New England's solar duck curve accelerates, deepens

Continued installations of consumer-sited solar power have poised New England for a new record number of "duck curve" days, or periods when wholesale demand for grid electricity is lower during the middle of the day than during the night. The shift has consequences for the rest of the grid, including on the portfolio of other generating resources needed to meet demand, related emissions, and power pricing.

Historically, consumer demand for electricity has been highest during the day and lowest during the night, based on household, business, and other social patterns of energy use. But as behind-the-meter solar generation was added to the system, midday demand for grid power was reduced. On April 21, 2018 -- a mild sunny day on a spring weekend -- conditions combined to cause grid demand to be lower at midday than at night. Based on graphs showing grid demand reduction in yellow, such as the chart below produced by ISO New England, this phenomenon has become known as the "duck curve".

Since 2018, the duck curve phenomenon has become more frequent, as shown in this chart produced by ISO-NE.

In 2024, the region experienced 107 duck curve days -- a new record. So far in 2025, ISO-NE reports 100 duck days, with a projection to exceed last year's record by the end of December.

The "duck curve" is also reaching new depths of midday load. On April 20, 2025, system demand reached an all-time low of 5,318 megawatts -- which the grid operator projects to be less than half the level of load it would have seen without behind-the-meter solar.

With midday behind-the-meter solar producing power, other grid resources need to ramp down their production to keep supply and demand in balance -- and then need to ramp back up as midday sun fades. This requires the grid operator to ensure a sufficient volume of dispatchable generation capable of responding to these shifts, like natural gas-fired power plants (or large volumes of energy storage which have not yet materialized in the region).

FERC Order 2222 opens wholesale markets to distributed energy resource aggregators

U.S. electric utility regulators have issued an order requiring the nation's regional organized wholesale electric markets to allow participation by portfolios of solar projects and other distributed energy resources. The Federal Energy Regulatory Commission's Order 2222 finds that existing regional electricity market rules are unjust and unreasonable in light of barriers that they present to the participation of DER aggregations in these markets, and requires regional grid operators to revise their tariffs to accomodate distributed energy resource aggregators. While further process and uncertainty remain ahead, FERC Order 2222 should facilitate the development of distributed energy resources by removing barriers to electricity market participation.

As defined by the FERC, distributed energy resources (DER) encompass a variety of types of technology when installed on the distribution system, a distribution subsystem or behind a customer meter. Typically less than 10,000 kilowatts in capacity for each installation, DER technologies include solar photovoltaic systems and other distributed generation or intermittent generation, electric storage, electric vehicles and their charging equipment, thermal storage, and other consumer-side measures like demand response and energy efficiency. The U.S. is experiencing significant growth in the number and size of DERs installed on the system, due to factors including federal tax incentives and state incentives, as well as considerations of reliability and utility rate design.

Through Order 2222, issued on September 17, 2020, FERC has now found "that existing RTO/ISO market rules are unjust and unreasonable in light of barriers that they present to the participation of distributed energy resource aggregations in the RTO/ISO markets, which reduce competition and fail to ensure just and reasonable rates." As a result, the Commission adopted a final rule requiring regional transmission organizations and other organized wholesale market operators to establish DER aggregators as a type of market participant, to allow them to register their DERs under one or more participation models that accommodate the physical and operational characteristics of those resources and to participate in the regional organized wholesale capacity, energy and ancillary services markets. Order 2222 allows DERs to aggregate together to satisfy minimum size and performance requirements that they might not meet individually.

The boundaries between federal and state jurisdiction over DERs arise as a matter of federal law, and have occasionally been tested -- most recently in connection with FERC Order 841, governing storage. As noted by the Commission, its Order 2222 final rule "builds off the DC Circuit Court’s recent ruling on Order No. 841, in which the court affirmed the Commission’s exclusive jurisdiction over the regional wholesale power markets and the criteria for participation in those markets." Order 2222 prohibits state regulators from broadly excluding DERs from participating in regional markets, but gives state retail regulatory authorities some power by creating a "small utility opt-in", as well as respecting states regulators’ current ability to prohibit aggregators from bidding retail customers’ demand response into regional markets. Regarding interconnection, Order 222 explains that "state and local authorities remain responsible for the interconnection of individual DERs for the purpose of participating in wholesale markets through a DER aggregation."

