Harbour Energy plc

Good morning everyone and welcome to Harbor's half year results call. Joining me today is Alexander Crane, our CFO. Following our disclosure statement in the material is our agenda. It's shown on page two. I'm going to speak a bit about performance, both operational and strategic growth, and then I'll turn it over to Alexander who will discuss our financial results. If we turn to page four, we have the highlights from the six months. These include a good operational performance 1st, with respect to safety. And 2nd, in particular in the UK. Our production from our operated assets was flat year on year. And where we took measures to address our cost structure. Next, we'll talk about progress with our organic growth projects outside of UK oil and gas. And finally doing all of this while improving our balance sheet. Leading to 0 net debt at mid year. Of course, the UK Wind for Profits Tax, or EPL, continues to have its impact, resulting in a higher tax burden, even with significant investment in the country. We do remain engaged with the UK government regarding the fiscal environment for the domestic oil and gas sector, which of course is critically important for the UK's energy security and also for the energy transition, as it's the oil and gas companies who are leading the country's efforts to capture and store 30 million tons of CO2 by 2030. Turning now to safety and the environment, I feel good about our results in the first half. We had no serious injuries, spills, or releases to the environment, and we saw a reduction in leading indicators following the launch of a Back to Basics campaign last year across our operations. We also continue to strive to reduce the environmental impact of our operations by addressing our emissions, by responsibly decommissioning retired infrastructure, and by being involved in CCS. Our emissions, which are on track to reduce by 50% by 2030 versus our 2018 baseline, were down slightly in the first half. Looking ahead, our Vietnam business, the sale of which was recently announced, includes our most emissions-intensive asset, accounting for about 10% of our emissions, but only 2% of our production. So this will improve our emissions levels and our intensity going forward. Slide seven takes a look at production, which averaged 196,000 barrels per day for the first half. The reduction versus last year reflects natural decline, partially offset by contributions from new gas wells at our operated toll mount and J area hubs. As you can see from the charts on the right, this resulted in UK production from our operated assets remaining essentially flat year on year, the result of investment and operating performance. We also had an increase in overall gas production. On the other hand, we're starting to see the impact on our production levels of other operators' decisions to defer drilling. This is particularly the case at barrel, where Apache has paused not only further subsea drilling, but also platform drilling at the asset. The main reason why we're narrowing our guidance for the full year to 185,000 to 195,000 barrels per day. The next page shows a bit more about our UK performance. Production efficiency was generally good at 82%, better than the UK average of 77%. And absolute operating costs remain flat year on year in the UK, which is a good outturn given the headwinds of inflation. This equated to $15 per barrel, again, better than the UK average, which sits at about $18 per barrel. This is the result of hard work and active management of our cost structure. We're leveraging our scale to realize efficiencies, especially in the supply chain. where we continue to rationalize our portfolio of supplier contracts and are on track to deliver a 50% reduction in those versus 2022 sometime next year. This includes the formation of strategic supply chain partnerships, including three so far, covering aviation, fabric maintenance, and shore-based logistics, which should lead to further cost savings as we go forward. Our margins will also be helped by the review of our UK organization. This is nearly concluded and we expect to deliver annual cost savings of $50 million from 2024. This reflects the completion of integration efforts following three acquisitions, including the go-live of our new enterprise management system late last year and the removal of three layers of management between our offshore managers and myself since closing the premier merger. We also continue to ensure our capital and resources are deployed effectively in support of our strategy, and this sometimes leads to divestments and relinquishments. Since the premier merger, we have exited Brazil, we've exited the Falkland Islands, we high-graded our UK2C portfolio, and we agreed the sale of our mature Vietnam assets, which have operating costs of about $30 per barrel and limited opportunities for growth. This next slide we showed at full year results, so I won't dwell on every aspect, but maybe a few things to call out. While the EPL has impacted our