December 24, 2022 capacity deficiency event in New England

New England's wholesale electricity grid experienced a capacity deficiency on December 24, 2022, according to grid operator ISO New England, Inc., but the system operator says its operating procedures successfully balanced supply and demand on the regional power system during evening peak hours, when unexpected generator outages and reductions and lower-than-expected imports led to a shortfall in operating reserves.

According to ISO-NE:

ISO New England did not call for controlled power outages on Christmas Eve, but did declare a capacity deficiency, meaning the region’s supply of electricity was insufficient to meet required operating reserves in addition to satisfying consumer demand, at 4:30 p.m. This action was taken after approximately 2,150 megawatts (MW) of resources scheduled to contribute power during the evening peak became unavailable. The outages and reductions coincided with net imports being approximately 100 MW less than had been expected based on that day’s Morning Report.

While the capacity deficiency was ongoing, at 4:40 PM, ISO-NE declared a "capacity scarcity condition" under its Forward Capacity Market’s Pay-for-Performance rules. This condition remained in effect until 6:05 p.m. Under the Pay-for-Performance rules, any resource that failed to meet its capacity supply obligation is penalized at a rate of $3,500 per megawatt-hour (MWh) for failing to meet its obligation, while resources that over-performed will receive $3,500/MWh of additional revenue. In total, ISO-NE has estimated penalties for the December 24 event to be approximately $39 million. In addition, any energy resources that cleared in the Day-Ahead Energy Market but failed to provide electricity in real-time are charged the real-time price for the missing energy; Real-Time Energy Market prices averaged approximately $484/MWh over the course of the day, peaking over $2,200/MWh during the 5 p.m. hour while the capacity scarcity condition was ongoing.

On January 12, 2023, ISO-NE provided an update on the December 24, 2022, capacity deficiency, "to help correct any confusion, misinformation, and misunderstanding resulting from various news stories and social media posts." According to that update, the incident was "mainly about timing". After noting that it entered the December 24 operating day with sufficient resource commitments to meet demand and required operating reserves, with a surplus of over 950 megawatts of fast-start resources, ISO-NE explains what happened next:

As the day went on, some generators in the region experienced unanticipated issues that caused them to go offline or reduce their output. These outages were caused by cold temperatures or mechanical problems, and not due to inadequate fuel supplies. Expected imported electricity from Canada was also reduced due to transmission system issues and unexpectedly high consumer demand in Québec. Despite these issues, New England was still expected to meet demand and operating reserves over the evening peak as of 3 p.m.

Around 4 p.m., additional unanticipated outages led to a capacity deficiency in the region. This meant that the 950 MW surplus was depleted and supply was insufficient to meet both demand and required operating reserves. In response, ISO New England system operators implemented procedures for dealing with capacity deficiencies. This included calling upon any resource that could respond quickly enough to be online for the evening peak, which usually falls between 5 and 6 p.m. during the winter months. The ISO dispatched all remaining offline resources that were available to provide electricity or operating reserves during this period.

In its update, ISO-NE described pricing and customer impacts from the incident:

Prices in the Real-Time Energy Market averaged more than $2,000 per megawatt-hour (MWh) during the 2.5-hour capacity deficiency. While high, these prices are unlikely to affect most consumers given how retail rates are set in the region. Though practices vary by state and utility coverage area, the rates paid by most retail customers are set for months-long periods and not subject to volatility within the wholesale marketplace. 

Almost all of New England’s wholesale electricity is bought and sold in the Day-Ahead Energy Market, where prices were unaffected by the capacity deficiency. Average day-ahead prices during that time were roughly $285/MWh.

As ISO-NE noted in its January 4 report, other regions of North America were challenged by extreme weather around the long holiday weekend, prompting varied responses outside New England including controlled power outages.

NJ considers PJM capacity market alternatives

The New Jersey Board of Public Utilities has opened an investigation into "how the State can best achieve its reliability, clean energy, and environmental objectives, while keeping costs to consumers as low as possible." Like many states, New Jersey’s utilities participate in a federally regulated regional transmission organization’s capacity market, but are also subject to state clean energy laws -- a tension that has caused the state's energy regulators to consider whether to leave the PJM regional capacity market.

At issue is whether New Jersey can "achieve its long-term clean energy and environmental objectives under the current resource adequacy procurement paradigm" -- the regional electric capacity market operated by PJM Interconnection -- or whether it should adopt an alternative mechanism to "meet New Jersey’s resource adequacy needs in a manner consistent with the State’s clean energy and environmental objectives, while considering costs to utility customers."

New Jersey electric utilities currently participate in the PJM regional markets, including a capacity market. The state has adopted a 2019 Energy Master Plan: Pathway to 2050, establishing a series of state-focused clean energy goals such as 7,500 MW of offshore wind by 2035 and 100% clean energy by 2050. Other states in the PJM region have adopted different clean energy goals.

At the same time, PJM's regional market is federally regulated. In December 2019, the Federal Energy Regulatory Commission directed PJM to modify its "Minimum Offer Price Rule" or MOPR, governing the capacity market. Designed to counteract excessive market power, the federal ruling directed PJM to modify its MOPR to also counteract the pricing effects of state clean energy policies. In its state Energy Master Plan, New Jersey described FERC's action as "actively attempting to support fossil fuel interests in the [PJM] region under the guise of promoting ‘fair’ competition."

In response to the FERC's MOPR order, on March 27, the New Jersey Board of Public Utilities issued an Order Initiating Proceeding in Docket No. EO20030203. Citing the federal order, the Board characterized it as "a direct attack on the State’s clean energy programs" and expressed concern that continued participation in the federally-regulated PJM market could frustrate New Jersey's ability to achieve its clean energy goals. The Board thus initiated a proceeding to consider whether to retain the current PJM market paradigm, or whether an alternative could achieve the state's climate and environmental goals at a lower cost to consumers.

Withdrawing from a regional transmission organization can be done under certain circumstances, but federally regulated tariffs and territories spanning multiple states with their own laws can complicate the path toward a clean break. As envisioned by the Board, possible alternatives for New Jersey might include using a "fixed resource requirement" or FRR approach under the PJM tariff to effectively withdraw one or more service areas from the broader PJM capacity market, or adopting a statewide clean energy standard that would require load-serving entities to source increased percentages of renewable or other clean energy.

