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November 2, 2024

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Study Shows Uneven Benefits for California, Rest of West in Single Market

The long-awaited results from a key study on the financial impact of an organized day-ahead electricity market in the West indicate that many entities outside California would see more benefits from a two-market outcome while the Golden State has the most to lose from such a split.

And while some industry stakeholders in the Northwest had speculated that the Bonneville Power Administration would be among the losers in a single-market solution, the findings — adjusted by BPA itself — paint a more complicated picture in which the federal agency could be either winner or loser in either scenario.

BPA discussed the findings during an Oct. 23 workshop, one of a series of stakeholder meetings related to its decision whether to join a day-ahead market.

The study was conducted by Energy+Environmental Economics (E3) on behalf of the Western Markets Exploratory Group (WMEG), a loose coalition of 26 transmission-owning entities covering most the Western Interconnection. The WMEG was established in 2021 to evaluate the region’s electricity market options, and its membership quickly expanded alongside broader discussions about the issue.

The WMEG asked E3 to limit the scope of the study’s cost-benefit analysis to variable production costs and energy market prices, while not considering potential investment savings that could be realized from lower capacity needs due to resource and load diversity, the ability to procure resources over a wider geographic area and coordinated regional transmission planning.

“Other market studies have shown those other benefit categories can create 2-10x the impact of production cost savings alone,” E3 noted in a presentation at the workshop.

“We think of our results as being quite conservative and intentionally so,” E3 senior partner Arne Olson said.

The study was structured to show a comprehensive picture of potential benefits for the West as a whole, while also breaking down results for individual utilities. While results were provided to WMEG study participants early this summer, they were not released publicly due to concerns about confidential information related to individual utilities. The BPA workshop offered a wider set of stakeholders and the public their first look into the analysis.

The study’s results are important because they likely will influence the choices of Western utilities weighing whether to join CAISO’s Extended Day-Ahead Market (EDAM) or SPP’s Markets+, decisions that likely will set the course for whether the West ends up with a single RTO in the future or two — or more — organized markets divided by seams.

“Today’s conversations represent just one element of the business case that Bonneville will use in helping arrive at a leaning [toward a market] in 2024,” Andy Meyers, BPA public utility specialist, said during the workshop. “And just to reemphasize something that we’ve shared before but want to make clear: We have not made any proposals about a leaning for 2024 at this point.”

EDAM Bookend vs. Main Split Footprint

In presenting the findings, E3 noted that the study was designed to provide WMEG members with “credible information” about the benefits of joining either EDAM or Markets+.

The results focused on three core scenarios for 2026:

    • A business-as-usual (BAU) case assuming continuation of the West’s current bilateral market for day-ahead energy combined with the existing footprint of CAISO’s Western Energy Imbalance Market (WEIM) for real-time trading. The BAU assumes no entities join either day-ahead market, E3’s Jack Moore said during the workshop.
    • An “EDAM Bookend” case that assumes a single combined day-ahead and real-time market that covers the entire Western Interconnection, excluding the Canadian provinces of British Columbia and Alberta. This scenario assumed no charges for wheeling power within the system, Moore said.
    • A “Main Split Footprint” that assumes participation in the EDAM by CAISO, PacifiCorp, Los Angeles Department of Water and Power, Balancing Authority of Northern California, Turlock Irrigation District and Imperial Irrigation District, while the rest of the West (excluding Alberta) participates in Markets+. This scenario assumed charges at the seams between the two markets, Moore said, noting that it was difficult to know what would be required to coordinate between the two, given that they wouldn’t be full RTOs.

Compared with the BAU case, the study found, the EDAM Bookend scenario results in $60 million in annual savings for the West as whole. But in breaking the results down by balancing authority area, the study indicates that California entities would realize $80 million in savings in that scenario, while WMEG members outside California would see a $20 million loss compared with the status quo. And results even vary among those WMEG members, Moore noted, with some realizing net benefits while others suffer losses at varying levels. Exact results for individual utilities must remain confidential, he added.

The cost-benefit outcomes get flipped in the Main Split Footprint case. In the scenario with two markets, West-wide costs increase by $221 million compared with BAU, with California entities taking a $247 million hit. Most of those increased costs stem from California’s need to fire up relatively expensive internal natural-gas-fired generation to substitute for cheaper imports, Moore said.

