NYPA Issues First Annual Integrated Report

August 7, 2023

by Paul Ciampoli
APPA News Director
August 7, 2023

The New York Power Authority on Aug. 2 released its first annual integrated report, which details the operations and activities carried out by NYPA and its subsidiary, the New York State Canal Corporation, in 2022.

The report takes an integrated approach to communicating the Power Authority’s performance, bringing together environmental, social and governance data and audited financial information to present a more comprehensive view of the Power Authority’s value creation process, NYPA said.

The report describes progress toward achieving the priorities set by VISION2030 and the goals outlined in its 2021–25 Sustainability Plan.

In particular, the report examines the value the Power Authority creates for the state, its customers, local communities, and employees through a wide range of activities and relationships focusing on three key areas of performance: enabling the just transition to a decarbonized New York state; empowering a resilient New York state through partnerships; and cultivating success as a team.

NYPA said VISION2030 is a core tenet of the report and focuses on five strategic priorities to achieve the clean energy goals of the Power Authority’s customers and the state. They include the Power Authority’s ongoing partnerships with customers to deliver clean and affordable energy solutions; pioneering the path to decarbonization while ensuring the reliability, resilience, and affordability of the state’s electric grid; facilitating the rapid development of transmission assets; preserving the value of hydropower; and adaptively reimagining the New York State canal system.

The Power Authority achieved progress on a myriad of major initiatives — such as Next Generation Niagara, Smart Path and Central East Energy Connect — and advanced our commitment to 100 percent carbon-free electricity by 2035.

The Power Authority “will lead the power generation sector by developing and publishing an action plan within the next two years to deliver upon its commitment to phase-out electricity production from its fossil fuel peaker power plants by 2030. NYPA will consider using the plants and the sites for renewable generation, energy storage or electric grid support needs,” it said.

NYPA has also implemented programs in partnership with customers and communities to help them achieve their sustainability and climate goals and continued to invest in its employees and their health and safety.

In addition to showing the Power Authority’s financial performance and progress towards meeting its VISION2030 strategy goals, it also shows the impact of the Power Authority’s performance on the environment and the community it serves.

 “We are pleased to publish the first New York Power Authority Integrated Annual Report, which explains the importance of sustainability to NYPA and Canals,” said NYPA President and CEO Justin Driscoll. “NYPA is a first mover in integrating its ESG reporting with its financial reporting to provide a complete picture of the Power Authority’s business operations. This annual report will track NYPA’s progress as it endeavors to achieve its VISION2030 strategic goals and advance Governor Hochul’s nation-leading climate and clean energy agenda.”

 The Power Authority will issue an annual Integrated Report moving forward.

To learn more about sustainability at NYPA, please visit nypa.gov/innovation/initiatives/sustainability.

As Renewable Portfolio Grows, Texas Becoming More Vulnerable to Curtailments: EIA

July 25, 2023

by Peter Maloney
APPA News
July 25, 2023

Renewable generation is growing quickly in Texas’ electric market, but the state is at risk of rising curtailments unless transmission resources also increase, according to the Department of Energy’s Energy Information Administration.

In A Case Study of Transmission Limits on Renewables Growth in Texas, the EIA projects that wind and solar generating capacity in the Electric Reliability Council of Texas region will double by 2035.

In a November 2022 study supporting the Public Utility Commission of Texas’ proposed market reforms, the PUCT projected total variable renewable capacity additions in its base case scenario to be 33 gigawatts by 2035, with the vast majority coming from solar installations.

Over the past two years, solar capacity additions exceeded all competing alternatives, representing 46 percent of all additions from 2020 to 2022 compared with 37 percent for wind, 10 percent for battery storage, and 7 percent for natural gas.

In 2022, solar capacity represented about 5 percent of ERCOT’s generation, the EIA report said, adding that by 2024 Texas is projected to lead the nation in solar power growth, overtaking California.

