Search
`
November 2, 2024

Posted on

NJ Greenlights Incentives for Multi-dwelling EV Chargers

The New Jersey Board of Public Utilities (BPU) on Wednesday authorized new incentives to promote the installation of EV chargers in multifamily buildings in an effort to broaden the demographics of electric vehicle drivers.

The BPU voted unanimously to establish the new program, which will offer a $1,500 incentive for the installation of a Level 2 charger in an apartment, condominium or mixed-use residential building, and pay half of the project’s “make-ready” costs — for installing the wiring required for a charger — up to a total of $5,000. Incentives increase to $2,000 for a Level 2 charger, and 75% of make-ready costs up to a total of $7,500 for installations in low-income or minority communities or those overburdened with pollution or other negative environmental impacts.

The board allocated $1 million to the program out of $14 million previously set aside to encourage the deployment of charging stations around the state. To be eligible for the multifamily program, a building must have a minimum of five units and have dedicated off-street parking. Applicants can seek funding for up to six Level 2 chargers, which, at 240 volts, can top up an EV battery, for example, while the owner is sleeping.

The BPU’s vote in support of the program was one of several aimed at advancing New Jersey’s clean energy initiatives at the agency’s last regular meeting of the year. The board also extended the completion deadline for projects in the state’s community solar pilot program and endorsed an agreement to work with the National Offshore Wind Research and Development Consortium.

The approval of the EV charger incentives follows Gov. Phil Murphy’s signing in July of a law that makes it easier to install EV chargers in a variety of locations, including multifamily buildings. The law automatically made the installation of electric vehicle supply equipment or the creation of make-ready parking spaces a permitted use under municipal zoning laws.

The law removed the often time-consuming necessity to seek a municipal zoning variance to permit the installation of EV chargers and specifically removed that requirement for multifamily buildings with five or more units. To meet the eligibility rules outlined in the law, a developer must equip 15% of available off-street parking spaces with make-ready charging infrastructure and install EV chargers in at least one third of the available spaces.

Speaking before the vote, BPU President Joseph L. Fiordaliso, said the multifamily incentives are important because they expand “the participation of all communities within the state of New Jersey into renewable energy, into, in this case, electric vehicles.”

Residents in multifamily buildings may not have the opportunity to buy or drive an EV unless their building is equipped with a charger, Fiordaliso said. “This is a start,” he said. “Every segment of our population must have the opportunity to participate in the clean energy revolution that we’re going through in this country, and in this state.”

The new incentive program is part of Murphy’s plan to cut New Jersey’s carbon emissions by 80% of the 2006 levels by 2050. The state also sees the installation of chargers as key to reaching its goal of putting 330,000 light-duty EVs and plug-in hybrids on the road by 2025. Other 2025 goals including putting at least 1,000 Level 2 chargers and 400 DC fast chargers at locations available for public use.

Promoting Competition, Ratepayer Protection

The BPU also belatedly ratified comments drafted by New Jersey and seven other states and the District of Columbia responding to FERC’s Advance Notice of Proposed Rulemaking regarding transmission planning, transmission cost allocation, and generation interconnection (RM21-17). The seven states — Connecticut, Maryland, Massachusetts, Delaware, Rhode Island, Vermont and Minnesota — and the District of Columbia submitted the comments to FERC on Nov. 26.

The comments include two key points:

  • The commission’s plan must ensure any rules enacted do not impede open and transparent competition and result in discriminatory behavior. “The Commission must closely scrutinize any proposed transmission reforms, especially those that impact competition,” a section of the ratified comments states. Given that ratepayers will need to spend billions more to reach clean energy goals, we cannot afford inefficient, non-transparent and non-competitive planning and procurement processes,” the comments said.
  • The commission should establish regional independent transmission monitors to track the planning and cost of transmission facilities in the region. “An independent transmission monitor with expertise in evaluating transmission development costs, and the best means of controlling those costs, would give ratepayers an important additional protection and an unbiased entity to guard their interests,” the agencies stated. Without it, the “inherent economic self-interest of transmission owners” could lead them to oppose transmission expansion and limit new entrants seeking to develop transmission facilities, the agencies said.

BPU Extends Community Solar Completion Deadline

Solar developers who took part in the first phase of New Jersey’s Community Solar Energy Pilot Program, which the BPU launched in 2019, will get another four months to complete their projects, the BPU decided Wednesday. Without the extension, the completion deadline for projects approved in the pilot’s first phase would be Dec. 30.

Two of the first phase projects, developed in Perth Amboy by Solar Landscape of Asbury Park, began operating in January. But the 78 MW of projects approved in the first phase have faced several challenges, said the BPU order outlining the reasons for the deadline extension. (See Billing Key to NJ Community Solar Growth.)

Many had to cope with completing installations amid the COVID-19 pandemic, the order said. In addition, developers faced complications from a change in New Jersey’s solar incentive programs, switching the state’s original Solar Renewable Energy Certificates (SRECs) incentives to a transitional program issuing Transition Renewable Energy Certificates (TRECs).

As a result of such shifting conditions, program participants had different deadlines, and the extension to April will simplify the rules and bring all the program participants onto the same page, the board order said.