However, the Main Split market scenario showed $26 million in savings for WMEG members in general, although some members would face losses compared with the BAU case.

“The trade-off has different effects for different entities,” Moore said.

E3 said the results indicate the importance of “critical” transmission lines between the Northwest and Southwest in the Main Split case, where transactions would depend heavily on paths in Idaho, Nevada and Montana to avoid wheeling through the EDAM.

“Northwest to Southwest becomes a pretty significant pinch point” in the Split scenario, Moore said. Olson added that the transmission constraints in that scenario also could depress energy prices in the Northwest and reduce the value of the region’s flexible resources.

BPA Findings

Presenters at the workshop saved the most anticipated findings — BPA’s results — for last.

The study’s initial findings showed BPA seeing financial losses relative to BAU in both the EDAM Bookend and Main Split scenarios, largely because of a sharp decline in transmission wheeling charge revenues within its territory under either market. E3 assumed that a more robust market would undercut the need for customers to secure wheeling contracts from BPA, reducing those revenues from $251 million in the 2026 BAU case to $5.5 million in EDAM and $31.8 million in Main Split.

But BPA Director of Market Initiatives Russ Mantifel said the agency drew a different conclusion about the impact of day-ahead market participation on those charges. Most wheeling revenues are derived from long-term contracts, the agency found, and counterparties are likely to maintain those agreements for the foreseeable future.

By restoring wheeling revenues to expected 2026 levels, BPA and E3 estimated the agency’s annual net benefits would rise to $134.7 million in the EDAM Bookend scenario and $28.8 million in the Main Split scenario.

“I think the wheeling revenue numbers in the study do a good job of articulating something that we as a region and that Bonneville has intuitively known, which is, for Bonneville, there’s probably some amount of transmission that for us, is probably long-term, firm point-to-point transmission that’s purchased and rolled over and over and over again,” Mantifel said.

But it was clear the recalibrated study results showing how BPA could benefit from both day-ahead market scenarios were not a clincher for either market.

“There’s no study that tells you exactly what you’re supposed to do,” Mantifel said. “These are big decisions with a lot of different complicated factors, and so Bonneville is going to try to utilize all this information, but we’re going to be based in the sort of decision framework” the agency has previously laid out for choosing which market to join.

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New York Announces Renewable Energy Projects Totaling 6.4 GW

Twenty-five renewable energy projects totaling 6.4 GW have been selected for development in New York, including three new offshore wind farms with a combined 4 GW of capacity.

The projects chosen for the conditional contract awards Tuesday now enter the negotiation process. If they all are successful, they are expected to create 8,300 jobs and spur $20 billion in economic development.

Gov. Kathy Hochul called it the largest-ever renewable energy investment by a state.

N.Y. Gov. Kathy Hochul | New York Governor’s Office

“Today, we are taking action to keep New York’s climate goals within reach, demonstrating to the nation how to recalibrate in the wake of global economic challenges while driving us toward a greener and more prosperous future for generations to come,” she said.

The onshore projects are a mix of technologies totaling 2,410 MW of capacity: 14 new solar farms, one with co-located storage; six repowered wind farms; one new wind farm; and one return-to-service hydro project. The largest is a 401.6-MW solar farm in central Pennsylvania that will feed into the New York grid.

The offshore component is:

    • Attentive Energy One — 1,404 MW developed by TotalEnergies, Rise Light & Power and Corio Generation;
    • Community Offshore Wind — 1,314 MW developed by RWE Offshore Renewables and National Grid Ventures; and
    • Excelsior Wind — 1,314 MW developed by Vineyard Offshore (Copenhagen Infrastructure Partners).

Just 12 days earlier, the state Public Service Commission rejected inflation-related cost adjustments for developers of 90 contracted projects that had said they might not be able to begin construction without more money.

These total more than 12 GW and constitute a large percentage of New York’s vaunted renewable energy pipeline — including almost the entire offshore wind pipeline, which is particularly hard hit by cost increases and supply constraints.

One of New York’s five planned offshore wind farms, the 132-MW South Fork, is under construction and may become the nation’s first utility-scale offshore wind project to generate power.

