In the 1990s, regional dissatisfaction with cost-of-service retail rates and lack of infrastructure investment led to industry restructuring and the creation of ISO New England. The ISO helped introduce a new industry framework in the region: competitive wholesale markets. (Learn about ISO New England’s responsibility for administering the region’s wholesale electricity markets.) Coupled with open access to transmission lines, competitive markets created a level playing field for buyers and sellers of wholesale electricity and helped transfer the risk in developing new power resources to investors and away from retail customers. Competitive markets also created an incentive for owners to build and run these plants as cost-effectively as possible.
Today, New England’s wholesale electricity markets continue to produce competitive prices that accurately reflect suppliers’ costs of delivering power to the grid to meet consumer demand and signal when new infrastructure is needed in the region.
With about 50% of the region’s generators able to run on natural gas, the price of this single fuel sets the energy market price most of the time. The high efficiency of natural-gas-fired generators and the generally low cost of nearby domestic shale gas (which emerged as a resource in 2008) are largely responsible for a 46% decrease in the average annual price of New England’s wholesale electricity over the past 10 years. Lower wholesale prices translate into lower power-supply charges for consumers.
Higher real-time power prices in 2013, 2014, and 2018 were largely due to spikes in natural gas prices during wintertime natural gas delivery constraints. When natural gas is constrained and at a premium, oil generation becomes more economic. High prices are an expected and efficient market outcome when system conditions are tight—signaling a system need. Price volatility becomes more acute as constraints on energy supply become more severe.
The energy market value rises and falls due to changes in fuel costs for the region’s generating fleet, as well as in consumer electricity demand. While 2017 recorded the second-lowest average annual energy-market prices in over a decade, natural gas prices rose in 2018 and pushed wholesale electricity prices up. Still, the total wholesale energy market value of $6.0 billion was down 19% from the first full year of wholesale market operations in 2004, and 50% from the 2008 value. The region should expect to see the annual energy-market value continue to decline over time as renewable resources drive down energy-market prices.
Nevertheless, prices in winter will continue to exhibit volatility reflective of the fuel and weather constraints that limit the ability of power resources to produce electricity during extended cold conditions. Natural gas delivery constraints during the cold spell that spanned the end of 2017 and beginning of 2018 significantly affected energy-market prices. The region's wholesale energy market was valued at $992 million for the two-week period from December 26 to January 8, compared with $243 million during the same time the prior year. Over the course of the entire winter, the energy market was valued at $2.6 billion, with approximately 38% of that coming during the cold snap. At a total wholesale electricity cost of $466 million, the first week of January was the costliest week of 2018.
Wholesale costs and retail rates can vary dramatically among the New England states and from year to year, mainly because wholesale and retail electricity markets are used to obtain different products. Wholesale market costs reflect the short-term market for electric energy and wholesale production capacity, whereas retail prices reflect the longer-term, fixed-price contracts for energy, the recovery of the costs to pay for the distribution system, and various policy-driven adders. Wholesale market costs are relatively consistent across the New England states (ranging from 7.48 cents/ kilowatt-hour (kWh) to 7.81 cents/kWh in 2018), due in large part to the region’s robust transmission system and its ability to move the lowest-cost power across the region. Retail power supply rates on the other hand vary significantly across the New England states (ranging from 8.92 cents/kWh to 13.51 cents/kWh in effect on January 1, 2019), due in large part to the vastly different power procurement practices of each state and the utilities within each state. (Source: 2018 Report of the Consumer Liaison Group).
The increasingly efficient fleet attracted by the region’s competitive markets, together with the region’s revitalized transmission system, have driven striking decreases in congestion costs and uplift costs, called Net Commitment-Period Compensation (NCPC). Additionally, the ISO has not had to use special reliability contracts since 2010. See the chart illustrating these lower costs on the Key Stats: Transmission page.
Annual auctions in the Forward Capacity Market (FCM) ensure the system has sufficient resources to meet future electricity demand. Obligations to provide capacity are determined through these auctions three years before the commitment period. Resources that clear receive monthly payments during the capacity year in exchange for their commitment to be available to meet the projected demand for electricity. That delivery period is called the capacity commitment period (CCP)—a one-year timeframe from June 1 through May 31 of the following year. There are also monthly capacity auctions as the year of need gets closer.
