Q2 2026 Aboitiz Power Corp Earnings Call
Speaker #1: Name is Jacqui Jesus, and I will be the moderator for today's call. Some reminders before we begin: first, we have put microphones on mute to minimize background noise during the presentation.
Speaker #1: Second, questions have been requested from the audience in advance, which we will go through during the Q&A portion. In case there are more questions from the floor, please feel free to click on the raised-hand button or submit your questions via the Q&A box.
Speaker #1: Those not taken up during the Q&A session will be answered via email. And lastly, this briefing will be recorded by joining this session you consent to your name, voice, image, and chat comments being recorded for use in dissemination.
Speaker #1: Our CFO, Sandra Aboitiz, will present the earnings results for Aboitiz Power, after the presentation we will open the floor for Q&A. Sandra, you have the floor.
Speaker #2: 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 43.3 billion, a 27% increase from 34.1 billion in the same period last year.
Speaker #2: For the second quarter alone, beneficial EBITDA came in at 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 13.8, 38.8 billion.
Speaker #2: 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 Cromite Gas.
Speaker #2: These factors successfully offset lower coal plant availability during the period. Looking at our other business units, the DU segment delivered 4.3 in EBITDA, 4.3 billion in EBITDA, and rest added 1 billion in EBITDA.
Speaker #2: 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.
Speaker #2: Recent capacity additions integrated into our portfolio include the 8-megawatt Magat Best 2, the 20-megawatt BAE Bests, the 172-megawatt Olongapo Solar Facility, and the 70-megawatt San Manuel Solar Facility.
Speaker #2: 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.
Speaker #2: We currently have 119 megawatts under construction, including being a Best Unit 1 and 2, Tamsor Wind, and Ambu Cloud Best. 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 presentation 2 wind project and the San Marcelino Floating Solar Project in Zambales.
Speaker #2: Early works began in late June for our Cadiz and Laoag solar projects, both moving toward full notice-to-proceed by this September. In July, we issued the full notice-to-proceed for the 180-megawatt peak Ubay solar project in Bohol.
Speaker #2: We also commissioned Magat Best 2 in May, and BAE Best in April, while continuing development on EAUC Bests, the TMI Nasipit Bests, and TVI Unit 3 in Cebu.
Speaker #2: 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.
Speaker #2: Contracted volumes under bilateral contracts expanded 17% year-on-year, to 15.2 terawatt-hours, on the back of the GNPD Morocco PSA and other short-term emergency supply agreements.
Speaker #2: Sorry, can you stay on that page? Just for another moment. Thank you. Bilateral contracts represented 85% of our total energy sales during the period, and roughly 90% of our base load capacity remains secured under contract.
Speaker #2: Spart market sales totaled 2.1 terawatt-hours, sales to ancillary services at 928 gigawatt-hours, and rest volumes grew 10%, to 2.8 terawatt-hours. Okay. Beneficial revenue for the first half grew 28% year-on-year, to 110 billion, compared to 86.2 billion in the first half of 2025.
Speaker #2: Top-line expansion was driven by contributions from Cromite Gas, CBK, the new solar assets, and higher market prices all around. The average bilateral contract revenue per kilowatt-hour rose to 5.64 pesos, from 5.32.
Speaker #2: Spot market revenue averaged 6.29 per kilowatt-hour, up from 4.09 pesos, supported by a higher LWAP of 5.73 per kilowatt-hour, versus 3.81 in the first half of 2025.
Speaker #2: Coal benchmarks were also higher, with the Newcastle Index averaging 127 US dollars per metric ton. Gross profit in the power generation segment rose 23% year-on-year, to 41.6 billion.
Speaker #2: While generation costs increased to 53.1 billion, and purchased power costs rose to 15.4 billion, gross margin expanded due to higher sales volumes and elevated market prices.
Speaker #2: The higher purchased power expense—sorry, just stay there quickly. Thanks. The higher purchased power expense was driven by the 50% increase in spot market prices, alongside higher purchased volumes required to cover coal plant outages.
Speaker #2: Nevertheless, our average gross profit per kilowatt-hour increased by 4%, to 2.09 pesos per kilowatt-hour. Energy sales volume in the DU segment grew 6% year-on-year, to 3.6 terawatt-hours.
Speaker #2: 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 4.3 billion, as top-line volume gains were offset by the incurrence of one-off expenses.
Speaker #2: In the rest segment, we continued 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%.
Speaker #2: 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 two new enabling factors.