activity levels in the UK, we're still progressing opportunities which have the potential to maximize the value of our assets and partially offset decline. Our Armada field is a good example. It came with the Shell portfolio in 2017. and was scheduled for decommissioning in 2018. We saw the opportunity to invest in the asset, materially improving uptime and adding reserves. Just recently, we approved an infill well at Northwest Seymour, which together with plant modifications could further extend Armada's producing life to 2030. I also spoke at full year results about the work we had initiated to evaluate opportunities to improve the recovery factor from our existing operated fields, in particular at J area. The aim of which is to allow us to capture resources and reserves that are not yet included in our booked volumes. While feasibility studies are still ongoing, we have approved investment in 2024 targeting the Judy Chalk with plans to drill one well and to retrofit three producing wells for gas If successful, these would add high return incremental reserves and could potentially de-risk additional investment to unlock further reserves from the field. Turning now to our drilling program, in line with our strategy, most of our capital is focused on low risk, short cycle drilling opportunities, in addition to our fairly steady UK decommissioning program. Currently, we have six rigs running, including one undertaking P&A work. ramping up to nine in late Q4. At Talbot, we successfully completed the first of three development wells, and at Leverett, we're currently appraising a discovery which, if successful, could be developed as a subsea tieback to Britannia. Outside the UK, we're set to drill several exploration wells, including two in Norway, the Equinor-operated JDE well and the Vore-operated Ringhorn North Prospect. The last point to highlight on this slide is that we've seen several drilling deferrals at partner-operated hubs as a result of the EPL, at the Apache-operated Barrel Field and the Totel-operated Elgin Franklin Field. We also had some impacts due to the delayed arrival of rigs. All of this means CapEx spending will be higher in the second half of the year than in the first, and our outlook for full-year CapEx is around $1.0 billion now. a hundred million lower than originally anticipated. Turning now to our organic growth opportunities outside of UK oil and gas, we've made some real progress in this area. First, we have a growing pipeline of international oil and gas projects. As shown on the left, these could add materially to our reserves and reserves life in the 2024 to 2025 timeframe. In Mexico, two major milestones, First, the regulator approved the unit development plan for our Zama oil field in June. Since then, the team has been busy preparing for feed, which is expected to start in the coming weeks. This would be the last material phase before a potential final investment decision next year. At FID of Zama, 75 million barrels of our 2C resources would move into 2P, replacing over a year's worth of our production today and increasing reserves life. The second milestone in Mexico was the shallow water con oil discovery on block 30 to the southwest of Zama. Early estimates put gross oil in place at 200 to 300 million barrels, and we're expected to reflect the discovery in our 2C volumes at year end. The team is now preparing to submit a plan to the regulator to appraise the discovery most likely in the second half of next year. If the appraisal is successful, the project has the potential to move fairly quickly to FID. Moving to Indonesia, we're nearing the start of a four-well campaign at Andaman following the Timpan discovery in 2022. We're also hopeful of making progress on our tuna project, which has been impacted by sanctions affecting our ability to work with the Russian partner. Another diversification opportunity for us is in CCS. which has the potential to deliver a long-term stable income stream. We had significant progress at our two UK projects, Harbor-Led Viking and Acorn, both awarded track two status by the UK government at the end of July. This enables the projects to move to the feed and due diligence phase ahead of potential final investment decisions. The UK's track progress is currently the only route to securing an economic license from the government for CO2 storage, thus offering our projects a significant first mover advantage. On this next slide, we have a bit more about Viking. With independently certified storage capacity of 300 million tons and the annual capacity of more than 15 million tons per annum, it is one of the largest planned CCS projects in the world, as you can see on the bottom of this page. And with our partner BP, we recently applied for and have been offered two additional storage licenses adjacent to the existing Viking licenses, which have the potential to increase capacity by more than 50%. In addition to the early customer agreements to deliver 15M tons of CO2 for storage, we have an exclusive