Thank you for standing by, and welcome to the Horizon Oil Limited Full Year Results Webcast. I would now like to hand over to Mr. Chris Hodge. Please go ahead.
Thank you. Well, welcome to the Horizon Oil 2021 full year results presentation. I am Chris Hodge, the company's CEO, and I am joined by Horizon Oil's CFO, Richard Beaman. I will make some introductory comments before handing over to Richard to run through the full year results. I will then cover the operational performance of our assets and strategic outlook and direction before opening up for questions.
So turning to the full year highlights, this slide provides an economic snapshot of the company's results for financial year 2021. It is very satisfying that despite the economic challenges presented by the COVID-nineteen pandemic, we met or exceeded all of our production and financial guidance with strong production recovery in oil prices driving profitability and free cash flow generation. This strong performance combined with cash inflows from the option proceeds and PNG sale left the company with one of the strongest balance sheets in its history paving the way for significant returns to shareholders. Importantly, and this should not be understated, operations were conducted safely and with no environmental incidents despite significant levels of activity at both fields. So with respect to the executive summary, the 2021 financial year can probably be best described as a tale of 2 halves.
With a challenging first half, we've continued low oil prices and production disruption at Mari, which was exacerbated by workover delays caused by COVID-nineteen restrictions. The second half saw production levels restored and enhanced following workover activities at both fields, infill drilling at Beibu, and these were aligned with a steady recovery in oil prices back above $70 per barrel. Pleasingly, the group generated strong cash flows and together with receipt of the 3,500,000 dollars from the sale of the PNG assets and $14,000,000 option proceeds led to a material increase in net cash to $32,000,000 So with the strengthened balance sheet and greater confidence in future cash flows through continued strong production and higher oil prices, the company was able to provide significant returns of capital to shareholders through share buyback initiatives and the recent $0.03 per share return of surplus capital. The company is now poised in a strong position, the result of a strong balance sheet, strong production and low operating costs. So I will now hand over to Richard Beemont to take us through the financials in more detail.
Thanks, Chris, and good morning, everyone. Look, before I go through the results, I would like to emphasize that all references to dollars are U. S. Dollars unless otherwise stated as this is the group's functional currency since all revenues are generated and received in U. S.
Dollars. It's also important to note that the divestment of the group's PNG operations during the year has been treated and classified as a discontinued operation in the full year accounts. And so the PNG income and expenses for the year have been excluded from EBITDAX and underlying profit in the presentation. And for comparative purposes, we've also normalized the FY 2020 results to also exclude the PMG discontinued operations. We move over to the full year highlights.
The table on the right in this slide summarizes the FY 2021 results with a comparison against the prior year. Notwithstanding the depressed oil price during the first half of the year and the COVID related production disruptions Chris mentioned, the full year results were strong with EBITDAX of $36,000,000 and an $8,000,000 statutory and underlying profit after tax, demonstrating the strength of Horizon's producing assets. Despite realized oil prices being 15% lower than the prior comparative period and just over $50 per barrel and production being 10% lower over 1,330,000 barrels, The company generated strong cash flows from operating activities of over $23,000,000 This cash flow coupled with the $14,000,000 option proceeds were the substantial drivers of $31,200,000 increase in net cash to $31,700,000 The strong cash flow was underpinned by high margin production at both Mari and Beibu where cash operating costs were again maintained below $20 per barrel despite the lower production levels. The cash generated combined with the option proceeds and PNG sale proceeds allowed for progressive debt reduction, continued investment in our assets to drive organic growth and a significant buildup of cash from which to initiate the approximately US37 $1,000,000 in capital management initiatives, including the on market buyback of 20,300,000 shares an unmarketable parcel buyback of 2,700,000 shares, which tidied up the share register and reduced the administrative costs associated with managing approximately 1,000 small shareholdings, representing about 20% of total shareholders, and probably most importantly, the recently completed AUD 0.03 per share capital return.
