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November 4, 2024

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NV Energy IRP Looks to Reduce Reliance on Open Market

NV Energy has filed a proposal aimed at reducing Nevada’s dependence on the open energy market through the addition of geothermal resources, battery storage and a 440-MW, gas-fired peaker facility.

The plan proposes to postpone by either five or 10 years the retirement dates of several gas-fired units in both northern and southern Nevada. The proposal also addresses NV Energy’s removal from its energy portfolio of two solar-plus-storage projects that the company said have stalled because of supply chain issues.

The plan was filed last week with the Public Utilities Commission of Nevada (PUCN) as an amendment to the company’s 2021 integrated resource plan. A commission decision on the plan is expected by mid-May. But NV Energy is asking the PUCN to approve the Silverhawk peaking facility by March 10, so that operations can start by July 2024.

NV Energy said Nevada’s energy supply has faced challenges over the last three summers caused by energy shortfalls in California and increased competition for energy across the West. The company said the proposal is intended to “shield” its customers from the impacts of regulatory changes in California and resource adequacy challenges.

“Our plan will advance Nevada’s energy independence — ensuring reliable energy for our customers no matter how hot it gets across the western United States while also advancing our state’s sustainability and clean energy goals,” NV Energy CEO Doug Cannon said in a statement.

NV Energy’s push for Nevada’s “energy independence” comes as the state faces a 2030 deadline for its transmission providers to join an RTO as mandated by Senate Bill 448 of the state legislature’s 2021 session.

NV Energy has been participating in the RTO discussions. It is also a participant in the Western Markets Exploratory Group (WMEG), a stakeholder group that is discussing the design of two proposed day-ahead markets: CAISO’s extended day-ahead market and SPP’s Markets+. (See NV Energy Seeks Recovery of RTO-related Expenses.)

“Our filing aligns with our support of a regional transmission organization that will improve resource adequacy and improve reliability for our customers,” an NV Energy spokesperson told NetZero Insider.

Plan Components

NV Energy’s new proposed resource plan includes a 200-MW, grid-tied battery storage system on the site of the coal-fired Valmy Generating Station in Northern Nevada, which is slated for retirement by the end of 2025. The estimated cost for the battery storage is $466 million.

The Valmy battery storage would be a four-hour system, in contrast to the recently approved two-hour Reid Gardner battery storage system. Reid Gardner was designed to target the tip of summer net peak load, while Valmy will cover a broader portion of the peak, NV Energy said in its filing.

Another component of the plan is 440 MW of natural gas-fired combustion peaking turbines on the site of the Silverhawk Generating Station in southern Nevada. Silverhawk is a 520-MW, gas-fired power plant near Las Vegas.

NV Energy said in its filing that the Silverhawk peaking plant would be able to run on a 15% hydrogen fuel mix, with a potential for 100% hydrogen operation in the future.

The geothermal piece of the plan includes a 120-MW package of geothermal projects from Ormat and a 20-MW geothermal system from Eavor. The pricing for the geothermal energy would be $69/MWh for the Ormat portfolio and $70/MWh for the Eavor project — prices that NV Energy called “historically low” for a geothermal resource. For example, the Eavor price would be 28% lower than the last geothermal energy price that PUCN approved.

NV Energy’s proposal also includes transmission upgrades to accommodate the new energy resources.

Solar Projects Stalled

NV Energy received PUCN approval in January to purchase the Iron Point and Hot Pot solar-plus-storage projects from Primergy Solar. The projects — totaling 600 MW of solar and 480 MW of battery storage — were intended as replacement resources for the Valmy coal-fired plant.

But now, Iron Point and Hot Pot are “no longer expected to move forward as previously approved,” NV Energy said in its filing, blaming supply-chain issues.

“Due to the recent … price increases in the solar and energy storage market, [the developer] was unable to complete procurement on the schedule and at a price supporting that approved by the commission,” the filing said.

NV Energy said it is working with the developer to find ways that one or both projects could be delivered. Primergy didn’t immediately respond to a request for comment sent to the solar company’s publicist.

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Utilities Grapple with Increasingly Distributed Power System

WASHINGTON — The transition to a more distributed power system is well underway, but system operators need better visibility into that shift, experts told GridWise Alliance’s gridCONNEXT 2022 on Tuesday.

“I’ve got 5,800 EVs and plug-in hybrids on my system, and I control 21,” said Mark Gabriel, CEO of Denver area cooperative United Power. “This number is going up between 100 and 200 a month. It is ramping like crazy, and we have no ability to control it.”

United Power has seen 9,400 of the 107,000 meters it serves adopt distributed solar, but it has control over none of those, he added.

The old days of vertically integrated utilities featured power systems that were much easier to run, and all of the risk was at the utility. But now the assumption of risk is moving toward the customer — or member in the co-op’s case, Gabriel said.

In response to the changes, United Power is shifting from its role as a generation and transmission cooperative to become a distribution system operator that will need to be linked up to a wholesale market, Gabriel said. Colorado law (SB 72) requires the state’s utilities to enter an RTO by 2030, but Gabriel said that shift should happen at least five years earlier.

Portland General Electric, which is facing many of the same issues, will get one-quarter of its supply from the distribution system by 2030, said Vice President of System Operations Larry Bekkedahl. The Oregon utility is also adding 3,000 MW of renewables and 1,000 MW of storage over the next decade to a system with peak demand of 4,400 MW.

“If anybody thinks they’re bored in our industry right now, come see me,” Bekkedahl said.

Those changes to supply are coming on top of climate-driven demand shifts. PGE saw its all-time peak in June 2021, when temperatures hit 116 degrees Fahrenheit in Portland. PGE’s demand was 10% higher than it ever had been.

