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Lawmakers Ask FERC Commissioners to Respond to Questions on Grid Reliability

May 3, 2023

by Paul Ciampoli
APPA News Director
May 3, 2023

House Energy and Commerce Committee Chair Cathy McMorris Rodgers (R-WA) and Energy, Climate and Grid Security Subcommittee Chair Jeff Duncan (R-SC) recently sent a letter to Federal Energy Regulatory Commission Commissioners asking the agency to respond to a series of questions related to grid reliability.

The lawmakers asked FERC Commissioners to comment on whether they believe the current Regional Transmission Organizations or Independent System Operators are the best mechanism to provide reliable electricity.

The Commissioners were also asked whether they think current market rules allow dispatchable, on-demand generation resources the opportunity to recover sufficient revenues to continue to operate in the RTOs/ISOs? “If so, which rules? If not, would you recommend FERC direct RTOs/ISOs to implement such rules?”

The letter also included the following questions:

The chairmen asked that FERC respond by May 10, 2023.

New England Grid Operator Sees Demand on Grid Increasing by About 23% Over Next Decade

May 2, 2023

by Paul Ciampoli
APPA News Director
May 2, 2023

ISO New England projects demand on the region’s power grid will increase by about 23% over the next decade due to accelerating electrification of the heating and transportation sectors.

The findings were published in the 2023–2032 Forecast Report of Capacity, Energy, Loads, and Transmission (CELT Report), a primary source for assumptions used in the ISO’s system planning and reliability studies.

The report provides a snapshot of the New England power system, including:

ISO New England said that gross annual electricity use is expected to grow by 2.4% annually over the 10-year period, while net annual use is expected to grow by 2.3% annually.

Energy efficiency is projected to reduce grid demand by 11,582 GWh this year and 12,810 GWh in 2032, while behind the meter PV is projected to reduce grid demand by 4,442 GWh this year, rising to 8,168 GWh in 2032.

EVs are expected to account for 13,961 GWh of grid demand in 2032, while heating electrification is expected to account for 7,334 GWh of demand that year.

Under typical summer weather conditions, gross peak demand is expected to rise annually at a rate of 1.2%. Net peak demand is expected to rise at an annual rate of 1.1%. For weather that is hotter than average, the gross peak is expected to rise 1.1% annually and the net peak 1.0%.

The net forecast includes summer peak demand reductions from behind the meter PV of 981 MW this year, rising to 1,117 MW in summer 2032.

Energy efficiency is expected to reduce summer peak demand by 1,969 MW this year, and by 2,436 MW in 2032, while transportation electrification is expected to contribute 2,346 MW to summer peak demand in 2032.

Public Power Utilities Recognized for Outstanding Safety Practices

May 2, 2023

by Paul Ciampoli
APPA News Director
May 2, 2023

One hundred sixty-six utilities have earned the American Public Power Association’s Safety Award of Excellence for safe operating practices in 2022.

APPA said that 283 utilities from across the country entered the annual Safety Awards. Entrants were placed in categories according to their number of worker-hours and ranked based on the incident-free records and overall state of their safety programs and culture during 2022.

A utility’s incidence rate is based on its number of work-related reportable injuries or illnesses and the number of worker-hours during 2022, as defined by the Occupational Safety and Health Administration.

“Safety needs to be the first thing on every utility employee’s mind as they go about their work, said Jim Boyd, Chair of APPA’s Safety Committee and Electric Operations Safety Manager at Tacoma Power in Washington. “The utilities honored by APPA for excellence in this area should be proud of the culture they have instilled in serving their communities.”

The Safety Awards have been held annually for more than 65 years. A complete list of winners is available at www.PublicPower.org.

Legislation Would Shift the Southwestern Power Administration to a Self-Financing Model

May 2, 2023

by Paul Ciampoli
APPA News Director
May 2, 2023

Senators Jerry Moran (R-KS) and Roger Marshall (R-KS) on April 28 introduced a bill that would move the Southwestern Power Administration to a self-financing model.

