Beach Energy Limited

Hello and welcome everyone to the Beach Energy half-year results presentation. My name is Morne Engelbrecht and I'm the Acting Chief Executive Officer of Beach. Putting me in the call today is our Acting Chief Financial Officer, Anne-Marie Barbaro, also joined by some of the Beach Executive team. For today's presentation, I will first provide an overview of the current state of play at Beach Energy. Then I'll be over to Anne-Marie, who will run through the financials, Then I'll provide an update across our portfolio of assets. Following that, we will open the lines for Q&A. Before I begin, slide two includes our disclaimer as well as information regarding our reserves disclosure. I will leave this with you to read in your own time. Let's move on to the main part of today's presentation. The first half in FY22 was one that not only delivered against our growth agenda, but also saw the continued execution of our strategy. This recorded production of 11 million barrels of oil equivalent in the first half. While this was down 20% on the corresponding first half last year, it is important to note that we now have some of the key building blocks in place to start realising incremental production volumes over the next year. The Oslo gas plant is now in a position to deliver increased production thanks to the commencement of the Geograph 4 and 5 wells. Further to this, CUPE is again running at its full 77 terajoules a day capacity following the commission of the inlet compressor. On the financial results, our statutory impact for the first half was $213 million, a 66% increase on the corresponding half in FY21. Again at the half in a net cash position of $74 million with a $600 million revolving facility providing us with strong levels of liquidity. We also made excellent progress towards our base, 28 million barrels of oil equivalent production target, FY24, with the start-up of Coupe, the continued drilling of wells in the offshore Otway, and the signing of the LNG Heads of Agreement with BP for white seal volumes. Given the strong progress we have made towards our base production target, we are now starting to look at the projects that could enable Beech to deliver above that target. This includes planning an exploration campaign in the Perth Basin, building a better understanding of the nearshore and offshore potential in the Otway Basin, investigating near yellow north and west exploration opportunities in the Bass Basin to complement the potential trefoil development, and planning for a Kupai East development well in the Ternaki Basin to further extend the production plateau for Kupai. Flight 4 speaks for itself. but it's an excellent illustration of the strong financials we enjoy at Beach. Our sales revenue increased 11% to $786 million and a half. This leads to an EBITDA figure of $513 million and a 65% EBITDA to revenue margin. I think a key point to highlight is the fact that 37% of our revenues came from fixed CPI-linked gas production. The board has also maintained a fully frank interim dividend of $0.01 per share. Moving to slide five, and you can see Beech continues to record strong safety performance, notwithstanding the fact that we are on a period of high activity. We have now recorded more than 5 million work hours without a lost time injury across the business. The company also recorded another milestone and a half with our Ottawa gas plant, reaching seven years without a recordable injury. However, the first half did see an increase in the total recordable injury frequency rate. While most of these incidents represent relatively minor injuries, we are addressing this through a series of targeted safety campaigns in the second half. Moving to slide six, I just want to quickly give you all a reminder of what we outlined yesterday, September last year. The takeaways from this were a base business production growth target of 28 million barrels of world equivalent, FI24, We funded balance sheet to support this target with only low levels of gearing reached. The delivery of material steady cash flows from eight gas plants across four markets. With this material free cash flow generation providing optionality and our continued commitment to sustainability with our aspiration to be net zero by 2050. I'm proud to say Beecher's first task saw a very strong period of delivery towards these ambitions. We effectively had a checklist of things we needed to achieve in a very active half, and we successfully ticked off every box. As mentioned, we brought the Cooper Inlet Compression Project online in September, which has seen the Cooper gas plant return to its full capacity. In the Victorian Otway Basin, we delivered the first volumes from our Otway Offshore Development Campaign. The Geograph 4 and 5 wells were drilled, connected, and commissioned, with gas now being delivered into the East Coast gas markets. We also commenced the final phase of the offshore drilling program, successfully drilling the thylacine north one well in line with pre-drill expectations. In the west, we commenced construction at weight shear stage two with the project on track and site works are now 42% complete. We also reached an historic milestone by signing a heads-up agreement to a BP for all of each of 3.75 million tonnes of LNG from the project. Finally, we sanctioned the Moonberg carbon caption storage project by joint venture partner and operator, Santos. We did a lot of heavy lifting in the first half. However, some key objectives remain as we look to close out the year. We still have three remaining offshore wells to drill into