 4% is PDP, 15% represents at 50%, and there's quite a bit more there. So that collectively is about 9 million barrels. We think the potential out here is around 50 million barrels. So there's a lot of upside here, and we we're not doing that to go and try to become a drilling company.

Like I said, we're doing this as the types of assets that we buy are PDP heavy, long life, flat. Sometimes those are fairly expensive in the acquisition process. You'd like to have an alternative when the bid ask gets a little too far apart to be able to put some capital to work or in a situation where operators might be underperforming. So we just feel like this provides some strength and security for our shareholders. In 2027, 2030, these wells out there are going to go away. This is optionality and inventory for us many years down the road.

Slide 7 shows the footprint. I think there's a couple of key takeaways here. One is the relationship with Foundation. We're non-op and we like being non-op, but we like this relationship with them. They're good operators. They've been operating up there in North Dakota. And so it's a chance for us to be a little bit closer, have more influence, have more collaboration working with them on developing this.

Now we do have the ability, if they're focused on other areas, and we want to drill a well, we do have the ability to go out there and drill in. They'll drill it for us or we can contract people to drill it, but we can propose wells and that gives us a decent optionality like I said.

Another thing to note over on the map, most of the acreage has been delineated. So we're looking at more infill wells rather than step-out wells, which is the nature of Evolution. That feels like our company. This is an 84% lease net revenue interest. So that's a pretty high net. And again, the PDP was pretty attractive with an RFP of over 10 years.

I think I'll skip Slide 8, it's just a few more expansive comments of what I just made. A couple of comments about the Jonah Field on Slide 9. One, you can see in the upper right-hand corner, it's about 100 miles from our Hamilton Dome. We know this area, and we're happy with Wyoming in the environment up there to operate in. But this deal is just classic evolution. This is right in the middle of our fairway. It's PDP, long life, stable regulatory, good markets and a good operator in Jonah operating. So we expect to close this on April -- and this is all 100% held by production. We don't anticipate any drilling here, might be some minor workovers and stuff. But again, a decent RFP of 8.1.

The thing we really like about this was on Slide 10, and this is where I kind of admitted that my opinion was wrong, although it was rooted in some logic because on gas, you've really got to watch midstream and marketing. It can be killer in terms of cost.

But if you look at this map on Slide 10, you'll see that Opal here has some ability to go west and they've been receiving north of Henry Hub, a premium to Henry Hub. So just as a point of reference, our Barnett is about $0.35, $0.36 under Henry Hub, and they've been getting over Henry Hub up there. So we're really excited about that going in the future.

So I really think that the Jonah Field is going to be a great -- it feels like Evolution is going to be a great field for us.

So finally, on Slide 11, I'd just like to point out a couple of things. One, we had a 5% yield at $0.30. We released this before we had raised the dividend. So right now, I think the stock is trading a little over $6. So it's kind of moving up to $0.40 a year, $0.10 a quarter, somewhere around 6%. And I think if you look at the bottom there, you've seen quite a bit of activity. We've moved into our revolver a little bit, as Ryan said. I don't think you'll see us continue that. I think you're going to see us digest a little bit, integrate these assets and start paying down the debt.

We feel like these 2 assets were strategic, we feel like they've built a lot of security for our dividend. And it was a big milestone. We feel like we turned a corner on a couple of hard years for the industry. And now we're looking forward back to $0.10 a quarter and we're excited about the future.

So a couple of final comments before we turn it over to question. So I want to thank all of our employees for their hard work for the past 2 years as we transformed Evolution in a much stronger company, with a significant footprint in diversified assets, multiple prolific producing key basins. As important, I, along with the full support of the Board on support -- or I want to thank our shareholders for their continued support our strategic long-term efforts.

And with that, I think we're ready to take some questions. So operator, if you'll open up the line, please.

(Operator Instructions) Your first question is coming from John Bair from Ascend Wealth Advisors.

Thanks again on behalf of myself and clients for raising that dividend. You bid off quite a bit here. So I got a few questions. What is the current rate on the credit facility, the interest rate?

Yes. So we're at 3%. So it's LIBOR plus 2.75% with the 25 basis point floor. So 3% even for the interest rate which is pretty good this market.