“Our previous peak was 4,100 MW,” Bekkedahl said. This summer’s high was 97 F, with a peak load of 4,250 MW. “So everyone that didn’t have air conditioning the year before now has air conditioning in their house.”

Such rapid demand growth makes the historic utility practice of using the previous 15 years as a guide questionable, he added.

CAISO recently broke a 15-year-old demand record as high temperatures led to consumers using 52,061 MW on Sept. 6, said Hani Alarian, the ISO’s executive director of power systems, technology and operations. CAISO avoided rolling blackouts with a text message from the governor’s office urging Californians to conserve.

CAISO, which has seen solar grow to more than 14,000 MW, also has 12,000 MW of rooftop solar, which is only seen by the grid operator when it impacts demand. The ISO also has seen more than 3,000 MW of battery storage added in recent years, which will continue growing, Alarian said.

All that solar has made the hours of 4 to 9 p.m. during high demand days the most difficult to manage, as solar production falls off while demand remains high.

“In three hours we [ramped] almost 18,000 MW; that’s a sustained 100-MW ramp rate [per] minute for three hours,” Alarian said. “That’s a lot of ramp.”

While the demand side is changing because of climate change, distributed generation and electrification, advanced metering technology is keeping pace and is now much more functional than the first round of the technology, which only eliminated meter reading jobs and helped utilities with operations, said Jonathan Staab, manager of product development at Landis+Gyr. The second wave of advanced meters allowed for more engagement with consumers by enabling dynamic pricing and increasing customer visibility into their power usage patterns.

“The third wave in this evolution happens to be the wave that we’re in right now,” Staab said. “This wave, I would argue, is probably the largest technological advancement, and it involves direct and often real-time engagement with consumers.”

While Landis+Gyr provides the meters for that engagement, the firm Sense offers software that can show customers exactly which of their appliances are using power — and even whether something is wrong with one of them, said its vice president of energy services, Colin Gibbs.

Gibbs demonstrated how his company’s app showed his home’s energy uses as his wife, who was across the country, turned on appliances such as the coffee kettle and their clothes washer. The appliances immediately showed up on his app with their total power use. “It’s important to note that this is not a smart coffee kettle; this is not an IOT [internet of things] device; this is just some regular, old electric resistance coffee kettle that we use in the morning,” Gibbs said.

Sense currently has to add a small submeter to customers’ utility meter that costs about $300 and another $150 for an electrician to install it, but eventually that will go away as more utilities roll out advanced smart meters. Sense will offer apps for new smart meters, Gibbs said.

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FirstEnergy to Pay $700K Penalty to ReliabilityFirst

FERC last week approved a $700,000 penalty on FirstEnergy Utilities (NYSE:FE) as part of a settlement between the utility and ReliabilityFirst for violations of NERC’s facility ratings standards.

NERC submitted the settlement as a Notice of Penalty in October (NP23-1). FERC said in a statement Wednesday that it would not further review it, leaving the penalties intact.

FirstEnergy’s penalty stems from infringements of FAC-008-3 (Facility ratings) and FAC-009-1 (Establish and communicate facility ratings). Requirement R8 of the FAC-008 specifies the information that transmission owners and some generator owners (GOs) must provide about their facilities to reliability and planning coordinators, and to transmission planners, owners and operators; R1 of the latter standard mandates that TOs and GOs “establish facility ratings for [their] solely and jointly owned facilities that are consistent with the associated facility ratings methodology [FRM].”

On May 9, 2019, FirstEnergy reported to ReliabilityFirst that it was in violation of FAC-009-1. The utility said it had discovered that a facility rating for a 345-kV line was incorrect; after a further extent of condition review on 10 substations, FirstEnergy decided to expand the review to include field walkdowns at all facilities to which the standard applied.

That expanded review “revealed further issues with the accuracy of [FirstEnergy’s] facility ratings across its entire footprint,” according to the settlement. While the full walkdown is expected to be completed by Dec. 31, the utility has already discovered inaccurate ratings at 443 facilities, about 35% of those reviewed by the date of the filing; 301 of those facilities have had their ratings adjusted downward, while the others had to be adjusted upward.

The FAC-008-3 violation arose from self-reports that FirstEnergy submitted in July 2020 and April 2021, stating that it had “failed to provide its TOP [transmission operator], PJM, with the most-limiting facility rating equipment.” The issue began when FirstEnergy realized during a communication with PJM that it had not informed the TOP that a flow circuit breaker was the most-limiting element on a 500-kV transmission line under some circumstances.

An extent-of-condition review found that 50 circuit breakers were similarly incompletely modeled in PJM’s energy management system (EMS). An additional 38 flow circuit breakers were discovered during a later review to either contain ratings discrepancies or to be absent from the EMS altogether.

ReliabilityFirst assessed the FAC-009-1 violations as a “serious and substantial” risk to bulk power system reliability because it could have caused FirstEnergy to operate equipment above its maximum rating, which might have led to equipment degradation and failure, to load shedding in emergencies or to “incorrect post-contingency planning.” The long duration of the violation — the earliest instance began in 2007 when the standard took effect, while the final infringement is expected to end by Dec. 31 — was another factor in assessing the risk.

The FAC-008-3 violations, on the other hand, were assessed as a moderate risk to grid reliability. The factors elevating it from a minimal level were the number of instances, the duration (about four and a half years) and the absence of effective processes to ensure that facility ratings would account for the behavior of circuit breakers in abnormal system conditions.

FirstEnergy’s mitigation actions for the FAC-009-1 violations mainly relate to the ongoing review of facilities, which is expected to lead to corrected ratings for all equipment; the utility has already changed its internal controls to improve the accuracy of its transmission ratings database. For the FAC-008-3 infringements, FirstEnergy’s mitigations include providing PJM with updated EMS model data and ratings, creating internal controls to detect any needed circuit breaker and line rating adjustments, and training personnel to ensure they understand the new processes.

