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November 17, 2022December 12, 2023

NERC Board of Trustees/MRC Briefs: Nov. 15-16, 2022

[EDITOR’S NOTE: This story previously incorrectly stated that the MRC would attend next May’s joint meeting in D.C. with the Board of Trustees virtually. While other stakeholders will attend the meeting virtually, the MRC will meet in-person along with the board.]

NEW ORLEANS — Stakeholders from across the ERO Enterprise gathered in New Orleans this week for the meeting of NERC’s Member Representatives Committee and Board of Trustees.

At Wednesday’s board meeting, NERC CEO Jim Robb joked that it was “great to be here in person and not watching from … the 23rd floor,” referring to his absence from the last MRC and board meetings in Vancouver. Robb tested positive for COVID-19 while on site and, in accordance with NERC’s policy — which was also in place this week — remained in his room while listening to the events via webcast. (See “Vancouver Hosts Return to In-person Meetings,” NERC Board of Trustees/MRC Briefs: Aug. 17-18, 2022.)

Board Makes Meeting Changes Official

In his remarks to the MRC meeting on Tuesday, NERC board Chair Ken DeFontes confirmed that the organization has decided to implement the new meeting schedule previewed at last week’s meeting of its Corporate Governance and Human Resources Committee. (See NERC Still Considering Scaling Back Board Meetings.)

Under the planned schedule, the MRC and board will hold two fully in-person meetings next year: one in February in Tucson, Ariz., and another in August in Ottawa, Canada. David Morton, chair of the Canadian Association of Members of Public Utility Tribunals, described the meeting in Ottawa as an important opportunity for the board to communicate with Canadian regulators, while the February meeting will include a stakeholder dinner, which DeFontes called “a chance for us to [thank] and recognize some key contributors.”

For the May meeting, which is being held at NERC’s new headquarters in D.C., the ERO plans to conduct a hybrid format in which only the board and MRC will meet one-on-one, while other stakeholders attend virtually. The last gathering of the year will be held entirely online; only the board is expected to meet for now, although DeFontes said a virtual MRC meeting could be arranged “should there come a need for some [actions] by the MRC.”

The new schedule is intended to reduce the costs of attending meetings for the ERO by easing the planning burden for NERC staff and eliminating two meetings’ worth of travel costs for most stakeholders. NERC staff told ERO Insider that the organization hopes the communication technology upgrades at its newly renovated D.C. office will improve the experience for those attending the May meeting virtually.

MRC Leadership Election

The MRC unanimously chose Jennifer Flandermeyer of Evergy and John Haarlow of the Snohomish County Public Utility District to serve as chair and vice chair, respectively, for 2023. Flandermeyer, who is currently vice chair, will take over the top spot from ElectriCities CEO Roy Jones.

BC Hydro’s Paul Choudhury, who chaired the MRC in 2021, briefly took over management of the meeting when Flandermeyer and Haarlow left the room during the vote. Because the MRC’s meetings were held virtually during Choudhury’s tenure, Flandermeyer joked that the opportunity to run the gathering in-person was “a gift” for the former chair.

Nominations are open through Thursday for sector representatives to replace those whose terms will expire in February 2023. The election will be held Dec. 14 to 23.

Standards Actions

The board voted unanimously to adopt the new reliability standard CIP-003-9 (Cybersecurity — security management controls), which will now be sent to FERC for approval.

CIP-003-9 is the product of Project 2020-03, set up by NERC in 2020 to address the risk of low-impact cyber assets with remote electronic access connectivity on the bulk electric system, as recommended in the ERO’s Supply Chain Risk Assessment report in 2019. NERC’s Vice President of Engineering and Standards Howard Gugel explained that the new standard, an update to CIP-003-8, adds a requirement for utilities to include “vendor electronic remote access security controls” in their cybersecurity policies, along with guidelines for how those controls are to be implemented.

Gugel also brought to the board for approval a new white paper drafted by the organization’s Low Impact Criteria Review Team. Gugel reminded the board that they authorized the team to examine “the issue of coordinated attacks on low[-impact cyber assets] and whether or not additional controls should be placed around [them] to help protect against coordinated attacks.”

The paper was posted for industry comment earlier this year and garnered “very supportive comments,” Gugel said. Its recommendations include further revisions to NERC’s Critical Infrastructure Protection (CIP) standards to improve user authentication procedures and security, new security guidelines around protection of communications with and between low-impact assets, and continuous monitoring of risk reports from the Electricity Information Sharing and Analysis Center. The board voted unanimously to accept the white paper.

In addition, the board accepted NERC’s Reliability Standards Development Plan (RSDP) for 2023-2025. The RSDP is “a snapshot of all of the projects that we have in place at this point,” Gugel said, which the organization has to file with regulatory agencies each year.

Along with the approvals at this meeting, Robb noted in his opening remarks the recent passage of NERC’s new cold weather standards EOP-012-1 (Extreme cold weather preparedness and operations) and EOP-011-3 (Emergency operations), which the board approved in a virtual meeting last month. (See NERC Board Approves New Cold Weather Standards.) The CEO thanked NERC’s standards developers for their work, which he called a “very important first step” in addressing the ongoing challenges posed by climate change.

GADS Expansion Gets Board OK

John Moura, director of reliability assessment and performance analysis at NERC, brought to the board a request to approve an update to the Generating Availability Data System (GADS), which trustees approved. The update will expand GADS, which currently covers conventional generation resources and some wind facilities, to include solar facilities and grid-connected energy storage, along with patching some gaps in its wind coverage.

In his presentation, Moura explained that while the behavior of traditional generation resources under a wide range of circumstances is well understood, the rapid expansion of renewable generation resources on the grid has outpaced grid planners’ understanding of their performance characteristics. The expansion of GADS is meant to give NERC’s assessment staff more insights into these assets and how they might react under pressure.

