Three Mile Island nuclear plant to close in 2019 absent policy reforms

Exelon Corporation has announced that it will retire its Three Mile Island Generating Station on or about September 30, 2019, unless energy policies change.  

Located in Pennsylvania, the Three Mile Island plant Unit 1 features a nuclear pressurized water reactor, feeding steam to generation with a net capacity of 837 megawatts.  Its license issued by the Nuclear Regulatory Commission allows operation until 2034.  Unit 1 is now over 40 years old, with construction having started in in 1968 and the plant being placed in-service in 1974.  (The former Unit 2 reactor partially melted down in 1979 and was closed; the Unit 2 complex is now owned by an affiliate of FirstEnergy Corporation.)

While the Three Mile Island plant has previously earned revenue by providing capacity to the PJM wholesale market, Exelon says the plant has not cleared in the past three PJM base residual auctions.  PJM's most recent capacity auction results, for the 2021/2021 delivery year, were announced last week, and came in below the previous year's results.  For generators, demand resources, and other sources of capacity bidding into the market, this means more expensive resources did not clear -- and those that did clear will receive lower revenues than if the auction yielded a higher price.

On May 24, shortly after the PJM auction results were announced, Exelon noted that Three Mile Island's failure to clear in the auction placed it "at risk of early retirement":

TMI remains economically challenged as a result of continued low wholesale power prices and the lack of federal or Pennsylvania energy policies that value zero-emissions nuclear energy. Exelon has been working with stakeholders on options for the continued operation of TMI, which has not been profitable in five years.

Exelon pointed to the "challenge nuclear energy continues to face without compensation for its ability to produce electricity without harmful carbon and air pollution and to contribute to grid resilience."

Six days later, Exelon announced that "it will prematurely retire its Three Mile Island Generating Station (TMI) on or about September 30, 2019, absent needed policy reforms."  Exelon announced that it is "taking the first steps to shut down the nuclear plant," including sending deactivation and shutdown notifications, terminating capital investment projects required for long-term operation of the plant, and canceling 2019 fuel purchases and outage planning.  

In its statement, Exelon noted that nuclear power is emissions-free, but is not included in Pennsylvania's Alternative Energy Portfolio Standard (AEPS).  The AEPS requires that 18 percent of the electricity supplied by Pennsylvania’s electric distribution companies and electric generation suppliers come from qualified alternative energy resources by 2021.  Under the current AEPS, eligible resources include solar PV, solar thermal, wind, low-impact hydro, geothermal, biomass, biologically derived methane gas, coal-mine methane and fuel cell resources, new and existing waste coal, distributed generation (DG), demand-side management, large-scale hydro, municipal solid waste, wood pulping and manufacturing byproducts, and integrated gasification combined cycle (IGCC) coal facilities, with specific set-asides for some categories of resources -- but not nuclear.  Exelon suggested that potential solutions could include amending the AEPS to include nuclear resources, or establishing a zero emissions credit (ZEC) program similar to the approach being implemented in Illinois and New York, among others.

Maine tidal pilot project not seeking new license

The holder of a federal pilot license for a Maine tidal energy project has told regulators that it does not intend to relicense the project beyond the pilot license's expiration in 2022, pointing to tidal current velocities at the project site as inadequate to justify pursuing a commercial license.

At issue is the Cobscook Bay Tidal Project.  On February 27, 2012, the Federal Energy Regulatory Commission issued a pilot project license to ORPC Maine, LLC for the project for a period of eight years.  Later that year, it became the first grid-tied commercial tidal power plant in the U.S.

The Commission later granted a subsequent request by ORPC to extend its license term for the Cobscook Bay Tidal Energy Project from eight years to ten years, until January 31, 2022.  In that order extending the pilot license term, the Commission noted "the experimental nature of hydrokinetic devices, the licensee’s dedication to expanding and improving the technology and design of its project, and the insignificant or no impact to the surrounding environment by extending the license term two years."

Because the FERC licensing process can take years to complete, licensees are required to make public filings between 5 and 5-and-a-half years in advance of license expiry.  On March 14, 2017, ORPC made such a filing.  In that March 14 letter, ORPC noted some project successes:

The Cobscook Bay Tidal Energy site has served a pivotal role in the advancement of ORPC’s technology specifically and the domestic marine hydrokinetic industry generally. ORPC anticipates that the project infrastructure in place, the environmental monitoring and data analysis efforts, resource information documentation, and collaborative relationships with existing marine users will continue through the duration of the existing pilot license term. With concurrence of the Project Adaptive Management Team, we will be testing new generations of system components and assembled systems at the project site and will keep FERC informed regarding these efforts.

