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.

Transportation, heating dominate Maine greenhouse gas emissions

Maine has reduced its total annual emission of greenhouse gases in recent years, thanks largely to the substantial decarbonization of the state's electricity supply -- but transportation and heating remain the largest contributors to Maine's overall carbon dioxide emissions.

According to the Maine Department of Environmental Protection, total estimated annual greenhouse gas emissions in Maine increased from 21.65 million metric tons of carbon dioxide equivalents (MMTCO2e) in 1990 to a peak of 26.97 MMTCO2e in 2002, and then declined to 18.21 MMTCO2e in 2012. This equals a reduction in annual emissions of 15% between 1990 and 2012 (a reduction of 11.7% between 1990 and 2015).

 

Most of Maine’s carbon dioxide emissions -- 53 percent -- came from the state's transportation sector, according to the Maine Department of Environmental Protection. Home heating represents the next largest contributor to statewide greenhouse gas emissions.

Maine’s electric power sector has reduced its annual carbon dioxide emissions by 73 percent since emissions peaked in 2002, largely by replacing high carbon fuels with natural gas. In 2015, Maine’s electric power sector emitted 1.57 MMTCO2 from the combustion of fossil fuels, or 9 percent of the state’s total CO2 emissions.

Meanwhile, the transportation sector’s carbon emissions have increased since 1990, primarily due to an increase in miles traveled. This increase comes despite increases in vehicle fleet efficiency and the addition of carbon-neutral ethanol to gasoline; the transportation sector now accounts for most of Maine's greenhouse gas emissions (at 53 percent of the all-sector total).

These facts and data have implications for Maine's policy efforts to further reduce the state's greenhouse gas emissions. The state's electricity supply has been substantially decarbonized, while transportation emissions have actually increased since 1990, and emissions related to residential heating (primarily with oil) are roughly at the same level they were in 1990. Efforts to address the carbon emissions associated with transportation and heating -- such as through electric vehicles and heat pumps -- could do much to continue reducing Maine's contributions to global carbon emissions.

Kaukauna hydro project relicensed

U.S. hydropower regulators have issued a new license to a Wisconsin municipality to continue operating and maintaining its hydroelectric generation project.

The City of Kaukauna, Wisconsin is located on the Lower Fox River. In 1939, the Federal Power Commission awarded the City an original license for the Kaukauna Hydroelectric Project. That license was replaced after its 1989 expiration with a new license issued by the Federal Energy Regulatory Commission. As licensed, the project consists of facilities including a dam and other structures, as well as two turbine-generators with a total installed capacity of 4.8 megawatts.

Because that license was set to expire in March 2019, in 2017 the City applied to the Commission for a new license for the project. No party opposed issuance of a new license. On March 29, 2019, the Commission issued the City a new license, authorizing continued operation of the project with some additional conditions required such as plans for items like managing operational compliance and debris and controlling invasive species of vegetation.

The licensing order also provides data on some of the project's costs and benefits. It notes that the project’s average annual generation is approximately 29,704 megawatt-hours. Including the cost of additional Commission staff measures imposed by the new license, the order states that the levelized annual cost of operating the project is $541,801, or about $18.24 per megawatt-hour. Multiplying the project's expected average annual energy generation by the alternative power cost of $42.04 per megawatt-hour, the order asserts that the total annual value of the project’s power is $1,248,756, in 2018 dollars, and that in the next year of project operation, it would save the City utility $706,955, or $23.80 per megawatt-hour compared to the likely alternative cost of power.

NESCOE Annual Report 2018 features market tensions

An organization representing the interests of the six New England states on electricity matters has issued its 2018 annual report, highlighting increasing tension between the region's wholesale competitive markets and a growing number of "out of market" mechanisms adopted to satisfy emerging state and regional needs. Through the report, the New England States Committee on Electricity (NESCOE) calls for regional discussion of possible market reforms to integrate state policies while protecting consumers from increased costs.

NESCOE is a not-for-profit entity organized under various state and federal laws. NESCOE is governed by a board of managers appointed by the Governors of the six New England States, and seeks to advance "the New England states’ common interest in the provision of electricity to consumers at the lowest possible price over the long-term, consistent with maintaining reliable service and environmental quality."