“To forecast energy assurance in the future, understanding the performance of the generation fleet that we have is fundamental; it is a must when we’re considering the reliability assessment obligations of the ERO,” Moura said.

November 17, 2022

Impact of NJ’s Storage Plan on Overburdened Communities Questioned

New Jersey’s Board of Public Utilities (BPU) needs to enhance and more sharply target its Storage Incentive Program (SIP) if the agency wants to stimulate development in historically polluted, overburdened communities, speakers at a public hearing said Monday.

The SIP cites a program goal of supporting overburdened communities with storage projects that provide “energy resilience, environmental improvement and economic opportunity benefits.”

The goal is one of seven in the SIP proposal. It suggests that placing storage resources in overburdened communities would provide benefits, such as enhanced resilience, while reducing emissions and offsetting the use of backup generation options such as peaker plants during emergency conditions.

But several speakers in the three-hour forum, which attracted more than 250 registrants and more than two dozen speakers, said the program needs to provide larger, and more directed, incentives if it is to bring the benefits of distributed storage to low-income and minority areas that have long suffered the scars of polluting plants and excessive emissions.

Ted Ko, a consultant to clean energy companies, said it’s “not sufficient” to simply incentivize the location of storage projects in the communities.

“While there’s a good reason to actually have deployment incentives to get people to deploy in those locations, it’s not enough to actually get the benefits to those locations,” he said. Instead, he added, the BPU “needs to come with a companion program, to actually get the storage to operate in a way that actually provides those benefits,” which he said could include providing resilience to the electricity system or avoiding the extra emissions unleashed when demand peaks occur.

Scott Elias, director of Mid-Atlantic state affairs for the Solar Energy Industries Association, urged the BPU to set aside a portion of the incentives for projects “located in or directly serving overburdened communities.”

“Our preference is that is done by establishing an adder of $1/kWh to the fixed portion of the incentive” allocated to projects in overburdened areas, he said.

Defining Incentive Capacity

The hearing — the third and final forum to solicit stakeholder input on the proposal — focused on program rules designed to stimulate the development of storage for distributed, or behind-the-meter, projects. The first hearing focused on providing an overview of the project and the second on the program rules for grid-scale projects. (See Stakeholders: NJ Storage Incentives Too Small, Slow.)

The program, with a target of building 1,000 MW of four-hour-plus storage by 2030, is part of the state’s effort to jumpstart state storage development in pursuit of the state goal of creating 2,000 MW of storage by 2030. The state has about 500 MW in place and is hoping to develop 1,000 MW through the Competitive Solar Incentive (CSI) program, which includes incentives for co-located storage.

With different rules for distributed and utility-scale projects, SIP provides incentives to both project categories through a combination of fixed incentives and a pay-for-performance mechanism. For distributed storage, the pay-for-performance payments would be administrated by electric distribution companies (EDC), which would pay “based on the successful injection of power into the distribution system when called upon by the EDC,” according to the proposal.

It would award capacity and incentives to distributed storage projects in blocks, allocating 9 MW of planned capacity in the first year, 10 MW in the second year and 15 MW in the third year. Combined they total about one-quarter of the capacity incentivized in awards to grid-scale projects under the program. Two speakers questioned the imbalance and suggested that more should be allocated to stimulate the development of distributed projects, which include residential and commercial projects competing for the same pot of incentives.

“Without any cap on project size, a single large commercial energy storage can eat up the entire capacity,” said Elias. Without increasing the capacity available, he said, it is “critical that the BPU separate capacity buckets for residential and nonresidential distributed projects, which will add to additional program complexity.”

Available Incentive Capacity

Competing demands for limited incentives prompted other speakers to express concern that insufficient capacity would hurt efforts to support overburdened communities.

John Rotolo, chief engineer for the Newark-based Passaic Valley Sewerage Commission, called the proposed incentive capacity “insufficient” and urged the BPU to increase the program capacity and “make the majority the capacity available to distributed storage projects,” such as those planned at his own agency.

The commission, which operates the largest sewage treatment plant in New Jersey, serves 48 municipalities and is situated in an overburdened community that has a “strong desire to minimize fossil fuel emissions.” During Superstorm Sandy, the commission lost power and could not treat sewage, which resulted in “hundreds of millions of gallons of raw and partially treated sewage” being released into the Passaic River and Newark Bay, Rotolo said.

The agency is in the process of evaluating responses to a request for proposals to develop a clean energy source that would tie in to a microgrid that in several of the proposals would be supported by storage, he said. The plan would require about 34 MW of storage, which would provide enough power to operate the facility during an outage, Rotolo said.

“We are concerned that the storage proposal does not provide enough incentive program capacity even for our single project, let alone the main vital resiliency projects I’m sure are being planned or already processed around the state,” he said.

Todd Olinsky-Paul, senior project director at Clean Energy States Alliance, said that to have a positive impact on overburdened communities, the BPU had to do more than just create a “carve out,” or allocation of incentives to those areas. He cited the example of California’s Self-Generation Incentive Program (SGIP), which provides storage incentives to residents that live in low-income or affordable housing. The program initially had a carveout but offered no “adders” or extra incentives to pay for storage in low-income housing and its residents, he said.

“There was absolutely no uptake until they increased the incentive rate, at which time the equity budget was fully subscribed almost immediately,” he said. “So, we recommend that the New Jersey BPU adopt both a separate capacity block and an additional upfront incentive for overburdened communities. The upfront incentive is important to help offset higher costs and also higher risks of financing.”