All initiatives were designed to increase shareholder value whilst not placing strain on the company's balance sheet. Whilst production levels were lower during the first half of the year, investment in infill drilling at Beivu and workover activities at both fields were safely completed during a period involving significant logistical challenges due to COVID-nineteen. Pleasingly, production levels were able to be increased in time to benefit from rising oil prices. On the ESG front, Horizon Oil's assets performed well with no loss of containment incidents during the year. In terms of safety, the company's assets achieved a total recordable injury frequency rate of 1.02, which well outperformed the industry average for NOBCMA administered areas.
The group continues to focus efforts on sustainability and governance as set out in the group's sustainability report released this morning with the annual report. Importantly, we have further enhanced our emissions disclosures and continue to report against the recommendations of the task force for climate related financial disclosures. We've also prepared a 3 year ESG action plan to refine our goals, targets and activities in our ESG priority areas. Now if we dissect cash flow, in this next slide, we can see that approximately 2 thirds of net cash inflows from operating activities of $23,200,000 was applied to the repayment of debt facilities and the share buyback initiatives, which together totaled $15,400,000 with the majority of remaining cash from operating activities of just under $8,000,000 reinvested in capital growth programs, including the Block 2212128 East development and Weizhou six twelve infill drilling. The proceeds on the sale of the group's PNG assets of $3,800,000 which included $300,000 in working capital adjustments, together with the options proceeds for $14,100,000 were retained and used to pass fund the recently approved $0.03 per share capital return.
Now to help dissect the full year results further, the next chart shows the key elements which have driven the consistent underlying profit result of approximately $8,000,000 and clearly shows in the white bars the significant impact of the reduction in revenues due to the 15% lower realized oil price and 11% reduction in sales volume. As can be seen, the 12% reduction in operating costs, 46% reduction in financing costs combined with reduced taxes and royalties helped to materially offset the $20,000,000 decrease in revenues resulting from lower realized oil prices and production. Continued discipline in spending across the business during the year helped to keep the company in a consistent underlying profit position. Now recognizing the change to Horizon's business following the P and G divestment and in the pursuit of driving lower costs in the company, we've implemented significant restructuring during the year and in recent months. Through a combination of planned redundancies and staff resignations, we have reduced headcount by approximately 50% over the past 18 months for just 12 employees and incurred just under $400,000 in restructuring costs during the year to affect these changes.
Approximately half of those individuals leaving the business have done so in this calendar year. So the annualized cost savings amounting to about $1,500,000 will only be fully realized in future years. As part of this restructuring, the company's key management personnel have been cut in half to just 2, being Chris and myself. We will look to optimize the cost structure going forward, but we need to make sure we have the necessary resources to extract the substantial remaining value from our existing assets. Turning over to the next slide, we can take a look at the financial year results compared against the previous 4 years.
As in previous presentations, we've included some detail of the impact of Weibo cost recovery revenue in early years to assist with normalizing the results. As mentioned previously, this was additional revenue earned in earlier years to reimburse the company for historical exploration expenditure in China and was largely recouped by the end of the 2019 financial year. So moving to sales volumes. The first of these slides shows that production and sales for the 2021 financial year was just shy of the 5 year average, with natural reservoir decline and the COVID driven reduced production at Maori impacting sales volumes. Importantly, much of the lower production at Maori has now been restored and with the additional infill wells of Beibu combined with the scheduled 12 8 East development production during the second half of next year, we would anticipate sales volumes returning to near the 5 year average.
Importantly, Beibu production has been very consistent over that 5 year period. It is this consistent production together with low operating costs, which has been the predominant driver of Horizon cash flow over recent years and provided the confidence to further invest in infill drilling and the 1280 East development during the year. Maori production has also been a significant contributor, particularly over the last 4 years owing to the successful acquisition of an additional 16% interest in Maori during 2018. The chart also clearly shows the contribution of Beibu cost recovery volumes to sales in FY 2017 2019, which has now ceased as historical exploration expenditure amounts have been recouped. The revenue chart also clearly shows the contribution to revenue of the Beibu cost recovery sales.
