Horizon Oil Limited

Well good morning everyone and thanks for joining. With me is Horizon CFO Kyle Keane. I'll first make some introductory comments covering the half year ended 31 December 22 before handing over to Kyle to run through the half year results in some more detail. I'll then cover the operational performance highlighting the upcoming activity for what is again shaping up to be a very busy few months and conclude with some guidance for FY23 and then we can open up for some questions. Looking to the compliance statement, look, during the course of this presentation, we will be making some forward-looking statements. And whilst we take every care in the preparation of these statements, actual results may materially differ depending on a variety of factors. So I'd encourage you all to read the disclaimer in full. Look, before I get into the numbers, please note that all references to US dollars unless otherwise stated, with the exception of any references to dividends and distributions tends to be in Australian dollars. Well, what an incredible half year it has been. We're delighted to have seen another period of record-breaking results for the company, primarily due to the tremendous drilling and production success we've had at our Block 2212 fields in China. Our team have worked tremendously hard with the Block 2212 joint venture, to help reach an all-time high production rate of over 20,000 barrels of oil per day gross during the half year, which represented an almost doubling of production rates from the asset against the long-term average. It was this production success, combined with stronger oil prices, which drove the outperformance of the key metrics shown on this slide, with over 800,000 barrels of oil sold during the period, 50% higher than the comparative half year. When combined with the almost 30% higher realized oil price, this success translated into 142% increase in statutory profit for the half year to $19 million. EBITDAX was 87% higher at $52.2 million, and revenues were over 93% higher at $75.7 million. Importantly, the continued strong free cash flow generation has enabled us to declare an interim dividend, our first, of 1.5 Australian cents per share, totalling roughly about 24 million Australian dollars, which builds on the 3 cents per share of distributions paid during the half year. Following the payment of roughly 48 million Australian dollars in distributions during the half year, We still ended the half year with a very healthy net cash position of just under 25 million US dollars, providing the liquidity to continue paying significant distributions. The half year results have been a testament to the success and focus on our strategy. We have continued to focus on maximizing free cash flow generation, which is mentioned as being driven by the production success from our Block 2212 asset in China. The 128 East development has been transformative in turbocharging production rates from block 2212, but has also been materially aided by infill drilling and workovers in the legacy Weizhao 612 fields. Oil prices have also clearly had a significant positive impact on cash flows, with an average realized oil price for the half year of just under US$95 a barrel, which was aided by some favorable hedge settlements. Pleasingly, and notwithstanding a period of significant inflationary pressures, cash operating costs continued to be maintained below US$20 a barrel. The strong cash flow has allowed us to continue to prioritise distributions to shareholders, with the 1.5 cent per share interim dividend following closely behind the 3 cents per share in distributions paid in October last year. The interim dividend represents over a 10% yield based on the share price at the end of the half year, with the quantum determined to balance shareholder returns, future commitments and maintenance of the group's liquidity levels. Prioritising such returns to shareholders is a key pillar of our strategy. Our ability to make such substantial returns is due in part to the strong cash flow generation from our low cost production assets, but also due to the investment in production growth within our portfolio, with exceptional returns and rapid payback periods. The 128 East development is a shining example of such an investment, with the roughly US$30 million invested in phases one and two of the development, on track for full payback within 12 months of first production. The Weizsau 612 infill wells and workovers offer an even more rapid payback, typically inside of six months and with substantial rates of return. Our pipeline of infill well opportunities in block 2212 is substantial, and the recent 12.8 East reserves upgrade highlights the remaining opportunities within the asset, which I will talk more on later. MARI also has some incremental value, high value opportunities with the most accretive project likely to be through life extension, which is a core focus of the venture now that OMV are retaining operatorship going forward. Whilst not our primary focus, we also continue to keep an eye out for exceptional new business opportunities which might complement the existing asset portfolio with a view to enhancing shareholder returns. I've already touched on some of the half-year highlights already. However, some additional key achievements were as follows. The combined daily production rate from Horizon's share of both Block 2212 and MARI averaged over 5,000 barrels of oil per day during the half year, an increase of over 35% from the average achieved during the 2022 financial year. Operationally, I've already mentioned the successful completion of the 1280s project. Impressively, the joint venture were able to interpret early production results from the project in the middle of the 2022 calendar year and fast-tracked the drilling of the four Phase 2 wells in only a matter of a few months. This is a testament to the strong collaboration in the joint venture and the quality and focus of our operators. On ESG, despite the elevated activity levels, we have continued to uphold a strong safety record significantly better than industry benchmarks. Specifically on climate change, We recently made a modest investment of just over a million US dollars of seed capital in a carbon removal credit developer called Novrac Limited to aid with the group's longer term decarbonisation ambitions and to act as a natural hedge against the growing carbon emission costs incurred at Māori under the New Zealand Emission Trading Scheme. Importantly, the investment presents an opportunity to deliver an additional cash flow stream and provide further value for shareholders. I will now pass over to Kyle to run through the financial results in more detail.