arrangement with associated British ports for the development of a jetty to enable shipped CO2. from the UK or from other countries to access our transportation storage system, giving the potential for additional revenues and improved returns. The main objective of the feed phase for Viking and Acorn is to obtain a firm cost estimate and schedule for the projects. These are key inputs to our decision making. This project process should be complete for Viking before the end of 2024, But the timing required to conclude the Track 2 discussions with the government, I would have to say, is a bit more unpredictable. A successful completion of both and confirmation of acceptable economic terms are the key milestones between now and consideration of an FID. Okay, now turning to the Andaman Sea in Indonesia. We're trying not to get too excited about the return to drilling in the Andaman where we're planning for a minimum four-wheeled program. This will start when the rig arrives, which is currently expected in October. This follows the Timpan gas discovery on our operated Andaman II license last summer, which de-risked this potential multi-TCF gas play. Through the upcoming campaign, we're looking to prove up additional volumes for a potential commercial development on the Andaman II license and also test the extension of the play to the south. The first well will be at the Liar End Prospect on the Mubadala-operated South Andaman license, where we hold a 20% interest. This will be followed by two wells on the Andaman II license, targeting the Hawa and Gyo Prospects. The rig will then return to South Andaman to drill the fourth well. I think the last thing to note on this slide before I hand over to Alexander is that during the first half of this year, we received the initial data from the new 3D seismic survey over the eastern portion of our Andaman II license. On first review, it looks encouraging with multiple prospects observed. So there should be more running room if this drilling campaign proves successful. So now over to Alexander.

Great. Thank you, Linda, and good morning to everyone joining. Now, in my section today, I will provide an update on our hedging program. I will take you through our financial results for the first six months of 2023, and then I will close with an update on our 2023 guidance. Now, before doing so, a summary of the key takeaways this time. First, we generated material cash flow during the first half. This enabled us to reduce our net debt to zero and supported competitive shareholder distributions over the period. Second, we forecast 2023 free cash flow of $1 billion, and this reflects the heavy first half weighting of our cash flows due to phasing of CapEx timing of tax payments, as well as on positive working capital movements. And third, this is all underpinned by a prudent approach to risk management and strict capital discipline in line with our three equally important capital allocation priorities of maintaining a robust balance sheet, investing in our assets to ensure a resilient portfolio and delivering meaningful shareholder distributions, including via our 200 million annual dividend policy. So with that, let's move to the next slide and talk a bit about hedging. As you can see from the chart on the left, we realized $76 per barrel and 58 pence per term for the period versus $82 per barrel and 69 pence per term last year. The difference between realized and market prices reflects the historical hedging program, most of which we put in place at the time of the premier merger to protect our balance sheet and to lock in the leveraging. As a result, for 2023, we are about 50% hedged, approximately 65% on the gas side and 30% on the oil side, evenly spread over the first six months of the year and the second. I do note that the first four bars on the center of this page are all for 2023. So you can see our hedged volumes are going down significantly from 2024. Now this is what you would expect, given where our balance sheet and leverage is today. We want to offer our investors more exposure to commodity prices. Now, in fact, as part of the recent redetermination, we changed our hedging requirements, linking them to the amount drawn on the facility to provide us with greater flexibility. This means that while our facility is less than 10% drawn, we have no hedging requirements. Two other items to call out on this slide. First, Our crude swaps at $84 per barrel in 2024 and $77 per barrel in 2025 are now close to the forward curve, while we have no oil hedging in place for 2026 onwards. And secondly, and as illustrated here in a lightly shaded red color, the introduction of zero-cost colors for gas to retain more upside to gas prices for equity investors while still protecting downside. And turning to our income statement. We delivered a strong profit before tax of 429 million for the period, albeit a significant reduction from last year, primarily driven by two factors. First, lower revenue. This is driven by lower commodity