The total estimated wholesale cost of serving load in 2017 was about $9.3bn, or about $42/MWh, which represents an increase of about 25% from wholesale costs of about $34/MWh in 2016, according to the California ISO Department of Market Monitoring’s (DMM) “2017 Annual Report on Market Issues & Performance.”
After normalizing for natural gas prices and greenhouse gas compliance costs, DMM estimates that total wholesale energy costs increased by about 4%, according to the report.
The report noted that various factors contributed to the increase in total wholesale costs, including:
- Increased prices for natural gas, especially in southern California
- High temperatures and associated loads during the summer
- Reduced supply offered into the day-ahead market
- Increased ancillary service requirements
- Increased congestion during some intervals
The report found that the ISO and energy imbalance markets continued to perform efficiently and competitively overall last year. The report added that DMM concludes that overall wholesale prices in 2017 reflect the efficient and competitive conditions that exist during most hours of the year, but the tightening of supply and demand conditions observed last year has created the increased potential for uncompetitive market outcomes in 2018 and beyond.
Discussing key highlights, the report said:
- Average hourly prices in the day-ahead and real-time markets now mirror the net load pattern throughout the year – with the highest prices during the morning and evening ramping hours, and some of the lowest prices during midday hours when solar output is highest
- For the first time, negative system marginal prices were relatively frequent in the day-ahead market. Prices fell below zero in over 110 hours in 2017, all during midday hours in the first two quarters with high levels of solar generation and high hydro conditions. In comparison, day-ahead system marginal energy prices were negative during only three hours during all of 2016
- Day-ahead prices reached historic highs during some hours. On Sept. 1, day-ahead market prices reached over $770/MWh and were greater than $200/MWh during a four-hour period. Those high day-ahead prices reflect a tightening of supply conditions during peak ramping hours that DMM expects will continue in 2018 and the coming years
- Expansion of the energy imbalance market (EIM) helped improve the overall structure and performance of the real-time market in the ISO and other participating balancing areas. Portland General Electric became a participant in the EIM on Oct. 1, 2017, which added transfer capability to the ISO from the Northwest region – that also includes PacifiCorp West and Puget Sound Energy
- Payouts to holders of auctioned congestion revenue rights (CRRs) exceeded the auction revenues by more than $100m in 2017, and by about $42m in 1Q18. Those losses are borne by transmission ratepayers who pay for the full cost of the transmission system through the transmission access charge (TAC). Those losses now total more than $750m since the start of the ISO’s CRR auction in 2009. Most of those losses stem from CRRs bought in the auction by purely financial entities, instead of generators that may be purchasing those as hedges
The report noted that DMM continues to recommend that the ISO continue the process of allocating CRRs to load-serving entities that pay for the transmission system through the TAC, but that the ISO stop auctioning off additional CRRs that are backed financially by transmission ratepayers through the congestion revenue balancing account, the report said. DMM also continues to recommend that the ISO move swiftly to replace the current CRRs auction with a voluntary market for financial contracts based on bids from willing buyers and sellers, the report said.
Discussing other factors that contributed to increased wholesale energy costs in 2017, the report noted that congestion on transmission constraints within the ISO system was relatively frequent in the third and fourth quarters, primarily impacting San Diego Gas and Electric load area prices in day-ahead and 15-minute markets. Average annual day-ahead prices in that area increased above the system average by about 90 cents/MWh (2.5%), and real-time congestion increased prices by about $1.50/MWh (4%).
The report said that key aspects of market performance and issues relating to longer-term resource investment, planning, and market design involve that:
- About 3,000 MW of summer peak gas-fired capacity retired in 2017, with an additional 600 MW of gas generation submitting an intent to retire in 2018
- About 770 MW of summer peak generating capacity was added in 2017, and all of that capacity was renewable, primarily new solar generation
- Solar energy is expected to continue to increase at a high rate during the next few years as a result of projects under construction to meet the state’s renewable portfolio standard. That continues to increase the need for flexible and fast-ramping capacity that can be dispatched by the ISO to integrate increased amounts of variable energy efficiently and reliably
Among other things, the report noted that DMM has recommended that the ISO begin to consider various actions that might be taken to reduce the likelihood of conditions in which system market power may exist and to mitigate the impacts of any system market power on market costs and reliability.
In 2017, the day-ahead market was not structurally competitive in a growing number of hours and prices reached record highs in some hours, the report said, adding that tighter supply conditions in 2018 are likely to create additional potential for the exercise of system market power not subject to mitigation.
DMM has provided some initial suggestions for actions for reducing and mitigating the potential for system market power that might be considered, including to:
- Set local and system resource adequacy requirements sufficiently high to ensure both reliability and reduced likelihood of non-competitive market outcomes
- Reexamine resource adequacy provisions relating to imports, which are only required to be bid into the day-ahead market – at any price – and do not have any further obligation if not scheduled in the day-ahead energy or residual unit commitment process
- Closely monitor for potential errors or software issues affecting market power mitigation
According to a June 11 market notice, DMM has scheduled a stakeholder web conference on June 14 to discuss the analysis and findings of its report.