On April 2, 2019, NESCOE released its 2018 annual report. The report notes that for over 20 years, "New England has generally relied on competitive wholesale markets to select resources to serve electricity consumers at the lowest cost without regard to resource type or fuel source." As described by the report, the wholesale markets operated by ISO New England Inc. were "designed to provide reliable system operations, attract investment, drive down wholesale prices, and increase generation fleet efficiency—all for the ultimate benefit of consumers."

But "in more recent years, ISO New England and some states have also turned to different means to satisfy evolving needs, including 'energy security' and state energy and environmental law compliance," according to NESCOE's report. As examples of these "non-wholesale market alternatives," NESCOE cites extraordinary measures taken by ISO-NE to retain the Mystic generating units outside Boston through a cost-of-service agreement, further ISO-NE energy security initiatives, as well as state and utility procurements of substantial volumes of renewable energy through long-term contracting.

NESCOE notes fundamental challenges to integrating state policy with the wholesale markets, including "complex jurisdictional questions, ensuring that consumers pay the cost of their own state’s laws and not others’, and achieving state law compliance at the lowest possible cost to consumers." In light of the region's increasing reliance on out-of-market solutions, NESCOE calls for "a rethink of what we are asking markets to do now and a fresh look at whether and what elements of the decades’ old wholesale market objectives stand up to current circumstances and law."

ISO-NE energy security improvements paper

Regional transmission organization ISO New England Inc. has released a "discussion paper" on the region's energy security, presenting "the ISO’s current perspective on underlying problems, root causes, and longer-term market solutions."

The 77-page paper notes that the region's electric power system "is undergoing a major transition" as nuclear, coal, and oil-fired power plants are retiring and being replaced by newer, more efficient natural-gas fired generation and renewable technologies like solar and wind. It expresses the ISO's concern that these replacement resources rely on the "just-in-time" delivery of their energy sources -- and that weather variations and capacity constraints on interstate natural gas pipelines mean these resources present greater fuel security challenges.

The paper concludes that "in many situations" the ISO-administered wholesale electricity markets do not provide adequate financial incentives for resource owners to make additional investments in supply arrangements that would be cost-effective and benefit the power system at times of heightened risk. It notes that while customers would benefit from reduced electricity prices if generators delayed their use of limited fuel stocks to the most critical period (which might not come for days), present market designs do not offer a generator a clear incentive to stockpile and maximize the value of their fuels.

But, ISO-NE says, "these challenges have sensible solutions," including "additional sources of energy supply (or reductions in demand) when gas pipelines are most constrained, renewable resources experience adverse weather, or both." The paper presents three core components of a solution: a multi-day-ahead market, new ancillary services in the day-ahead market, and a seasonal forward market.

The grid operator has taken a number of short- and medium-term steps toward addressing these challenges through market reforms, and has been tasked by the Federal Energy Regulatory Commission with developing a long-term solution by this fall.

NH approves utility demand reduction initiative

New Hampshire utility regulators have approved an initiative by two electric distribution companies to incentivize customers to reduce their energy use during times of peak demand on the grid. If successful, the Commercial and Industrial Demand Reduction Initiative could yield savings for all consumers.

Earlier this year, electric utilities Public Service Company of New Hampshire d/b/a Eversource Energy and Unitil Energy Systems, Inc. proposed the Initiative to reduce demand at the time of the regional peak demand on the ISO New England Inc. system. As proposed, the utilities would provide incentives to large commercial and industrial customers to curtail their energy use during times of projected peak demand during the summer of 2019.

The utilities would pay "curtailment service providers" or CSPs $35 per kilowatt of actual curtailed load. CSPs would attract and enroll commercial and industrial customers, and would schedule their curtailments during times of possible peak system demand -- according to the utilities, the CSPs would request curtailments about 10 times per summer, each for about two to four hours duration. Curtailment performance would be measured relative to an established baseline load.

The program is relatively small, with Eversource seeking to curtail 5 megawatts and proposing a $250,000 budget, and Unitil another 1.8 megawatts for a budget of $93,795. The utilities will recover the costs of this initiative through a System Benefit Charge approved by the New Hampshire Public Utilities Commission.