Board staff subsequently issued a Request for Written Comments in the proceeding, soliciting written comments on four sets of topics by April 29. Issues raised in the request for comment include whether New Jersey could utilize the Fixed Resource Requirement alternative to satisfy its resource adequacy needs and accelerate its clean energy goals, whether modifications to the Board's Basic General Service construct could facilitate resource adequacy procurements aligned with the state's Energy Master Plan, and whether other mechanisms such as a clean energy standard or clean energy market could facilitate achievement of the state's clean energy goals.

Staff have suggested the Board's investigation will be completed later this year.

FERC approves energy storage tariffs

U.S. utility regulators have approved the first two regional implementations of a landmark 2018 order designed to remove barriers to the participation of electricity storage in wholesale markets.

In 2018, the Federal Energy Regulatory Commission issued its Order No. 841, requiring each organized power market to revise its tariff to establish a "participation model" for electric storage resources in the capacity, energy and ancillary service markets. The rule requires each market's participation model to include market rules that recognize the physical and operational characteristics of electric storage resources and facilitate their participation in those markets. The Commission later affirmed the rule, through its Order No. 841-A.

Last week, the Commission issued two orders approving Order No. 841 compliance filings by Southwest Power Pool, Inc. and by PJM Interconnection. The Commission generally found that the SPP and PJM tariff revisions complied with the new rule, and largely accepted their filings. For example, the Commission found that both proposals "generally enable electric storage resources to provide all services they are capable of providing; allow electric storage resources to be compensated for those services in the same manner as other resources; and appropriately recognize the unique physical and operational characteristics of electric storage resources."

However, the Commission also provided directives for further compliance filings by SPP and PJM to be made within 60 days. The Commission found that while both filed tariffs generally satisfy Order No. 841’s directive allowing electric storage resources to de-rate their capacity to meet minimum run-time requirements, neither tariff included minimum run-time requirements for resource adequacy and capacity, respectively. Because "such requirements affect rates, terms and conditions of service," the Commission initiated proceedings under section 206 of the Federal Power Act to address the specific issue of minimum run-time requirements.

In a pair of separate statements (on SPP and on PJM), Commissioner McNamee concurred with the orders insofar as they found compliance with the Commission's orders and regulations. But Commissioner McNamee said, "I write separately, however, to express my continuing concern that the Commission exceeded its statutory authority under the Federal Power Act, and should have, at the very least, provided states the opportunity to opt-out of the participation model created by the Storage Orders." Commissioner McNamee also reiterated jurisdictional concerns he had previously raised in a partial concurrence to and partial dissent from Order No. 841-A, "to the extent the Commission’s Storage Orders exercised authority over the distribution system and behind-the-meter."

Other organized wholesale market operators, such as ISO New England, Inc., are also adopting tariff revisions to comply with Order No. 841, to enhance the ability of electric storage facilities to participate in regional wholesale electricity markets.

New England electric fuel security reform filings delayed

Federal electricity regulators have given New England's regional grid operator more time to develop proposed new mechanisms to enhance long-term fuel security, after states and market participants asked for an extension to allow continued stakeholder discussions. At stake are what could be significant reforms to the region's electricity markets, including new opportunities for generators to earn revenue for providing fuel security, as well as the prospect of significant new costs for consumers.

ISO New England Inc. is the regional transmission organization and independent system operator for the electric grid serving nearly all of New England. In this role, it develops and administers markets for electric energy, capacity, and other products. ISO-NE also engages in regional system planning, and manages proposals to retire or close power plants that provide capacity to the region.

In 2018, the owner of the Mystic Generating Station, the largest power station in Massachusetts by nameplate capacity, proposed to retire its units in 2022. But after a study of the remaining electric system, ISO-NE determined that the retirement of Mystic's units 8 and 9 would present "unacceptable fuel security risks" that could lead to rolling blackouts as soon as the winters of 2022 through 2024. In response, ISO-NE asked the Federal Energy Regulatory Commission for waivers to allow the grid operator to retain the Mystic units to meet fuel security needs.

Some stakeholders disagreed that the Mystic units' retirement posed a reliability risk; others argued the costs of retaining them would outweigh any benefits. While the Commission denied ISO-NE's waiver request, it ultimately approved a short-term cost-of-service agreement under which regional ratepayers will pay to keep the Mystic units online. But the Commission also made a preliminary finding that ISO-NE's tariff may be unjust and unreasonable, and directed ISO-NE to file proposed tariff revisions creating a long-term fuel security mechanism by July 1, 2019. At the grid operator's request, the Commission later extended that deadline to November 15, 2019, to allow more time for proposal development and stakeholder discussion.

In the meantime, this spring ISO-NE filed a proposed short-term "inventoried energy program" from December 1 through the end of February during winters 2023/2024 and 2024/2025 as "a bridge to a long-term, market-based solution that more comprehensively addresses the region’s energy security risks" -- but Commission staff identified that filing as "deficient" and requested additional information, which prompted ISO-NE to provide additional information. In the absence of a Commission quorum willing to vote, those revisions became effective by operation of law on August 6, 2019, although parties have sought rehearing regarding the Commission's failure to act.

But even more time may be necessary. On July 31, 2019, the New England States Committee on Electricity (NESCOE) filed a motion requesting an additional six-month extension of time to allow ISO-NE and the region to work through issues related to ISO-NE’s proposed long-term fuel security mechanism. Representing the governors of the six New England states, NESCOE said granting its request would "enable a more complete and holistic filing in response to the directives in the July 2018 Order, allow ISO-NE to address core consumer protection elements that are fundamental to state support, and remove barriers to achieving a greater degree of regional coalescence around a proposal." Several commenters supported the motion.

Ultimately, the Commission granted an extension of time up to and including April 15, 2020 for ISO-NE to file its long-term fuel security mechanism. While New England will soon be forced to address the issue of fuel security for its electric generating portfolio, these short-term and long-term market changes proposed by the grid operator are on hold for now.

FERC upholds Block Island offshore wind PPA

Federal energy regulators have denied a complaint by a Newport, Rhode Island city councilor against state regulators' approval of a power purchase agreement for an offshore wind project off Block Island.

At issue is Deepwater Wind Block Island, LLC's small-scale 30-megawatt offshore wind project located near Rhode Island's Block Island. The project sells its output to utility Narragansett Electric Company, Inc. d/b/a National Grid (National Grid), pursuant to a power purchase agreement approved by the Rhode Island Public Utilities Commission on August 16, 2010.

