Good afternoon, ladies and gentlemen, and welcome to the Evolution Petroleum second quarter fiscal year 2022 earnings release conference call. At this time, all participants have been placed on a listen-only mode, and we will open the floor for your questions and comments after the presentation. It is now my pleasure to turn the floor over to your host, Ryan Stash. Sir, the floor is yours. Thank you. 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. Finally, Jason will provide some closing comments and details about our two 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 2022 earnings call. As Ryan mentioned, we will discuss our two 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 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 three weeks, we have announced two 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 more 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 adjusted EBITDA of $10.2 million, which was 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 4,957 net BOE per day, which is down from 5,843 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 three years associated with an overriding 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 nine-month suspension of CO2 purchases during the calendar year 2020 due to repairs of 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 that temporarily reduced daily production. At Hamilton Dome, we saw a sequential quarter increase in net production of 2% to 38,021 barrels or 413 barrels of oil per day. It's primarily due to continued restoration of previously shut-in wells and strategic adjustments to water injection locations and volumes. Our operating partner, Merit, remains focused on maintenance projects in Hamilton Dome. Net production from the Barnett assets for the second quarter of fiscal 2022 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 Barnett 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 Btu mix in both the second and the first quarters of 2022, 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 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 gas prices over the past few months. Diversified began operating the Barnett Shale assets as of July 2021 after purchasing their interests from Blackbeard Operating. Based on our discussions, Diversified is planning to run one 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 CapEx, 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 on 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, we'll have paid out approximately $80 million or $2.50 per share back to the shareholders as cash dividends since the program began in December 2013. With that, I'll now turn the call back over to Ryan to discuss some of our financial highlights. Thanks, Jason. I'll now share some additional details regarding our financial results for the second quarter of fiscal 2022. Please refer to our press release from yesterday afternoon for additional information and details, but some of the key highlights include, adjusted EBITDA increased 20% to $10.2 million from $8.5 million in the first quarter of fiscal 2022. Second quarter adjusted EBITDA was $22.32 on a per BOE basis, which is 41% higher than the first quarter. 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, plus $4 million of debt, resulting in net cash of $9.6 million as of December 31. As Jason mentioned, we paid a dividend of seven and a half cents 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 output, we declared an increased distribution to ten cents 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 2022. 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. 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 $60 million draw on our credit facility. As a result, we currently have $20 million drawn on the credit facility, which includes the previously mentioned $4 million balance as we ended on December 31. Yesterday, we announced that we entered into a definitive agreement to acquire non-operated natural gas assets from 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 two acquisitions, we expect that our net debt will be below our stated maximum leverage target of 1x pro forma adjusted annual EBITDA. Now, as we 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 then in effect. 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% over 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 pay-down 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 a result of the additional royalty income that 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, 2021 to August 20, 2021 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 costs 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 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 NGL 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 non-cash 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 estimate, net income would have been $7.3 million or $0.22 per share. For the three months ending December 31, 2021, we invested $300,000 in CapEx, which were primarily associated with Delhi Field capital maintenance activities. 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 Diversified 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 2022 of $500,000-$1.5 million. Additionally, per discussions with the operator of our recently acquired Williston Basin assets, we expect additional capital expenditures of $500,000-$1 million during the remainder of our fiscal 2022. 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. 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 three weeks, we've announced two significant transactions to acquire additional non-operated oil and gas assets located in two 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, and this week's announcement that we've entered into a definitive agreement to acquire natural gas assets in the Jonah Field, located in Sublette 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 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 two years, we've increased both net daily production and PDP reserves by approximately 400%. Equally important, we've accomplished this without this growth in the value creation without materially diluting shareholders or any onerous debt or a material increase to G&A. Let's look at the slide deck now, going through a few slides of the acquisition. Slide two shows some disclaimers there that these are forward-looking statements. It's important to note that. On slide three, 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 gonna do, what we've been communicating that we're gonna do and be consistent. We look at these assets and they're both long lived and dominated by PDP value. That's what we feel like we bought them on. The Williston has upside, and so does Jonah. 