Good morning. I'd like to welcome shareholders and visitors to this annual general meeting of Australis Oil & Gas Limited. My name is Jonathan Stewart. I'm the chair of the board of the company and chair of this annual general meeting. Ian Lusted, Graham Dowland, Steve Scudamore, directors of Australis, Julie Foster, company secretary, are present at the meeting. Alan Watson, a director of Australis, will participate in the meeting via webcast. Mr. Philip Murdoch and Mr. Mark Joey from the company's auditors, BDO Audit (WA) Pty Ltd, are also present. Apologies, none on that basis. Before we start the formal part of the AGM, I wish to take a few minutes to say a few words. Thank you very much to those of you who are in attendance today at this AGM, and thank you to those listening and/or watching online.
The timeframe for delivery of the returns we seek for investors has been longer than we anticipated. We have discussed previously the influences in this regard. Key question today is: Can we deliver value going forward? Our response is unequivocally yes. We believe our assets of currently producing reserves and a large undeveloped onshore U.S. oil position are valuable and very much required in a market with reducing quality inventory. We currently see improving demand for our assets with strong economic fundamentals, an attractive location, and short lead time for development. What we have. Improved oil prices during the past year or so have not seen the historic response from the industry in terms of commitment to exploration and new project evaluation. Rather, investor-driven demand for returns of cash from oil companies has seen low levels of new capital committed to oil exploration.
The result has and will be a tightening of inventory available for future drilling. The invasion of the Ukraine by Russia, the prolonged war, and the consequent sanctions and dislocation have added to supply concerns and delivery complications. Oil demand has improved, and as a result, we have reasonable oil prices at present and expectation of higher oil prices for longer. We expect that higher levels of confidence in future oil pricing and reducing inventory levels will translate to increased demand for quality development opportunities and ready inventory of oil, such as that which we hold. Maintenance of our ownership and control of our key asset has remained your board's focus, with a view to securing third-party engagement. This third-party engagement is likely to take several shapes over the next period to generate additional activity within our acreage and the broader play.
We have continued to discuss cooperation scenarios with several third parties and will continue to report progress and, as and when appropriate. We are grateful for your patience in the realization of our objectives and urge you to stay the course. We will continue to work hard to deliver the value we see in our asset base. On behalf of the board and shareholders, I would also like to thank our management and employees, both here in Australia and in the U.S., who have again shown considerable commitment, professionalism and skill during the past year. The executive team and staff have continued to execute operations efficiently and safely. We remain optimistic that the coming year will be one of material progress. Thank you. I'll now return to the formal part of the meeting.
As at least two shareholders are present, I advise the meeting that a quorum is present and the annual general meeting is properly constituted. In accordance with the corporate governance principles and recommendations, and where applicable, the ASX listing rules, I declare all resolutions of this meeting will be put to a poll as follows. Resolutions 1 to 10 will be proposed, Shareholders present at the meeting will be able to ask questions on each resolution. However, voting by poll will be conducted following the tabling of all 10 resolutions. Should any shareholder physically present at the meeting wish to ask a question on a resolution, please raise your hand. We will endeavor to answer as many questions as possible during the meeting.
As advised in the notice of meeting, shareholders unable to physically attend the meeting were advised to send to the company in advance any questions they may have on any resolution. We have received general questions in advance of the meeting and will attempt to address these during the meeting. Shareholders and shareholder representatives present at the meeting have been provided with a poll form. Upon declaring the poll open, I will ask these shareholders to complete their poll forms. Upon tabling the resolutions, I will disclose the combined ballot proxies received in favor, against abstaining and undirected. As chair of the meeting, I intend to vote all available undirected proxies held in favor of resolutions 1 to 9, and against resolution 10.
The company's notice of annual general meeting has been provided online for all shareholders to download, and has been sent to all directors, the company's auditor, BDO, and those shareholders who requested a copy of the notice. If there is no objection from the meeting, I will take the notice of the annual general meeting as having been read. Thank you. For procedural efficiency, I request that any general questions be left until the formal part of this meeting has been concluded. Financial reports. I now table the financial report for the year ended 31st December 2022, together with the directors' report and the auditors' report. This is not a resolution. Does anyone have any comments or questions on these documents? No. As there are no questions in relation to the financial report, I will now ask the meeting to consider resolutions 1 to 10.