The BPU in October selected 105 projects totaling 165 MW for the second phase of the Community Solar Energy Pilot Program, but those projects are not affected by the deadline change. The board is planning a permanent community solar program that will begin in 2022. (See NJ Selects 165 MW in Community Solar Projects.)

Backing Clean Energy Collaboration

The BPU also backed two agreements related to the state’s growing offshore wind sector. In one, the board approved a memorandum of understanding with the National Offshore Wind Research and Development Consortium, a national nonprofit organization that works with industry to conduct research aimed at reducing the cost of offshore wind. The MOU will define the “procedures and protocols” for the BPU’s membership in the organization.

The second agreement, with the New Jersey Department of Environmental Protection, will determine how the state administers the revenues it will collect from fees of $10,000 per MW to be paid by developers of offshore wind projects approved in the second of the BPU’s two solicitation rounds. The fees are intended to “support research initiatives and the regional monitoring of wildlife and fisheries related to the introduction of offshore wind projects.” The agreement will determine the rules and guidelines governing how the funds are allocated.

The two agreements will be made public when they are signed, said BPU spokesperson Peter Peretzman.

Posted on

NYISO ICAP/MIWG Briefs: Dec. 14, 2021

NYISO Monitor: Q3 Energy Prices Up Sharply Y-o-Y

NYISO energy markets performed competitively in the third quarter of 2021, with all-in prices ranging from $38/MWh to $117/MWh, up 62% to 94% from 2020 in all regions except New York City, which saw a decrease of 16%, the Market Monitoring Unit said.

“So there was quite a large spread, with particularly high prices in Long Island,” said Pallas LeeVanSchaick of Potomac Economics as he presented the quarterly report on the ISO’s electricity markets to the Installed Capacity/Market Issues Working Group.

Energy prices rose 68% to 124% primarily because of higher gas prices, which rose 110% to 139% across the system. The exception was New York City, which saw a decrease driven by lower capacity prices resulting from a lower locational capacity requirement, he said.

Third quarter 2021 natural gas and fuel oil prices (Potomac Economics) Content.jpgThird quarter 2021 natural gas and fuel oil prices in the New York Control Area. | Potomac Economics

 

Nuclear output fell by an average of 820 MW/hour following the retirement of Indian Point 3.

Both 345-kV lines from upstate New York to Long Island were out of service for more than half of the days during the quarter, LeeVanSchaick said, which led to some “pretty extraordinary conditions on Long Island, very tight, with very volatile pricing.”

He said the loss of the lines resulted in several “inefficiencies” including:

  • Lack of reserve shortage pricing during Long Island capacity deficiencies;
  • Understated reserve requirements in the day-ahead and real-time markets;
  • Inflexible generator scheduling related to gas-balancing charges; and
  • Over-accreditation of capacity for some conventional Long Island generation.

NYISO was able to substantially reduce the use of out-of-market dispatch to manage congestion on Long Island because they started modeling two 69-kV facilities, which were constrained on more than 80% of the days in the quarter, LeeVanSchaick said.

Despite several heat waves, load exceeded 30 GW on just one day, and transmission owners activated utility demand response on 10 days, mostly for peak-shaving.

NYISO applied supplemental resource evaluation (SRE) — a determination of the least-cost selection of additional generators to be committed — for statewide capacity needs on three days. Some of those SREs probably would not be necessary if there was more consideration of the utility DR deployments that are going to be called before the ISO makes the decisions, LeeVanSchaick said.

The Monitor identified several categories of conventional generating capacity that may receive excessive accreditation under the current rules, which he said should be evaluated further.

“We do also still observe large quantities of out-of-merit commitment for operating reserve requirements that are not adequately reflecting the day-ahead and real-time markets … both at the larger level as well as in more localized areas,” he said.

Reserve Enhancements for Constrained Areas

Pallavi Jain, energy market design specialist, presented a study evaluating the feasibility of dynamically scheduling reserves in the security constrained unit commitment (SCUC), real-time commitment (RTC) and real-time dispatch (RTD) intervals

“We’re looking at dynamically scheduling reserves because the current static modeling of reserves and the associated requirements may not optimally reflect the varying needs of the grid to respond to operating conditions,” Jain said.

Based on all the mathematical formulations and the prototype, the ISO has determined that it is feasible to set dynamic reserve requirements based on the single largest contingency systemwide and using the available transmission headroom. However, this concept would need to be further developed and its applications to all reserve areas would need to be evaluated, Jain said.

National Grid pipeline sections (National Grid) Alt FI.jpgNational Grid pipeline sections stacked during construction. | National Grid

 

The ISO made several recommendations, such as considering revising the approach for the determination of the single largest contingency from the current static requirement to a more dynamic methodology; applying the dynamic reserves approach to all reserve areas; and keeping the methodology consistent between the day-ahead and real-time markets to the extent practical.

Senior Manager Tariq N. Niazi presented a consumer impact analysis of the reserve enhancements for constrained areas, which looked at four scenarios based on conditions on Aug. 5, 2021, a hot summer day.

In three of the scenarios LBMPs decreased between $0.60/MWh and $2.60/MWh in different load zones and reserve clearing prices increased by less than $0.10/MWh in the reserve areas. A fourth scenario found an insignificant change in prices.