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Western Energy Leaders Explore Grid Integration

Energy officials from California and across the West weighed the potential benefits of Western electricity system integration for cost savings, transmission and resource adequacy in an all-day workshop Friday hosted by the California Energy Commission.

The workshop was meant to brief a broader audience, including state lawmakers, on regional market developments. In the past year, CAISO and some California lawmakers have advanced the idea that California should play a larger role in regional markets as it faces competition from challengers such as SPP.

Friday’s session was part of the commission’s Integrated Energy Policy Report (IEPR), a biennial assessment of energy issues and policy recommendations in which the CEC tries “to elevate important topics to make sure … the state Legislature is aware of what is happening in the energy space,” Commission Vice Chair Siva Gunda said.

“So, with that spirit, we have included the Western integration topic as an important element of this year’s IEPR,” Gunda said. “A lot has been happening over the last couple of years, and we thought it’s extremely important to provide a transparent, high-level update on what’s happening in the West as it pertains to Western integration and the markets.”

CAISO, for instance, began a stakeholder process in mid-October to explore the benefits of greater regional cooperation and a Western RTO, as California lawmakers had requested in Assembly Concurrent Resolution 188 in August. The resolution’s goals were limited, requiring only that CAISO report to the Legislature on recent studies of RTO benefits, but some saw ACR 188 as a cautious opening gambit in another regionalization effort. (See CAISO, NREL Start to Study Western Cooperation.)

Several prior attempts at turning CAISO into an RTO fizzled in 2016-2018, as most lawmakers balked at broadening its governance to include other states. CAISO is a public benefit corporation created via state statute in 1998; the California governor appoints the five members of its Board of Governors.

However, circumstances have changed substantially since the last legislative attempt to broaden CAISO’s governance in 2018.

SPP is making inroads in the West with its Markets+ day-ahead offering and a plan to expand its Eastern RTO into the Western Interconnection. Utilities in Colorado and Wyoming have indicated they plan to join both. (See SPP Issues Final Markets+ Proposal.)

The Western Power Pool (formerly the Northwest Power Pool) will soon launch its Western Resource Adequacy Program, which could cover much of the Western Interconnection. WPP hired SPP to administer the program, and some observers have speculated that the WRAP might be a logical precursor to another Western RTO.

Workshop participants met in a hybrid in-person and online gathering to weigh these and other developments. They included members of the California Public Utilities Commission, CAISO CEO Elliot Mainzer, Air Resources Board Chair Liane Randolph and Gov. Gavin Newsom’s senior energy adviser Karen Douglas.

Participants from other states included utility commissioners from Colorado and Oregon and representatives of SPP, the Western Interstate Energy Board, the Western Electricity Coordinating Council, the Western Power Pool and the Northwest & Intermountain Power Producers Coalition.

“The attendance here today is indicative of the importance of this conversation,” Gunda said.

Role of Markets

A panel exploring the role of regional markets began the substantive discussions.

This year CAISO fast-tracked its extended day-ahead market (EDAM) proposal for its Western Energy Imbalance Market, a real-time interstate trading forum that has saved participants more than $3 billion in the past eight years. The real-time market, however, involves only a small amount of the transactions that occur in day-ahead trading.

“The success of the WEIM demonstrates that there’s a potential for a lot more,” said Anna McKenna, CAISO vice president of market policy and performance.

A recent study by consulting firm Energy Strategies found the EDAM could generate $1.2 billion a year in benefits, or 60% of the savings of a West-wide RTO, if it encompassed the entire U.S. portion of the Western Interconnection.

Energy Strategies Principal Keegan Moyer said a full Western RTO would generate even greater benefits. His firm estimated the benefits at $2 billion a year in electricity costs in test-year 2030 in a study prepared for state energy offices in Colorado, Idaho, Montana and Utah. (See Study Shows RTO Could Save West $2B Yearly by 2030.)

“The EIM was an excellent first step, and the $3 billion number is impressive,” Moyer said. “But every data point that we’ve seen from our work and others is that there’s still a lot of opportunity out there, which is why you see so much effort, I think, put into this by the industry.”

EIM-Map-Updated-2022-07-04-(CAISO)-Alt-FI.jpgCAISO’s Western Energy Imbalance Service is expected to encompass nearly 80% of load in the Western Interconnection by next year. | CAISO

CAISO has scheduled a stakeholder meeting for Dec. 7 to discuss its final EDAM design and plans to seek approval from its board and the WEIM Governing Body in February.

Eric Blank, chair of the Colorado Public Utilities Commission, said a study performed by his commission found increased regional coordination could save the state’s electric utilities up to $300 million a year, or about 5% of their costs. State law requires Colorado transmission owners to join an RTO by 2030.

“These benefits were roughly the same whether we went west to CAISO, east to SPP or did something [in between],” the hypothetical study results showed, Blank said.

CAISO’s one-state governance is a potential roadblock to expanding it into a Western RTO unless state lawmakers broaden its governance structure. SPP would maintain its inclusive governance structure in the West, Carrie Simpson, the RTO’s director of Western services development, said in the workshop.

The expectation is that participants in SPP’s existing Western Energy Imbalance Service will eventually join Markets+ and that many Markets+ participants will become members of SPP’s planned RTO West, she said.

One diagram in her presentation showed a larger RTO West and Markets+ transacting business with CAISO and WEIM. Another used a map showing SPP and WPP dominating the Western landscape, with CAISO relatively isolated. (A comparable CAISO map would show the WEIM covering much of the Western Interconnection.)