I advise that the number of proxy votes exercisable by all proxies validly appointed in respect to all resolutions are as indicated on the screen. Resolution 1 relates to the adoption of the remuneration report of the company for the year ended 31st December 2022, as set out in the company's 2022 annual report. Shareholders should note that the vote on this resolution is advisory only and does not bind the directors of the company. In addition, key management personnel and their closely related parties are not permitted to vote on this resolution unless they are voting on behalf of a proxy. The remuneration report is included in the annual report on pages 52 to 81. The Corporations Act requires companies to put to shareholders a non-binding vote to enable shareholders to voice their opinion on matters included in the report. I now invite discussion, if any.
Resolution two. I'll hand over to Ian Lusted for this resolution.
Thank you, Jon. Resolution two deals with the re-election of Mr. Jonathan Stewart as a director. I now invite discussion, if any. Thank you.
Resolution three deals with the re-election of Mr. Steve Scudamore as a director. I now invite discussion, if any. Resolution four deals with the issue of performance rights to Mr. Ian Lusted or his nominees. I now invite discussion, if any. Resolution five deals with the issue of performance rights to Mr. Graham Dowland or his nominee. I now invite discussion, if any. Resolution six, Ian Lusted, please.
Resolution six deals with the issue of fee rights A to Mr. Jonathan Stewart or his nominees in lieu of non-executive director cash fees. I now invite discussion, if any. Thank you.
Resolution seven deals with the issue of fee rights A to Mr. Steve Scudamore or his nominee in lieu of non-executive director cash fees. I now invite discussion, if any. Resolution eight deals with the issue of fee rights A to Mr. Alan Watson or his nominee in lieu of non-executive director cash fees. I now invite discussion, if any. Resolution nine deals with the issue of an equity securities under the Australis Oil & Gas Limited Employee Equity Incentive Plan. I now invite discussion, if any. Resolution 10 deals with the election of Mr. Kirk Barrell as a director. I now invite discussion, if any. Okay, calling a poll. As all resolutions have been tabled, resolutions 1 to 10 will now be put to a poll.
The persons entitled to vote on this poll are all shareholders, representatives, and attorneys of shareholders who are physically present at the meeting or have submitted a valid proxy. A poll form was provided to eligible shareholders, representatives, and attorneys of shareholders at registration. If anyone in the room is entitled to vote but has not received a poll form, please raise your hand for assistance. We're delivering it. I will now go through the procedures for completing the poll form. Shareholders should mark the box beside each resolution on the poll form to indicate how and how many votes you wish to cast for each resolution. Proxy holders have been provided with a summary of voting instructions that details the votes to be cast on the resolutions for which you have been appointed as proxy.
When proxy holders and appointed representatives of shareholders have been instructed to vote in a particular manner for a resolution, you will be deemed to have completed the poll form in accordance with that instruction. In respect of any open votes that a proxy holder and appointed representatives may be entitled to cast, you will need to mark the box beside each resolution on the poll form to indicate how you wish to vote. Please ensure you complete the registered holder name where indicated. When you have finished filling in your voting paper, please lodge it in the ballot box to ensure your votes are counted. The ballot box is at the rear of the room. If you require any assistance, please raise your hand. Are there any questions? No. Okay.
Ian will provide the meeting with his CEO address while the poll forms are being completed and returned. I will deliver the results of the poll following the presentation. Yeah.
Thank you very much, Jon. It would be easier for you to go sit down.
Yeah.
Thank you very much, Jon. Good morning to those of you in the room, certainly good morning to those of you who are joining us online. I'm gonna split the presentation up today into four parts. The first, we'll talk a little bit about the 2022 results. The second, we'll talk a little bit about the asset that we hold. Third, I'll provide a little bit of a comparison in terms of that asset to some of the other more mature and developed players in the U.S. The fourth section, we'll talk a bit about the BD activities been underway and the context in terms of the U.S. industry. It's a format that we followed last year, I think it's something that's useful and helpful.