On June 7, 2018, Ms. Kathryn E. Leonard filed a complaint to the Federal Energy Regulatory Commission, alleging that the implementation of the power purchase agreement violated various federal laws, including the Federal Power Act, Public Utility Regulatory Policies Act of 1978 (PURPA), and the Supremacy and Interstate Commerce Clauses of the U.S. Constitution.

On April 24, 2019, the Commission issued its order denying Ms. Leonard's complaint. In the seventeen-page order, the Commission noted that the complainant provided no evidence in support of her assertion that the power purchase agreement was entered into pursuant to Rhode Island's implementation of PURPA. Instead, the Commission found that the Rhode Island Public Utilities Commission's approval of the contract was pursuant to state law, not pursuant to its PURPA regulations -- but that even if it were pursuant to PURPA, federal regulations governing sales by qualifying facilities to electric utilities explicitly permit negotiated rates.

The Commission similarly found that the complainant failed to show that the contract or its pricing was unjust and unreasonable under the Federal Power Act, and to provide sufficient support for its constitutional claims. The Commission also distinguished the Block Island PPA from contracts it previously invalidated in another case, Hughes v. Talen, which involved contracts for differences and an explicit requirement of participation in the capacity market. For these reasons, the Commission denied the complaint.

The Block Island project is the first commercially-operating offshore wind project in the United States. A number of other projects are currently under development, and several states in the Northeast have enacted laws requiring utility procurement of offshore wind energy. According to a 2016 analysis by the U.S. Department of Energy, U.S. offshore wind has a technical resource potential of more than 2,000 gigawatts of capacity, or 7,200 terawatt-hours of generation per year -- nearly twice the nation’s current electricity use.

FERC relicenses Poe hydro project

The Federal Energy Regulatory Commission has issued an order issuing a new hydropower license to utility Pacific Gas & Electric Company for its Poe Hydroelectric Project.

The 143-megawatt project is located on the North Fork Feather River in northern California, and includes land within the Plumas National Forest. Originally licensed in 1953, the project includes two dams impounding reservoirs, a 33,000-foot-long pressure tunnel bypassing about 7.6 miles of the river, and a powerhouse with two turbines.

The Commission issued a new 40-year license for the Poe project to PG&E on December 17, 2018. In relicensing proceedings, the Commission considers a number of public interest factors, including the economic benefits of project power. In general, the Commission evaluates the economics of a hydropower project by comparing the current costs of the project to likely alternative power, without considering forecasts concerning potential future inflation, escalation, or deflation beyond the license issuance date. The Commission says the basic purpose of its economic analysis is to provide a general estimate of the potential power benefits and the costs of a project, and of reasonable alternatives to project power.

In the Poe project's case, the Commission noted that after considering mandatory conditions and other measures suggested by Commission staff, PG&E's annual cost of operating the project would be about $9,590,000. Assuming that the project would generate an average of 498,113 megawatt-hours of energy annually, this works out to $19.3 per megawatt-hour. By comparison, the Commission found that the project's the corresponding alternative energy cost plus the value of its dependable capacity gave this power a value of $50,800,000, or $102 per megawatt-hour in the first year of operation, the project would cost $41,210,000 or $82.7 per megawatt-hour less than the likely alternative cost of power.

ISO-NE files info on 2022-2023 capacity market auction

This week the operator of New England's wholesale electricity markets made a series of filings with its federal regulator providing information on its upcoming thirteenth forward capacity auction, through which electric generators may commit to providing electric capacity during the period from June 1, 2022 through May 31, 2023.

ISO New England Inc. is the independent system operator and wholesale market-maker for most of New England's electricity grid. It is a private, not-for-profit entity, which operates pursuant to a tariff on file with the Federal Energy Regulatory Commission. As part of its planning for system operations, ISO-NE operates a forward capacity market through which it conducts annual auctions through which qualified generators and other resources may bid to obtain commitments to provide capacity in a future year, in exchange for which resources will be compensated. The next primary auction for capacity supply obligations will be Forward Capacity Auction 13 (or FCA 13), which will be held beginning on February 4, 2019, and will cover the 2022-2023 capacity commitment period.

In advance of each primary auction, ISO-NE calculates an "Installed Capacity Requirement," which it defines as a measure of the installed resources that are projected to be necessary to meet reliability standards in light of total forecasted load requirements for the New England Control Area and to maintain sufficient reserve capacity to meet reliability standards. In computing the Installed Capacity Requirement, the grid operator considers parameters and assumptions including load forecast, resource capacity ratings, and resource availability. It also considers what relief can be obtained during a capacity deficiency through measures including emergency assistance (tie benefits) from neighboring interconnected regions (New Brunswick, New York, and Quebec), load reduction by reducing system voltage by 5%, and running the system at a minimal level of operating reserve.
 
In its November 6 Installed Capacity Requirement filing, the grid operator told the Commission that it proposed a installed capacity requirement for FCA 13 of 33,750 megawatts, after taking into account 969 megawatts of credits over interconnection with Canadian utility Hydro-Quebec.

In a parallel Informational Filing for qualification in FCA 13, the grid operator noted that 31,432 megawatts of existing generating capacity resources qualified for the 2022-2023 capacity commitment period, as did 80 megawatts of existing import capacity resources, and 3,413 megawatts of existing demand capacity resources, totaling 34,925 megawatts of existing capacity. Some resources submitted bids to retire, and 3,223 megawatts of resources submitted bids to withdraw in part or in whole from the auction if it clears below a defined price. Additionally, ISO-NE qualified 238 new capacity resources, totaling 8,716 megawatts.

ISO-NE will conduct its thirteenth forward capacity auction starting on February 4, 2019.

ISO-NE Pay for Performance starts June 2018

The operator of New England's electric grid and wholesale electricity markets has adopted a new design for its capacity market, called “Pay For Performance” or PFP, which will become effective on June 1, 2018. As of that date, capacity payments will reward power resources that make investments to successfully boost performance during periods of system stress, while resources that don’t perform will forfeit capacity payments. According to grid operator ISO New England, Inc., these capacity market reforms represent “a significant evolution of the Forward Capacity Market.”

Since 2008, ISO-NE has operated a wholesale market for electric capacity, in addition to markets for energy and ancillary services. According to the grid operator, its Forward Capacity Market (FCM) ensures that the New England power system will have sufficient resources to meet the future demand for electricity. The market design features annual Forward Capacity Auctions held three years in advance of the operating period, in which resources compete to obtain a commitment to supply capacity in exchange for a market-priced capacity payment.

