Aboitiz Power Corporation (AP) Earnings Call Transcript & Summary

Good afternoon. Welcome to AboitizPower's earnings results briefing for the first half of 2026. My name is Jacqui De Jesus, and I will be the moderator for today's call. [Operator Instructions] Lastly, this briefing will be recorded. By joining this session, you consent your name, voice, image and chat comments being recorded for use in dissemination. Our CFO, Sandro Aboitiz, will present the earnings results for AboitizPower. After the presentation, we will open the floor for Q&A. Sandro, you have the floor.

Thank you very much, Jacqui, and good afternoon, everybody. Welcome to our first half 2026 financial results briefing. Beneficial EBITDA for the first half of 2026 reached PHP 43.3 billion, a 27% increase from PHP 34.1 billion in the same period last year. For the second quarter alone, beneficial EBITDA came in at PHP 23 billion, up 21% year-on-year and 13% quarter-on-quarter. The Power Generation segment remained our primary growth driver, accounting for 90% of total beneficial EBITDA at PHP 38.8 billion. Generation EBITDA expanded by 30% year-on-year, driven by higher contracted volumes, stronger market prices, contributions from CBK and our new solar assets alongside the full first half earnings from Chromite Gas. These factors successfully offset lower coal plant availability during the period. Looking at our other business units, the DU segment delivered in EBITDA, PHP 4.3 billion in EBITDA and RES added PHP 1 billion in EBITDA. Next slide, please. Our total generation portfolio today stands at 6,171 megawatts of attributable capacity. Coal capacity now represents 50% of our total portfolio, down from 57% in December 2025. Recent capacity additions integrated into our portfolio include the 8-megawatt Magat BESS 2, the 20-megawatt Bay BESS, the 172-megawatt Olongapo Solar facility and the 70-megawatt San Manuel Solar facility. Next, please. This slide provides an update on our renewable energy development pipeline. As of the end of June 2026, 846 megawatts of our initial renewable energy pipeline are operational. We currently have 190 megawatts under construction, including Binga BESS Unit 1 and 2, CamSur Wind and Ambuklao BESS. Out of the 639.5 megawatts awarded to us under the green energy auction program, 179.5 megawatts are actively under construction today. This includes the Presentacion 2 Wind project and the San Marcelino Floating Solar project in Zambales. Early works began in late June for our Cadiz and Laoag Solar projects, both moving toward full notice to proceed by the September. In July, we issued the full notice to proceed for the 180-megawatt peak Ubay Solar project in Bohol. We also commissioned Magat BESS 2 in May and Bay BESS in April, while continuing development on EAUC BESS, the TMI Nasipit BESS and TVI Unit 3 in Cebu. Total energy sold increased 7% year-on-year to 17.3 terawatt hours. Total energy generated grew 11% to 22.7 terawatt hours, while purchased power volumes rose 27% to 5.4 terawatt hours. Contracted volumes under bilateral contracts expanded 17% year-on-year to 15.2 terawatt hours on the back of the GNPD Meralco PSA and other short-term emergency supply agreements. Bilateral contracts represented 85% of our total energy sales during the period and roughly 90% of our baseload capacity remains secured under contract. Spot market sales totaled 2.1 terawatt hours, sales to ancillary services at 928 gigawatt hours and RES volumes grew 10% to 2.8 terawatt hours. Okay. Beneficial revenue for the first half grew 28% year-on-year to PHP 110 billion compared to PHP 86.2 billion in the first half of 2025. Top line expansion was driven by contributions from Chromite Gas, CBK, the new solar assets and higher market prices all around. The average bilateral contract revenue per kilowatt hour rose to PHP 5.64 from PHP 5.32. Spot market revenue averaged PHP 6.29 per kilowatt hour, up from PHP 4.09, supported by a higher LWAP of PHP 5.73 per kilowatt hour versus PHP 3.81 in the first half of 2025. Coal benchmarks were also higher with the Newcastle Index averaging USD 127 per metric ton. Gross profit in the Power Generation segment rose 23% year-on-year to PHP 41.6 billion, while generation costs increased to PHP 53.1 billion and purchase power costs rose to PHP 15.4 billion. Gross margin expanded due to higher sales volumes and elevated market prices. The higher purchase power expense was driven by the 50% increase in spot market prices alongside higher purchase volumes required to cover coal plant outages. Nevertheless, our average gross profit per kilowatt hour increased by 4% to PHP 2.09 per kilowatt hour. Energy sales volume in the DU segment grew 6% year-on-year to 3.6 terawatt hours. Commercial and industrial customers accounted for 68% of the volume at 2.4 terawatt hours, while residential customers comprised 32% at 1.1 terawatt hours. However, despite the higher sales volume, segment EBITDA dropped 3% to PHP 4.3 billion as top line volume gains were offset by the incurrence of one-off expenses. In the RES segment, we continue to maintain a market-leading position, holding a 27% market share according to the latest CREM report. Industrial and manufacturing accounts for 58% of our customer demand, followed by commercial customers at 37%. In this space, we have pursued opportunities via the threshold dropping to 100 kilowatts and because of the enablement of the retail aggregation program that resulted in an additional 70 megawatts of customers in this space because of those 2 new enabling factors. Strong EBITDA brought reported net income after tax to PHP 18.4 billion, a 45% increase from PHP 12.7 billion in the first half of 2025. From a total EBITDA of PHP 43.3 billion, net interest expense accounted for PHP 10.6 billion. depreciation and amortization of PHP 10.5 billion and taxes and other provisions of PHP 4.2 billion. Next slide, please. The last 2 slides outline our balance sheet management. On this slide, total interest-bearing debt dropped to PHP 325.6 billion from PHP 332.5 billion at the year-end of 2025, reflecting partial payments of the bridge financing that was used for the Chromite Gas acquisition. Cash and cash equivalents stood at PHP 62.7 billion, placing net debt at PHP 258.5 billion. The net debt-to-equity ratio improved to 1.17x compared to 1.24x at the end of December 2025. Next slide, please. Our debt maturity structure overall remains long term and fairly conservative. 89% of our total debt is denominated in Philippine pesos, which insulates our balance sheet from foreign exchange volatility. Debt maturities are also comfortably distributed over the coming years with PHP 128 billion maturing beyond 2031, providing the funding headroom needed for ongoing capital expenditure program. That concludes our operational and financial presentation for the first half of 2026. We're now happy to answer any questions. Thank you.