I am obliged to point out the following disclaimers and make sure that they're all fully read. I'll please take those as having been looked through. The 2022 results, they are available to any of our shareholders or others who want to download the annual report. It's available on our website, obviously goes into more detail than I'm gonna cover up here. We'll start off on the safety and the environmental side. I'd just like to make a statement. I'm intensely proud of what the team have achieved over the course of 2022. We had nearly 5,000 workdays of time. We drove over 180,000 miles in company vehicles. We carried out 10 full workovers with rigs on site and heavy equipment.
Of course, in the background, we've had continuous production operations over the course of the last 365 days during the course of 2022, all without a single reportable incident. The only incident we had of any safety nature was a small first aid case, which actually happened in the office. The team member with some over-the-counter medication was able to return to work immediately, and it wasn't a serious incident, but it is a demonstration of how seriously we take it. We're a small team, but safety is integral in everything that we do. Again, I think we've been able to demonstrate that during the course of this year. From an environmental perspective, it's again, been a good reporting year. There are only two small reportable incidents, and very small volumes involved.
The numbers have gone up slightly. Our ability to pick up those leaks when they've occurred, those minor leaks, has improved. You see the volumes involved are very small. In 2022, for the second year, we actually reported to the TCFD framework, our Scope 1 and Scope 2 emissions. The volumes have gone down. Intensity is up very slightly, but at the end of the day, these are very, very small problems. In fact, we're now reaching the regulatory threshold below which we're no longer required to report in the U.S.. The volumes are becoming so small. It's all associated or practically all associated with the flaring that takes place. These are small volumes. We flare about at 0.8 million cubic feet of gas a day across the entire field. 20 separate locations.
Moreover, when we move to full field development, we've been running pilot programs that allow us to utilize that gas and avoid flaring in the future. We're using the opportunity that we've got at the moment. From a fiscal perspective, 2022 was actually a good year for us. It was certainly helped by the prevailing oil prices, which were relatively strong. Not only were we able to cover all of the overheads associated with the company and run the company itself, we're able to take part in some capital programs. We were a 10% participant in two new wells that were fractured in the course of the year and board online. We also had our land program that we were funding. Of course, we were able to meet our debt obligations, both amortization and the interest payments.
In fact, we paid down our Macquarie debt by 25% during the course of 2022, and our net debt position at the end of the year was just over $4 million. It's a good position to be in. We do run a hedge program, and that hedge program is designed deliberately and set by the board to be conservative. It's about guaranteeing a minimum cash flow that allows us to run the company. In doing so, perhaps in 2020, it was probably our savior. It certainly kept us going during the very low oil prices that were prevalent. It's fair to observe that in 2022, it act as a bit of a cam in terms of revenue. By its very nature, it is conservative. We've been trying to address that by switching the emphasis from swaps across to costless collars.
That allows us more exposure to the upside. Quarter-on-quarter, we've been able to report diminishing costs associated with that hedge program while still protecting the downside. I think in Q1 of 2023, it was only $300,000 of hedge costs associated with that position. That transition is occurring, and certainly that helps. From a cost perspective, obviously from a production operations, our costs break down into three categories. In blue on the chart, you can see the fixed operating costs. In orange are the variable costs. The sort of occasional spike on top of that are the workover costs in gray.
It's a two-year period you can see there. If you just look initially at the blue and the orange lines in terms of our LOE, our lease operating expenses, you can see that it's been pretty consistent over the course of the last two years. There's monthly variations, but overall we've managed to keep costs down. You should look at that chart in the context of the inset. We're all very much aware in terms of what's happened to inflation or CPI. It's gone up considerably during the course of 2022. Again, I think we've got to give credit to the team in terms of insulating our own cost base from some of those inflationary pressures during the course of 2022.