Seams between RTOs and ISOs are common in the Eastern Interconnection and would work in the West, including between CAISO and SPP, Simpson said.

“You can have many markets next to each other, optimizing efficiently through seams. We have it in the East. It’s very common. MISO, PJM and SPP coordinate regularly together,” Simpson said. “And so, to the extent that we have seams [in the West], absolutely we will want to work with all of our neighbors to make sure we’re optimizing systems as efficiently as possible to bring the greatest benefits to customers.”

Whether California will again seek to form a Western RTO to compete with SPP remains doubtful.

CAISO’s ACR 188 report, performed by the National Renewable Energy Laboratories, is being conducted in partnership with Western entities such as NV Energy, PacifiCorp and the Western Area Power Administration. A draft is expected later this month, and CAISO hopes to deliver the report to the Legislature during the first weeks of its 2022 session, which begins Jan. 3.

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NJ Shoots for 4 GW+ in 3rd OSW Solicitation

New Jersey is seeking projects totaling 1.2 to 4 GW — and potentially larger — in the state’s third offshore wind project solicitation planned for early 2023, according to a draft document released by the New Jersey Board of Public Utilities (BPU) on Thursday.

The Solicitation Guidance Document seeks proposals that are significantly larger than in the first two solicitations, which awarded projects totaling 1.1 GW and 2.658 GW, and expands the state’s already aggressive effort to become a key player in the growing offshore wind sector. The document presents a new solicitation schedule shaped to accommodate Gov. Phil Murphy’s decision in September to increase the state’s OSW target capacity from 7.5 GW by 2035 to 11 GW by 2040.

“The board seeks to promote robust competition in this third solicitation and future solicitations to support the continued development of the offshore wind industry in New Jersey,” the draft says.

The new schedule envisions four more solicitations after the third one next year, with each additional solicitation expected to award capacity of about 1.2 GW, though the BPU “may award projects above or below the target.”

The first project is expected to come online in the 2024-2025 period, with the final project up and running by 2038. The draft says that for the 2023 solicitation, the BPU “reserves the right to select less than 1,200 MW or more than 4,000 MW of qualified projects if circumstances warrant.”

The BPU will seek stakeholder input on the draft solicitation at a public hearing on Dec. 13.

Building an Industry

The requirements set out in the draft solicitation for project applicants show that New Jersey is looking to build upon the state’s OSW infrastructure already in development.

New Jersey awarded its first offshore wind project, the 1.1-GW Ocean Wind 1 developed by Denmark-based Ørsted, in 2019, and in 2021 awarded two more: the 1.148-GW Ocean Wind 2, and the 1.51-GW Atlantic Shores project, developed by a joint venture between EDF Renewables North America and Shell New Energies US. (See NJ Awards Two Offshore Wind Projects.)

The state has accompanied the project awards with an effort to position itself to serve other parts of the East Coast offshore wind sector by developing a logistics, marshalling and manufacturing hub. The heart of the effort is the development of what New Jersey officials say is the first custom-built wind port in the nation, committing $478.2 million to the project with bonding for another $160 million underway.

The wind port, located at Alloways Creek in Salem County, will include a 30-acre marshalling area for component assembly and staging; a dedicated, overland, heavy-haul transportation corridor; and a heavy-lift wharf with a dedicated delivery berth and an installation berth that can accommodate jack-up vessels. (See NJ Wind Port Draws Heavy Hitters.)

The BPU on Oct. 26 approved the expenditure of $1.07 billion for transmission upgrades to deliver 6,400 MW of OSW generation to the grid. The BPU picked the projects — the largest of which is an onshore substation known as Larrabee Tri-Collector Solution — from among 80 proposals submitted by 13 developers in response to a solicitation issued by PJM under FERC Order 1000’s State Agreement Approach. (See related story, FERC Approves PJM Tariff Revisions for SAA Cost Allocation.) However, the BPU largely awarded contracts for onshore work and left the offshore infrastructure mostly unallocated.

The draft solicitation seeks to fill that gap by requiring applicants to outline a “prebuild infrastructure” that would interconnect with the recently approved onshore infrastructure. Applicants would have to provide plans to build duct banks and access cable vaults for transmission to run to onshore interconnection points.

“Developers of future qualified projects would then install their cables through the prebuilt duct banks utilizing the prebuilt cable vaults, with minimal further disruption to the communities” around the interconnection points, the solicitation says.

Qualified project connections (NJ BPU) Content.jpgDiagram of qualified project connections to point of interconnection (POI) with and without prebuild | NJ BPU

 

Economic Impact

The solicitation also seeks to generate a range of project alternatives, requiring applicants to submit at least one 1.2-GW project while adding that they are “highly encouraged to submit applications covering a range of project sizes up to approximately 4,000 MW.”

Applicants would have to submit a package with a completed application form and an explanation of their project, as well as an in-depth analysis of its economic impact on the state. They would have to detail the “proposed investment in New Jersey offshore wind infrastructure, supply chain, labor force development” and other investments. They would also have to outline the economic development impact on communities in the state and provide detailed job creation information, including location, types and number of jobs it would generate, and wage or salary levels.

The proposal must also say whether the planned project will use the New Jersey Wind Port or “alternative infrastructure” located in the state or elsewhere.

“The BPU encourages use of the New Jersey Wind Port for project marshalling and for locating Tier 1 manufacturing facilities, where feasible,” the solicitation says.

The heart of the application, however, is the cost of the project and its underlying economics. Applicants must set out the level of the OSW renewable energy certificate (OREC) at which the developer believes the project would be commercially viable.

“OREC pricing will be on a pay-for-performance basis,” the solicitation said. “Payments will be made on a dollar-per-megawatt-hour basis.”

