Hello, everyone. I'm Jay Cheatham. I'm the Chief Executive of Pantheon Resources. Today, you will hear from myself, our newly appointed Executive Chairman, David Hobbs, and our newly appointed Senior VP of Engineering, Tony Beilman. This is a picture of our Theta West well with our Theta West camp. It was drilled a little over a year ago on the North Slope. Next slide. This is our disclaimer. Will you please read it thoroughly? Next slide, please. This is the North Slope of Alaska. For those of you who have been in our webinars previously, you've seen this in many forms. To the north of our acreage, which is in blue, is Prudhoe Bay, Kuparuk, and the other legacy fields of the North Slope. Prudhoe Bay was discovered in 1968. The original DeGolyer and MacNaughton report on Prudhoe Bay estimated 10 billion barrels of oil in place and 3 billion barrels recoverable. Today, Prudhoe Bay is in excess of 30 billion barrels of oil in place and in excess of 16 billion barrels ultimate recovery. To date, ultimate recovery is greater than the original oil in place estimated by DeGolyer and MacNaughton. The red outline is our 1,000 sq mi of proprietary three-D seismic. In the blue, you will see we have two named fields, Ahpun, which is on the eastern edge of our acreage and will be developed along and near the Dalton Highway, and Theta to the west, and we will talk more about them later. First, a little more recent history. In June of 2018, Bob Rosenthal approached myself and Justin about a merger between Great Bear and Pantheon. Great Bear had a decaying lease position. They needed immediate activity at Alkaid, and Farallon had security over 100% of their leasehold. Pantheon was struggling in East Texas. In July 2018, Philip and I met with Bob and Michael Duncan, and Michael presented a development case on Alkaid, and the Alkaid #1 well had been drilled four years previously, but had not been tested. Phillip and I were both skeptical because of our history with ARCO and the North Slope being the playground of the majors. Over the next two months, they convinced us that there was something there for Pantheon and the merged companies. Let's fast-forward five years. We now have 193,000 acres that is renewed with tenure. We have two production units that have been assigned by the state of Alaska to Pantheon. We've drilled 2 appraisal wells. We tested the Alkaid #1, and we drilled our first horizontal production well. We have tens of billions of barrels of oil in place, and we estimate 2 billion barrels of recoverable resource. Now, none of that would have been possible without Phillip Gobe's leadership and Phillip Gobe's skill. I wanna give a big thank you to Phillip. Now we're set on a new and different set of challenges and course. We are now transitioning to a development and cash flow generating company. As we transition to that, we're also transitioning to a new team that I mentioned earlier. Now, David is Executive Chairman, and his primary focus is on company strategy. My primary focus is gonna be on executing that strategy. We are going to share the communications about Pantheon to our shareholders and to the world. As I said, we've added Tony Beilman, who brings a world of experience in drilling and completing horizontal wells. Of course, he will be full-time as our Senior VP of Engineering. Next slide. The Ahpun field, as I mentioned, and Ahpun was a much beloved polar bear that resided in the Alaska Zoo for about 20 years. Ahpun is approximately 500 million barrels of recoverable oil developable along and near the Dalton Highway from the regional top seal down to the Hue Shale. It will include all of those reservoirs. Next slide, please. The Kodiak field is the reservoirs below the Hue Shale and above the Pebble Shale lower, and includes the previously described basin floor fans and will be developed over several phases, but has approximately 1.5 billion barrels of oil recoverable. Now I will turn it over to David to go through our company strategy. Thanks very much, Jay, and I'm delighted to be able to be talking to everyone today. It's a privilege to be able to share Pantheon's strategy for the transition from an appraisal company to a development company, from a strategy of accruing resources to turning them into cash flow. Our previously stated strategy was to prove up recoverable resources with a view to selling on to a major company, and the proof point there was Oil Search's acquisition of Pikka and Horseshoe from Armstrong. However, two things have moved on in the past five years. First, the appetite of the majors for Alaska has diminished, and even a number of foreign majors who might have an appetite would be unlikely to achieve CFIUS approval, so they're not a valid universe of potential buyers. The second is a perception that Pantheon doesn't have the financial strength to bring the resources to production and potential partners being prepared to outwait us, and that has lent heavily on the share price. The consequence of that is that the board's refusal to accept excessive dilution by doing a bad deal at appreciably less than independently assessed values for the assets by an order of magnitude means that the equity market valuation has given in to worry that perhaps the assets are just not that attractive. The only route by which that perception will