Thank you, Sandro. Now on to Q&A. So as I mentioned earlier, we will start the questions -- we will start off with the questions we received in advance. [Operator Instructions] So let's open the Q&A portion with the hot topic that everyone has on their minds, system loss. The first question is, would you have any comments on the impact of system loss recovery disallowance? Do you expect it to affect the broader cost recovery framework?

Yes. I think directionally, the objective here is to reduce the cost to consumer and ensure that the distribution network operates efficiently. So that is an objective, I think we support, right? I think in the near term, eliminating the VAT on system loss charges can probably produce the biggest immediate impact. At the same time, we're also ensuring that we engage in a constructive conversation with other industry stakeholders, including the policymakers and regulators to ensure that any long-term reforms are sustainable and achieve the intended objectives.

Thank you. The next question is, could you share with us the system losses for VECO and Davao Light?

In 2025, total systems loss for VECO was 6.36%, which includes a feeder loss of 4.78%. In Davao Light, it was 9.41%, including feeder loss of 5.45%. If you recall, the ERC's mandated loss cap for feeder loss is 5.5%. So both of those utilities operate underneath that cap.

Next question is, if the system loss charge is removed with no replacement recovery mechanism, do you have an estimate of the financial impact across VECO, Davao Light, Cotabato Light and the EnerZone units combined?

I think it's premature to communicate potential financial impact here. It ultimately depends on in what shape these amendments actually are finalized, right? And so it's probably too early to do that. And of course, we will share a proper assessment once there's an approved framework to actually measure against.