The final rule largely tracks a 2016 proposed rule developed by FERC staff, with some changes. The regulator appears excited to take this step. According to a fact sheet issued by the Commission under the title, "FERC Order No. 2222: A New Day for Distributed Energy Resources", Order 2222 "will help usher in the electric grid of the future and promote competition in electric markets by removing the barriers preventing distributed energy resources (DERs) from competing on a level playing field in the organized capacity, energy and ancillary services markets run by regional grid operators."

Order 2222's final rule will take effect 90 days after its publication in the Federal Register. Grid operators will then have 270 days within which they must submit to FERC a compliance filing and a plan for timely implementation of the final rule. While Order 2222 and federal laws place some constraints on what the grid operators may propose, each regional transmission organization or independent system operator has some leeway to develop and propose solutions it views as tailored to its own markets and needs. This feature of federalism will likely result in some diversity in terms of regional designs, to be considered through regional stakeholder discussion and the Commission's regulatory processes.

Maine regulators approve long-term contract

Maine utility regulators have approved a long-term contract to purchase the output of a 72.6-megawatt wind power project under development by Weaver Wind, LLC in Hancock County, Maine. The 20-year contract bears a price of 3.5 cents per kilowatt-hour, escalating at 2.5 percent per year.

A Maine statute enacted in 2006 authorizes the Public Utilities Commission to direct investor-owned transmission and distribution utilities to enter into long-term contracts, to the degree necessary to ensure reliability, meet energy efficiency program requirements, or reduce customer costs. In 2008, the Commission used this law to order a contract with the Rollins Wind project. After three subsequent procurement rounds, in 2017 the Commission approved a contract to buy 75 megawatts from Dirigo Solar, LLC, at a price of 3.4 cents/kWh escalating at 2.5% annually for 20 years.

In response to its most recent solicitation, earlier this year the Commission approved a term sheet for a contract to buy 100 megawatts from Three Rivers Solar Power, LLC’s solar project, with a price of 3.5 cents/kWh escalating at 2.5% annually for 10 years. Most recently, on July 12, 2019, the Commission approved a contract to buy the output of the Weaver Wind project, also at a price of 3.5 cents/kWh escalating at 2.5% annually for 10 years.

In addition to this existing law, in 2019 the Maine state legislature enacted several additional long-term contracting programs. One new law creates a new "Class IA" renewable portfolio standard, and requires the procurement by December 31, 2020 of energy or renewable energy credits from Class IA resources sufficient to cover between 7 and 10 percent of Maine's retail electricity sales, with a second round bringing the total procurement to 14 percent of Maine's retail electricity sales. Another new law requires the procurement of 375 megawatts from distributed generation resources between 2020 and 2024, with each project sized at less than 5 megawatts, and specific requirements for participation by non-residential and "community" or shared-ownership projects.

Collectively, these laws create a variety of opportunities for electric power generation projects to compete for and win long-term contracts to sell their output to Maine utilities.

New England 2019 Regional Energy Outlook describes shifts, challenges

New England's electricity system is shifting toward a "hybrid grid," according to the operator of New England's wholesale electricity markets and electric transmission system. A recent report by ISO New England, Inc. describes the electric sector's transition towards generating resources with lower carbon emissions and the resulting implications for the environment and the economy.

ISO New England is the federally-designated regional transmission organization serving New England. The grid operator recently released its 2019 Regional Energy Outlook, a document described as “one of the many ways the ISO keeps stakeholders informed about the current state of the grid, issues affecting its future, and ISO initiatives to ensure a modern, reliable power system for New England.”