The ISO will continue working on the prototype in hopes of completing a market design proposal by December 2022 and implementation in 2025.

Coordinating Tx and Distribution

NYISO also updated stakeholders on a project to ensure coordination between transmission system operators (TSOs) and distribution system operators (DSOs) in compliance with FERC Order 2222.

The project will ensure that NYISO and the New York transmission operators have the communication protocols and procedures in place to maintain reliability as DER penetration increases, said Michael Ferrari, market design specialist in new resource integration. (See NYISO Updates Grid in Transition Work and Plan for 2022.)

The ISO has been working with the applicable member systems individually to identify transmission nodes, with those identified in the New York Control Area now totaling 115.

Transmission nodes are electrically similar facilities to which individual DER may aggregate as a DER coordinating entity aggregation (DCEA), represented by a single point identifier (PTID).

A transmission node might comprise several load nodes, which provide the most detail for NYISO system modeling and are associated with distribution stepdown transformers at facilities below the transmission level NYISO currently secures.

NYISO will present the list of transmission nodes at an ICAP meeting early in the first quarter of 2022.

NYISO and the investor-owned utilities in the state have created a framework to prohibit resources participating through an aggregator from receiving compensation for the same services as part of another program. The ISO’s Order No. 2222 compliance filing proposes to require aggregators make attestations that its DERs are not providing the same service(s) in a retail market or program.

To prevent double counting, NYISO is collaborating with the utilities to develop a document identifying retail market services that conflict with wholesale market services.

This project and current coordination efforts will continue in 2022 with a focus on facility enrollment; metering and communications infrastructure and configurations; and NYISO administrative and operational manuals, an aggregation program manual, and supporting modifications to existing manuals, Ferrari said.

One stakeholder expressed concern that the ISO was working only with the utilities on DER participation and not with aggregators, saying the one-sided approach is a missed opportunity to encourage DER participation.

The ISO responded that any utility denying participation to DER must provide detailed data to back up its rationale and lay out steps the utility will take to improve market access in that specific case.

Prohibiting Critical Infrastructure Load from DR Programs

Responding to NERC and FERC guidance, NYISO is proposing to prohibit market participants from enrolling critical infrastructure load in its demand response programs. (See Grid Faces Multiple Risks in Winter Months, NERC Warns.)

Critical infrastructure is load needed to deliver natural gas, fuel oil, and other fuels used to supply generation, and load otherwise likely to impact the supply of fuels to generators serving the New York Control Area, said Francesco Biancardi, market design specialist. It includes natural gas compressors, LNG storage facilities, fuel oil suppliers, refineries and control centers.

NERC on Oct. 6 submitted a Standard Authorization Request to address extreme cold weather grid operations, preparedness and coordination. Recommendation No. 8 states that “balancing authorities’ operating plans (for contingency reserves and to mitigate capacity and energy emergencies) are to prohibit use of critical natural gas infrastructure loads for demand response.”

In January 2021, approximately 1,071 kW of curtailment capability was offered by special case resources (SCRs) that include critical infrastructure load, according to an ISO survey of DR providers. About 175 kW of such curtailment capability was offered in July 2021.

While the total kW of demand response load is small as compared to total system MW, it is possible that curtailment of a small amount of critical infrastructure load could have a material impact on generator availability, Biancardi said. For example, curtailment of a few kW of natural gas compressor station load could cause an outage of many MW of generation, Biancardi said.

The ISO is working toward implementation before Winter 2022/23.

Posted on

BOEM Issues Final Environmental Review of NY Bight

The U.S. Bureau of Ocean Energy Management (BOEM) gave a green light for further offshore wind development in the New York Bight Thursday, issuing a final environmental assessment (EA) with a finding of no significant impact.

The report clears the way for auctioning of up to 10 new wind energy leases, the first of which are expected early in 2022.

The EA considered potential environmental consequences of the OSW development, which includes site characterization activities (i.e., biological, archeological, geological and geophysical surveys and core samples) and site assessment activities such as the installation of meteorological buoys. The EA also considered project easements associated with each potential lease issued and grants for subsea cable corridors.

BOEM determined that the OSW work in the Bight would neither cause any significant impacts, nor constitute a major federal action significantly affecting the quality of the human environment within the meaning of the National Environmental Policy Act of 1969.

“Adverse effects to the environment … would range from negligible to minor,” the EA said.

New York has contracted nearly half of the 9 GW of OSW targeted for construction by 2035. (See NY Awards 2.5-GW Offshore Deal to Equinor.)

OSW developers also have begun constructing the port facilities needed to build and operate their projects, with Equinor using the Port of Albany for tower manufacturing, the nearby Port of Coeymans for turbine foundation manufacturing, and making the South Brooklyn Marine Terminal into an assembly and operations and maintenance hub. (See NY Builds OSW Ports in Brooklyn, Albany, Long Island.)

Posted on

NYPSC OKs Exelon Spinoff of 4 Upstate Reactors

New York regulators on Thursday approved Exelon’s (NASDAQ:EXC) plan to split its regulated transmission and distribution business and merchant nuclear power generation into two separate publicly traded companies (Case No. 21-E-0130).