The bill, S. 1324, the Southwestern Power Administration Fund Establishment Act, would address the long-term shortfall SWPA faces in receiving funding authority for purchase power and wheeling needs used to plan for and respond to drought, as well as to support long term capital investments for hydropower assets.

The bill Southwestern Power Administration Fund Establishment Act would give the SWPA the authority to operate on a self-funding, revolving Treasury fund to help provide long-term stability to SWPA.

“This would give the SWPA more stable funding in order to lower customer rates, which can be highly volatile due to market demand and weather,” the lawmakers said in a news release.

“Furthermore, this legislation would provide SWPA more clarity to help plan long-term infrastructure improvements and power replacement. This bill will also allow SWPA to avoid drastic and unnecessary spikes in power rates charged to its wholesale customers in an extreme or multi-year regional drought situation,” they said.

The SWPA customer group, Southwestern Power Resources Association, supports this legislation, as does the American Public Power Association.

SWPA is one of four Power Marketing Administrations in the U.S. Its service territory includes Arkansas, Kansas, Louisiana, Missouri, Oklahoma and Texas.

Predictive Software Could Help Integrate Renewables, Reduce Need for Storage

May 2, 2023

by Peter Maloney
APPA News
May 2, 2023

Predictive software could reduce the amount of energy storage needed to transition to a economy that includes growth in renewable energy, according to a new study from the National Renewable Energy Laboratory.

The study, Shifting Demand: Reduction in Necessary Storage Capacity Through Tracking of Renewable Energy Generation, proposes an alternative approach to bridging the mismatch between peak demand and peak generation in an electric system that is increasingly relying on intermittent sources of generation, such as wind and solar power.

One solution to that problem is to store peak generation and dispatch it during times of peak demand using utility scale battery energy storage systems but, as an alternative, the study’s authors analyzed a means of shifting demand by using a forecast-aided predictive control algorithm.

While battery energy storage systems can improve dispatchability, the study’s authors noted that the technology has “several challenges,” including inadequate safety validation, degradation of the batteries and “most crucial,” cost of the systems. “Due to these challenges, it may be beneficial to limit the total BESS capacity required for deployment,” the authors wrote.

Alternatively, the use of forecast-aided predictive control can shift demand “considerably to more closely track” a renewable energy signal, the study found. “This significantly reduces the size of the required utility-scale BESS,” the authors said.

The study analyzed a forecast-aided predictive control algorithm that is used to autonomously control both electric vehicle charging stations and the heating, ventilation, and air conditioning systems in buildings.

Electric vehicles and hybrid electric vehicles, along with heating and cooling systems for buildings, already account for roughly 10 and 40 percent of electric demand, respectively, and both are poised to increase with calls to decarbonize the economy. So, shifting demand for electric vehicles and buildings is “imperative” and provided the framework for the study, the authors said.

“We have an idea of how many people will be in the building, and then from there we can get an estimate of how many electric vehicles will be arriving at the charging station,” Dylan Wald, a graduate intern at the National Renewable Energy Laboratory, a Ph.D. student and lead author of the study, said in a statement. “Everything is intertwined, and we can leverage this interconnectedness.”

The study on forecast-aided predictive control was based on research the National Renewable Energy Laboratory did last year that showed electric vehicle charging and buildings can work together to provide services to the grid. The improved algorithm took that work a step further by including forecasts to improve real-time tracking ability by taking into account how much wind and solar power will be generated, as well as the temperature and time of day and week in order to estimate the energy demand for a building and charging stations, the study’s authors said.

The analysis indicated that under days of more intermittent renewable generation, forecast-aided predictive control performed adequately, however, the performance of the algorithm decreased during weekends when demand is less significant and less flexible. The analysis also found that the forecast-aided predictive control performance is sensitive to the accuracy of the forecasts incorporated in the algorithm.

“This work is showing us you don’t always need such a big battery,” Jennifer King, a research engineer at the National Renewable Energy Laboratory and co-author of the study, said in a statement. “You likely still need a smaller battery.”