In the report, ISO New England emphasizes the region’s decarbonization and shifting resource mix, noting that “carbon emissions from the grid have fallen by roughly a third... the region is on its way from having an electric grid dominated by fossil-fuel and nuclear generation to one that includes large amounts of wind and hydro generation and hundreds of thousands of small solar and storage systems spanning the six states. The states’ next step in their decarbonization journey is to transition the emissions-heavy heating and transportation sectors to low-carbon electricity.”

ISO-NE describes the way these changes are happening as “challenging reliable system operations and competitive wholesale electricity markets.” ISO says that “for the foreseeable future, the region will remain vulnerable to energy shortfalls and wholesale price volatility as more and more resources with limited-energy ‘inventories’ (natural gas generation, wind, solar, battery storage) displace resources with on-site fuel that can sustain operation for extended periods (oil, coal, nuclear, dual-fuel generation).”

ISO New England says its competitive markets weren’t designed to telegraph future energy scarcity conditions, compensate resources for fuel inventory, achieve carbon reduction goals, or specifically lead to renewable development. It notes that state-sponsored resources suppress market prices when in markets, but would lead to overbuild if outside markets. ISO advocates, “Establishing a realistic price on carbon remains a more seamless and simpler way to achieve clean-energy goals through markets without distorting competition, but this is not in the ISO’s jurisdiction. State or federal policymakers could pursue this direction but have not done so to date.” ISO notes, “Nuclear resources will prove critical to meeting both decarbonization and energy-security goals for years to come, but how they can remain financially viable is still unclear.”

ISO-NE says it is focused on 3 elements to support the transition to the “hybrid grid”: supporting the rapid transformation of the region’s electricity supply and demand mix, maintaining a robust transmission system, and ensuring energy security. 

The grid operator also noted limitations on what tools it can use to address these challenges: “Importantly, ISO New England does not have the authority to dictate investments in energy infrastructure that can help ensure that the region’s energy needs can be met in all seasons, under all conditions. Our toolkit is to create financial stimuli through the wholesale electricity markets that will drive action. Opposition or impediments to infrastructure decisions will only exacerbate the region’s energy-security constraints.”

Maine advances legislation restoring net metering

The Maine state legislature has voted to advance a bill that would amend the state's statute governing the net metering of small distributed renewable energy projects. If enacted into law, the amendment would reverse regulatory changes imposed in 2017 that reduced the value of net energy billing to participating customers.

Maine has allowed customers with distributed renewable energy generation to use the power they produce to offset their electricity bill since the 1980s. In 2017, the Maine Public Utilities Commission amended its rules governing net energy billing to reduce the amount of power that a customer could net against its electric utility bill. The Commission did this by inventing a concept called "gross metering," which allowed electric utilities to collect charges even for power generated and consumed on-site in real time, while requiring participating customers to install a second meter.

The "gross metering" concept was controversial for a variety of reasons, including the fact that it deterred customer adoption of solar power and other distributed renewables (by adding costs while cutting compensation), and the fact that for the first time ever it allowed utilities to collect charges from customers for power produced and consumed entirely on the customer's premises even where that power never went on utility grid facilities.  The Commission later exempted most medium and large customers from this policy after finding that the cost of installing an extra meter wasn't justified, but left the gross metering requirements in its Rule Chapter 313 governing net energy billing. In response, in 2019 various state legislators proposed bills that would alter or restore the net energy billing paradigm.

One of these bills has now received favorable votes in both the state House and Senate. LD 91, An Act to Eliminate Gross Metering, was originally sponsored by Representative Seth Berry. It clarifies the statutory definition of net energy billing, which currently defines the concept as "a billing and metering practice under which a customer is billed on the basis of net energy over the billing period taking into account accumulated unused kilowatt-hour credits from the previous billing period." As amended by LD 91, the definition would specifically define "net energy" as the "difference between the kilowatt-hours delivered by a transmission and distribution utility to the customer over a billing period and the kilowatt-hours delivered by the customer to the transmission and distribution utility over the billing period." This clarification removes the Public Utilities Commission's ability to define "net energy" in any other way. LD 91 also directs the Commission to amend its rules "to be substantively equivalent to the rules in effect on January 1, 2017" (that is, before the Commission's 2017 regulatory amendment.)