Thanks, Richard. Before I go through the results, I would like to emphasize that all references to dollars are to United States dollars, as this is the group's functional currency, since all revenues are generated and received in United States dollars. The table on the right of this slide summarizes the half year 23 results with a comparison against the prior half year. As Richard has mentioned, the half year results were strong, with significant increases in all key metrics owing to both production growth and a higher average realized oil price during the half year. Production volumes increased 40% as a result of the successful execution of both phase one and phase two of the 12 at East development, as well as two info wells and a multi-well work over program in the 612 fields in block 2212. Revenue increased 93% despite the deferral of a scheduled Maori lifting to January 2023. The higher revenue was of course driven by the 40% increase in production and a 30% increase in realized oil prices to just under $95 a barrel. The increased revenue, combined with the maintenance of cash operating costs below $20 a barrel, drove a surge in EBITDAX to $52 million. This cash flow helped to rebuild the company's cash position to just over $40 million at period end. This is following the substantial 3 cents in distributions paid to shareholders during the period, which resulted in a cash outflow of $30 million. Pleasingly, we exited the period with a strong balance sheet with net cash just under $25 million. Dissecting cash flow. In this next slide, we can see that the strong net cash inflows of approximately $25.7 million largely helped to rebuild the cash position, following the $30 million in distributions paid Funds drawn from the group's senior debt facility largely offset CAPEX costs associated with the 12 release development and infill while Zoom 612. With a closing cash balance in excess of $40 million, the group has the necessary funds to cover the remaining 12 release development costs and other near-term capital commitments of approximately $15 million, meet near-term debt repayments, setting aside funds from R&D commissioning, maintaining an appropriate working capital balance and paying interim distribution of 1.5 Australian cents per share. To help dissect the half-year result further, the next chart shows the key elements which have driven the substantial increase in statutory profit to $19 million and clearly shows in the yellow bars the significant impact of the production growth from block 2012 and a 30% higher realized oil price. partially offset by the deferral of the MARI lifting to early January 2023. Despite cost pressures and a high inflationary environment, all controllable costs were largely maintained during the financial period, with the increase in operating costs driven by a higher non-cash amortization charge and, as expected, incremental operating costs associated with the 12 release development commencing production, noting that cash operating costs were still maintained below $20 a barrel produced. The higher realized oil price drove substantial increases in revenues and profitability, which notably increased royalties and levies during the half year. Turning over to the next slide, we can take a look at the full year calendar results against the previous four years. As in previous presentations, we have included some detail of the impact of the BEVU cost recovery revenue in earlier years. This assists with normalizing the results. As mentioned previously, this was additional revenue earned in earlier years which reimbursed the company for historical exploration expenditure in China and was largely recouped at the end of the 2019 financial year. The first of these slides highlights the growth in both production and sales, despite sales volumes being impacted by the deferral of Amari Lifting to Jan 2023 of approximately 125,000 barrels net-to-horizon. As mentioned, production levels increased owing to the successful execution of both phase one and phase two of the 12B development. as well as two infill walls and a multi-wall workover program in the 612 fields in Block 2212. The ability of the Block 2212 joint venture to sustain consistent production levels through infill drilling and other initiatives and to continue to maintain low operating costs has been the predominant driver of Verizon's cash flow over recent years and provided the confidence to further invest in infill drilling, workovers and the 1280s development, which has paid dividends this half year. MORI production is also a significant contributor, particularly over the past five years owing to the successful acquisition of a further 16% interest in the Maury Manai fields during 2018. The revenue chart shows the contribution to revenue of the Bebu cost recovery sales in earlier years. Once we strip this away, we can see the significant impact of the 50% higher realized oil price during the calendar year. Pleasingly, oil prices continue to trade above $80 a barrel, which notably bodes well for revenue and cash flow generation. The next slide again shows the relative impact of higher production and oil prices on the group's profitability in the 2022 calendar year, with an 82% increase in EBITDAX and a dramatic increase in the statutory profit from $11.1 million to $35.5 million. The strong EBITDAX and profit results were further aided by the group's continued low cash operating costs, maintained below $20 a barrel produced, and the maintenance of low general and administrative costs, despite inflationary pressures. The next slide shows the continued strong free cash flow generation, with the orange line in the chart on the left, normalized to exclude cost recovery cash flows in earlier years. This again shows the impact of higher production and oil price in free cash flow generation. noting that the operating cash flows exclude the Block 2212 November sales of approximately $10 million, which was received in cash in early January 2023. If we normalize for this receipt, calendar year 2022 free cash flow generation exceeded the past five calendar years. As previously mentioned, the company is highly leveraged to the oil price and generates approximately $5 a barrel in additional free cash flow for every $10 a barrel increase in the oil price. Now I have saved the best chart to last with a net cash net debt chart in 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 $64 million at the end of the 2018 calendar year to a strong net cash position of $24.8 million in only four years. And this is after cumulative distributions of just under $65 million has been paid. That represents free cash flow generation over a four-year period of approximately $150 million or $220 million Australian, notwithstanding the depressed oil price environment during the 2020 calendar year. Our focus is to continue to drive this free cash flow generation out in the future by extracting maximum value from our assets. The resilience of the cash flow, higher oil prices and a strong production result provided the confidence to declare Horizon's first income distribution and continue to return significant value to our shareholders. I will now pass over to Richard to provide an update on our asset portfolio and an outlook for the company.