The Public Service Commission accepted a joint proposal by Exelon staff of the Department of Public Service, the state Attorney General, the Alliance for a Green Economy and the Long Island Power Authority for four upstate nuclear power plants to be spun off by Exelon.

The spinoff, Exelon Generation, will become part of a new, independent, publicly traded entity that owns the two-unit 1,918-MW Nine Mile Point nuclear power plants in Scriba, Oswego County; the 579-MW R.E. Ginna nuclear power plant in Ontario, Wayne County; and the 842-MW James A. FitzPatrick nuclear power plant, also in Scriba.

“Getting all the parties from disparate sides to sit at the table together to agree on this shows how significant their goals were of supporting the interests of New York,” PSC Chair Rory M. Christian said. “The simple fact that we’re going to be able to decommission these plants in 20 years, rather than the recommended 60, is a huge accomplishment. The financial protections you accomplished and achieved through these negotiations are just as significant.”

FERC in August approved the corporate transfer proposal, determining the transaction to be “consistent with the public interest” (EC21-57). (See FERC Sanctions Exelon’s Plan to Split Utility, Generation Businesses.)

The current operating licenses expire in 2029 for Ginna and Nine Mile Point 1, 2034 for FitzPatrick and 2046 for Nine Mile Point 2. The Nuclear Regulatory Commission (NRC) and the PSC required funds be set aside for the decommissioning of the facilities and the restoration of the sites.

Operational Details

Diane X Burman (NYPSC) Content.jpgNYPSC Commissioner Diane X. Burman | NYDPS

A lot of these issues were not as contentious as others for the parties, so working with the collaborative process seems to have worked here, Commissioner Diane X. Burman said.

Exelon has an “extraordinary obligation” to the state of New York, considering the more than $7 billion in ratepayer money that supports the four units and without which these plants would have ceased operation some time ago, Commissioner John B. Howard said.

“Second of all, the parent of this company, it should be pointed out, has had serious corruption allegations in the state of Illinois, and those are being pursued by various law enforcement and prosecutorial entities in that state and with the federal government. So that was the background by which we started this case,” Howard said.

Exelon also has proven itself devoted to focusing on safety and reliability, Howard said.

John B Howard (NYPSC) Content.jpgNYPSC Commissioner John B. Howard | NYDPS

In addition, the nuclear plants represent “a huge chunk of the overall central New York economy” and the people working at the facilities are “maybe the highest-paid and best-benefited workers in the region,” he said.

Under the approved proposal, Exelon and Exelon Generation agreed to the following:

  • Continuation of emergency operation facilities in New York;
  • Depositing an additional $15 million in the remedial trust fund for Nine Mile Point Unit 2 and maintaining a minimum trust fund balance of $144 million per unit — or $576 million in total across the four units;
  • Provide a 20-year projected backstop timeline for decommissioning following the end of licensed term rather than the 60 years allowed by the Nuclear Regulatory Commission;
  • Acknowledgment of New York State’s 10 millirem clean up guidance standard for residual radiation, rather than the NRC 25 millirem standard;
  • Annual decommissioning trust fund reporting rather than the 2-year summary level reporting to NRC, and twice-a-year reports during decommissioning; and
  • Provide an 18-month advance notice of shut down rather than the 12-month NYISO requirement.

Proposal supporters included the affected counties, the New York State Building and Construction Trades Council and the International Brotherhood of Electrical Workers, Local 97, representing approximately 4,700 electrical workers across upstate New York.

Posted on

FERC Sits Out One Grand Gulf Tax Dispute

FERC told the Louisiana Public Service Commission Thursday that it would not appoint a discovery master or settlement judge in an ongoing dispute over Entergy’s decommissioning deduction for its Grand Gulf Nuclear Station.

The PSC is attempting to compel Entergy subsidiary System Energy Resources, Inc. (SERI) to hand over accounting information and discussion notes with the IRS and understand the sudden decision to forgo a deduction it has enjoyed and renewed for 17 years (ER21-142).

However, the tax clash will continue to play out in another FERC docket.

The federal commission said in its order that state regulators were raising their arguments under an informal challenge as an interested party and that they needed a more formal channel for those measures.

The PSC filed the information request through a 2020 amendment to SERI’s formula rate protocols that allows interested parties to request information and submit informal challenges to unit power sales agreements. The commission claimed it needed to better understand Grand Gulf’s 2020 formula rate inputs.

SERI owns 90% of the 1,400-MW Grand Gulf plant in Port Gibson, Miss., and sells the plant’s output under a FERC-regulated wholesale rate to Entergy’s Arkansas, Mississippi, Louisiana and New Orleans subsidiaries. It’s taken a tax deduction since 2003 for future costs of shuttering the plant.

The Louisiana commission alleges SERI’s Grand Gulf power sales agreements contain “millions of dollars of unjust and unreasonable charges” because it didn’t reflect the decommissioning tax benefit in its rates. The PSC has accused Entergy of collecting money from ratepayers for taxes that were never paid.