In an order dated April 5, 2019, the New Hampshire Public Utilities Commission approved the Commercial and Industrial Demand Reduction Initiative. According to the Commission, reducing demand at the time of the ISO-NE system peak will result in savings not just for participating customers, but for all ratepayers, primarily in the form of avoided capacity costs and possibly reduced transmission costs. The Commission noted that the peak load reduction initiative aligns with the statewide energy efficiency plan for 2018 through 2020.

The value of the savings -- and by extension the benefit/cost ratio -- vary depending on the degree to which the curtailments coincide with the time of system peak. But according to the Commission, "The Initiative is predicted to achieve capacity and possibly transmission savings far in excess of program costs. If the Utilities are successful at curtailing their targeted loads of 5 MW for Eversource and 1.8 MW for Unitil, then the benefits are projected to exceed the costs of the program by almost a factor of five. Even at significantly lower coincidence factors, the Initiative is projected to produce savings that will exceed program costs.."

Maine considers energy, climate planning

Here's a roundup of some of the proposed Maine legislation calling for changes to how the state plans for its future with respect to energy and climate matters.

• LD 658, Resolve, To Direct a Plan for Energy Independence for Maine: This resolve directs the Governor's Energy Office to adopt a 10-year energy independence plan, including conservation and renewable energy strategies, for the State to become a net exporter of energy by 2030.
• LD 797, An Act To Limit Greenhouse Gas Pollution and Effectively Use Maine's Natural Resources: This bill would require Maine to reduce its net annual greenhouse gas emissions to at least 80% below the 1990 net annual greenhouse gas emissions level, by January 1, 2050. It directs the Department of Environmental Protection to update Maine's climate action plan and to evaluate Maine's progress toward these emissions reductions.
• LD 818, An Act To Reduce Greenhouse Gas Emissions: This bill provides Maine to reduce net annual greenhouse gas emissions to at least 80% below the 1990 net annual greenhouse gas emissions level, by January 1, 2030. It directs the Department of Environmental Protection to establish interim net annual emissions levels and to monitor and report on gross and net annual greenhouse gas emissions, and to update the State's climate action plan and evaluate the State's progress toward meeting the reduction levels. It requires the Board of Environmental Protection to establish greenhouse gas emission standards for individual sources or categories of sources. 
• LD 893, An Act To Create an Updated Unified Maine Climate Action Plan: This bill requires the Department of Environmental Protection, working with the Maine Interagency Climate Adaptation Work Group and the University of Maine, to update the Maine Climate Action Plan developed in 2004 by the department. It requires the department and the work group to convene stakeholders to evaluate and include in the updated plan mitigation and adaptation strategies.
• LD 950, An Act To Develop a State Energy Plan To Provide a Pathway to an Energy Portfolio Free of Fossil Fuels: This bill proposes to develop an energy plan to provide a pathway to an energy portfolio free of fossil fuels.
• LD 1282, An Act To Establish a Green New Deal for Maine: Among other measures, this bill would create a task force charged with creating a plan to advance environmental sustainability, renewable energy and economic growth for Maine. The bill would require the plan to include a renewable resources strategy to achieve 80% reliance on renewable resources for electricity supply by 2040; a job training strategy, including a training program to prepare workers for green jobs; and a residential energy strategy that provides incentives for installation of solar energy systems and heat pumps.

Maine considers thermal RPS

At least two bills pending before the Maine legislature would impose new "thermal renewable" requirements on suppliers of electricity. Here's a look at how a thermal renewable portfolio standard might fit into Maine law.

Since Maine's restructuring of its electricity sector in 1997, Maine law has required competitive electricity providers to comply with statutory renewable portfolio standards. These laws require suppliers to obtain renewable energy credits or RECs representing the environmental attributes of qualifying generation, in quantities sufficient to cover defined portions of the supplier's portfolio. For example, as of March 2019, the renewable portfolio standard requires providers to source 10% of their power from qualifying "Class I" renewable resources built or refurbished after 2005, plus another 30% from other "Class II" renewable resources, for a total mix containing at least 40% renewable power.