Developers of the other four planned facilities, totaling 4,230 MW, may need to cancel their contracts and attempt to rebid in future solicitations.

The New York State Energy Research and Development Authority said the strike price for the three offshore wind projects announced Tuesday could vary depending on price indices, federal incentives and other factors. But it is expected to be $96.72/MWh in 2023 dollars as a weighted average and $145.07 as a nominal weighted average over the 25-year contract terms.

This would yield an average charge of $2.93/month for New York electric ratepayers over that period, NYSERDA said. And it is less than the increase developers of the four contracted offshore wind projects had been seeking. In its comments to the PSC on the requests, NYSERDA said they would have resulted in a weighted average of $167.25/MWh for the four contracted projects.

A couple of hours after the PSC rejected the requests Oct. 12, Hochul announced a new 10-point plan to “Expand a Thriving Large-Scale Renewable Industry.” Given recent events, “thriving” might be a stretch, and most of the 10 points were policies and initiatives already in place.

However, the first of the 10 points promised an announcement on contract awards, and she followed through 12 days later — acknowledging the setbacks in passing but focusing on the promise of the next chapter.

Economic Goals

Hochul announced the tentative contracts in an IBEW Local 3 training facility where some of the young people who will build the state’s clean energy infrastructure are learning their trades.

New York’s statutory goals include an energy portfolio that is 70% renewable by 2030 and 100% zero emissions by 2040. It is struggling to stay on schedule and simultaneously using the energy transition as a vehicle for social justice and economic development — particularly in offshore wind, a new industry in which it hopes to become a leader.

The domestic supply chain stands to gain two significant new components in New York with the three offshore wind projects chosen for contracts: a nacelle factory and a blade factory operated by General Electric and subsidiary LM Wind Power USA, respectively. Plans for both were announced this year but were conditioned on the companies securing enough orders to warrant construction.

Hochul announced $300 million in state funding to build the facilities, which she said would attract $668 million in private financing.

National Climate Adviser Ali Zaidi joined Hochul for the event, which he called an investment in the neglected middle class as much as in the environment.

renewable energy

White House Climate Adviser Ali Zaidi | New York Governor’s Office

And that is not just in New York, he said: Already, more than 4,000 contracts have been signed in 47 states to supply the nascent U.S. offshore wind industry.

It is, Zaidi said, “an economy that is being built not just to put steel in the ground — or, in the offshore industry, steel in the water — but really steel in the spine of the American middle class.”

All of the projects chosen in New York’s latest round of awards will be eligible for tax credits of up to 50%, he added — if they use domestic components, train apprentices, create jobs in disadvantaged communities and pay prevailing wages.

The Alliance for Clean Energy New York, a trade group that represents the developers chosen for contracts, said the projects would have the economic and environmental benefits the state is trying to achieve.

Fred Zalcman, director of the New York Offshore Wind Alliance, called the contract awards a good change of direction from recent news. “Today’s announcement, awarding three contracts for more than 4,000 MW of offshore wind generation, shows that New York is prepared to double down on this clean, renewable and job-creating resource, and will go a long way towards instilling confidence in a market that has recently faced tremendous headwinds,” he said. “We look forward to working with the governor and other stakeholders in getting these early-stage projects to the finish line.”

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California Far Outpacing Clean Truck Targets

Truck manufacturers have been racking up zero-emission vehicle credits in advance of California’s Advanced Clean Trucks (ACT) rule taking effect with model year 2024, a new report shows.

About 7,900 zero-emission trucks from model years 2021 and 2022 have been sold in California, according to a report from the California Air Resources Board (CARB). Another 1,000 ZEV trucks are expected to be sold from those model years based on participation in the Hybrid and Zero-Emission Truck and Bus Voucher Incentive Project.

The combined total is about 60% more than the 5,500 zero-emission trucks that CARB expects manufacturers to need to meet the model year 2024 quota. And that doesn’t include zero-emission truck sales from model year 2023.

“Helping the businesses that rely on trucks to transport goods across the state switch to zero emissions is key to achieving a clean air future, and the data show that progress is well underway,” CARB Executive Officer Steven Cliff said in a statement.

