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November 19, 2024

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RMI Report: GETs Could Speed Renewable Development, Save Consumers Billions

An RMI study into the applicability of grid-enhancing technologies (GETs) on the PJM grid found they could save consumers hundreds of millions of dollars a year and speed renewable development when used as an alternative to reconductoring and rebuilding lines. 

“With growing demand for electricity to power our lives and an influx of clean energy projects under development, the U.S. grid needs to expand, fast. Grid-enhancing technologies can be deployed in a matter of months and offer a multifaceted solution — they unlock greater efficiency on the grid, keep electricity rates down and enhance reliability throughout the energy transition,” Katie Siegner, RMI electric sector expert, said in an announcement of the study. The study was funded by Amazon and included analysis by Quanta Technology. 

The study, released Feb. 15, looked at how dynamic line ratings (DLRs), topology optimization (TO) and advanced power flow controls (PFCs) could be used in the analysis PJM conducts to determine network upgrades required for generation interconnection requests. It modeled the feasibility of using the technologies for projects in the PJM interconnection queue and compared costs to reconductor or rebuild lines to GET alternatives. 

Some of the greatest cost-saving potential came from PFCs, which modulate the reactance on a line to redirect power from congested lines to those with available capacity. The study identified 69 transmission overloads that could be addressed by flow controllers, with the potential to reduce interconnection costs for associated projects by $523 million over reconductoring or rebuilding lines. PFCs are limited to circumstances where there would be multiple paths for power to flow and are best suited for transmission under 550 kV. 

The study found DLRs were applicable to 49 overloads and could reduce costs by $504.5 million by increasing line ratings under favorable conditions. The technology uses sensors and existing data about installed infrastructure to change line ratings based on how factors such as wind speed, air temperatures and conductor sag can affect the amount of power a line can handle before overheating. Although overall summer line capacity could be increased by 17% over current static ratings, the study acknowledges dynamic ratings vary with the weather and therefore are more suited to making energy deliverable than bringing new capacity online. 

Topology optimization could reduce the cost to alleviate 72 overloads by $273 million by using software to determine alternate grid configurations that reroute power around constraints, such as opening or closing breakers automatically. 

The report states GETs can significantly reduce the amount of time to make the necessary grid adjustments to bring new generation online, addressing concerns PJM has raised about the balance of deactivations and new resource entry, as well as reducing energy costs by speeding development of low-cost renewables. It estimates ratepayers could save $1.1 billion in annual production costs by 2033 against a $0.1 billion installation cost for GETs. 

“These findings make a compelling case for more widespread deployment of GETs in PJM, where today there are only a handful of pilots and proposed projects. PJM and its stakeholders have an opportunity to spur broader uptake of these technologies by leveraging the growing proof points, modeling tools and changing regulatory landscape that are driving GETs adoption,” the study said. 

It calls for PJM and utilities to train staff in GET deployment and for regulators to draft new guidance and oversight for their usage, arguing adoption in the U.S. is behind Europe due to a lack of understanding and few incentives to seek cheaper transmission options. Generation developers also can benefit from evaluating GETs as an alternative to PJM’s recommended network upgrades for their projects. 

There have been some inroads for DLR usage in PJM, in which a pilot program to install the technology on PPL’s Juniata-Cumberland line resulted in line capacity increasing 18% under normal conditions and 10% under emergency conditions, Joseph Lookup, PJM’s director of asset management, told RTO Insider last year. (See Grid-enhancing Technologies Poised for Growth with Federal Funds.) 

Speaking in the announcement of the study, Alexina Jackson, AES vice president of strategic development, said it presents an opportunity for greater understanding of how new technologies can benefit the grid. 

“There are numerous market-ready technologies that can optimize our electrical grid and accelerate the future our customers need. Realizing how to model the functionality and quantify the benefits of these technologies is a barrier to the implementation of grid-enhancing technologies,” she said. 

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Fossil Retirements to Slow Briefly as Solar and Storage Proliferate

The U.S. Energy Information Administration reports that fossil fuel generation retirements will slow in 2024 and that solar and storage will dominate capacity additions. 

The two forecasts represent a pause and an acceleration, respectively, of recent trends. 

EIA said Feb. 20 that operators plan to retire 5.2 GW of capacity this year, most of it coal- or natural gas-burning plants. Coal retirements alone totaled 22.3 GW in the past two years and are expected to total 10.9 GW in 2025. 

EIA said Feb. 15 that developers and power plant owners plan to add 62.8 GW of new utility-scale capacity in 2024. Almost all scheduled additions are emissions-free power sources, including a record 36.4 GW of solar. That would nearly double the 2023 total of 18.4 of new solar, which itself was a record. 

