The federal transmission system regulator ruled October 21 that California can require its utilities to pay a price for renewable energy that will support its Feed-In Tariff (FIT) plan. The ruling resets the existing price standard and is expected to drive the deployment of renewable energy.
“The FERC decision will make distributed generation in general and fixed price approaches much easier,” said Adam Browning, Executive Director of The Vote Solar Initiative. Ted Ko, the FIT Coalition’s Associate Executive Director, agreed: “It’s a very important decision.”
Understanding why it is important and how it will be good for renewables requires some history.
The ruling came because the California Public Utilities Commission (CPUC) had asked the Federal Energy Regulatory Commission (FERC) to define what “avoided cost” means.
Defining “avoided cost” was necessary because when California’s SB 32 instituted the FIT for medium-sized renewable projects in 2009, it also expanded the definition of “avoided cost.”
The FiT concept came out of California’s 1978 Public Utilities Regulatory Policies Act (PURPA). It was refined by Germany in the early 2000s. It is intended to drive the building of renewable capacity by guaranteeing a fixed payment to renewable energy developers for the power their projects produce over an extended period of time.State regulators
are directed by FERC to protect the ratepayer. The CPUC therefore set California’s per kilowatt-hour electricity payment to generators of renewable energy projects of up to 20 megawatts at the lowest estimated price a utility would have to pay to obtain power from a new, industry-standard natural gas plant.
That price was dubbed a utility’s avoided cost. Note to wonks: The technical name of the avoided cost in California is the Market Price Referent (MPR). It follows utility rates in having a sliding time-of-use (TOU) (peak to off-peak) payment schedule.
With the FIT instituted by SB 32, the definition of avoided cost was expanded to include environmental factors, a hazy term that became crucial to clarify when the FIT ran into another law.
California’s AB 1613 requires utilities to purchase energy obtained through combined heat and power (CHP) generation. CHP systems recover at sites where electricity is generated and can reuse it to generate more electricity. Reusing electricity generated on-site requires no transmission.
CPUC went to FERC with a proposal that CHP users be granted a higher return on the electricity they generate because it does not further burden the transmission and distribution system nor lose electricity on the lines.
Since the inception of the FIT as an incentive to boost distributed generation (DG), advocates for renewables have argued that their generation, like CHP systems, avoids transmission and distribution burdens and losses.
FERC’s October 21 ruling surprised and pleased renewables advocates and proponents for the wider application of the FIT, like Ko and Browning.
Besides granting the higher return to CHP systems, it granted value to the “locational benefits” of distributed medium-sized projects located at or near where their power is consumed because, it acknowledged, DG avoids the costs of using existing wires and the costs of building new wires and infrastructure. There are also avoided losses along the wires and other avoided costs that follow from DG projects’ location.
This is, according to Vote Solar’s Browning, a key component for renewable energy development going forward.
FERC made, according to the FIT Coalition’s Ko, two further adjustments to the avoided cost (MPR) standard. Besides adding locational benefits to the avoided cost, it shifted the definition of avoided cost from the lowest estimated price a utility would have to pay to obtain power from a new natural gas plant to the lowest estimated price a utility would have to pay to obtain power from a comparable resource.
No longer will a renewable energy source typically used as peaking power be compared to a source typically used at off-peak hours or as a base load source. Instead, like will be compared to similar sites in setting avoided costs.
Finally, Ko said, the ruling changes how Renewable Energy Credits (RECs) are used. Every kilowatt-hour of renewable energy purchased by a utility earns it a REC that applies toward renewably-sourced electricity requirements imposed by the state Renewable Electricity Standard (RES).
According to Ko, the FERC ruling allows the price of the RECs to be unbundled from the purchase price and allotted a separate price by the CPUC, a price that captures the otherwise hazily-defined environmental benefits of renewable generation. Requiring utilities to pay extra for RECs adds to the amount that a renewable energy generator can expect to earn.
In states like California where there is no competitive REC market, the CPUC could set this additional return so that, combined with the total avoided cost (including locational benefits and comparable resource valuation), it adds up to the cost of generation plus a reasonable profit. This pricing power gives CPUC the ability to drive responsible renewable development by making it profitable.
Browning said the decision makes the implementation of SB 32 significantly easier and promises more opportunity to grow renewable energy markets.
According to Ko, if his Coaliton’s proposed FIT for California is implemented at these prices, electricity rates will rise less than one percent in the near term, and, as fossil fuel prices rise, will be five percent less than the average electricity price by 2020.
Browning said he would not be surprised to see the FERC ruling challenged in court.