The OREC must reflect the total capital and operating costs for the project over 20 years, “including costs of equipment, construction, financing, operations and maintenance, and taxes,” offset by any state or federal grants or subsidies, according to the draft solicitation. “The OREC pricing proposal shall specify the nameplate capacity, expected energy output and assumed capacity factor for the proposed project, along with the number of ORECs that the project will produce.”

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Climate Activists Take Over Small Piece of ISO-NE

Climate activists managed to successfully take over a small piece of ISO-NE last week, winning control of a significant portion of the committee that controls the grid operator’s official platform for interacting with the public.

Six activists organized by the anti-fossil fuel group No Coal No Gas were elected to two-year terms on the Consumer Liaison Group’s (CLG) Coordinating Committee on Wednesday, securing a say in how the group operates, as ISO-NE officials looked on with what one attendee described as “grim” faces.

While the CLG carries little formal power, it’s an important (and FERC-mandated) piece of how the grid operator communicates with the public. CLG holds four meetings a year, which provide a rare opportunity for the public to hear from and interact with high-level officials at ISO-NE and other key energy policymakers in the region.

Climate advocacy groups in New England have criticized how ISO-NE conducts its work, calling out the organization for policies they say are maintaining the grip of fossil fuels on the region’s grid and hampering the clean energy transition.

No Coal No Gas built support for a slate of candidates and encouraged its members to attend last week’s meeting and vote. More than 100 members of the advocacy group attended the meeting.

Nathan Phillips, a Boston University ecologist from Newton, Massachusetts, was one of the activists who was elected.

“It was the incredible feeling of being in the belly of the beast but having a hundred friends who had your back,” he told RTO Insider. “It felt like democracy. It felt like people power.”

No Coal No Gas laid out its plan in the weeks before the meeting in emails to members.

“We believe that the CLG could be a more productive forum and a space to build power among communities and ratepayers from across New England who are advocating for themselves regarding electricity (how it is generated, the cost, how the markets are structured),” the group wrote.

The group’s priorities include more closely connecting CLG’s work to people in New England who are, for example, struggling to pay their energy bills.

If they have their way, the forum’s name might also change.

“I think it should be called the Ratepayer Liaison Group,” said Phillips “It became apparent to me in the meeting, the words and the language matter.”

To him, the term “ratepayers” gives more agency and power to the people it’s describing than “consumers.”

“Until now, the CLG has mostly been a space where ISO-NE presents to the public about what they are doing. There has been little actual input from the public, and even less from everyday ratepayers and environmental justice communities,” No Coal No Gas told its members ahead of the meeting.

The other activists elected were Sonja Birthisel, a University of Maine researcher and nonprofit director; Kendra Ford, a Unitarian Universalist minister from New Hampshire who recently made a strong impression at ISO-NE’s public board meeting; Regine Spector, an associate political science director at the University of Massachusetts, Amherst; Ian McDonald, an activist from Killingly, Conn.; and Jacob Powsner, co-owner of a farm in Rutland, Vt.

Two incumbents were ousted from the committee: Associated Industries of Massachusetts executive Robert Rio and former Harvard University energy supply official Mary Smith.

Along with allies from state consumer advocacy offices and environmental groups who make up several incumbents on the committee, the group pushing for change has gained a majority.

“It will now be much harder for ISO New England to keep the CLG from getting feisty,” wrote Donald Kreis, New Hampshire Consumer Advocate and an incumbent who was re-elected. (Kreis has called for the CLG to be abolished altogether.)

ISO-NE spokesperson Matt Kakley said in an email to RTO Insider that the grid operator is “pleased to see the increased interest in the Consumer Liaison Group and hope people continue to attend meetings, gain insight into the regional energy landscape, and engage in the discussions.”

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Solar Industry Pushes for Bigger Incentives from NJ Program

Solar advocates last week urged the New Jersey Board of Public Utilities (BPU) to maintain or increase the incentives offered for new solar installations under the state’s Administratively Determined Incentive (ADI) Program.

As part of the Garden State’s 2021 Successor Solar Incentive (SuSI) Program, the BPU is required to conduct a reevaluation of SuSI incentive levels after the first year of its implementation. The ADI half of the program targets net metered residential, community solar projects and net metered non-residential projects under 5 MW. The second prong, the Competitive Solar Incentive (CSI) program, creates a competitive bidding process for solar renewable energy credits for their projects.

The BPU could recommend changes to the incentive levels, the share of incentives available to each block of eligible projects or other program rules based on public comment, modeling done by the Cadmus Group, and other factors. Written comments can be filed on the board’s Public Document Search page until 5 p.m. on Dec. 9 under Docket QO20020184.

While the program is on target to meet its net metered residential goal of 150 MW subscribed, it has struggled to attract non-residential and interim subsection grid investments, the latter of which consist of solar installed on brownfield, infill or landfill sites. Of the nearly 289 MW available for net metered non-residential, less than 55 MW was subscribed as of Nov. 10, while just one application has been received for the interim subsection market segment, accounting for a bit more than 5 MW of the 75 MW available.

The BPU says the significantly higher incentives offered under the state Transition Incentive Program likely account for the lackluster interest in net metered non-residential installations under than the ADI program. 

At a stakeholder meeting hosted by the BPU Friday, Scott Elias, director of Mid-Atlantic state affairs for the Solar Energy Industries Association, said most of the non-residential developments that have come online did so under the TI program. However, he believes the “market underperformance” of the ADI is also due to historic price increases in the industry and commercial incentives being too low.

“It’s critically important for the BPU to pay attention to some of the justifications for increased incentive levels,” Elias said. “This year was successful from a solar installation point of view, but most, if not all, of those installations coming online are from the TI program, not the ADI program, and the long-term health of the New Jersey solar industry and our ability to meet New Jersey’s ambitious solar goals are really contingent upon the health of the ADI program.”

