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Transmission Line to Link Wind Farm Off Coast of Long Island is Approved

November 30, 2022

by Peter Maloney
APPA News
November 30, 2022

The New York State Public Service Commission earlier this month approved a transmission line that will interconnect to a proposed wind farm off the coast of Long Island to the state’s electrical grid.

The 924-megawatt (MW) wind farm is sited in federal waters and would be the largest offshore wind farm to be connected to New York’s electric grid. The 25-mile transmission line will carry electricity from the proposed Sunrise Wind Farm to an existing substation in Brookhaven in Suffolk County.

The transmission line is a high-voltage, 320-kilovolt, direct current (DC) submarine export cable bundle that would be up to 5.2 miles long and enter New York State territorial waters three nautical miles from land. The transmission line then will transition from an offshore cable to an onshore cable that will travel up to 17.2 miles to an onshore converter station. The transmission line is being built by Sunrise Wind LLC.

The Sunrise wind farm is being developed by a partnership of Ørsted and Eversource with support from Con Edison Transmission and the New York Power Authority, which will assist the development of the transmission facilities needed to deliver the offshore wind energy to the electric transmission grid. The wind farm will be more than 30 miles east of Montauk Point.

Sunrise Wind is entering negotiations with New York State contractors and trade labor organizations on a project labor agreement to cover construction activities for the project and committing to paying prevailing wages.

The developers expect construction to start as early as 2023 with the wind farm entering service by 2025.

The offshore wind project will provide Long Island Power Authority (LIPA) customers with clean, affordable energy, Thomas Falcone, LIPA’s CEO, said in a statement. “Both South Fork Wind and Sunrise Wind are helping to build a new and dynamic offshore wind industry right here on Long Island — an industry that will protect our environment and provide new clean energy jobs.”

The Sunrise wind farm was awarded as part of New York State Energy Research and Development Authority’s (inaugural competitive 2018 offshore wind solicitation.

Construction on the South Fork Wind project, New York’s first offshore wind farm, began in February. The project was selected under a 2015 LIPA request for proposals to address growing power needs on the east end of Long Island.

Massachusetts Municipal Wholesale Electric Details Model to Develop Carbon-Based Incentives

November 30, 2022

by Paul Ciampoli
APPA News Director
November 30, 2022

The Massachusetts Municipal Wholesale Electric Company (MMWEC) and the Center for EcoTechnology (CET) recently released a report detailing a new model designed to help municipal light plants (MLPs) develop carbon-based incentives for MMWEC’s NextZero program.

The report, “Carbon-Based Incentives: Aligning Utility Incentives with the Decarbonization Impacts of Efficiency and Electrification Measures,” was produced by CET, with assistance from staff from MMWEC and Shrewsbury Electric and Cable Operations (SELCO). 

MMWEC received a grant from the American Public Power Association’s Demonstration of Energy & Efficiency Improvements (DEED) program to help fund the project.

The report details the development of the model, which is designed to help MMWEC’s MLP members set energy efficiency and electrification incentives at levels that are fully aligned with the Commonwealth’s decarbonization objectives, MMWEC noted.

The model uses carbon as the metric for deriving incentive levels and for comparing carbon benefits from a range of measure types, including efficiency, electrification, renewable energy, demand response, and storage. In addition to the carbon analysis, the model also calculates economic impacts of installed measures for the customer and utility. 

The model, to be used by NextZero program managers and utility staff, is designed to be easily adapted to reflect the unique aspects of each utility. Users have control over utility-specific inputs, including electricity pricing, electricity carbon emission factors, existing utility incentives, and carbon price, which is a price per ton of carbon avoided. 

With inputs relevant to MMWEC participants, the model finds that overall, the measures with the largest recommended incentives are ground source and air source heat pumps.  Other top measures from a carbon mitigation perspective are electric vehicles, solar PV, and heat pump water heaters. 

“While the model is a helpful tool to measure carbon and financial impacts of energy efficiency and electrification measures, the study’s authors suggest that other benefits, such as fuel switching and health benefits, be considered in the development of incentives as well,” MMWEC noted.