Cliff said the figures indicate trucking businesses are interested in zero-emission vehicles, and manufacturers are stepping up to meet the demand.

Rivian led the way in model year 2022, with 5,286 zero-emission trucks sold in California. Ford followed with 1,686 ZEV trucks sold — out of a total of 28,606 medium- and heavy-duty vehicles delivered for sale in the state.

GM delivered 24,500 trucks for sale in model year 2022, but none of them were zero-emission, according to CARB.

In the Class 7-8 tractor category, Volvo sold 64 zero-emission vehicles from model year 2022. Paccar sold 16, followed by Daimler and Nikola Motor, with 13 each.

For model year 2022, 104,558 medium- and heavy-duty trucks were delivered for sale in California, including 7,639 zero-emission trucks, or 7.3%.

Advanced Clean Trucks, which CARB adopted in 2020, requires truck manufacturers to sell an increasing percentage of zero-emission vehicles in California starting in 2024.

The sales requirement varies based on the weight class of the truck. For model year 2024, ZEVs must account for 5% of Class 2b-3 trucks; 9% of Class 4-8 trucks; and 5% of Class 7-8 tractors. CARB said that on average, about 6% of trucks sold will need to be ZEVs in model year 2024.

Truck manufacturers may earn early credits for ZEV sales in model years 2021 through 2023, to be banked for use in later years or sold to other truck makers. The early credits are good through the 2030 model year.

Truck manufacturers that sell 500 or fewer vehicles a year in California are exempt from ACT but may opt to generate ZEV sales credits that can be banked or transferred.

Zero-emission truck sales generate credits that increase with the weight class of the vehicle. For model years 2022, truck manufacturers earned 6,414.7 credits, bringing the total for 2021 and 2022 to 7072.6 credits.

In July, CARB announced an agreement with leading truck manufacturers called the Clean Truck Partnership. (See CARB, Manufacturers Partner to Support Clean Truck Rules.)

The manufacturers agreed to meet California’s vehicle standards even if they’re challenged in court.

Under the Clean Truck Partnership agreement, truck manufacturers committed to selling as many zero-emission trucks as reasonably possible in California and other states that have adopted ACT.

The agreement came after a coalition of 19 states petitioned a federal appellate court in June to review EPA’s approval of Advanced Clean Trucks. Last month, a briefing schedule was filed in the case, with final briefs due in April.

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White House Announces Regional Tech Hubs to Spur Innovation

The White House and the Department of Commerce on Monday announced the designation of 31 “Tech Hubs” around the country, including a handful focused on the energy transition.

It marks the first phase of the Tech Hubs program, which is designed to drive regional innovation and job creation by strengthening a region’s capacity to manufacture, commercialize and deploy technology that will advance U.S. competitiveness. The 31 were picked from nearly 400 applications and are each eligible for up to $75 million in grants.

“Our Tech Hubs Program is fundamental to that mission and will supercharge innovation across the nation by spurring cutting-edge technological investments and creating 21st century job opportunities in people’s backyards,” Commerce Secretary Gina Raimondo said. “Each of these consortia will help us ensure the industries of the future — and their good-paying jobs — start, grow and remain in the United States.”

The program was authorized by the CHIPS and Science Act, which was signed into law in August 2020. The 31 hubs focus on a range of industries including semiconductors, clean energy, critical minerals, biotechnology, precision medicine, artificial intelligence and quantum computing.

The energy-related Tech Hubs include:

    • The Gulf Louisiana Offshore Wind (GLOW) Propeller, meant to grow a domestic offshore wind supply chain using Louisiana’s existing energy infrastructure, ports and shipbuilding network;
    • The Intermountain-West Nuclear Energy Tech Hub, which aims to position Idaho and Wyoming as global leaders in small modular reactors and advanced nuclear energy to contribute to a clean energy future;
    • The South Carolina Nexus for Advanced Resilient Energy, led by that state’s Department of Commerce and including Georgia, which aims to be a global leader in advanced energy by developing, testing and deploying exportable electricity technologies;
    • The South Florida Climate Resilience Tech Hub, led by the Miami Dade County Innovation and Economic Development Office, which aims to advance its global leadership in sustainable and resilient infrastructure solutions for the climate crisis; and
    • The New Energy New York (NENY) Battery Tech Hub, based out of the State University of New York Binghamton and meant to bolster battery technology development and manufacturing across the value chain.