Elias noted that, since the start of 2021, costs for commercial installations have increased 15% while residential costs have gone up 12%, largely due to shipping constraints and other supply chain issues stemming from the pandemic and trade instability. He said those factors should be incorporated into the modeling done by the Cadmus Group, which is used to generate a report the BPU relies on to set its incentives. He recommended that the BPU increase incentives for the non-residential segment and at least maintain them at current levels for residential.

“The residential sector is the only sector performing well right now. But labor rates for the residential segment are increasing due to skilled labor shortages, and increased module pricing is increasing residential system prices. And that alone justifies increasing the incentive level — or at the very least maintaining the incentive level, which is my recommendation,” Elias said. “I want to be clear that it would be a mistake if the BPU reduced the residential solar incentive to moderate market activity and throttle development to avoid reaching arbitrary market segment allocation.”

‘So Many Variables’

Fred DeSanti, executive director of the New Jersey Solar Energy Coalition, said he trusts Cadmus to identify proper figures and metrics for its recommendations to the BPU, but he’s concerned the board will choose to throttle residential incentives to push for the rate of installations under the program to remain at the target. He encouraged the BPU to find a flexible approach in the middle of the two options of reducing incentives or leaving them in place and closing the market when subscriptions reach the 150-MW mark.

“That’s of great concern to me because nobody knows what the build rate’s going to be next year. Nobody knows if a recession’s going to come,” DeSanti said. “There’s so many variables out there that no one can predict accurately. I really am concerned about the fact that we could end up getting to a tipping point” with large-scale layoffs for residential solar companies.

Kyle Wallace, vice president of public policy and government affairs at PosiGen, shared those concerns, saying the Cadmus models seem reasonable and aligned to what he’s been seeing in the residential market, with cost estimates increasing 10% to 20% to reflect the rising costs of capital and labor.

“I’m a little concerned now that we’re seeing that success and, from what I see, the ADI succeeded in a lot of its objectives on the residential side. And now we’re seeing that success as kind of a problem and we need to throttle that back,” he said.

The scale of incentives provided to solar projects has long been a point of contention in the formation of New Jersey’s clean energy initiatives, with developers arguing they’re too low compared with past programs and the state Division of Rate Counsel arguing they’ve tilted too far in favor of developers. The SuSI program combines incentives set at rates determined by the BPU with competitive solar renewable energy certificates through the CSI program to reduce the cost to ratepayers while still advancing the state’s aggressive solar goals. (See Proposed NJ Solar REC Program Wins Initial Support.)

Though the state remains behind on reaching its goal of 12.2 GW in solar capacity by 2030, the pace of development has picked up. The state reached a 4 GW milestone in July and as of Oct. 31 had increased to 4.2 GW, according to the latest figures from the state’s Clean Energy Program. (See NJ Faces Challenges as Solar Sector Hits 4 GW.)

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New York State Clean Energy Jobs Hit Record High in 2021

New York’s clean energy sector reached record-high employment in 2021, rebounding from the COVID-19 pandemic much further than the general workforce.

The 2022 New York Clean Energy Industry Report, released last week by the New York State Energy Research and Development Authority, paints clean energy as one of the fastest-growing job classifications in the state.

From 2016 to 2021, the number of people working in such jobs increased 13%, and the number full-time equivalents rose 33%, meaning that not only are there more people working in the field, more of them are devoting all of their time to clean energy-related work.

The NYSERDA report counts 165,055 people working in clean energy statewide in December 2021, 0.8% higher than in December 2019, shortly before the pandemic caused the temporary or permanent loss of 2 million jobs statewide.

The New York State Department of Labor meanwhile counted the statewide nonfarm workforce at 9.29 million in December 2021, down 5.3% from December 2019.

The state’s general workforce has regained additional jobs in 2022 but as of October was still 2.7% below its pre-pandemic total.

With all the policy initiatives and funding being directed to the energy transition this year, it is likely that the clean energy workforce grew again in 2022.

NYSERDA President Doreen Harris said the numbers showed progress not only toward the state’s decarbonization goals but toward building a green economy that benefits the state and its residents.

“We are leading the way with an orderly and equitable transition so that all New Yorkers can participate in our clean energy future, while creating family-sustaining jobs and providing meaningful economic opportunities for our communities all over our great state,” she said in an introduction to the report.

The Alliance for Clean Energy New York, whose member organizations are doing some of the hiring reflected in the NYSERDA report, said the news was good but not surprising.

“The solar and building efficiency sectors are bouncing back after the pandemic, and investment in New York continues,” ACE NY President Anne Reynolds said.

“The report also shows over $10 billion in investment over the last 10 years, and we hope and expect that job growth will continue as more wind and solar power projects reach construction in the coming year. The offshore wind sector and the clean vehicle sectors are especially promising, and we applaud and support efforts to build a clean energy supply chain in New York.”

Details and Statistics

Delving into the report, several details jump out:

  • Some of the biggest job gains were in solar power and in alternative transportation such as battery-electric and hybrid-electric vehicles, registration of which has increased fivefold in five years in New York.
  • Clean-energy installation firms saw the largest job loss when the pandemic hit and the largest rebound as it began to ease.
  • Energy efficiency is the only clean-energy subsector in which employment had not recovered to pre-pandemic levels by the end of 2021, with lighting and HVAC lagging furthest behind.
  • Clean-energy work was credited in the report with supporting the net creation of 13,010 jobs outside the field in 2021, with employers as diverse as software developers, civic organizations and wholesalers expanding their payrolls.