Once we strip this away, we can see the significant impact of a lower oil price during the current year. Pleasingly, oil prices recovered strongly through the second half of the financial year and continue to trade around $70 per barrel, which bodes very well for higher forecast revenues and cash flow generation in FY 2022. Revenue over the first half of FY 2022 will be supported by recently executed hedging through a mixture of swaps, options and collars, which provide oil price protection to approximately half of Horizon's forecast production through to 31 December 2021 at a weighted average price of $69 per barrel, whilst also retaining exposure to rising oil prices. The next slide again shows the relative impact of lower oil prices on the group's profitability in the 2021 financial year, but pleasingly highlights the resilience of the asset portfolio and continuing to generate strong EBITDAX and return a consistent underlying profit despite the challenges faced in FY 2021. This result is driven by the group's low cash operating costs, which were maintained below $20 per barrel.
Importantly, the group was able to sustain per barrel operating costs well below $20 per barrel despite the 10% reduction in production, highlighting the significant cost improvements made. While some cost savings resulted from deferrals of work, we expect that the majority of cost savings are sustainable over the longer term and continue to forecast costs remaining below $20 per barrel over the coming year. The next slide shows the continued strong free cash flow generation with the orange line in the chart on the left normalized to exclude the cost recovery cash flows. While this again shows the impact of the lower oil price and production on free cash flow in the current year, it highlights the capacity of the business to sustain free cash flow generation through oil price cycles with the prior downturn having impacted FY 2017. Now I've saved the best chart to last with the net cash net debt chart on the right.
Here we can see how the strong and sustained free cash flow generation from the group's assets has driven consistent and sustained debt reduction from a net debt position of over US108 $1,000,000 at the end of FY 2017 to a strong net cash position of US31.7 million dollars in only 4 years. That represents free cash generation over a 4 year period of over US140 $1,000,000 approximately AUD 200,000,000 Our focus is to continue to drive this free cash flow generation from our assets out into the future by extracting maximum value from our assets. The resilience of the cash flow, higher oil prices coupled with this rapid de gearing and return to a significant net cash position provided the confidence to implement the various capital management initiatives during the year and return significant value to shareholders. I'll now pass back to Chris to provide an update on our asset portfolio and the outlook for the company.
Yes. Thank you, Rich. So turning now to the overview of the portfolio. On the slide here is the geographic focus area for the company, which continues to be the Asia Pacific region. As you can see, we currently have material joint venture interests in each of our production licenses, which ensures we have an appropriate level of influence, while still managing risk.
Our focus is to work with the operators in these fields to extract maximum value from our low cost production. The assets of course are the lifeblood of the company and provide significant leverage to the oil price for investors, aided by low cash operating costs, which remain below $20 per barrel overall. Turning to the reserve slide, the proven and probable reserves for the group are 6,700,000 barrels, which represents a 1,400,000 barrels reduction, and that reflects the annual production achieved with minor technical adjustment. Moving to the next slide, the Block 22 in China. So detailed on the map of the Block 2212 fields, which were operated by Scenic and Rock Oil, and which the company has a 26.95 percent interest in the producing 612 and 128 East fields and a 55% interest in any surrounding exploration areas.
As depicted on the map, the oil fields are tied back to a centralized Cenook infrastructure, where oil is metered for sale and transferred by a pipeline to the Weiju Island Terminal. These fields continue to provide reliable strong cash flows contributing approximately 70% of Horizon's cash flow. The next slide provides a summary of our China fields and shows the production performance over the last 5 years. These are conventional oil fields, which ordinarily suffer from natural reservoir decline. However, the joint venture has managed to sustain gross production at an average of over 9,300 barrels per day for the last 5 years.
Whilst production during the half year dipped below long term average, a work program followed by a successful 2 well infill program has restored and increased production back to over 10,000 barrels per day. However, current production is approximately 8,000 barrels of oil per day. The sustained production rates at Babu have been achieved through infill and near field drilling, installation of additional water handling capacity and production optimizing well workovers. Indeed, we have just this last week completed 4 workovers in the twelve-eight Westfield and from which we expect to increase gross production by 1,000 barrels of oil per day. The production is forecast to be increased back above 10,000 barrels of oil per day during or soon after quarter 1, 2022, when the 1280 East development comes online.