Kyle Wallace — vice president for public policy and government affairs at PosiGen, a Livingston-based developer of solar projects for disadvantaged consumers — said the BPU should have a separate allocation of incentives for overburdened communities to help address the fact that the distinct challenges and costs faced by projects catering to those communities mean that the market for them will take longer to develop.

He added that low-income applicants should be paid the full incentive upfront, rather than over 10 years, because those consumers are less able to handle the financial commitment from having an investment tied up long term on a solar project, let alone an additional storage project.

“They don’t have that same tolerance that higher-income households may, where they’re willing to put off their payback period a few more years to add storage,” he said. “Low-income customers just do not have that luxury.”

Other speakers encouraged the BPU to consider ways in which the program can encourage the use of vehicle batteries to provide storage when they are not powering the vehicle, a strategy that is not incorporated into the SIP.

“We want to make sure the BPU storage program can support the full range of applications and use cases, including cases where storage is embedded as part of a broader project, for instance solar and EV charging,” said Pamela Frank, CEO of ChargEVC-NJ, a nonprofit trade and research organization that promotes electric vehicle use. “Electric vehicles in particular, when they’re not operating on the roads, which is the majority of time, they present opportunities to utilize the car battery.”

Stanislav Jaracz, president of the New Jersey Electric Vehicle Association, said that moving in that direction would require a clear statement of intent from the BPU. Vehicles currently are not wired to be bi-directional, and manufacturers won’t move in that direction unless they see a market for it, he said.

“I think it’s very important that we in New Jersey start ahead and have this regulation in place so that we send the message to the carmakers, so that they make the vehicles capable of having bidirectional chargers,” he said.

November 17, 2022

SunZia Transmission OK’d by Ariz. Regulators

Arizona regulators have granted a key approval to the SunZia Transmission project, Pattern Energy’s proposal for delivering wind energy from central New Mexico into Arizona.

The Arizona Corporation Commission (ACC) last week approved a certificate of environmental compatibility for the project, which will consist of two 525 kV transmission lines across a 550-mile corridor.

The lines are intended to send energy from the 3,500 MW SunZia Wind project, which Pattern Energy is looking to develop in central New Mexico, to population centers in Arizona. SunZia Wind will be the largest wind project in the Western Hemisphere, the company said in a release.

“SunZia is proof that New Mexico is leading the charge in the clean energy transition,” U.S. Sen. Martin Heinrich (D-NM) said in a statement.

The ACC approval completes the Arizona state permitting process for the transmission project. In addition, the New Mexico Public Regulation Commission granted two separate approvals — in May and in October — related to SunZia Wind, Pattern Energy said.

The company said it is awaiting approval from federal agencies, including the Bureau of Land Management, as well as local jurisdictions. Construction is expected to start in mid-2023.

Amendments Requested

The ACC originally approved an environmental certificate for SunZia Transmission in 2016. In May, SunZia Transmission LLC asked the commission to amend the approval. SunZia asked the commission to split its decision into two separate environmental certificates to allow separate ownership of each line. The move will facilitate financing.

SunZia also asked the commission to approve additional structure types and updated structure design for the project. In addition, the company asked to extend the time to complete the project, from February 2026 to February 2028.

Pattern Energy called the commission’s unanimous decision to approve the requests a “major milestone.”

Critics of the project said it would harm wildlife and questioned the benefit to Arizona, because New Mexico power would be sold to California, according to a draft order to approve the certificate.

A Pattern Energy spokesman said agreements are still being negotiated, so it’s too early to say how much of SunZia’s wind energy would go to California.

Regarding wildlife, Pattern Energy said previously that SunZia Transmission worked closely with wildlife conservation groups to analyze environmental impacts and find the best route for the transmission project.

Supporters of the transmission project pointed to the need for more renewable energy to combat climate change and the economic benefits the project would bring to rural Arizona.

“Our window to combat [climate change] by reducing greenhouse gas emissions is closing quickly,” Adam Stafford, Western Resource Advocates’ managing senior staff attorney in Arizona, said in a statement. “We need to take action now, and building the SunZia lines helps us move in the right direction.”

Kevin Wetzel, Pattern Energy’s senior director of business development, said the SunZia projects would “greatly benefit” Arizona. SunZia wind will complement solar energy produced in the state, he said, helping utilities and commercial customers reach their renewable energy goals.

In addition, “new transmission and diversified generation resources will improve overall WECC reliability and resiliency, which benefits all Western states, including Arizona,” Wetzel said in a statement provided to RTO Insider.

Project Acquisition

In July, Pattern Energy announced it had acquired SunZia Transmission from SouthWestern Power Group. Pattern Energy had previously been awarded the full 3,000 MW of capacity of the transmission line.

SouthWestern Power Group is retaining ownership of a second 500 kV transmission line, El Rio Sol Transmission.

Combined, the SunZia transmission and wind projects form the largest renewable energy infrastructure project in U.S. history, with a total investment of more than $8 billion. Both projects are privately funded.

After initial approval of SunZia Transmission, the route was adjusted in consultation with the Department of Defense and White Sands Missile Range. The modified route partially parallels the existing Western Spirit Transmission line for 35 miles, which reduces environmental impacts, Pattern Energy said.

November 17, 2022

Calif. Proposes World’s ‘Most Ambitious’ Climate Goals

California regulators on Wednesday released an updated proposal for bringing the state to carbon neutrality by 2045, incorporating changes such as boosting offshore wind development and moving toward net zero without new natural gas-fired plants.

The new version of the climate change scoping plan is a follow-up to a draft that the California Air Resources Board released in May. The CARB board is scheduled to vote on finalizing the plan during its Dec. 15-16 meeting.

The plan would rapidly shift the state away from fossil fuels and toward renewable energy and zero-emission vehicles. It would cut greenhouse gas emissions to 85% below 1990 levels and create 4 million jobs, the agency said.