Like Maine, most states have adopted renewable portfolio standards for their electricity sector. But some states are also exploring the inclusion of renewable thermal power in their standards, in the hope of supporting the development of thermal renewable resources like solar thermal or biomass projects. As of 2018, fourteen states had adopted some kind of thermal renewable components for their renewable portfolio standards, including New Hampshire.

The Maine legislature is now considering proposals to add a thermal component to Maine's renewable portfolio standard:

• LD 1465, An Act To Diversify Maine's Energy Portfolio with Renewable Energy, includes unallocated language directing the Public Utilities Commission to develop a plan for implementing a thermal renewable resource portfolio standard. The bill would require the thermal standard to require each competitive electricity provider to account for 4% of its portfolio of electricity supply sources with "thermal renewable resources." While the Commission would define eligible resources, the bill would require the inclusion of commercial and industrial pellet and wood heating systems, residential biomass systems and combined heat and power systems fueled by biomass. The bill would also require the Commission to establish a renewable energy credit value for net thermal energy produced by eligible resources, and to allow thermal renewable energy credits to be used to satisfy suppliers' statutory portfolio requirements.

• LD 1494, An Act To Reform Maine's Renewable Portfolio Standard, would add a new thermal renewable portfolio requirement. It would require each competitive electricity provider to purchase thermal renewable energy credits in amounts that increase from 0.4% of retail supply in 2020 to 4% of retail supply by 2029. It would award thermal renewable energy credits to qualifying producers of useful thermal energy at the rate of one credit per 3,412,000 British thermal units of thermal energy.

Like most states, Maine's adoption of its electric renewable portfolio standard was driven by a desire to require that electricity consumed in the state come from a mix of resources that includes renewables. Adding a thermal renewable portfolio standard would broaden Maine's existing law to incentivize the use of wood and other thermal renewable resources for heating. While some facilities, like a biomass-fired power plant located where its waste heat can be used, might qualify under both the electric and thermal requirements, adding a thermal component to Maine's law would tend to shift a portion of REC revenues away from generators of renewable electricity and toward producers of thermal renewable energy.

Maine considers long-term contracting for renewables

The Maine legislature is considering several bills that would amend the statutory framework for Maine's procurement of energy resources.

Maine restructured its electricity sector in 1997 by deregulating generation and recasting electric companies as transmission and distribution utilities. As a result, competitive electricity providers or a "standard offer" provider selected by the Public Utilities Commission are the primary wholesale buyers and retail suppliers of energy. In this restructured environment, Maine's transmission and distribution utilities generally may not own, have a financial interest in or otherwise control generation or generation-related assets, and have no natural need to buy electricity.

However, several statutory programs do require Maine's transmission and distribution utilities to enter into multi-year contracts to buy capacity, energy, renewable energy attributes, or other products of electric generation. These programs include Maine's "capacity resource adequacy" statute, which authorizes the Commission to direct investor-owned transmission and distribution utilities to enter into long-term contracts for energy, capacity, and renewable energy credits when such contracts are in the best interest of customers. That statute requires the Commission to conduct a competitive solicitation for proposed contracts no less often than every 3 years if the Commission determines this to be cost-effective, and requires that all costs and direct financial benefits associated with these contracts be allocated to ratepayers. Recent procurements under this law include 75 megawatts from Dirigo Solar, LLC, at a price of 3.4 cents/kWh escalating at 2.5% annually for 20 years, and 100 megawatts from Three Rivers Solar Power, LLC’s solar project, with a price of 3.5 cents/kWh escalating at 2.5% annually for 10 years.

Other procurement programs under existing law include Maine's community-based renewable energy pilot program and Maine's Ocean Energy Act. By statute, the costs and benefits associated with a long-term energy contract are allocated to ratepayers -- so if the contract pricing is below-market, ratepayers receive a credit, whereas above-market contract prices lead to increased ratepayer costs. (In 2018, the average annual wholesale electricity price in New England was 4.354 cents per kilowatt-hour.)