Yes. Yes. Okay. And looking at the math on this. I mean, are you looking to expand that credit facility now with the most recent acquisition announcement because doing the back of the envelope, it looks like with large acquisition that you've got, adding that on would take up that additional $20 million. Am I missing something here?

Well, so yes, a couple of points. One is we actually had approval from first for up to $50 million. That's kind of their max hold level, and so that's likely what we'll go back to, quite frankly. Beyond $50 million, it's an active debate kind of talking about the Board level. We don't really feel like we need a lot of additional liquidity, and we think as much cash flow as these assets are going to be generating, we're going to be able to pay it down very quickly. So we're certainly thinking about it. But I think going up to $50 million, which is comfortable from them first and clearly comfortable for what our assets can support, we feel like it would give us plenty of liquidity given how much cash -- free cash flow we expect to have.

Okay. And then looking at the 2, the Jonah and the Williston acquisitions, it appears -- and Jason, you, I think, kind of underscored this. But it appears that there's probably going to be more activity going forward, the Williston asset as opposed to Jonah at this point. Is that a fair statement?

Yes. No, I definitely think that's fair. And Jonah is going to be limited to some workovers and things like that, more operational optimization, but I don't anticipate any drilling up there. It's fairly developed. They are different assets that way. That's what we like other.

And also, I just wanted, I was looking at the slide deck on your Slide 6, under the probable possible, the third bullet point says as proved undeveloped wells are drilled and put on production, these locations would be reclassified to proved undeveloped. Is that a typo? Am I missing something on that?

No. It's just the nature of what classified as PUDs. Like I said, about 150...

I mean if you bring them online, wouldn't they be producing wells? It be proved development.

No. No, well. Okay. So let's say that there's a PDP well currently producing well and then offset to that currently producing well, a location or 2 away, they will classify as PUD currently. But the locations there are 3 or 4 locations away that are not classified as proved, they're classified as probable. But as you drill a couple of these wells, then those other ones that are probable right now will become proved because they're closer to producing wells, if that makes sense.

So right now, 150 of the 400 are within 1 or 2 locations of producing wells, which means they would be classified as a PUD right now. But as you continue to drill more of those other remaining 250 wells or whatever will become proved as you -- does that make sense, John?

I think so. I guess, if you're -- if there are wells that are online and producing, then I guess...

No, those would definitely be PDPs.

Okay. So

I'm saying like a lot of these probable's or possible as things get drilled closer to them, they'll go from probable to PUDs. .

I think you read the bullet, John. It's just. Instead of the word these, just think about that, that should be probable and impossible is what I was referring to, right? So probably impossible locations would be mixed pad.

So is there a typo there? Am I...

No.

Well, it's referring to the whole category of probable and possible.

Okay. I mean we can talk about that offline. Last quick question and that is CO2, are you -- are they -- is the operator, Denbury, are they continuing to ramp up CO2 injection and so forth? Or is that kind of stabilized at this point? And kind of how long do you think it might be? Or is there any guidance or thoughts on how long it might take to get that production back up to the levels it was at before the CO2 stopped injecting CO2? No, to capture back that extra 10,000.

I think that in December, they were able to ramp up to 100 million. I think they're about 105 million right now. I think they want to hold it there for quite a while. Denbury, in our discussions with Denbury and then also D&M our reserve auditors, they're kind of seeing that as sort of a 24 month, 18 to 24 months forward starting to rise up to previous projections. I don't know that we will get back to -- before it went down, it was 5,600 barrels a day. We're right around 4,000 right now.

So I'm not sure -- we don't expect it to get back to 5,600 in 24 months. We do expect to see the decline arrested, and we've already started seeing that and then we start -- we would hope to see kind of an increase. You got to realize we're also pulling out oil every day. So we're fighting the natural decline on top of that. So even arresting the current decline is making progress towards where it would have been.

But John, I think the best way for me to answer that is probably not going to get back 5,600 barrels a day. That's 88 for just the oil, by the way, I'm referencing. And we would expect it to take at least 18 to 24 months before it gets back to where we thought it would have been at that point.

Your next question is coming from Lee Curry from Curry Partners.

