RPS Mechanism
Prerequisites
Thirty US states have renewable portfolio standards requiring utilities to source a specified percentage of their electricity from renewable sources by a target date. Texas's RPS, enacted in 1999, set a target of 10 GW of renewable capacity by 2025. Texas hit that target in 2009, sixteen years early. California's requires 60% renewable electricity by 2030 and 100% clean electricity by 2045.
An RPS works through mandates and tradeable certificates. Utilities must prove compliance by retiring Renewable Energy Certificates (RECs), each representing 1 MWh of renewable generation. Utilities can generate their own renewables, purchase RECs on the open market, or sign PPAs with renewable developers. States that fall short face financial penalties, typically $50-100/MWh of shortfall.
REC markets. A wind farm in Kansas generates 1 MWh and receives one REC. It sells the electricity into the wholesale market and the REC separately to a utility in Missouri that needs to meet its RPS obligation. The REC price (typically $1-20/MWh depending on the state) is the premium the market puts on "renewable" versus generic electricity.
Why do REC prices vary so much across states?
Supply and demand within each state's compliance market. States with aggressive targets and limited in-state renewables (like Massachusetts) have high REC prices ($30+/MWh). States with abundant wind or solar and modest targets (like Texas) have REC prices near zero because supply exceeds the mandate. The REC price is a real-time indicator of how binding the RPS constraint actually is.
Texas set an RPS target of 10 GW by 2025 and achieved it in 2009. This outcome suggests:
Texas's wind boom was driven primarily by excellent wind resources and federal production tax credits. The RPS created initial momentum, but market economics carried deployment far past the target, illustrating that mandates can become non-binding when technology costs fall fast enough.
The answer is CLesson complete
Next: CES vs RPS→This unlocks