But then ORPC noted an intent not to seek a commercial license for the project after the pilot license's expiration:

While the project site serves as an excellent testing area, ORPC considers the tidal current velocities at the Project site inadequate to justify pursuing a commercial license. Therefore ORPC does not intend to file a NOI or PAD for the Project at this time.

In a May 25, 2017 letter to the licensee, Commission staff characterized the licensee's March 14 filing as "a notice of intent not to relicense the Cobscook Bay Tidal Project," citing the licensee's position on tidal velocities, and noting the licensee's stated intent to continue operating the project until the pilot license expires on January 31, 2022.

Licensee seeks West Branch and Sysladobsis Dam amendment

A Maine dam owner has applied to federal regulators seeking to exclude from its hydropower license one of two dam-based developments which comprise the project.

At issue is the January 31, 2017 application of Woodland Pulp LLC to the Federal Energy Regulatory Commission for an amendment to the license for the West Branch Storage Dam Project.  The West Branch project was first licensed in 1980, and currently operates under a license issued by the Commission in 2016.  It includes two developments -- Sysladobsis and West Grand -- each of which operates as a water storage facility to provide flood storage and flow releases for downstream hydroelectric generation. 

As described in the license amendment application, the Sysladobsis development includes Sysladobsis Dam.  This dam is about 250 feet long and 9 feet high, consisting of three earth embankment sections, a small timber gate structure, and a fish passage facility.  The dam impounds the 5,400-acre Sysladobsis Lake; water released from the dam flows Sysladobsis Lake into the downstream West Grand impoundment, then into either Grand Lake Stream or Grand Lake Brook.  The project does not include any electricity generating facilities, but rather operates as part of a 112-year-old system of headwater storage dams in the St. Croix River watershed including Woodland Pulp LLC’s Forest City Project No. 2660 which the licensee has applied and the recently relicensed Vanceboro Project No. 2492. Generation associated with these projects occurs at the Grand Falls and Woodland hydroelectric projects downstream on the St. Croix River.

The licensee has requested FERC approval to remove the Sysladobsis development from the West Branch Project as a legal matter, and proposes "to remove the two wooden gates at the Sysladobsis Dam," but says it "does not propose to remove the Sysladobsis Dam as part of the amendment, and such removal is not necessary or appropriate."  Rather, the applicant asserts, "There will be no structural alteration of the dam, and there will be no discharge into the water. Once the gates are removed, the dam will no longer act as a water control structure for Sysladobsis Lake. Instead, impoundment levels and outflow will be determined by the natural precipitation cycle."

According to the licensee's application, "This change is necessary since operation of the Project as-is will no longer be economic under the new license issued March 15, 2016."  The licensee cited license terms and conditions including specific water level requirements and operating plans, reporting, and consultation requirements, "some with unreasonable time constraints."  The application notes, "As such Woodland cannot continue to fund and support the Sysladobsis development and incur increased losses on non-economically viable facility components."

In a separate docket, the Commission is considering an application by the same licensee to surrender its Forest City project license.

PJM's 2020-2021 capacity auction results

PJM Interconnection -- the operator of the wholesale electricity market serving mid-Atlantic and eastern states -- has reported its latest capacity auction results.  PJM's 2020/2021 Reliability Pricing Model Base Residual Auction was the first auction since PJM applied new capacity performance requirements to all resources.  While some areas yielded higher prices due to transmission limits and retiring generators, most of the PJM footprint yielded a clearing price of $76.53/megawatt-day for 2020/2021 -- about 24% lower than last year's auction price for the 2019/2020 delivery year.

Like most other capacity market constructs, the PJM capacity auction is designed to provide a price signal and a forward commitment process that allows new entry to participate or existing units to retire with forward notification.  Securing future capacity revenues can be an important element in supporting project finance for newly built resources.

PJM has had several forms of capacity markets over the years.  Since 2007, its "Reliability Pricing Model" or RPM has featured annual auctions, through which generators and other resources offer to commit to delivering capacity in three years.  The auction is called a "Base Residual Auction," because it covers what's left of anticipated regional needs after any utility- or customer-specific self-supply and bilateral capacity deals are counted.