Speaker #2: Strong EBITDA brought reported net income after tax to 18.4 billion, a 45% increase from 12.7 billion in the first half of 2025. From our total EBITDA of 43.3 billion, net interest expense accounted for 10.6 billion, depreciation and amortization 10.5 billion, and taxes and other provisions at 4.2 billion.
Speaker #2: Next slide, please. The last two slides outline our balance sheet management. On this slide, total interest-bearing debt dropped to 325.6 billion, from 332.5 billion at the year-end of 2025, reflecting partial payments of the bridge financing that was used for the Cromite Gas acquisition.
Speaker #2: Cash and cash equivalents stood at 62.7 billion, placing net debt at 258.5 billion. The net debt-to-equity ratio improved to 1.17 times compared to 1.24 times, at the end of December 2025.
Speaker #2: 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.
Speaker #2: Debt maturities are also comfortably distributed over the coming years, with 128 billion maturing beyond 2031, providing the funding headroom needed for ongoing capital expenditure program.
Speaker #2: That concludes our operational and financial presentation for the first half of 2026. We're now happy to answer any questions. Thank you.
Speaker #1: 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.
Speaker #1: But the participants in this call may still click on the raise hand button or submit your questions via the Q&A box on the webinar controls in case you have other questions.
Speaker #1: So, let's open the Q&A portion with the hot topic that everyone has on their minds: systems loss. The first question is: would you have any comments on the impact of system loss recovery this allowance?
Speaker #1: Do you expect it to affect the broader cost recovery framework?
Speaker #2: Yeah, I think the directionally the objective here is to reduce the cost to consumer and ensure that the distribution network efficiently. So that is an objective, I think, we support, right?
Speaker #2: I think in a near term, eliminating the VAT on systems 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.
Speaker #1: Thank you. The next question is: could you share with us the system losses for VECO and Davao Light?
Speaker #2: In 2025, total systems loss for VECO was 6.36%, which includes the feeder loss of 4.78%. In Davao Light, it was 9.41%, including feeder loss of 5.45%.
Speaker #2: If you recall, the ERCs mandated loss cap for feeder loss is 5.5%, so both of those utilities operate underneath that cap.
Speaker #1: Thank you. Next question is: if the system loss charges 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?
Speaker #2: 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.
Speaker #2: And of course, we will share a proper assessment once there's an approved framework to actually measure against.
Speaker #1: 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?
Speaker #2: Yeah, so again, along with the last question, I think it's premature to outline specific contingency plans. Until the amendments take shape into 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.
Speaker #1: Thank you for that, Sandro. 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?
Speaker #2: So I guess the short answer is no. Systems loss recovery is a distribution-side matter between the DU and its customers, and it doesn't affect the generation charge under the PSA.
Speaker #1: Thank you. 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 Aboitiz Power?
Speaker #2: 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.
Speaker #1: Thank you. The next question is on transmission. It's 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 number 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?
Speaker #2: 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.
Speaker #1: Thank you for that. The next two questions would be on the spot market. So the first one is on reserves market. How will AP be impacted by the potential lower price ceiling for power reserves in the spot market?
Speaker #2: So the price ceiling that's being proposed is obviously lower than the market price is today. So that ceiling would obviously have a downward impact on AP.
Speaker #2: 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.
Speaker #1: Thank you. And then on LNGPH, do you have updates on the line rental issue on LNGPH?
Speaker #2: 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.
Speaker #2: So that issue was raised, actually, to ERC via PIPA through a formal position paper. ERC has acknowledged the paper. And it's in the process of resolving it.
Speaker #2: Although the timing of that resolution is uncertain at this point. And yeah, so the timing is uncertain at this point in terms of the resolution of that issue.
Speaker #1: Thank you. We have a question here on CBK. Could you provide an update on the current status of CBK's tariff application?
Speaker #2: So in order for CBK to submit a tariff, there are other conditions that have to be met first. And those two conditions relate to, number one, the establishment of a payment and settlement mechanism with ERC.
Speaker #2: And the second one is a required WESM rules amendment with the DUE, and those two things are still in the process of being finalized through public hearings and stuff like that, right?
Speaker #2: So until those two things are put in place, we are not able to submit a tariff application. But we are, I guess, doing all of the pre-work that's required so that by the time these two things are put in place, we're fully ready to submit that tariff application as quickly as possible once those conditions are met.
Speaker #1: Thank you. The next question is on plant availability. What was the reason for the lower coal plant availability in the second quarter of 2026?
Speaker #2: 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 the last couple of months, right?