Retirements 

Fossil fuel generation has been retiring rapidly, so much so that some grid operators have begun issuing warnings about potential capacity shortfalls. (See NYISO to Keep Gas Peakers Online to Solve NYC Reliability Need and PJM Requests 2nd Talen Generator Delay Retirement.) 

The 5.2 GW scheduled for retirement in 2024 would be the least since 2008 and would be down 62% from 2023, when 13.5 GW was retired. Forecast for retirement in 2024 are plants totaling 2.4 GW of natural gas, 2.3 GW of coal, 450 MW of petroleum and 20 MW of other power sources. 

The largest gas retirement will be the last six units (1,413 MW) at the Mystic Generating Station outside Boston, one of the nation’s oldest power plants. The other large gas retirement scheduled is TVA’s Johnsonville station (754 MW). 

The largest coal retirements will be Seminole Electric Cooperative’s Unit 1 in Florida and Homer City Generating Station’s Unit 1 in Pennsylvania, both 626 MW. 

Almost all of the petroleum-fired capacity retirement will be at TVA’s Allen plant, which has 20 old combustion turbine units totaling 427 MW. 

Construction 

EIA forecasts heavy growth in renewable energy development in 2024 — particularly in photovoltaics, which is outstripping other generating resources as supply chain challenges and trade restrictions ease. 

The planned additions break down to 36.4 GW of solar, 14.3 GW of battery storage, 8.2 GW of wind, 2.5 GW of natural gas and 1.1 GW of nuclear, plus about 200 MW from other sources. 

Slightly more than half the nation’s 2024 utility-scale solar construction is planned in three states: Texas (35%), California (10%) and Florida (6%). Elsewhere, the nation’s largest single solar project — the Gemini facility in Nevada, with 690 MW of solar capacity and 380 MW of battery storage — will start to come online this year. 

Battery construction also could set a record: 14.3 GW of grid-scale storage capacity added in 2024 would nearly double the installed capacity nationwide, which stood at 15.5 GW at the start of this year. The heaviest battery development is expected to be in the states with the heaviest solar development: Texas (6.4 GW) and California (5.2 GW). 

Wind energy is the outlier in the report. Wind capacity addition has slowed after record construction of 14 GW-plus in both 2020 and 2021. The big news in U.S. wind energy in 2024 is likely to be the Vineyard Wind (800 MW) and South Fork Wind (130 MW) projects, the nation’s first utility-scale offshore wind farms. Both are nearing completion off the Northeast coast. 

The 2.5 GW of natural gas additions planned in 2024 is the lowest total in a quarter-century. Also notable: 79% of the gas capacity added in 2024 will be simple-cycle turbines, which can start up and ramp up or down relatively quickly to support the grid at times of fluctuating demand or faltering supply from wind and solar generation. This will be the first year since 2001 the slower but more efficient combined-cycle turbine technology did not account for most capacity additions. 

EIA forecasts a relatively small amount of fossil fuel generation retirements in 2024. | EIA

Finally, start-up of the fourth reactor at the Vogtle nuclear plant in Georgia, originally scheduled for 2023, now is slated for 2024. 

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NJ Launches Electric School Bus Program With Bidirectional Incentives

New Jersey is encouraging school districts to consider “bidirectional” charging systems that use electric school buses for energy storage under the state’s new $45 million three-year pilot program to put electric school buses in 18 school districts. 

The Legislature in December approved funding for the electric school bus program, 18 months after Gov. Phil Murphy (D) signed legislation enacting the pilot. The state Department of Environmental Protection (DEP) opened the program application process Feb. 1 and in recent weeks has held three webinars to guide potential participants through the application process. The deadline for applications is May 17. (See: New Jersey Senate Advances Electric School Bus Pilot Program.) 

The last webinar Feb. 14 provided a deep dive on bidirectional charging, outlining the benefits and incentives available for vendors and school districts that draw on bus batteries to power school buildings at certain times of day. 

New Jersey does not allow electric buses to send electricity directly to the grid. But the program offers up to $50,000 in additional support for projects that use a “vehicle-to-building” (V2B) strategy. According to the project solicitation guidelines, these incentives are “intended to both encourage projects which increase electric grid resilience and to add value to electric school bus investments.” 

Speaking at the Feb. 14 webinar, Gilbert Botham, a senior economic advisor for the DEP, said using buses as storage would enable the districts to cut the cost of powering its buildings. Districts could charge the bus batteries during cheaper overnight hours and use the power during the late afternoon or evening, when the building otherwise would be drawing electricity from the grid at higher rates, he said. 

“Your electricity bill from the utility should go down due to the decreased demand” in power from the grid because the bus battery is meeting the need, he said. After dropping off the final students in the afternoon, the electric bus may be at 30% charge, he said, adding that “you can use that last 30% to arbitrage down to zero and then charge overnight on cheap electricity.” 

