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.

Wholesale Electricity Prices Are Historically Low; Constrained Fuel Supplies Drive Price Spikes

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.

Fast Stats
  • More than 500 buyers and sellers in the wholesale electricity marketplace
  • $9.8 billion traded in wholesale electricity markets in 2018 (data subject to adjustments): $6.0 billion in energy markets and $3.8 billion in capacity and ancillary services markets
  • About 77% of real-time pricing set by marginal natural-gas-fired generators in 2018, with hydro setting price next most often (14%)

Average Annual Price of Wholesale Electricity

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 Largest Driver of Wholesale Energy Cost

Annual Value of Wholesale Electricity Markets Declined 50% Over the Past Decade

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.

Annual Value of Wholesale Electricity Markets

*2018 data are subject to adjustment
Source: 2018 Report of the Consumer Liaison Group
Note: Forward Capacity Market values shown are based on auctions held roughly three years prior to each calendar year.

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 Energy Costs during Winter 2017-2018 Compared to Winter 2016-2017

Retail Electricity Rates Reflect Different Policy Choices of the Individual States

priceWholesale 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).

Markets Have Worked in Tandem with Transmission Improvements to Help Lower Energy Costs

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.

The Capacity Market Is Attracting Power Resources; Prices May Rise With Changing Resource Mix

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.

Accommodating Publicly-Funded Resources While Maintaining Competitive Markets

windFor 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.

More About the Region’s Capacity Auctions

  • For the first seven auctions, excess capacity in the region helped keep prices relatively low.
  • The eighth Forward Capacity Auction (FCA #8) concluded with a small deficit in necessary power system resources, resulting in higher prices to meet consumer demand in New England in CCP 2017/2018. Read “Finalized Auction Results Confirm Slight Power System Resource Shortfall in 2017–2018.”
  • In FCA #9, a new sloped demand curve was implemented, allowing the region to procure a level of capacity resources within a range, depending on price and reliability needs. FCA #9 concluded with sufficient resources for CCP 2018/2019 in most of the region but with a shortfall in Southeastern Massachusetts and Rhode Island. Clearing prices were higher than in previous auctions, reflecting the need for new resources to ensure a reliable supply of power in New England during CCP 2018/2019. Read “Annual Forward Capacity Market Auction Acquires Major New Generation Resources for 2018-2019.”
  • FCA #10, conducted in February 2016, yielded a clearing price that was more than 25% lower than the previous year’s $9.55/kW-month for most resources. The lower clearing price demonstrates strong competition among resources and also illustrates that the capacity market is continuing to work: higher prices resulting from resource shortfalls in earlier auctions provided the incentives for developers to bring new—and needed—resources to the market. Read “ISO-NE Capacity Auction Secures Sufficient Power System Resources, At a Lower Price, for Grid Reliability in 2019-2020.”
  • FCA #11, conducted in February 2017, produced a clearing price for all three capacity zones of $5.30 per kilowatt-month, the lowest since 2013. No large new generators cleared in the auction, but 640 MW of new energy-efficiency and demand-reduction measures—the equivalent of a large power plant—cleared and will be available in CCP 2020/2021, as did 6 MW of new wind power and 5 MW of new grid-connected solar power. Read “Finalized Results Confirm 11th Capacity Auction Procured Sufficient Resources, at the Lowest Price in Four Years, for 2020–2021” for details.
  • FCA #12, conducted in February 2018, produced the lowest clearing price in five years. The auction acquired 30,011 MW of generation, including 174 MW of new generation, primarily in increased output at existing power plants. The auction also procured 514 MW of new energy-efficiency (EE) and demand-reduction (DR) measures. In all, about 3,600 MW of EE and DR cleared. Read the press release for more: “Finalized Results Confirm 12th Capacity Auction Procured Sufficient Resources for 2021–2022.”
  • FCA #13, conducted in February 2019, was the first to include a secondary substitution auction under the CASPR rules. The primary auction (FCA #13) closed at a preliminary clearing price of $3.80 per kilowatt-month (kW-month) across New England, compared to $4.63/kW-month in the 2018 auction. The substitution auction closed with Vineyard Wind, an offshore wind project in development off the coast of Massachusetts, assuming an obligation of 54 MW from an existing resource that will retire in 2022-2023. Read more in the press release: “New England’s Forward Capacity Auction Closes with Adequate Power System Resources for 2022-2023.

