Key Grid and Market Stats

Markets

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.

The Region Had the Second-Lowest Wholesale Prices in Over a Decade in 2017

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. A frigid late December 2017 led to spikes in energy market prices and higher consumer demand. Even so, lower prices and demand for most of 2017 kept the region’s energy market at its second-lowest annual value since 2003, when the ISO launched redesigned markets. The low energy market value helped keep the total combined value of New England’s markets at one of its lowest levels, as well, despite the increase in capacity prices precipitated by the need to replace retiring generators. The region had its lowest average annual energy market price in 2016 due to a combination of mild weather and extremely low natural gas prices.

Fast Stats

Close to 500 buyers and sellers in the wholesale electricity marketplace
$6.9 billion traded in wholesale electricity markets in 2017 (data subject to adjustments): $4.5 billion in energy markets (which had the second-lowest average prices since 2003) and $2.4 billion in capacity and ancillary services markets
About 70% of real-time pricing set by marginal natural-gas-fired generators in the first three quarters of 2017, with wind setting price next most often (15%)

annual value of wholesale markets

The high efficiency of natural-gas-fired generators and the generally low cost of nearby shale gas (which emerged as a resource in 2008) are largely responsible for a 35% decrease in the average price of New England’s wholesale electricity between 2004 and 2017. (2004 was the first full year of the redesigned energy market.) These lower wholesale prices translate into lower power-supply charges for consumers. In contrast, high annual averages in 2013 and 2014 were largely due to spikes in natural gas prices during wintertime pipeline constraints. Similar spikes were experienced during winter 2017/2018.

average annual price of wholesale electricity

Markets Are Yielding Tangible Results

The open, transparent wholesale electricity markets designed and run by the ISO stimulates strong competition among close to 500 buyers and sellers and has attracted billions of dollars in private investment in some of the most efficient, lowest-emitting power plants in the country. Markets select the lowest-priced power resources competing to produce electricity or provide other specialized services, compensating all suppliers equally, regardless of technology. Markets also provide the incentive for resources to offer prices for electricity as close as possible to their fuel and operating costs and to perform reliably. Competition drives private investment in energy production technologies that provide efficiencies and savings today, as well as in emerging technologies that may revolutionize energy production tomorrow. In addition, the ability of wholesale market prices to accurately reflect current conditions at specific locations serves as a signal to developers to invest in new power resources when and where they are most needed.

The aforementioned characteristics of competitive markets have helped produce real benefits for New England, including:

Less air pollution—The region’s shift to natural-gas-fired generation has been largely responsible for significant long-term reductions in regional generator air emissions, with sulfur dioxide (SO₂) falling by 98%, nitrogen oxides (NO_X) by 73%, and carbon dioxide (CO₂) by 29% between 2001 and 2016, as the region has largely shifted away from burning coal and oil.
Lower wholesale energy costs (see the chart above)
Enough power resources to meet the region’s needs—The Forward Capacity Market (FCM) has procured roughly 35,000 MW of capacity, including 2,700 MW of active demand response and energy efficiency (EE)—the equivalent of several large power plants—to meet New England’s needs during the 2018 summer peak.

Energy Markets Mirror Natural Gas Prices

Because so much of New England’s generating capacity runs on natural gas, the price of this single fuel source typically sets the price for wholesale electricity. (The bid price of the last generator needed to satisfy the total demand for electricity determines the wholesale price of electricity.) Natural-gas-fired generators set the real-time price about 70% of the time through the first three quarters of 2017 and set the day-ahead price more often than any other type of physical resource.

Natural gas and wholesale electricity prices are linked

Both electricity and gas prices have seen dramatic swings in recent years due to the region’s inadequate natural gas delivery and storage infrastructure, which can cause price volatility.

From 2008 through 2012, the price of natural gas declined significantly in New England with increasing production from the Marcellus Shale and moderate winter weather that resulted in minimal natural gas pipeline constraints. Wholesale electricity prices declined concurrently.
But in the winter of 2012/2013, this began to change. As pipelines into the region ran at full capacity to meet growing heating needs, New England experienced some of the highest natural gas prices in the country.
These winter price spikes continued through the winter of 2014/2015. However, by June 2015, the average monthly wholesale power price had plummeted, due to mild weather, low demand, and the lowest average natural gas price since 2003.
In 2016, extremely low natural gas prices, aided by the 2015/2016 “winter that wasn’t,” kept wholesale electricity prices low.
Cold snaps during winter 2017/2018 again resulted in pipeline constraints driving up prices.

Follow the trends with the ISO’s monthly analyses of electricity prices and demand.

Wind Units Now Setting Real-Time Pricing at Times

In May 2016, new do not exceed (DNE) dispatch rules made wind-powered generators eligible to set the price in the Real-Time Energy Market. (Read “ISO-NE incorporates wind-powered resources into real-time dispatch with Do Not Exceed Dispatch Project.”) Wind generators set the real-time price 15% of the time in the first three quarters of 2017, including over 20% of the time during the spring. This has reduced the frequency of natural-gas-fired units setting the price and has put a downward pressure on prices.

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 Long-Term Capacity Market Is Attracting Tomorrow’s Power Resources

Auctions in the Forward Capacity Market (FCM) ensure the system has sufficient resources to meet future demand for power. Resources that clear in these auctions receive monthly payments in exchange for their commitment to be available to meet the projected demand for electricity three years out. That delivery period is called the capacity commitment period (CCP)—a one-year period from June 1 through May 31 of the following year.

Of the new capacity coming from resources within New England, almost half is a combination of demand resources (including energy-efficiency measures), wind, grid-scale solar, other renewable resources, and hydro (see chart below). Several major new natural-gas-fired generators are to be located in the high electricity demand areas of Connecticut, Rhode Island, and Southeast Massachusetts. Additionally, electricity imports (mostly hydropower) have made up about 5% of the total capacity procured in Forward Capacity Auction (FCA) #1, held in 2008, through FCA #11, held in 2017. The ISO is collaborating with regional stakeholders to enable market entry for even more clean energy backed by public policies. See Accommodating State Clean-Energy Goals within the Competitive Marketplace.

New Regional Power Resources Procured in FCAs #1–11

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.”

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

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.

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, 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.

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 FCA #11 and #12, 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.