Much of the growth in Texas’ solar power is occurring in the sparsely populated western region where daytime solar power complements the region’s abundant wind generation that is more productive in the evening and night.

In its analysis, EIA said it assumed there would be “no significant upgrades” made to the ERCOT transmission grid, which allowed the agency to isolate how the existing transmission system affects future renewable generation.

On days with more wind and solar generation and strong demand, limited transmission capacity restricted wind and solar generation flows and curtailments occurred, accounting for 36 percent of the projected curtailments in 2035, the EIA report found, adding that transmission-constraint curtailments could be reduced by upgrading the transmission system.

The EIA analysis also found that 64 percent of the wind and solar curtailments happened when the energy supply from high wind and solar resources outpaced low demand. An increase in demand, such as through battery charging, could potentially reduce those types of curtailments, the report found.

In 2022, ERCOT curtailed 5 percent of its total available wind generation and 9 percent of total available utility-scale solar generation. By 2035, however, the EIA projects wind curtailments in ERCOT could increase to 13 percent of total available wind generation, and solar curtailments could reach 19 percent.

“Understanding the source of the renewable curtailments is key to developing a long-term plan that not only includes renewable capacity, but one that seeks to maximize the value of renewable assets to the grid by investing in curtailment mitigation to support load-shifting programs or assets, ranging from time-of-use pricing to utility scale batteries,” the report concluded.

New York Grid Operator Warns of Reliability Deficit in New York City Area by 2025

July 18, 2023

by Peter Maloney
APPA News
July 18, 2023

The New York City area could have a deficit as large as 446 megawatts as early as summer 2025, according to the New York Independent System Operator.

The deficit in reliability margins for the New York City area is driven primarily by the combination of a forecasted increase in peak demand and the unavailability of certain generators, according to the NYISO report, Short-Term Assessment of Reliability:2023 Quarter 2.

Specifically, some generating plants affected by legislation known as the Peaker Rule will not be available, leaving NYISO’s New York City zone with a deficiency of as much as 446 MW for a duration of nine hours on the peak day during expected weather conditions when accounting for forecasted economic growth and policy driven increases in demand, the report said.

The Peaker Rule, adopted by the New York State Department of Environmental Conservation in 2019, limits nitrogen oxides emissions from simple-cycle combustion turbines used as peakers to meet spikes in demand.

As of May 1, 2023, 1,027 MW of affected peakers have deactivated or limited their operation, and an additional 590 MW of peakers are expected to become unavailable beginning May 1, 2025, all of them in New York City, the report said.

Beyond 2023, the New York City transmission security margin is expected to improve in 2026 if the Champlain Hudson Power Express connection from Hydro Quebec to New York City enters service on schedule in spring 2026, but the margin gradually erodes thereafter as expected demand for electricity grows, the report said.

Forecasted reliability margins within New York City may not be sufficient if the Champlain Hudson Power Express project experiences a significant delay, additional power plants become unavailable, or demand significantly exceeds current forecasts, according to the report.

Without the Champlain Hudson Power Express project in service or other offsetting changes or solutions, the reliability margins continue to be deficient for the report’s 10-year planning horizon, NYISO said. In addition, while Champlain Hudson Power Express is expected to contribute to reliability in the summer, it is not expected to provide any capacity in the winter.

Beginning in August 2023, NYISO said it plans to solicit market-based solutions to the reliability need that could include supply or demand-side solutions, such as generation, storage, and/or new participation in programs that aim to reduce demand.

In October and November 2023, after the solicitation window has closed, NYISO said it would evaluate the submitted proposals. If they are not viable or sufficient to meet the reliability need, interim solutions will need to be put in place, NYISO said.

One potential outcome could be relying on generators that are subject to the Peaker Rule to remain in operation until a permanent solution is in place, NYISO said.

In anticipation of such a scenario, the Peaker Rule authorized NYISO to designate certain units to remain in operation beyond 2025 on an as-needed basis for reliability.