The objective of the joint venture is to continue to sustain production rates well into the future, as has successfully been achieved in the past. Further infill and near field appraisal opportunities have been worked up by Horizon in house and are currently being considered by the joint venture in order to replace reserves and sustain production rates. Our ability to invest in such organic growth is driven by Block 2212's low cash operating costs and favorable fiscal regime. The current producing fields have a current contractual and economic production life until 2028, 2030 for 1280 East and field decommissioning costs have been prepaid into a sinking fund. Accordingly, these fields are expected to continue to generate strong free cash flows for the group over the medium to longer term.
Turning now to the next slide, chartered Block 2212 in full and production enhancement. Our crude oil sales from the fields totaled 800,000 barrels at a net realized oil price of $54 per barrel and a low cash operating cost of just $12 per barrel. In early 2021, we drilled 2 infill wells to target undeveloped reserves in the 612 area, the Northern Group of fields. Both wells were successful and commenced production in February. As for the outlook I previously mentioned, we anticipate increasing oil production by some 1,000 barrels a day as a result of the recent workovers, and we're working very closely with our joint venture partners to agree on infill and appraisal targets for drilling in the financial year ahead.
Turning to the field cross sections on the right, they are rather too small to see the detail, but there are some points of interest. The upper cross section slices across the northern group of fields and illustrates the geological complexity, and therefore, the scope for further in 4 drilling. The scale is some 4 kilometers from the producing platform on the left to the shallower field on the right. 1 of the recent infill wells was drilled into this structure and the other into the shallow fault bound anticline in the middle, which contains multiple thin sands. Getting these wells right takes significant amounts of planning and expertise, and we work closely with our joint venture partners to achieve this.
The lower cross section runs from west to east, from the 128 West field on the left to the 128 East development on the right. And as you can see, the geology is quite different, fewer and thicker sands and structurally more subdued with broad low relief anticlines. Once again, we work closely with our partners to ensure that infill opportunities and drilling trajectories are optimum. Turning to the next slide, about 2,212. So this project is very much taking shape, and we look forward to the least wellhead platform being towed to its location.
This is imminent. I think it may be occurring tomorrow, as is the laying of a pipeline to connect with the twelve-eight Westfield. Once the platform has been installed, the drilling of 6 producing wells will commence along with 1 water injector. We anticipate 1st ore during the Q1 next year with gross ore production to average some 4,000 barrels of oil per day during the 1st year. And looking to the diagrams on the right, these depict 5 horizontals drilled into the low relief shallow reservoir with one well drilled into a deeper structure and one water injector also drilled into that deeper horizon.
This new wellhead platform not only produces from the 12/8 East field, but also allows access to remaining discovered resources, 12, 10, 1, for example, as well as prospective opportunities. This is the first phase of development and is expected to recover some 600,000 barrels net to Horizon. If this is successful, 2 further phases are possible. Total development costs are linked to the oil price, such that based on the current oil price, about $70 a barrel, Horizon's total share is US19 million dollars dollars 3,100,000 of that has been paid to date with the majority of the remainder coinciding with the commencement of production. Now turning to the Maori Minai fields in New Zealand.
Detailed on the map is the Maori and Minai fields, which are currently operated by OMV, and which the company has a 26% interest. These fields generate approximately 30% of Horizon's cash flow and are anticipated to continue to produce stable production and cash flows over the coming years. I mentioned that OMV are the operator. Nearly 2 years ago, OMV advised of its intention to sell its 69% working interest to Jade Stone, subject to regulatory approvals. Over the initial several months, RMV and Jage Stone worked cooperatively to transition the operatorship.
However, regulatory approval was not forthcoming. The lack of regulatory approval was and still is a hot political issue related to liability for abandonment. This is fueled in New Zealand by Tamarin failing in its obligation to abandon TUI and that's been exacerbated by a similar occurrence in Australia. So as far as we know, the deal is still live and the operatorship transition is therefore still in limbo, pending legislation to be enacted by the New Zealand parliament. The future remains unclear.
However, OMV in the meantime has stepped up, has initiated several cost saving measures and it's taking its responsibilities as operator very seriously. As such, the field is being well managed. So the next slide provides a summary of Mari and shows the historical production performance over the last 3 years. As with Beivu, these are conventional oil fields, which suffer from natural reservoir decline. However, initiatives implemented in recent years providing primarily involving water injection and production enhancing workovers have reduced field decline with daily gross production at an average of approximately 6,000 barrels a day for the last 3 years.