prices, especially UK gas prices, and also due to lower oil volumes. And the second factor is the change in the movement of sterling versus US dollar between the periods. In the first half of 2023, we recognized an unrealized foreign exchange loss of 85 million on the British pound denominated assets on our balance sheet. Whilst you may recall that in the first half of 2022, we saw a 360 million foreign exchange gains. Next, there are three one-off costs during the period, which I would like to note. First, we have recognized a 16 million accrual in relation to the UK organization review, which is on track to complete this quarter. We expect the UK review to deliver cost savings of around 50 million per annum from 2024 onwards, split across OPEX and CAPEX and G&A. G&A of 91 million includes base and corporate overheads of 30 million and depreciation of non-oil and gas assets of around 20 million. In addition, we have some period-specific items making up the $40 million balance here, including redundancy provisions and external consulting costs. Now, the second issue. we have recognized a 13 million write-off in respect of the X well on Block 30 in Mexico, which was plugged and abandoned. This, together with a successful Khan 1 well, means that we have now completed our commitments for this phase of the license. And thirdly, we have incurred a 19 million net impairment charge, primarily resulting from the impairment of Solon, following an increase in our estimated costs for decommissioning the assets. Next, our financing costs. As some of you will recall from the full year update, we saw a significant reduction in our balance sheet decommissioning liability as a result of applying a higher risk-free rate in line with market movements. Now, the impact of this is that we will now see a higher unwinding of that discount going through our financing cost line on an annual basis. Looking at this from a earnings rather than a profit lens, our EBITDAX was $1.4 billion, so only a 30% fall from the prior year, which is revenue and price driven. Our income state tax charge pushes us into a small loss after tax position with the effective tax rate close to 100%. This reflects three factors. The main factor is the higher UK statutory tax rate of 75%, up from 40% in the first half of 2022 due to the introduction of the EPL. Second, not all costs are fully deductible at this rate, so typically a company's effective tax rate is higher than the statutory rate. For us, these effects more than offset the higher capex deductions that received a higher investment allowance. And thirdly, we had a number of period-specific items which further increased the effective tax rate. Notably, and as just mentioned, we had a decommissioning estimate update for Solan which pushed up the tax rate as decommissioning is not deductible for the EPL. We had unrealized foreign extra losses, which are relievable at lower rates. And there were some smaller prior year adjustments and remesherments. Now, had these period-specific items not arisen, our effective rate would have been closer to 80%. In the first half, our current tax liability was $413 million, split overseas with $8 million and UK $405 million, of which around $300 million is in respect of the EPL. Let's move to the balance sheet then on slide 18. We have continued deleveraging in the period and currently have nothing drawn under the RBL. We have moved from 778 million net debt at the end of last year to a small positive net cash position at half year. We also see a significant reduction in the derivative liability we carry on our balance sheet for commodity hedges. We have moved from 3.3 billion at year end to 1.2 billion at June 30th, reflecting the unwinding of our hedge position and the fall in gas price outlook. We have moved from a net deferred tax asset position of 1 billion to a net deferred tax liability position of 0.7 billion, driven in large part by the movement in our derivative position. This reflects the fact that the future hedging losses have reduced, and so too has the associated tax relief. There is also a 150 million increase in decommissioning provisions due to the increase in the DECOM estimates, the usual annual unwinding and foreign exchange movement, and this is only partly offset by the decommissioning activity undertaken in this period. The final point I will touch on is equity. Equity has increased because of a favorable movement on unrealized commodity derivatives, net of the shareholder returns. We continue to have significant distributable reserves on the balance sheet, which supports our annual dividend policy of 200 million. When we look at the cash flow generation on slide 19, You will see on the graph to the left that gross operating cash flow for the period was 1.6 billion. This 1.6 billion is after 173 million of favorable working capital movements, including the change in realized cash flow hedges that were not yet settled at June 30th. 50% of this was used to pay down the outstanding RBL balance. 