The recent 2020/2021 auction, covering the period June 1, 2020, to May 31, 2021, was notable in several regards.  It was the first in which all resources were subject to capacity performance requirements which have been phased in over time.  Under these rules, generation, demand response, and energy efficiency resources must perform when dispatched, with few excuses for non-performance.  Failure to perform when dispatched will lead to significant charges for non-performance, meaning resources should not make forward commitments lightly.

The recent auction was also the first to see participation by Price Responsive Demand resources -- a form of demand response in which resources react to market prices by curtailing grid load. The auction was also the first base residual auction held under the provisions of PJM’s Enhanced Aggregation filing.  Under these provisions, which were accepted by the Federal Energy Regulatory Commission in March, seasonal resources may aggregate into a year-round resource -- for example, combining winter-peaking wind generators with solar and demand response resources whose capacity is best in the summer, yielding an aggregated resource that could clear in the market.

In all, PJM says it procured 165,109 megawatts of resources, covering its anticipated residual needs with a 23.3% reserve margin. 2,350 megawatts of new gas-fired generation cleared, suggesting the selected projects may actually be built.  7,532 megawatts of demand response resource cleared -- a notable decrease from previous years' demand response participation rates, explained largely by the newly imposed year-round performance requirements.  1,710 megawatts of energy efficiency resources also cleared, as did 504.3 megawatts of wind, 119 megawatts of solar, and 398 megawatts of aggregated seasonal resources.

Maine commission rejects LNG contract proposals

Maine utility regulators have decided not to order utilities to enter into contracts for liquefied natural gas storage capacity, after finding that none of the proposed contracts satisfied statutory requirements.

In 2013, the Maine legislature enacted the Maine Energy Cost Reduction Act in response to concerns about natural gas and electricity price increases driven by constraints on natural gas supply into and within the New England region.  That law authorized the Maine Public Utilities Commission to execute (or to direct utilities to execute) one or more "energy cost reduction contracts" for natural gas pipeline capacity, if certain prerequisites were met.

In 2016, the legislature enacted a further law amending the Maine Energy Cost Reduction Act, to include liquefied natural gas storage capacity -- "physical energy storage"-- along with interstate natural gas pipeline as within the Commission’s authority for long-term capacity contracts.  In a subsequent proceeding, the Commission solicited bids, ultimately considering 11 physical energy storage contract (PESC) proposals from 6 bidders.

But according to the Commission's order, analysis by its consultant Navigant "indicated that no PESC proposal would provide more than a minimal reduction to natural gas or electricity prices in the regional wholesale markets. Thus, no PESC would reduce electricity prices for Maine consumers, and any benefits of the PESC come from managing the purchase and sale of gas stored in the physical energy storage facility at differing times of the year and flowing those differences back to ratepayers."  The Commission noted that "perhaps the most useful aspect of the Navigant analysis is the extent to which it demonstrates the risks of the PESCs, given the extent to which the cost-benefit results are shown to be highly sensitive to assumptions about the future, such as the presence or absence of ANE and the use of winter peak-day vs. average-day prices."

The Commission further found that "there is no barrier that would prevent private entities from developing LNG storage facilities in the region; thus, under existing market rules, private transactions can be expected to achieve substantially the same market price impacts as those which might occur through the execution of a PESC."  The Commission also concluded that "the proposed PESCs do not meet the statutory prerequisites with respect to market rules and private transactions, cannot be considered economic or commercially reasonable, will not have a significant impact on natural gas or electric prices, and will not significantly enhance reliability in Maine or the region. Moreover, the proposed PESCs expose the State's utility ratepayers to substantial risk and could result in significant rate increases, particularly in the near term."

For these reasons, the Commission concluded that "none of the PESC proposals presented in this docket satisfy the statutory requirements specified in LNG Storage Act. Therefore, the Commission cannot order the execution of a PESC."

In the meantime, progress on an Energy Cost Reduction Contract for pipeline capacity appears stalled, despite years of proceedings and initial progress.  The Commission issued its Phase 1 Order on November 13, 2014 in which it made the necessary prerequisite findings for ordering a pipeline contract, and invited proposals.  It issued its Phase 2 Order on September 14, 2016, finding that two pipeline capacity proposals satisfied the statutory requirements for acceptance and would benefit ratepayers.  But on November 26, 2016, the Commission postponed further activities regarding the development and review of a precedent agreement for pipeline capacity, pending future developments in other New England states, noting that it would monitor such developments and would renew activity in the docket in the future if circumstances warrant. There has been no activity in the pipeline contract docket since the issuance of that November 26 order.