Gov. Gavin Newsom called the plan “the most ambitious set of climate goals of any jurisdiction in the world.”

“If adopted, it’ll spur an economic transformation akin to the industrial revolution,” the governor said Wednesday in a statement.

CARB revised the draft scoping plan based on changes requested by the CARB board, by the agency’s Environmental Justice Advisory Committee and by Newsom. Other changes are in response to laws passed by the state legislature this year.

The plan calls for meeting the increased demand for electrification without new gas-fired plants, while maintaining reliability. It includes the development of 20 GW of offshore wind by 2045. Both strategies were requested by Newsom in July. (See Newsom Calls for ‘Bolder’ Climate Action in Calif.)

The scoping plan sets a goal of 6 million electric heat pump appliances installed in the state by 2030. All-electric appliances would be required in new homes starting in 2026 and in new commercial buildings beginning in 2029. Appliance sales for existing homes would be 80% electric by 2030 and all electric by 2035.

The plan relies on carbon removal and sequestration, which it calls “an essential tool to achieve carbon neutrality.” Carbon capture and sequestration would be used in sectors such as electricity generation, cement production and refining.

The plan is projected to reduce greenhouse gases by 48% below 1990 levels in 2030, surpassing a mandated 40% reduction by 2030.

The scoping plan is a framework for the state to reach carbon neutrality by 2045. But further action, such as the adoption of regulations, is needed to move toward the plan’s goals.

“Hitting the targets — from the required build out of renewable resources to putting tens of millions of zero-emission cars and trucks on our roads and highways — will require implementation on a very ambitious timeline,” CARB said.

David Weiskopf, senior policy advisor with NextGen Policy, said the plan’s ambitious goals have the potential to offer major benefits.

“But until we take action, it is just a report,” Weiskopf said in a statement. “It is our job as an advocacy community to turn seemingly impossible goals into realities and to prevent outcomes that continue the legacy of environmental racism at the hands of polluting fossil fuel companies.”

November 16, 2022January 30, 2024

NARUC Annual Meeting Taps Into Winter Unease, Rate Design, Storage

NEW ORLEANS — The 2022 annual meeting of the National Association of Regulatory Utility Commissioners covered ground on rate design, energy storage and reliability as the energy portfolio undergoes renovation.

The meeting, which began Sunday and concludes Wednesday, continued NARUC’s multiyear theme of innovative and disruptive technology and regulation.

“The energy transition poses the greatest threat to reliability,” said NERC Director of Legislative and Regulatory Affairs Fritz Hirst during a briefing Sunday on the reliability organization’s 2022 Winter Reliability Assessment.

Hirst called NERC’s summer assessment a “sobering report.”

“And the winter assessment is no exception,” he said, adding that a large portion of the country will confront reliability risks should severe winter weather strike.

Fritz Hirst 2022-11-15 (RTO Insider LLC) FI.jpg

NERC’s Fritz Hirst | © RTO Insider LLC

Hirst said Texas, MISO, SERC and New England are particularly exposed to winter risk, due to generation retirements, fuel supply and generator vulnerability to the elements.

He added that the Pacific Northwest’s hydropower conditions have improved since last year and SPP has added enough natural gas and wind generation to manage winter resource adequacy, likely keeping them off the season’s hot seat.

Hirst said it’s “cold comfort” that the National Oceanic and Atmospheric Administration is predicting a mild winter for much of the country.

“It matters not what the predictions are because all it takes is a cold snap lasting several days in a region,” he said.

Hirst also said an ongoing nationwide shortage of transformers might mean longer restoration times. He said that though NERC cannot mandate resource adequacy, the “energy sufficiency challenge” is top of mind for staff. The agency’s consideration of a standard for forward-looking energy reliability assessments seeks to tackle the burgeoning issue, he said.

“The system needs flexible, dispatchable resources, whether that’s coal or natural gas,” Hirst said. “Natural gas is probably your best bet … and that will be the case until we have some breakthrough in storage at scale or in hydrogen.”

Michelle Bloodworth, CEO of coal lobbying group America’s Power, said she’s alarmed by the pace at which dispatchable resources are exiting the grid. She said operators are “vastly underestimating” the amount of coal resources poised to exit the system.

Utilities have announced the retirement of more than half of the nation’s 200 GW coal fleet by 2030, Bloodworth said. She said the industry should “do a better job of publicly recognizing” that coal resources have reliability attributes that are essential for the foreseeable future. America’s Power has filed a letter with FERC, asking the commission to acknowledge those attributes.

The Brother Martin boys’ college preparatory marching band of New Orleans serenaded NARUC attendees on Nov. 14 | © RTO Insider LLC

“Every coal plant that leaves puts more and more pressure on the natural gas system,” said Bloodworth.

She added that she hoped carbon capture and sequestration investments on the nation’s existing coal plants are given an assist by the Inflation Reduction Act.

“It takes time and sustained investment. We’ve seen more subsidies on the intermittent generation to date,” she said.

State regulators also wrung their hands over natural gas price increases.

During a Monday roundtable, Colorado Public Utilities Commission Chairman Eric Blank said customers will see increases north of 60% on the natural gas portions of their bills.

“It’s just enormous, enormous,” Blank said. “I would say the regulatory options are very limited. We’re just struggling.”

He said “it’s a lot more fun” to regulate when fuel prices are stable. He asked other regulators for ideas on limiting bill increases.

Regulators suggested prohibiting utilities from earning a return on natural gas power purchases, customer charge suspensions, and more robust energy efficiency programs that hedge high commodity prices.

Some regulators said while surging natural gas prices will strengthen some commissions’ commitment to electrification, renewable energy and hydrogen substitution, others will concentrate on how to blunt the price hikes.