Based on the findings its Short-Term Reliability Process, NYISO said it may designate certain units, in sufficient quantity, to remain in operation for an additional two years, until May 1, 2027, with the potential of an additional two-year extension to May 1, 2029, if a permanent solution has been selected but is not yet online.

NYISO said it would only temporarily retain peakers as a last-step approach if it does not expect solutions to be in place by the time the identified reliability need is expected in 2025.

PJM Met Demand Through December 2022 Event, but Extreme Cold Stressed Grid

July 18, 2023

by APPA News
July 18, 2023

The PJM Interconnection was able to maintain system reliability and serve customers throughout the extreme weather that affected the regional transmission organization from Dec. 23 through Dec. 25, 2022, according to a PJM report.

The Winter Storm Elliott Event Analysis and Recommendation Report noted that PJM operators were able to avoid electricity interruptions and even support its neighbors during certain periods, although the operators had to implement multiple emergency procedures and issue a public appeal to reduce energy use.

Winter Storm Elliott’s rapidly falling temperatures coincided with a holiday weekend that combined to produce unprecedented demand for December, which was further complicated by unexpectedly high resource unavailability and/or failures to perform, the report said.

On Dec. 23, the first day of the storm, the stress on PJM’s neighbors began to signal extreme conditions headed for the PJM region. The Southwest Power Pool set a new winter peak on that day. The Tennessee Valley Authority experienced the highest 24-hour electricity demand supplied in its history. PJM was able to export energy to TVA, Duke Carolinas and Duke Energy Progress before having to curtail most exports during peak conditions in the face of emergency conditions.

PJM’s forecast for Dec. 23 was about 127,000 megawatts, and load came in at about 136,000 MW, about 25,000 MW above a typical winter peak day. In preparation, PJM had approximately 158,000 MW of operating capacity plus available generation able to be called upon in real time and was able to meet load with the help of a Maximum Generation Action and Demand Response.

The next day, the coldest of the weekend, PJM said its operators decided to schedule conservatively in terms of reserves. PJM anticipated approximately 155,700 MW should have been available for Dec. 24, but complications arose from the unanticipated failure of generation resources that were called on that day. At one point, almost a quarter of the generation capacity, 47,000 MW, was on forced outages, the report said.

Across the entire PJM generation fleet, natural gas generators accounted for 70 percent of the outages on Dec. 24, most of them caused by equipment failure likely resulting from the extreme cold with broader issues of gas availability also contributing to the outages, the report said.

Winter Storm Elliott was the first wide-scale use of PJM’s Capacity Performance rules that were introduced in 2016 in the wake of the 2014 Polar Vortex. The high outage rates for generators during Winter Storm Elliott resulted in substantial Non-Performance Charges that are part of Capacity Performance rules.

PJM estimates there are approximately $1.8 billion in Non-Performance Charges based on the current rules, which call for the charges to be allocated to suppliers that exceeded their committed capacity level.

While PJM operators were able to keep electricity flowing in the region throughout the storm “Elliott also provides some clear lessons for PJM and its stakeholders that drive” the 30 recommendations contained in this report,” PJM said.

The recommendations are broadly focused on:

• Addressing winter risk with enhancements to market rules, accreditation, forecasting and modeling;
• Improving generator performance through winterization requirements, unit status reporting and testing/verification;
• Tackling long-standing gaps in gas-electric coordination, including timing mismatches between gas and electric markets, the liquidity of the gas market on weekends and holidays, and the alignment of the electricity market with gas-scheduling nomination cycles;
• Evaluating how the Performance Assessment Interval system of rewarding or penalizing generator performance is impacted by exports of electricity to other regions, whether excusal rules can be simplified, PAI triggers need to be refined, and if the contributions of Demand Response and Energy Efficiency are accurately valued;
• Pursuing opportunities with Generation Owners, other members and states to improve education, drilling and communication regarding PJM’s emergency procedures, Call for Conservation and PAIs.