30%, or approximately 450 million, went on capital expenditures, comprising around 340 million of investment in our assets and 110 million spent on decommissioning. As a result, the total capex for the first half equated to a little less than half of our updated 1 billion total capex forecast for the year, and this reflects the increase in activity towards the second half of the year that Linda mentioned. A net 7% of our gross operating cash flows went towards financing costs, including lease costs. and 16% or 250 million was returned to shareholders through dividends and buybacks during the period. It is worth noting that no UK tax payments were made in the period. Now, ordinarily, we would have made UK tax instalment payments in January this year relating to 2022. However, We made a UK tax overpayment last year due to the clarification on timing of EPL installments for certain companies, which we reallocated to cover the normal January tax payment. We expect to make over $400 million of tax payments in the second half of this year. As a result, all of our UK cash tax payments fall within the second half of this year. This, together with the aforementioned phasing of capex payments, means that our 2023 free cash flow is heavily first-half weighted. We also completed our annual redetermination for the RBL facility. Now the outcome of which is that our facility size continues to be 3.7 billion with a 1.75 billion letters of credit sublimits. The borrowing base is set at 1.1 billion at July 2023, which reflects the full effect of the EPL and does not take into account the recently announced floor price mechanism. As mentioned above, we moved from a net debt position at year end to a small net cash position at June 30th, with our 2026 500 million bond offset by cash of 500 million. As at period end, we had available liquidity of 1.6 billion, comprising the 1.1 billion undrawn RBL facility and 500 million of cash. As you can see from this slide, we have reduced our net debt by 2.9 billion since completion of the premier merger in April 2021, continuing our track record of rapidly paying down debt post large-scale acquisitions. We've also built a track record of returning capital to shareholders and have announced approximately 1 billion of shareholder returns since December 2021. This reflects our 200 million annual dividend policy, which we set at a level which is sustainable through the cycle, and the return of excess capital via buybacks, especially during 2022 when we saw volatile commodity prices. In March 2023, we announced a 200 million buyback, which is ongoing today. We continue to review and discuss shareholder returns at every board meeting, taking into account a number of factors. These factors include the macroeconomic outlook and our other capital allocation priorities, including investments in the business, which is increasing in the second half of the year, and maintaining optionality for value accretive, yet disciplined M&A. At $80 per barrel and 100 pence per term, our 2023 full-year cash flow forecast is unchanged at 1 billion. This reflects the impact of lower commodity prices offset by lower 2023 capex forecast and a positive working capital adjustment. In summary, this does likely bring us back into a small net debt position at year end, and then a potential to be net debt free in the first half of 2024. Now, finally, let's have a look at our guidance for the year. On the left, we have our original 2023 guidance set back in January. In the middle, we have our actuals for the first half, and on the right, our updated guidance. On production, eight months through the year, and with most summer maintenance program now successfully completed, we are comfortable narrowing the range to 185 to 195,000 barrels of oil equivalents per day. The reduction at the top end reflects delays and deferrals of drilling at partner operated hubs, primarily barrel. Operating cost guidance at around $16 per BOE is reiterated, higher than the $15 per BOE achieved in the first half, which is mainly a result of lower production volume forecasted in the second half. Guidance for total capital expenditure is reduced by 100 million to 1 billion, with some cutbacks now falling in 2024 due to the delayed arrival of rigs, primarily at Andaman and the greater Britannia area, as well as a deferral of the subsea and platform drilling campaigns at Beryl. Now, I appreciate that was a lot of detail. So with that, I will hand it back to Linda for some closing remarks. Thank you.

Thanks, Alexander. I'm going to wrap it up now and then open it up for Q&A. So to summarize with this last slide, I think generally good operational performance in the first half with active management of the cost base. This led to strong cash flow, enabling us to reduce net debt to zero. And then the strong financial position has supported, I think, competitive shareholder returns and as Alexander said, positions as well going forward. So now we're happy to take your questions and over to Ellen to help us out with that.