change is for Pantheon to demonstrate economically viable production and bring it on stream. Who knows? If we don't need to sell down the assets, then perhaps investors will recognize their underlying value rather than expose themselves to the risk that someone else will own, end up owning them on the cheap. Hence, the revised strategy. Next slide, please. In today's webinar, we're gonna show you why we believe that the resources are worth $5-$10 per barrel at final investment decision, that's FID, for the full field developments of Ahpun and Kodiak. That is our strategic goal. We believe that we passed the economic threshold to begin the regulatory process to install the hot tap into the TAPS main oil pipeline around 2 miles north of our leases, and for the state to begin approving our Ahpun development plan. We don't underestimate the scale of the task ahead, but we believe it can be achieved at acceptable levels of value dilution through initiation of a low-cost phased development program, leading to positive cash flows sufficient to fund all future activity on the assets. Until today, the narrative has been that the assets can't be attractive because no industry validation has been achieved through a farm-out that allows a see-through value to the remainder of the portfolio. The fear of dilution in the event that a funding transaction does not happen has begun to weigh heavily on the stock market value. We're gonna be honest with you and confront the hard truth, and we'll continue to be transparent with you. We cannot rely upon a large company arriving with a multi-billion dollar check after whatever the next catalyst may be. We have to reposition the company to be financially strong enough to realize the value of this incredible endowment without relying upon events outside our control. We're not gonna pretend that there's a magic wand by which the maximum value of the assets can be realized without significant investment. It would be quite possible today to farm out 50% of the portfolio at a value around or just above today's market capitalization for a carry that would get us part of the way to cash flow breakeven. We could raise further funds at a premium to today's price for the remainder, which reserve-backed debt might augment and achieve a total funding requirement of $350 million. In that situation, today's shareholders would own significantly less than half the current 2 billion barrels of expected recoverable oil, and we would have given it away too cheaply. We don't need to raise all the money on day one. What we need to do is undertake the key steps that any industrial player would take to move these assets from where they are today to being on production and being able to start the development of the major Kodiak resource over the course of the next five years. We will explain the building blocks of our strategy. First, the economic case for developing Ahpun, which incidentally contains some of the lowest quality reservoir in our portfolio, but is geographically advantaged by its proximity to existing infrastructure. This case is supported by the flow test of Alkaid #2, and Tony is going to explain that in more detail shortly. Second is our ability to switch from high-cost single well operations to lower cost multi-well operations. Again, Tony's gonna talk us through that. The economics, as you'll see, of drilling each incremental well mean that de-development drilling will actually be liquidity enhancing because each well delivers a greater borrowing capacity than its cost once it's onstream. To be in a position to secure the financial needs, we'll take a number of actions geared to professionalizing the organization. We'll establish a Houston headquarters, and I'll be moving to the United States in the summer. Houston will become the center of gravity for our technical, corporate, and financial activities going forward. We'll shortly appoint advisors on the tax, legal, and financial aspects of a U.S. listing. We'll share a target date with you, as soon as we have a valid structure that ensures minimum costs and tax leakages. As I mentioned, we're beginning the regulatory process, both to secure the FERC approval for the hot tap into the main oil line and for the state's approval of the upcoming development. Now I'm gonna hand over to Tony, who's had hands-on experience of hundreds of wells in unconventional basins in the Lower forty-eight. Maybe, Tony, you can provide a bit more background on your experience and let me use this opportunity to welcome you aboard as Senior Vice President of Engineering for Pantheon. Thank you, David, for the introduction. Yes, after 40 years of various experience in multiple basins, with the last 15 years focused in unconventional plays, both on the horizontal drilling and the completion side, I'm happy to be a part of the team and leverage my experience to hopefully get us to a great ending for all of us. Again, thank you for that introduction. I would like to cover 3 points of interest related to the completions of the Alkaid 2H. First, we're gonna discuss briefly the current reserve projections. Then I'll identify some of the key areas of the frack design that led to the outcome and experience that we see on the Alkaid #2, and how that can be improved by optimizing new frack techniques that we've seen