Legislation proposed in 2019 could alter or add onto these statutory mandates to procure certain energy resources. Some of the bills calling for reforms to Maine's long-term contracting programs include:

• LD 41, An Act To Replace Net Energy Billing with a Market-based Mechanism: This bill would require the Commission to procure, to the maximum extent possible, 20 megawatts of large-scale community solar distributed generation resources under its existing capacity resource adequacy statute. It requires that the contract rate be calculated annually and that no contract may be for more than 6¢ per kilowatt-hour or the average wholesale electricity rate over the preceding 12 months, whichever is less.
• LD 273, An Act To Require Transmission and Distribution Utilities To Purchase Electricity from Renewable Resources at Certain Prices: This bill would require a transmission and distribution utility, at the request of the owner of a renewable resource, to purchase the resource's output at a price per kilowatt-hour that is 50% of the average cost per kilowatt-hour to generate electricity using a fossil fuel in Maine.
• LD 1127, An Act To Expand Community-based Solar Energy in Maine: This bill would require the Commission to direct Maine's investor-owned transmission and distribution utilities to enter into long-term contracts for up to 100 megawatts of "community-based solar resources." It limits eligibility to projects of 10 megawatts or smaller, and reserves 20% of the program capacity for projects less than 2 megawatts. It also requires the resource to be at least 75% owned by Maine residents. It would require contracts to specify a fixed rate for a term of at least 20 years, which must be less than 9 cents per kilowatt-hour.
• LD 1465, An Act To Diversify Maine's Energy Portfolio with Renewable Energy: This bill would require the Commission to hold a series of annual solicitations, select projects, and direct Maine's investor-owned transmission and distribution utilities to enter into long-term contracts for 800 megawatts from "grid-scale renewable resources," 90 megawatts from "community-based renewable resources," and 135 megawatts from "commercial and industrial renewable resources," all by 2025.
• LD 1494, An Act To Reform Maine's Renewable Portfolio Standard: The bill would increase Maine's Class I renewable portfolio standard to 50% by 2030, and would require the Commission to conduct competitive solicitations for long-term contracts to cover half of each year's annual increase in the standard.

Many of these bills combine long-term contracting with other measures, such as Maine's renewable portfolio standard.

Maine considers renewable electricity law reforms

The Maine legislature is considering a list of bills that would amend the state's renewable portfolio standard. Existing law requires electricity providers to source 10% of their power from qualifying "Class I" renewable resources built or refurbished after 2005, plus another 30% from other "Class II" renewable resources. But legislators have filed numerous proposals to alter Maine's renewable portfolio standard. Some bills propose fairly narrow reforms, while others reach broadly. Here's a guide to how some of those bills would change Maine's renewable portfolio standard:

• LD 334, An Act To Change the Definition of "Renewable Capacity Resource": This bill would add generators fueled by municipal solid waste in conjunction with recycling to the definition of Class I or "renewable capacity resource."
• LD 1027, An Act To Eliminate the 100-megawatt Limit on Hydroelectric Generators under the Renewable Resources Laws: This bill would remove the current 100-megawatt capacity limit for hydroelectric generator qualification as a Class I or Class II resource. 
• LD 1279, An Act To Modernize Maine's Renewable Portfolio Standard: This bill would remove the current 100-megawatt capacity limit for hydroelectric generator qualification as a Class I or Class II resource, and instead adds a new limitation that qualifying hydro must be in Maine and 25 megawatts or greater. It would add new limits on what fraction of the total Class I requirement could be satisfied by hydroelectric generators, increasing from 25% in 2020 to 100% by 2035.
• LD 1282, An Act To Establish a Green New Deal for Maine: Among other provisions, this bill would require 80% renewable resources by 2040.
• LD 1465, An Act To Diversify Maine's Energy Portfolio with Renewable Energy: This bill would increase the portfolio requirement for new renewable resources from 10% to 50% by 2030, removes the restriction limiting solar and hydro resources seeking Class I status to projects no larger than 100 megawatts, adds a new limitation that qualifying hydro must be 25 megawatts or greater, and limits refurbishment-based eligibility to Class I status to refurbishments occurring between 2005 and 2019. It also moves Maine toward an additional thermal renewable portfolio standard.
• LD 1494, An Act To Reform Maine's Renewable Portfolio Standard: This bill would increase the renewable portfolio standard to 50% by 2030, remove the restriction limiting solar projects seeking Class I status to projects no larger than 100 megawatts, limit pathways to Class I eligibility for restarted or refurbished facilities, phase in Class I eligibility for certain hydropower generation licensed by the Federal Energy Regulatory Commission, and impose an additional thermal energy standard.