“It’s going to be an ugly time for ratepayers in Georgia in the next few months,” Georgia Public Service Commissioner Tim Echols predicted.

“Is the final word from this session, ‘This job sucks?’” Blank joked. “Is that the takeaway?”

Rate Design Considerations

Debbie Lew, associate director of the Energy Systems Integration Group (ESIG), said zero marginal cost renewable resources and looming, immense electrification loads mean that regulators will have to introduce more dynamic pricing that incentivizes demand when supply is plentiful.

“New electrification loads are a double-edged sword — they can help or stress both the distribution and bulk power system,” Lew said during a Sunday panel. “We know we’re going to need more than time of use rates.”

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ESIG’s Debbie Lew | © RTO Insider LLC

But Lew said time-of-use rates are beneficial today. She said Sacramento Municipal Utility District’s TOU rate created on a $5 million investment averted the need for a new, more expensive 150-MW resource to meet peak demand.

Lew said if regulators want demand flexibility, they will need to expose some customers or load-serving entities to price signals that “reflect cost causation and grid needs.”

“If all demand were price-sensitive, we might not need … reserve margins. Obviously, we’re a long way away from that,” she said.

Brattle Group principal Sanem Sergici focused on electrifying heating with heat pumps. She called their adoption “a key component of state and city climate action plans” but said adoption hinges on their installation and operating affordability compared to natural gas.

Sergici said regulators must design new rate structures that balance customers’ payback periods, fixed charges and incentives under the IRA. She said it’s possible to use cost-based rates and avoid subsidies to foster heating electrification.

“With the right rate design, adoption is possible. It’s time to stop discouraging electrification of heating,” she said, adding that rate design can be “a constant evolution” if the bulk electric system becomes winter peaking.

Storage Makes an Entrance

Jason Burwen, American Clean Power Association’s vice president of energy storage, told regulators to expect 10 GW of new storage annually nationwide for the foreseeable future if transmission system planning is updated, regulatory and permitting processes are revamped, and supply chain issues stabilize.

He predicted the IRA will counteract some of the recent inflation-based price increases of storage facilities.

From left Enel’s Greg Geller, Interstate Renewable Energy Council’s Radina Valova, PJM’s Danielle Croop and American Clean Power Association’s Jason Burwen | © RTO Insider LLC

PJM Manager of Market Design Danielle Croop said PJM has 40 GW of hybrid generation projects and 54 GW of standalone energy storage in its interconnection queue. She said the amount of storage projects likely means that storage is becoming cost effective.

Greg Geller, Enel North America’s head of U.S. and Canada regulatory affairs, said storage is a key component of decarbonization plans. He said regulators can take three steps to stimulate storage additions: collaborate with utilities and grid operators, allow storage to compete to solve grid issues, and give consumers as much cost-causation transparency as possible so they can fire up distributed resources when they stand to save the most.

Geller said Texas, in particular, has an alluring regulatory environment. Enel’s storage projects in the state usually make it through the interconnection queue in one or two years, he said. Elsewhere, the wait is upward of three years. Geller said that storage solutions might help avoid decades-long stranded costs on more permanent assets.

November 16, 2022

Mass. OSW Projects to Continue Through Regulatory Process

BOSTON — Negotiations will continue on two Massachusetts offshore wind projects that developers have declared financially unviable.

Commonwealth Wind and Mayflower Wind in October requested the state Department of Public Utilities pause its review of the power purchase agreements they had struck with Eversource Energy, National Grid and Unitil for two planned wind farms. The developers said inflation, supply chain problems and other factors had altered the economics of the projects, which are rated at a combined 1.6 GW.

The DPU rejected the request and directed the developers to continue with the PPAs as originally negotiated or file a request to dismiss the proceedings. (See Mass. Rejects Delay of Offshore Wind Review.)

In a notice to the DPU on Nov. 7, Mayflower withdrew its motion to suspend review and said it will seek to resolve the financial issues through conversation with the state and the three electric distribution companies.

Commonwealth filed a similar notice Nov. 14, saying if the DPU would not support a pause, the appropriate course of action would be to continue with the proceeding and discuss contract changes or other ways to make the project financeable and economically viable.

Eversource, National Grid and Unitil told the DPU on Nov. 1 that they have no intention of renegotiating the PPAs.

Commonwealth, the larger of the two projects at 1.2 GW, is being developed by Avangrid (NYSE:AGR). In a statement late Monday, the company said, “We have been transparent and committed, at all times, to doing everything we can to move the project forward, including coming to the table with all parties to find a solution to the unprecedented economic challenges facing this major infrastructure project. …

“Ensuring Commonwealth Wind is able to move forward is squarely in the public interest and the best possible outcome for Massachusetts and its ratepayers, and we look forward to continued engagement so this project can deliver on its immense economic and environmental benefits and help the state achieve its ambitious 2030 climate target.”

November 16, 2022

Pa. Municipalities Chart Own Energy Paths as State Remains Divided

Municipalities across Pennsylvania have been charting their own course on climate and energy policy under divided federal and state governments, and while Democrats made major gains in the most recent cycle, Harrisburg could remain an uphill battle for the party’s priorities.

In Philadelphia, much of that effort has been channeled through a city agency created in 2010 to support affordability and sustainability amid concerns about electricity deregulation.

“We had to start it knowing we didn’t have a big source of federal funding or state funding,” said Emily Schapira, CEO of the Philadelphia Energy Authority (PEA). “We had to develop projects that could be financeable and could be budget neutral for the city and the school district.”

The authority has since launched about a dozen programs and in 2016 set a 10-year goal of $1 billion invested in clean energy citywide and the creation of 10,000 jobs. Schapira said the authority has so far invested $291 million through public-private partnerships and created 2,500 jobs.