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 investment. 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 on the Carthage pipeline on East Texas coming down to Sabine Pass, thinking that that's where the prime markets are. This is a really good lesson. It was a good lesson for our team that, you know, our opinions aren't good enough, including mine, and we've got to be driven by the data. 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. We're happy to be willing to change if the data suggests that. I think that's an important culture that we're building. Slide four, 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 gonna be a great asset that contributes to our dividends for multiple decades. We all love Delhi. We've also added on and added some diversity. I think that's gonna be important for the health and the strength and the security of our business and our dividend. It's important to note on this that this is a 6-to-1 ratio on, in terms of BOE. 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 596 in production, we like that, and we feel like we got a good buy on that, but we also have a tremendous amount of upside that really has us excited about that. Slide five, 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've got exposure to all three commodities. 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% NGL. That's the kind of company that we wanna put together. We feel like there's resilience there in commodity mix, diversity. In ResCat, continuing over to the upper right, looking at ResCat, you know, previously we've been kind of high 90% of PDP. We're now starting to get into some PUD, which is some opportunity in ResCat, differentiation. 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 for our cash flows aren't in one place. With that, you get a little bit of operator diversity. We learned with Denbury, who's doing very well right now, but a couple years ago, they went through some financial situations where they couldn't spend the amount of money that we would've liked them to on our asset. This gives us a little bit of diversity and security away from a concentration on a single operator. 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 gonna run up a bunch of CapEx spending. This, for us, was about optionality. Again, we feel like we bought this on a PDP-type valuation and got a good purchase, but we really like having these options. 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. 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 drilled, a producing well. We don't really need that. I think there's 40-something locations built. 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 five-year rule by the SEC. You know, putting out a small program like there of a couple five-well pads a year, 10 wells a year over a five-year period, that's 50 wells. Anything above that, we kind of call probable or possible. Even though if you look at the reservoir calculation on, or the reserves calculation on the upper left-hand side, that donut, 4% is PDP, 15% represents that 50, and there's quite a bit more there. That collectively is about 9 million barrels. We think the potential out here is around 50 million barrels. There's a lot of upside here, and we're not doing that to go and try to become a drilling company. Like I said, we're doing this. 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. We just feel like this provides some strength and security for our shareholders, you know, in 2027, 2030. These wells out there aren't gonna 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 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. 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 wanna drill a well, we do have the ability to go out there and drill one. They'll drill it for us, or we can contract people to drill it. We can propose wells, and that gives us a decent optionality, like I said. Another thing to note over on the map, that 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. Again, the PDP was pretty attractive with an R/P of over 10 years. I think I'll skip slide eight, as it's just a few more expansive comments of what I just made. A couple comments about the Jonah Field on slide nine. 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 and the environment up there to operate in. 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 Energy. We expect to close this on April. 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 R/P of 8.1. The thing we really like about this was on slide 10, and this is where I kind of admitted to. that my opinion was wrong, although it was rooted in some logic, because on gas, you've really gotta watch midstream and marketing. It can be a killer in terms of cost. 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. Just as a point of reference, our Barnett is about $0.35, $0.36 cents under Henry Hub, and they've been getting over Henry Hub up there. We're really excited about that, going in the future. I really think that the Jonah Field is gonna be a great. It feels like Evolution is gonna be a great field for us. Finally, on slide 11, I'd just like to point out a couple things. We had a 5% yield at $0.30. We released this before we had raised the dividend. Right now I think the stock's trading a little over $6, so it's kind of moving up to $0.40 a year, $0.10 a quarter, somewhere around 6%. 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 gonna see us digest a little bit, integrate these assets and start paying down the debt. We feel like these two assets were strategic. We feel like they built a lot of security for our dividend. It was a big milestone. We feel like we've 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. A couple final comments before we turn it over to questions. I wanna thank all of our employees for their hard work over the past two years as we transformed Evolution into a much stronger company with a significant footprint and diversified assets, multiple prolific producing key basins. As important, I, along with the full support of the board, want to thank our shareholders for their continued support of our strategic long-term efforts. With that, I think we're ready to take some questions. Operator, if you'll open up the line, please. Certainly. Ladies and gentlemen, the floor is now open for questions. If you have any questions or comments, please press star one on your phone at this time. We do ask that while posing your question, please pick up your handset if you're listening on speakerphone to provide optimum sound quality. Once again, if you have any questions or comments, please press star one on your phone. Please hold while we poll for questions. Your first question is coming from John Bair from Ascend Wealth Advisors. Your line is live. Good afternoon, Jason and Ryan. Good job. Good job. Thanks again on behalf of myself and clients for raising that dividend. You bit off quite a bit here, so I got a few questions. What is the current rate on the credit facility, the interest rate? Yeah. We're at 3%, it's LIBOR plus 275 with the 25 basis point floor, 3% even for the interest rate, which is pretty good in this market. Yeah. Yep. Yep. Okay. 