Thanks, Kyle. I'll now provide an update regarding our producing assets, starting with the Group's flagship asset, Block 2212 in China. This has clearly been a standout year for the asset, with the recent addition of the 12-8 East field development, indicated in the bottom right green rectangle in the graphic, providing a third production hub. The half year was a period of significant activity, which commenced with a two-well Weijiao 6-12 drilling program, followed by a four-well Weijiao 12-8 East Phase 2 drilling program. As I mentioned earlier, record Block 22-12 production was achieved during the half year, with daily oil rates reaching peak production of over 20,000 barrels of oil per day gross in December, representing an approximate doubling of production rates since early 2022. The additional production and cash flow generation during the period means that the asset now represents approximately 80% of Horizon's cash flow, aided by the very low cash operating costs, which were less than US$12 a barrel produced during the half year. Whilst we expect production rates to naturally decline as water production from the fields increases, our objective is to continue to develop the material pipeline of infill drilling opportunities to sustain oil rates well above the Block 2212 long-term average of around 10,000 barrels of oil per day. Turning to the next slide, we've included some technical detail to help investors understand both the drilling results and the remaining potential in the 1280s development. Starting with the main Xiaowei reservoir, which as can be seen in the map on the left and the cross sections on the right, is an oil field with a large aerial extent, excellent reservoir characteristics, and a relatively thin oil column containing high viscosity oil. Accordingly, oil production from this field is characterized by high initial oil rates with relatively rapid decline due to rapid water production. Maximising oil recovery from reservoirs with these characteristics requires numerous well penetrations with long horizontal reservoir intersections drilled as close to the top of the reservoir as possible. The first phase of the development drilling concentrated in the western side of the field, wells A2H to A6H. Importantly, as we drilled out towards the east with wells A5H and 6H, The top of the reservoir was seen to be shallower and hence the oil column thicker. These results provided significant encouragement to accelerate the Phase 2 drilling campaign with a further three Xiaowei wells, A8H to A10H. The cross sections highlights the modelled initial and current oil saturations and the coning effect as the wells are produced and water production rapidly increases. Encouragingly, the initial production results suggest potential for a number of additional wells in the field, including wells potentially between the existing producers. The most mature of these is the A12 well, which is indicated on the eastern flank of the lower cross section and is progressing towards a potential drilling date in the second half of 2023, with a larger third phase of development possible in the next few years. This slide shows cross-sections of the Weizhao and 1210 single-well reservoirs, which are produced from the A1H and A11H wells, which bookend the 1280s drilling campaign. You can see that these reservoirs have more structural and reservoir complexity than the Xiaowei reservoir, and whilst they both presented some drilling challenges, have both resulted in good production wells. Importantly, the Weizhao reservoir has very different properties to the Xiaowei. such as the oil decline rates are more gradual and water cut development more modest. Both Weizhao and 1210 reservoirs may present future drilling opportunities. Set out here is a summary of our recent 1280s reserves upgrade, following a detailed and ongoing review of production data from the 10 1280s production wells, together with the corresponding subsurface data obtained during the drilling of those wells. The company has increased its 2P developed oil recovery before subtracting production by over 150% from just under 500,000 barrels net to horizon to 1.24 million barrels, which is an increase of 750,000 barrels. 