Studies show electricity usage peaks in Northeastern states about 6 p.m. and drops off dramatically by midnight. 

“In the case of an emergency, you can actually use your electric school bus. It’s a giant rolling battery,” Phillip Burgoyne-Allen, an associate with the electric school bus initiative at the World Resources Institute (WRI), said at the DEP’s first hearing Feb. 1. 

“If there’s a large power outage for an extended period of time, you can use that bus battery to help charge a gymnasium or cafeteria or some other emergency shelter,” he said. 

Feasibility Testing

School districts, or vendors working with them, can apply under New Jersey’s program for financial support to lease or buy between two and 24 new electric buses ― either a 44-seat C-type bus or 70-seat D-type bus ― with a range of at least 90 miles. Applicants could receive $270,000 for a bus purchase and accompanying Level 2 charging station installation, and $290,000 for a bus and direct current fast charger (DCFC), with an additional subsidy of $30,000 if the district is in an overburdened community. 

The program incentive rises to $320,000 for a bus purchase and an accompanying bidirectional charging system that is capable not only of charging the bus but of sending electricity in the other direction so the bus effectively can be used as a storage facility. 

A single entity can apply for funding for 16 buses under the main program, and another eight buses under the bidirectional charging pilot. 

Projects that are funded as bidirectional pilots must use the technology at least six days a year. These are defined in the program guidelines as “uptime days” in which the electric bus is plugged into the charging station by, at latest, 5 p.m. with bidirectional functionality enabled until midnight of that calendar day. 

The school district can receive additional incentives if the bus is available for uptime days beyond the six required, with $5,000 awarded for two additional days in the first year of the program, $5,000 awarded for four additional days in the second year and $10,000 for an additional six days in the third year. 

School buses are particularly attractive for such a strategy due to the lengthy summer holidays and spring and winter breaks in which they often sit idle. 

Botham said the incentive structure is designed to give the DEP insight into the usefulness of bus batteries as storage. 

“We have to make sure that we get data from these buses,” he said. “That is one of the biggest things … that we are really wanting to understand: Is this possible? How is this possible? And what data can we derive from this to help the state understand the feasibility of this technology?” 

If the project demonstrates the feasibility of using electric school buses as storage, the state could consider “a second phase of the program which would demonstrate the feasibility of selling electricity from the bus back to the grid during peak demand, creating a fully integrated bidirectional system,” according to the current program guidelines. However, that kind of expansion would require regulatory approval. 

Rapid Impact

The opening of the pilot program follows years of planning, during which environmentalists have argued New Jersey is behind where it needs to be in terms of introducing electric buses, and creating a pilot ― rather than a program ― for electric buses will just delay the state further. (See New Jersey Legislators Back $45 Million EV Bus Bill.) 

According to the most recent figures from WRI, the nationwide count for electric school buses as of June 2023 was 2,277 vehicles ordered, delivered or in operation. 

The corresponding figure for New Jersey is 21 electric school buses ordered, delivered, or in operation, spread across six school districts, Burgoyne-Allen said. School districts have committed to buying another 200 electric buses, and funding of about $20 million has been allocated to electric school bus purchases, he said. 

Electric buses still cost at least three times the $110,000 to $125,000 price of a diesel bus, but WRI, a research and data organization that advocates for electric school bus use, expects the cost of electric buses to decline, especially the battery cost, Burgoyne-Allen said. 

“We anticipate that as the technology improves, as the pricing improves, that these buses are going to be even more competitive with diesel buses on a pricing front,” he said. 

Still, he added, even if a school district gets incentives that cover 90% or 95% of the cost of an electric bus, “coming up with the 5 or 10% can be a challenge.” 

New Jersey’s program allows the state funding to be combined with federal tax credits, which can reach $40,000 for eligible vehicles, the DEP said. 

WRI also is seeing a reduction in the delays that have characterized some school bus purchases in the past, with the wait from order to delivery stretching out a year or 15 months, Burgoyne-Allen said. 

“There have been a lot of supply chain issues,” he said. “But we’re seeing those increasingly get sorted out. We’re seeing manufacturers increasing their production capacity on electric school buses and opening new factories and expanding factories so that they can bring these buses to the road on a faster pace.” 

Once deployed on school routes, the buses can make a rapid impact, Tim Farquer, superintendent of Williamsfield Schools in Illinois, said at New Jersey’s Feb. 1 webinar. His district has operated five school routes with electric buses since November. Over about 23,000 miles of operation, the district has used 21,000 kW of electricity and spent about $500 in fuel costs. Adding power from a district solar array, final costs are well below the $14,000 that would have spent on diesel, Farquer said.  

“We’re getting better numbers than we anticipated,” he said. “We’re just burning a little over one kWh of electricity per mile traveled.” 