In addition to these bills, further legislation calling for reforms to Maine's renewable portfolio standard is expected. Numerous additional bills propose other changes to Maine's renewable energy policy, such as increased solicitation and procurement of long-term contracts for clean energy, reforms to Maine's net energy billing policy, and tax benefits for renewable energy property.

New England governors agree to cooperate on energy issues

The six New England governors have issued a joint statement on energy policy, calling for regional cooperation on mechanisms to “value” nuclear and clean energy.

The March 15, 2019 statement is captioned "New England Governors’ Commitment to Regional Cooperation on Energy Issues." It bears the signatures of Connecticut Governor Ned Lamont, Maine Governor Janet Mills, New Hampshire Governor Chris Sununu, Massachusetts Governor Charlie Baker, Rhode Island Governor Gina Raimondo, and Vermont Governor Phil Scott.

The governors' statement opens with an acknowledgement: "Reliable and affordable energy is essential to ensuring that New England continues to attract investment in the region and grow our economies, while protecting our environment and quality of life." It reaffirms the states' "commitment to cross-border collaboration and advancement of our common goals, while working to ensure that the region’s energy system fosters continued reliability and more affordable electricity for local homes and businesses."

The statement notes recent regional reliability challenges such as natural gas pipeline constraints and and the risk that the Millstone nuclear plant in Connecticut will retire. It also notes state efforts to add new clean energy resources, as well as challenges arising from the intersection of wholesale markets and these state environmental mandates.

The governors committed to "evaluate market-based mechanisms that value the contribution that existing nuclear generation resources make to regional energy security and winter reliability", and to cooperating on the development of a mechanism or mechanisms "to value the important attributes" of specific clean energy resources prioritized by individual states, while "ensuring consumers in any one state do not fund the public policy requirements mandated by another state’s laws." The statement also projects the prospect of further regional collaboration on "market-based approaches such as the Regional Greenhouse Gas Initiative."

ISO-NE explores long-term fuel security mechanism

New England's electricity markets are at a crossroads with respect to how the region addresses concerns over "fuel security," or ensuring that power plants have or can obtain the fuel needed to run. Like many sagas, the story includes a preface and multiple chapters (1 through 3, so far) -- and presumably, an ending that has yet to be released.

As described by federal regulators, regional transmission organization ISO New England Inc."has long recognized that maintaining fuel security in the New England region... is particularly challenging in winter when natural gas pipeline capacity is generally more constrained than in other seasons." In January 2018, ISO-NE released its Operational Fuel Security Analysis, evaluating the level of operational risk posed to the bulk power system under various fuel-mix scenarios, which identified a number of scenarios in which the grid operator would violate NERC reliability criteria by depleting operating reserves or need to shed load.

In March 2018, Exelon Generation Company, LLC proposed to retire its Mystic generation units outside Boston as of June 1, 2022. In response, ISO-NE conducted a study which found that the loss of two of these units -- Mystic 8 and 9 -- presented "unacceptable fuel security risks" including numerous violations of reliability criteria and "load shedding -- rolling blackouts -- during the New England winters of 2022-2023 and 2023-2024."

On May 1, 2018, ISO-NE filed a petition to the Federal Energy Regulatory Commission seeking waiver of multiple provisions of ISO-NE's tariff to allow the grid operator to retain the Mystic 8 and 9 units for fuel security purposes. On July 2, 2018, the Commission issued an order denying ISO-NE's waiver request, making a preliminary finding that ISO-NE's tariff may be unjust and unreasonable, and directing ISO-NE to file a proposed long-term fuel security mechanism by July 1, 2019. Soon thereafter, on July 13, the Commission approved a cost-of-service agreement under which regional ratepayers would pay to keep the Mystic units online through May 31, 2024. These activities -- ISO-NE's waiver request and the subsequent cost-of-service agreement -- have been labeled "Chapter 1" by regional stakeholders.