360,000 barrels of the increase related to revisions to previous estimates associated with the initial phase one reserves. with 390,000 barrels related to reserves booked for the Phase 2 wells. Production for the six months was 320,000 barrels net to Horizon, resulting in remaining 2p developed reserves of 31 December of 910,000 barrels, almost double what was originally booked. What is most encouraging from this reserves upgrade is the production and subsurface data highlights the remaining potential in the 1280s fields. On average, each well drilled as part of the program has added approximately half a million barrels gross of recoverable reserves. As I mentioned earlier, we see the potential of drilling a number of additional wells across the 1280s fields, particularly in the Xiaowei Reservoir. Pleasingly, the incremental capital costs of such an expansion is limited mainly to drilling costs, which have historically been around $2.5 million per well, net to horizon, and some equipment processing upgrades. Which brings me on to our next slide, setting out the production history from Block 2212 and our recently updated view of its future. We've shown this chart a few times in recent presentations, and there are some key changes in the chart which I want to highlight. As a reminder, our current 2p reserves forecast is shown in the dark green, which has been updated to reflect the recent 12.8 East reserves upgrade. This has had the effect of increasing the production peak, bulking up and lifting the 2p forecast curve. As mentioned previously, production rates from block 2212 are expected to naturally decline. The light blue sawtooth profile is the additional production potential and value to be unlocked from future activities. You will note that we have added additional indicative production increases in the chart, which aim to represent additional potential infill well opportunities, which have matured largely as a result of the reserves upgrade at 12 8 East. I would emphasize that all of the indicative future activities remain subject to further technical and economic valuation and subject to JV or joint venture and regulatory approvals. What is most apparent from this chart is that the legacy of maintaining around a 10,000 barrel of oil per day average production rate from the block has now materially changed with the prospect of sustaining significantly higher average rates over at least the next three years. As previously stated, the indicative cost of unlocking the blue area shaded in this chart is in the order of 10 to 15 million US dollars net to Horizon per annum for the next three to five years. We've also extended the chart until the end of the petroleum contract in 2030. As well, the legacy Weijiao 612 and 12A Westfields are contractually due to be handed over to Seahook in August 2028. The 12 8 East field can run through to the end of the petroleum contract in 2030 and possibly beyond by agreement. The prospect of extending production out until at least the end of the petroleum contract has again been enhanced by the recent 12 8 East production results and reserves upgrade. Turning now to New Zealand and Māori, where we have seen continued stable reservoir performance. Importantly, sustained water injection into the main Māori Moki reservoir has continued to maintain rates in this reservoir, such that we expect production rates to be largely sustained without the need for significant capex spend. Operating costs are still modest in the context of the current oil price, but were impacted by the shutting of some wells for work overs to mainly replace broken pumps. Cash flow from Māori has been enhanced over the past six months, from record premiums being received on oil sales into the east coast of Australia, with the recent January lifting again being sold at historically high levels. The immediate focus at MAR is on low-cost, high-value well workovers on three wells, including water injection optimisation work on the MR2A well. These activities are expected to increase overall production rates by around 1,000 barrels of oil per day gross. With the termination of the proposed divestment by OMV of their stake in the MARI field, we are continuing to work with OMV to plan out how to extract maximum value from the asset. To