Natural Gas in the Philippines — Current Status Overview

Query: What is the current status of natural gas in the Philippines, covering both indigenous production (Malampaya) and the imported LNG build-out, including the regulatory framework, long-run trajectory under PEP scenarios, and key policy tensions?

I. The Core Situation

Natural gas supplied approximately 16% of total national power generation (17.9 TWh out of 111.5 TWh) in 2022 [PEP 2023-2050 Vol. I, p.53, 2023]. Almost all of this came from a single domestic source — the Malampaya gas field — which is in advanced depletion. The collapse of Malampaya output is the primary supply-side driver of the government’s entire LNG import strategy and is one of the most consequential facts shaping PEP 2023-2050 [PEP 2023-2050 Vol. I, pp.53–55, 2023].

II. Indigenous Gas: Malampaya

Field Status

The Malampaya gas field, located offshore Northwest Palawan in the South China Sea (Service Contract 38), is the Philippines’ only significant domestic natural gas resource. It has been supplying Luzon power plants since 2001 [PEP 2023-2050 Vol. I, p.54, 2023].

• Remaining reserves (as of May 2023): 147 BCF [PEP 2023-2050 Vol. II, pp.2–3, 2023]
• 2022 output: 2.6 MTOE (112.2 BSCF) — down 7.4% year-on-year [PEP 2023-2050 Vol. I, p.55, 2023]
• SC 38 renewal: President Marcos Jr. signed the renewal on 15 May 2023, extending the contract for 15 years to 22 February 2039; the consortium (operated by Prime Energy Resources Development B.V.) must drill at least two deep-water wells in Sub-Phase 1 (2024–2029) [PEP 2023-2050 Vol. II, p.3, 2023]
• GSPA expiry: The Gas Sales and Purchase Agreement for the Ilijan power plant expired on 5 June 2022, immediately removing ~1,200 MW of Luzon capacity; Ilijan resumed operations in April 2023 via imported LNG [PEP 2023-2050 Vol. II, pp.13–14, 2023]
• Long-run trajectory: DOE projects Malampaya output will fall from 2.6 MTOE (2022) to just 0.6 MTOE by 2050 (−5.3%/yr) [PEP 2023-2050 Vol. I, p.79, 2023]

Existing Gas-Fired Fleet (as of December 2022)

Five gas-fired power plants run on Malampaya gas, with a combined installed capacity of 3,730.6 MW (four plants still utilizing Malampaya gas after Ilijan’s GSPA expiry):

[PEP 2023-2050 Vol. II, p.13 fn.11, 2023]

Statutory Protection of Indigenous Priority

RA 12120 (§23) mandates that procurement and utilization of indigenous gas — including by gas-fired power plants — be prioritized over imported LNG, consistent with energy security and consumer welfare [RA 12120, §23, 2025]. Power generated from indigenous gas has statutory priority over other conventional energy sources. DOE must set a minimum percentage of electricity demand to be sourced from indigenous gas [RA 12120, §23, 2025]. The VAT regime reinforces this: indigenous gas and aggregated gas (blends with an indigenous component) are VAT-exempt, while pure imported LNG is not [RA 12120, §38, 2025].

III. Imported LNG: Build-Out Status

LNG imports are the government’s designated bridge to replace Malampaya output, maintain dispatchable capacity, and supply existing and new gas-fired plants while renewable energy scales up [PEP 2023-2050 Vol. I, Table 7, 2023].

DOE-Approved Projects (as of 7 July 2023)

Seven LNG projects have DOE approval with an aggregate capacity of 21.98 MTPA:

[PEP 2023-2050 Vol. II, Table 6, 2023]

Key Milestones (2023)

• Linseed Field received the Philippines’ first LNG delivery in April 2023 via the Ocean Glacier vessel (from UAE), enabling Ilijan to resume operations after ~8 months offline [PEP 2023-2050 Vol. II, p.14, 2023]
• FGEN’s FSRU (BW Batangas) arrived in Batangas on 16 June 2023; capacity of 162,524 m³ and regasification up to 500 MMSCFD [PEP 2023-2050 Vol. II, p.14, 2023]
• Projects are heavily concentrated in Batangas Bay, with one small-scale terminal in Mariveles, Bataan

Tax Treatment of Imported LNG

Imported LNG carries a favorable tax profile [PEP 2023-2050 Vol. II, p.17, 2023]:

• No excise tax — not enumerated under NIRC Title VI, Chapter V per BIR guidelines
• No customs duty — exempt under Section V, Chapter 27.11 of the 2017 ASEAN Harmonized Tariff Nomenclature
• No mineral product excise — RA 9337 (2005) removed the prior excise on locally extracted gas and LNG [RA 9337 (RVAT), §151, 2005]
• No VAT only if blended with indigenous gas (aggregated gas) under RA 12120; pure imported LNG does not qualify [RA 12120, §38, 2025]

IV. Regulatory Framework

From Administrative Circular to Primary Legislation

RA 12120 was signed by President Marcos Jr. on 8 January 2025 and is the first comprehensive statutory framework for the Philippine Downstream Natural Gas Industry (PDNGI) [RA 12120, §2, 2025]. See Digest: RA 12120 — Philippine Natural Gas Industry Development Act and Philippine Downstream Natural Gas Industry (PDNGI) .