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Berkeley Lab Reports Narrowing Income Gap on Residential Solar

The 2023 edition of a federal rooftop solar demographic report finds the median household income of people installing solar systems has decreased but is still well above the median American household income. 

The Clean Energy States Alliance held a webinar Feb. 15 to discuss the data in the report, which is designed as a reference for policy makers and industry stakeholders. 

The Lawrence Berkeley National Laboratory’s “Residential Solar-Adopter Income and Demographic Trends: 2023” is based on address-level data for 3.4 million residential solar systems installed through 2022, covering about 86% of residential systems. 

Key takeaway points from the report:
 

    • The documented income disparities are due in part to the rooftop solar industry concentrating on high-income states. 
    • Residential solar adopters are diverse, but many share a few common traits — they own a single-unit residence, occupy a higher income bracket, hold jobs in the business or finance sector, are middle aged and do not reside in a disadvantaged community. 
    • The differences between solar- and non-solar households are diminishing gradually as the industry reduces prices and expands into lower-income states and disadvantaged communities. The emergence of policies and business models that support broader adoption also helps. 

Researchers found that Americans installing rooftop solar systems most often have higher incomes and own a single-family house. | Lawrence Berkeley National Laboratory

Report co-authors Galen Barbose, Sydney Forrester and Eric O’Shaughnessy explained some of the findings during the webinar. 

Barbose said the income gap between solar and non-solar is not as wide as it initially seems. 

Median household income of solar adopters in 2022 was $117,000, compared with just $69,000 for all U.S. households. 

But the median income was $86,000 for U.S. households that occupy housing they own, which is a better metric, because 94% of rooftop solar installations were on single-family owner-occupied homes. 

Finally, the average owner-occupied income rises to $98,000 nationally once weighted for the number of solar installations in each state. 

That’s not to say everyone with a solar panel on their roof earns a lot of money: In 2022, 43% of solar adopters had household incomes less than $100,000 and 12% reported incomes of less than $50,000. 

“The main takeaway here is that solar adopters come from all parts of the income spectrum,” Barbose said. 

“When thinking about these trends, we like to distinguish between two underlying dynamics that are at play: a broadening of solar markets as solar adoption expands into new parts of the country, as well as a deepening, where even within established markets, we see solar increasingly reaching less affluent households within the region.” 

Median income for solar households dropped from $140,000 in 2010 to $117,000 in 2022. Over the same period, the percentage of rooftop solar adopters living in designated disadvantaged communities doubled from 11% to 22%. 

One shortcoming of the data is that it cites mid-2023 income, rather than income at the time the solar panels were installed. It also does not account for ownership transfer: Some residents of solar-equipped houses bought those houses well after the panels were installed, so their income and other demographics had no bearing on the decision to install solar. 

Forrester drilled down on three pronounced trends in the report:  

Each of the successively higher income brackets presented had successively larger photovoltaic systems on average, successively higher rates of battery storage installed on site, and successively higher rates of ownership of the equipment, rather than leases or power-purchase agreements with a third-party owner. 

In states other than California, median system size was 7.2 kW for households with annual income less than $50,000, gradually increasing to 9.2 kW for those with annual incomes above $200,000. This can be due to the higher cost of larger systems, the larger roof area often available in more expensive homes and the higher electrical demand often seen in higher-income households, Forrester said. 

(California is a category unto itself, a high-income state that accounts for 42% of the installed systems analyzed nationwide in the report. It is not an accurate snapshot of America.) 

O’Shaughnessy said the lower rate of solar adoption by lower-income households often reflects not a lack of interest in solar but a lack of money to pay for it. 

Berkeley Lab analyzed this issue a few years ago, he said. 

Looking at the incentives offered to low- and moderate-income (LMI) households, researchers found evidence “that not surprisingly, incentives do work. The catch there is that LMI incentives tend to be very small. So, it’s not really a scalable solution,” O’Shaughnessy said. 

“Leasing or third-party ownership, a model that allows homeowners to adopt solar with no or little money down, the evidence suggests that was probably the biggest factor that opened up the market to LMI households,” he said. “That is also a policy decision — not every state allows third-party ownership.” 

O’Shaughnessy added: “We continue to look at questions of why there is lots of low-income adoption in certain places, not others.”  

Data for the report were gathered from the U.S. Census Bureau; the U.S. Bureau of Labor Statistics; the White House Council on Environmental Quality’s Climate and Economic Justice Screening Tool; Berkeley’s own Tracking the Sun database; BuildZoom and Ohm Analytics; and an Experian ConsumerView dataset purchased for the project. 

Berkeley Lab’s online portal allows public analysis of the demographic data. 