Much of that work has taken the form of energy efficiency upgrades in city buildings, schools and low-income housing restoration programs. In some cases, such as the transition to 140,000 LED bulbs for street lighting, the long-term energy savings are being used to pay for the upfront capital costs of the initiatives. Workforce development programs and one of the nation’s first solar vocational high school curriculums have allowed the city to doubly benefit by keeping the labor for these projects local.

The authority additionally created a green bank last year to attract further private investments in energy efficiency, renewable energy and resilience projects, including its Solarize Philly initiative, which provides free assessments and discounted installations. Across its efforts, the PEA has assisted in the installation of 1,200 rooftop solar installations in the city.

Schapira said the authority designed many of its programs to be easily shared with other municipalities, including the software management systems it created to track funding sources. One of the biggest challenges it has found is that federal, state and local funds are often provided in isolation and with conflicting data sharing restrictions or requirements, an issue the software attempts to alleviate.

“We’ve really designed everything to really be scalable and replicable,” she said. “That’s a model that can be easily shared.”

In Pittsburgh, the Sustainability & Resilience wing of the Department of City Planning has been making progress on its Climate Action Plan goals for 2030. The city’s goals also call for reducing emissions from transportation by 50% and the Pittsburgh International Airport went live with a solar- and natural gas-powered microgrid last year.

Governor-elect Shapiro Promotes “All-of-the-above” Energy Policy

Many of the initiatives being undertaken in Philadelphia mirror the goals Democratic Governor-elect Josh Shapiro laid out in his “all-of-the-above” approach to energy policy. In a June overview of his economic priorities, Shapiro pushed for legislation to generate 30% of the state’s energy with renewables by 2030 and to set a goal to reach net zero by 2050.

His approach promised to marry investments in developing clean energy generation, while maintaining “responsible fracking” — which could include expanding no-drilling zones and strengthening health guidelines. Shapiro’s campaign did not return requests for comment following Tuesday’s election.

After the state joined the Regional Greenhouse Gas Initiative last April, Shapiro questioned the effectiveness of the multistate agreement and said he would have to further consider the impact to the economy and workers before pledging to continue the state’s participation. Even with his support, the implantation of RGGI has been held up by Republican objections in the state courts.

November 16, 2022

Fund Created to Develop NY Offshore Wind Ecosystem

Equinor and bp have created a fund to help pay for workforce development and support community-empowerment aspects of New York’s nascent offshore wind industry.

The companies are partners in the Empire Wind and Beacon Wind projects planned for construction off the coast of New York. They announced the fund Tuesday with the New York City Economic Development Corp. and the Sunset Park Task Force.

The Offshore Wind Ecosystem Fund will help fund job education and training; bring employment and small-business opportunities to historically marginalized communities; and help bring minority- and women-owned business (M/WBE) enterprises into the burgeoning industry.

State law mandates 9 GW of offshore wind capacity be installed by 2035, and some scenarios being considered would entail 20 GW installed by 2050.

Brooklyn’s Sunset Park neighborhood will be a focal point of the offshore wind initiative, as a staging and assembly port is built there, and there is a concerted effort to offer the people who live there a chance to benefit from the development.

“The Offshore Wind Ecosystem Fund is bringing an integrated approach to environmental justice in Brooklyn,” Borough President Antonio Reynoso said in a news release. “Not only will these grants accelerate our clean energy efforts, but they will also open up green careers to new generations and empower small businesses owned by minorities, women and service-disabled veterans to participate in the offshore wind industry.”

Amanda Farias, chair of the City Council’s Economic Development Committee, said: “I am excited to see the attention that the NYCEDC, Equinor and the Sunset Park Task Force are paying to the intersectional needs of our workforce. To recover equitably, we must put our Black, brown and minority communities first. This grant does just that by making sure our offshore wind sector is focusing on M/WBEs, [service-disabled veteran-owned businesses] and environmental justice communities.”

Doreen Harris, CEO of the New York State Energy Research and Development Authority, said: “This Ecosystem Fund will support communities like Sunset Park with a pathway to provide historical knowledge and local expertise for workforce training and development initiatives — and guide community investments that will best serve their neighborhoods and the broader development of offshore wind projects.”

November 16, 2022June 14, 2023

Offshore Wind Seeks State Leadership on Transmission

CHARLESTON, S.C. — Offshore wind and transmission developers say the states that are driving project development need to lead on the transmission side by collaborating to build an offshore grid.

That was the consensus that seemed to form at the Business Network for Offshore Wind OSW Grid & Transmission Summit last week as attendees brainstormed the most cost-effective way to interconnect the massive amounts of offshore wind states are procuring to meet their decarbonization goals.

The summit was held over two days at the Francis Marion Hotel to discuss strategies for offshore transmission development, mostly on the East Coast.

Rather than the typical format for an energy conference, the Business Network tried something different for the first day: a marathon series of discussions among the audience, mostly about the offshore wind industry’s dream: a “backbone” transmission line along the East Coast, from Maine to Florida, connected to the onshore Eastern Interconnection and allowing offshore wind projects to “plug and play.”

Such a “mesh-ready” system would save all stakeholders — states, developers, utilities and ratepayers — money on costly onshore transmission upgrades and allow projects to provide more capacity, speakers said.

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Jason Gershowitz, principal at Kearns & West, led attendees of the summit in a series of free-wheeling discussions Nov. 9. | © RTO Insider LLC

The discussions were held under the Chatham House Rule: Attendees were free to use the information but not to reveal who provided it at the meeting. (As such, RTO Insider can not quote anyone who spoke.) Jason Gershowitz, principal at Kearns & West, lightly guided attendees as they traded tales of their experiences getting their projects built — the challenges, setbacks and successes. They also debated what is needed going forward and offered solutions for observed problems.