this end, we are actively engaged in examining the potential for life extension beyond the current permit expiry in 2027, and are also conducting updated decommissioning studies, which have led to a revision to our decommissioning estimate in the half-year accounts. The chart on this slide reflects our current MARI forecast in the dark green, which, as you can see, is expected to exhibit a more modest decline when compared to that of Block 2212. Whilst we've included indicative future activities in light blue, these would likely require a significant capex expenditure commitment and permit extension to be commercially viable. such that most of our current efforts are focused on lower cost production optimisation works and work over activity with the objective of maintaining current production rates. We see significant value in simply extending the permit by up to five years to maximise value from the current well stock, i.e. well that is sort of unlocking that dark blue profile you can see on the slide. As I mentioned, the immediate focus is on workovers to reinstate production from the currently shut-in wells, as well as to enhance rates through the conversion of a third well to a permanent water injection. This table sets out the timing of operational activity over the period until early 2024. Please note that the timetable is indicative, and most of the activities remain subject to further technical and economic evaluation. joint venture and regulatory approvals. In total, we have between two and five infill wells in Block 2212 which are being matured, with the possibility of some or all of these being drilled towards the end of the calendar year. Upgrades to water handling capacity of Block 2212 is also being prioritised, particularly for the 128 East project, as the more water we can manage, the higher the production rates we can sustain. Further infowell opportunities in a possible 1280 Space III drilling program is also being considered, with the possibility of drilling these in future years. As mentioned at MARI, we have two immediate workover priorities, which are aimed at reinstating production from the currently shut-in Manaya 1 and MR6A wells. This is in addition to the permanent conversion of the MR2A well to a water injector, which should aid in sustaining production levels from the main Māori Moki reservoir. Other activity at Māori is focused on life extension with a venture evaluating options to extend the licence beyond 2027, progressing decommissioning studies and examining other value accretive opportunities. In looking forward and keeping with the key elements of our strategy, we plan to capitalise on our recent production growth. to maximise free cash flow generation and shareholder returns. To ensure these can be sustained, we will continue to invest in further production growth within our existing assets whilst also looking out for new business opportunities. Turning now to guidance. We're anticipating a strong end to the financial year, driven by the higher production levels out of Block 2212 and aided by a sustained higher oil price. We therefore have production guidance net to horizon of 1.85 to 1.95 million barrels, which would be a record for the company. Sales we expect to also be in the range 1.85 to 1.95 million barrels, similar to our production volume due to the forecast timing of MARI liftings. And if oil prices are maintained at around current levels, $80 to $85 a barrel, we anticipate $155 to $165 million of revenue. And finally, our EBITDAX estimate is $105 to $115 million, following continued focus on cost minimization and other initiatives to maximize earnings. If we don't provide any guidance on distributions at this time, Needless to say that having just declared an interim dividend, this element of our strategy is clearly a priority for the board and we are continually reviewing our capital management options. But due to the continued focus on investing in production growth, high levels of operational activity combined with timing uncertainties will be in a much better position to quantify the extent of any final dividend with the release of the full year results in August. And with that, Kyle and I will be very pleased to answer any questions you may have.