PJM said many of the recommendations are being developed through the Critical Issue Fast Path–Resource Adequacy process or other forums, including the Electric Gas Coordination Senior Task Force, Operating Committee and Market Implementation Committee.

Southwest Power Pool Details Progress in Clearing Interconnection Study Backlog

July 13, 2023

by Paul Ciampoli
APPA News Director
July 13, 2023

The Southwest Power Pool on July 12 reported that it has reached the halfway point in clearing the backlog of requests to study the impacts of connecting new generating resources to the region’s power grid.

Over the last several years, overwhelming interest in building new generation – primarily from developers looking to construct wind and solar farms – led to longer than usual timelines in SPP’s study processes.

In response to record growth in its interconnection queue, over the last three years SPP said it has worked to make improvements to the quality of its study models and processes.

In January 2022, the Federal Energy Regulatory Commission approved tariff revisions designed to simplify and reduce SPP’s study timelines.

SPP said it has also taken steps to improve model accuracy, such as posting models and draft interconnection study results for review before the final results and using fuel-based dispatch: enhancing planning models so that they simulate the dispatch of generation more like SPP’s real-world, day-ahead market while identifying transmission needs resulting from the interconnection of new generators.

SPP’s “Definitive Interconnection System Impact Study” (DISIS) process utilizes a three-phase approach to evaluate the impact of the proposed generation to the transmission system and provides a report and decision point window for each phase.

Since the implementation of the backlog mitigation plan, SPP has completed five DISIS Phase One analyses and two Phase Two analyses. The remaining studies are currently on track to be completed by the end of 2024.

SPP said it has seen an exponential increase in installation rates over the last nine years adding a record amount of generation to the resource pool. Within that timeframe, an average of 2,800 MW of new wind generating capacity has been added to our region year over year.

“As a result of the success of the backlog mitigation plan, interconnection customers have executed agreements to add over 14.5 GW of new generation to the system over the next four years,” SPP said.

There are 561 active requests remaining in the SPP interconnection queue, of which approximately 220 of them were submitted in 2022. These requests represent 112 GW of new generation—108 GW of which are renewable, storage or hybrid resources.

To facilitate flexibility for generation requests, SPP has performed more than 27 modification studies to analyze generation changes due to technological advancements and supply chain issues. Several other studies have analyzed the replacement and optimization of existing granted interconnection service with new generation.

PJM Transition to New Interconnection Process Gets Underway

July 10, 2023

by Paul Ciampoli
APPA News Director
July 10, 2023

The transition to the PJM Interconnection’s new interconnection process kicked off on July 10, setting the stage for more than 260,000 megawatts of mostly renewable projects to be studied over the next three years, the grid operator said.

More than 95% of the projects requesting grid connection are renewables or batteries, or a hybrid of both, PJM noted.

Among other reforms, the process moves from a “first-come, first-served” queue approach to a “first-ready, first-served” cycle method. It includes decision points along the way at which the developers must submit readiness deposits and demonstrate site control or withdraw their projects. These requirements are expected to weed out the large number of speculative projects that have contributed to existing backlogs, PJM said.

 Starting on July 10, PJM opened a 60-day window for developers in transition to post the readiness requirements.

In September, PJM will update its models with those generators qualifying to enter the transition and begin processing projects with no or minimal system impacts that qualify for a “fast-lane” process.

PJM also created the new Queue Scope tool, which enables developers to better assess the engineering and financial impacts of a project at various locations on their own before they formally enter PJM’s interconnection queue. This should save them, particularly smaller developers, time and money and result in more viable projects to be studied by PJM.

The Federal Energy Regulatory Commission approved the interconnection process reforms on Nov. 29, 2022.

About 44,000 MW of projects have completed the PJM study process but have yet to move to construction, due to siting, financing, supply chain, or other issues. In 2023, less than 2,200 MW of projects have come online; in 2022, that number was 2,000 MW.

By the end of 2024, PJM expects to have cleared about 62,000 MW for connection, another 100,000 MW by the end of 2025, and an additional 100,000 MW by the end of 2026.