Ashley Muspratt, President at the Center for EcoTechnology, said that the model “we built allows utilities to set a carbon price, or a willingness to pay for carbon, and the model will set incentives accordingly. This way, a utility is always paying a consistent carbon price, say $50 or $100 per ton of CO2.” 

“The Carbon-Based Incentive Model allows participants in the NextZero program to focus limited resources on measures that eliminate the most carbon emissions at the lowest cost, allowing rates to remain as low as possible,” said MMWEC’s Sustainability Policy and Energy Program Senior Manager, Bill Bullock.  “MMWEC considers low electric rates a built-in incentive to make strategic electrification an easier choice for electric customers in municipally owned electric utilities.”

MMWEC is a not-for-profit, public corporation and political subdivision of the Commonwealth of Massachusetts created by an Act of the General Assembly in 1975 and authorized to issue tax-exempt debt to finance a wide range of energy facilities. 

MMWEC provides a variety of power supply, financial, risk management and other services to the state’s consumer-owned, municipal utilities.

APPA Approves Six New Projects for Grant Funding

November 29, 2022

by Jackson Bedbury
APPA News
November 29, 2022

The Board of Directors for the American Public Power Association’s (APPA) Demonstration of Energy & Efficiency Developments (DEED) program met in Burlington, Vermont, from October 27-28 to review open projects and allocate new funding. Of the 13 projects submitted for review, six projects across four states were awarded grants totaling nearly $600,000.

The largest grants awarded $125,000 each to Wakefield Municipal Gas & Light Department (Massachusetts) for its Energy Management Park and Educational Project, Stowe Electric Department (Vermont) for its Deployment of Distribution Automation Technologies Pilot Project, and Taunton Municipal Lighting Plant (Massachusetts) for its Deployment of Distribution Automation Technologies Pilot Project.

Smaller grants were also awarded for the Northern California Power Agency’s (California) Hydrogen Project Development Plan, CDE Lightband’s (Tennessee) Artificial Intelligence Enabled Visual Surveillance Demonstration Project, and Anaheim Public Utilities’ (California) Sustainability Education Center.

When reviewing proposals, the DEED program considers criteria including the project’s applicability to other public power utilities, the development of new equipment or methodologies, the timeliness of potential results, and overall customer value.

In addition to the project grants, the board approved three Lineworker & Technical Education Scholarship applications for $2,000 each and five student internships for $4,000 each.

The current DEED Board of Directors comprises Board Chairperson Mike Noreen, Conservation and Efficiency Coordinator, River Falls Municipal Utilities (Wisconsin); David Burnett, Power Director, Brigham City Power (Utah); Brian Meek, Director of Training and Safety, Kansas Municipal Utilities (Kansas); Jennifer Rogers Smith, Director of Member Services, Oklahoma Municipal Power Authority (Oklahoma); Darryl Strother, Electric Operations Manager, Rocky Mount Public Utilities (North Carolina); Rachel Huang, Director of Energy Strategy, Research, and Development, Sacramento Municipal Utility District (California); Jared Combs, Business Intelligence Analyst, CDE Lightband (Texas); Jackie Pratt, General Manager, Stowe Electric Department (Vermont); Kyle Roadman, General Manager, Emerald People’s Utility District (Oregon); and Kenneth Roberts, Supervisor of Safety/Training/Mutual Aid Coordinator, ElectriCities of North Carolina (North Carolina).

For more information on the DEED program, to become a DEED member, or to apply for a DEED grant, see the APPA website.

Ribbon Cutting Held for Massachusetts Municipal Wholesale Electric Company Solar Field

November 29, 2022

by Paul Ciampoli
APPA News Director
November 29, 2022

The largest single solar field and the largest public power solar project in Massachusetts is nearing completion, the Massachusetts Municipal Wholesale Electric Company (MMWEC) recently reported.