So while production rates during late 2020 were impacted by the shutting of 3 wells, 2 workovers were conducted during the period to restore production. And pleasingly, production rates from the field have been very stable over recent months, no decline in the main Maori Moke reservoir, highlighting the effectiveness of water injection into the field. A third workover was completed earlier this year. However, the well is currently offline to assess low levels of sand production. Current production from the field is reduced at 4,500 barrels a day, pending MR6A coming on back online and a replacement ESP required for a workover on well MR8A.
So with respect to field optimization, crude oil sales from the field totaled 4 65 barrels at a net realized oil price of $58 per barrel and a cash operating cost of $25 per barrel. Production during the year was reduced due to COVID-nineteen delays. I've already touched upon the operator issue, but if and when rep judge don't take the reins, we have a deep understanding of the field, and if such, can facilitate a smooth transition, focus being on maximizing longevity and therefore value. Looking ahead, we hope to reinstate production from MR6A, with the installation of a temporary desander on the wellhead platform, replacing ESP on MR8A, see increased production rates following the conversion of MR2A to an injection well and continue with optimization of the cost structure. So turning now to the outlook.
Despite the recent oil price wobbles, we continue to be bullish on oil price. The world remains highly dependent upon oil and investments in new supplies increasingly subdued as ESG and climate pressures bite. We intend to capitalize on these higher prices to deliver value. So looking at the components, strong operational cash flows, these increase at a rate of US8 $1,000,000 per annum for every incremental US10 dollars per barrel increase in oil price. Married to a sub $20 cost of production, married to a sub $20 per barrel cost of production, we are targeting in the order of $20,000,000 to $25,000,000 of free cash flow assuming current oil prices.
We are disciplined in our investments. We will repay US13 $1,000,000 of debt during the financial year, and we will continue with smart investments, twelve-eight SID, infill drilling, increased water handling capacity, etcetera, selected workovers to keep Beibu production flat. We estimate some $15,000,000 to $20,000,000 of CapEx during the upcoming financial year, primarily for the 1280 East development costs. We aim to increase shareholder value through cash through capital management initiatives where appropriate, delivering on organic growth opportunities at twelve eighty East and the like, and we will maintain opportunity we will maintain optionality for growth. What we're seeing is increasing numbers of attractive brownfield opportunities are being available for minimal consideration.
We can and should be in the mix for these sorts of opportunities. And last but not least, we have an increased awareness and focus on ESG, environmental, social and governance. We continue to encourage our operators to maintain the highest standards of safety and asset integrity, and we recognize that non financial performance is increasingly important in today's world, not only for our bankers and insurers, but also for our investors and actually for ourselves. So that concludes the formal presentation. And we will now turn to the questions.
Thank you very much, Chris and Rich. So the first question we have is in relation to the BeiDou Gulf asset. Is there any optionality to extend the permits for Huazhu 6 12 and 12 8 West and 12 8 Eastfields beyond 2028 and 2,030 respectively? And if so, what are the conditions to achieve an extension, including any monetary payments?
Okay. I'll take that one, Vas. So the question is optionality to extend the China Beibu assets. And if so, what are the conditions? The 2028, 2030 dates are pretty much a hard stop.
Some 7 years away, I would expect as we move forward into the next couple of years, we will start addressing this issue. If there is the opportunity to extend, we would need to offer significant investments to Cenac. And I would hope and expect that we will be having a discussion and negotiations to see if it's possible to extend these licenses.
Thanks for that, Chris. Second question again with Beboo. Why are crude oil sales in FY 'twenty one of 801,000 barrels being Horizon Oil share materially below crude oil production of 873,000 barrels? And we're on the assumption that our production was metered through a pipeline back to say, NUC facilities and therefore production itself should broadly align.
Yes. Look, I can cover that one. Look, essentially, it's governed by the PSC. So our entitlement is governed by the PSC. Yes, we have a 26.95% working interest in the field, but there's through that through essentially that petroleum contract, there is some VAT which goes in kind to the Chinese as well as some small royalties which also are taken in kind.