Two others are focused on the country’s critical minerals supply chain. The Nevada Lithium Batteries and Other EV Material Loop is led by the University of Nevada, Reno, and it aims to build a self-sustaining and competitive lithium lifecycle cluster, spanning extraction, processing, manufacturing and recycling.

The University of Missouri is leading the Critical Minerals and Materials for Advanced Energy Tech Hub, which is aiming to position south-central Missouri as a global leader in critical minerals processing to provide the materials needed to support battery technology.

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NextEra’s Renewables Unit, FPL Key Performance

NextEra Energy said Tuesday its renewables subsidiary had its best origination quarter in its history, adding about 3.25 GW to its backlog.

NextEra Energy Resources’ (NEER) backlog now exceeds 21 GW, net of projects placed in service. The clean-energy unit placed a little over 1 GW of resources into service.

NEER and Florida Power & Light, the nation’s largest electric utility, added 65,000 more customers from a year earlier, helping NextEra beat Wall Street estimates.

NextEra reported third-quarter earnings of $1.219 billion ($0.60/share), compared to $1.696 billion ($0.86/share) for the same period a year ago.

“We will be disappointed if we are not able to deliver financial results at, or near the top of, our adjusted earnings per share expectations ranges in each year through 2026,” CEO John Ketchum told financial analysts during the company’s third-quarter conference call.

“The strength of both businesses … combined with our competitive advantages and strong balance sheet, positions us to continue creating long-term value,” he said.

NextEra’s share price closed at $55.12 Tuesday, a gain of $3.60 and nearly 7% on the day.

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MISO Likely to Pay $815K for NERC Violations

MISO has agreed to pay an $815,000 penalty for a pair of NERC violations committed over the summer.

MISO Vice President of Operations Renuka Chatterjee said MISO addressed the issues quickly while self-reporting them to ReliabilityFirst’s enforcement group. The grid operator agreed to ReliabilityFirst’s non-negotiable settlement proposal in late August.

Chatterjee said ReliabilityFirst determined the severity of the violations, and MISO would have faced a higher penalty if it hadn’t admitted the violations.

“MISO agreed to settle and admit the violations to minimize risk of increased penalty amount for MISO stakeholders,” Chatterjee said at an Oct. 18 Advisory Committee teleconference.

MISO said both incidents violated standard IRO-008-2, which governs operational analyses and real-time assessments.

MISO reported it discovered missing data while it was updating models in its day-ahead analysis for an unspecified day. The data is tied to contingency scenarios the RTO runs to prepare for the next operating day.

The second breach came when MISO discovered it lapsed in monitoring a 115-kV tie-line because it had been erroneously marked as external to the grid operator. MISO said it corrected the issue and has since implemented a procedure to reflect a change in seasonal ownership of the constraint.

“An after-the-fact analysis with updated ratings also showed that this non monitoring did not represent a system operating limit violation,” MISO added.

ReliabilityFirst has forwarded the penalty agreement to NERC for approval. The agreement then goes before FERC for authorization.

After FERC approval of the agreement, MISO will make a section 205 filing to recover the penalty from market participants. MISO said it anticipates FERC will issue an order on the settlement in late November or early December. In the anticipated timeline, MISO said it will recover the penalty sometime in the first half of 2024.

MISO said it maintained reliable operations throughout both events. The grid operator said, “at no time was there any harm to the bulk electric system.”

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NERC Board Approves Cold Weather Standards

In a special meeting Monday morning, NERC’s Board of Trustees agreed to adopt two new reliability standards for extreme cold weather, leaving approval by FERC as the last step before they become enforceable.

Trustees accepted EOP-011-4 (Emergency operations) and TOP-002-5 (Operations planning), both of which were produced by Project 2021-07 (Extreme cold weather grid operations, preparedness and coordination). NERC began the project in November 2021 to address the recommendations of the FERC-NERC joint report into the winter storms that struck Texas and the South Central U.S. that year. (See FERC, NERC Release Final Texas Storm Report.)