the thylacine field. Drilling is currently underway at Thylacine West 1, and we are on track to complete drilling campaign around the middle of the calendar year. In the coming months, we will take the final investment decision for the Enterprise Onshore Pipeline project. This is a low-risk project that ties in the 2020 enterprise discovery of the Hathaway gas plant. In the Perth Basin, construction activity will continue at Waitseer Stage 2, with our focus also now including the development drilling campaign. With our operator Mitsui, we intend to drill a minimum of five gas development wells targeting the Kingyear and Highcliffe sandstone formations. Finally, in the coming weeks, we'll recommence our oil exploration program in the western flank with a drilling program of at least 11 wells. It's important to remember that success from any of these wells is not factored into our base production growth target or our guidance, so any discoveries would help deliver upside. On the sustainability front, the key achievement and a half was the sanctioning of the Moomba carbon capture and storage project by JV participant operator Santos. This project forms a key pillar of our aspiration to reach net zero emissions by 2050. It's by far the biggest investment we have made to date to reduce our operational carbon footprint and will deliver the state change and beaches CO2 emissions profile. In our zone test, this month booked 100 million tonnes of CO2 storage resource in the Cooper Basin in South Australia. As you're aware, Beaches' reserves and resources process occurs at 30 June each year. We're currently working through that process and we'll consider the Moomba CCS project together with all our other reserves and resources projects in preparation for the report in August. Slide 9 provides our unchanged FY22 guidance. We have maintained our FY22 guidance range of 21 to 23 million barrels of oil equivalent. Guidance is maintained based on the fact that we are outperforming our annualized decar rate of 35 to 45% in the western flank as development wells come online. We've also connected the geographic wells, albeit production is subject to customer nominations. This is offset by the lower than non-operated production performance in the Cooper Basin JV experienced in the first half. Capital expenditure guidance has also been maintained to be between $900 and $1.1 billion. Our per barrel guidance for unit field operating costs and unit DD&A guidance are also unchanged. With that, I'll hand over to Anne-Marie, who will run through the financial results.

Thanks, Mornay. Good morning, everyone, and thank you again for joining us today. My name is Anne-Marie, and I've been with the company for three years most recently as General Manager of Finance. I was elevated to the role of Acting CFO in November last year. I have the pleasure of speaking to you today to provide an update on a very positive set of financial highlights. Turning to slide 11, and as Morna has already highlighted, each announced a reported net profit after tax of $213 million for the first half of FY22, up 66% on the same half last year. Our EBITDA of $513 million reflects a 26% increase on the corresponding half. Cash from operations jumped 105% to $605 million with stable cash flows from our fixed-price CPI-linked gas business, which alone, excluding associated liquids, delivered approximately 37% of our group revenue. We also announced an interim dividend of $0.01 per share, fully franked. Slide 12 highlights our NPAT in comparison to the first half of FY21. The 11% rise in revenue during the first half was primarily driven by a 75% increase in realised oil price. Reduced tariffs and tolls and depreciation are the result of lower production volumes. This was partially offset by a 40% increase in royalties and third-party purchases driven primarily by increased commodity prices. and a 6% increase in field operating costs following FY21 asset acquisition. Slide 13 highlights our strong cash position with total cash of $213 million at the end of the half. As mentioned earlier, operating cash flow of $605 million was up 105% on the corresponding half. This cash flow included $29 million of income tax paid and a $42 million receipt for settlement of Coupé carbon tax arbitration. Our free cash flow pre-major growth investment was $329 million. Turning to slide 14, and you can see our balance sheet continues to be extremely strong with a net cash position of $73 million at the end of the half. Our total liquidity stands at $673 million, a result of a successful refinancing of our debt facility to $600 million with favourable terms and margins. This means we are well positioned to fund our future growth strategy, including the committed capital towards the offshore Otway drilling and Waitseer Stage 2 developments. This is reinforced by the fact we expect our net gearing to remain below 10% despite a capital-intensive FY22 work program. Before I hand back to Mornay, I'd like to quickly highlight we expect to be a beneficiary of the Federal Government's Economic Recovery Initiative, allowing businesses to immediately deduct eligible capital assets. At this stage, we estimate this will have a 200 to 300 million positive impact on operational cash flows over the next three financial years. This remains unchanged from our estimate discussed at Investor Day in September. This will ensure we're in good shape to pursue growth above our previously stated base production target of 28 MMBOE in FY24. With that, I would like to hand back to Mornay to run through our markets and operating assets.