LD 91 faces additional votes in the state legislature, before it would move to the desk of Governor Janet Mills for her signature. The legislature is also expected to consider other bills affecting net energy billing or expanding incentives for solar development, later this session.

Will Maine change its net metering law?

Several pieces of proposed Maine legislation could affect the state's version of net metering. Here's a quick look at Maine's net energy billing policy, how it could change, and what that might mean for consumers.

Maine's electricity rules allow consumers with certain distributed generation facilities (like solar panels) to elect "net energy billing." Like other forms of net metering, the basic concept is that consumers can use their on-site generation to offset their purchases of electricity from the grid, both in real time, and by banking credits for power exported to the grid during periods of time when on-site generation exceeds the consumer's load.

The Maine Public Utilities Commission first adopted a net energy billing rule in the 1980s, allowing customers to net imports and exports within any month or other billing period, in recognition that consumers should not be required to install an extra meter to measure exports from small renewable power facilities and other distributed generation. In 1998, the Commission revised its rule to allow annualized netting as a means of encouraging the use of small-scale renewable technologies designed primarily to serve the customer’s own needs.

In 2017, the Commission revised its rule to reduce the benefits of net metering for future projects, both by reducing the credit for nettable energy, and by shifting the state to a "gross metering" paradigm. Under gross metering, which has been called "one of the strangest and most regressive policies for valuing residential solar in the United States," utilities collect charges even for power generated and consumed on-site in real time. While the Commission later granted an exemption from its gross metering policy for most medium and large customers after finding that the cost of installing an extra meter (estimated at over $3,000 per installation) wasn't justified, the revised rule remains on the books for now.

But further possible changes to net energy billing figure among the numerous energy issues implicated by the list of legislation proposed for the Maine State Legislature's 2019 session. Several bills that have been printed so far suggest that the Legislature will consider various bills that would eliminate gross metering (like LD 91, An Act to Eliminate Gross Metering and LD 143, An Act To Protect Electric Ratepayers from Gross Output Metering Costs), or would replace net energy billing with a market-based mechanism (like LD 41, An Act To Replace Net Energy Billing with a Market-based Mechanism), among other measures. Other bill titles suggest possible changes to the state's policy on shared ownership net metering, which allows multiple customers to offset their load with generation from a community solar project or other off-site facility.

The Legislature's Joint Standing Committee on Energy, Utilities and Technology will schedule public hearings on these bills. The Committee has scheduled public hearings on LD 41 and LD 91 for 1:00 p.m. on January 29, 2019.

ISO-NE 2018 CELT projects future energy usage declines

The operator of New England's bulk electric grid projects that both energy usage and peak demand from the utility grid will decline slightly in the region over the 10-year period between 2018 and 2027, primarily due to the deployment of energy efficiency measures and behind-the-meter solar arrays.

ISO New England Inc. is the regional transmission organization responsible for the electric grid and electricity markets across most of New England. On April 30, 2018, ISO-NE published its 2018-2027 Forecast Report of Capacity, Energy, Loads, and Transmission, or CELT Report. The grid operator prepares annual CELT reports which describe the assumptions used in ISO system planning and reliability studies. These assumptions include the total generating capability of in-region resources, as well as a long-term forecast for growth in energy consumption and peak demand.

According to ISO-NE's 2018 CELT Report, overall regional electricity use will grow 0.9% annually over the 10-year period. But when energy efficiency and behind-the-meter generation are taken into account, ISO-NE's forecasts for both regional energy usage and peak demand project slight declines over the 10-year period. The grid operator projects an annual decrease in net energy usage by -0.9% annually, with seasonal peak demands projected to decline by -0.2% to 0.7% annually. ISO cites "continuing robust installation of energy-efficiency measures and behind-the-meter solar arrays throughout the region" as the primary factors driving this decline.