A ribbon-cutting and dedication ceremony were held in October at the project site on the Ludlow property of MMWEC, the Commonwealth’s designated joint action agency for public power utilities.

The MMWEC/Master Sergeant Alexander Cotton Memorial Solar Project is a 6.9-megawatt AC/10.34- megawatt DC solar farm constructed on a 35-acre section of MMWEC’s Ludlow campus, which is adjacent to Westover Air Reserve Base.

Six MMWEC member municipal light plants are participating in the project, including those located in Boylston, Ipswich, Mansfield, Marblehead, Peabody and Wakefield. EDF Renewables is the project developer.

The project is named in honor of the late Master Sergeant Alexander Cotton of the 439th Airlift Wing at Westover Air Reserve Base, in appreciation of his dedication and service, and in recognition of the long history between MMWEC and Westover.

MMWEC said the project will generate more than 13,800 megawatt hours per year and will displace nearly 13,220,400 pounds of CO2 emissions from Massachusetts power plants per year, based on current ISO New England average emissions.

Featuring state of the art bifacial module technology, the panels produce energy from direct sunlight as well as light reflected onto the backside of the panels. This allows for better year-round production, including during the winter, when snow cover on the ground reflects light onto the back of the panel, MMWEC noted.

“Consistent with the Commonwealth’s decarbonization roadmap, the solar project allows the participating municipal light departments to increase the non-carbon generation mix in their power portfolios, while helping them to maintain stable rates for their customers,” said MMWEC CEO Ronald DeCurzio.

Clark Public Utilities, Pend Oreille Public Utility District Enter Hydro Power Sales Agreement

November 29, 2022

by Paul Ciampoli
APPA News Director
November 29, 2022

Clark Public Utilities and the Pend Oreille Public Utility District (PUD) have entered into a long-term power sales agreement under which Pend Oreille PUD will sell all energy produced by the Box Canyon hydroelectric project in Washington State to Clark Public Utilities from Jan. 1, 2026, through December 2041, with contract extensions available under mutual agreement.

The Clark Public Utilities Board of Commissioners unanimously approved the 16-year power sales agreement on Oct. 18 following unanimous approval by Pend Oreille PUD’s Board of Commissioners on Oct. 4. Clark Public Utilities and Pend Oreille PUD are both located in Washington State.

The agreement “reflects a long tradition of collaboration and cooperation among the state’s customer-owned public utility districts to deliver reliable, responsible power to the local communities served, and is a critical piece of Clark Public Utilities’ strategy to meet state-mandated emissions reduction targets ahead of schedule,” the public power utilities said.

The Box Canyon Dam averages approximately 50 megawatts of generation annually.

Clark Public Utilities will pay the forecasted dam costs and debt service payments associated with the power plant modernization and the environmental mitigation modifications made by Pend Oreille PUD over the last decade.

The contract secures a stable, long-term customer for Pend Oreille PUD, which, since 2019 has undertaken a multi-phase remarketing effort of its energy supply, both in anticipation of and following the closure of the Ponderay Newsprint Company, which represented about 70 percent of the utility’s historical load.

EPA Issues First Final Decision to Deny Plant’s Request to Continue Disposal of Coal Ash

November 28, 2022

by Paul Ciampoli
APPA News Director
November 28, 2022

The U.S. Environmental Protection Agency (EPA) on Nov. 18 issued the first final decision to deny a facility’s request to continue disposing of coal combustion residuals (CCR) into an unlined surface impoundment after the deadline to stop such disposal has passed.

Specifically, EPA took final action to deny the deadline extension request submitted by Gavin Power, LLC for the 2,600-megawatt General James M. Gavin Power Plant in Cheshire, Ohio. EPA proposed to deny this request on January 11, 2022.

EPA said it was denying the request for an extension because Gavin has failed to demonstrate that it is in compliance with 2015 CCR regulations. In particular:  

According to the Federal Register this facility must stop placing CCR and non-CCR waste streams into its bottom ash pond no later than April 12, 2023, or such later date as EPA establishes to address demonstrated electric grid reliability issues. 