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, you know, with the large acquisition that you've got, adding that on would take up that additional $20 million. Am I missing something here? Well, a couple points. One is we actually had approval from MidFirst for up to $50 million. You know, that's kinda their max hold level, and that's likely what we'll go back to, quite frankly. Beyond $50 million, you know, it's an active debate kind of talking about the board level. You know, we don't really feel like we need a lot of additional liquidity, and we think as much cash flow as these assets are gonna be generating, we're gonna be able to pay it down very quickly. We're certainly thinking about it, but I think going up to $50 million, which is comfortable for MidFirst and clearly comfortable for what our assets can support, we feel like it would give us plenty of liquidity given how much free cash flow we expect to have. Okay. Then looking at the two, the Jonah and the Williston acquisitions, it appears, Jason, you I think kinda underscored this, but it appears that there's probably gonna be more activity going forward, in the Williston asset as opposed to Jonah at this point. Is that a fair statement? Yeah. No, I definitely think that's fair. Jonah's gonna be limited to you know, some workovers and things like that, more operational optimization. I don't anticipate any drilling up there. It's fairly developed. Yep. They're different assets that way. That's why we like them together. I was looking at the slide deck. On your slide six, 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's classified as PUDs. Like I said, about 150- I mean, if you bring them online, wouldn't they be producing wells? They'd be proved developed. No, no. Well, okay. Let's say that there's a PDP well, currently producing well, and then offset to that currently producing well, a location or two away, they will classify as PUD currently. The locations that are three or four locations away were not classified as proved. They're classified as probable. 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. Right now, 150 of the 400 are within one or two locations of producing wells, which means they would be classified as a PUD right now. As you continue to drill, more of those other remaining 250 wells or whatever will become proved as you do. Does that make sense, John? I think so. I guess if they're wells that are online and producing, then I guess. No, those would definitely be PDPs. Okay. Am I? I'm saying that a lot of these probables or possibles if, as things get drilled closer to them, they'll go from probable to PUDs. Yeah. Okay. Yeah. I think you read the bullet, John. It's just instead of the word these, just think about that. Probable and possible is what it's referring to, right? Probable and possible locations would be reclassified. Is there a typo there? No. Okay. Well, it's referring to the whole category of probable and possible locations. Okay. Okay. We could All right. Maybe we can talk about that offline. Last quick question. That is, CO2. Is the operator, Denbury, continuing to ramp up CO2 injection and so forth, or is that kinda stabilized at this point? Kinda 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 they stopped injecting CO2? Well- In other words, 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 right now. I think they wanna 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-month forward starting to rise up to previous projections. I don't know that we'll get back to. See, before it went down, it was 5,600 barrels a day. We're right around 4,000 right now. 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. 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. Even arresting the current decline is making progress towards where it would have been. John, I think the best way for me to answer that is probably not gonna get back to 5,600 barrels a day. That's 8/8ths for just the oil, by the way, that I'm referencing. We would expect it to take at least 18-24 months before it gets back to where we thought it would have been at that point. Yeah. Okay. Good. I'll get off now and let somebody else on. Thanks. Thanks, sir. Thanks for the question. I'll follow up with you. Yep. Thanks. Yep, sure. Thank you. Your next question is coming from Lee Curry from Curry Partners. Your line is live. Good morning, Jason and the guys there. Enjoyed Morning, Lee Reading 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 Foundation's, you know, level of exploration de-risking here? What do you expect of them in the future? 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. Oh, very good questions. Lee, 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 wanna, like, imply, like I said earlier, that we're gonna become some big driller and outspending 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 wanna drill it, then they can take over our interest and drill our capacity. If they're in a position where they don't wanna drill it, we can take, you know, 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. Right now, on the type curve, that's that comes in about 19-20 years. Effectively, it's it means they're out of that well. We feel like we got a bunch of wells out there that we can go drill if we want to, regardless of their desire of 100% if we, if we'd like to. At the same time, we can't get drilled under the ground. We can just say no, and we don't lose any other opportunities other than that wellbore. It's really a wonderful situation. Most of them, 85% of it being held by production, again, I'm thinking in 2028 or 2030, I'm gonna have things to do, regardless, you know. The optionality for us really is, like I said, twofold. I studied negotiations at Notre Dame, and the first rule was the BATNA, your best alternative to the negotiated agreement. A lot of these PDP packages, the bid ask is just so rough sometimes that, you know, we don't wanna overpay for things. You can really do some damage to your balance sheet, and a lot of companies have done that. 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 this. I love that element of optionality as you described it there. Yeah. 