ISO-NE first proposed a version of PFP in 2014 as a means to address what it characterized as "capacity resource performance issues in New England." According to an article by ISO-NE's chief executive officer, ISO-NE felt that the prevailing capacity market design increasingly failed to incentivize resource performance during times of system stress. The grid operator reported "escalating incidents of poor generator performance that have threatened bulk power system reliability," and identified a "broken linkage" between capacity payments and actual performance under the previous rules.

According to ISO-NE, its Pay for Performance reform "firmly connects capacity payments to resource performance." It is designed to increase financial incentives for resource owners to make investments to ensure their resource’s reliability during periods of scarcity.

The Pay for Performance market design is based on a “two-settlement approach” such as is used in forward markets for electricity and other commodities.

In a first stage, a market participant takes on a Capacity Supply Obligation – a forward obligation to provide a specified amount of capacity from its resource – in exchange for a Capacity Base Payment. That base payment is determined by multiplying the resource’s Capacity Supply Obligation (in megawatts) by the relevant clearing price – either the clearing price from a Forward Capacity Auction or reconfiguration auction, or a bilateral contract price. Once a market participant has taken on a Capacity Supply Obligation in exchange for the Capacity Base Payment, the participant has a physical, resource-specific obligation to cover a share of the system’s energy and reserve requirements during reserve deficiencies.

In a second stage, the participant is subject to a settlement for deviations from its committed share. Under PFP, this second payment, which can be positive or negative, is called the Capacity Performance Payment. If a resource delivers more than its share of the system’s requirements during a capacity scarcity condition, it will be paid an additional amount for that incremental production; if it delivers less than its share, it must “buy out” of its position by paying other resources that did deliver.

Tariff revisions were accepted by the FERC in 2014 and 2015, and ISO-NE has subsequently developed further changes to its tariff to implement the program. The revised tariff is scheduled to take effect on June 1, 2018.

ISO-NE files 12th capacity auction results

The organization responsible for New England's wholesale electricity markets has announced the results of its twelfth annual forward capacity auction. According to grid operator ISO New England, Inc., its FCA 12 concluded with sufficient resources to meet electricity demand in 2021-2022, at the lowest price in five years.

As in some (but not all) other organized electricity markets, New England's electricity market design includes a wholesale energy market as well as a forward capacity market. Operated by ISO New England, the Forward Capacity Market or FCM is designed to secure capacity resources sufficient to meet future demand. The capacity market is separate from the energy market, and can provide additional revenues for qualified resources.

The grid operator conducts annual Forward Capacity Auctions or FCAs, held three years in advance of each one-year operating period. Generation and other capacity resources such as load management or energy efficiency can compete in these auctions to obtain monthly market-priced capacity payments during the delivery year, in exchange for the obligation to supply capacity -- and supply energy or curtail demand when dispatched by the ISO in that future period. Capacity revenues can support the development of new resources as well as the retention of existing plants by providing predictable cash flows and incentivizing consistent resource availability.

ISO New England held its twelfth FCA on February 5 and 6, 2018, auctioning off capacity supply obligations for the capacity commitment period of June 1, 2021 through May 31, 2022. On February 28, 2018, ISO New England submitted its forward capacity auction results filing for FCA12 to the Commission. According to the filing, the descending clock auction commenced with a starting price of $12.684/kW-month, with resources in most zones to be paid at a clearing price of $4.631/kW-month based on the system sloped demand curve. About 1,100 megawatts of imports over certain interfaces with Canada will be paid at reduced capacity clearing prices. These prices are all below recent ISO-NE forward capacity auction results.

Through FCA12, ISO-NE procured 30,011 megawatts of generation, including 174 megawatts of new generation. The auction also acquired about 3,600 megawatts of energy efficiency and demand-reduction measures, 514 megawatts of which is new. The grid operator estimated the total cost of the capacity market in 2021-2022 to be approximately $2.07 billion.

ISO noted that it had rejected two "de-list bids", or requests by existing generators to leave the capacity market, for local reliability reasons. It identified those bids as coming from Exelon Generation Company, LLC with respect to its Mystic 7 and 8 units, totaling about 1,278 megawatts. As described in supporting testimony, ISO asserted that "allowing the resources to leave the market would have resulted in a violation of NERC, NPCC, or ISO criteria." According to a related press release, ISO found that "transmission lines in Greater Boston could be overloaded if Mystic 7 and Mystic 8 were not available during 2021-2022."

ISO described the results of the auction as just and reasonable, and asked the Commission to accept the filing.

Report: 50 GW US electric storage potential

A recently adopted federal regulation aimed at helping electric storage resources participate in wholesale electricity markets could unlock 7,000 megawatts of storage potential -- or up to 50,000 megawatts if all benefits can be captured through state and federal action -- according to a report by consulting firm The Brattle Group.

The study is titled, “Getting to 50 GW? The Role of FERC Order 841, RTOs, States, and Utilities in Unlocking Storage’s Potential.” Released on February 22, 2018, the report concludes that electric storage market potential could grow to 50,000 MW within the next ten years, if storage costs continue to decline and state and federal regulatory policies continue to be supportive.

The Brattle report comes one week after the Federal Energy Regulatory Commission's issuance of Order No. 841, a final rule aimed at removing barriers to the participation of electric storage resources in wholesale markets operated by regional transmission organization and independent system operators. The Brattle report describes Order 841 as "an important step in unlocking the value in wholesale energy, ancillary services, and capacity markets," noting the consulting firm's finding that at least half of storage's total possible value can be achieved in wholesale electricity markets.

Crucially, the Brattle study finds that fully realizing the value of electric storage will require state policy reforms similar to those at the federal level. Generally speaking, wholesale electricity sales and interstate transmission are subject to federal jurisdiction, while retail sales and local distribution are subject to state jurisdiction. This split jurisdiction means that some value streams available through battery storage can be only captured at the state level -- for example benefits from deferring or avoiding investments in transmission and distribution infrastructure by using storage as a non-transmission alternative, or customer benefits like increased reliability and engagement with power supply.

Storage can also save customers money -- as noted in the report, avoiding retail rate demand changes is one of the primary business drivers for storage deployment by U.S. commercial and industrial customers. But these values can only be fully captured through state action to remove the barriers that remain.

Some states are acting to incentivize or require energy storage investments. California set a mandate of 1,325 megawatts of storage by 2020, and Oregon and Massachusetts have also set state storage mandates.