The PJM system’s current total capacity is about 184,000 MW.

Additional information and frequently asked questions about the transition to the new interconnection process can be found on the Interconnection Process Reform webpage.

Northeast Grid Operators Support Proposal by States to Enhance Transmission Planning

July 4, 2023

by Paul Ciampoli
APPA News Director
July 4, 2023

ISO New England, the PJM Interconnection, and the New York Independent System Operator have voiced support for a proposal from eight Northeast states to develop a new approach to the development of interregional transmission coordination.

Earlier this month, officials from the six New England states as well as New York and New Jersey asked for help from the Department of Energy to form a Northeast States Collaborative on Interregional Transmission.

The officials said the proposed partnership between DOE, the states, and the three affected regional transmission organizations could help “strengthen our power grid, drive down consumer costs, and accelerate the deployment of clean energy,” particularly offshore wind.

In a response, the three RTOs said they agreed they have a key part to play. Leaders of the RTOs sent a letter to Maria Robinson, Director of the DOE’s Grid Deployment Office on June 27.

The letter notes the three RTOs already share information and cooperate extensively around system planning studies and projects with cross-border impact.

“Offshore wind development is a key component of the larger reviews of interregional transfer capability across the Eastern Interconnection,” the executives wrote. “Accordingly, the NYISO, PJM, and ISO New England welcome the opportunity to leverage the expertise, tools, and processes we have in place to serve the work of a Northeast States Collaborative.”

JEA, Gainesville Regional Utilities, Others Begin Active Energy Trading on Platform

July 3, 2023

by Paul Ciampoli
APPA News Director
July 3, 2023

The Southeast Energy Exchange Market on June 28 said that Duke Energy Florida, JEA, Tampa Electric Company, and Gainesville Regional Utilities have initiated active energy trading, which now allows them to buy and sell power using the SEEM platform.

SEEM launched operations supporting enhanced energy trading in November 2022.

Duke Energy Florida, JEA and Tampa Electric Company joined as members of SEEM effective Jan. 1, 2023.

Gainesville Regional Utilities will be a non-member participant. JEA and Gainesville Regional Utilities are Florida public power utilities; Duke Energy Florida and Tampa Electric are investor-owned utilities.

Members have a seat on the SEEM Board and related committees and pay all operational, audit, administrative and legal expenses, which allows non-members to participate in SEEM at no cost.

During the first seven months of operation there have been more than 45,000 transactions representing more than 1 terawatt of power transacted across all Participants including transactions in 73% of all hours since market launch, SEEM said. 

The SEEM platform facilitates automated, sub-hourly trading, allowing participants to buy and sell power close to the time the energy is consumed, utilizing available unreserved transmission. Participation in SEEM is open to any entity that meets the qualifying requirements set forth in the SEEM Agreement.

The SEEM footprint includes 23 entities in parts of 12 states with more than 180,000 MW (summer capacity; winter capacity is nearly 200,000 MWs) across two time zones.

FERC Approves Final Rule Aimed at Improving Credit Risk Management in Wholesale Power Markets

June 15, 2023

by Paul Ciampoli
APPA News Director
June 15, 2023

The Federal Energy Regulatory Commission on June 15 approved a final rule designed to improve credit risk management in the organized wholesale electric power markets operated by regional transmission organizations and independent system operators.

The Commission’s final rule will allow RTOs and ISOs to share credit-related information among themselves so they can better assess market participants’ credit risks. 

The final rule explains that permitting the sharing of credit-related information among RTOs and ISOs could improve their ability to assess market participants’ credit exposure across multiple electric power markets.

It also could enable market operators to respond to credit events more quickly and effectively, thereby minimizing the overall risks of unexpected defaults by market participants.

The market operators’ tariffs currently contain confidentiality provisions that act as barriers to such information sharing. 

