Karoon Energy Ltd

Thank you for standing by and welcome to the Karun Energy Limited 2023 half year results. All participants are in a listen only mode. There will be a presentation followed by a question and answer session. If you wish to ask a question, you will need to press the star key followed by the number one on your telephone keypad. I would now like to hand the conference over to Mr Julian Fowles, CEO and Managing Director. Please go ahead.

Yeah, thank you very much. And good afternoon, everyone. And thanks for joining our call. And to those on the webcast, as introduced, my name is Julian Fowles, the CEO at Karun Energy. I'm joined today by Ray Church, our chief financial officer, and Anne Diamond, who heads up our IR team. Earlier this morning, we released to the market our results for the first half of FY 2023, including a slide pack that we'll run through now. And we'll really just focus on the highlights, given that people have had a chance to look at and digest the pack already. So we can move to slide four, noting the disclaimer on slide two. This represents the first half highlights and our achievements, and I'll go through those as the headlines first off. So the headlines are we had a very strong first half, both operationally and financially, during which we also delivered on our key growth projects in Navona Interventions and in Patola. We managed to fund those activities through existing cash and cash flow from operations, meaning that we minimized the draw on our debt facilities, thereby reducing unnecessary spend while also retaining a high degree of liquidity. Safety, of course, remains top of our priorities, especially given the broad front of our current operations. Some of the key highlights are that relative to the first half FY22, we achieved a 275% increase in our underlying net profit to US$82.4 million, driven by both higher production and higher oil prices. Our Bauna interventions have performed better than expected, and the two Patola wells also came in with better than expected reservoir quality. Patola remains on track for first oil during March, and once on stream we expect our gross oil production from BMS 40 to reach over 30,000 barrels of oil per day before natural decline resumes. We also upgraded our reserves just following the end of the half with a 23% uplift in 2P, meaning we've achieved an overall reserve replacement of 259% since we first took over operatorship of Verona. And finally on this slide, as we announced last week, the NEON 1 well reached TD in mid-February, and the decision was taken based on the encouraging results at that well to drill NEON 2 once the operations at NEON 1 are complete. After NEON 2 has been drilled and completed, the data acquisition completed, our intention would be to release the rig. So if we can move to slide 5. This slide summarizes the progress we've made against our strategic objectives. It's very pleasing to see that we've achieved much of what we set out to do two years ago. Although some of the work is still ongoing, most notably the Patola tie-in has yet to be finished and Neon to be progressed through the drilling of Neon 2, we have established Karun's reputation as a safe, reliable and responsible operator, delivering on our promises and building value for our shareholders. I'll now hand over to Ray and let him talk to our financial results.

