PDP 2023-2050 Ch.2 — CEM Methodology, Demand Forecasts, Scenario Definitions

Source: raw/_pdf/planning-docs/pdp-2023-2050.pdf, document pages 49–63 (PDF offset 0).

Coverage

• Section 1: Methodology — PLEXOS® CEM, 4-step process
• Section 2: Data Inputs — demand/supply assumptions, electricity sales forecast, peak demand forecast, generator parameters, capacity additions (committed projects Table 29)
• Section 3: CEM Simulation — settings, reserves, nodal assumptions
• Section 4.1–4.2 intro: Scenario definitions and results overview

Key Findings

1. CEM Methodology

Tool: PLEXOS® (Energy Exemplar) — least-cost optimization software used by 350+ organizations in ~60 countries [PDP 2023-2050, p.49, 2025].

Philippine Capacity Expansion Model (CEM): Built per-power-plant. Runs hourly from 2022 to 2050 across three nodes (Luzon, Visayas, Mindanao single-bus approach). Off-grid excluded. Year 2022 set as technical base year [PDP 2023-2050, pp.50–60, 2025].

4-step process: Data Gathering → Scenario/Assumptions Creation → Model Generation/Simulation → Modification (iterative refinement) [PDP 2023-2050, p.50, 2025].

RE profiling: Solar and wind profiled hourly using weather data (Renewables Ninja); hydro/geothermal/biomass monthly-profiled. Solar and wind plants clustered by regional location [PDP 2023-2050, p.56, 2025].

New build cost basis: NREL 2022 Annual Technology Baseline (ATB) database. RE capacity limits set by CREZ potential and DOE-awarded service contracts as of April 2023. Coal excluded from new build options (moratorium alignment) [PDP 2023-2050, p.56, 2025].

2. Key Assumptions (Table 25)

Demand forecast methodology: bottom-up sectoral disaggregation (household, commercial/services, industrial, other) per grid [PDP 2023-2050, pp.52–53, 2025].

3. Electricity Sales Forecast (Table 26)

AAGR 2022–2050: 5.4% (CES); 5.3% (REF)

Key milestones (CES):

By 2050 Luzon holds 70.8% share; Visayas 15.6%; Mindanao 13.6% [PDP 2023-2050, Table 26, 2025].

4. Peak Demand Forecast (Table 28)

AAGR 2022–2050: 5.2% overall (Luzon 5.0%, Visayas 5.6%, Mindanao 5.5%)

Load factors (6-year average 2016–2022): Luzon 70.2%, Visayas 70.2%, Mindanao 68.7%.

[PDP 2023-2050, Table 28, 2025]

5. Committed Power Projects (Table 29, as of 30 April 2023)

The committed projects list is one of the two capacity categories in the CEM (alongside new builds). Notable committed capacity by grid [PDP 2023-2050, Table 29, 2025]:

Luzon committed coal (1,900 MW) — the final pre-moratorium pipeline:

• Mariveles Coal-Fired Power Plant Phase I: 600 MW (Units 1-3: Aug 2023–Jan 2024; Units 4-8: May 2024–Sep 2026)
• Mariveles Coal-Fired Power Plant Phase II: 600 MW
• Masinloc Power Plant expansion: 700 MW (Unit 4 Jun 2025, Unit 5 Dec 2025)

Luzon committed natural gas (2,412.5 MW):

• Batangas Combined Cycle Power Plant Phase 1: 1,312.5 MW (Sep 2024)
• Natural Gas-Fired Power Plant: 1,100 MW

Luzon committed geothermal (411 MW): Kalinga Phase 1/2/3 (40 MW each, 2030–2034), Labo (105 MW), Palayan Binary, Tanawon, Tiwi Binary, Maibarara 3, Bacman 4, Kayabon, Mt. Malinao

Luzon committed solar (2,095 MW): Multiple projects; largest: Santa Rosa NE2 (280 MW), Concepcion Tarlac 2 (200 MW), Tayabas (450 MW), Sapang Balen clusters (5×92 MW)

Luzon committed BESS (1,504 MW+): 30+ NGCP-linked BESS sites; most targeting Jul 2023–Sep 2024 COD

Visayas committed coal (135 MW): Palm Concepcion Coal-fired Power Plant (Jun 2026)

Visayas committed geothermal (131.6 MW): Biliran Units 1-5, Northern Negros, Mahanagdong Brine Optimization, Dauin

Visayas committed BESS (300 MW): Ormoc BESS (2×300 MW, Jul 2023)

Mindanao committed coal (270 MW): Misamis Oriental CFB Plant (Mar 2027)

Mindanao committed BESS (280 MW): 14 BESS projects, mostly 20 MW each (2023-2025)

6. CEM Reserve Settings

Three reserve tiers modeled [PDP 2023-2050, p.60, 2025]:

• Regulating reserve: 4% of peak demand per grid
• Contingency reserve: capacity of the largest running generating unit per grid
• Dispatchable reserve: capacity of the 2nd largest running generating unit per grid

NGCP ancillary service procurement plan reflected in reserve provisions.

7. Nodal / Interconnection Assumptions

3-node single-bus model (Luzon, Visayas, Mindanao). Interconnections modeled [PDP 2023-2050, pp.60–61, 2025]:

8. Scenario Definitions

Three scenarios [PDP 2023-2050, pp.61–62, 2025]:

Reference Scenario: 35% RE generation by 2030, 50% by 2040 (NREP targets). Baseline for policy evaluation. No nuclear, no coal repurposing, no OSW targets beyond NREP.

CES 1 (Low Offshore Wind): >50% RE by 2050; OSW 19 GW by 2050; Nuclear 1,200 MW by 2032 → 2,400 MW by 2035 → 4,800 MW by 2050; coal repurposing of existing plants.

CES 2 (High Offshore Wind): Same nuclear and coal repurposing as CES 1; OSW 50 GW by 2050; >50% RE by 2050.

Both CES scenarios incorporate: 12–15% natural gas share for flexibility; ~20,000 MW BESS (1H/2H/4H duration) for grid stability and VRE integration. All scenarios meet NREP 35%/50% targets [PDP 2023-2050, pp.62–63, 2025].

Coal repurposing: DOE engaged multilateral development partners on financing; stakeholder forums planned as of February 2025. Hydrogen, ammonia co-firing, and ocean thermal excluded from current model runs but flagged for future scenarios.

Scale-up required: 5× existing capacity by 2050 (REF/CES 1); 6× (CES 2) [PDP 2023-2050, p.62, 2025].

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