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FERC Approves Rate Incentives for NJ OSW Transmission

FERC on Feb. 15 approved four rate incentives to Mid-Atlantic Offshore Development (MAOD) for its component of the approximately $1 billion in transmission to serve offshore wind in New Jersey under the State Agreement Approach (SAA) with PJM (EL23-101). 

The company, a joint venture between Shell New Energies US and EDF-RE Offshore Development, received approval to receive the RTO participation, regulatory asset, abandoned plant and hypothetical capital structure incentives. MAOD is tasked with constructing the new 230-kV Larrabee Collector substation and HVDC converter stations for $193.6 million, nearly a fifth of the total SAA project cost. (See New Jersey Launches OSW Infrastructure Solicitation.) 

The company’s request was protested by the Long Island Commercial Fishing Association and New Jersey ratepayers, who argued that it did not meet the Order 679 requirement that there be a connection between the incentives sought and the investments being made. They posited that Ørsted’s cancellation of the Ocean Wind 1 and 2 projects and economic assistance requested by Atlantic Shores Offshore Wind signal that the generation the transmission is designed to serve might not be built.

The commission rejected the protests, stating the SAA projects are meant to support New Jersey’s offshore wind development goals, not any three of the planned projects, and therefore may move forward even if those projects are not built. 

“Denying incentives because of the actions of third-party developers that may negatively impact the project would be inconsistent with the commission’s interpretation and implementation of Section 219,” the commission wrote, citing the Federal Power Act section requiring transmission incentives supporting capital investment. 

The company sought the regulatory asset and hypothetical capital structure incentives because of its status as a first-time, nonincumbent transmission developer without existing rates that can offset development costs. Establishing a regulatory asset would allow startup and development costs not capitalized to be recovered once rates are initiated after the project’s completion; the commission said approving a 50% debt and 50% equity capital structure would establish financial principles that nonincumbents lack. 

Approval of the 50-point RTO participation adder was conditioned on it being applied to a base return on equity that is later shown to be just and reasonable. 

The order also greenlit the abandoned plant incentive to provide 100% recovery of costs if the project is abandoned for reasons outside of the developer’s control. MAOD cited environmental, policy, siting and land acquisition risks the project faces, as well as risks inherent in it being one component of the larger SAA project involving numerous other developers. 

Commissioner Mark Christie concurred with the majority’s order, reiterating his concern that in many cases, the commission has a “check the box” approach to approving incentives; in this case, however, he said they’re warranted on the basis they’re in support of New Jersey’s policy goals and the associated costs would be allocated to the state’s ratepayers. 

But Christie also disputed the order’s wording in finding that MAOD’s request met the Order 679 requirement that projects seeking incentives undergo “a fair and open regional planning process that considers and evaluates reliability and/or congestion.” He argued PJM didn’t review whether the project would improve reliability or economics and that the project instead was evaluated by the New Jersey Board of Public Utilities using its own criteria. Nonetheless, he agreed the incentives are appropriate given the costs and benefits are allocated to one state. 

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PJM Seeks Waiver to Postpone 2025/26 Capacity Auction

PJM on Feb. 12 submitted a waiver request asking FERC to delay the 2025/26 Base Residual Auction by 35 days, which would bump the commencement to July 17. 

The RTO argued the delay would allow a more “orderly administration” of the auction and additional stakeholder education on how effective load-carrying capability (ELCC) values will be calculated under the process FERC approved last month. (See FERC Approves 1st PJM Proposal out of CIFP.) 

“Such education would provide market participants with greater confidence that their respective accredited UCAP [unforced capacity] values are accurate and consistent with the approved marginal ELCC methodology,” the request states.  

During the Jan. 16 meeting of the Planning Committee, Adam Keech, PJM vice president of market design and economics, told stakeholders the RTO plans to release class average accreditation values in the coming weeks.  

Keech also said PJM has shifted the pre-auction activities schedule by 10 days in support of stakeholder education, with an additional special session of the PC scheduled for Feb. 21 for that purpose. 

The auction originally was scheduled to begin June 12. 

PJM requested expedited commission action by Feb. 26, one day before the pre-auction deadline for market participants to submit unit-specific offer caps and inform the RTO of whether they intend to use the fixed resource requirement alternative to the Reliability Pricing Model. 

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PPL CEO Talks Energy Transition on Q4 Earnings Call

PPL Corp. CEO Vincent Sorgi on Feb. 16 touted his company’s plans to prepare its utility subsidiaries for a changing grid.  

“Looking ahead, we remain laser focused on creating the utilities of the future to advance the clean energy transition reliably, affordably and sustainably for our customers,” Sorgi said during an earnings call. “And throughout PPL, we’re driven to create long-term value for both our customers and shareowners.ˮ 

The company reported annual earnings of $740 million, which were down slightly from 2022 in the face of milder temperatures, more storms and a more challenging economy in 2023. 