So essentially, it reduces our entitlement to roughly around 25%. Obviously, in early years, we benefited from cost recovery. And we in fact, we went up to about a 40%, 45% entitlement whilst we were recouping our exploration costs. So it does vary a little bit, but at the moment, it's around about that 25% of share of production.
Thanks for that, Rich. Next question, well done on a good result. You've mentioned that China development costs fluctuate based on different oil prices. I just wondered, firstly, how material that is? And secondly, what oil price you've assumed in the CapEx outlook for FY 2022?
I can cover that. So this relates to the 128 East development. And as we mentioned, capital costs and production costs are essentially pegged to the oil price with a little bit of a natural hedge. Look, it is quite material. The contract essentially allows for differing CapEx and OpEx based on a price oil price ranging between, on top of my head, about $35 a barrel on the downside and up to about $75 per barrel on the upside.
On a CapEx basis, and I think we had this in an earlier announcement, essentially that pricing range from that marries up with about $11,000,000 CapEx of $35 a barrel all the way up to $19,000,000 $20,000,000 of the top side. So we've assumed in our outlook $70 a barrel for the purposes of the $19,000,000 we've disclosed. Obviously, if it goes much higher, it doesn't make any meaningful difference. But if it goes lower, then yes, it will it's a reasonably linear kind of adjustment.
Great. Thanks for that, Rich. The next question we have is, does the forward strategy include to shelve the search for new oil assets and concentrate on our 2 existing assets?
So I'll take that question. Firstly, let me just say we are concentrating on our 2 existing assets. As I mentioned, we've got the 1280 development coming on and we've got infill wells to work up. We also have, following the return of capital to shareholders, limited cash available. However, we are able to do 2 things at the same time.
We've done a lot of work in the last year. There's a lot of people know that we've been open to new ventures. So we're getting a lot of things coming to us at the moment. So we don't actually have to go out there and search. So we're able to sort of sit back and consider.
What we're also seeing a lot of new ventures coming across as the larger companies are sort of scrambling for the exit doors as a result of ESG. We're seeing some really interesting opportunities becoming available. Typically, they're brownfield opportunities. And in an ideal world, we'd like to exploit the differences between effective date and settlement so that you can effectively acquire these assets with little or no cash outlay, I guess, much as we've seen with Jade Stone and Murray. So yes, we are focusing on the existing assets very much so, but we are retaining optionality for growth possibilities.
And if we can get something for really good value, that's better than the alternatives, absolutely, we will consider that. So that concludes my answer. Thank you.
Great. Thanks for that, Chris. The next question we have is on a nominal basis, we have a pretty strong result on the cost front. Presumably part of that is natural field decline, but it looks like we've also been able to bring down costs on top of that. The person who's asked this question was wondering how sustainable do we think that is going forward and how the China development might impact that?
I can probably take that one. Look, as I sort of alluded to, we obviously got sub $20 per barrel operating cost at the moment, and our current forecast show that, that will be sustained at least through FY 2022. We think it's we see it as being quite sustainable to retain those levels. Yes, we have some natural field decline, but at Maori, that's fairly modest given the benefits of water injection. And at Beibu, with the continued investment in infill drilling and with the 1280 East development coming on, that will certainly help us to keep a lid on cost.
The 1280 East development, obviously, it adds significant new production. It has a different cost structure, but given the incremental volumes coming on, it will enable us to keep those per barrel operating costs consistently low.
Great. Thank you, Richard. I think this question is also for you. Are there any immediate plans to further reduce the head
cuts have been made very recently with some recent redundancies and resignations. With the headcount now down to 12%, we see that as an appropriate level for the stage of where the business is at. We need to manage our operators. It's important to recognize with OMV essentially looking to exit and Jade Stone still some time away from coming in. We're essentially doing a lot of technical work at Maori.
And similarly at Beibu, it's we've got a significant development, which is underway, and we need to keep a solid eye on both Sea Nook and Rock managing what is a significant investment for the company. But obviously, we will continue to assess our cost structure and resourcing levels and adjust as we see fit.
Great. Thanks, Rich. The next question we have is for you, Chris. What actions are management undertaking or have planned to attract new investors to drive the share price higher?