The actual size of the clean-energy workforce in New York at the end of 2021 was likely larger than indicated in the report: The authors note that jobs in nuclear power or electric transmission, while clean and/or integral to the clean-energy transition, are not explicitly labeled “clean” and therefore were not counted.

Other workers split their time between “clean” and “other” duties; work in uncategorized technologies; or work for companies that did not supply information. They also were not counted as “clean.”

Clean energy job growth in New York is expected to ramp up as billions of dollars are spent annually on infrastructure.

Potential Shortcomings

The job growth and the surrounding details are not without some caveats.

The Just Transition Working Group of the New York State Climate Action Council projects an increase of 211,000 clean energy workers from 2019 to 2030, countered by a loss of 22,000 jobs in job sectors that shrink as a result of clean energy’s growth.

The final scoping plan being prepared by the council is expected to address ways to help those displaced workers transition to new jobs.

NYSERDA’s report notes a significant loss of “traditional energy” jobs from 2019 to 2021 but does not ascribe this to the pandemic, the rise of clean energy or any other cause.

Before the pandemic, from 2016 to 2019, the traditional energy workforce in New York showed minor growth (4%) even as the clean energy workforce racked up a 16% gain. However, the traditional energy workforce shrank 14% in 2020 and nearly 1% in 2021 for a total two-year loss of 14.7%, which the clean-energy workforce saw a net 0.8% gain in the same two years.

The NYSERDA report flags other potential sticking points as New York’s government and industries attempt to expand the green workforce.

Nine in 10 employers had difficulty hiring in 2021, particularly in the energy-efficiency field. Workforce shortage already is an issue in New York, which has a lower labor participation rate — the percentage of civilian residents aged 16 and older who are employed or seeking employment — than most states: 60.3% in July 2022, compared with 62.1% nationwide.

Some members of the new green workforce will need specialized skills gained through extensive training and experience. For example, in 2030, New York expects it will need 6,000 people working in offshore wind, an industry that barely exists in the U.S. Two recent studies by the National Renewable Energy Lab lay out the disconnects reported by would-be employers and by would-be employees as they attempt to close the workforce gap.

Meanwhile, other states with ambitious climate-protection goals of their own will be competing for the same workforce; the final scoping plan is expected to acknowledge this and attempt to address it.

NYSERDA meanwhile has committed to spending more than $120 million to address the need for skilled workers, partnering with numerous organizations to create a pipeline for a workforce ranging from entry-level to highly skilled. New York is also creating multiple pathways for traditionally underrepresented groups to be part of the clean-energy transition, as employees or entrepreneurs.

Finally, the report says there needs to be a continued stream of money to make all this happen. It notes that 81% of the $11 billion invested in New York’s clean energy industry came through the public sector from 2011 through 2021, jumping to 91% public-sector funding in 2019-2021. A major infusion of federal money through the Inflation Reduction Act and other streams is expected in the coming years.

Data for the NYSERDA report were drawn from the U.S. Energy and Employment Report, in which more than 1,900 businesses participated. The margin of error is 2.23% at a 95% confidence level.

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Duke: NC Outages from Attacks May Last Until Thursday

More than 33,000 customers remained without power Monday afternoon in Moore County, N.C., following apparent attacks on two of Duke Energy’s (NYSE:DUK) substations over the weekend, and the company said some customers may not see their electricity restored until Thursday.

Ronnie Fields (WRAL-TV) Content.jpg

Moore County Sheriff Ronnie Fields at a press conference Sunday afternoon

| WRAL-TV

The outages began near the town of Carthage about 7 p.m. Saturday. They “shortly thereafter … spread to the greater majority of central and southern Moore County,” Sheriff Ronnie Fields said in a press conference Sunday afternoon. At the height of the outages, more than 45,000 customers had lost power, Duke said in a press release on Sunday; the utility’s outage map has been updated since then to reflect the restoration of some customers as crews work in 24-hour shifts, Duke confirmed to RTO Insider.

‘Pretty Sophisticated Repair’

Crews and sheriff’s deputies investigating the outages discovered “extensive damage” to two substations. Fields said the deputies found evidence indicating that firearms had been used to disable the facilities with “multiple shots” fired by attackers who “knew exactly what they were doing.” Duke said parts of the substations had been damaged “beyond repair,” requiring technicians to completely replace the affected equipment.

Duke spokesperson Jeff Brooks said at Sunday’s press conference that “we are looking at a pretty sophisticated repair with some fairly large equipment,” and that Duke is “pursuing multiple paths of restoration [to] restore as many customers as possible, as quickly as possible.”

The county implemented a 9 p.m.-5 a.m. curfew Sunday night “to best protect our citizens and … businesses of our county,” Fields said. Additionally, most county operations were shut down on Monday except emergency services, along with limited transportation for medical needs. County Manager Wayne Vest said that the county would probably be working “a skeletal operation” through Monday and hope to “get back up to full speed” by Wednesday.

“We faced something [Saturday] night here in Moore County that we’ve never faced before, but I promise you we’re going to get through this, and we’ll get through it together,” Fields said at the press conference. “We’re very united here in Moore County, and we’re not going to let this hold us back, and I can promise you, to the perpetrators out there, we will find you.”

No Known Motivation

Law enforcement has not publicly identified any culprit or motivation for the attacks so far. Fields said that “every available officer” in his office is doing “what we can to try to determine what happened,” with municipal and state officials contributing to the effort, along with the FBI.

The Electricity Subsector Coordinating Council (ESCC) said in a statement Monday that it was “working closely with … law enforcement officials” in their investigation into the attacks. Participants in an ESCC-hosted conference call Monday night included FERC Chairman Richard Glick; Brandon Wales, executive director of the Department of Homeland Security’s Cybersecurity and Infrastructure Security Agency; and Deputy Energy Secretary David Turk.