PPL owns utilities in Pennsylvania, Kentucky and Rhode Island, and Sorgi reported “constructive regulatory outcomes” in the latter two. Kentucky regulators approved $2 billion in spending on generation, while the Rhode Island Public Utilities Commission approved PPL’s first infrastructure safety and reliability plan since the company purchased Rhode Island Energy from National Grid in 2022. 

“In addition, we received the green light to deploy advanced metering functionality across Rhode Island as we lay a foundation for a smarter, more resilient, more reliable and more dynamic electric grid capable of supporting the state’s leading climate goals,” Sorgi said. 

PPL is planning to invest $14.3 billion in capital spending from 2024 to 2027, which will strengthen reliability and resiliency while enabling more clean energy and keeping a lid on costs for customers, Sorgi said. That will translate into rate-base growth of 6.3% annually, compared with 5.7% last year. 

The company does not plan to file any rate cases this year, though it might go to the Pennsylvania Public Utility Commission for a waiver request “in the near future” to accelerate the replacement of aging infrastructure at PPL Electric Utilities, Sorgi said. 

PPL’s long-term plans are to continue hardening its transmission and distribution systems against climate change, improving its cybersecurity and rolling out advanced grid technology. 

“It means expanding our industry-leading use of technology, including smart grids, automation, data analytics, AI and technologies that haven’t even been invented yet to build a self-healing grid,” Sorgi said. “It means investing in R&D to drive innovation to advanced technologies that can be scaled safely, reliably and affordably to meet our customers evolving energy needs.” 

The company plans to expand its transmission system and add grid-enhancing technologies (GETS) to existing lines to connect more renewables and improve reliability. It also expects to invest in its distribution system to manage two-way power flows as more distributed energy resources are connected. 

The broader energy transition is going to require significant investments from the entire sector, Sorgi said. 

“The industry and others are projecting a 200 to 300% increase in electricity demand, which will require additions of reliable generation unless we see unprecedented amounts of energy conservation,” he said. “At the same time, aging fossil fuel plants in this country are being retired very rapidly, without replacements of reliable dispatchable generation capacity.” 

Sorgi said the math does not add up, with fossil fuel plants representing 50% of the total generation capacity in the country and some of the needed replacement technologies not ready. The power industry tends to take 40 years to commercialize new technology, but that is not good enough now, he said. 

“We need to cut that time frame in half, at least, to meet net zero-by-2050 targets, especially as we think about the big four new potential technologies: nuclear [small modular reactors], carbon capture and sequestration, long-duration energy storage and hydrogen,” Sorgi said. “In the meantime, we need to leverage commercially viable resources that exist today to reduce our carbon footprint while maintaining reliability.” 

For now, the industry will need to continue using natural gas plants to balance renewables and keep the lights on, he added.

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CAISO CEO Emphasizes Power of Partnership in West

FOLSOM, Calif. — CAISO CEO Elliot Mainzer thinks interregional coordination is key to Western states meeting their goals around climate policy and grid reliability in the face of a changing resource mix and increasingly volatile weather conditions. 

And getting to that level of cooperation will be most efficient inside the footprint of a single electricity market to serve the broad region, Mainzer said in a Feb. 13 interview with RTO Insider. 

“How do you bring different parts of the West together, respect their differences and their desires, interests, policies, preferences, etc., but link them together to really harness the physics and the economics so that everybody can save money and do this reliably and efficiently?” Mainzer said.  

The Western Energy Imbalance Market’s (WEIM) role in helping the West respond to extreme weather events provides proof that having just one regional wholesale electricity market would be crucial to meeting decarbonization goals reliably and economically, Mainzer said. The transmission connectivity enabled by the WEIM has allowed entities across the West to share energy in times of need.  

“It’s a basic principle of portfolio diversification that the broader the footprint and the deeper the pool of diversity and transmission connectivity … your chances of an economically efficient and reliable solution are better,” he said.  

Mainzer and CAISO are pushing to further expand WEIM’s footprint and capabilities by rolling out the Extended Day-Ahead Market (EDAM), which FERC approved in December. (See CAISO Wins (Nearly) Sweeping FERC Approval for EDAM.)  

“Our hope would be to try to make sure that everybody that’s currently in EIM would also join our Extended Day-Ahead Market,” he said. “A market footprint that does not optimize that natural transmission connectivity and resource diversity across the West is going to be less optimal for consumers at large in terms of both economics and reliability.”  

Mainzer said the ISO is less focused on the markets debate among Western stakeholders than on getting the first tranche of new EDAM members into the market, ensuring that market rules and stakeholder processes are as solid as possible. EDAM so far has commitments from six-state utility PacifiCorp and the Balancing Authority of Northern California, with an announcement from the Los Angeles Department of Water and Power likely pending. (See LADWP Poised to Join CAISO Day-ahead Market After Board OK.)   