So we'll just pause for a moment just to see the questions as they come in.

So our first question we have here is for you, Kyle. I've noticed that your FY23 sales volume guidance mirrors your production guidance. Typically, your sales will be a little lower due to the fiscal terms in China. Considering there was no Māori lifting made in the December quarter, how are you expecting to make this up? Is it safe to assume an additional lifting will occur in Māori in either the March or June quarter?

Thanks. Look, it's a good question. As Richard's mentioned in his guidance slide, it purely comes down to the timing of Māori liftings. But that's expecting to end the financial year with lower inventory volumes in Māori than what did when we commenced the financial year. I just will point out that there was no MORI lifting in the December quarter, and as I've mentioned in my speech, it was deferred through to January 2023.

Thanks, Kyle. The next question we have is regarding the pre-interest rate of MORI, as mentioned in the slide back and in the previous quarterly results. What is driving this pre-interest rate is a demand from East Coast Refinery. And if so, do you expect this to continue over the near term, given the elevated refining margins and stronger February results from our East Coast refiners?

Yeah, I can tell you that. It's not necessarily that sort of easy, but certainly some of the earlier strong premiums were driven by essentially the freight cost going through the roof. around the world. So, you know, being able to sell into East Coast Australia, Murray, is it a bit of a competitive advantage given its short freight haulage distance to the East Coast? That coupled with, you know, we certainly got the sense that the East Coast refineries were sort of caught a little bit short with the rapid increase in demand as we've sort of come out of COVID and hence they were really trying to get their hands on whatever oil they could get. More recently, it's also got a little bit to do with the diesel shortages we're seeing around the world, really, and Mari crude being a very good quality and a low API, light sweet crude, it's quite attractive in the market, hence the premiums. Do we expect it will continue? Oh, look, I think longer term we'll see a more normalisation, but certainly if these sort of diesel shortages continue, I'd like to expect we get some higher premiums in the near term.

Thanks, Richard. The next question we have is how does the hedging work for both oil price and currency for the company?

I'll take that one. Look, as I mentioned, we have sufficient cash reserves to cover all current commitments. such that the need to layer in significant volumes of oil price hedging as a risk management tool is somewhat diminished. And having said that, we will constantly evaluate our hedging position. But also noting at the moment, most industry sources suggest that there's more upside potential in the oil price than there is downside risk. From a currency perspective, we do hedge currencies, mostly our Australian dollar for our local general and administrative expenditure. and the New Zealand dollar for our cash calls for operating costs in New Zealand.

Thanks, Kyle. Next question we have is, do you see any sovereign risk issues from your China-based assets?

Look, I think we've had that sort of question a few times in the past. I mean, we're kind of unique in that we're essentially an Australian company that's almost a domestic producer in China. We're partnered very well with, in the joint venture, with Sea York and Rock Oil, the Fosun group in the main. We haven't experienced any issues, notwithstanding some of the geopolitical pressures and rhetoric between Australia and China. As I said, we're more viewed as a domestic producer, and I think you can take a lot from the ability and the cooperation of the joint venture to be able to turn around that phase two development in or drilling campaign in 12 8 East in such short order to sort of demonstrate the cooperation between ourselves and our Chinese partners.

Thanks for that Richard. I think that's the end of the questions. We might give 30 seconds if there's any last ones before we paint you back. We haven't received any more questions. If you do have any further questions, please feel free to email them through to info at horizonoil.com.au and we'll be happy to answer any questions you may have. With that, I'd like to hand you back over to the operator.