The new standards are part of the second phase of the project; FERC already approved two standards produced in phase 1 — EOP-012-1 (Extreme cold weather preparedness and operations) and EOP-011-3 (Emergency operations) — in February. (See FERC Orders New Reliability Standards in Response to Uri.) With the conclusion of phase 2, the team for Project 2021-07 will move into the third and final phase to address further changes to EOP-012-1 that FERC directed this year.

EOP-011-4 updates its predecessor with requirements for transmission operators (TOPs) and balancing authorities (BAs) to update their operating plans to address emergencies arising from “the critical natural gas infrastructure loads that fuel a significant portion of … generation.”

Under the new standard, TOPs would have to prioritize critical natural gas loads in manual and automatic load shedding; they also would have to identify entities that are required to assist with load shedding, and those entities would be required to develop a load-shedding plan that prioritizes critical natural gas infrastructure loads. BAs also would be required to exclude critical natural gas infrastructure loads from their demand response programs during periods of extreme cold weather.

TOP-002-5 would require each BA to develop an operating process for its area that addresses preparations for and operations during extreme cold weather periods. The process must contain methodologies for identifying the periods in which it applies, for determining adequate reserve margins during these periods, and for developing a five-day hourly forecast that considers weather, demand, resource commitment, and capacity and energy reserve requirements.

During Monday’s meeting, Trustee Jim Piro asked Soo Jin Kim, NERC’s vice president of engineering and standards, how the team decided on the threshold for determining “what is an acceptable reserve margin calculation.” Kim replied that the team felt it was important to encourage entities to get plenty of lead time ahead of any possible events.

“I know some of the entities did push for a three-day look-ahead with regards to adequate reserve margins, [but] at the end of the day, we asked that the entities [try to] coordinate as [far] ahead as possible. It does allow for future coordination,” Kim said.

Board Chair Ken DeFontes added that he felt it “particularly important” that utilities were required to think about how their load-shedding programs might impact the natural gas system and adjust their plans to ensure those impacts are as small as possible.

Following the unanimous vote for approval, DeFontes confirmed with Kim that the third phase should be complete in the beginning of 2024.

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FERC Approves ERO 2024 Budgets

FERC last week unanimously approved the 2024 business plans and budgets for NERC, the regional entities and the Western Interconnection Regional Advisory Body (WIRAB), though Commissioner James Danly said in a concurrence that he would like to see “a significant improvement in the speed and agility” of the ERO’s response to energy reliability risks (RR23-3).

NERC’s final budget, approved by the organization’s Board of Trustees in August, stands at $113.6 million, an increase of $12.6 million (12.5%) over its 2023 budget. (See “2024 Budget Approved,” NERC Board of Trustees/MRC Meeting Briefs: Aug. 16-17, 2023.) The RE budgets are also set to grow:

    • Midwest Reliability Organization — $24.9 million (up from $23.1 million);
    • Northeast Power Coordinating Council — $22.1 million (from $19.4 million);
    • ReliabilityFirst — $31.3 million (from $28 million);
    • SERC Reliability — $32 million (from $28.2 million);
    • Texas Reliability Entity — $19.2 million (from $17.7 million); and
    • WECC — $35.4 million (from $31.8 million).

In contrast, WIRAB’s budget for next year is set to shrink from $883,520 to $831,492.

The total assessment for the ERO is set at $216 million, comprising $97 million for NERC ($87.1 million from U.S. entities, $9.5 million from Canadian entities and $346,814 from Mexican entities), $128.3 million for the REs and $580,417 for WIRAB.

In its filing, NERC also outlined anticipated funding sources outside of the assessment, such as $10.1 million of third-party funding for the Electricity Information Sharing Analysis Center’s (E-ISAC) Cybersecurity Risk Information Sharing Program; $1.8 million in fees for users of the System Operator Certification Program; and $1.1 million in interest and investment income.

NERC’s biggest spending increases next year are expected to be in personnel (+13.4%), meeting and travel (11.5%) and operating (15.7%). The organization plans to hire an additional 14.3 full-time equivalent (FTE) positions next year, bringing its total staffing level to 251.1 FTEs.