Massachusetts community microgrid projects solicited

A Massachusetts economic development agency focused on clean energy has launched a program seeking to catalyze the development of community microgrids throughout Massachusetts.

Generally speaking, a microgrid is a localized power grid that can disconnect from the traditional grid to operate autonomously.  According to the U.S. Department of Energy, a microgrid's ability to operate while the main grid is down means microgrids can strengthen grid resilience and mitigate disturbances, while enabling faster system response and recovery once reconnected to the main grid. Microgrids can also support flexibility and efficiency, by enabling the integration of growing deployments of renewable and distributed energy resources like solar, and by reducing energy losses in transmission and distribution.
 
A "community microgrid" could be defined in several ways, but a typical definition focuses on a multi-user microgrid providing electrical and/or thermal energy to multiple consumers, integrated with and supported by the local community, relevant utilities, and building or site owners.  As with other microgrids, a community microgrid implementation could reduce energy costs and reduce greenhouse gas emissions, while providing increased energy resilience.

While federal support for microgrids has existed for years, states are now becoming active in exploring how microgrids can help meet society's energy needs and policy goals. Massachusetts is one hotbed of interest in microgrids, and a recently announced program could help stimulate the microgrid industry. The Massachusetts Clean Energy Center’s (MassCEC) Community Microgrids Program anticipates providing about $75,000 in funding to support each of 3 to 5 prospective community microgrid projects with the following characteristics:

• Are community, multi-user microgrids (as opposed to single owner or campus-style microgrids) located in Massachusetts -- but MassCEC will consider proposals from Applicants with an existing campus wishing to extend the microgrid to additional parties outside of its borders;
• Demonstrate significant potential to reduce greenhouse gas emissions through the integration of energy efficiency, Combined Heat and Power (“CHP”), renewable energy systems, electric and/or thermal storage technologies, demand management, energy efficiency, and other relevant technologies;
• Have the active and engaged support of the local utility (either investor-owned or municipal light plants) and other relevant stakeholders;
• Encompass a public or private critical facility, including but not limited to schools, hospitals, shelters, libraries, grocery stores, service (gas) stations, fire/police stations or waste water treatment plants;
• Support the distribution system by addressing capacity concerns, providing black start capability, facilitating renewables integration, or providing other services that are meaningful to the local utility;
• Attract third party investment; and 
• Highlight Massachusetts-based clean energy/microgrid technology.

MassCEC is presently soliciting Expressions of Interest from groups interested in participating in feasibility assessments for community microgrid projects meeting its defined criteria.  According to MassCEC, respondents may include municipalities and their public works departments, electric distribution companies, municipal light plants, emergency services departments, owners of critical infrastructure such as hospitals and financial institutions, self-organized groups of commercial building owners, developers or any other actor that either owns property within a potential microgrid or can demonstrate that they represent stakeholders with the capability of developing a community microgrid.  Support from the local government and the relevant electric or gas distribution company is also required.

MassCEC says it intends its funding to support feasibility assessments to advance the selected microgrid projects through the early project origination stages, enabling them to attract third-party investment. Projects that produce a favorable feasibility assessment may then be eligible for additional technical assistance or grants for later stages of project development

Completed expressions of interest, including all required documentation, must be received by MassCEC by Friday, June 23, 2017 by 4:00pm. MassCEC anticipates awarding the first round of feasibility assessments in Q3 2017.

Will clustering help New England's interconnection queue?

Faced with a persistent backlog of requests to interconnect to the electric grid across parts of New England, will the region's major grid operator adopt a "clustering" methodology to streamline the study process and reduce procedural delays?

At issue are ISO New England's interconnection procedures, which govern the process through which generators and transmission lines may interconnect to the New England bulk power system.  For nearly all large projects and some smaller ones, ISO-NE administers the process and conducts extensive engineering studies to determine whether such interconnections would be feasible without adversely affecting reliability and how they should be accomplished.  In general, ISO-NE uses a first-come, first-served basis: a project's impacts on the grid are studied in sequential order based on that project's position in the interconnection queue.  In practice, this means that a project's studies do not commence until the studies for projects ahead in line are complete.