The final rule and a July 2022 Notice of Proposed Rulemaking “demonstrate the Commission’s commitment to ensuring that market rules minimize the overall risks of unexpected defaults by market participants and respond to concerns raised” at a February 2021, FERC staff technical conference on principles and best practices for credit risk management in organized wholesale electric markets, FERC said.

The final rule takes effect 60 days after publication in the Federal Register.

MMWEC, Public Power Entities Ask FERC to Force Disclosure on Charges

June 1, 2023

by Paul Ciampoli
APPA News Director
June 1, 2023

Massachusetts Municipal Wholesale Electric Company, leading a group of public power entities throughout New England, recently filed a motion at the Federal Energy Regulatory Commission asking that it force the disclosure of information “concerning the exorbitant charges being imposed on New England ratepayers under a fuel security cost-of-service agreement,” MMWEC said on May 22.

Joining MMWEC in the request are the Connecticut Municipal Electric Energy Cooperative, New Hampshire Electric Cooperative, Vermont Public Power Supply Authority, Energy New England, and a group of Massachusetts public power systems known collectively as the Eastern New England Consumer-Owned Systems.

In 2018, the region’s grid operator, ISO New England, executed a two-year agreement, which began June 1, 2022 and ends May 31, 2024, requiring the continued operation of Mystic Units 8 & 9, which are owned by Constellation Mystic Power, LLC. 

ISO-NE says that the units are needed to ensure regional “fuel security.” Mystic is paid under the agreement both its full cost of service and nearly all of the costs of Mystic’s affiliated liquefied natural gas fuel supplier, the Everett Marine Terminal.

MMWEC said the agreement protects customers against unreasonable fuel charges by requiring that ISO-NE audit Mystic’s fuel procurement practices. The audits are conducted to ensure that service under the agreement is being provided at the lowest possible cost.  

Over the first ten months of the two-year term of the Mystic agreement, consumers have been charged more than $436 million in fuel costs, most of which resulted from Constellation’s LNG purchases, and then selling at a loss, burning uneconomically, or otherwise disposing of fuel that it turns out Mystic did not need, MMWEC said in a news release.

“In the ten months since the Mystic agreement went into effect, the only document concerning the audits that ISO-NE has released is an uninformative, three-page summary of the conclusions of a consultant retained by the grid operator,” MMWEC said.

The consultant concludes that the charges are appropriate under the agreement, “but provides no insight into what MMWEC and the other public systems say is a key driver of the fuel-related charges: Mystic’s fuel purchasing decisions and the terms of its liquefied natural gas supply contracts.” 

The motion asks that FERC direct ISO-NE to release additional information concerning the variable charges passed through the agreement, including redacted copies of any reports, studies or other analyses produced by or for ISO-NE in connection with the audit.

In support of this request, the motion states that because of the paucity of data made public, neither FERC, the New England states, nor consumers have had the opportunity to assess what contributed to these charges and to determine if they are justified and reasonable. 

MMWEC and its supporters asked that FERC direct Mystic and ISO-NE to release data related to the excessive charges and continue to do so on a quarterly basis. 

The motion states that this information will help MMWEC and the public systems determine whether certain charges are warranted, whether there should be enhanced auditing, or if the agreement should be amended. 

MMWEC, joined by the New Hampshire Electric Cooperative, called FERC’s attention to the issue in a joint filing last December, in which they stated the charges had become much larger and more volatile than anticipated. 

Since that time, the charges have grown even larger, MMWEC said. In January and February 2023 alone, ISO-NE has passed on more than $220 million in charges under the agreement. The $120 million supplemental capacity payment to Mystic for January 2023 was more than a quarter of the value of the entire New England wholesale energy market for that month. 

The motion concludes by requesting that FERC direct Mystic and ISO-NE to release more robust and useful information about the basis “for the extraordinary charges and ISO-NE’s audit of them, as was promised during the 2018 proceeding in which Mystic and ISO persuaded FERC to approve the agreement.” 

MMWEC is a not-for-profit, public corporation and political subdivision of the Commonwealth of Massachusetts created by an Act of the General Court 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.