The increased meeting and travel costs reflect “a return to pre-pandemic levels of in-person meetings and travel … while continuing to utilize the efficiencies of virtual meetings where appropriate,” NERC said. The organization attributed its raise in operating expenses to increases in spending on contractors and consultants, along with increased software license and support costs.

A significant number of the added FTEs, 4.7, are to handle the Interregional Transfer Capability Study (ITCS), which Congress ordered NERC and the regional entities to perform in this year’s Fiscal Responsibility Act. (See Lawmakers, White House Promise More Work on Permitting After Debt Deal.) The ERO is required to submit the report to FERC by Dec. 2, 2024, imposing costs on NERC and the REs that were not envisioned in their initial budget drafts.

In order to avoid raising the assessment proposed in its draft budget, NERC proposed to fund the $2.6 million required for the ITCS costs by drawing $1.3 million from the Assessment Stabilization Reserve, for non-personnel costs, and the remainder from the Operating Contingency Reserve. Drawing on the ASR in this way requires an exception under section 1107 of NERC’s Rules of Procedure; FERC granted the request.

The commission also agreed to permit an exception under section 1107 to allow NPCC and SERC to deposit penalty funds received between July 1, 2022, and June 30, 2023, amounting to $535,018 and $6.6 million, respectively, into their ASRs; and to allow MRO to use $1.2 million from its ASR and $119,026 of penalties collected before June 30, 2022, to reduce its 2024 assessments.

Finally, FERC approved WECC’s request to use up to $250,000 from the funds donated by Peak Reliability upon its dissolution in 2019 to support an expanded trial of an energy market simulation platform and the acquisition of electromagnetic transient simulation software.

In his concurrence, Danly said he is “not convinced” that the commission is “really getting value for the money [NERC is] spending to address known or emerging reliability risks.” He noted the commission’s separate order on developing standards for inverter-based resources, a reliability risk that he said “we have known about, and been actively discussing, since at least 2016.” (See FERC Orders Reliability Rules for Inverter-Based Resources.)

Despite this long debate, he said, the proposed standards would not be required to take effect until 2030. “Up to nearly 14 years is a very long time, and the reliable operation of the [power grid] remains imperiled until these risks are adequately addressed. We are as responsible for this situation as NERC,” Danly wrote, noting that the proposed 2024 budget is 12.5% higher than that for 2023, which was 13.7% higher than 2022.

“Will this increased funding actually help expedite the development and implementation of needed NERC reliability standards? Based on NERC’s recent track record, I have my doubts,” he concluded.

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NY Drills Down on Statutory Meaning of ‘Zero Emissions’

The New York Department of Public Service is once again seeking input on what exactly “zero emissions” means.

More precisely, it is trying to find an acceptable, expanded definition as the state’s statutory goals for emissions reductions appear increasingly hard to reach. And it is asking for legal interpretations as it goes through the process.

The Public Service Commission opened the contentious conversation in May when it acknowledged that favored technologies such as wind and solar might not be enough to achieve 70% renewable energy by 2030 and 100% emissions-free energy by 2040 (Case 15-E-0302).

This suggested a possible fallback on technologies opposed by many clean energy advocates, such as hydrogen, bioenergy and carbon capture.

The number and range of comments filed by the late August deadline was not surprising, given the potential impacts on the business plans of energy developers and on the health and wallets of state residents.

The Department of Public Service on Oct. 20 issued a series of follow-up questions to clarify the points made in the first round of questions.

The issue is even more salient now than when the PSC started the ball rolling in May: Developers of much of the state’s clean energy pipeline — 90 projects totaling more than 12 GW — said in June they might not be able to begin construction without more money. And the PSC voted unanimously Oct. 12 to reject their request for an inflation adjustment.

Renewable energy had been coming online slowly in New York even before this turn of events, and NYISO has been warning with growing urgency about a potential generation shortfall as fossil fuel plants are retired.

