Obtaining Capacity Credits
The Reserve Capacity Mechanism (RCM) ensures the WEM has adequate generation and demand-side capacity for peak demand and energy adequacy.
Expression of Interest
Optional EOI in Jan–Mar. In 2025, AEMO received 50 EOIs totalling 2,494 MW of potential capacity.
CRC Application
Apply for Peak and Flexible Certified Reserve Capacity during Apr–Jun window. AEMO assigns Facility Class & Technology Type.
CRC Assessment
AEMO notifies CRC quantities in August. Reserve Capacity Security may be required. Decide bilateral vs. market allocation.
Credits Assigned
Peak and Flexible Capacity Credits assigned in September. Network Access Quantity (NAQ) determined. Prices published.
WEM Planning Criterion
| Limb | Purpose | 2027-28 Target |
|---|---|---|
| A — Peak | Enough capacity to meet forecast annual peak demand + reserve margin | 6,238 MW |
| B — Energy | Expected unserved energy ≤ 0.0002% of annual consumption | 0.0002% EUE |
| C — Flexible | Sufficient flexible capacity for the largest 4-hour demand increase + margin | 2,527 MW |
2025 Reserve Capacity Cycle (for 2027-28)
2026 Reserve Capacity Cycle Dates
These dates apply to the 2028-29 Capacity Year (starting 1 October 2028).
WA Market Context
The 2025 WEM ESOO highlights significant investment opportunities driven by coal retirements and growing peak demand.
Key Market Drivers
- Coal closures: Collie (317 MW) in 2027, Muja D (422 MW) in 2029, Pinjar gas (522 MW) 2029–2032
- Bluewaters uncertainty: 434 MW coal plant fuel supply expires June 2026 — assumed unavailable from 2027-28
- Peak demand records: All-time max 4,486 MW on 20 Jan 2025 — 253 MW above previous record
- Battery limitations: 4-hour batteries exhausted by 8:30 PM. New storage needs 6+ hour duration
- Firm gen prioritised: At least 110 MW new gas/wind/solar required. Battery alone insufficient
- Class 1 & 3 prioritised: New firm and intermittent generation in NAQ framework
- Flexible Capacity (Limb C): Creates additional revenue for fast-ramping generation with 10-year price guarantee option
Network Investment Areas
- Eastern Goldfields: Sub-regional capacity shortfall — critical need for new supply
- North Country: CEL-North expansion for 2027-28 to enable new renewable connections
- System strength: Emerging gaps in Collie, Merredin, and North Country as thermal generation retires
- Clean Energy Link: $1.6B transmission expansion creating new connection opportunities
ROI: Sub-5 MW Behind-the-Meter
Return-on-investment analysis for deploying a sub-5 MW diesel facility behind-the-meter at an industrial estate, connecting to an 11kV distribution line. No Western Power connection costs. Pricing from AEMO's 2025 ESOO and ERA benchmark determinations.
Reference Configuration — 2× Cat 3516C
Annual Revenue — Capacity Credits
Based on actual WA prices from the 2025 ESOO. The BRCP for 2027-28 was set at $360,700/MW/year by the ERA — a 57% increase over the prior year.
| Scenario | Rate ($/MW/year) | Your 4.20 MW |
|---|---|---|
| Peak RCP (2026-27 new facilities) | $216,092 | $907,586 |
| Peak RCP (at 2025-26 level — deficit year) | $251,420 | $1,055,964 |
| BRCP ceiling (Peak + Flexible) | $360,700 | $1,514,940 |
Capital Costs (BTM + 11kV)
| Item | Low Est. | High Est. |
|---|---|---|
| 2× Cat 3516C gensets (50 Hz, 11kV alternator) | $1,500,000 | $2,000,000 |
| 11kV switchgear & protection | $80,000 | $120,000 |
| Site works, BOP, foundations, bunding | $350,000 | $550,000 |
| Permits, studies, engineering | $80,000 | $180,000 |
| Total CAPEX | $2,010,000 | $2,850,000 |
- WP Connection (Enquiry → Planning):
$275K–$690K→ $0 - WP Execution (construction, augmentation):
$500K–$1.5M→ $0 - GPS modelling & network studies:
$200K–$400K→ $0 - Total saved: $975K–$2.6M in CAPEX
Annual Operating Costs
| Item | Annual Cost |
|---|---|
| Maintenance & standby readiness (2 units) | $50,000 – $80,000 |
| Insurance | $20,000 – $40,000 |
| Site lease / host agreement | $30,000 – $60,000 |
| AEMO market fees | ~$550 |
| Total Annual OPEX | ~$100K – $180K |
Payback Scenarios (BTM — 2× 3516C)
Conservative
Peak CC only at $216K/MW
Net annual: ~$768K
CAPEX $2.33M
(mid)
Payback: ~3.0 years
Mid-Case
Peak CC at $251K/MW (deficit)
Net annual: ~$916K
CAPEX $2.33M
(mid)
Payback: ~2.5 years
Optimistic
Peak + Flexible at BRCP ceiling
Net annual: ~$1,375K
CAPEX $2.33M
(mid)
Payback: ~1.7 years
Key Takeaways
- BTM transforms the economics — eliminating WP connection costs cuts CAPEX from ~$4.5M to ~$2.3M, halving payback period
- Sub-5 MW = regulatory simplicity — no GPS, no AEMO registration, no transmission studies. Save $200K–$500K and 6–12 months
- Only 2 units to maintain — the 3516C delivers 2.10 MW per unit with a native 11kV alternator. No step-up transformer needed
- Paid to be available, not to run — CCs pay for standing ready. Diesel fuel cost is irrelevant unless dispatched in genuine emergencies
- Market is tightening — 2025-26 Peak RCP hit $251K/MW due to an 826 MW deficit. Coal closures will deepen this
- Flexible CC is the wildcard — BRCP jumped 57% to $360,700/MW. If Flexible RCP is set near that, returns improve dramatically
- Compare all options — see the Financial Model page for 5×C32 vs 3×3512C vs 3×DCP vs 2×3516C vs Megapack head-to-head