Markets

For decades before restructuring, the region’s utilities operated as vertically integrated, rate-payer-funded, regulated monopolies that generated, transmitted, and distributed electricity. Dissatisfied with investments that increased consumer rates while limiting funds for needed infrastructure, the federal government and the New England states introduced a new industry framework in the late 1990s: competitive wholesale markets where privately developed resources would compete with each other to provide the least-cost, reliable wholesale electricity supply. The goals of competitive wholesale electricity markets were to lower costs, encourage innovation, and shield consumers from unwise investments. (Learn about ISO New England’s responsibility for administering the region’s wholesale electricity markets.)

During this time, the New England states also began introducing clean-energy incentives and emission-reduction goals, focusing first on reducing greenhouse gas (GHG) emissions from the electric power industry. Emissions regulations work well with the wholesale markets by making higher-polluting power plants more expensive to operate and providing a reliable means for cleaner resources to come on line in their place.

Over the past 20 years, the market and policy approach has driven change in the direction the states have been seeking: around $16 billion in private investment in some of the most efficient, lowest-emitting power resources in the country, shifting investment costs and risks away from consumers, lowering wholesale prices, reducing carbon emissions, and enabling the transition to an even lower-carbon system.

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

Transmission MarketsOver the past 20 years, the ISO’s continuous study of the transmission system has helped guide cooperative regional investment that not only improves reliability but enables the competitive markets to work as designed. Transmission system upgrades allow the ISO to dispatch the most economic resources throughout the region, allow less-efficient resources to retire, and enable the interconnection of power plants with lower emissions. Upgrades have nearly eliminated congestion costs in the New England energy market and, with the aid of low natural gas prices and other factors, have helped drive down and mitigate “uplift” payments to run specific generators to meet local reliability needs. See the chart illustrating these lower costs on the Key Stats: Transmission page.

Remarkably Low Wholesale Electricity Prices

When the wholesale markets opened to competition, private companies invested billions of dollars in the development of natural-gas-fired power plants because they used advanced technology that made them run efficiently; were relatively inexpensive to build, site, and interconnect; and their lower carbon emissions compared to coal and oil helped the region meet state environmental policies. As lower-cost, highly efficient natural gas plants displaced older oil and coal plants in New England, wholesale electricity prices declined.

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 the significant decrease in the average annual price of New England’s wholesale electricity over the past 10 years. After plummeting almost 50% a decade ago, average wholesale energy prices have remained consistently low since then (see chart below). Lower wholesale prices translate into lower power-supply charges for consumers.

In 2019, New England experienced a mild winter that moderated natural gas prices, a cool summer that tempered air conditioning use, and surging amounts of solar power and energy efficiency that lessened electricity demand from the grid. The markets responded in-kind, and New England had the second lowest annual average real-time energy market price since the introduction of the current market structure in 2003, at $30.67 per megawatt-hour.

Fast Stats
  • More than 500 buyers and sellers in the wholesale electricity marketplace
  • $7.6 billion traded in wholesale electricity markets in 2019: $4.1 billion in energy markets (lowest since the start of competitive markets) and $3.5 billion in capacity and ancillary services markets
  • The average real-time price for wholesale power in New England in 2019 was $30.67 per megawatt-hour.

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. 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 and Wholesale Electricity Prices graph

The Capacity Market Is Attracting Power Resources

Whereas the energy market value varies with fuel prices, the capacity market value varies with changes in amounts of electricity-producing resources. (Power resources compete in the Forward Capacity Market to take on a commitment to be available to meet projected demand for electricity three years out.)

Strong competition has generally kept capacity market auction prices low for most years, but when generation started to retire, the capacity market value over the past few years has increased. The capacity market works in tandem with the energy and ancillary service markets to provide revenue that attracts and sustains power resources needed today and into the future. Over the years, the FCM has enabled the entry of nearly 12,000 MW from energy efficiency, demand response, renewable resources and natural gas plants. And it has provided an orderly process for the retirement of almost 7,000 MW from older fossil units and nuclear plants.

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.

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 a state’s longer-term, fixed-price contracts for energy; the recovery of the costs to pay for the transmission and distribution systems; stranded costs from legacy, vertically integrated utility investments; and various policy-driven adders, such as funding energy efficiency and solar photovoltaic incentive programs.

So while wholesale market costs have been consistent over time and across the New England states in recent years (ranging from 7.48 cents/kilowatt-hour (kWh) to 7.81 cents/kWh in 2018), retail power supply rates 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 different laws and power procurement practices of each state and the utilities within each state. (Source: 2019 Report of the Consumer Liaison Group).

Helping the States Accelerate the Clean-Energy Transition to Fulfill their GHG Goals

Despite significantly reduced emissions from the power system, action toward meeting economywide GHG goals set by the states is just getting underway. There is a growing desire to accelerate actions needed to meet the climate goals. With deadlines looming, the states are eager for the quicker transformation of the power grid to renewables and for electrification of the broader economy.

Because large-scale renewable resources typically have higher up-front capital costs and different financing opportunities than more conventional resources, they have had difficulty competing in the wholesale markets. Therefore, the New England states are promoting, at varying levels and speed, the development of specific clean-energy resources to meet their public policy goals.

Several states have established public policies that direct electric power companies to enter into rate-payer-funded, long-term contracts for large-scale carbon-free energy that would cover most, if not all, of the resource’s costs. Long-term contracts carry risk given the rapid development and falling costs of new technologies—and this risk of stranded costs is placed back on consumers. As policymakers seek to convert the transportation and heating sectors to carbon-free electricity to fully meet climate goals, this public policy trend is expected to continue.

Pricing carbon within the competitive market structure is the simplest, easiest, and most efficient way to rapidly reduce GHG emissions in the electricity sector. Moreover, placing a realistic price on carbon would enable consumers to pay accurate, competitive prices without the risk of paying for stranded costs. However, New England state policymakers and other stakeholders responsible for putting this approach into motion have not pursued a carbon-pricing option that effectively reflects decarbonization goals, neither economywide nor in the electricity sector.

In the absence of a regional strategy for realistic carbon pricing, ISO New England designed and implemented Competitive Auctions for Sponsored Policy Resources (CASPR) to enable the resource transition to take place in a manner that does not compromise reliability. CASPR is a state-of-the-art solution that allows state-sponsored clean-energy resources (such as state-contracted offshore wind) into the capacity market without artificially depressing prices for all other resources. Unrestricted entry of state-sponsored resources into the capacity market could lead to economic distortions, undermine the competitiveness of the market, and cause retirements to happen too quickly. Or, it could deter new investment in other resources that don’t have a contract but are needed to operate the grid reliably (such as merchant investment in grid-scale storage technologies).

It is important to note that CASPR does not prevent potential capacity resources from clearing in the primary auction if they are economic. Rather, it provides an opportunity for state-sponsored resources unable to clear in the primary auction to trade with a capacity resource seeking to retire, thereby avoiding the expensive and inefficient acquisition of more resources than required for reliability.

The ISO conducted the first substitution auction in conjunction with Forward Capacity Auction #13 in 2019. CASPR will work over time, depending on the timing and buildup of the economic incentives for buyers and sellers. While CASPR is a second-best solution for reducing (or eliminating) carbon from the power sector, the market design demonstrates ISO New England’s consideration of the region’s climate goals and adherence to our mission to ensure reliability through a competitive wholesale market structure.

More About the Region’s Capacity Auctions

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.

  • 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

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
FCA #14 in 2020 for CCP 2023/2024 33,956 323 335 $2.00

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:

Zones

  • 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.

Pricing

  • 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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