The DPS on Oct. 20 issued six new questions and asked for legal interpretations rather than policy considerations:

    • State Public Service Law and the landmark Climate Leadership and Community Protection Act of 2019 do not define “emissions” when they call for zero emissions. Should that be read as all air pollutants, just greenhouse gas emissions or something else?
    • Should the PSC read “zero emissions” and “net-zero emissions” as distinct terms, and if so, how should it characterize and apply the distinction?
    • The state Department of Conservation has counted biomass combustion emissions for electrical generation on a gross rather than net basis; should that inform the PSC as it defines zero emissions for the statewide electrical demand system?
    • What discretion does the CLCPA offer DPS staff as it specifies parameters such as which elements of the lifecycle of a given emissions source should be counted toward an emissions limit, and the threshold level at which emissions from that source are disqualifying?
    • Public Service Law designates fuel cells as a renewable energy system if they do not use a fossil fuel resource while generating electricity. What significance does this have for characterizing fuel cells that consume hydrogen, biogas, renewable natural gas or other non-fossil fuels as “zero emissions?”
    • “Statewide electrical demand system” is not defined in the CLCPA or elsewhere. What definitions does the law support, and how do they relate to electricity generated outside of the state or behind the meter?

Comments are due by Jan. 19.

A two-day technical conference on the matter is scheduled in-person and virtually Dec. 11-12.

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Overheard at Connecticut Power and Energy Society’s ‘Future of Energy’ Conference

HARTFORD, Conn. — Hartford Mayor Luke Bronin opened Connecticut Power and Energy Society’s “Future of Energy” conference with a call to speed up the pace of the energy transition, while also praising the state’s accomplishments.

“We’ve got to go so much faster if we’re going to get where we need to go,” Bronin said. “We know how much is at stake.”

Commissioner Katie Dykes of the state’s Department of Energy and Environmental Protection said climate change is stressing the state’s infrastructure, which has endured the effects of flooding from heavy and persistent rains that have bombarded the northeast this year.

Dykes said economywide decarbonization relies on decarbonizing the electric sector — which will in turn relies on the successful deployment of offshore wind — while also keeping electric rates as affordable as possible.

“There is a ceiling on what ratepayers can afford when it comes to offshore wind at this moment,” Dykes said.

For developers preparing bids for the state’s upcoming offshore wind procurement, “it’s important to keep price in mind,” Dykes said, expressing her hope some developers may be willing to take a lower profit margin to help the industry off the ground.

She expressed her hope that coordinated procurements between Connecticut, Rhode Island and Massachusetts, along with indexing provisions in the contracts to account for inflation, will help overcome the industry’s recent struggles. (See Mass., RI, Conn. Sign Coordination Agreement for OSW Procurement.) In early October, Avangrid reached an agreement to back out of its contract with two Connecticut utilities for the 804-MW Park City Wind project, calling it “unfinanceable.” (See Park City Wind to Cancel PPAs, Exit OSW Pipeline.)

Dykes added that the state will continue to think creatively about improving the procurement process, and is considering holding regular, annual solicitations and dividing wind and related transmission procurements into “separate but synchronized” processes.

Paul Lavoie, Connecticut’s chief manufacturing officer, said offshore wind presents “a once-in-a-generation opportunity for us to stand up a new industry,” and that the state needs to increase its workforce development to prepare for the opportunity.

“The number one problem in Connecticut is the lack of a skilled and available workforce,” Lavoie said, adding this likely will remain the top issue for industry and manufacturing for the next 20 years.

He added that collaborating with neighboring states will allow each state to play to its strengths and minimize workforce shortages in any given state, citing coordinated procurements as an example.

“When it comes to the offshore wind industry, we can no longer be competitive — we have to be collaborative,” Lavoie said. “If Massachusetts has a strength, let Massachusetts have that work. If Connecticut has a strength, let Connecticut have that work.”

Lavoie also connected workforce shortages with the shortage of affordable housing in the state. “We don’t have enough places for people to live,” he said.

A local supply chain also could help insulate against future inflation increases, said Per Onnerud of Cadenza Innovation, a company that develops lithium-ion battery storage.

“Unfortunately, our supply chain right now is in China, for the lithium industry,” Onnerud said. “We need to lessen our relationship with China. We need to decouple, but we also cannot completely go cold turkey … It’s about striking a balance.”

Deputy Commissioner Robert Hotaling of the Connecticut Department of Economic and Community Development added that the state must focus on bringing education and employment opportunities to diverse and underserved communities.

“Diverse workforces drive innovation,” Hotaling said. “People from different backgrounds have different ideas, which lead to diverse solutions.”