Thank you Anne-Marie. I'll just quickly run through the current gas market dynamics we are seeing before jumping into our assets portfolio. Slide 16, you will see the beaches geographical diversity and market distribution is across three gas markets. The fourth to be added soon. Australian East Coast gas market, the Australian West Coast gas market, New Zealand domestic market. As I said, soon to be the global LNG markets. There are four incredibly robust markets where gas is desperately needed. The Australian energy market operator continues to see gas shortfalls within the East Coast gas market from as early as next year's winter, while the ACCC believes the shortfall could come this year. On the West Coast, IEMO's latest outlook says there could be a potential domestic supply gap from around 2025. We are already seeing the energy supply tightness forecast between 2022 and 2025 starting to rear its head. No new greenfield LNG supply anticipated until post 2025. Our strategy has long been about delivering gas into the right markets at the right time. We feel our portfolio is perfectly positioned to achieve just that. On slide 17, we start with the Otway Basin, which is undergoing its biggest year of activity out of the development campaign in FY22. As previously mentioned, the first half saw beach-connected Geograph 4 and 5 wells at the Otway gas plant. Both wells are now producing gas to East Coast Gas Market and represent the first new volumes from the offshore development campaign. We also drilled the first of the Phyllocene Wells, Phyllocene North 1. This well was successfully drilled and intersected the reservoir in line with pre-drill expectations. The Ocean Onyx is currently drilling the Thylacine West 1 well before finishing off the campaign in the middle of this year with the Thylacine West 2 and Thylacine North 2 wells. The four Thylacine wells will be connected back to the Otway gas plant in the second half of FY23. From an onshore perspective, we expect to take FID on the Low Risk Enterprise Pipeline project in the coming months as we look to tie that discovery back to the Otway gas plant, also in the latter part of FY23. From an operational perspective, it was an excellent first half at the Ottawa gas plant, and we should operate it at 99.9% reliability. Moving to slide 18, and this is an important slide because it helps explain the intricacies of our gas production and sales from the Ottawa gas plant. It would be understandable to assume that the combination of high reliability plant and the connection of Geograph 4 and 5 see daily production set between 160 to 180 terajoules per day. However, this is not necessarily the case. It's dependent on customer nominations. Current CPI-linked take-or-pay gas sales agreements have considerable flexibility for the customers to nominate. This means there will be daily production volatility. When looking through beach off-way gas plant production, it's important to remember that it isn't a reflection of beaches' well capacity or plant reliability. but more so the daily nomination arrangements, which are lastly set by the customer. Nonetheless, because of the take-a-pay arrangements, the annual volumes going through the plant will be balanced by the end of each calendar year. It's important to remember Beech has the right to market volumes for Lavella and new discoveries, including Enterprise and Artisan, independently of the existing gas sales agreements and their nomination rules. This process is currently underway for our Enterprise volumes, which we are targeting to tie in to enable additional optionality and increase the utilization of the off-way gas plant. As you can see from the chart, beach will reach the 205 terajoules a day capacity at the off-way gas plant once the thylacine wells are connected. However, based on the GSAs, there will be periods where the plant isn't at full utilization. On slide 19, we turn to the Perth Basin, which is the second of our major growth basins. Similar to the Otway Basin, the Perth Basin saw a height of activity in the first half of FY22. Construction commenced at Waitseer Stage 2 gas plant as of 31 December, construction was 42% complete. The first half also saw Beach sign its first ever LNG Hedgehog Agreement with BP, which is 3.75 million tonnes from Waitseer Stage 2. Waitseer JV has also secured Eastern Well rig to drill the upcoming Perth Basin development drilling campaign. Also of note was the fact that the Bahara Springs facility returned to near full capacity in mid-November, following the successful rectification of the CO2 membrane issues. In the coming weeks, drilling will commence at the first of minimum five gas development wells of Wadesia, targeting the Kenya and Haikou Sansa informations. This development drilling program is scheduled to span 12 months, from Q1 2022 to Q1 2023. At Waitress Stage 2, development of off-site fabrication will continue, while the site construction will progress in earnest as we look to have the plant online in the second half of 2023. Given the potential for domestic gas shortages in the Western Australian market in the near to medium term, this will progress further development and exploration drilling opportunities surrounding acreage with a view of leveraging the recently secured rig. Moving to Slide 20, when we turn our attention to the Western flank, The first half saw us arrest some of the