in the other unconventional basins throughout the Lower 48. Then we'll also present a table that shows those generational changes over the last 8 years in the lower 48 in dealing with completions of unconventional plays. We'll highlight how the Alkaid 2H compares to those generational changes. Finally, Jay and I, and Michael have worked on a lot of the cost estimates. I mean, the cost reconciliation part, and I'll turn that over to Jay after my presentation. Slide 8, please. Slide 8 presents the decline forecast based on the production history after the clean out of the Alkaid #2 in February. As you can see, our projections or estimates are that we'll recover approximately 260,000 barrels. The 30-day IP off of the Alkaid #2 was about 270 barrels. You can see the remaining economics related to that projection. Slide nine, please. Slide nine summarizes our development well economics going forward. As you can see, it highlights the improvements from the frack designs, longer laterals, and as such, you can see the expectations, estimates of 1.2 million barrels versus the 300,000 barrels that we saw off the Alkaid #2. You can see the IP comparison of 1,000 barrels a day versus the 270 barrels per day that we saw on the Alkaid 2. You can see what the net present value, which is $29 million and a $13 million well cost. You can see the discounted internal rate of return is very attractive at 300%. This is based on the Alkaid well performance and the revised completion models, and you can see we can get a 2x performance increase by increasing the lateral as well as 2-4 performance increase based off of optimizing the frack designs. Next slide, please. Slide 10 highlights the generational changes that we've seen in most of the unconventional basins throughout the U.S. Those basins include the Permian Basin, the Haynesville, the Marcellus, the Utica, and the Eagle Ford, among others. In this slide, we wanted to highlight the generational changes over the last eight years. In the Permian Basin and these other basins, they're pushing gen 4, generation 4 completions now. The yellow highlights where the Alkaid fell within those generational changes. Predominantly, the Alkaid came on in a generation 2 type design. Slide 11, please. Slide eleven, I'm not gonna go into great depth on this slide, but what this slide shows is what the future improvements would look like with improved frack designs and longer laterals. There'll be a webinar that Pantheon will present at a later date that'll highlight all these technical improvements. With that note, as I mentioned, Michael, Jay, and I did a reconciliation on the cost, and I'm gonna turn the slide back over to you, Jay. Thank you, Tony. Once again, welcome aboard. I'm happy that you are with our team. Next slide, please. As you can see, this is the Alkaid 2 estimated cost versus the actuals. This is for the drilling and completion. The estimate that was done in the fall of 2021 was done after the completion of the Talitha-A well. The costs were based on that well cost and design. The actual number of days we estimated was not too much in excess. We estimated 65, it took us 69 days to drill and complete. That delta was primarily because we had some issues in setting and kicking off the plug. I would just say that in future wells, we will not drill a pilot hole, we will just drill directly into the horizontal, so we will not experience those types of issues in the future. The total rig cost in tubulars were a little under $1 million over the estimates. That was just general inflation. As everyone knows, in 2022, there was a quite extensive inflation in the oil field and everywhere, generally around the world. Logging, we will not do LWD/MWD extensive logging in the future. There's no need for those in development wells. We basically missed that by about $2 million. The workover rig, after the failure of the All American rig, there was only one other rig available for the workover, and so we paid for a single vendor cost on that. The majority of the overruns, that's a little more than $8 million, was actually in the frack, in the pumping, in the chemicals, in the sand. The sand, it was typically we sourced the sand out of Canada, and general inflation, double handling, fuel price increases increased that substantially. In the future, we have found a source, a local source, so we will cut that sand cost down dramatically. For pumping, we had to import horsepower from both Louisiana and Russia. There was also one single vendor that bid for the pumping of this frack, and similarly on the chemicals, it was a single vendor. We paid for the cost of importing horsepower from abroad and from the Lower 48 and for a single vendor. Many of those costs will not be there with development wells when we're drilling multiple wells and have a better ability to negotiate with the vendors. We went from about $22 million - $34 million to drill and complete this well. In addition, we spent $6 million on the 2 clean outs. As Tony said, in the future, we will design our fracks so that we minimize the sand flowback. Also, we spent about $10 million on a permanent production facility. We did have mission creep on that. Initially, we had estimated that we would have a single well facility that was not automated. We ended up with a 6-8 well facility that is