The report also covers implications for existing storage resources, most of which are hydropower. It finds that existing storage resources can provide substantial new capabilities, if they can be operated more flexibly than today. As noted in the report, "Increasing flexibility of existing hydro can be very valuable, reducing the need for new investments." The report also suggests that optimizing operating strategies could increase storage revenues by 2 to 5 times.

NH PUC considers efficiency plan

New Hampshire utility regulators are considering a three-year statewide energy efficiency plan proposed by several electric and gas utilities. The case could shape the near-term future of New Hampshire energy efficiency programming.

Under a 2016 settlement agreement, the New Hampshire Public Utilities Commission approved the implementation of an Energy Efficiency Resource Standard (EERS) beginning 2018, subject to Commission approval of the specific programs proposed to meet this standard. On September 1, 2017, utilities Liberty Utilities, Public Service Company of New Hampshire, Unitil Energy Systems, Inc. and Northern Utilities, Inc. jointly proposed a 2018-2020 Statewide Energy Efficiency Plan for approval by the Commission. The proposed 2018-2020 New Hampshire Statewide Energy Efficiency Plan document spans 369 pages, and is supported by testimony filed by the utilities.

As described by the utilities, their proposals would extend and expand existing "NHSaves" programs for another 3 years, and would add new initiatives including "a new residential energy audit option, a financing option for moderate income residents, new measure offerings in both residential and commercial programs, and multi -year energy planning to encourage long-term energy savings projects among large commercial customers."

According to the utilities, the measures implemented through the 2018-2020 Plan will save more than 4 billion electric kilowatt-hours and 7.5 million natural gas MMBtu, plus another 5.4 million MMBtus from other fuels, yielding customer energy cost savings of more than $867 million in energy costs over the life of the measures. The utilities also project that the measures "will reduce peak demand by 39 MW, which in tum will reduce costs for all customers."

The Commission has docketed the proceeding as Docket No. DE 17-136, and set a procedural schedule for the case including the filing of testimony and pursuit of possible settlement through November 2017, with hearings on the merits in early December.

Winter 2017-18 and the New England electric grid

With measures in place to ensure the reliability of New England's electric grid for the coming winter season, grid operator ISO New England, Inc. expects to have adequate electricity supplies this winter -- but according to a recent presentation to federal regulators, the biggest challenges could come in the form of extended cold weather when fuel inventories are already depleted or a day when gas supplies are constrained and suddenly a large non-gas resource is lost.

According to an October 19, 2017 presentation by ISO-NE to the Federal Energy Regulatory Commission, in 2016 nearly half of the electricity produced in New England came from natural gas, and the availability of gas impacts both grid reliability and production costs.  At the same time, the gas pipeline infrastructure serving New England is limited, with pipelines reaching their maximum capacity at times including winter months when demand peaks for gas for heating.

In response to concerns over reliability and past events like the January 2004 "cold snap" and the 2014 "polar vortex", ISO-NE has taken steps including developing operating procedures, a Winter Reliability Program and "Pay for Performance" changes to market rules that incentivize investment in operational improvements and secure fuel arrangements, as well as improving communication and coordination with generators, pipelines, and other stakeholders.

With those measures in place, ISO-NE recently told the Commission it expects to have adequate electricity supplies this winter, but that gas pipeline constraints continue to be a concern.  ISO-NE noted that while Spectra Energy placed its Algonquin Incremental Market project in service providing some relief last winter, that relief "was short-lived due to the retirement in 2017 of more than 1,500 MW of non-gas units (Brayton Point Power Station)."  The grid operator also noted that "LNG shipments are unknown" and that "Non-gas resources will continue to play a vital role in maintaining reliability."

Citing the biggest challenges this winter as extended cold weather when fuel inventories are depleted or a day when gas supplies are constrained and the region is using primarily nuclear, coal, and oil resources and suddenly a large non- gas resource is lost, ISO-NE noted that while the region has adequate generating capacity to serve load under those conditions, "the ability to meet energy needs is at risk if gas cannot be supplied to gas-fired generators."

FERC electric storage policy statement

U.S. energy regulators have issued a policy statement addressing how electric storage resources may provide services at a mix of cost-based and market-based rates.  The Federal Energy Regulatory Commission's January 19, 2017 policy statement on storage provides insight into how the Commission views its role in regulating the rates at which energy storage would be compensated -- but was accompanied by a dissenting view expressed by Commissioner LaFleur.   The result is a mix of both greater certainty and continued debate.

Electricity storage is a growing industry, both in terms of installed capacity and its capability to flexibly support the grid.  Today's electric storage resources can both charge and discharge electricity to and from the grid.  Moreover they can provide various services to multiple entities -- for example, consumers, grid operators, or transmission and distribution utilities -- and can switch nearly instantaneously between modes of operation or services provided.  In these ways, electric storage resources share some functions of consumer load, generation, transmission, and distribution. 

Some of these functions -- e.g. sales of electric energy at wholesale in an organized market -- may be compensated at market-based rates.  But other functions of energy storage could be compensated at cost-based rates under federal law -- perhaps functioning as a transmission asset, compensated through transmission rates.  Thus it's possible that a particular energy storage resource -- think a battery attached to the electric grid, perhaps sited at a factory or other consumer's location -- might be compensated for its operations under both cost-based and market-based rates.

This is a good thing, according to the Federal Energy Regulatory Commission.  According to the January 19, 2017 policy statement, "Enabling electric storage resources to provide multiple services (including both cost-based and market-based services) ensures that the full capabilities of these resources can be realized, thereby maximizing their efficiency and value for the system and to consumers."

But previous proceedings before the Federal Energy Regulatory Commission have exposed some concerns about allowing electric storage resources to recover costs through both cost-based and market-based rates concurrently.  As described by the Commission, these include "double recovery of costs to the detriment of cost-based ratepayers, potential for adverse competitive impacts in wholesale electric markets to the detriment of other competitors, and the need for independence of regional grid operators from market participants."

With respect to utilities subject to its jurisdiction, the Commission's recent policy statement, "Utilitzation of Electric Storage Resources for Multiple Services When Receiving Cost-Based Rate Recovery," provides guidance regarding these issues.  It details possible approaches for avoiding double recovery of costs.  The Commission notes that with regard to adverse market impacts, it "is not convinced there will be a detriment to other market competitors."  The policy statement also offers guidance on how grid operators and electric storage owners or operators should interact, to ensure independence as required by Commission policy.

