ISO-NE market monitor report: Total cost of wholesale electricity markets was $9.1bn in 2017

ISO New England (ISO-NE), in a May 17 “ISO Newswire” post, said that the 2017 Annual Markets Report that was issued by the Internal Market Monitor at ISO-NE, found that the region’s wholesale power markets were competitive in 2017.

ISO-NE said that according to the report, the total cost of wholesale electricity markets was $9.1bn last year, representing an approximate 20% increase over the record-low costs in 2016.

According to the report, that increase was substantially due to higher capacity market costs associated with the eighth forward capacity auction (FCA 8), which took effect during the second half of 2017. Capacity costs increased by $1.1bn, or by 93%, on 2016 costs, the report noted, adding that up until FCA 8, capacity prices were relatively low and set administratively at the market floor prices due to surplus capacity conditions.

Capacity costs represent an increasing share of overall wholesale costs – increasing from 15% in 2016 to 25% in 2017 – and will increase further in 2018, to an estimated $3.5bn, as higher capacity prices from FCA 9 take effect, the report said.

Capacity costs will begin to decline after June 2019, as new resources enter the market and a higher capacity surplus applies downward pressure to capacity prices, according to the report.

ISO-NE, in its May 17 post, noted that energy costs made up $4.5bn of the total $9.1bn, with both capacity costs and regional network load costs at $2.2bn in 2017. The costs for such reliability services as operating reserve, regulation, and net commitment period compensation, totaled about $200m, ISO-NE noted.

According to the report, the $4.5bn of total energy costs in 2017 went up 9% from 2016. The report noted that the increase in energy costs was driven by higher natural gas prices, which averaged $3.72/MMBtu, up 19% on 2016 prices. The upward pressure of natural gas prices on energy costs was mitigated by lower wholesale electricity demand, particularly in 3Q17, the report said.

Further discussing the $4.5bn of total energy costs, the report noted that:

  • Day-ahead and real-time locational marginal prices (LMPs) averaged $33.35/MWh and $33.94/MWh, respectively – simple average. Compared with 2016, prices were up by between 12% to 17%, or by $3.58/MWh to $4.99/MWh, in the day-ahead and real-time market, respectively
  • Supply and demand-side participants continued to exhibit a strong preference towards the day-ahead market, with about 97% of the cost of energy settled on day-ahead prices
  • Demand – or real-time load – was at its lowest in the past 18 years. Demand was down by 2% in 2017, or by 341 MW per hour, compared to 2016. The largest reduction was observed in 3Q17, when demand was down by 8%, or by nearly 1,280 MW on average per hour, compared to the prior year. The trend of declining load can be explained by seasonal temperature differences year-over-year, the increase in energy efficiency programs, and the strong growth in behind-the-meter solar generation

The report also noted that ISO-NE in March 2017 implemented fast-start pricing rules to better reflect the costs of operating fast-start resources through the real-time price and to strengthen performance incentives. The changes have had the effect of increasing real-time LMPs, reducing uplift – or net commitment period compensation (NCPC) – payments and increasing operating reserve payments, the report said. Additionally, since fast-start pricing mechanics are not applied in the day-ahead market, it is expected that higher real-time LMPs may increase the opportunity for virtual demand to converge day-ahead and real-time prices, the report said, noting that since the implementation of fast-start pricing, offered and cleared virtual demand bids increased.

The ISO and stakeholders also made significant progress in 2017 in developing a mechanism designed to protect competitive capacity market pricing while accommodating the entry of state-sponsored renewable resources, the report said. The rules underpinning that initiative, known as Competitive Auctions with Sponsored Policy Resources (CASPR), were recently approved by FERC and will be implemented for FCA 13, the report said.

The design will continue to rely on the minimum offer price rule (MOPR), with the intention of protecting competitive pricing in the primary auction, the report said, noting that a new secondary auction will follow the running of the primary auction, in which the MOPR will not be applied. In the secondary auction, resources that are willing to exit the capacity market will trade their capacity supply obligation (CSO) position with new state-sponsored resources that did not receive a CSO in the primary auction, the report said. Concern remains about how effective CASPR will be in protecting competitive capacity market prices over time and will need to be analyzed and monitored closely, according to the report.

The FCM and the energy market exhibited competitive outcomes despite the presence of structural market power, according to the report, which also noted that measures are in place in both of those markets to identify and mitigate market power.

Among other things, the report noted that three categories of capacity resources participate in the FCM. Generation resources make up 87% of total capacity – about 29,400 MW – with the remainder comprising import – 4%, or about 1,200 MW – and demand response – 9%, or about 3,040 MW, the report said. Overall demand response capacity has fluctuated in recent years, with retirements of active demand resources being offset by the new entry of passive demand resources – energy efficiency, the report said.

Combined, gas and gas/oil dual-fuel generators accounted for 54% of total average generation capacity, the report said, adding that coal generation had the largest year-over-year decrease due to the retirement of Brayton Point in June 2017. Coal accounted for 1,350 MW in 2017, down from 2,000 MW in the previous four years, the report said. Similar to 2016, in 2017, nuclear generation accounted for 4,000 MW – 13% ­­– of the capacity fuel mix, the report said, noting that the retirement of the Pilgrim nuclear facility – about 690 MW – in 2019 will reduce nuclear capacity and energy further.

The report also listed market enhancement recommendations, including for ISO-NE to develop and maintain a database of corporate relationships and asset control that allows for accurate portfolio construction for the purpose of identifying uncompetitive participation, including the potential exercise of market power and market manipulation.

Also, the report recommended that ISO-NE develop and implement processes and mechanisms to resolve the market power concerns associated with exempting all or a portion of a forward reserve resource’s energy supply offer from energy market mitigation.

Another recommendation calls for ISO-NE to make available to the market the metrics that describe the accuracy of the new baseline methodology for demand resources. The planned implementation date for a new methodology for determining demand-resource baselines is June 1, at which time new market rules will become effective that will fully integrate dispatchable demand resources into the day-ahead and real-time markets, the report added. The new methodology’s predictive ability in estimating a resource’s actual load should be made transparent to the market, the report said.

About Corina Rivera-Linares 2807 Articles
Corina Rivera-Linares, chief editor for TransmissionHub, has covered the U.S. power industry for the past 13 years. Before joining TransmissionHub, Corina covered renewable energy and environmental issues, as well as transmission, generation, regulation, legislation and ISO/RTO matters at SNL Financial. She has also covered such topics as health, politics and education for weekly newspapers and national magazines. She can be reached at corinar@pennwell.com.