In terms of the gray, which is the workover cost, this is a theme that I touched upon last year, and I don't mind coming back to it again. It's been a continued focus for us. You can see on the graph, this is the frequency of workovers on a year-over-year basis. Since Australis took over as operator, we've actually reduced that frequency by over 60%. That's really fundamental. It's a fundamental impact on our bottom line costs, and it also has a flow on effect in terms of our reserve base. Important work.
It's been driven again by the team, and they've been looking at things like chemical treatment programs around operating practices, both production and completion operations, around some of that completion design, metallurgy and so forth in terms of the materials that we select. We've also recently been improving a lot of our inspection criteria, which again has yielded dividends for us in terms of driving those numbers down. 2022 was a good year for us overall in terms of our production operations, both safety, environmental, and fiscal. Let's talk a little bit then about the asset that we hold. By way of background, the Tuscaloosa Marine Shale, the TMS for short. We use this phrase regularly, and again, I don't mind repeating it.
We believe this is one of the last discovered, delineated, but undeveloped quality unconventional plays left in the lower 48. We make that statement throughout many of our presentations and many of our ASX releases, and we think it's key in terms of opportunity. Historically, the play's been well known. It is a source rock that's been known about for decades. It was first explored as a potential unconventional opportunity in about 2010, and the analog for it was the nearby Eagle Ford Shale for the initial targeted wells. It's fair to say that the results were variable in terms of those initial results, and it very quickly became clear that the drivers for quality acreage within the TMS were quite different to those on the analog that was being used in terms of the Eagle Ford.
Fortunately, there were a handful of companies that stayed the course, that continued to drill wells, and over a period of time, they started to delineate a relatively small part of the play where results were consistent, and in terms of deliverability, they were on par with the much more established and mature plays that were being busily developed at the time. In fact, by 2014, there were five rigs running concurrently within the play. What the biggest, sort of, operator, still busy in the play, a company called Encana, had actually declared the play commercial and were moving towards full field development. The play was about to take off. 2014, the oil price dropped. All of those companies were heavily leveraged.
They all went through some sort of debt restructuring or Chapter 11, and everything stopped. For us, that was the opportunity. This was a play that had had over $1 billion spent on it. They'd shown where not to drill and where the wells needed to be located. They'd started the journey as to how to drill them and how to complete them, and we were already seeing, as I say, results that were comparable to the more established plays. For us, what was our plan? It was quite simple. It was simply we were going to try and find a high-quality oil asset. We were going to build a material position, hopefully on a low-cost base. We were then going to demonstrate value, and we were going to find a partner ultimately with a plan to exit.
In order to do that, we needed 2 things. We needed the right asset, we needed the right market conditions. From an asset perspective, we've always been confident that this is the right play. If you look at this, we've got long-term production from wells that have been online now for seven or eight years. We can map out decline profiles and compare them and be confident in terms of the deliverability from this asset. We're in the right zip code. We're close to infrastructure. We're close to markets. We de-derive a premium associated with the product we produce. All really important factors. We've got a very supportive local regulatory environment, particularly in Mississippi. The Mississippi authorities want to see this play being developed, they're very supportive in terms of our efforts to do so. I mentioned that there was a relatively uncompetitive environment.
That did lead to a low-cost entry into this play, but it also allowed us to build a very contiguous and material position within that delineated core part of the play. We're able to do so with very favorable terms associated with the leases from a development perspective. All of this we think is a significant element associated with an incoming party looking to develop. Moreover, we think we've got first mover advantage. As and when funds become available, we think we can add to the position very quickly. From a market perspective, certainly when we first went into this, there were just two drivers. One is that we felt this was a relatively scarce opportunity. In other words, it was something that would become desirable if we could repackage it.
Secondly, there was a theme that had been running for the previous 5 or 10 years of underinvestment in the oil and gas space, and we felt that they were drivers for us. I will talk more about the existing market positions at the end of the at the end of the presentation. That's what we saw. That's why we liked it. That's why we still do like it. What do we hold? At the end of Q1 this year, we sat on 77,000 net acres. Around 50% of that is held by existing production. We're always trying to balance our existing cash position with a land program to maintain control in that area, and we're confident at the moment we've been able to do that and manage that position. In anticipation of drilling, we've also been permitting units.