Also in attendance were state and federal officials charged with implementing their governments’ goals, as well as European developers.

What played out was an exercise in problem solving among players in a nascent industry still struggling to find its sea legs.

Bottom-up Collaboration Needed

The problems with offshore transmission development are similar to those onshore in the U.S.: diverse state policies and goals; clogged supply chains; different standards and rules in each grid operator; and opposition by not-in-my-backyard residents.

While FERC has instituted several proceedings seeking to encourage interregional transmission development onshore and make it easier for generators to interconnect to the queue, it has not sought an active role in offshore transmission. Judging by several comments at the conference, that isn’t necessarily desired. Though attendees did not come to any hard solutions, they agreed that there needs to be a bottom-up approach among stakeholders, not a top-down mandate from the federal government.

Currently, each state that is procuring offshore wind is soliciting transmission solutions on its own. There seemed to be some reluctant acceptance among attendees that the New Jersey Board of Public Utilities’ recent selection of the Larrabee Tri-Collector Solution — which will only involve onshore transmission upgrades and a new substation — was the state’s only real option given the costs of offshore transmission and lack of proposals for an offshore backbone. (See NJ BPU OKs $1.07B OSW Transmission Expansion.)

States are also very protective of the benefits that will come with the projects, especially the construction, manufacturing and shipping jobs, and they are competing among themselves for manufacturing and logistics hubs at their ports. Several attendees suggested pressuring states to put aside competition and collaborate on building an offshore grid that would benefit all involved. The states could form a coalition, laying out a clear goal and agreeing to share costs.

Others suggested that the three grid operators along the East Coast — ISO-NE, NYISO and PJM — come together, perhaps with a “nudge” from FERC, to independently plan an offshore grid. Still, states would need to play a key role in pushing the RTOs and FERC to work together. Here the challenge is a lack of consistency — as well as the inevitable difficulty of getting three different stakeholder bodies to reach agreement.

Still others suggested that wind developers themselves should collaborate among themselves rather than wait for the state governments to fix things for them. Developers could propose joint transmission solutions that incrementally build the backbone.

Several Europeans in attendance seemed bewildered that U.S. states with similar clean energy policies, such as those in New England, could not come together like countries in the North Sea — such as Belgium, the Netherlands, Germany, Denmark and Norway — which recently committed to building an offshore network in the sea by 2050.

Not Enough People

The attendees also discussed the lack of workers to fill all the open positions in the offshore wind field.

The industry began by picking off workers from the offshore oil and gas industry for their expertise in ocean construction and operating marine vessels. It then began enticing more with promises of training for industry-specific jobs.

Now that that labor pool has been exhausted, several attendees noted, developers are recruiting workers from competitors with hefty signing bonuses.

Attendees said there needs to be more engagement with students in high school and lower grades to encourage them to study electrical engineering and other related fields in college. One attendee, however, noted that it’s difficult to get children excited about infrastructure.

November 16, 2022June 14, 2023

Federal-State Task Force on Tx Debates Deeper Project Reviews

NEW ORLEANS — The Joint Federal-State Task Force on Electric Transmission’s fifth meeting since its inception last year featured dialogue on local project review, cost management and FERC’s notice of proposed rulemaking on regional transmission planning, cost allocation and cost containment (AD22-8). (See States Urge More Transparency on Tx Planning, Independent Monitors.)

FERC Chairman Richard Glick opened the task force’s discussion Tuesday during the National Association of Regulatory Utility Commissioners’ annual confab by noting there is a lot of “costly” transmission on the horizon.

“So, we need to make sure that consumers get the best bang for their buck,” he said.

Jason Stanek, chair of the Maryland Public Service Commission, said even if the task force already had managed to achieve consensus on a planning approach and cost allocation methodology, cost management and project review would still be issues.

“What I’ve been hearing is something is lacking, something is missing in this process,” FERC Commissioner Willie Phillips said of transparency in proposing and reviewing local transmission projects.

Phillips said it’s “interesting” that states seem unable to replicate the results of utility planning studies, especially since FERC requires them to do so.

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Glick said the depth and breadth of regulatory gaps depend on the type of project and whether they’re located in an RTO. But he said a great number of local projects don’t appear to have a “sufficient level of review.”

“It’s not easy to determine whether a decision is right, especially when there’s a lack of transparency in the process,” he said.

Pennsylvania Public Utility Commissioner Gladys Brown Dutrieuille said only projects 101 kV and above that require new siting are subject to intensive review in the state. She said over the last several years, her commission has seen big increases in smaller and rebuild transmission projects that are handled by staff and don’t require a thorough review.

California Public Utilities Commissioner Darcie Houck said that most of PG&E’s billions of dollars in planned projects through 2026 will fall under CAISO’s category of self-approved projects that bypass review.

“We’re seeing the same trends,” Michigan Public Service Chairman Dan Scripps said. He admitted that he isn’t yet sure who should provide project oversight and said it might be some combination of FERC, the states and grid operators. He also said should the federal agency introduce independent transmission monitors, it should take care to make sure it doesn’t slow project development.

Phillips said FERC also must ensure that an independent transmission monitor doesn’t create an incentive for utilities to leave RTOs.

Review Tied to Formula Rates?

FERC Commissioner Mark Christie said some projects are scrutinized at the state level while others get by without oversight. He pointed out that while FERC cannot prescribe projects, it does wield control over formula rates. The commission could condition its formula rate treatment on whether a project has undergone a credible, state-level review, he said.

“And we’ll let the states tell us if it was credible,” suggested Christie, adding that FERC could apply the question to multiple states for interstate lines.