EPA said its final decision recognizes the importance of maintaining grid reliability and establishes a process for Gavin to seek additional time if needed to address demonstrated grid reliability issues.

Because Gavin is in the PJM Interconnection region, EPA said it closely considered the comments from and discussions with PJM and developed a process that relies on and is consistent with PJM’s existing approach to scheduling outages and protecting electric grid reliability.

Specifically, PJM’s process of maintaining grid reliability requires a facility like Gavin to request a planned outage at least 30 days prior to the start of the outage. PJM confirmed in EPA discussions that 30 days is generally sufficient time to assess a facility’s planned outage request.

To ensure that PJM has adequate time to evaluate a request, EPA’s final action also requires Gavin to submit any request for a planned outage to PJM within 15 days of publication of EPA’s final decision in the Federal Register. EPA said it will continue consultations with relevant electric grid authorities to maintain reliability.

EPA’s CCR Part A Final Rule, published on August 28, 2020, grants facilities the option to request an extension to the deadline for unlined CCR surface impoundments to stop receiving waste under two circumstances.

These facilities could submit a demonstration showing a continued need to use the surface impoundment due to lack of capacity.

EPA received and reviewed 57 applications from CCR facilities requesting deadline extensions and determined that 52 were complete, four were incomplete, and one was ineligible for an extension.

Of the 52 complete applications received, EPA proposed determinations for seven facilities, four in January, two in July, and one in October of 2022. Of the seven determinations, three were proposed denials, and four were proposed conditional approvals.

The January 11th proposed determinations raised a host of new legal positions that have been challenged in Electric Energy, Inc., et al. v. EPA. Petitioners contended EPA’s new interpretation of compliance with the 2015 CCR rule was issued without notice and comment and without EPA acknowledging its sudden change in position.  Briefings in the case are expected to begin in early December.

On March 25, 2022, APPA and the Large Public Power Council (LPPC) submitted joint comments in response to the first set of CCR alternative deadlines to initiate closure demonstrations.

EPA’s proposed actions on the first group of Part A CCR Decisions will profoundly affect the electric utility sector, including public power utilities, the groups said.

Furthermore, the proposed decisions will likely have adverse repercussions for both the remaining unlined surface impoundments as well as other CCR disposal facilities regulated under the federal CCR rule, APPA and LPPC said.

Reliability, Resiliency, Safety and Affordability Flows from Small Modular Reactor Technology

November 28, 2022

by Peter Maloney
APPA News
November 28, 2022

New nuclear technologies, such as small modular reactors (SMR), have reached a point where they are able to help utilities address growing concerns about fulfilling their core mission: delivering safe, affordable, and reliable electric power.

Several industry trends are challenging utility executives’ abilities to balance those three key objectives.

A July report from the North American Electric Reliability Corp. (NERC) highlighted the growing threats to reliability, including extreme weather events, the growing proliferation of “inverter based resources” such as photovoltaic solar power and energy storage, and increasing reliance on natural gas-fired generation.

The growth of renewable resources aimed at meeting state and federal goals aimed at addressing greenhouse gas emissions has been impressive. In the first half of the year, 24 percent of utility-scale generation in the United States came from renewable sources, according to the Energy Information Administration. However, as NERC pointed out this summer, as renewable resources have proliferated, gas-fired generators are becoming “necessary balancing resources” for reliability, leading to an interdependence that poses “a major new reliability risk.”

In this environment, if utilities are going to stay on track to meet their clean energy targets while providing secure, safe and reliable electric power to meet growing demand, they are going to need a new solution.

“NuScale Power’s SMR technology offers a carbon-free energy solution with features, capability, and performance not found in current nuclear power facilities,” Karin Feldman, Vice President of NuScale’s Program Management Office, said in an interview.

Several utilities have already begun exploring the potential of a new generation of nuclear technology to help them meet both their clean energy and reliability needs as they work toward meeting growing demand.