That allows us to increase our interest in particular areas driven by subsurface parameters or ownership in particular areas. It also allows us a degree of control as that we're designated as operator having done so. We think we've still got the material position that we're looking for. Today, we carry a net 280 future locations to the company. Ryder Scott have just certified a recoverable estimate on that of 120 million barrels. That's the asset that we hold. How does it compare? We do this regularly. We do it really for two reasons. One, because when we're presenting to an audience, we want to give you a degree of comfort that we have a quality asset and an asset that stacks up well to alternatives.
Secondly, when we're going through a business development process, we use this sort of material I'm about to present to you now in order to address some of the preconceptions about the play and provide empirical data that supports our position and why we're excited about it. This is a the graph that I've put up on the, the slide there is actually generated by a data analytics company in the U.S. called Novi Labs. What you're looking at is that they produced a report in the in the last quarter of last year. It was looking at the three major oil plays in the U.S. and looking at well performance out of those plays. We've talked about them in the past. It's the Permian, the Eagle Ford, and the Bakken.
They then split those down into subbasins, and there's 11 of them all together. They were just discrete areas within those basins, so they could allocate out performance. What you're looking at, and that the metric they've looked at is cumulative oil average cumulative oil production in a given year on a normalized basis per 1,000 ft. How much do all the wells that were drilled in any particular year, in any particular sub-basin, how much do they produce in the first year, and then normalized per 1,000 feet of horizontal. The line, different colors you can see are the different sub-basins, and the thickness of those lines actually refers to the number of wells that have been drilled in that particular year.
For example, if you look at the yellow and the pink lines on there, the yellow is the Delaware Basin, and the pink is the Midland Basin. These are the two main sub-basins of the Permian, which is the largest producer in the U.S. at the moment. About 5.6 million barrels a day. It would be the third largest producing country in the world if it was just looked at on its own. These are big producing areas. A couple things to point out. First of all, is that you can see that we've got peak production on those two areas actually in 2016. Since 2016, the productivity out of those horizons has actually pretty much stayed the same.
You can see they're the two thickest lines in the last four or five years, and that's consistent with the amount of drilling that's taking place and the growth in production in those two areas. If you look at the light green, that's the Central Eagle Ford area. That's the area that Aurora, our previous company, was busy in. You can see that peaked actually a little bit later in 2017 in terms of productivity. It's actually been on a decline since that point in time. The other ones all have smaller areas typically, so less wells drilled in them, and you can see they all have their own peaks and troughs as they're identified, drilled out, and then the best part of the acreage is consumed, and typically they'll start to decline after that.
That's the three main plays in the U.S.. That's what they look like with this sort of analysis. Let's now look at what the TMS looks like. Now we've only drilled 90 wells. I say we. In the play, there have only been 90 wells drilled to date. If I was to draw this as a line, it would probably be too thin for you to see here. We changed the, sort of the representation. It's the bar chart and the chart on the right-hand side. You can see that the well count in terms of wells put on production increased to 2014. There were 31 wells put online in 2014. It was a relatively busy year for the play.
Over on the right-hand side in 2019, you can see the 6 wells that Australis drilled and produced and put online as part of our operational program. The dots are exactly the same thing. The dots are the average production, cumulative production in 12 months from wells drilled in that year, normalized per 1,000 ft. It's exactly what we were looking at before. You can see a trend. First of all, you can see the increase that occurs in that period of 2011 to 2014 and 2015. We were drilling wells and drilling more and more in that center part of the core where we know the acreage is better. We were starting collectively to improve both the execution and the design of both the drilling and the completions.
That was driving the improvement in terms of productivity that you see there. I'll point out that our wells on the right-hand side, we've been very open over the last few years that we did have some operational execution challenges during that program. From a productivity perspective, you can see where the dot sits in 2019, it was actually better than any of the wells that were done previously. That's the average of all six of those wells. That was our underlying target for that program of work. It was to demonstrate rock productivity. That was the primary reason for putting those wells in the ground. Let's take that data, and now I'm gonna overlay it.