Results of the Annual Forward Capacity Auctions

Commitment Period
Total Capacity Acquired (MW) New Demand Resources
New Generation
Clearing Price
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 &
FCA #9 in 2015 for CCP 2018/2019 34,695 367 1,060 System-wide: $9.55
$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).

Please note:


  • In FCAs #1 through #6, Rest-of-Pool (ROP) included Massachusetts, Connecticut (CT), New Hampshire (NH), Vermont (VT), and Rhode Island (RI); Maine (ME) was a separate zone.
  • In FCAs #7 and #8, ROP included western and central Massachusetts (WCMA), Southeast Massachusetts and Rhode Island (SEMA/RI), NH, and VT. CT, Northeast Massachusetts/Boston (NEMA/Boston), and ME were separate zones.
  • In FCA #9, ROP included WCMA, VT, NH, and ME. CT, NEMA/Boston, and SEMA/RI were separate zones.
  • In FCA #10, ROP included WCMA, CT, ME, NH, and VT; the new Southeast New England (SENE) zone combined NEMA/Boston and SEMA/RI.
  • For FCA #11, the region was divided into three zones: Northern New England (NENE), including VT, NH, and ME; Southeast New England (SENE), including Northeastern Massachusetts, Greater Boston, and the former SEMA/RI zone; and ROP, including CT and WCMA.
  • For FCA #12 and #13, the region was divided into three zones: Northern New England (NNE), including VT, NH, and ME; Southeast New England (SENE), including Southeastern Massachusetts, Rhode Island, Northeastern Massachusetts, and Greater Boston; and ROP, including CT and WCMA. NNE was modeled as an export-constrained zone, while SENE was modeled as an import-constrained zone.


  • In FCAs #1 through #7, the auction had a floor price. If the auction closed at the floor price with surplus supply, resources could choose to pro-rate the amount of megawatts they provided or receive the pro-rated price. When the floor price was eliminated starting with FCA #8, the option of pro-ration was no longer needed.
  • In FCA #7, the NEMA/Boston zone cleared at $14.99/kW-month, which will be paid to new capacity; existing capacity will receive an administratively set price of $6.66/kW-month in 2016/2017.
  • In FCA #8, the auction cleared at $15.00/kW-month, which will be paid to new capacity in all zones and existing capacity in NEMA/Boston; existing capacity in all other zones will receive an administratively set price of $7.025/kW-month.
  • From FCA #9 on, a sloped demand curve has been used, allowing more or less than the capacity requirement to be procured, depending on price and reliability needs.
  • In FCA #9, administrative pricing rules were triggered in the SEMA/RI zone due to inadequate supply. New capacity in the zone will receive the auction starting price of $17.73/kW-month and existing capacity in the zone will receive an administratively set price of $11.08/kW-month.
  • In FCA #10, all resources within New England and Quebec imports cleared at $7.03/kW-month; New York imports cleared at $6.26/kW-month; and New Brunswick imports cleared at $4/kW-month.
  • In FCA #11, all resources within New England, plus Québec and New York imports, cleared at $5.30/kW-month; and New Brunswick imports cleared at $3.38/kW-month.
  • In FCA #12, all resources within New England, all imports from New York, and 57 MW over a Québec interconnection will be paid $4.63/kW-month. Imports from Québec totaling 442 MW and from New Brunswick totaling 194 MW will be paid $3.70/kW-month and $3.16/kW-month, respectively.
  • In FCA #13, all resources within New England, as well as imports from New York and Québec, will be paid $3.80/kW-month, and imports from New Brunswick will be paid $2.68/kW-month.

Capacity Procurement

  • In FCAs #1 through #8, capacity was procured using a fixed systemwide Installed Capacity Requirement and fixed zonal Local Sourcing Requirements and Maximum Capacity Limits.
  • In FCAs #9 and #10, capacity was procured using a systemwide capacity demand curve and fixed zonal Local Sourcing Requirements and Maximum Capacity Limits.
  • In FCAs #11 through #13, capacity was procured using systemwide and zonal marginal reliability impact demand curves.

More information can be found on these pages of the FCM Participation Guide: About the FCM and Its Auctions and Installed Capacity Requirement.

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