Key Structural Features of RA 12120

• Two permit tracks: Own-Use Permit (exclusive capacity) and TPA Permit (third-party access) — TPA is no longer universally mandatory as it was under PDNGR [RA 12120, §18, 2025]
• No franchise required: PDNGI facilities need only a DOE Permit, not a legislative franchise (distinguishing gas from electricity transmission) [RA 12120, §18, 2025]
• Aggregation mechanism: Aggregators may blend indigenous and imported gas; DOE sets the minimum indigenous percentage; aggregated gas receives VAT exemption [RA 12120, §4(b), 2025]
• Stranded asset tracking: DOE must publicly track and report stranded asset risk for all natural gas infrastructure — the first Philippine energy law to mandate this [RA 12120, §5(r), 2025]
• Renewable gases: DOE gains regulatory authority over hydrogen, ammonia, and biomethane — also a statutory first [RA 12120, §36, 2025]
• All permits via EVOSS: Processed through the one-stop-shop system under RA 11234 [RA 12120, §5(d), 2025]
• IRR deadline: DOE must promulgate the IRR within 6 months of effectivity; codes (Transmission, Distribution, PLSR Terminal, TPA) due within 2 years of IRR effectivity [RA 12120, §49, §5(g), 2025]

V. Long-Run Trajectory: REF vs CES

The PEP 2023-2050 models two fundamentally different paths for natural gas:

[PEP 2023-2050 Vol. I, Tables 16–17, 25, 2023; PEP 2023-2050 Vol. II, p.21, 2023]

Reference Scenario (REF): Natural gas (predominantly LNG) becomes the largest single source of electricity by 2050 at 35.0% (158.8 TWh), up from 16.0% in 2022. Net LNG imports grow from zero (2022) to 24.3 MTOE by 2050 at 8.5%/yr. Under REF, the Philippines effectively trades one form of import dependency (coal/oil) for a large new structural LNG import dependency [PEP 2023-2050 Vol. I, p.75–77, 2023].

Clean Energy Scenario (CES): Offshore wind (19–50 GW) and nuclear (1,200 MW by 2032) displace a significant portion of LNG-fired generation. No additional LNG capacity beyond the seven committed projects is required. The CES minimizes LNG import exposure while improving energy self-sufficiency [PEP 2023-2050 Vol. II, p.21, 2023].

VI. Key Policy Tensions

1. Indigenous priority vs. import scale Malampaya’s 147 BCF in remaining reserves will run down well before 2039. The statutory priority for indigenous gas (RA 12120, §23) is real but cannot offset the physical depletion — the existing fleet requires LNG imports to keep running now. Indigenous gas sets the ceiling; LNG fills the rest [PEP 2023-2050 Vol. I, p.79, 2023; RA 12120, §23, 2025].

2. LNG as bridge fuel vs. stranded asset risk RA 12120 frames natural gas explicitly as a transition fuel [RA 12120, §2(h), 2025]. The same law requires DOE to publicly track stranded asset risk for every terminal and pipeline built. The seven committed LNG projects represent approximately USD 865 million in construction costs (excluding FGEN and Linseed) [PEP 2023-2050 Vol. II, Table 8, 2023]. Under CES, no further LNG investment is needed — implying the committed projects themselves carry long-run risk if OSW and nuclear are delivered on schedule.

3. GHG trajectory under REF Natural gas GHG emissions grow at 8.4%/yr under REF, rising from 6.1 MtCO₂e (2022) to 58.0 MtCO₂e by 2050 — the fastest-growing emission source in the energy system. Gas is cleaner per unit than coal, but the sheer volume of LNG required under REF erases that per-unit advantage at scale [PEP 2023-2050 Vol. I, p.80, 2023].

4. REF execution risk vs. CES execution risk REF is lower-risk on the supply side (LNG technology is proven, terminals are permitted) but locks in import dependency and GHG growth. CES requires aggressive execution of OSW permitting and nuclear commissioning — both of which face significant institutional and timeline risk. The choice between paths is therefore a choice between known import dependency and uncertain but cleaner domestic build-out. See Offshore Wind (OSW) and Nuclear Energy Program (Philippines) .