Enjoyed the results. Tell me a little bit about -- explain a little bit more on the optionality in the Williston, which is an attractive aspect of it to me. What has been the operator -- what has been foundations? Level of exploration derisking here? What do you expect with them in the future? How -- do you have complete choice on going along or not going along with every well they drill? Tell a little bit more about what's going on there?

Very good questions. Lee, we -- I appreciate that because we're excited about what the inventory and the reserves does in terms of just the security for the company, but didn't want to imply like I said earlier, that we're going to become some big driller and outrunning CapEx. This is more about security. In terms of optionality, we have -- either one of us can propose wells foundation or us.

If we're in a position where we don't want to drill it, then they can take over our interest and drill our capacity. If they're in a position where they don't want to drill it, we can take up to 100% of a well. If we do that, then the interest owners that don't participate in any particular well don't lose out on any other wells, and they will be out of that particular wellbore for a 300% penalty. And right now, on the type curve, that comes in about 19 to 20 years. So effectively, it means they're out of that well.

So we feel like we've got a bunch of wells out there that we can go drill if we want to, regardless of their desire of 100% if we'd like to. But at the same time, we can't get drilled into the ground. We can just say no, and we don't lose any other opportunities other than that wellbore. So it's really a wonderful situation. And most of them, 85% of it being held by production. Again, I'm thinking in 2028 or 2030, I'm going to have things to do regardless.

But the optionality for us really is, like I said, twofold. I study negotiated the (inaudible) when the first role was about your best alternative to the negotiated agreement. A lot of these PDP packages, the bid ask us to so rough sometimes that we don't want to overpay for things, you can really do some damage to your balance sheet and a lot of companies have done that. And Evolution's had a great reputation for being fiscally disciplined. This allows us an alternative to that negotiation to go out and put some money to work if we need to, which is great.

I love that element of offset as you described it there. It sort of allows you -- if I'm understanding this correctly, it allows you to utilize the optionality and do some drilling on what could be a fabulous bunch of probable and possible's there only if and when you want to and without pi(expletive) off Foundation because you're not going along to every well they produce. Is that a correct analysis?

No, that's right. That's right. I mean -- but they are the right kind of partner for us. They have LPs and they do their operations out of cash flow and they give distributions. Very much like us, we do things out of cash flow and we give a dividend. So with the right kind of partner -- you don't want a partner that's just going to outspend cash flow around. So anyway -- but yes, I think you're seeing all that right. We're super excited about it.

How large of a market cap or revenue? How big of a company is Foundation say, compared to you all?

They're private. I think they're in Fund VII. It's about $100 million. They've been around for 15, 20 years. So they're working on Fund VIII. So they've got assets in a number of different places, and they've consistently bought and sold and -- yes.

Okay. On Jonah, did you buy out a partner? Is that what XRO is? Did you buy out an existing partner?

That's right. That's right. Jonah Energy operates and they own the majority of it. Exxaro was a private equity-backed company. They've been successful in South Texas in a number of ways. I think that they wanted to get into that field and maybe buy a bigger piece and become an operator, and Jonah was pretty dominating up there.

They wanted to sell out, I think that they're unwinding the company completely. It's a really good position for them, but we feel like we kind of burned on the ground there. And that were just not part...

This is even better because it was them selling and not Jonah selling.

Yes, that's right. That's right. Well, Jonah is a pretty good operator. We've been impressed with all that we've seen from them.

I'm surprise -- I just was ignorant of. I didn't realize that there were places in the middle of the United States that you were getting premium prices for gas versus the Gulf Coast. What's been the history of those price premiums? I mean, did it just develop lately? Or what? What give me a little history on that?

Well, I think there's a little bit of a crunch of a lack of infrastructure development headed towards California in the west. There's not a lot of new -- there's no new pipelines going out there. And it's the same thing that's happening up in Appalachia in Pennsylvania. So there's a big pipeline going down out of the Permian going west, but it's completely full, and you can't really get into capacity. Coming down from the north through Washington from Canada, that's pretty much bottlenecked in full as well. .

So you've got Opal here that's just sitting there with some capacity. And Exxaro actually, and we will as well take our gas in kind and they've got 5 or 6 buyers that are sort of bidding on it. So they've -- we put in there that they've been averaging around $0.04 above Henry Hub, but it's average is quite a bit higher than that. So we anticipate that's going to be strong for a little while. We're pretty excited about that.