Commissioner LaFleur issued a dissenting opinion, while nevertheless calling storage "an important and promising resource that warrants Commission attention to ensure that our markets are appropriately adapted to recognize storage’s unique characteristics and contributions."  While expressing an openness "to potential structures that compensate storage providing transmission service at a cost-based rate while participating in the wholesale markets", she expressed concern "about the broad rationale for this approach put forth in the Policy Statement," which she called "both flawed in its conclusions and premature in its timing."  In particular her dissent focused on what she described as "the Policy Statement’s sweeping conclusions about the potential impacts of multiple payment streams on pricing in wholesale electric markets" -- and whether it might have implications for resources other than storage that receive multiple payment streams.  She also disagreed with the Commission's decision to issue the policy statement separate from its pending Notice of Proposed Rulemaking on the participation of electric storage in wholesale markets.

Both the majority policy statement and Commissioner LaFleur's dissent shed light on how the Commission approaches energy storage rate issues.  Storage seems universally considered worth investigating or supporting, but disagreement remains within the Commission with respect to some aspects of how storage resources should be compensated (as well as procedural issues related to the Commission's consideration of these questions).  Nevertheless the policy statement does provide guidance and clarification into how a majority of the Commission views the compensation of storage resources under both cost- and market-based rate structures -- while also framing future discussions over how storage resources will be integrated into markets.

FERC declares QF rights

Federal energy regulators have issued an advisory opinion regarding the rights of Qualifying Facility electric generators to sell power to their local utility under the Public Utility Regulatory Policies Act (PURPA).  The Federal Energy Regulatory Commission's declaratory ruling illustrates how the Commission interprets PURPA and QF rights, in the context of state renewable energy portfolio standards and

PURPA was enacted by Congress in 1978 to promote goals including energy conservation and greater production of domestic and renewable energy.  It established a new class of generating facilities called QFs, to receive special rate and regulatory treatment. A chief benefit of QF status is the
right to sell energy and capacity to a utility, usually at either at the utility's avoided cost or at a negotiated rate.  By regulation, QFs generally have the option to sell energy either "as-available," or as part of a long-term contract or other legally enforceable obligation for delivery of energy or capacity over a specified term.

The Federal Energy Regulatory Commission oversees this program, although state energy commissions play important roles.  Section 210 (H)(2)(A) and (B) of PURPA give the Commission discretionary power to enforce its PURPA rules, including the power to require state commissions and non-regulated utilities to comply.  But the Commission may also decline to initiate an enforcement action, on a case by case basis.

Earlier this year, a group of QFs filed a complaint to the Commission against the Connecticut Public Utilities Regulatory Authority.  Windham Solar LLC and Allco Finance Limited alleged that Connecticut law and PURA’s regulations violate the Commission's PURPA regulations regarding an electric utility’s mandatory purchase obligation and a QF’s ability to sell pursuant to a legally enforceable obligation. Complainants effectively alleged that they couldn’t get a long-term contract to sell energy and capacity at avoided cost rates on a forecasted basis, unless the energy and capacity were bundled with renewable energy certificates (RECs), or unless the energy and capacity were provided under a short-term contract not to exceed one year.

Some of those basic facts were contested by PURA and others, and the Commission noted a history of dispute and litigation among the complainants and Connecticut energy regulators. So the Commission declined to initiate an enforcement action on the complaint.

But the Commission did issue a declaratory ruling, reciting case law and interpretation on two points: the relationship between state RECs and PURPA, and QF opportunities to secure long-term contracts.  The Commission noted that RECs exist under state law and not PURPA, but that avoided cost contracts do not automatically include RECs.  It also noted that winning a competitive solicitation cannot be the only way a QF may be allowed to obtain long-term avoided cost rates.

The original comes with robust citations to precedent, omitted for convenience below:

4. The Commission has previously addressed issues regarding the relationship between state-created RECs and PURPA. The Commission has stated that the states have the authority to determine who owns RECs in the initial instance and how they are transferred, and has explained that the automatic transfer of RECs within a sale of power at wholesale must find its authority in state law, not PURPA. The Commission has also held, however, that a state regulatory authority may not assign ownership of RECs to utilities based on a logic that the avoided cost rates in PURPA contracts already compensate QFs for RECs in addition to compensating QFs for energy and capacity, because the avoided cost rates are, in fact, compensation just for energy and capacity. Moreover, while the Commission has made clear that states have the authority to regulate RECs, states cannot impede a QF’s ability to sell its output to an electric utility pursuant to PURPA. Thus, regardless of whether a QF has previously sold its RECs under a separate contract, that QF has the right to sell its output pursuant to a legally enforceable obligation.

5. The Commission has also held that “requiring a QF to win a competitive solicitation as a condition to obtaining a long-term contract imposes an unreasonable obstacle to obtaining a legally enforceable obligation.” The Commission likewise has determined a state regulation to be inconsistent with PURPA and the Commission’s PURPA regulations “to the extent that it offers the competitive solicitation process as the only means by which a QF . . . can obtain long-term avoided cost rates.” Accordingly, regardless of whether a QF has participated in a request for proposal, that QF has the right to obtain a legally enforceable obligation. 

As noted in the declaratory ruling, the Commission's "decision not to initiate an enforcement action means that Petitioners may themselves bring an enforcement action against the Connecticut Authority in the appropriate court."

Supreme Court rules on state energy incentives

The U.S. Supreme Court has released its ruling on a case affecting how states may provide incentives for electric power generation.  In Hughes v. Talen Energy Marketing, LLC, the Court upheld a lower court's ruling invalidating a Maryland program to subsidize construction of new power plants.  The ruling provides important insight into how the Court views the boundary between federal and state jurisdiction over energy matters.

The Supreme Court of the United States.

The Hughes case involved a new Maryland program to encourage in-state generation capacity, and its relationship to federally blessed capacity market.  Under the Federal Power Act, the Federal Energy Regulatory Commission has exclusive jurisdiction over wholesale sales of electricity in the interstate market, while States regulate retail electricity sales. 

For years,  Mid-Atlantic regional grid operator PJM Interconnection has held capacity auctions to identify need for new generation and compensate generators for development.  PJM's auctions have been approved by the Federal Energy Regulatory Commission under the Federal Power Act.  But due to concern that the PJM auction was failing to encourage development of sufficient new in-state generation, Maryland enacted its own regulatory program.  Under that state program, Maryland held a competitive process to select a developer for a new power plant, and required load-serving entities to enter into a 20-year pricing contract (called a "contract for differences") with the developer.  The developer would still sell its capacity to PJM, but would receive extra money under the state program to make up the difference between the PJM market price and the contract price.