According to ISO-NE, this system has worked well for most of the region.  Excluding northern and western Maine, the grid operator reports that on average, system impact studies are completed within a year of the customer's interconnection request.  But ISO-NE notes that its "Interconnection Queue has experienced a persistent backlog of requests to interconnect in northern & western Maine."  Many of these requests relate to wind projects located relatively far from the transmission system, but similar challenges could arise relating to large solar projects in parts of Maine, Vermont, or New Hampshire.

The grid operator may be able to address this backlog by changing its interconnection procedures to be more in line those adopted in other regions, by allowing "clustering" or pooled and simultaneous study of certain resources. As described by ISO-NE in a presentation delivered last year, all of the other Independent System Operators or Regional Transmission Organizations -- such as NYISO, PJM, MISO, CAISO, and SPP - include some form of clustering in the interconnection process; New England stakeholders have requested that ISO-NE investigate clustering; and the Federal Energy Regulatory Commission has also addressed clustering, including in a May 2016 technical conference.

ISO-NE's proposed clustering methodology would allow, under specific circumstances, for two or more Interconnection Requests to be analyzed in the same System Impact Study (SIS) effort.  Projects participating in a cluster would share cost responsibility for certain shared interconnection related transmission upgrades, known as Cluster Enabling Transmission Upgrades (CETU), identified by ISO-NE as necessary for the applicable interconnection requests to interconnect.

As noted in an April 2017 presentation to the NEPOOL Participants Committee, this proposal was favorably voted by the Transmission Committee on January 24, 2017 and by the Participants Committee on February 3, 2017.

The presumptive next step forward in New England's attempt to resolve the interconnection queue backlog by clustering studies would be that ISO-NE will file its tariff revisions with the FERC -- but the grid operator has signaled an intent to wait to file the revisions until there is "a high probability of a FERC quorum."  Three of the five seats on the Commission are presently vacant, and the Commission is currently operating without a quorum.  In the meanwhile, ISO New England's present tariff does not allow clustering of studies, so for now customers and others proposing to interconnect generation or transmission into the New England grid will continue to wait and push for reform.

Boom in FERC hydro relicensing

U.S. federal hydropower regulatory staff currently has a full workload processing original license, relicense, and exemption applications, as well as its compliance and dam safety work, according to testimony presented to the House Energy & Commerce Committee, Subcommittee on Energy -- and this workload is expected to increase as many hydro projects face relicensing proceedings.

The Federal Energy Regulatory Commission regulates over 1,600 non-federal hydropower projects located at over 2,500 dams, under Part I of the Federal Power Act.  These projects collectively represent about 56 gigawatts of hydropower capacity, over half of the nation's total hydropower capacity.

The Federal Power Act generally requires non-federal hydropower projects to be licensed by the Commission if they: (1) are located on a navigable waterway; (2) occupy federal land; (3) use surplus water from a federal dam; or (4) are located on non-navigable waters over which Congress has jurisdiction under the Commerce Clause, involve post-1935 construction, and affect interstate or foreign commerce.  Licenses are generally issued for terms of between 30 and 50 years, and are renewable.

According to testimony presented to the House Energy & Commerce Committee, Subcommittee on Energy on May 3, 2017, the Commission's relicensing workload "has started to increase and will continue to remain high well into the 2030s."  Between fiscal years 2017 and 2030, the Commission projects that about 480 older projects will begin the pre-filing consultation stages of the relicensing process.  These projects facing relicensing represent about 45 percent of Commission-licensed projects, and one-third of jurisdictional licensed hydropower capacity.

The testimony also notes that some of these projects may face different standards in a relicensing context than were considered when their current or original licenses were issued.  Many projects now entering relicensing were first licensed in the early to mid-1980s, following the enactment of PURPA but prior to enactment of modern environmental standards.

For example, the Electric Consumers Protection Act of 1986 directed the Commission, when issuing licenses, to give equal consideration to power and development, energy conservation, fish and wildlife, recreational opportunities, and other aspects of environmental quality.  This mandate may not have applied to a 40-year license issued in 1982, but would come into play during a relicensing case initiated in 2017.

