What’s Driving Energy Prices in California?
Wet year. Low energy prices.
In 2019, California’s energy prices were low, driven, in part, by the fact that it was a wet year in the West. The abundance of available snowmelt and surface water allowed for hydro facilities to generate what would otherwise have to be delivered by more expensive generation units. In dry years, 2014 for example, hydro facilities simply can’t run as often as they do in wet years and the need for marginal generation resources increases, thereby resulting in higher energy costs.
As of this writing, it is too early in the state’s water year to predict whether 2020 will be as wet as 2019 and yield similar prices as last year. In January 2020, roughly the midpoint of the current water year, California’s Department of Water Resources reported that eight of its 12 reservoirs were at or above historical average levels, with none below 91% of normal.
Low energy prices. High resources (For now)
While electricity rates in California have been traditionally high, wholesale energy prices have been low. The average cost per megawatt-hour of load decreased 44 percent to about $39/MWh for the third quarter of 2019 from $69/MWh in the same quarter of 2018. The decrease in average wholesale electric prices has been primarily driven by a 43 percent decrease in natural gas prices compared to the same quarter in 2018.
Currently, as was the case in 2019, California as a whole is an over-resourced state due to its profusion of resources on the grid that have been built to keep up with the expanding Renewable Portfolio Standards (RPS) requirements. That abundance, however, appears to be changing.
In its annual Resource Adequacy Report released in August 2019, the CPUC identified (for the first time, on record) a shortfall in system resources. The overall available capacity that can be used to meet all load-serving entities’ (LSE) resource adequacy (RA) decreased significantly due to the retirement of 3,122 MW of older gas cogeneration facilities. Increased penetration of use-limited resources on the grid has also raised RA concerns.
To alleviate the shortfall, California’s Integrated Resource Planning (IRP) and CPUC ordered 3.3 GW of system RA to be procured by all LSEs (IOUs, CCA’s and Electric Service Providers) under the CPUC’s jurisdiction and to come online between August 2021 and August 2023. Considering the California grid typically runs at about 35 GW on a non-peak day, the 3.3 GW order is substantial.
Does the current Resource Adequacy Program pass muster?
Faced with rapidly changing resource dynamics on the grid, the CPUC is conducting a regulatory proceeding to evaluate the RA program to determine if it meets the needs of California’s evolving grid. Questions the commission seeks to answer include:
- Will the current and projected resource mix ensure grid reliability?
- Will CA have enough energy available during all hours?
- What changes (if any) in counting of availability limited resources–including renewables, storage and demand response–are needed?
- Should local RA be procured centrally to ensure local reliability? If so, by whom?
- Should the flexible RA construct be adjusted?
The ongoing evaluation and subsequent debates will be a major issue to watch in 2020-2021. What results could ultimately affect the capacity valuation and participation rules of customer-sited resources including solar, storage, and demand response–both behind the meter and/or in microgrid configurations.
This post was excerpted from the 2020 State of Demand-Side Energy Management in North America, a market-by-market analysis of the issues and trends the experts at CPower feel organizations like yours need to know to make better decisions about your energy use and spend.
CPower has taken the pain out of painstaking detail, leaving a comprehensive but easy-to-understand bed of insights and ideas to help you make sense of demand-side energy’s quickly-evolving landscape.
Published by