But incumbent generators challenged the new Maryland program; a federal district court issued a declaratory judgment holding that Maryland's program improperly sets the rate the developer receives for interstate wholesale capacity sales to PJM.  On appeal, the Fourth Circuit affirmed, finding that Maryland's program was preempted because it impermissibly conflicts with FERC policies.  The case then came to the Supreme Court of the United States.

The Supreme Court's April 19, 2016 decision affirms the lower courts' rulings.  The Court agreed with the Fourth Circuit's judgment "that Maryland's program sets an interstate wholesale rate, contravening the FPA's division of authority between state and federal regulators."  In the majority opinion's words, "States may not seek to achieve ends, however legitimate, through regulatory means that intrude on FERC's authority over interstate wholesale rates, as Maryland has done here."

The Hughes ruling sheds light on how the Court might view other state programs to incentivize new or clean generation.  That said, the Court emphasized that its holding in Hughes is limited -- that it rejected Maryland's program "only because it disregards an interstate wholesale rate required by FERC."  The Court explicitly said it would not address "the permissibility of various other measures States might employ to encourage development of new or clean generation," such as tax incentives, land grants, direct subsidies, construction of state-owned generation facilities, or re-regulation of the energy sector.

The majority opinion concludes with a reminder that "[s]o long as a State does not condition payment of funds on capacity clearing the auction, the State's program would not suffer from the fatal defect that renders Maryland's program unacceptable."  This suggests one potential path for permissible state incentives for electric power generation.

Electric storage and wholesale markets

As electric energy storage technology improves in capability and cost-effectiveness, what barriers exist to electric storage resources' participation in organized electricity markets in the U.S.?  Staff of the Federal Energy Regulatory Commission have issued a series of data requests and a request for public comment in an effort to identify barriers that could lead to unjust and unreasonable wholesale electricity rates.

For purposes of this inquiry, Commission staff defines an electric storage resource as a facility that can receive electric energy from the grid and store it for later injection of electricity back to the grid. This includes all types of electric storage technologies, regardless of their size and storage medium, or whether they are interconnected to the transmission system, distribution system, or behind a customer meter.

Historically, electricity had to be consumed as soon as it was generated, and storing electricity was challenging and expensive.  But a new industry has grown up around electric storage.  Federal regulators have acted to support energy storage, such as in FERC Order No. 784 which lets cost-effective storage be paid fairly for the ancillary services it provides to the grid.

According to a series of April 11, 2016 letters from Commission staff to various regulated Regional Transmission Organization (RTO) and Independent System Operator (ISO) entities, "Commission staff has been examining the use of electric storage resources to help meet wholesale electricity needs for some time."  In light of "key developments in the technology and cost-effectiveness of electric storage resources," the letters express staff's interest in "examining whether barriers exist to the participation of electric storage resources in the capacity, energy, and ancillary service markets in the RTOs and ISOs potentially leading to unjust and unreasonable wholesale rates."  The letters also describe staff's expectation that if potential barriers exist, staff will examine whether any tariff changes are warranted.

A data request is attached to each letter.  In those data requests, staff seeks information on rules that affect the participation of electric storage resources in the markets.  These rules include those governing electric storage resources' eligibility to participate in the markets, the qualification and performance requirements for market participants, required bid parameters, and the treatment of electric storage resources when they are receiving electricity for later injection to the grid.

FERC staff's data requests are organized into 6 categories:

• The Eligibility of Electric Storage Resources to be Market Participants
• Qualification Criteria and Performance Requirements
• Bid Parameters for Electric Storage Resources
• Distribution-Connected and Aggregated Electric Storage Resources
• When Electric Storage Resources are Receiving Electricity
• Potential Changes to the Rules Affecting Electric Storage Resources

The letter requests a response to the data requests on or before May 2, 2016.  Concurrently, staff solicited public comment on the issues raised in the proceeding.

As noted in the data request letters, this is not the first time Commission staff has considered energy storage.  Will this round of regulatory process identify barriers to electric storage resources' participation in wholesale markets?  Will any barriers identified give rise to changes to grid operators' tariffs?  The case has been docketed as Docket No. AD16-20-000, Electric Storage Participation in Regions with Organized Wholesale Electric Markets. 

ISO-NE files IRC-related values for 2019-2020

In advance of an upcoming auction to sell electric generating capacity into the New England market, regional grid operator ISO New England Inc. has submitted key information about its plans to the Federal Energy Regulatory Commission.

ISO New England is the private, non-profit entity that serves as the regional transmission organization for New England.  In this role, ISO-NE plans and operates the New England bulk power system, administers New England’s organized wholesale electricity market, and has some responsibility over system reliability.  Reliability can be stated in terms of a loss of load expectation or “LOLE”, which measures how often non-interruptible customers are disconnected.

New England has adopted a capacity market as part of its wholesale electricity market structure.  One aspect of system reliability is ensuring sufficient generating capacity is available to meet consumer demand.  Pursuant to Section III.13 of the Tariff, the ISO administers periodic Forward Capacity Auctions, or FCAs, in order “to procure the amount of capacity needed in the New England Control Area.”

ISO-NE will hold its tenth Forward Capacity Auction in February 2016, covering the 2019-2020 Capacity Commitment Period.  To do so, ISO-NE must first identify how much generation will be needed to meet reliability standards in light of total forecasted load requirements for the New England Control Area and to maintain sufficient reserve capacity to meet reliability standards.  One key value characterizing this need is the "Installed Capacity Requirement" or ICR.  ICR refers to the amount of resources needed to meet the reliability requirements defined for the New England Control Area of disconnecting non-interruptible customers no more than once every ten years.  Under Section 205 of the Federal Power Act, ISO-NE files with the FERC proposed ICR-Related Values for the each auction.

On November 10, 2015, ISO New England submitted to the FERC its Installed Capacity Requirement, Local Sourcing Requirement for the Southeastern New England Capacity Zone, Hydro Quebec Interconnection Capability Credits, and Demand Curve Values for the 2019-2020 Capacity Commitment Period.  In that filing, ISO-NE proposed an Installed Capacity Requirement (net of certain credits for imports) of 34,151 MW.

ISO-NE noted that for the most part, this and other key values were calculated using the same Commission-approved methodology that has been used to calculate the values submitted and accepted for other recent Capacity Commitment Periods. One key difference for the tenth FCA is the inclusion of behind-the-meter photovoltaic (“PV”) resources that are not yet reflected in historical loads as a reduction in the load forecast. This change addresses a requirement imposed by the FERC in its January 2, 2015 Order accepting the Installed Capacity Requirement and related values for the ninth FCA.