Speaker #2: 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 the of both units of TVI being down.
Speaker #1: Thank you. 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?
Speaker #2: Based on the current team's estimate, we're estimating a return to service of both units by the end of by the end of August. The team is working on accelerating that return to service.
Speaker #2: But based on our latest thinking, it looks like end of August is the current estimate. In terms of the unestimate of the financial impact, we're not in a position to give a final number at this stage.
Speaker #2: As the full scope of the work that's needed to be done is still ongoing.
Speaker #1: Thank you for that. I see that Jelline's hand is raised. Jelline, you may have the floor.
Speaker #3: Hello. Good afternoon. Thank you for acknowledging the raised hand. I have a follow-up question on the discussion on line rental charges. Were you able to recognize any impact from this one?
Speaker #3: I understand that there might be other assets apart from LNGPH that might have benefited or endured higher than usual line rental charges. Can you comment on what transpired in Q2?
Speaker #2: Are you talking about the line rental charges as a result of the April map market suspension?
Speaker #3: Yes. Yes.
Speaker #2: Yeah. So I guess it's fundamentally affected us negatively, right? So the way it works is that a lot of the PSAs that we have with our customers have line rental caps.
Speaker #2: So anything above the cap, we must absorb, but we are challenging the way that line rental was computed during the market suspension. And I guess that's the crux of the issue that PIPA has raised, right?
Speaker #2: So we have, I guess, reflected the impact of that in our first half financials. And any reversal of that will be seen in the second half, if that actually happens.
Speaker #3: Okay. So that means that the relatively stronger margins is still after considering the negative impact of line rental charges.
Speaker #2: Yes. That's right. That's right.
Speaker #3: Okay. Understood. Sandro, another follow-up on the TVI. I understand that you have a lawable outages with your contracts with several views.
Speaker #2: Yes.
Speaker #3: Maybe VECO including. How much of this has already lapsed or fully consumed as of 1/2/26? And if there will be any insurance claims, expecting when could we expect that on a P&L impact basis?
Speaker #2: Yeah. On the first part of the question, so we've exhausted the outage allowance, right? So we are providing replacement power to the under the contracts where we are obligated to do so.
Speaker #2: So that the outage allowance basically expired the first half of the year, right? So now until these units return to service, we are providing replacement power.
Speaker #2: On insurance, that's still being I guess worked out and quantified, right? The amount of the potential claim there. So we're not in a position to disclose or to have any confidence there, I guess, on the timing.
Speaker #2: Of that potential claim.
Speaker #3: a follow-up question on the EPIRA amendment. I think there are several bills but I'm sure you're monitoring all of those. But I do understand that there's a lower market share limit across generation or a more punitive gross ownership.
Speaker #3: Is this something that you expect to come back or come across in your discussions with decision makers? And if so, what's the official statement from Aboitiz Power with regard to this one?
Speaker #2: Yeah. I guess, again, at this point, it's all of these things are under deliberation, right? And so I think to comment either way. And they're still being worked out with all of the stakeholders involved.
Speaker #3: Thank you. And I think lastly for me, the El Niño. Can you comment about what you're currently seeing across your hydro portfolio be it on the run of river or impounding dam?
Speaker #3: Are you worried about the impact on in terms of utilization and maybe conduit to this is your expectation on spot prices going into 1/2/27?
Speaker #3: Thank you.
Speaker #2: Okay. Yeah. So we are seeing the impact of, I guess, of El Niño in terms of generated volumes in hydro. So just to give you an idea, energy generated so far for hydro is 32% down versus sorry, for the first half of '26, it's 20% down versus the first half of '25, right?
Speaker #2: So we're expecting that to continue. And that's all, I guess, assumed in our current planning for the rest of the year. And then in terms of spot price expectations moving into 2027, I guess, just like last year where spot prices were lower than forecast for the most of the year, I think this year we're expecting that prices are going to be higher than our initial forecast for the remainder of this year.
Speaker #2: And probably into 2027, having said that, it still hasn't changed our strategy to contract our base load portfolio which we're really doing to ensure there's long-term I guess, revenue predictability on those assets, right?
Speaker #2: So today we're at 90%. And we're hoping to be at 100%, I guess, sometime next year, right? Regardless of what our near-term expectations on spot prices are.
Speaker #3: Thank you for those for your answers. Thank you.
Speaker #1: Thanks, Jelline.
Speaker #2: Thanks also.