Next question is, what is AP's contingency plan if the charge is removed before any alternative recovery structure is legislated or approved by the ERC?

Yes. So again, along with the last question, I think it's premature to outline specific contingency plans until the amendments take shape in the form of an actual approved amendment. And we are, again, still in constructive conversations with all of the stakeholders to ensure that any plan that's put in place takes into consideration, obviously, the various stakeholders and that any plan is sustainable in the long term.

And then I guess, lastly, on systems loss, is there anything in AP's generation supply contracts with its own distribution utilities that would need renegotiation if the DUs can no longer recover systems loss costs?

So I guess the short answer is no. Systems loss recovery and distribution-side matter between the DU and its customers, and it doesn't affect the generation charge under the PSA.

And then there's a broader question here on regulatory changes in the sector. There have been so many proposed changes to EPIRA, which one do you think is most material for AboitizPower?

So it's -- I guess it's difficult to identify any single amendment as the most material as all of the proposed changes remain under deliberation. But because the systems loss, I guess, issue is new and fresh, it's the one that we are obviously monitoring very closely at the moment and working with all of the various stakeholders to ensure that anything that is put in place is sustainable in the long term.

Thank you. The next question is on transmission -- is related to transmission assets. So in relation to ERC's updated policy on point-to-point limited transmission facilities and associated transmission projects under ERC Resolution #18, are costs associated with construction and depreciation of the point-to-point transmission assets also part of the PPA bids presented to the ERC?

I suppose when we say PPA bids here, we mean the PSA contracts that are submitted to ERC for approval. And ultimately, those costs can be included as part of the project cost, which is recovered through the PSA rate.

The next 2 questions would be on the spot market. So the first one is on reserve market. How will AP be impacted by the potential lower price ceiling for power reserves in the spot market?

So the price ceiling that's being proposed is obviously lower than the market prices today. So that ceiling will obviously have a downward impact on AP. But that number, again, is still in consultation and has not been finalized, but it is obviously lower than the high market prices on the reserve market side we're seeing today.

And then on LNGPH, do you have updates on the line rental issue on LNGPH?

Again, I assume this is related to the line rental issue that was created as a result of the market suspension and modified administered price in April. So that issue was raised actually to ERC via PIPPA through a formal position paper. ERC has acknowledged the paper and is in the process of resolving it, although the timing of that resolution is uncertain at this point. And yes, so the timing is uncertain at this point in terms of the resolution of that issue.

Thank you. We have a question here on CBK. Could you provide an update on the current status of CBK's tariff application?

So in order for CBK to submit a tariff, there are other conditions that have to be met first. And those 2 conditions relate to, number one, the establishment of a payment and settlement mechanism with ERC. And the second one is a required WESM rules amendment with the DOE. And those 2 things are still in the process of being finalized through public hearings and stuff like that, right? So until those 2 things are put in place, we are not able to submit a tariff application. But we are, I guess, doing all of the prework that's required so that by the time these 2 things are put in place, we're fully ready to submit a tariff application as quickly as possible once those conditions are met.

The next question is on plant availability. What was the reason for the lower coal plant availability in the second quarter of 2026?

So I guess here, the primary reason is due to the forced outages of both units in TVI, TVI 1 and 2. Both units experienced steam turbine vibration issues and have been on outage in the last couple of months, right? There have been other outages in the fleet that are more, I guess, minor. But the biggest reason of the lower plant availability in the second quarter is really because of both units of TVI being down.

And then specifically for TVI, when can we expect the power plant to return to service? Would you also have an estimate of the financial impact of the foregone generation or replacement power and restoration costs on TVI?

Based on the current team's estimate, we're estimating a return to service of both units by the end of August. And the team is working on accelerating that return to service. But based on our latest thinking, it looks like end of August is the current estimate. In terms of the -- an estimate of the financial impact, we're not in a position to give a final number at this stage as the full scope of the work that needed to be done is still ongoing.

I see that Jelline's hand is raised. Jelline, you have the floor.