Look, it's been quite a sort of tumultuous year with the oil price going up and down. We've been locked away for much of that year. I wasn't even able to get to APA this year, so I haven't even sort of engaged with people physically. Normally, in a normal sequence of events, we'd be going to conferences, we'd be speaking to investors more directly. That doesn't excuse us.
I think we haven't given an updated presentation for a while. We need to do that. We need to engage, I think, again with shareholders now that we've given the capital return. We're going to take a deep breath, really sort of quantify our strategy and communicate. And so I think in answer to that question then, we will be refreshing our corporate presentation, communicating more with the shareholders and probably instigating a roadshow or 2 to try and drive that share price higher and get the story out to more investors.
Great. Thanks for that, Chris. Richard, the next question is for you. Jason's presentation indicates that they are very hopeful, if not confident, they can double current 2P reserves and extend Mario life until 2,000 and 38, rather than the end of this decade. What is Horizon's view on this?
Look, we share a lot of similarities with Jade Stone's view. Our reserves position, resources position for Mario is quite similar. Currently, we hold 2P reserves out to the end of 2027, which is the end of the current license. There is capacity within New Zealand to extend the license. And you'll see in our reserves report, we hold significant 2C contingent resources at Maori, most of which is to do with extending the life beyond 2027.
But we obviously we can't book them today until we've essentially got the right to extend. New Zealand is no surprise. New Zealand obviously has a lot of climate change activism and focus. And so we can't just take it for granted that we'll be able to extend the life of the field. But certainly, that's one of our key focuses.
Thanks for that, Rich. The next question is, if a 12 days Phase 2 and beyond are warranted based on Phase 1 performance, would HZM be entitled to production beyond the current 2029?
Yes. Look, I can take that as well. Chris sort of alluded to it earlier. The current sort of drop dead date on the petroleum contract. But if we showed significant investment being done, which required production to go out beyond the end of the permit, there is some capacity within the current contractual framework to allow us to extend.
But as Chris mentioned and I'd sort of confirm, we need to be demonstrating there's a significant investment to be had that would warrant that extension.
Right. Thank you for that. The next one we have, I think this one's for you again, Rich. So you have stated the expected average production in year 1 from Torbayt East is 4,000 barrels of oil per day. Can you give an indication of the likely initial production rate and rate of decline?
Look, I can just make a comment on that. We have provided an average there. The nature of this 12.8 Eastfield is that the oil is really quite viscous and each of these horizontal wells will come on individually very high rates for a short period of time and decline quite quickly. And the initial rate will depend on the timing of each of these wells as they come on. So it's from an instantaneous point of view, you could probably get a rate which is significantly higher than that, but it will come off that rate very, very quickly.
So the most sort of best way of describing it is just to give this average. So very difficult to give an initial production rate, very difficult to give a rate of decline. All we're really comfortable doing is saying this is going to be the average over the year. And it's really a function of the nature of the oil, the nature of this and the nature of this field. Great.
Thanks for that, Chris.
The next question we have is, can we provide some commentary on any inorganic opportunities we are looking at? And what does the M and A pipeline look like if there are many fore sellers out there due to ESG?
Gosh, there are forced sellers, they're not many. The opportunities are all very different. The ones we've seen are in some of them, ones that we've seen are in Southeast Asia. They're actually some of them look very attractive, some of them look quite messy and probably they're messy because the majors don't want to get involved, for example, in abandonment. However, the carrot might be significant production before abandonment is due.
So we're starting to see those. As I said, they all look very, very different. It's hard to sort of generalize on them. The M and A pipeline, look, there are some companies out there. We are potentially quite attractive because we have quite strong medium term cash flow.
And there are some companies out there with assets, which have been discovered and which require capital and over the next couple of years. So there are possibilities there. But we haven't looked particularly seriously at that. I think now having given the capital return, we're just very much focused on regrouping, maximizing the value, building cash and then maximizing our optionality as a result of that.
Great. Thanks for that, Chris.
I can just say, as there's another question following up, do we have any dividend plan? No, we don't have any dividend plans at the moment. As I've said, we're just very much focused on maximizing production from the existing assets. And that's going to take us through for another at least in the 6 months, probably 9 months. At that point, we'll assess our options.