Speaker #1: Okay. So the next question is on CAPEX. On CAPEX, you've guided for around 62 billion in CAPEX for 2026. How long do you expect the current elevated CAPEX cycle to persist?
Speaker #1: And what would you consider normalized maintenance CAPEX run rate for your generation and distribution businesses thereafter?
Speaker #2: So maybe just to be clear, the 62 billion of CAPEX that we guided for this year, consists both of MOB CAPEX and growth CAPEX.
Speaker #2: And actually, the bulk of its growth CAPEX. So of the 62, the 80 to 85 percent of that is allocated to growth. And the bulk of that is to build out the renewable energy pipeline.
Speaker #2: Primarily the JA projects, right? So I think for as long as we feel there are growth opportunities to deploy capital into, and for as long as we feel that our balance sheet can support that the debt that's going to be required to fund that CAPEX, we'll likely continue to see I guess, total CAPEX in that range, right?
Speaker #2: As far as MOB CAPEX is concerned, again, of the 62 billion, about 10 billion of that is allocated towards MOB CAPEX, which is fairly consistent on a year-on-year basis.
Speaker #1: Thank you. And then last question that was sent in is on Banfeng. On that acquisition, could you provide an update on the expected closing timeline?
Speaker #2: So the transaction still is being evaluated by the relevant government authorities in Vietnam. So we're not, I guess, in a position to provide any an update on the expected timeline as it's still moving through the Vietnamese government regulatory approvals.
Speaker #1: Thank you. I see questions on the Q&A box. The first one reads, "In relation to the retail bonds maturing in 2026, how does management plan to manage these maturities?
Speaker #1: Are there plans to refinance them to smoothen the debt maturity profile, or will these be settled using cash flows and existing liquidity?"
Speaker #2: So the current plan is to refinance. And we are I guess, looking at the various options we have to refinance those maturities.
Speaker #1: Thank you. The next question is on the Chromite acquisition. May we know how much of the remaining loans use are you how much of the remaining loans are used for the Chromite acquisition?
Speaker #1: What is the timeline to settle the remaining loans as well as the loans used for the CBK acquisition? Noting that AP also secured 70 billion bridge loans in 2025 for CBK.
Speaker #2: On Chromite, I don't have the exact number. I mean, we can email it, but most of those loans have already been have already been settled.
Speaker #2: And again, I think we can just email the exact number in response to that. As far as CBK is concerned, we are in the, I guess, in the process of injecting financing into the asset itself, right?
Speaker #2: So we're working with various banks on a project finance loan that will effectively take out the bridge debt for CBK. hopefully going to be in place sometime before the end of the year.
Speaker #1: Thank you for that. That was the last of the open question on the Q&A box. Again, may we remind everybody that if you have questions, you may click on the raise hand button or submit your questions via the Q&A box on the webinar controls.
Speaker #1: I do not see any hands raised at the moment. And there are no open questions on the Q&A box. Last call. Oh, okay. Jelline, did you have something?
Speaker #1: Please go ahead.
Speaker #3: Hello. Might as well use the time. I have a question on the distribution volumes. I noticed that it's still pretty strong as of two Qs, still up 6% year on year.
Speaker #3: Despite the guidance last quarter that it might taper off. Why do you think this growth continues to be relatively resilient?
Speaker #2: Yeah. So it's actually mixed across the utilities. So some utilities are up, some are down. If Jehan is on the call, maybe I can call on her to help provide more color in what she's seeing across the various utilities.
Speaker #3: Yeah. So hi, good afternoon. In terms of growth, a lot of our growth is really coming from our distribution utilities in the south, particularly from Davao Light and in Cotabato Light, where a lot of the industrial customers have been growing steadily and there are a lot there's a big mall that opened in Cotabato Light.
Speaker #3: And there's a lot of steel plants in the Davao area that has started operations. So the sources of these growth are expected to be sustained until the end of the year.
Speaker #3: Okay. Thank you so much. Okay.
Speaker #2: Thanks, Jelline.
Speaker #1: Okay. Thank you. One final call for questions. If none, I think we can close we can close the Q&A session for Aboitiz Power. So thank you, Sandra and Jehan, for being in the call.
Speaker #1: For the benefit of those who missed the session or would like to rewatch the event, a recording of this briefing will also be uploaded on our website.
Speaker #1: So on behalf of everybody, and the entire presentation development team, we would like to thank everybody for joining us today. For those of you who will join us also for the earnings call of AEV, see you later at 5:00 PM.
Speaker #1: And for the rest, see you again in November for our third quarter briefing. Thank you.