fully automated, and the total cost of that was $10 million, including $3 million in commissioning. We now have a permanent production facility that we will have to upgrade some in the future for additional gas and water handling, and also put in a refrigeration unit to handle as much of the NGLs as we'll be producing. We do have that facility now, and we own it. I'm pleased that we designed and assembled, we disassembled it, we transported it and assembled it again, all in a single season, which is quite remarkable on the North Slope. The next slide, please. I'm not gonna go into a lot of detail on this because we will have a future webinar where Tony and Michael will take you through this. I mentioned some of the cost savings that we estimate to get from the GBP 34 million down to the GBP 13 million. Obviously, the big ones are, as I mentioned, the drilling time savings. We will not drill a pilot hole. We won't have to set a plug. The frack optimization and no longer being hostage to a single vendor. The local sand versus bringing sand out of Canada and having to transport it to the Port of Seattle and putting it on our barge and transporting it to the North Slope and taking it off the barge and putting it into trucks and trucking it down to the location. We'll use the existing pad. We will no longer have the extensive logging costs. That will be what will be discussed in more detail at a future webinar. Now I'd like to talk about the Ahpun Field Development Project, phase 1. As David mentioned, we will develop the permitting and TAPS. We will do a hot tap about 2 miles north of the Alkaid Pad on the west side of the Sagavanirktok River. That'll be completed in approximately 24 months. We will go out for batch drilling and completion of the first 4 production wells, and we expect a reduction in the cost. Maybe we won't get down to the $13 million on that, but we will reduce those costs. We will also have water and gas disposal wells as required. As we've mentioned, we will have to handle water and gas over time. That is not unusual in the oil field, and we will design for that. We will upgrade the modular production skids into incorporate that. We will strip out the NGLs to maximize our marketable liquids. That is to be completed in approximately 27 months. The initial depletion will be along the Dalton Highway with our two already permitted Alkaid and Theta pads, with the production sent to TAPS along the corridor up to the hot tap. The quality bank adjustment that Pat Galvin so aptly discussed in our last webinar will result in a 10% shrinkage, which means that if we put 1,000 barrels in at to TAPS, we will get approximately 900 barrels of ANS crude marketable at Valdez. The excess associated gas that we do not use to produce electricity, along with produced water and CO2, is to be reinjected into the reservoir to enhance our oil recovery. Next slide, please. Now I'd like to update everybody on the acreage that we acquired in 2023. Basically, the main acquisition, which is shown in red, was securing the remaining portion of the Kodiak field, which is the extreme up-dip portion of that field. I'll show you more about that in the next slide. We also blocked up around our Alkaid and Talitha units, and it will extend our ownership around those units and greatly extend our ownership in the Kodiak field, where we believe the up-dip portion, the chimney, as we call it, contains billions of barrels of oil in place. Next slide, please. Many people said, "Well, you had 153,000 acres. Why did you need to add to that?" It's really simple. We added to it, one, to block up around Alkaid and Talitha, but more importantly, to get the very best reservoir in the Kodiak oil field. We drilled our initial well, Talitha, in sort of the extreme down-dip portion, and we had rather modest reservoir qualities. We went 10.5 miles, and we predicted that we would go up-dip, that the reservoir would expand by about 50%, and we would greatly enhance our reservoir properties. All of those things happened. We now project that the extreme up-dip portion of the Kodiak field will have permeabilities about 50 times greater than the original permeabilities in Talitha A, and we will have porosities between 14% and 17%. That is a huge improvement over the porosities seen at Talitha A. Now, as David mentioned, the Alkaid field or Ahpun, the reservoir properties there are close to the Talitha A property. It is part of our lower reservoir quality that we are developing initially, but because it's along the Dalton Highway, the economics are very, very robust. With that, I will turn it over to David. Thanks very much, Jay. The next slide, please. We talked about the overarching strategy, and a key part of that is going to be capital formation. We talked about a need for some $350 million of investment to bring this portfolio of assets up to being cash generative to a point where it's self-supporting. That sounds like a lot of money, but it's much easier to conceptualize it in bite-sized pieces. Not all of it needs to be at the same time. Not all of it needs to be from the same source. There's an overriding philosophy that we want to share and is a core part of our strategy going forward, which is that we will always prefer now to finance the business conservatively. We'll do it by looking at what