NuScale’s project portfolio includes a six module, 462-MW VOYGR™ SMR power plant. Utah Associated Municipal Power Systems (UAMPS) plans to develop at the Department of Energy’s (DOE) Idaho National Laboratory in Idaho Falls for their Carbon Free Power Project (CFPP).

NuScale also has memorandums of understanding to evaluate the deployment of its SMR technology with Associated Electric Cooperative in Missouri and Dairyland Power Cooperative in Wisconsin.

“What we bring to the table is a technology that is smaller and simpler; that lowers total costs while providing high reliability and resilience, and greater safety,” said Feldman, who develops and manages NuScale’s portfolio of projects and establishes and maintains project controls, cost estimating, and risk management standards. She is also NuScale’s primary interface with the DOE.

Cost Comparisons

The smaller scale of NuScale’s reactors – 77 MW versus 700 MW or even 1,600 MW or more for conventional reactors – brings several cost advantages, Feldman said. Smaller reactors can be fabricated in a factory, which is cheaper than field fabrication, because it involves repetitive procedures that foster iterative improvement and economies of scale, she said. Smaller reactors also take less time to build, which lowers construction costs.

Because they are modular, an SMR does not force a utility to commit to participation in a nuclear project in the 1,000-MW to 2,000-MW size range. An SMR project can be scaled to meet demand, and modules can be added as demand requires, Feldman said. That helps reduce financial risk for a utility, she said.

Another, related consideration, highlighted by the supply chain disruptions in the wake of the COVID-19 pandemic, is that much of NuScale’s technology can be locally sourced. “We are taking advantage of the U.S. supply chain to the greatest extent possible,” Feldman said. “We have some overseas manufacturers, but we are also engaged to develop additional U.S. capabilities in areas such as large-scale forgings.”

Reliability and Resiliency

Nuclear power plants generally have high reliability, over 92 percent, nearly twice the reliability of coal and natural gas plants, but the smaller, compact design of SMR technology can offer additional reliability advantages, Feldman said. Because NuScale plants are designed to scaled up in incremental steps, if any one of the individual reactors has an issue, the other reactors can continue to generate power, she explained.

NuScale’s SMR technology also enhances resiliency, Feldman said. The design calls for the reactors to be housed in a building below grade, hardening their vulnerability to airplane strikes and very large seismic events, she said.

An SMR plant also is designed with black start capability so that it can restart after a disruption without using the surrounding electric grid. “So, in the event of an emergency, it could be a first responder to the grid, one of the first generators to start up,” Feldman said.

And because the design calls for multiple reactors, a problem with one reactor does not require the entire plant to shut down. An SMR plant can also operate in island mode, serving as a self-sufficient energy source during an emergency, Feldman said.

In some ways, a NuScale SMR power plant resembles a microgrid. In fact, NuScale’s technology team has done a lot of analysis on microgrid capacity, Feldman said, noting that the analysis found that a 154-MW SMR plant could run for 12 years without refueling. “The technology is very good for mission critical functions and activities,” she said.

Safety First

Cost and resiliency are important considerations, but if a power plant, especially a nuclear power plant, is not safe, other considerations pale in comparison.

Safety is built into NuScale’s SMR design, Feldman said. “The SMR has a dual walled vessel design that gives it an unlimited coping period,” she said. “If an incident does occur, the plant can shut down without operator intervention or action and be safe and secure,” she said.

NuScale’s integrated design encompasses the reactor, steam generators and pressurizer and uses the natural action of circulation, eliminating the need for large primary piping and reactor coolant pumps.

If needed, the reactor shuts down and self cools indefinitely without the need for either alternating current or direct current power or additional water. The containment vessel is submerged in a heat sink for core cooling in a below grade reactor pool housed in a Seismic Category 1 reactor building as defined by the U.S. Nuclear Regulatory Commission (NRC). In essence, the unit continues to cool until the decay heat dissipates at which point the reactor is air cooled, Feldman said.

