• Post-result NDR conference call – Hormuz resilience, and 3-4% CAGR volume growth during 2026-2030. 
• 10% of revenue from Middle East was not affected by US/Isarel-Iran war in 1Q26. Operation is up and run at full capacity in 2Q26TD
• 2Q-3Q26F ASP to reflect oil price hike with expected less hedging impact as geopolitical risk eases
• Maintain BUY with FY26F TP of THB174
  

1Q26-post result NDR conference call with management. On 29 May 2026, we held a post-result conference call with management from PTTEP as follows:

1. Khun Chanamas Sasnanard, CFO
2. Khun Nattapol Tachavaraporn, IR manager
3. Khun Thipapun Peanratpimol, IR officer

Key discussions are as follows;

PTTEP's five-year plan (2026–2030) is anchored on three pillars — Drive Value, Decarbonize, and Diversify — with a total budget envelope of USD33.3bn. The core thesis remains unchanged: maximize domestic gas production to underpin Thailand's energy security while simultaneously expanding the international portfolio for long-term value creation. On the domestic front, PTTEP retains an 82% market share of Thailand's gas production and targets sales volume growth from ~560 KBOED in 2026 toward a 3–4% CAGR through 2030. Strategically, the portfolio will rebalance from a 64/36 domestic/international split in 2026 toward 75/25 by 2030, with international volume nearly doubling from 133 KBOED to 249 KBOED, primarily driven by Malaysia, the Middle East, and Africa.

Operational Response & Hormuz Resilience. Management was notably candid on the Hormuz disruption narrative. Middle East operations — Oman and UAE combined — accounted for only 10% of Q1/2026 sales volume, materially limiting direct production exposure to Strait closure risk. To compensate for the energy supply shortfall at the national level, PTTEP aggressively ramped Gulf of Thailand gas delivery approximately 70 MMSCFD above the initial plan across its four key domestic blocks (G2/61, Contract 4, Arthit, MTJDA B17-01), all running beyond Contractual Delivery Capacity (CDC). Management characterized cost inflation and logistics risk from the conflict as "insignificant," which we view as a mild positive surprise relative to market concerns heading into the call.

Key E&P Project Updates. The project-level update reinforced a volume growth story weighted toward 2027–2028 catalysts. Domestically, the G3/65 block achieved a gas discovery at the Bussabong-09 well, with FID targeted in 2026 and first gas of 30–40 MMSCFD expected in 2028 — a meaningful organic optionality event for Thailand supply continuity. In Malaysia, the SK405B Sirung-Chenda FID was confirmed with EPCIC already awarded (first production 2028 at 200 MMSCFD gas / 15 KBPD oil), while Lang Lebah (SK410B, 5 TCF resource) remains under re-engineering to sharpen economics before FID. In the Middle East, the UAE Ghasha Concession reached FID on Dalma Gas, Hail & Ghasha, and SARB Deep Gas fields — a significant long-cycle development that underpins the international growth trajectory toward 2030. Algeria HBR Phase 2 FID was also confirmed, targeting a ramp from 17K to 60K BPD by 2030.

Volume Growth & Investment Roadmap. The 2026–2030 development budget stands at USD33.3bn (USD20.7bn CAPEX, USD12.6bn OPEX), supporting a production CAGR of 3–4% from ~560 KBOED in 2026 to ~625 KBOED by 2030, with peak production volume reaching ~870 KBOED on a gross basis. The key volume inflection point is 2028, when four major projects are scheduled to deliver first production simultaneously: Myanmar M3 (60 MMSCFD), Malaysia Greenfields (200 MMSCFD + 15 KBPD), G3/65 (30–40 MMSCFD), and Mozambique Area 1 (13 MTPA LNG). Vietnam Block B (490 MMSCFD by 2030) and Algeria HBR Phase 2 (60 KBPD by 2030) add further momentum into 2029–2030. The exploration budget for 2026 is a modest USD129m (9 wells), with activity concentrated in G1/65 & G3/65 seismic, Yadana exploration, and Malaysia SB412/SK325/SK314A — consistent with capital discipline given the existing development pipeline.

Key questions;
Q: With mark-to-market hedging losses weighing on reported net profit, will the board anchor FY26 dividends to normalized earnings rather than reported profit? Would PTTEP maintain its dividend payout ratio or absolute dividend during periods of oil price and earnings volatility?

A: Management emphasized that dividend decisions are based on multiple factors, including cash on hand, capex requirements, and operating expenses, rather than solely reported earnings. As an example, PTTEP maintained dividend payments despite significant non-cash impairment and write-off charges related to the Mozambique project in prior years. Therefore, the current mark-to-market hedging losses are expected to have an insignificant impact on dividend payments.

Q: The Middle East accounted for c.10% of 1Q sales volume. Can management quantify the revenue impact from the Hormuz disruption? Have any force majeure notices been issued by offtakers?

A: Management stated that there has been no operational or commercial impact from the closure of the Strait of Hormuz since March. Operators have continued to run normally, and sales deliveries to offtakers remain uninterrupted. No force majeure events have been reported.

Q: Given the expected production decline at Yadana, Sinphuhorm, and S1 during 2028–2031, could PTTEP face transition challenges similar to those experienced at the Erawan project during the concession handover?

A: Management believes the situation is different. Yadana still has reserve upside and commercialization potential beyond the current concession expiry in 2028, with ongoing exploration and appraisal drilling activities. For Sinphuhorm and S1, however, management expects production to follow the natural decline profile of mature fields, with limited remaining reserve upside under the current regulatory framework.

Our take

2Q-3Q26F to see full impact of oil price hike in ASP. Based on 1Q26 performance, low 1Q26F ASP is due to 1-2 month lagged time adjustment to oil prices. We expect liquid to fully reflect higher oil prices in 2Q26F where we expect USD6-7/bbl discount of liquid price (vs USD11-12/bbl in 1Q26F, and USD2-3/bbl in normal situation). For gas price, we expect average gas price to remain flattish in 2Q26F and rise to c.USD5.90-5.95/mmbtu (up 1-2% q/q).

We conservatively estimate 2Q26F net profit at THB21.99bn (+60% y/y, +10% q/q), assuming: i) production volume of c.560kboed (+11% y/y, +1% q/q); ii) average Dubai crude price of USD95/bbl and average gas selling price of USD6.0/mmbtu; iii) ASP of USD51.34/boe (+14% y/y, +9% q/q); iv) unit cost of USD30/boe (-3% y/y, +7% q/q); and v) a corporate tax rate of 45%

Maintain BUY. We maintain a BUY rating with an FY26F TP of THB174, based on a DCF valuation using a WACC of 11.69% and a terminal growth rate of 1%. Despite easing geopolitical risk in the Middle East from truce potential between US and Iran, we continue to favour PTTEP in the energy sector, as it is a direct beneficiary of the oil price spike stemming from escalating tensions in the Middle East, while having limited exposure to regulatory risks such as electricity tariff cuts or the potential adoption of a new pooled gas pricing mechanism. In addition, PTTEP’s medium-term outlook remains solid, underpinned by resilient production growth of c.3.5% CAGR over 2026–2030F, stable gas selling prices, and an attractive expected dividend yield of around 5%.

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