I appreciate that it's busy, but if you see the underlying lines which refer to the original report done by Novi Labs, and then if you concentrate on where the dots sit relative to that's the performance of the TMS on exactly the same scale. As the participants in the play through to 2014 started to concentrate in the core and refine the design, you can see by the end of that in 2014, the TMS was actually the second-best producing sub-basin in the U.S. This is good productive rock. There's nothing wrong in terms of the deliverability, and it's why we believe fundamentally that we've got a very valuable asset.
Even if you fast-forward into 2019, by this stage, there were nearly 70,000 wells drilled in the other plays and we're on well 90 in the TMS. We're just getting started. If you look at where the Australis productivity sits, you can see it was actually in the top quartile and very comparable to the best and most mature plays that are being developed even now prolifically in the U.S. This is good rock. Remember that what the Novi Labs have done on all those lines, that they've actually taken sub-basins. They've actually not just said, "What's the average of the whole thing?" But, "What's the average of different parts of the play?" I've made it very clear that there's parts of the TMS work, and there are parts that don't work so well.
Let's go back again and look at the TMS. The map that you see on the right-hand side there is of the Gulf Coast, and the TMS is that sort of large pancake area that runs through the center of Louisiana and just clips the part of Mississippi. It's a big area. The bit that we think or we know that works at the moment is the much smaller oblong you can see there in red. That's what we refer to as the TMS core. The chart that you can see on the bottom is actually one we've used in the past. It's a slightly different metric in terms of productivity, but effectively it's looking at all 90 wells that have been drilled in the play, and then it's trying to differentiate.
Those that are in blue are the ones that have been drilled inside the red oval, inside the TMS core. The ones that are in orange are the ones that are outside. You can clearly see the differentiation. The ones that are inside, on average, are much better performers than the ones that are on the outside. If I take a subset, not of the 90 wells in the TMS, but the 61 blue lines, all the wells that were drilled within the core, and then I go back to the previous diagram, we're now looking at the red dots. You can see here clearly that in 2013, 2014, and 2015, the TMS, if you just looked at the TMS core, was as good as the very best play being developed in the U.S. at the time.
Again, I'll reiterate, this is at the time on well 50 or 60 in the play. The competing plays were on wells. I'll be honest, I don't know the number, but tens of thousands in terms of their development profile. This is good rock. Obviously, the 2019 dot hasn't moved, and that's because Australis only drilled within the TMS core. Hopefully take out of that why we remain confident in terms of the quality of the asset that we've got, and it's really just a question of timing. Let's just talk briefly then about business development and where we sit in the U.S. Australis have had a very well articulated and clear and consistent strategy from day one. What we wanted to do is we wanted to identify an unconventional oil target with key characteristics.
Hopefully, at the beginning of the presentation, I've explained why we think that particular topic has been done and that particular box has been ticked. We wanted to secure a material position with a low entry cost. Because of the circumstances that I described earlier on, we feel like we've been able to do that one. We felt we would have to repackage the asset. We'd have to find some way of demonstrating underlying value. We think that despite some of the challenges that we had with the operational program in 2018 and 2019, from a productivity perspective, we can clearly demonstrate again that the rock is productive and it delivers. We're confident that we've got a tick in that particular box. The fourth step is the one that's been frustrating.
Securing a partner and bringing funding in is obviously what we've been working on really since 2020. We feel like we get a bit of a pass in the year of 2020 during COVID and everything that was going on there. We did have conversations. There were people that were interested, but we had a relatively low expectation in terms of our ability to transact in that environment. The truth is that post-COVID, with an improving market and certainly an improving oil price, you would naturally think that they would be the perfect circumstances to be out there marketing a new and exciting exploration and development and appraisal opportunities such as the TMS. In that environment, you also would have expected that the U.S., in particular, there would have been a surge of activity.
