Over the past 20 years, New England’s wholesale electricity markets have attracted billions of dollars in private investment in some of the most efficient, lowest-emitting power resources in the country—providing reliable electricity every second of every day, lowering wholesale prices, shifting costly investment risk away from consumers, and reducing carbon emissions. Because private firms make this investment and not public utilities, consumers are shielded from the investment risks they had been exposed to before the introduction of competitive markets.
Here’s the breakdown of the amount of electricity produced by generators in New England and imported from other regions to satisfy all residential, commercial, and industrial customer demand during 2019. This is called net energy for load (NEL).
|GWH (a)||% of GENERATION||% of NEL||
(a) GWh stands for gigawatt-hour.
(b) As of January 2016, this chart approximates the amount of generation by individual fuels used by dual-fuel units, such as natural-gas-fired generators that can switch to run on oil and vice versa. Previously, the report attributed generation from such units only to the primary fuel type registered for the unit. The new reporting flows from changes related to the Energy Market Offer Flexibility Project implemented December 2014. See the notes in the Net Energy and Peak Load by Source Report for more details.
(c) Hydro is not included in the renewables category primarily because the various sources that make up hydroelectric generation (i.e., conventional hydroelectric, run-of-river, pumped storage) are not universally defined as renewable in the six New England states.
(d) “Other” represents resources using a fuel type that does not fall into any of the existing categories. Other may include new technologies or new fuel types that come onto the system but are not yet of sufficient quantity to have their own category.
(e) Tie lines are transmission lines that connect two balancing authority areas. A positive value indicates a net import; a negative value represents a net export.
(f) The energy used to operate pumped storage plants.
|Total Generation (b)||97,853||100.0%||82%|
|Net Flow over External Ties (e)||22,985||19%|
|Pumping Load (f)||-1,717||-1.4%|
|Net Energy for Load (g)||119,122||100.00%|
In 2019, natural-gas-fired generation, nuclear, other low- or no-emission sources, and imported electricity (mostly hydropower from Eastern Canada) provided roughly 99.5% of the region’s electricity.
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 nearby shale gas emerged as an inexpensive and plentiful fuel resource in the 2008 timeframe, natural gas generators became the go-to resource for New England, clearing as the largest resource type in the market year after year. Nearly half of the region’s electric generating capacity uses natural gas as its primary fuel (about 15,000 MW), and natural-gas-fired power plants produce about 40% of the grid electricity consumed in a year.
In contrast, aging coal-fired, oil-fired, and nuclear power plants have been closing largely because their operating, fuel, and environmental-compliance costs make them too expensive to compete against lower-cost resources. Since 2013, roughly 7,000 MW of mostly coal, oil, and nuclear generation have retired or have announced plans for retirement in the coming years. Another 5,000 MW of oil and coal, which now run only during peak demand or periods of gas pipeline constraints, are likely to retire soon. (The region’s remaining two zero-carbon-emitting nuclear facilities, Millstone and Seabrook, supply a quarter of the electricity New England consumes in a year and will be critical components of a reliable clean-energy grid because they are carbon free and have a dependable, on-site fuel supply). Competition in the markets brought about this change at a faster pace than under the traditional industry model. Under wholesale markets, private companies have carried the risks of uneconomic investments, not utilities and their customers. Consumers have benefited from this least-cost resource mix created through competitive markets.
Nuclear, oil, and coal generators are critical on the coldest winter days when natural gas supply is constrained (as shown below). Coal- and oil-fired resources also make valuable contributions on the hottest days of summer when demand is very high or major resources are unavailable. As more and more conventional, thermal generation that store fuel on site retire, the system is increasingly made up of generating facilities that run on just-in-time energy sources: natural gas (from pipelines and LNG deliveries), wind, and solar energy.
With limited options for storing natural gas, most natural-gas-fired plants rely on just-in-time fuel delivered to New England through interstate pipelines. However, interstate pipeline infrastructure has only expanded incrementally over the last several decades, even as reliance on natural gas for home heating and for power generation has grown significantly. During cold weather, most natural gas is committed to local utilities for residential, commercial, and industrial heating. As a result, we are finding that during severe winter weather, many power plants in New England cannot obtain fuel to generate electricity. Liquefied natural gas (LNG), brought to New England by ship from overseas, can help fill the gap—but regional LNG storage and sendout capability is limited, and its timely arrival depends on long-term weather forecasts, global market prices, and other logistical challenges.
Winter also imposes the most challenges for solar output in New England due to snow, clouds, and shortened daylight hours. In addition, shortened winter days means consumers use the most electricity after sunset, and therefore solar doesn’t reduce winter peak demand. While offshore wind experiences its highest production during winter, winter storms that limit solar power can also significantly limit the output of wind generation. This type of variability is an understandable challenge in meeting the states’ decarbonization goals through greater renewable, weather-dependent technologies, and it poses new technical challenges to the grid’s reliability.
All six New England states have renewable energy standards, which require electricity suppliers to provide customers with increasing percentages of renewable energy to meet state requirements.