achieves the lowest overall dilution of value for our shareholders, up to the point of cash flow breakeven, where we won't need to raise any further capital. That taking the right steps along the way, moving the assets from looking at volume to looking at value, from appraisal into development, will provide those steps that will allow us to minimize dilution and effectively execute our strategic plan. Next slide, please. To recap on what that plan is, as we said, our objective here is to deliver sustainable market recognition of $5-$10 per barrel. How do we come up with that number? If we take the well economics, the incremental well economics that Tony showed you, and assume that nothing improves as we move into better quality reservoir, then at ANS prices between $60-$80 per barrel on the basis of the development of the expected recovery, what we see is $5-$10 per barrel in the NPV10, NPV12 kind of range. That is our target. In order to achieve that, we need to achieve final investment decision on the two large fields or extremely large fields, Ahpun and Kodiak. To have reached a position where we are no longer reliant on markets for capital to further development. We reckon that that requires 20,000 barrels per day of production into TAPS. That's what the analysis right now shows. Over the coming weeks and months, we'll be refining that plan in order to minimize and use capital as efficiently as possible. That plan requires around 30 optimally fracked 10,000-foot lateral wells from the Alkaid and Theta pads, and processing capacity, which is not a significant upgrade from what we've already built. We've got a really good handle on the costs of getting there. By having long lead times for arranging the delivery of goods and services, we will be able to overcome the problems we've experienced with being one at a time operations and having only one supplier. That way, we can become a preferred partner and have a preferred partner to minimize costs and ensure that we hit our milestones along the way. That starts with a hot tap into the TAPS main oil line, because the costs of accessing facilities with trucked oil mean that it is more economically attractive to hold back on production until we can access the pipeline on a common carrier basis without paying any premium to anyone. To get us started off down that road, as I said, I'll be moving to Houston. The company's center of gravity will be our Houston headquarters. The majority of our staff will spend a significant proportion of their time together in the office so that we capture the opportunities of that interaction on an ongoing basis. We'll be hiring advisors on our U.S. listing strategy, and we have begun planning for and will shortly be engaging with both the FERC and the state for the development permits to allow the Ahpun Field development to move forward. Next slide, please. What you can see is an illustrative timeline. In terms of the key activities, we're expecting the Netherland, Sewell & Associates report on Kodiak during the first half of July. We're expecting an initial report on Ahpun that incorporates the Alkaid 2 test results probably in September. And of course, as we analyze the additional reservoirs that form part of the Ahpun Field, we'll have a final Netherland, Sewell & Associates report that will be the support for funding. That will allow us to begin intensively looking at the development financing for Ahpun, with a view to having the field FID during the second half of 2025. If we begin development drilling running into that final investment decision because some of that development drilling will be the proof of the optimization of the fracking, then we're in a position within two years to have achieved positive net cash flow that will support phase two development for Ahpun. Equally importantly, give us the confidence that we can move to final investment decision on Kodiak with a view that in the second half of 2028, we should have got to a point where we have reserves recognized because we've got regulatory approvals, we've got company commitment to the development, and we have demonstrable economic projects that will underpin the valuation we talked about of $5-$10 per barrel of proved reserves. With that, we'd like to thank you very much for joining us in this webinar. As mentioned, we intend to share greater depth on some of the technical issues with you in follow-up webinars. There will be a webinar when we get the Netherland, Sewell report that should allow us to share in great detail the findings of that and the consequences for the economic attractiveness of the Kodiak Reservoir. Furthermore, we'll be posting a full list of Q&A that have been submitted. Thank you to those who've submitted questions. We wanted to give you an opportunity to hear the presentation so you could ask questions on the back of the presentation rather than requiring questions as in the past were being submitted beforehand. Some we've covered in the presentation. Others, we will post the detailed Q&A to the website. We'll do that and refresh it on an ongoing basis, so that we're making sure that we're not leaving investors worrying or wondering about the answer to a particular question. Thank you very much indeed for having joined us, and we look forward to the next webinar in two or three weeks time.