ISO-NE asked FERC to accept the proposed ICR-Related Values for the tenth FCA to be effective on January 9, 2016 (i.e. 60 days after filing), to enable their use in the tenth FCA scheduled for February 2016.

Record low prices in summer 2015 New England wholesale electricity market

The summer of 2015 brought New England the lowest wholesale electricity prices since 2003, thanks to record low prices for natural gas.  According to regional grid operator ISO New England Inc., this illustrates what happens "when New England power plants can access the vast supply of lower-priced, domestic natural gas being produced in the Marcellus shale deposit."

ISO-NE, "Summer 2015: The lowest natural gas and power prices since 2003"

In a post on its ISO Newswire site, the grid operator noted that the average real-time wholesale electricity price for June, July, and August 2015 was $26.86 per megawatt-hour (MWh). By comparison, the average real-time price of wholesale electric energy in 2014 was $63.32 per megawatt-hour.  While summer energy prices have typically averaged lower than winter prices in New England, 2015's summer prices were low even in comparison to other recent summers: $34.31 in 2014, or $43.94 in 2013.

What explains New England's low wholesale electricity prices this summer?  According to ISO New England, it's because existing natural gas-fired power plants could get fuel at a low price:

In essence, the reason was the low price of natural gas that could be delivered to the power plants that burn natural gas to make electricity. For most of the year, the price of natural gas is low in New England, and as a consequence, the demand for natural gas for both heating and power generation just continues to grow. In fact, in 2014, New England power generators using natural gas produced 44% of the region’s electricity.

The ISO-NE post describes how low-priced natural gas plus adequate interstate pipeline transportation capacity yields New England low electricity prices.  Indeed, the average price of  natural gas in New England during June, July, and August averaged a record low $2/MMBtu.  This is nearly 40% below last year's summer average ($3.27/MMBtu), itself the next-lowest summer record.

New England's average summer electricity price was even below that of other regions, like the Midwest.  According to ISO-NE, "This summer’s prices indicate that the region’s electricity prices can be competitive, in the more commonly understood sense, with other regions of the US when low-cost fuel is available." Indeed, at times the price of natural gas in New England was below that of the benchmark Henry Hub.

The post also describes how heavy winter demand for natural gas for both heating and power generation, combined with pipeline constraints, yields high natural gas prices and thus high electricity prices.  This has occurred repeatedly in recent winters, such as in January and February 2014 and February 2015.  What is at issue is thus the ability of the interstate natural gas pipeline transportation network to ship enough gas into the Northeast -- a capability exceeded through much of the recent winters, with the resulting price paid in coal and oil emissions as well as dollars.

As ISO-NE notes, most customers' retail rates for electricity are set using mechanisms to reduce rate volatility, and time of use rates are not yet widely adopted.  But the net movement of wholesale markets is eventually priced into retail rates.  Can New England keep competitive with other regions?

Maine PUC considers community energy projects

The Maine Public Utilities Commission is evaluating the viability of proposed community-based renewable energy projects that remain under development.

Maine has run a community-based renewable energy program since 2009.  The program gives qualified wind, solar, and other renewable energy projects long-term contracting opportunities to sell the facility’s output to a Maine transmission and distribution utility at attractive rates.

In 2015, the Maine Legislature adopted P.L. 2015 ch. 232, An Act to Amend the Community-based Renewable Energy Program”.  Beyond minor revisions to the law, the act adds strict deadlines for key program milestones: the Public Utilities Commission has until December 31, 2015 to order or allow utilities to enter into long-term contracts under the program, and all projects selected for a contract must become operational and commence generating electricity by December 31, 2018.

Section 5 of the Act also created a new "viability assessment" process designed to make sure the program is as effective as possible.  The program size is capped at 50 megawatts statewide; all of this capacity was quickly claimed by certified projects.  But not all projects that have been certified are operational; some have yet to be built.  Some stakeholders expressed concern over "permit banking" -- developers obtaining and holding onto program capacity, without actively developing it, while other projects would move forward if they could get the capacity.

As a result, the Legislature directed the Commission to review all certified projects that have not yet reached commercial operations, to determine whether the projects are reasonably likely to achieve commercial operations within a 3-year period.   If the Commission determines a project will not be viable by December 31, 2018, the Act directs the Commission to revoke any contract awarded, but such projects will remain certified under the program.   If the removal of nonviable projects frees up program capacity for contracting, the law directs the Commission to conduct an expedited request for proposals to select community-based renewable energy projects to become program participants and enter into long-term contracts.

The Commission's viability assessment process is now ongoing.  A July 13, 2015 procedural order identified six projects as having been either certified or awarded a contract, but not been placed in commercial operation.  Project developers were invited to submit information related to the viability assessment by August 7. 

The Commission meets on September 22 to deliberate on the viability assessments.

ISO-NE projects slow growth in electricity demand

New England's electric grid operator predicts slow growth in annual energy usage in the region over the next decade, with slightly quicker growth in peak demand.

A Maine power plant -- the ecomaine Waste-to-Energy plant in Portland, Maine.

ISO New England, Inc. develops an annual long-term load forecast using factors including state and regional economic forecasts and 40 years of weather history.  Its most recent baseline forecast projects a compound annual growth rate of 1.0% in total energy usage in New England from 2015 to 2024.  For 2015, ISO-NE projects 138,745 gigawatt-hours (GWh) of load, growing to 152,280 GWh in 2024.

ISO-NE's forecast also projects future peak demand, a measure of the highest amount of electricity used in a single hour in New England.  Often, peak demand drives the need for constructing and maintaining power plants and transmission lines (and energy efficiency investments).  According to the latest ISO-NE forecast, New England's peak electricity demand is projected to rise by a compound annual growth rate of 1.3%, from 28,395 MW this year to 31,905 MW in 2024.

These baseline projections for future peak demand and energy usage take into account load reductions that can be expected from future installations of distributed solar photovoltaic facilities.  ISO-NE has prepared a separate Distributed Generation Forecast to estimate the load-reducing effects of distributed solar facilities developed as a result of state policy goals.

ISO-NE's baseline projections do not account for significant energy-efficiency savings, neither those committed through the region’s three-year Forward Capacity Market (FCM) nor future savings that can be expected beyond the FCM timeframe.