The House Subcommittee on Energy is considering discussion drafts and several pieces of legislation affecting hydropower, including the Hydropower Policy Modernization Act of 2017; the Promoting Hydropower Development at Existing Non-Powered Dams Act; the Promoting Closed-Loop Pumped Storage Hydropower Act; the Promoting Small Conduit Hydropower Facilities Act of 2017; and the Supporting Home Owner Rights Enforcement Act.

Total eclipses, solar PV and the grid

Utilities and electric grid coordinators are preparing for a total solar eclipse that is projected to temporarily reduce solar photovoltaic generation across parts of North America this summer. 

The 2017 total solar eclipse will be the first in the U.S. in 26 years (since Hawaii 1991), and the first in the lower 48 states since 1979.  While the duration of the total eclipse across the U.S. will be roughly 93 minutes, some areas in its path will experience up to 95% of the Sun being obscured.

The eclipse is projected to affect solar PV generation.  Solar resources occupy an increasing role in the U.S. electric generating portfolio. Between 2000 and 2016, total U.S. solar capacity increased from 5 megawatts (MW) to 42,619 MW.  But as more solar resources are connected to the grid, the potential impact of an eclipse on grid operations may change.

According to a May 1, 2017 presentation to the Board of Governors of the California ISO, the eclipse is projected to reduce solar output in the CAISO region by 4,194 megawatts, while gross load will increase by 1,365 MW.  Taking into account estimated wind production, the presentation projects a net load increase of 6,008 MW during the eclipse.

The ramp rate, or speed at which supply and demand will change, is also a factor.  The eclipse is projected to diminish solar output by about 70 MW per minute as it approaches totality, and about 90 MW per minute on the return.  By contrast, a typical average ramp rate for CAISO might be 29 MW per minute.  Thus the eclipse is projected to call for a greater degree of fast-ramping or flexible resources, compared to typical operating conditions.

But according to international electric reliability organization NERC, the August 21, 2017 total solar eclipse "is unlikely to cause any reliability issues to the North American bulk power system."  NERC documented its findings in an April 25, 2017 white paper, A Wide-Area Perspective on the August 21, 2017 Total Solar Eclipse.  NERC's report identifies California and North Carolina as the states most likely to experience the greatest impact from solar production fall-off from the eclipse. At the same time, NERC recommends "that utilities in all states perform specific studies of the eclipse’s impact of solar photovoltaic power output on their systems and retain necessary resources to meet the increased electricity demand requirements."  In particular, NERC notes that generation and system operators may greater visibility into utility-scale solar projects than into behind-the-meter or distributed solar photovoltaic resources, highlighting the need to model all scales of solar development.

Following the 2017 eclipse, the next total solar eclipse is projected to cross North America on April 8, 2024.

New England summer 2017 electricity supply forecast

New England will have an adequate supply of electricity this summer, according to the regional grid operator, but its forecasts show the possibility of occasional "tight system conditions."

ISO New England Inc. is the operator of the region's wholesale electricity markets and bulk power system.  To help inform its planning, the grid operator prepares seasonal short-term forecasts.  ISO New England's most recent projection, covering summer 2017, found that "New England is expected to have the resources needed to meet consumer demand for electricity this summer."

Weather can have a significant impact on consumer demand for electricity.  ISO New England projects that under normal weather of about 90 degrees Fahrenheit (°F), this summer's electricity demand will peak at 26,482 MW.  This forecast falls between last year's summer system peak (August 12, 2016, at 25,466 MW) and the all-time record peak demand (August 2, 2006, at 28,130 MW).  But if the summer of 2017 is unusually hot, New England might set a new record for system demand: the grid operator projects that demand could rise as high as 28,865 MW under extreme summer weather, such as an extended heat wave of about 94°F.

ISO also notes that its "forecast estimates indicate the possibility of a tighter-than-expected margin of supply and reserves" because "up to 700 megawatts (MW) of expected new resources are delayed and may not be available this summer."  In addition, the 1,500 MW Brayton Point coal- and oil-fired power plant in Massachusetts will retire, leaving New England with approximately 29,400 MW of total capacity available this summer.  Meanwhile, approximately 2,000 MW of behind-the-meter solar facilities are currently installed throughout the region, which can reduce demand for grid power.

In its press release, ISO New England noted its readiness to maintain system reliability under tight supply conditions this summer.  Measures the grid operator could take in case of a supply deficit under peak summer conditions include importing additional electricity from neighboring regions, and implementing a variety of operating procedures to keep the grid balanced including calling on demand-response resources to curtail energy use.