Christie said the national transmission rate base has increased 9% or more for the third year in a row.

“What goes into rate base goes into customers’ bills — every nickel,” he said.

Stanek said he didn’t think states, which are “perpetually” underfunded and understaffed, should be tasked with undertaking project prudency studies on the bulk power system. He said such analyses would be too complex and expensive.

“I think Commissioner Christie is on the money that formula rates are an incentive. They’re a carrot,” said Matthew Nelson, chair of the Massachusetts Public Utilities Commission. He said he supported the idea of “step-down” return on investments, where cost overruns would trigger reduced rates.

FERC Commissioner Allison Clements said the task force might consider creating a standardized data collection from transmission developers across all 50 states. She asked what happens if FERC discovers a state doesn’t have a credible project review process.

Christie suggested commissions call on expert RTO witnesses to testify on the prudency of some proposed projects. He reminded regulators that utilities bear the burden of demonstrating that a project is necessary before state commissions.

Kansas Corporation Commissioner Andrew French said establishing independent transmission monitors would be most helpful for local projects. He said large projects subject to regional cost sharing already are sufficiently inspected by parties that stand to pay.

French said at present, transmission owners can easily finalize local and replacement projects that maintain a status quo system.

“There just isn’t an incentive to [propose] an optimal solution,” he said, adding that commission staffs need help understanding the pace of investment and whether transmission owners are engaging in optimal planning.

However, Georgia Public Service Commissioner Tricia Pridemore, who replaced former Arkansas regulator Ted Thomas on the task force, denounced a “top-down” level of review. She said Georgia has a solid planning process that invites economic development, and it has never experienced a major blackout.

Glick countered that there has been a “ballooning” of local projects and some attention on them would be worthwhile.

“It might be that non-RTO states have sufficient authority,” he said.

Glick wrapped the meeting by urging the task force to keep up the collaboration if he doesn’t return to the task force for its next meeting in February. (See Glick’s FERC Tenure in Peril as Manchin Balks at Renomination Hearing.)

Clements Weighs in on Planning Direction

In a Monday keynote during the NARUC meeting, Clements urged thoughtful, low-regret transmission planning so customers don’t experience “wild jumps” in the transmission component of their bills.

Clements said FERC commissioners could issue hundreds of pages of cost-management decrees and “sit very smugly,” but if states and utilities don’t think the resulting cost containment rules are fair, they will be pointless.

She said the commission is laying crucial groundwork to get new infrastructure built: “To me it’s not so much as an ambitious agenda as it is an imperative need.”

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Clements repeated the industry adage that the transmission system is on the cusp of a buildout like that of the nation’s highway system in the mid-1950s. She said the key to mitigating widespread extreme weather events is to have an interconnected transmission system greater than the size of the weather patterns.

She pointed out that interconnection queues are brimming with projects waiting for grid treatment.

“Right now, we’re looking at twice as much generation than exists on the transmission system today trying to get on,” Clements said.

She said federal and state regulators should help utilities ensure the most efficient use of the existing system through dynamic line ratings and other grid-enhancing technologies,

“Now is the time to do it, since we’re thinking about larger investments in backbone transmission,” she said.

However, Clements said she understands grid operators’ hesitation to introduce system stressors with new transmission technologies. She said control room operators are understandably cautious and protective of system reliability and that FERC is trying to land on “the least scary way” to introduce new technologies.

“If the speed limit is 60, and it’s a nice day in April, maybe go 75,” Clement said. “But if it’s February and icy, go 40. Make the system better and smarter, and I think that’s a great analogy.”

State Rights of First Refusal and Order 1000

A Tuesday NARUC panel deliberated on which is worse: FERC’s failed attempt at competition under Order 1000 or the ensuing wave of state rights of first refusals for incumbent utilities.

Former FERC commissioner Tony Clark, now an adviser with Wilkinson Barker Knauer, said some prefer continued transmission development under monopolies rather than a “complex bidding process that doesn’t work” under Order 1000.

“The state ROFRs are the symptom, but Order 1000 is the disease,” Clark said. “I think we ought to admit that this is an industry that naturally trends toward a natural monopoly.”

Devin Hartman, R Street Institute’s director of energy and environment, said consumers could potentially save several billion dollars with competitive solicitations. He said consumer groups and grassroots movements are organizing to fight state ROFR laws.

Hartman said there’s “no economic reason” to reinstall a federal ROFR.

Ten states have enacted ROFRs: Indiana, Iowa, Michigan, Minnesota, Montana, Nebraska, North Dakota, Oklahoma, South Dakota and Texas.

Four other states have considered such laws: Colorado, Kansas, New Mexico and Wisconsin.

A consumer collective has filed a joint complaint at FERC against MISO’s practice of respecting state ROFR laws in its regional transmission planning and cost allocation (EL22-78). (See Consumer Groups File FERC Complaint Against MISO.)

Wisconsin Public Service Commissioner Ellen Nowak, whose state discussed a bill that ultimately didn’t pass, said viewing the issue as a debate between competition and full regulation is a “false choice.”

“It hasn’t played out as we have expected,” Nowak said of competitive processes in practice. “The sticker price looked good, but then there’s a lot of little exemptions that have to play out.”

“States want control over who is building critical infrastructure in their state… It’s not putting up another Dunkin’ Donuts; it’s critical infrastructure,” Nowak said, explaining that states need trusted utilities. She said incumbent utilities are still beholden to a transparent process, and they can be subjected to cost caps.

However, Nowak predicted that the bill will again be introduced during Wisconsin’s next legislative session.

“ROFRs are anti-competition laws,” said Ari Peskoe, director of Harvard Law School’s Electricity Law Initiative. “This is benefitting the largest incumbents. I’m not sure who else benefits from this.”