The Louisiana commission and Entergy are involved in a separate docket before FERC over whether the utility violated filed rate doctrine by neglecting to include the decommissioning deduction as a rate base offset. The federal commission this year set that case for settlement hearings to determine customer refunds (ER21-748).

SERI relinquished its decommissioning deduction in 2020 following an IRS Notice of Proposed Adjustment that disallowed more than $1 billion of the deduction. The subsidiary quickly accepted the settlement, and Entergy said its net operating loss carryforwards would absorb the adjustment’s costs.

The Grand Gulf plant has been criticized in recent years for its persistent unplanned outages. Earlier this year, the PSC was joined by the Arkansas Public Service Commission and the New Orleans City Council in a FERC complaint over the plant’s malfunctions and performance issues. The trio argued that Entergy should refund customers the $800 million spent on upgrades to the plant in 2012. They also said Entergy should refund its customers the $361 million in power purchases it has had to make when the station was unavailable since the upgrade.

The Louisiana PSC has registered other grievances about Grand Gulf rates, arguing that SERI’s return on equity was overstated. (See FERC Rebuffs Challenges to Grand Gulf Ruling.)

Posted on

FERC Ups Hydro Dam Inspection and Safety Requirements

FERC on Thursday approved a rule to improve hydro dam safety by instituting a two-tier inspection program and requiring such inspections to be performed by teams with site-specific expertise, rather than a single independent consultant.

Additional provisions in the rule (RM20-9-000) will also codify a 2012 requirement that dam owners develop and file with FERC a Dam Safety Program, as well as report any public safety incidents, including rescues, related to project operations. The rule passed unanimously, with newly installed Commissioner Willie Phillips not voting. It will take effect 90 days after publication in the Federal Register.

The new requirements are based on recommendations from an analysis of the February 2017 incident in which California’s Oroville Dam, the tallest dam in the nation, saw major damage to its primary spillway and the first activation of its auxiliary spillway. About 180,000 people were forced to evacuate the surrounding area. Emergency response and repairs cost more than $1.1 billion, said a recent report from the Congressional Research Service.

Citing that report, FERC Chair Richard Glick said that the U.S. has 90,000 dams, 15% of which are classified as “high hazard potential,” meaning that any failure of the dam could result in loss of life. In addition, half the dams are more than 50 years old and could require upgrades costing an estimated $20 billion, Glick said.

FERC has jurisdiction over more than 2,500 hydro projects, said a Hydropower Primer the commission released in 2017. Following the Oroville incident, FERC convened its own review panel to suggest potential changes to its Dam Safety Program. A notice of proposed rulemaking (RM20-9) was issued in July 2020. (See FERC Proposes Tougher Hydro Safety Rules.)

David Capka, director of the Division of Dam Safety and Inspections in the Office of Energy Projects, said the final rule contains some “clarifying edits” made in response to comments received from stakeholders, including dam owners, other federal agencies and trade associations. But otherwise, it is essentially the same as the 2020 NOPR, he said.

Two-tier System

Prior to the vote, Tara DiJohn, attorney-advisor in FERC’s Office of General Counsel, provided more detail on the four “overarching objectives” of the rule.

All hydro projects under FERC’s jurisdiction will still be subject to the commission’s inspection rules, as spelled out in regulations known as Part 12D, which require inspections every five years. But, DiJohn said, under the two-tier system, “the required scope of the inspection will alternate between a periodic inspection and a comprehensive inspection.”

Ultimate damage at the service spillway (California Department of Water Resources) Alt FI.jpg
Ultimate damage at the Oroville service spillway | California Department of Water Resources

Periodic inspections will focus on “the performance of the project over the previous five years,” she said. “It includes a field inspection or review of project operations, an in-depth review of monitoring data trends and behavior, and an evaluation of whether any potential failure modes are occurring.”

Comprehensive assessments will build on the periodic reviews “with a deep dive into every aspect of a project, including a detailed review of the design basis, analysis of records and construction history, and evaluation of spillway adequacy [and] potential failure modes analysis and risk analysis,” she said.

Commissioner Allison Clements raised concerns about the cost of the new inspections. “If we’re going to strengthen safety, we have to balance the benefits of more stringent requirements with the cost burden to the regulated [projects], including the smaller entities that may have fewer resources,” she said.

The two-tier system is intended to help offset the cost of inspections, DiJohn said, with the periodic inspections being “less burdensome.” With smaller, less complex projects, licensees can also propose a single independent consultant to perform the inspection, she said.

First Line of Defense

The second major provision modifies who performs the Part 12D inspections. “Instead of focusing on the individual independent consultants, we will focus on the qualifications of the independent consultant teams,” DiJohn said.

“We have a lot of very large and very complex projects, and requiring one person to be responsible to review all the features of those projects is a lot to ask,” she said. “To have the right expertise, we want to ensure that licensees look at teams to do that.”

While first required in 2012, the Dam Safety Programs codified in the new rule will “formalize licensees’ policies and procedures related to organizational oversight and responsibilities, internal communication, resource allocation and continuous improvement,” DiJohn said. “A proactive, conscientious licensee is the first line of defense against potential dam safety issues.”

Finally, the rule expands requirements for reporting on public safety incidents at or near dams, DiJohn said, adding rescues to the list of incidents to be reported, along with serious injuries and deaths.