You'd have expected the companies to take those additional revenues and put them to work in terms of growing production and growing revenue. Certainly, that's what's happened historically, and that's been a big contributor to the cyclic nature of our industry that we're well-known for and often given a hard time for, and perhaps quite rightly. The reality, though, is that the reaction's been much more muted. The reality is that shareholders have driven a very different business model. Taking those additional revenue streams from the higher commodity prices and returning to shareholders or paying down debt, whether it's, you know, through various mechanisms. The truth is that it's worked. I think as a sector, the U.S. oil and gas space is probably the highest-yielding sector in the U.S. at the moment.
I think simply because of the dividends and the buybacks that are being created from the revenues, associated with the higher commodity prices. It also had a knock-on effect in terms of M&A. Those companies that were employing that particular strategy and were forced to by shareholders, they were taking a much more cautious approach to M&A. It tended to be more of the same. Often it was just buying production so that the results were immediately accretive in terms of returns to shareholders. In terms of us trying to sell a, an opportunity that was new, was different, and had a different risk profile, it's been a very different market for us to sell in than you would normally expect to have arisen as a result of circumstances.
We've made the point in the past, and the last couple of slides in the presentation will touch upon it, but we actually, whilst we understand the business model and we can recognize its value in the short term, we don't believe it's sustainable. Because as large as these plays actually are, as I was showing you earlier, they are finite. They do have a limitation. Whether that's for a variety of different reasons, but whether that's because of lack of inventory or the impact of wells on each other in future locations, then we're certainly starting to see that. In previous years, I've talked about the Eagle Ford and the Bakken and shown you how production has declined over time in those particular plays.
This time, I'd like to concentrate on the Permian, which as I say, is the biggest contributor to U.S. production. It's another Novi Labs slide that we have here that we picked up, and this time we're looking at the Midland Basin. This is on the eastern side of the Permian. It produces about half of that 5.5 million barrels a day, so it's a big producing area. What you're looking at here is a chart that looks again at productivity out of wells in that area. You look at the brown line first, the reddy-brown line, that's actually showing you the average horizontal length of wells drilled in the Midland Basin.
It shows you there that from 2014, 15 to today, the average well length has extended from 7,000 ft to 11,000 ft. They're getting longer. The dark blue line shows you what the cumulative production out of those wells are. You can see two things. One is that it's not following the same trajectory. A longer well is no longer producing proportionately as much oil. Also, you can see on the end of the program that we're actually starting to see a drop-off in terms of productivity out of wells in that area. If you now normalize that, which is the light blue line on the bottom, you can see there that's been perfectly flat over the last six or seven years.
That's consistent with the graph that I showed you earlier when we were showing all the different plays. This one actually goes on the extra six months. You can see by mid-2022, the productivity out of the Midland Basin was actually lower than it was back in 2015 and on a downward trend. Why? Well, there's probably three reasons. One is that this is all around optimization. When you've drilled 20,000 wells, you've probably got it pretty much down to a pat. In other words, there's not a lot of opportunity to improve productivity through design on these wells. The second is that this is limited. It is finite. It means that as companies drill out their best acreage and their best locations, they're then forced to go to secondary or tertiary locations.
Bottom line is they just don't produce as much oil. The third is that the very act of drilling a well and putting it in the ground and putting it on production depletes the local area. An offset location that's still yet to be drilled gets affected by that depletion, and we see a lower performance out of the adjacent wells, even if the rock itself is good quality. These wells are heavily developed. These areas are very heavily developed. Now, we all know that because we spend time over there. I appreciate that not all of our audience will be familiar with it. I'll try to demonstrate this. We're in the Permian still. We're over on the other side of the Permian now, on the west side of the Permian.
This is another study done by another analytics group called Dietrich. What you're looking at there is you're looking at all of the horizontal wellbores that have been drilled in the Delaware Basin. They're all the little lines you can see on the map on the left-hand side. There's around about 20,000 of them all together, and the different colors are just different horizons that are being accessed within the, within the overall structure. What I've then done is I've gone on to Google Earth, and just randomly from the center of the play, I picked out a block that's about 10 kilometers by 8 kilometers. All of the little patches and little light patches you can see there are actually surface pads. They've got multiple wells on them. They've got drilling facilities on them.