Thank you, Julian. Good afternoon, everyone. I'll also aim to point out the highlights that provide more detail to the presentation rather than talk to all the slide contents. And I think the main themes driving the financial results are strong oil price, growing production and high uptime in facilities, controlled fixed costs, strong cash flow and sound liquidity position. Moving quickly to the financial highlights for the year, for the half year, you can see that all key financial metrics reflect continued improvement in performance compared to the same period last year. The key drivers behind these positive outcomes are our reliable operations performance with high uptime levels, higher prices for our product, and disciplined cost management in OPEX and capital projects. I'll flag that operating cash flow of $167.1 million showed a high rate of conversion of underlying EBITDA, and this funded all of the significant cash investment in our two major programs and minor capex associated with plant equipment, office and IT hardware, while leaving liquidity largely unchanged at $343.2 million. Just a few points to note on the income statement. Growth in revenue to $299.4 million was driven by two components. Volume represented $61 million of disimprovement from the comparable period, with seven liftings compared to five liftings from the bow on a field, while oil price growth represented a further $51.9 million increase in revenues from the first half of FY22. Other income of $1.1 million comprises of interest on our cash balances across the period. The reduction in unit OPEX for Bona reflects increased production from the interventions program, as well as largely fixed contract rates that have escalated annually for US inflation. In addition, we've seen modest procurement gains, savings through co-time maintenance operations, intra-period weakness in Brazilian currency impacts on local costs, and deferral of some activities into the second half. Costs also include $6 million of inventory movements driven by the increased production rate at the end of December. Royalties of $30.3 million reflect the 35% increase in production and higher oil price and included in this cost are also special participation and R&D levies which were $1.1 million and $1.7 million respectively and which currently offset the royalty rate reduction of $2.3 million and a half. As production increases in future periods, the royalty reduction should exceed the R&D and special persuasion levies and become more visible. Depreciation and amortisation has increased to $48 million as a combined result of higher production and commencement of amortisation of capitalised boner interventions costs. Corporate expiration and other costs totaling $14.6 million reflect some planned costs having been avoided, completed at lower cost or deferred. Finance and interest costs of $3.7 million reflect not only the full six months cost of RBL commitment fees, interest and amortized borrowing costs, but also $2.1 million of non-cash costs associated with unwinding of the discount on restoration provisions. which is an expense driven by changes in the US 10-year Treasury rate. Underlying income tax expense of $43 million is affected by $1.3 million impact of non-cash share-based payments and non-deductible costs in Australia, offset by a $1.3 million non-cash benefit from FX movements affecting value of Brazilian Real dominated tax assets, sorry, denominated tax assets. As these offset each other, the underlying effective tax rate reflects the Brazilian income tax rate of 34%. And I'd like to point out that we have no remaining carry forward Brazil tax losses. The resulting underlying profit was $82.4 million for the half. Slide 9 demonstrates the cash generating capability of our operations as operating cash flow including FPSO lease payments and finance cash costs grew to $144 million and a half. I'd like to note that this excludes $40.5 million cash for an early December lifting, which was collected on 3rd January. Payment for a second December lifting of $38.7 million was also received on 20th of January. This net cash flow fully funded our major capex investments, of $139 million without further requirement for debt drawdown. This resulted in a growth of closing cash on hand from $158 million to $163 million through the half. This sets us up well for the balance of the Patola Development and Neon Control Well cash flows and also provided adequate cash for the first contingent payment to Petrobras of $84.5 million in January 2023. So moving on to liquidity on slide 10. This means that the debt facilities haven't changed through the hearth with no further draws required since the establishment of the reserve based facility in November 2021. $180 million remains therefore undrawn against this and the accordion facilities. As you can see, these facilities begin to roll off from end of 2023 and with expectations of having successfully completed the Bowen interventions and Patola developments and the resulting higher production that will support potential refinancing to begin later this year after production from Patola is brought online and neon drilling is completed. With cash on hand of $163 million, and overall liquidity of $343 million. This is more than adequate for remaining drilling and development cash flows, which is estimated at $160 to $190 million through year end, as well as the Petrobras contingent consideration payment made in January 2023. Looking ahead to guidance for the full year, while full year production guidance remains consistent with previous guidance, Several items on this slide reflect our focus on cost management through procurement, optimising maintenance operations, identifying avoidable costs and timing additional costs to align with production growth. Consequently, full year forecast unit production costs are anticipated between $13 and $17 per barrel. While the first half unit production costs are slightly more than the full year range, this is driven by timing for production increases from Vauna interventions and we're confident that we'll complete this year within this range and that unit costs should fall in the second half as higher levels of Vauna production will be present for the entire second half with additional ramp up from Patola contributing further to unit cost reduction. Depending on Patola volumes and production uptime at those peak levels, we may be at the lower end of full year guidance and that will be reviewed in the third quarter. Other operating costs are expected to be between $19 and $23 million for the full year, with $9.2 million incurred in the first half. Finance costs, which include facility commitment fees and interest, have increased to $9 to $10.5 million for the full year, and this growth, mostly in the second half, is predominantly driven by the increase in the discount rate, which creates a non-cash cost, as loan and patola restoration provisions are unwound. Note that as the total wells were completed in the half, although not yet tied in, $23.8 million was added to the restoration provision on the balance sheet, which also contributes to this non-cash cost in the second half. Unit DD&A guidance for the full year is reduced to $12 to $14 per barrel, driven by recently announced increases in reserves, partly offset by a higher aromatising cost base, as bone interventions and potola costs are commissioned and capitalised. In terms of investment expenditure, the Bowen intervention and Patola project costs for the full year are also now anticipated at $200 to $220 million. Julian will talk more about these programs shortly. Other plant and equipment spend is now expected to be $4 to $8 million, as some contingent items will not likely be required. And we expect reduced spend on IT and cyber-related projects, as costs for these projects are lower than anticipated. Moving on, slide 12 provides a reconciliation from underlying to statutory impact and EBITDA. As in the past, non-cash movements in fair value of contingent consideration have been removed from the underlying results, as have accounting-driven non-cash FX movements on US dollar cash balances held in Australia. As our hedges were out of the money in July through November, while Brent crude traded above $90 per barrel, we recorded a realized loss of $7.1 million in statutory net earnings. The tax-rebatable social investments of $1.8 million were also represented in tax expense within underlying profit. These social project investments achieve a 100% reduction in income tax payable in Brazil. So the cost and associated tax effect complications have been removed from the underlying pre-tax result while they remain in the after-tax earnings result for presentation purposes.