The ERO Enterprise has also mobilized in response to the incident. SERC Reliability CEO Jason Blake said in a statement that the regional entity is “in close coordination” with Duke, NERC, federal agencies and “appropriate industry members across our 16-state footprint [so that] information is shared as it becomes known and that utilities across our footprint are in a heightened security posture.”

Asked about online rumors that the attacks were meant to shut down a local drag show that was planned to occur Saturday night, Fields said that while “anything’s possible,” the office had “not been able to tie anything back” to the show. Calling the perpetrators “cowards,” he acknowledged that no person or group had stepped forward to take responsibility for the attacks, adding that while the targeting of the power grid “wasn’t random,” he could not say at this point whether the incident should be considered an act of domestic terrorism.

The suspected connection to the drag show was apparently strengthened by a series of provocative Facebook posts by Emily Grace Rainey, a self-proclaimed conservative activist living in Moore County who served in the U.S. Army before resigning amid an investigation of her participation in the Jan. 6, 2021, attack on the U.S. Capitol.

Before the outage began, Rainey had posted the contact information of the drag show’s sponsors, adding, “You know what to do.” After the outage started she wrote, “The power is out in Moore County, and I know why,” later posting a picture of the theater where the show was supposed to be held with a caption saying, “God will not be mocked.”

However, Fields said on Sunday that while deputies had interviewed and “had a word” with Rainey, the lead “turned out to be nothing.” He urged citizens not to post false information online, reminding listeners that it “takes time for us to run that down.”

History of Physical Security Threats

The idea of domestic terrorists attacking the power grid has gained credibility in recent years, especially following the announcement in February that three men had pleaded guilty to planning to damage substations with high-powered rifles. (See FBI: Conspirators Planned Grid Attack to Start Race War.) According to their confessions, the men hoped to spark “confusion and unrest” that would lead to a civil war, inspired by “racially or ethnically motivated violent extremist views.”

The tactics of Saturday’s incident also resemble those of the 2013 attack on Pacific Gas and Electric’s Metcalf substation near San Jose, Calif. In that event, whose perpetrators have never been identified, snipers fired an estimated 150 rounds at transformer radiators in the facility, hitting 10 of the 11 targets and resulting in the loss of about 52,000 gallons of cooling oil. (See Substation Saboteurs ‘No Amateurs’.) The attackers are also believed to have cut underground fiber optic cables near the substation, temporarily disabling phone and 911 service for the area.

Physical security for bulk electric system facilities is addressed in NERC’s Critical Infrastructure Protection (CIP) reliability standards, most notably CIP-014-3 (Physical security), the first version of which was introduced two years after the Metcalf attacks. Asked about security preparations at Duke’s substations on Sunday, Brooks said that “we take security extremely seriously” and that the utility was confident its security requirements were in place at the affected facilities.

“We understand that we’re critical infrastructure, and so we do incorporate multiple layers of security at all of our facilities and across our system to help protect the grid and … restore power when we have disruptions,” Brooks said. “We can’t provide specific information on security measures at a critical facility, but I can say that certainly we’re one of the most highly regulated industries in the country. There’s a lot of protocols around security that we follow, and we believe we followed those in this case.”

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FERC Approves PJM Tariff Revisions for SAA Cost Allocation

FERC on Friday approved revisions to PJM’s tariff that assign the full costs of constructing transmission upgrades necessary for the installation of 7,500 MW of offshore wind in New Jersey to the state (ER22-2690).

The commission affirmed that the proposal conforms with Order 1000’s State Agreement Approach, which permits a state to take on the cost of transmission upgrades for generation projects supporting their public policies. The order allows the installation of an estimated $1.07 billion in grid upgrades to go forward.

FERC found that the tariff revisions would not result in costs being passed to customers outside New Jersey, a concern raised by Long Island Power Authority; New York Power Authority; and three merchant transmission facilities (MTFs), Neptune Regional Transmission System, Linden VFT and Hudson Transmission Partners, which filed a protest as the “MTF Parties” on Oct. 31. (See NY Stakeholders Balk at NJ OSW Cost Allocation.)

The groups argued that the proposed language left open the possibility that a portion of the costs could be indirectly passed on to New York customers through border rate service. They called for more explicit clarifications to be added to preclude that possibility and specify that costs can only be applied to firm point-to-point transmission service.

The commission ruled that PJM adequately addressed those concerns in the revisions, as well as in a settlement agreement that FERC approved the same day between the RTO, its TOs and the MTF Parties, pertaining to point-to-point border rates (ER19-2105).

“We do not agree with MTF Parties that the crediting under the border rate revenue requirement, as proposed in the border rate settlement, may still result in New Jersey SAA project costs being passed through to entities that did not voluntarily agree to pay for those costs,” the commission said. “The border rate settlement specifically provides that the revenue requirement will not include the costs of state agreement public policy projects. Passing on such costs would violate that term.”

The order was unanimously approved, though Chair Richard Glick did not participate. Commissioner James Danly wrote in a concurring statement that he believes the order addresses the MTF Parties’ concerns, but if they continue to believe there are issues with the approved revisions, they should seek a rehearing.

“To the extent to which the MTF Parties find that the language set forth in today’s order fails to allay their concerns, they should pursue rehearing by citing the specific tariff language to which they object and should enumerate the specific misinterpretations that they fear, along with the consequences of those misinterpretations,” he wrote.

The FERC approval now allows for PJM and the New Jersey Board of Public Utilities to shift their attention to filing amendments to the SAA. During a Nov. 4 meeting of the PJM Transmission Expansion Advisory Committee, Assistant General Counsel Pauline Foley said filing those amendments with FERC first required the approval of a cost allocation methodology from the commission.