That gives you an idea of the density in terms of development. If we take it a little step further, and my little mouse will work here, and we just expand this one up. We're now looking at a block that's about a 1 km by 800 m. That's the density of wells that are being drilled out in these mature plays. When I talk about them being drilled out, you really need to understand they are heavily developed and heavily drilled. There isn't a lot of space left. If you go back to this map, you can clearly see that they've focused on areas where it's higher concentration in the better subsurface, and what they're left with now is the, is the secondary and tertiary type locations. When they run out of these, then they are forced to start to look elsewhere.
As I've shown you earlier on, the TMS has all of the attributes you'd be looking for in terms of a new play. Our belief is that incrementally and slowly, the industry is being forced to get out of the comfort zone that they've been put into and the shareholders have forced them to adopt. The assets like the TMS will become highly desirable. Obviously, that's the position that we've been working on and working towards. In summary, I think I've probably used up my 20 minutes, maybe plus a couple. Fiscally and from an EHS perspective, 2022 was a good year for us, both in terms of results and in terms of our performance.
From an asset perspective, we've managed to retain a material position that is desirable in the core part of the play, and we managed to do it out of existing cash flow. We still have 120 million barrels recoverable. From an industry perspective, we're aware that we've got increasing maturity within the established plays, and we've got a business structure that's working well in the short term but is not sustainable. All of the participants are now starting to talk about inventory being a big issue for them going forward. I think at that point, I'll probably stop and thank you very much for your time. I'll hand over to Jon, and if we have questions, et cetera, we can go through. Thank you.
Thank you, Ian. I trust you found that informative. Are there any questions in the room? No. We do have some questions that have been received. The first question. You?
Yeah.
Yeah. The first question is, do we plan on drilling longer laterals from our current average length of 7,000 ft?
The base plan at the moment is to drill 7,500 foot laterals. That's our base case. The drivers for that are the local land rules and the size of the units that we form. It's clear, and every other player over time, as I just showed you in the Midland Basin, has found the economics improve as wells are extended. I expect the TMS to be the same. There are wells today in the TMS that have been drilled out to 9,000 feet, and we can reconfigure things. The answer is probably yes, but our base case at the moment stands, and all of our economics are based on a set 7,500 foot lateral.
Thank you. The second question was, or is: If the U.S. oil price rallies into all-time highs, might we consider hedging 100% of production for 1 year considering the curve would be rising? I might answer this briefly. The board. We have an approved board hedging strategy. With that, we seek to balance the protection of a minimum revenue stream with the risks associated with being over-hedged and not delivering sufficient volume to meet a contract position. If our actual production was impeded for some reason, and we were not able to deliver that volume of oil, that would be a significant financial problem. We've typically hedged between 50% and 70%, which we think is balanced, but also consistent with our requirements with our debt.
That's of the forward first-year production, we still consider that to be an appropriate balance. The third question is instead of diluting ownership in our assets, might we consider debt/quasi-equity funding from commodity-focused lenders such as Battle Bank? I'm actually not familiar with Battle Bank. As part of our partnering efforts, we certainly have and do engage with a number of more finance-oriented entities. They seek to structure a combination of debt and/or preferred equity as part of the offer. We continue to discuss several alternative plans comprising multiple elements towards generating shareholder value. Our focus very much when considering any potential structure is maximizing shareholder value. I'm not going to forecast exactly how the structure will look, but it's likely to include several elements. Okay.
We have the results of the poll. Okay. Poll results. The votes have been counted on resolutions 1 to 10, and I now declare that resolutions 1 to 9 inclusive have been passed by the requisite majorities, and resolution 10 has not been passed. The results will be released to the ASX immediately following the meeting. There are no other matters that can be properly considered in the formal part of the annual general meeting, I now declare the annual general meeting closed. Thank you very much for your attendance.