Calling dam safety “one of our most important jobs,” Glick said the new rule was “a step in the right direction … [but] not the end of our efforts to protect the public.” The commission is planning a staff-led technical conference, possibly in April, Glick said, examining financial assurance measures for hydropower projects to ensure than licensees have sufficient financial resources for dam maintenance and repair as needed for public safety.

Posted on

MISO-SPP M2M Settlements Exceed $200M

SPP’s market-to-market (M2M) settlements with MISO exceeded $20 million in October for the second time in 12 months, staff told the Seams Advisory Group Wednesday.

The $20.59 million in settlements, which accrued in SPP’s favor, pushed the M2M payments due to SPP to $203.87 million since the grid operators began the process in March 2015.

Permanent and temporary flowgates were binding for more than 1,875 hours in October. Outages and power swings from nearby wind increased shadow prices. The grid operators exchange settlements for redispatch based on the non-monitoring RTO’s market flow in relation to firm-flow entitlements.

M2M settlements hit a record $51.49 million, in MISO’s favor, in February, thanks to February’s winter storm. Settlements have accrued to SPP during the eight months since February and for 23 of the last 25 months.

New SAG Members

The group welcomed new members Luke Haner of Omaha Public Power District and Brenda Prokop of ITC Great Plains to their first meeting.

The SAG still has three open seats that it plans to fill next year. With a membership normally dominated by transmission owners, the group hopes to diversify by targeting larger retail customers and generation developers when it seeks applications after Jan. 1.

Rate Pancaking Issues

The Seams Liaison Committee’s (SLC) Pancaking Working Group met briefly Wednesday to review survey results of stakeholders’ pancaking issues and its information request of SPP and MISO.

Only five of 20 respondents to the stakeholder survey said their companies have experienced a failed cross-seam transaction, transmission project or interconnection project because of rate pancaking issues. Twelve said rate pancaking is a factor when seeking long-term generation commitments and half said the same for siting or accessing generation in a particular location.

Stakeholders said reservations timing is not consistent between the RTOs. SPP charges for all use of its transmission system, including unreserved use, while MISO only bills for network services taken, not reserved, at the time of the monthly system peak. MISO bills for transmission service each month based on actual usage at the zonal coincident peak, but SPP uses a 12-month rolling average.

Point-to-point reservations (Organization of MISO States) Content.jpgPoint-to-point reservations across the seam | Organization of MISO States

The RTOs told the working group that 59 load-serving entities have transactions across the seam. MISO has three active point-to-point (PTP) service requests across the seam and SPP had 75 network service and PTP requests.

Marcus Hawkins, the Organization of MISO States’ executive director, said he has not yet sifted through all the data, leading to group to plan another meeting in January to take a deeper dive. The working group plans to present its findings to the SLC in February.

Posted on

CAISO Proposes Paying Storage Differently

CAISO issued a straw proposal this week that seeks to address the state’s dependence on energy storage for meeting summer evening peaks by paying batteries to stay charged during the day in readiness for when they are needed most.

Avoiding energy emergencies like those in the past two summers requires batteries to be ready to discharge during heat waves in the hours after the sun sets and solar goes offline, CAISO said.  But requiring storage resources to maintain a state of charge means they cannot take advantage of other financial opportunities during the day, it said.

“A principal concern raised by the storage community is a lack of compensation during critical periods when the ISO must retain state of charge on limited energy storage devices, which may preclude their active participation in the real-time markets,” the proposal says. “The existing bid cost recovery rules, which are designed based on traditional energy generation resources, do not consider energy storage charging and discharging cycles.”

A main objective of CAISO’s energy storage enhancements stakeholder initiative is to develop a “set of solutions to enhance the optimization of storage resources and to allow additional flexibility for storage operators to manage state of charge in the real-time markets,” the straw proposal says. “The ISO proposes a new model, called the energy storage resource (ESR) model, which is unique from existing models because bids are predicated on state of charge values, rather than a dispatch instruction for power.”

The ESR model would require scheduling coordinators to “submit bids in terms of incremental state of charge instead of traditional bids submitted in terms of incremental energy,” in recognition that a resource’s costs to charge and discharge are different based on its state of charge, it says.

“Specifically, the energy storage resource model will allow storage resources to offer lower prices to provide energy when a battery has a nearly full state of charge and higher prices when it is nearly depleted,” it says. “This new model would be employed in the ISO’s market software for both the day-ahead and real-time markets and could be used by participants in the energy imbalance market.”

Before last summer, FERC approved a temporary two-year measure by CAISO to require batteries to maintain a minimum state of charge on days with insufficient supply to meet demand. The proposed changes are intended as long-term market rules.

Another part of the proposal involves paying storage resources for exceptional dispatch by compensating them “at the difference between the prevailing price during the exceptional dispatch and the reference interval discharge price. The reference interval discharge price will be the period when the storage resource actually discharges and sells energy.”

Batteries Proliferate

The proposed new rules reflect the state’s growing reliance on batteries to maintain reliability.