“That’s a huge implication because we may run into supply chain issues with batteries needed for the grid or for EV charging. We need a different solution,” King said.

First Solar-Plus-Storage Project by a Municipality on Long Island is Completed

May 2, 2023

by Paul Ciampoli
APPA News Director
May 2, 2023

New York Gov. Kathy Hochul on April 20 announced the completion of the first solar-plus-storage project by a municipality on Long Island, now operating in the Town of East Hampton.

The rooftop array makes the Parks Department building at the Town Hall campus the first building in the town to achieve the goal of net zero carbon emissions from electricity generation. The project, developed with the New York Power Authority, supports New York State’s goal to procure 70 percent of its electricity from renewable energy by 2030, and the Town of East Hampton’s goal of community-wide renewable energy only in all sectors, also by 2030.

The 165-panel system is tied directly into the Long Island Power Authority’s distribution grid and will provide about 90 megawatt hours of energy annually.

The 75-kilowatt solar PV system will generate renewable energy and charge a 137-kilowatt hour battery. It is expected that 100 percent of the energy costs of the building will be offset with credits from the energy produced by the solar PV system. Any additional energy credits will be allocated to another building on the Town Hall campus.

The town, in collaboration with the Power Authority, selected New York-based Solar Liberty and its financing partner on the project, Inclusive Prosperity Capital, through a competitive process to develop the solar-plus-battery storage system. 

The solar PV system will be financed through a 20-year power purchase agreement with Inclusive Prosperity Capital, with no upfront costs to the town. A PPA also enables the Town to benefit from cost offsets provided by tax credits. 

The battery was added at no cost to the town through grant support from NYPA.

NYPA recommended the system’s installation as part of East Hampton’s ongoing efforts to move toward a 100 percent renewable energy goal. NYPA Distributed Energy Resource Advisory Services assisted as advisor throughout implementation.

The New York State Energy Research and Development Authority has committed nearly $35,000 to the project through its Retail Energy Storage Program, which provides funding to commercial customers for standalone, grid-connected energy storage or systems paired with a new or existing clean on-site generation like solar.

LIPA and Energy Storage

For its part, LIPA has also pursued energy storage. LIPA previously installed a 10 megawatt storage project and in 2021 PSEG Long Island issued a request for proposals on behalf of LIPA for bulk energy storage.

Lubbock Power & Light Lowers Electric Rate Heading Into Summer

May 1, 2023

by Paul Ciampoli
APPA News Director
May 1, 2023

Texas public power utility Lubbock Power & Light is lowering the power cost recovery factor portion of its electric rate for the summer.

The summer 2023 rate for a residential customer is an 18.7% rate decrease as compared to the current winter rate, resulting in substantial savings for all customers throughout the hottest months of the year when electricity use is at its highest, it said.

The PCRF is the amount LP&L pays to purchase or generate power, passed directly through to customers with no mark-up.

During an April board meeting, the LP&L Electric Utility Board voted unanimously to implement the electric utility staff’s recommendation for a rate decrease. The reduced rate is effective for all residential and commercial customers May 1 through September 30, 2023.

“LP&L is committed to providing our customers with safe, affordable and reliable power in our last summer as a power provider,” said Joel Ivy, director of electric utilities. “We’re thankful we are in a position to pass on savings to our customers when they need it most.”

The rate reduction is possible due to LP&L negotiating lower wholesale power costs in current power contracts and low natural gas prices.

Public Power Utilities Earn Reliable Public Power Provider Designation from APPA

May 1, 2023

by APPA News
May 1, 2023

One hundred nine of the nation’s more than 2,000 public power utilities earned the Reliable Public Power Provider designation from the American Public Power Association for providing reliable and safe electric service.

The RP3 designation, which lasts for three years, recognizes public power utilities that demonstrate proficiency in four key disciplines: reliability, safety, workforce development, and system improvement. Criteria include sound business practices and a utility-wide commitment to safe and reliable delivery of electricity.

This year, 109 utilities earned the designation, and a total of 271 public power utilities nationwide hold the RP3 designation. 