While the energy-market value varies with fuel prices, the capacity market value varies with changes in amounts of supply competing to provide capacity. (The FCM compensates resources for taking on an obligation to meet the region’s electricity needs approximately three years after the annual auction is held.) The capacity market value over the past two years was higher, reflecting a rash of generation retirements that led to a smaller amount of competing supply and thus higher prices. Strong competition has generally kept capacity market auction prices low for most years. However, as energy-market revenues decrease over time, the prices in the capacity and ancillary markets will likely rise to cover the costs for resources that rely solely on market revenue (i.e., without state- and federal-based incentives) and are needed to balance renewable resources and provide energy security, particularly in winter.
For the ISO’s capacity market to function as designed and incentivize competitive resource development in New England, prices need to accurately and transparently reflect the true costs of building and operating resources. However, sponsored resources with contracts that guarantee revenues can bid into the market at below-market prices and thereby suppress prices for all other resources. Depressed prices can drive resources with higher costs out of business or discourage the development of the nonsponsored resources and new technologies needed to satisfy New England’s electricity needs, balance intermittent renewable generation, and provide grid-stability services.
The ISO has implemented an enhancement to the capacity auction called Competitive Auctions for Sponsored Policy Resources (CASPR) to ensure that the capacity market continues to reflect accurate resource costs. CASPR establishes a competitive market mechanism through which sponsored resources can compete to buy out the capacity supply obligations held by older, higher-emitting generators seeking to retire.
CASPR provides a path into the capacity market for sponsored resources, maintains competitive pricing, and reduces the likelihood of expensive procurement of more power resources than the region needs. By ensuring a level playing field for power resources that don’t receive state incentives, CASPR also minimizes the potential for one state’s consumers to bear the costs of other states’ subsidies. The ISO ran the first substitution auction in Forward Capacity Auction #13 in February 2019, covering the capacity commitment period of June 1, 2022, through May 31, 2023.
| Auction Commitment Period |
Total Capacity Acquired (MW) | New Demand Resources (MW)1 |
New Generation (MW)2 |
Clearing Price ($/kW-month) |
|---|---|---|---|---|
| FCA #1 in 2008 for CCP 2010/2011 | 34,077 | 1,188 | 626 | $4.50 (floor price) |
| FCA #2 in 2008 for CCP 2011/2012 | 37,283 | 448 | 1,157 | $3.60 (floor price) |
| FCA #3 in 2009 for CCP 2012/2013 | 36,996 | 309 | 1,670 | $2.95 (floor price) |
| FCA #4 in 2010 for CCP 2013/2014 | 37,501 | 515 | 144 | $2.95 (floor price) |
| FCA #5 in 2011 for CCP 2014/2015 | 36,918 | 263 | 42 | $3.21 (floor price) |
| FCA #6 in 2012 for CCP 2015/2016 | 36,309 | 313 | 79 | $3.43 (floor price) |
| FCA #7 in 2013 for CCP 2016/2017 | 36,220 | 245 | 800 | $3.15 (floor price) NEMA/Boston: $14.99 |
| FCA #8 in 2014 for CCP 2017/2018 | 33,712 | 394 | 30 | $15.00/new & $7.025/existing |
| FCA #9 in 2015 for CCP 2018/2019 | 34,695 | 367 | 1,060 | System-wide: $9.55 SEMA/RI: $17.73/new & $11.08/existing |
| FCA #10 in 2016 for CCP 2019/2020 | 35,567 | 371 | 1,459 | $7.03 |
| FCA #11 in 2017 for CCP 2020/2021 | 35,835 | 640 | 264 | $5.30 |
| FCA #12 in 2018 for CCP 2021/2022 | 34,828 | 514 | 174 | $4.63 |
| FCA #13 in 2019 for CCP 2022/2023 | 34,839 | 654 | 8373 | $3.80 |
1 Not counted as new is the demand-resource type once known as real-time emergency generation (RTEG). RTEG resources, which participated in FCAs #1 through #7, were treated as existing capacity and capped at 600 MW.
2 Some new capacity reflects increased capacity at existing resources.
3 This total includes new generation acquired in both the primary auction (783 MW) and substitution auction (54 MW).
Zones
Pricing
Capacity Procurement
More information can be found on these pages of the FCM Participation Guide: About the FCM and Its Auctions and Installed Capacity Requirement.