CAISO will have 2,500 MW of four-hour lithium-ion battery storage connected to its grid by the end of this year, CEO Elliot Mainzer told the Western Energy Imbalance Market’s Governing Body on Wednesday. He called 2021 the “advent of the bulk storage fleet on the California grid.”

“I believe that is the highest concentration of lithium-ion battery storage in the world and testament to years of policy support and procurement efforts by state officials,” he said.

Most of the battery resources were connected in response to the rolling blackouts of August 2020, when the state’s vulnerabilities to outages during severe Western heat waves became clear. The state’s increasing reliance on solar and wind power, without sufficient storage, was partly to blame for the energy emergencies. (See CAISO Sees ‘Explosive’ Growth in Storage in July.)

The energy storage enhancements stakeholder initiative, which began in May, focuses on market reforms to bring massive amounts of utility-scale storage into CAISO’s system to back up the solar and wind power needed for California’s transition to 100% clean energy by 2045, as well as to meet local capacity requirements. (See CAISO Readies for Storage Scale-up.)

The separate energy storage and distributed energy resources (ESDER) stakeholder initiative began five years ago and proposed numerous changes in four phases. FERC approved the fourth phase in October; it included market power mitigation measures for storage resources and biddable state-of-charge parameters. (See FERC Accepts Latest CAISO Storage, DER Rules.)

CAISO expects to add at least another 1,000 to 2,000 MW of storage in 2022-2024, most of it in lithium-ion batteries with four-hour discharging capacity.

Summer reliability issues will likely continue through 2024, as natural gas plants close and the state’s last nuclear generator, Pacific Gas and Electric’s Diablo Canyon power plant, begins shutting down, CAISO has said. State energy planners hope a large-scale buildout of solar, wind and batteries will compensate.

Posted on

SERC Urges Winter Preps Before Standard Enforced

NERC Trustee Roy Thilly urged members to adopt the agency’s new cold weather standards before they become enforceable in early 2023 during SERC Reliability’s year-end board meeting.

“The tolerance for outages is non-existent,” Thilly said Wednesday, referring to the general public’s attitude.

He also warned that regions can’t depend on neighboring supplies should a widespread weather event strike, saying it takes four years on average to implement a new standard after a major event.

“That simply is too long a period in some cases,” Thilly said. “We need to decide when we need to be more agile and nimble.”

SERC’s 2021 regional risk report listed supply chain issues, extreme weather, generation fleet transitions, cyber security threats, a dependence on rising natural gas prices and the challenge of integrating variable resources as major concerns this winter. (See Grid Faces Multiple Risks in Winter Months, NERC Warns.)

SERC CEO Jason Blake said the organization plans to tailor its operations more closely to its regional risk reports in 2022. He said it’s important for SERC to be able to point to the report’s sections as the reasons behind workshops and agenda items.

Blake also said SERC will focus more on severe weather preparations.

“We have a very hot footprint; we have parts of the footprint that get pretty cold,” he said. “We also have parts of the East Coast. … If you’re going to get hit by a hurricane, you’re probably in SERC.”

SERC board member Venona Greaff said the new freeze-protection rules should surprise no one.

“For many, it seemed like a freight train bearing down on us, but it’s been a long time coming,” she said, noting that parts of the country have been experiencing notable cold-weather strain on the grid since 2011.

Greaff said NERC left cold weather undefined, giving generation operators the responsibility of deciding which temperatures pose a risk. She said it’s not realistic for the Deep South to enclose entire plants in buildings like those in the North. Greaff said that during the summer, southern generation operators need heat to dissipate, but said operators could consider enclosing smaller segments of their facilities.

Melinda Montgomery, SERC’s senior director of engineering and advanced analytics, said about 86% of SERC entities in a recent survey intended to complete plant winterization before the end of November.

Montgomery said the organization plans to survey its members again on their performance following this winter.

Montgomery said while gas well-head freeze offs and frozen coal piles were an issue in SERC territory during February’s winter storm, frozen plant equipment, water supply issues and local transmission emergencies also contributed to the loss of load.

The February event culminated in the largest controlled firm load shed event in U.S. history at more than 23.4 GW. (See FERC, NERC Release Final Texas Storm Report.)

David Huff, an engineer with FERC’s Office of Electric Reliability, said the winter storm wrought the largest monthly decline of U.S. natural gas production on record. He said production in the continental U.S. dropped 28%; Texas’s production alone dipped more than 70% when compared to its January production.

Huff said 1,045 generating units experienced 4,124 “outages, derates or failures to start.” Of those failures, 58% came from natural gas-fired generation. He said frozen equipment accounted for more generation outages than fuel-supply issues. However, if there was an outage caused by fuel supply, it was overwhelmingly a natural gas generator.

Protecting transmitters, sensing lines and instrument against freezing, as well as protecting wind turbine blades against icing could have reduced offline megawatts caused by outages, Huff said.

Posted on

PUC Forges Ahead with ERCOT Market Redesign

Texas regulators on Thursday pushed ahead with commission staff’s proposal to re-design the ERCOT market, directing the grid operator to work with it in implementing the two-phase approach.

In a 35-minute discussion, the Public Utility Commission did not address the 54 stakeholder comments it received on staff’s Dec. 6 strawman proposal, sticking to language in staff’s original memo. (See PUC Narrows Options for ERCOT Market Redesign.)