“Receiving an RP3 designation is a great honor signifying a utility has demonstrated commitment to industry best practices,” said Troy Adams, Chair of APPA’s RP3 Review Panel and General Manager at Manitowoc Public Utilities, Wisconsin. “And ultimately, the culture developed from this pursuit of excellence and continued improvement through the RP3 program results in measurable value delivered to the local community.”  

This is the eighteenth year that RP3 recognition has been offered. A full list of designees is available on the APPA website.

Calif. Public Power Leaders Say New Rule Threatens Ability of Utilities to Respond to Emergencies

May 1, 2023

by Paul Ciampoli
APPA News Director
May 1, 2023

A rule recently approved by the California Air Resources Board that is designed to transition all medium- and heavy-duty vehicles in the state to electric or hydrogen-powered vehicles includes “a major flaw that could risk longer water and electric outages during emergencies,” leaders of the California Municipal Utilities Association, the Southern California Public Power Authority and the Northern California Power Agency said.

At issue is the Advanced Clean Fleets rule, which was approved by CARB on April 28. The rule requires most California fleets to begin purchasing zero-emission medium- and heavy-duty vehicles in 2024. Beginning January 1, 2024, 50% of medium- and heavy-duty vehicles purchased by publicly owned electric utilities and public water and wastewater agencies must be zero-emission. Starting January 1, 2027, all medium- and heavy-duty vehicles purchased by public agencies must be zero-emission. The rule stems from an Executive Order issued by Governor Newsom in 2020 that, among other things, also initiated California’s approach to banning the sale of gasoline powered by cars by 2035.

In an Op-Ed completed prior to the rule’s approval, Barry Moline, Executive Director, California Municipal Utilities Association, Michael Webster, Executive Director, Southern California Public Power Authority and Randy Howard, General Manager, Northern California Power Agency, acknowledged that overall the rule is essential to achieve California’s environmental goal of a carbon-neutral economy by 2045.

“But the proposed rule’s major concern is that it may hinder many local utilities’ ability to respond to emergencies, natural disasters, and significant service disruptions. Customers and communities served by local governments that own and operate their own water, wastewater, and electric utilities will be at risk,” wrote Moline, Webster and Howard.

The heavy specialty vehicles that utility crews use daily reach power lines; clear debris; transport, remove, and set utility poles; move and set critical water infrastructure; and provide water purification for communities, they pointed out. “During emergencies, this important work is often done under challenging conditions and in rural, isolated locations.”

But these specialty utility vehicles are not widely available in electric or hydrogen models. “That likely will continue to be the case for the next several years — a period when the ACF rule will require California utilities to purchase and utilize zero-emission vehicles. While these vehicles account for only a small number statewide, they play an outsize role in safely maintaining and restoring the electrical grid and water infrastructure,” Moline, Webster and Howard said.

They emphasized the point that publicly owned utilities do not want an exemption to the rule, noting that generally, public water, wastewater, and electric utilities support purchasing zero-emission vehicles wherever feasible.

“But given the stakes — and risks to public health and safety — the rule must be amended to provide reasonable, practical accommodations when a zero-emission vehicle cannot do the same emergency work as a traditional utility vehicle. This prudent amendment would help protect local communities statewide that serve Californians,” the Op-Ed said.

“We must also recognize the reality that vehicles powered by hydrogen — not electric — are better suited for the work of many utility vehicles. It is paradoxical to rely on an electric vehicle to restore power when there is no electricity to keep the vehicle charged.”

Hydrogen vehicles, on the other hand, “are not dependent on the grid and can be refueled quickly in the field, allowing a utility crew to operate around the clock while repairing damaged infrastructure. The widespread deployment of hydrogen vehicles is, however, on a slower timeline than electric vehicles.”

The federal government “is providing billions of dollars to build hydrogen hubs across the country, which should help expand the hydrogen vehicle industry. Until then, utilities need the flexibility to purchase traditional vehicles when a zero-emission vehicle is unavailable or cannot meet emergency response needs,” Moline, Webster and Howard said.