production declines in our oil acreage. In addition, we drilled four horizontal oil development wells with a 100% success rate, with a fifth well drilling ahead. On the exploration front, we experienced a 33% success rate from our gas drilling program in Expel 106, with successes at Rose Bay 1 and Lowry South 1. However, the media action happens in the second half as we'll soon commence the oil exploration campaign. We'll drill three appraisal wells in the Expel 104 martlet oil field before kicking off the oil exploration campaign with 11 oil exploration wells with additional wells planned after an assessment of the results. Important to reiterate, this has factored in no exploration success in the Western Flank as part of the base business production target. Any success would deliver additional production. I look forward to updating you on the results of that campaign in due course. On the Cooper Basin and looking at the Cooper Basin JV on slide 21, our strategy remains to pursue high-value, low-risk opportunities. To that end, beach participated in 32 wells, an overall success rate of 88% in the first half. Our first-half production of 3.7 million barrels of wool equivalent was down 13% on the corresponding half, to unplanned downtime at Moomba and upstream operations, as well as some planned maintenance at Moomba and natural fuel decline. We shall continue to work with Operator Santos to ensure we maximise production from those facilities. We each plan to participate in 35 to 40 wells in the second half. On slide 22, we start to turn our attention to projects where we believe we can start to deliver upside to our base growth targets. In the Bass Basin, the first household beach reprocessed seismic data, and in doing so, we identified new exploration opportunities, Yolo West and Yolo North. These prospects could be developed with jack-up rigs on the Yolo platform and deliver increased and extended production through the Lang Lang gas plant. This is something we look to progress in the coming months with a view to potentially commence drilling these prospects at FY23, subject to approvals. In addition to the production boost these wells could provide, they would also deliver a level of flexibility around the timing of the treadfall project in the event that the project, which is currently in feed, is sanctioned. To that end, we acquired the prime 3D seismic in the first half with the data now being processed to support a potential FID for the treadfall development and quantify the potential of the nearby white ibis and bass prospects. Moving across the Tasman to New Zealand, and on slide 23, we turn our attention to the Taranaki Basin. As previously mentioned, in the first half, we brought the Cooper Inlet Compression Project online, the first gas introduced into the plant two weeks ahead of schedule. As a result, the plant's throughput returned to the full 77 TJs a day. Plasty and plateau production rates are expected from the Cooper Field through FY23. This figure has been updated slightly to reflect data coming through since the completion of the compression project. In a similar vein to our Bass Gas assets, we are now assessing options to extend plateau production at the Cooper gas plant to deliver upside on our base production target. As such, we continue to assess a potential development well, Cooper East, which could be drilled from the existing Cooper platform. Running of that well has been considered for FY23, again, subject to approvals and RIC availability. In closing out today's presentation, I want to hone in on a few key points. Our growth program is on track with several key deliverables toward the 28 million barrels of oil equivalent target achieved today. Offload is first gas from the Octway offshore wells, and the fact that Cupe is again running at 77 TJ spec capacity. However, we know the job is far from done, and in the second half, we're still focused on delivering key milestones towards our growth target. This includes drilling the remaining three wells in the offshore waterway campaign by the middle of this year, pushing FID on the enterprise pipeline project, commencing the development drilling for the Waitier Stage 2 project, and signing the agreement with BP for BESA's 3.7 million tonnes of LNG from Waitier. The second half will also see us refining a focus on projects that have the potential to deliver production above our stated growth target. These include the Western Flank Oil Exploration Campaign, to which any discoveries could serve above our base case target, progressing our plans in the Perth Basin to conduct an exploration campaign at the conclusion of the Waitian Development Drilling Program, better understanding the nearshore potential of the Otway Basin following our success at the enterprise, executing the YOLO Enfield Program to extend the life of YOLO, as well as progress feed on trefoil, and finalized plans to drill the Kupe East development well in the Taranaki Basin to extend plateau at Kupe. These first three points are supported by our final takeaway, which is the continued strength of our balance sheet. We retain a net cash position of $73 million with liquidity of $673 million. This provides us with significant flexibility to execute and expand our growth opportunities among other capital management options. With that, I'll hand back to the operator for the Q&A session. Thanks, operator.