Great. Thank you, Chris. The next question we have is, can we give a guesstimate production rate into future years? And how many years can production be maintained in the 1,300,000 to 1,400,000 barrels of oil per day? Well, I think I should say 1,000 barrels of oil per day.
We haven't really put out any guidance around production at this stage. But we did sort of mention some targets in one of our presentations last year where we certainly were reasonably comfortable in targeting production levels in that range over the next 2 to 3 years. A lot of that just depends on our capacity to mature infill well infill drilling targets, particularly at Beibu to continue the flat production that we've been able to manage in prior years. But certainly, 12 ADs first phase will obviously keep production rates at least at those sort of levels. And the extent to which we can bring in subsequent phases and other infill drilling will help to determine whether we can sustain it, but that's certainly our objective.
Great. Thanks, Richard. I guess, Chris, this next question is for you. Is the company able to confirm a continuing cash return policy either by dividend or capital going forward given the anticipated strong cash generation?
Probably a keyword there is a continuing cash return policy. Look, in the short term, the performance of 12 Ad East is going to be critical. The other thing we have to bear in mind is with respect to Maori and given the pending legislation from New Zealand, we may need to start accumulating cash in anticipation of Amari abandonment. We'd love to be able to have a continuing cash return policy, but at the moment, it's too early to be definitive. I'd like to be able to address that question in 6 months' time when we've got through this sort of 6 to 8 months period.
Great. Thanks for that, Chris. Next question we have is from a shareholder value maximization standpoint, does the Board see any merit in operating the company in runoff mode?
Runoff mode is an option. I think it's probably an extreme option. At the moment, we're exploiting full optionality. We've got as I said, we've got we're maximizing the value from existing assets. We're being opportunistic if something really good comes along.
I think that would be the ideal outcome. If we don't achieve that, if we don't achieve anything, any new assets and then the alternative is very much so, yes, we'd have to operate the company in runoff mode. I would caution again, we have to be mindful that if we are going to go into runoff mode, we would need to accumulate significant cash in anticipation of Amari abandonment. So it may not be as attractive in reality as it might appear on paper. So it is an option, but it's probably not a preferred option at this stage.
Great. Thanks for that, Chris. Richard, I believe this one will be for you. What is the operating cost range at 12.8 East?
Yes. Look, as I mentioned, it is linked to oil price. So there's a fixed cost base for maintenance and running the platform and so on. And then there's really sort of a variable cost, which is linked to the price of oil for the lease cost for the platform. It's quite hard to sort of put the numbers to it because it's on a cost per barrel basis, it's very much dependent on production.
And as Chris alluded to, the field comes on very strong. And so you'll see operating costs initially well below $10 a barrel cash costs well below $10 a barrel when it first comes on. And as the production comes off, then they'll clearly climb. And then it gets into the $20 odd a barrel mark by sort of E2 and 3 of the field. But we'll try to provide a bit more clarity on that in future announcements as we move towards first oil.
Great. Thanks for that, Rich. The next question we have is, are the potential brownfields such referred to in the Southeast Asian region where Horizon Oil operates?
They're not in China. We've seen opportunities in New Zealand, but primarily we've seen them in Malaysia and Thailand and also Indonesia.
Great. Thanks for that, Chris. Next question we have, are there any inflection points over the coming years where the rate of natural production decline would accelerate?
I think I can just comment on that. I think the natural decline will accelerate when we're no longer investing. Obviously, each opportunity to invest, we're sort of countering natural decline here. Each sort of infill drilling, each infill drill location is likely to get smaller and smaller as we go through time. It probably isn't an inflection point, but it does get harder and harder to maintain the rates that we've been achieving in the past.
Great. Thanks for that, Chris. Just waiting to see if any further questions are coming up. I think that's pretty much it on the questions at the moment. So I think that sort of concludes the webcast.
So thank you all for joining for today. If you have any further questions, please send them through and we can address them privately. Thank you, Chris and Richard, and I'd like to pass you back to the operator now.
Thank you. That does conclude our conference for today. Thank you for participating. You may now disconnect.