In two orders, the commissioners agreed to adopt the strawman as its market redesign blueprint and ordered ERCOT to take the strawman’s Phase 1 blueprint and file a comprehensive implementation report on the plan by Jan. 10. The commissioners also directed the ISO to prepare nodal protocol revision requests for their approval, potentially sidelining ERCOT’s stakeholder process.

Phase 1’s order involves modifying the operating reserve demand curve (ORDC); allowing for “more targeted response” to increase the use of load resources; reforming emergency response service; and adding new ancillary service products.

The PUC ordered ERCOT to make the ORDC changes effective Jan. 1. The modifications include setting the curve’s minimum contingency level to 3,000 MW and eventually decoupling the systemwide offer cap and the value of lost load, now set at $5,000/MWh.

The commission earlier this month lowered the high systemwide offer cap to $5,000/MWh. (See Texas PUC Pushes 44% Reduction in ERCOT Offer Cap.)

Texas PUC Meeting 2021-12-16 (Texas Admin Monitor) Content.jpgPUC Chair Peter Lake (2nd from right) explains his thoughts on the ERCOT market redesign. | Texas Admin Monitor

 

PUC Chair Peter Lake also asked commission staff to work with ERCOT in “crystalizing” the major “abstract” concepts of Phase 2, which is described in the second order. He said staff should focus on Phase 2’s backstop reliability service proposal first and then the load-side reliability mechanism he has been promoting since October.

Neither order had been filed as of Thursday evening.

The PUC did not discuss the cost impact of its proposals.

ERCOT’s Kenan Ögelman, vice president of commercial operations, told the PUC that ERCOT staff would target a Feb. 15 deadline to provide the inputs, specifications, quantification and relevant metrics it would need to design and build each of the Phase 2 proposals.

Alison Silverstein, a former PUC and FERC staffer, said in a fiery response to RTO Insider that she was “deeply disappointed” by the commission’s actions. She said the commissioners should have called for “much more” analysis of both phases’ reliability, market and cost impacts and should include better stakeholder and public input going forward.

“Today the commission voted to implement many Phase 1 measures that will have interacting effects on resource and system operating capabilities and costs, without any clear analysis of whether and how it will all work together or what it could cost Texas electric customers,” Silverstein said. “We don’t know whether all these measures will collectively help or hurt day-to-day resource availability and reliability, and there has been zero calculation of how much additional money they will suck out of Texas electric customers’ wallets.

“I’m willing to pay more for better reliability, as are many Texans, but it’s the commission’s responsibility to make sure that we get what we pay for. Today, the PUC abdicated that responsibility,” Silverstein said.

Consultant Doug Lewin of Stoic Energy, who live-tweeted the open meeting, said although there will be a cost analysis on the load side reliability mechanism and the backstop reliability service, “it still seems to me like they’re missing an integrative look at system needs.”

“How big should the backstop reliability service be? What are we basing that on: a detailed, transparent analysis?” he said in an email to RTO Insider.

Both Lewin and Silverstein said the FERC-NERC investigation of Winter Storm Uri’s devasting power outages in Texas and elsewhere was largely ignored by the PUC. The report laid the blame for the nation’s largest controlled load shed at the foot of the natural gas industry and listed 28 recommendations to prevent a reoccurrence. (See FERC, NERC Release Final Texas Storm Report.)

“There was a lot of discussion at the legislature and in the press about how the 2011 recommendations were largely ignored,” Lewin said. “How seriously are we taking this more recent set of recommendations?”

ERCOT said in a statement that the PUC’s proposals “will require a lot of coordination among all the market participants and market experts,” calling them “the most significant and important changes … since [the market’s] migration to a competitive market almost a quarter-century ago.”

“ERCOT is glad to be able to assist the PUC in this effort and will continue to work closely with the agency to meet the aggressive timeline,” a spokesperson said.

“It is unprecedented to make so many substantive, market and cost changes with such minimal regulatory process and public and stakeholder input,” Silverstein said. “The pace and scope of the PUC’s decisions today may pass legal standards for Texas administrative law practice, but it violates sensible practices for sound public policy and public-interest decision-making.”

The open meeting was punctuated by almost 50 minutes of public comments, organized by the Sierra Club, Public Citizen and Texas Campaign for the Environment. The groups asked the PUC to prioritize public input in their decision-making and consider “people-first solutions.”

To make their point, the group’s members held up a symbolic power line, decorated with 350 icicles, each representing the names of 10 people asking the commission to weatherize the Texas grid to “protect and benefit the people of Texas, rather than the profits of Texas energy companies.”

The wide range of comments called for energy efficiency and demand response measures that decrease energy consumption. One speaker tearfully recounted her granddaughter being forced to go without power for 60 hours and then another 30 without water.

“You need to start being accountable to the people of Texas,” another person said.

Emma Pabst, a representative for the Sierra Club’s Beyond Coal Campaign, called for an energy grid “that works first and foremost for our communities.”

“The fossil fuel industry left us to die during the [February] freeze,” Pabst said. “Natural gas made $11 billion, while we were left to die in our homes.”