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, you know, probable and possibles there, if only if and when you want to and without pissing off Foundation because you're not going along to every well they produce. Is that a correct analysis? No. That's right. I mean. Okay ... 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. Okay. We do things out of cash flow, and we give a dividend. We're the right kind of partner. You don't want a partner that's just gonna outspend cash flow. Yes be in the ground. Anyway, but yeah, I think you're seeing all that right. We're super excited about it. What, how large of a market cap or revenue? How big of a company is Foundation, say, compared to y'all? They're private. I think they're in fund seven. It's about $100 million. They've been around for 15, 20 years. All right. ... they're working on fund 8. They've got assets in a number of different places, and they- All right. ... they've consistently bought and sold and, yeah. Okay. On Jonah, did you buy out a partner? Is that what XTO is? Did you buy out an existing partner? That's right. Jonah Energy operates, and they own the majority of it. XTO was a private equity-backed company. They had been successful. Right 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. 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've kind of got a bird's nest on the ground there. Yeah, they were just a partner. This is even better 'cause it was them selling and not Jonah selling. Yeah, that's right. Okay. John is a pretty good operator. We've been impressed with all that we've seen from them. I'm surprised or I just was ignorant. 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? Give me a little history on that. Well, I think there's a little bit of a crunch or a lack of infrastructure development headed towards California in the West. Right. Right. There's not a lot of new pipelines going out there. There's no new pipelines going out there. It's the same thing that's happening up in Appalachia and Pennsylvania. There's a big pipeline coming down out of the Permian going west, but it's completely full, and you can't really get any capacity. Coming down from the north through Washington from Canada, that's pretty much bottlenecked and full as well. You've got OPAL here that's just sitting there with some capacity. XRA actually, and we will as well, take our gas in kind, and they've got five or six buyers that are sort of bidding on it. They've been averaging around four cents above Henry Hub, but it's Boy. Actually averaged quite a bit higher than that. We anticipate that's gonna be strong for a little while. We're pretty excited about that. All right. Well, I just wanna say, I wanna congratulate you on being patient, and it looks like it finally paid off for you. 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. Thank you. Once again, ladies and gentlemen, if you have any questions or comments, please press star one on your phone at this time. Please hold while we poll for questions. Your next question is coming from John Bair from Ascend Wealth Advisors. Your line is live. Like the movie, I'm back. Anyways, Yeah. I got kinda curious and a question on the Giddings royalties. What was the three-year lag on that? Was those properties tied up in something? In the royalties escrowed or just kinda 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, you know, notoriously slow sometimes on these types of royalty payments. I think they took these over from WildHorse, I think is where they originated from. There are two wells that were drilled, back in 2018 that, you know, sat in their revenue suspense for, you know, a couple years. Chesapeake finally got around to clearing out suspense. You know, obviously we weren't aware at the time that, you know, that they were on the lands that we had sold years back and kept an override on. You know, we're now receiving consistent checks for them, certainly not the amount that we got in that one-time check for the three years. It was just a situation where there were two wells drilled that, you know, they hadn't really done their land records well enough to know who all the royalty owners were. Are those two wells still in production then, so you've got- Yeah. -something coming in from that on the- Yeah. No, there's some cash still coming from those. It's not huge, but. $10,000-15,000 a month. About $10,000-15,000 a month coming in from them now. Okay. All right. A little clarification on the Williston too. I think in the comments you were saying that estimates are CapEx of about $ 500,000 to $1 million through fiscal year 2022, so the next basically through the end of June. Is that right? Yeah. Down there was a little bit of low-hanging fruit, a few workovers they identified and some behind-pipe zones. There's a little bit of conventional Red River production up there and Nisku production. These are vertical recompletes of four or five workovers in May, I think, that they're gonna do. Okay. Any kind of real drilling in the back of the Pronghorn is probably gonna come in 2023. I would imagine that that's something that you're kind of having evaluated all this and closed on it or soon to close that, you know, kind of. Could we expect that CapEx might expand from what you are anticipating or what you've, you know, 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 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 gonna put a lot of work in high-grading locations and doing a lot of rock mechanic and geo work over the next six months. I would say this. Right now it's an interesting situation where with such a backwardated 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 gonna go back down into a pandemic or generally demand's gonna 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. It really comes down to when we get the high-graded locations of things that we would wanna go do, like Ryan said, we're making a lot of cash flow. We gotta then decide what to do with it. Ryan and I's 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. It's really 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 or we put money into some wells? I think we would anticipate. We like the locations and we think we would anticipate drilling. Yeah. A lot of variability and. Yeah. Uh-huh. The previous caller, and as you said, a lot of optionality. It looks pretty exciting. Okay, thanks very much. I'll follow up. Thanks, John. Bye now. Appreciate it, John. Okay. Thank you. Thank you. Once again, ladies and gentlemen, if you have any questions or comments, please press star one on your phone at this time. Please hold while I poll for questions. 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 gonna be in early May. 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.