All right. Well, I just want to say I want to congratulate you on being patient and it looks like it's finally paid off for you. And I would say a job well done, Jason, and keep up the good work.

Thank you, Lee. I sure appreciate that. Thanks for your interest. .

(Operator Instructions) Your next question is coming from John Bair from Ascend Wealth Advisors.

Like the movie, I'm back anyway. Kind of curious on a question on the Giddings royalties. What was the lag, the 3-year lag on that as that? Was those properties tied up in something that -- in the royalties escrowed? Or just kind of curious on that.

No, I mean, it's a great question. It was -- so these are assets that I believe were, I think, originally owned prior to Chesapeake -- Chesapeake was the operator. And they're notoriously slow sometimes on these types of royalty payments. And I think they took the offer from Wildhorse, I think it's where they originated from. And there are 2 wells that were drilled back in 2018 that sat in their revenue suspense for a couple of years of Chesapeake finally got around to clearing our suspense. And obviously, we want to wear at the time that they're on the -- it was land that we had sold years back and kept an override on.

And so we're now receiving consistent checks for them, certainly not the amount that we got in that onetime check for the 3 years, but it was just a situation where the 2 wells drilled that they hadn't really done their land records well enough to know who all the royalty owners were.

And are those -- you say those are still -- those 2 wells are still in production then so you've got something coming in from that.

Yes. Yes, there's some cash that coming from those. It's not a huge.

10,000, 15,000 a month.

10,000 to 15,000 a month coming in from them.

Okay. All right. And then a little clarification on the Williston too. I think in the comments you were saying that estimates are CapEx of about $0.5 million to $1 million over -- through fiscal year '22. So the next basically through the end of June. Is that right?

Yes. So there was a little bit of low-hanging fruit, a few workovers they've identified and some mine pipes. There's a little bit of conventional Red River production up there and Nisku production. So these are vertical recompletes 4, 5 workovers in May, I think, that they're going to do. But any kind of real drilling in the Bakken, the Pronghorn is probably going to come in 2023.

And I would imagine that, that's something that you're in kind of having evaluated all this and closed on it -- soon to close that kind of -- could we expect that CapEx might expand from what you are anticipating what you've put out in the press release and so forth? I guess some of that would probably depend upon prices staying up at kind of these levels, but is am I thinking in the right direction here that maybe you might be a little more active in getting some wells down? .

Well, we're going to put a lot of work in high-grading locations and doing a lot of rock mechanic and geo work over the next 6 months. But I would say this, right now, it's an interesting situation with such a backward-dated curve. I think at some point, the back end of the curve as, I guess, the general markets feel a little more comfortable being on solid footing that things aren't going to go back down into a pandemic or generally demand is going to be fairly consistent or growing. The back end of that curve, I think we're anticipating is going to come up, making everything a lot more expensive.

So it really comes down to when we get the high-graded locations of things that we would want to go do, like Ryan said, we're making a lot of cash flow. We got to then decide what to do it. Ryan, a nice job is to reinvest the capital and not just have a bunch of savings in the bank earning 0.5% interest, but reinvest in activities. Now is that an additional acquisition?

Well, if we find one that fits our profile, that's properly priced, we'll put the money there instead of going drilling. If the back end of the curve comes up and things become too expensive to buy, then we'll drill because if they're too expensive to buy, that means prices are high anyway. So it really is that optionality. I think that it wouldn't be necessarily a function of just CapEx going up but more of a choice of the reinvestment, do we make more acquisitions that we put money into some wells. So -- but yes, I think we would anticipate -- we'd like the locations, and we think we would anticipate or...

A lot of variability in the previous caller and you said a lot of optionality, look pretty exciting.

(Operator Instructions) Thank you. There are no further questions in the queue. I will now hand the conference back to our host for closing remarks. Please go ahead.

Well, we appreciate your time today and look forward to providing further updates on our business. During our third quarter fiscal 2022 earnings call that's going to be in early May. Bill, please feel free to contact us with any other questions or comments. Thank you.

Thank you, ladies and gentlemen. This concludes today's event. You may disconnect at this time and have a wonderful day. Thank you for your participation.