They said that CARB must take these emergency response concerns seriously and amend the Advanced Clean Fleets rule “to accommodate the essential work of publicly owned electric and water utilities.”

In early April, the three groups submitted a detailed letter requesting specific changes to the regulation. Among other things, the groups asked CARB to open a subsequent Advanced Clean Fleets implementation rulemaking following adoption of the rule, so that concerns detailed in the letter can be addressed.

Meanwhile, there is at least one bill under consideration by California lawmakers that is intended to give utility fleets the flexibility that CMUA believes is needed, noted Matt Williams, Communications Director for CMUA.

Rising Costs for Projects Withdrawn from SPP Interconnection Queue: Report

May 1, 2023

by Peter Maloney
APPA News
May 1, 2023

Average interconnection costs for the Southwest Power Pool are stable for projects that complete all interconnection studies but have escalated sharply for projects that withdraw from the queue, according to a report from Lawrence Berkeley National Laboratory.

The report, Generator Interconnection Cost Analysis in the Southwest Power Pool (SPP) Territory, found that the interconnection costs for projects completed in the 2020-2022 timeframe were largely unchanged at $57 per kilowatt, from completed projects in the 2002-2009 timeframe at $54 per kilowatt.

Projects that withdrew from the interconnection queue, however, saw large cost escalations in the 2010s, from $22 per kilowatt in the 2000s to $247 per kilowatt in the 2010s and $304 per kilowatt in the early 2020s.

Projects still moving through the queue had an average cost of $106 per kilowatt in 2020-2023.

Average costs for withdrawn projects are now five times the costs of completed projects, likely a key driver for those withdrawals, the Berkeley Lab researchers said in the report. They also noted that project-specific interconnection costs in the Southwest Power Pool differ widely due to many factors and do not have the shape of a normal distribution.

The Southwest Power Pool’s queue has ballooned over the past decade, the Berkeley researchers said, noting that the cumulative active queue is now more than five times larger than in 2013, with 2022 additions being nearly three times the size of 2021 requests.

At year-end 2022, the Southwest Power Pool had 109 gigawatts of generation and storage capacity actively seeking grid interconnection, a level of capacity more than twice as large as the power pool’s roughly 51-gigawatt peak load in recent years.

Almost all, more than 96 percent, of the capacity in the Southwest Power Pool’s queue is clean energy, including solar and solar hybrids at 51 gigawatts, wind at 35 gigawatts, and standalone storage at 13 gigawatts.

Broader network upgrade costs are the primary driver of recent cost increases, especially for withdrawn projects, the Berkeley researchers found. No costs for upgrades beyond the interconnecting substation were reported in the 2000s, but they have recently increased on average to $23 per kilowatt in the 2020s. For withdrawn projects, network costs grew sharply in the 2010s to $180 per kilowatt and continued to climb for some projects in the 2020s, to $230 per kilowatt.

The report also found that a very small subset of generators seeking interconnection in the Southwest Power Pool face lower network upgrade costs by choosing interconnection services as an energy instead of a capacity resource. However, those project owners of energy resources forfeit preferential treatment during high load hours, cannot participate in the Southwest Power Pool’s resource adequacy market, and may face increased curtailment, the researchers said.

SPP initiated interconnection process reforms in 2009, transitioning to a clustered, “first-ready, first-served” approach and increasing project deposits and readiness criteria; despite these and other reforms, some of which are ongoing, SPP’s active queue interconnection wait times have increased steadily, with the typical project taking nearly six years to reach commercial operations in 2022, the report found.

Another recent report from Lawrence Berkeley said requests to connect clean energy projects to the grid have soared in recent years, leading to longer wait times and backlogs for project developers.

The Southwest Power Pool report is the fourth in a series analyzing interconnection costs in wholesale electricity markets, with prior studies analyzing the Midcontinent Independent System Operator, the PJM Interconnection, and the New York Independent System Operator.

Berkeley Lab is working on a forthcoming study that will analyze ISO New England’s interconnection queue.