In 2018, the NRC found that NuScale’s SMR safety design eliminates the need for class 1E power, that is, power needed to maintain reactor coolant integrity and remain in a safe shutdown condition.

In August 2020, the NRC approved the overall design of NuScale’s SMR. In a next step, the NRC in July directed staff to issue a final rule certifying NuScale’s SMR design.

If approved, the certification would be published in the Federal Register and have the effect of law, providing even greater comfort to any entities exploring SMR technology to provide clean, emission free, reliable and affordable power, Feldman said.

The rulemaking is on NRC’s docket for a decision in November.

Finally, after a rigorous years long review by the NRC, the Final Safety Evaluation Report (FSER) regarding NuScale’s Emergency Planning Zone (EPZ) methodology was issued. This is another tremendous “first” for NuScale’s technology. With the report’s approval of our methodology, an EPZ that is limited to the site boundary of the power plant is now achievable for a wide range of potential plant sites where a NuScale VOYGR™ SMR power plant could be located.

N.Y. Governor Signs Bill Placing Two-Year Moratorium on Certain Types of Cryptocurrency Mining

November 28, 2022

by Paul Ciampoli
APPA News Director
November 28, 2022

New York Gov. Kathy Hochul on Nov. 22 signed a bill into law that places a two-year moratorium for certain types of cryptocurrency mining operations.

In a memorandum related to her signing the bill, Hochul said that the law will prohibit Environmental Conservation Law permits from being issued for two years to proof-of-work cryptocurrency mining operations that are operated through electric generating facilities that use a carbon-based fuel.

New York is the first state to take such action, Hochul said.

The law also requires the state’s Department of Environmental Conservation (DEC) to prepare a generic environmental impact statement on cryptocurrency mining operations that use proof-of-work-authentication methods to validate blockchain transactions.

The law still allows for the issuance of permits for generating facilities that “use alternatives to carbon-based fuel, such as hydropower, which would permit growth and business development in this industry,” the memorandum said.

Cryptocurrency and other trade groups expressed disappointment in Hochul’s action.

The Chamber of Digital Commerce, a blockchain trade association, said that to date, “no other industry in the state has been sidelined like this for its energy usage. This is a dangerous precedent to set in determining who may or may not use power.”

“The Business Council does not believe the legislature should seek to categorically limit the growth and expansion of any business or sector in New York,” said Heather Briccetti Mulligan, President & CEO of the New York Business Council. “We plan to further engage and help educate them regarding this industry and the benefits it provides to the local, regional, and state economy.”

Click here for additional details on the bill that Hochul signed into law.

New York DEC Denies Air Permit Renewal To Cryptocurrency Mining Power Plant

In July, the DEC denied renewal of an air permit to a 107-megawatt (MW) power plant in Yates County that is used to power computer operations for proof-of-work cryptocurrency mining.

In denying a Title V air permit renewal for Greenidge Generation in the town of Torrey, the DEC cited the dramatic increase in greenhouse gas emissions from the facility since the passage of the state’s Climate Leadership and Community Protection Act driven by “the change in the primary purpose of its operations.”

California Regulators Adopt $1 Billion Transportation Electrification Program

November 27, 2022

by Paul Ciampoli
APPA News Director
November 27, 2022

The California Public Utilities Commission (CPUC) on Nov. 17 adopted a five-year, statewide, $1 billion transportation electrification program.

Under the program, 70 percent of the funds will go towards charging for medium-and heavy-duty vehicles and 30 percent will go towards light-duty charging at or near multi-unit dwellings.

The program offers rebates for customer side EV infrastructure investments at commercial, industrial, and residential sites beginning in 2025 and provides higher rebates for projects in underserved, disadvantaged, and tribal communities to ensure charging infrastructure reaches these hard-to-reach communities.

The CPUC decision directs the state’s investor-owned utilities to host annual roundtables and workshops to discuss potential program modifications with stakeholders and CPUC staff.

The action resolves the transportation policy framework that has been in development since 2020. The decision also furthers the integration of EVs as an energy resource that can help meet the needs of the grid by developing a strategy for promoting vehicle-grid integration.