Long-Term, Interregional Transmission Planning Crucial

CAISO is also looking to improve long-term, interregional transmission planning, Mainzer said. 

The ISO faces the challenge of onboarding roughly 7,000 MW of capacity a year for the next two decades to meet the climate goals set out by California’s Senate Bill 100, he said. To do so, it is prioritizing long-term transmission planning via partnerships with regulatory agencies, utilities and other entities throughout the Western Interconnection to expand transmission interconnectivity. 

“We certainly think that both the economic value proposition and the reliability benefits of the Extended-Day Ahead Market will be significantly enhanced by bringing even greater transmission connectivity to the Western system,” he said.   

CAISO’s 2022-2023 Transmission Plan provides a 10-year blueprint, and its 20-Year Transmission Outlook, released in May 2022, looks further into the future, forecasting the connectivity needed to meet increasing demand over the next two decades.  

The ISO is also developing several interregional transmission lines, including the Ten West Project, which will enable delivery from 1,000 MW of renewables into California from the Southwest while also increasing CAISO’s export capability in the opposite direction. The line is under construction and is expected to be in service by this May.  

CAISO last year approved the Southwest Intertie Project-North (SWIP-N), a 285-mile, 500-kV line in Nevada that will allow access to 2,000 MW of Idaho wind resources. The line is expected to be in service by the end of 2026. (See CAISO Board Approves Nevada Transmission Line to Access Idaho Wind.) 

Three other interregional transmission lines are in the works as well.  

Looking to the Future

While transitioning the grid to non-emitting resources is no easy feat, Mainzer is optimistic about the direction the industry is headed.  

“When I think back to where things were when I was first coming in in the late ‘90s and I think about where things are now today in terms of just the sheer amount of renewable resources on the grid and the new technology and the level of market sophistication that we have — we could have never imagined it,” he said.  

Mainzer came to CAISO in 2020 when the ISO’s fleet contained only 250 MW of battery storage. The current figure is 7,000 MW and climbing. The grid operator is also integrating more long-duration energy storage, including rapidly evolving batteries that can hold up to 100 hours of storage.  

And Mainzer expects to see much more innovation around clean, dispatchable generation in the next 10 to 15 years. He considers himself “energy agnostic,” believing portfolio diversity is key to the energy transition.  

“The growth curves are amazing,” he said. “That will bring additional capabilities and allow us to be even less and less dependent on the gas fleet, but certainly for the next few years … we’ll continue to rely on those resources under the most extreme conditions.”  

Load flexibility will be important in responding to volatile weather, Mainzer said, particularly with demand response, virtual power plants and other types of adjustable capabilities.  

“When we get into these crazy-hot days in the summer and we’re 5 to 10% away from problems, just having 5 to 10% load reduction capability that would be automated and embedded into people’s thermostats to be able to back off that super-peak consumption would be a huge difference maker,” he said.  

‘Fabulous Success Story’

Historical tensions between California and the rest of the West, including around the 2000/01 energy crisis, largely stemmed from “immature” resource adequacy programs, Mainzer said, and so CAISO is also focusing on strengthening RA in partnership with other state entities. 

“When we don’t take care of business in terms of resource adequacy, our markets go sideways and it becomes very divisive,” Mainzer said. “RA success is the foundation of healthy partnership.”  

Mainzer hopes industry participants can look beyond historical friction to enable stronger collaboration in the energy transition.  

“I think we tend to focus far too much on the small number, literally handful, of issues that we’ve run into together over many, many years of partnering,” Mainzer said. “I believe that when you look at the facts, when you look at the economic value that’s been created from the partnership between California and its neighbors through transmission optimization, bilateral and market trade, and supporting each other through reliability events, it’s been a fabulous success story.” 

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NYISO Defends 10-kW Minimum for DER Aggregation Participation

NYISO on Feb. 13 defended its proposal to set a 10-kW minimum requirement for distributed energy resources to participate in an aggregation in response to a deficiency letter from FERC, which asked it to justify the figure (ER23-2040). 

The ISO argues the rule would prevent staff from being overwhelmed by initial program participation requests. Renewable energy advocates have protested, arguing the rule would discriminate against smaller aggregations. (See Clean Energy Groups Protest NYISO DER Proposal.) 

NYISO explained the 10-kW threshold “is based on its two decades of experience administering” the existing special-case resource (SCR) and emergency demand response programs (EDRP), which it views to be the “participation models closet in kind to the DER and aggregation model.” 

The ISO said it settled on the 10-kW requirement because it believes that, like the SCR program and EDRP, managing DER aggregations would include “a significant amount of manual work” and want staff to become accustomed to it. 

It also reasoned the rule would impact mostly residential facilities employing demand-reduction technologies, such as energy storage resources or smart home products, and the 172,434 rooftop solar installations in New York with capacities under 10 kW.