The New England states are also promoting greenhouse gas (GHG) reductions on a state-by-state basis and at the regional level, through a combination of legislative mandates and aspirational 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.
|State(s)||State Procurement Initiatives for Large-Scale Clean Energy Resources||Resources Eligible/Procured||Target MW (nameplate)|
|CT||2019: Offshore Wind RFP||Offshore Wind||400—2,000 MW|
|MA||2019: Section 83C II Offshore Wind RFP||Offshore Wind||800 MW|
|RI||2018: Renewable Energy RFP||Solar, Wind, Biomass, Small Hydro, Fuel Cells and Other Eligible Resources||400 MW|
|CT||2018: Zero-Carbon Resources RFP||Nuclear, Hydro, Class I Renewables, Energy Storage||Approx. 1,400 MW
|CT||2018: Clean-Energy RFP||Offshore Wind, Fuel Cells, Anaerobic Digestion||252 MW|
|MA, RI||2017: Section 83C I Offshore Wind RFP||Offshore Wind||800 MW (MA)
400 MW (RI)
|MA||2017: Section 83D Clean-Energy RFP||Hydro Import||Approx. 1,200 MW
|MA, CT,RI||2015: Multi-State Clean-Energy RFP||Solar, Wind,
Developers of clean-energy resources are taking advantage of state incentives, declining technology costs, and revenues from the wholesale markets. About 95% of resources currently proposed for the region are grid-scale wind, solar, and battery projects. As of January 2020, about 20,100 MW have been proposed in the ISO Generator Interconnection Queue.
Wind power dominates new resource proposals. ISO New England has more than 14,000 MW of wind interconnections under study, which is by far the largest group of resources seeking to connect to the region’s electricity grid (as of January 2020). The New England coast offers prime conditions for offshore wind, and about 13,500 MW of proposed wind is located offshore of Massachusetts, Rhode Island, and Connecticut, with most of the remaining located onshore in Maine. In 2016, the wind turbines at the Block Island Wind Farm began putting power onto the electricity grid, making the 30 MW project the first offshore wind farm in the United States. Learn more about transmission needed to support a hybrid grid.
Solar power now ranks second in the ISO Interconnection Request Queue, surpassing natural gas. Most solar power in New England is connected to local distribution utilities or “behind the meter” directly at retail customer sites. Because such projects do not follow the ISO interconnection process, they aren’t reflected in the ISO Queue numbers above. The ISO must still track solar power’s growth in the region for forecasting and planning purposes, however, since it reduces demand on the grid; the region had over 180,000 solar power installations at the end of 2019 with a combined nameplate generating capability of more than 3,400 MW. Read more about solar power in New England—its growth, locations, and effects on the system, as well as how the ISO is handling related challenges.
Energy storage is “charging” ahead and now ranks third in the ISO Interconnection Request Queue, also surpassing natural gas. For more than 40 years, New England has enjoyed the benefits of two large-scale pumped-hydro energy- storage facilities that can supply almost 2,000 MW of capacity within 10 minutes. Now, new storage technologies are emerging, driven by technological advances, falling costs, support from the states, and changes to the markets that enable storage participation. About 20 MW of grid-scale battery-storage projects have come on line since 2015; nearly 2,300 MW of grid-scale stand-alone energy-storage projects are requesting interconnection. Grid-scale and behind-the-meter energy storage can contribute a number of benefits:
Storage also consumes energy and may not provide assistance once depleted. Energy-storage resources draw electricity from the power system or directly from a generating resource (such as a colocated solar or wind facility) as they “stockpile” energy and then send electricity to the grid at a later time. Overall, they consume more energy than they supply, as operations and losses during energy conversion consume some of their “inventory” of stored energy. If these resources are already depleted during a system emergency, they would not be able to provide help but would instead sit idle, making their “inventory management” and optimization a key technical challenge for the grid’s reliability.
In addition, 2,600 MW of energy efficiency (EE) measures can reduce electricity demand from New England’s power grid. New England states invest billions of dollars on EE programs that promote the use of energy-efficient appliances and lighting and advanced cooling and heating technologies (nearly $5.4 billion on EE programs from 2013–2018 and another $10.7 billion between 2021 and 2029). Massachusetts, Rhode Island, Connecticut and Vermont rank among the top 10 states in energy efficiency in the US, according to the American Council for an Energy-Efficient Economy's 2018 rankings.
Unlike EE and behind-the-meter PV, which are passive demand resources, active demand resources (also known as demand-response resources) can be dispatched by the ISO. Demand-response resources can reduce their electricity consumption from the regional grid “on demand,” by powering down machines (load management), by switching to an on-site generator (distributed generation), or by switching to a storage device (batteries). Demand-response resources provided about 500 MW of the region’s total capacity needs in 2019. And, after a multi-year development effort, on June 1, 2018, ISO New England became the first US grid operator to deploy demand-response resources as part of the energy dispatch and reserve-designation process along with generating resources. Integrating demand-response resources directly into the wholesale market for energy and reserves was a long sought after but complex goal. Active demand response accounted for 26 GWh of reduced system demand in 2019.
Read about solar power in New England—its growth, locations, and effects on the system, as well as how the ISO is handling related challenges.
Learn about how ISO New England is actively pursuing innovations to help create a more efficient, responsive, reliable system that can handle expanded renewable generation and smart grid technology.