The CPUC is undertaking multiple efforts to promote EV adoption and infrastructure, including adopting rules to ensure that customers installing EV chargers do not have to wait unreasonable times to interconnect to the grid.

In the proceeding to modernize the electric grid for a high distributed energy resources future, the CPUC is overseeing the investor-owned utilities’ plans to upgrade the distribution grid to meet the new load EV charging will create. Additionally, the CPUC’s Integrated Resource Planning (IRP) proceeding, which ensures sufficient electric generation and transmission capacity to meet reliability and GHG reduction goals, is planning for increasingly high penetrations of electric vehicles to guide procurement and infrastructure decisions.

FERC Moves to Address Reliability Issues Tied to Growth of Inverter-Based Resources

November 27, 2022

by Paul Ciampoli
APPA News Director
November 27, 2022

The Federal Energy Regulatory Commission (FERC) on Nov. 17 took a number of actions addressing reliability issues tied to the growth of inverter-based resources (IBRs). 

IBRs are solar photovoltaic, wind, fuel cell and battery storage resources that use power electronic devices to change direct current power, produced by generators, to alternating current power, to be transmitted on the bulk-power system. “As use of this technology grows, it is important to ensure that IBRs do not adversely impact the technical reliability of the grid,” FERC noted.

At the meeting, FERC Commissioners approved an order and a notice of proposed rulemaking (NOPR) containing directives and proposed directives to the North American Electric Reliability Corporation (NERC), to account for the increasing number of IBRs in the nation’s resource mix. 

FERC Order

In the order, FERC directed NERC to submit within 90 days a work plan for Commission approval describing, in detail, how NERC plans to identify and register owners and operators of Bulk-Power System-connected IBRs that are not currently required to register with NERC under the bulk electric system definition but that in the aggregate have a material impact on the reliable operation of the Bulk-Power System.

Many IBRs connecting to the Bulk-Power System do not individually meet the current bulk electric system definition and, thus, are not registered with NERC, FERC staff said in a presentation.  NERC’s Commission-approved bulk electric system definition defines the scope of NERC’s reliability standards and the entities subject to NERC compliance. This means that those IBRs are not required to comply with mandatory reliability standards or respond to NERC Alerts. 

The order directs NERC to do three things. First, to complete modifications to its registration processes no later than 12 months after Commission approval of the work plan.  Second, to identify all owners and operators of Bulk-Power System-connected IBRs that in the aggregate affect the reliable operation of the Bulk-Power System no later than 24 months of Commission approval of the work plan.  And third, to register owners and operators of Bulk-Power System-connected IBRs that in the aggregate have a material impact on the reliable operation of the Bulk-Power System no later than 36 months after Commission approval of the work plan. 

The order recognizes that smaller Bulk-Power System-connected IBRs may not present the same reliability impact in all circumstances as generation that has historically been registered.  Accordingly, the order acknowledges that NERC may determine that the full set of reliability standard requirements otherwise applicable to generator owners and operators need not apply to all newly registered Bulk-Power System-connected IBR generator owners or operators.

NOPR

In the NOPR, FERC preliminarily finds that the reliability standards do not fully address the impacts of IBRs on the reliable operation of the Bulk-Power System. 

The NOPR proposes to direct NERC to develop new or modified reliability standards that address four reliability gaps related to IBRs:

The NOPR proposes to direct NERC to submit a compliance filing within 90 days of the effective date of the final rule detailing a comprehensive standards development and implementation plan explaining how NERC will prioritize the development and implementation of new or modified reliability standards to address the reliability gaps. 

The NOPR explains that NERC’s plan should take into account the risks posed to the reliable operation of the Bulk-Power System, standard development projects already underway, resource constraints, and other factors as necessary. 

Comments in response to the NOPR are due 60 days after the date of publication in the Federal Register, with reply comments due 30 days later.

FERC also issued an order that approved reliability standards that are related to IBRs, which NERC proposed earlier this year.