These smaller resources, NYISO claimed, are minor contributors to the ISO’s markets and might not even opt to participate in the DER aggregation model, favoring other programs meant for small facilities, such as the SCR. 

“The question is whether the delayed implementation and costs associated with building the infrastructure to enable sub-10-kW resource participation in the DER and aggregation participation model is justifiable in light of their expected contribution to the Bulk Electric System,” it said. 

This is the second time NYISO has responded to a deficiency notice to its DER participation model proposed in June; much of its response reiterated arguments it made the first time, in October. FERC had requested more details about how the ISO settled on the 10-kW figure. 

The ISO argued that any further delays, such as FERC rejecting its proposal, would mean it would need to “undertake a significant multiyear process to develop new market rules” addressing the commission’s concerns and potentially “delay the transition of over 400 MW” of demand-side resources capable of participating in the DER aggregation model. 

NYISO said it “is ready to implement the model immediately upon commission acceptance of the tariff revisions proposed,” adding that “seven entities” already “submitted aggregator registration materials” and three have completed their registration. 

The ISO urged FERC to act on the proposed revisions by April 15, as it is prepared to roll out its DER aggregation participation model April 16. 

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Southern Looks Beyond Vogtle After Challenging 2023

After a year in which unusually mild weather depressed electric use, Southern Co. is forecasting 5 to 7% annual earnings growth thanks to a robust economy in Georgia.  

The company faced “unprecedented headwinds” in 2023 but achieved numerous milestones during “an exceptional year,” CEO Chris Womack said in announcing the company’s fourth-quarter and full-year earnings Feb. 15. 

Among the accomplishments Womack highlighted in his presentation was the long-delayed completion of Unit 3 at the Vogtle nuclear power plant near Waynesboro, Ga., which entered commercial operation on July 31 more than seven years late and $17 billion over budget.  

The CEO pointed out that Southern subsidiary Georgia Power reached an agreement with the state’s Public Service Commission last August to resolve all remaining prudency issues at Unit 3 and Unit 4. Under the agreement, the recovery of capital construction costs from ratepayers for both units is capped at $7.6 billion, leaving the remaining costs — estimated at around $2.6 billion — to be paid by Georgia Power. The PSC approved the agreement in December. 

Womack said Southern is making “meaningful progress” toward completion on Unit 4, with initial criticality achieved Feb. 14, marking the start of the nuclear chain reaction inside the reactor. The company expects the final unit to be in service by April. 

Along with the progress on Vogtle, Womack mentioned the completion of Unit 8 at Alabama Power’s Plant Barry, a 727-MW combined cycle unit that began operating Nov. 1, and the acquisition of two solar projects that will provide 350 MW when finished.  

The company’s operating revenue for the three months ending in December came to $6 billion, compared to $7 billion for the same period in 2022. Net income for the period — excluding losses on plants under construction, losses on capital investments and tax impacts — stood at $700 million, compared to $285 million for the same period the year before.  

Operating revenue for the full year was $25.3 billion, down from $29.3 billion in 2022; however, net income for the full year — excluding the same elements — was $4 billion, up from $3.9 billion the previous year. 

Southern reported adjusted earnings per share of 64 cents for the quarter, up from 26 cents for the same period in 2022, with adjusted earnings per share for the whole year rising from $3.60 to $3.65, which CFO Dan Tucker noted was “at the very top of our 2023 guidance range.” He cited “higher utility revenues and lower nonfuel O&M [operations and maintenance] costs and income taxes.” 

Tucker said the company’s electric revenue was reduced because 2023 was “the mildest year in our history for our electric service territories.” Electric retail sales, adjusted for weather, were down 0.4% from 2022, with reduced residential and industrial usage (down 0.5% and 1.9% respectively) balanced by strong commercial sales growth of 1.3%. 

The decline in industrial sales was primarily due to “continued slowing in [the] housing and construction-related sectors, as well as lower sales to chemical companies due to outages and long-planned plant closures,” Tucker said. However, he pointed out that the population in Southern’s electric territories grew by 0.8% between July 2022 and July 2023, with Georgia adding more than 26,500 new jobs last year. In 2022, the state added 45,600 jobs, more than 15,000 of them from auto factories being built by Hyundai and EV truck maker Rivian. 

Based on these trends, Southern is setting an adjusted earnings per share guidance range for 2024 of $3.95 to $4.05, with long-term adjusted EPS growth rate of 5-7%, Tucker said. These figures assume Vogtle Unit 4 is completed on schedule. 

Despite the challenges, Womack said Southern’s electric and gas businesses “continued to excel at the fundamentals and started this year strong,” noting that the company operated reliably during January’s winter storm even as “electricity demands reached all-time winter peaks.”