On August 31, 2018, ISO-NE submitted proposed tariff revisions establishing a fuel security study methodology, a short-term cost-of-service mechanism to ensure fuel security, and related provisions governing the allocation of costs for such out-of-market compensation. The Commission accepted those proposed revisions by order dated December 3, 2018. These short-term tariff revisions have been labeled "Chapter 2."

On March 25, 2019, ISO-NE filed tariff revisions with the Commission to implement a short-term program to "recognize the value of resources that can store fuel for use when winter energy security is most stressed." The proposed program would compensate generators for maintaining larger stockpiles of energy or fuels than they would otherwise retain in inventory. Compensation would be available to generators powered by oil, coal, nuclear, biomass, and waste, as well as batteries and certain some hydroelectric resources that can store and release water. It would also be available to natural-gas-fired generators with firm contracts for delivery of natural gas, as well as some demand response resources.

The grid operator says it would run this 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."

Meanwhile, the July 2019 deadline to file that long-term market solution -- known as "Chapter 3" -- continued to advance. But on January 18, 2019, ISO-NE asked the Commission for more time to allow for collaboration with New England stakeholders -- until November 15, 2019. No parties opposed the motion, and on March 18, 2019, the Commission granted an extension for ISO-NE's Chapter 3 filing -- but only until October 15, or one month short of the extension that the grid operator had requested. In the interim, ISO-NE and the NEPOOL stakeholder body continue to debate the contours of a long-term fuel security solution.

2018 was a record year for US energy in many ways

According to federal data, 2018 was a record year for US energy in many ways. Some of the records the U.S. Energy Information Administration says we hit in 2018 include:

• U.S. net electricity generation: U.S. net electricity generation increased by 4% in 2018, reaching a record high of 4,178 million megawatthours (MWh), and exceeding the previous peak which occurred before the recession in 2007. EIA cites weather -- cold winters and a hot summer -- as the primary driver of this growth.
• U.S. renewable energy generation:  EIA says renewable resources generated 742 million MWh of electricity in 2018, nearly double the amount produced in 2008. Wind and solar provided nearly 90% of the increase in renewable electricity over the past decade, driven primarily by capacity additions.
• U.S. nuclear electricity generation: U.S. nuclear power plants generated 807.1 million MWh of electricity in 2018, surpassing the previous peak of 807.0 million MWh in 2010. This result is due to a combination of added capacity through uprates and shorter refueling and maintenance cycles, and comes despite the closure of several nuclear power plants since 2010. The record level of nuclear generation might not be surpassed soon; with twelve more reactor closings planned through 2025, EIA projects that net electricity generation from U.S. nuclear power reactors will fall by 17% by 2025.
• U.S. natural gas production: U.S. natural gas production grew by 10.0 billion cubic feet per day (Bcf/d) in 2018, an 11% increase over the previous record year of 2017. According to EIA, the growth from 2017 to 2018 was the largest annual increase in production on record.
• U.S. natural gas consumption: U.S. natural gas consumption increased by 10% in 2018, reaching a record high of 82.1 Bcf/d. EIA cites increased domestic consumption of natural gas across all sectors, "led by a 3.8 Bcf/d increase in the electric power sector caused by a combination of recent natural gas-fired electric capacity additions and weather-related factors."
• U.S. natural gas plant liquid production: U.S. production of natural gas plant liquids has increased to an average of 4.3 million barrels per day (b/d) in 2018, up from 2.5 million b/d in 2012. Natural gas plant liquids include ethane, propane, normal butane, isobutane, and natural gasoline. EIA ties the growth in liquid production to the increased production of natural gas itself and the related increase in the use of horizontal drilling and hydraulic fracturing techniques.
• U.S. coal exports reached highest level since 2013: EIA says it expects that U.S. coal exports reached 116 million short tons in 2018, the highest level in five years, based on foreign trade data collected by the U.S. Census Bureau. This is nearly double the level of exports made in 2016. EIA attributes the growth in exports to the fact that "international prices have made it more economic for U.S. producers to sell coal overseas."

Each of these records has implications for the economy and the environment.