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November 20, 2022December 12, 2023

FERC Addresses IBRs in Multiple Orders

At its open meeting on Thursday, FERC significantly advanced NERC’s remit to address the challenges posed by the growth of solar and wind generation on the bulk electric system, directing the organization to develop new reliability standards for inverter-based resources (IBRs) (RM22-12) and create a plan for registering entities that own IBRs (RD22-4). The commission also approved two new reliability standards involving IBRs.

In a presentation on the two orders to NERC, Leigh Faugust of FERC’s Office of General Counsel told commissioners that the moves are necessary because of the rapidly changing nature of the BES’ generation mix. Existing regulations standards were designed for an electric grid where energy primarily came through synchronous generation resources like coal, nuclear and hydropower; however, new generation types like wind and solar — as well as battery energy storage systems — connect to the grid through inverters.

“According to NERC, the rapid integration of IBRs is the most significant driver of grid transformation on the bulk power system,” Faugust said. “NERC has reported that solar and wind IBR projects in all stages of development may total upwards of 860 GW of added nameplate capacity over the next decade.”

Although IBRs “are being increasingly incorporated into the bulk power system and distribution grids,” reliability standards largely have not yet been updated to reflect the new normal, Faugust said. In addition, current rules defining which resources qualify as part of the BES — and thus have to register with NERC, follow its reliability standards and respond to NERC alerts — do not apply to many smaller IBRs that are connected to the transmission system.

Registration Criteria, Standards up for Revision

The first of the commission’s orders concerns these registration criteria. It directs NERC to submit a work plan within 90 days detailing how it will identify and register owners and operators of IBRs that are connected to the BPS and “in the aggregate have a material impact” on reliable operation, but are not currently required to register with NERC.

Under the draft order, NERC will be required to complete modifications to its registration processes no later than 12 months after the commission approves its work plan. The organization will have to identify all relevant IBR owners and operators within 24 months after approval, and register them no later than 36 months after approval.

FERC’s order provides some flexibility to NERC by allowing it to decide which of the reliability standards’ requirements IBR owners and operators will have to comply with upon registration; the commission gave the example that new registrants might be required only to comply with “provisions pertaining to facility interconnections and studies, protection systems, modeling, voltage support and frequency response,” along with newly passed standards. NERC’s decisions in this regard will be subject to the commission’s approval.

In its second order, FERC issued a draft Notice of Proposed Rulemaking intended to deal with “the impacts of IBRs on the reliable operation of the” BPS, which the commission said are not adequately addressed by current reliability standards.

Four specific perceived gaps in the current standards are targeted by the draft NOPR. First, the commission said that IBR owners and operators “do not consistently share IBR planning and operational data”; when they do share such data, they are “often inaccurate or incomplete.” Data that should be shared, according to FERC, include location, capacity, telemetry, control setting, ramp rates and a wide range of additional information.

The commission quoted a report from NERC’s Inverter-based Resource Performance Subcommittee (IRPS) that found that NERC’s current standards are at least in part to blame for the situation. According to the report, MOD-032-1 (Data for power system modeling and analysis) leaves “the level of detail and data formats up to each [transmission planner] and [planning coordinator] to define.”

The next gap in the standards is in the validation of data and creation of system models. FERC’s NOPR said that no current standard includes “unregistered IBR modeling data and parameters and IBR-DER [distributed energy resource] aggregate modeling data and parameters to ensure reliability.” While NERC has recommended on several occasions that stakeholders coordinate on providing accurate modeling data, the lack of a mandatory standard means that it is difficult to ensure such collaboration happens.

Another shortcoming in NERC’s current set of standards is planning and operational studies, which Faugust pointed out are not currently required to include models with validated IBR data. Finally, FERC pointed to a lack of IBR performance requirements, such as ride-through capability, that are not currently covered by reliability standards.

FERC’s draft NOPR would direct NERC to submit a compliance filing within 90 days of the effective date of the final rule; the filing would outline a comprehensive standards development and implementation plan for new or modified reliability standards to address the reliability gaps. Comments in response to the draft NOPR are due 60 days after its publication in the Federal Register, with reply comments due 30 days later.

The commission’s third IBR-related action in Thursday’s meeting was the approval of two new reliability standards: FAC-001-4 (Facility interconnection requirements) and FAC-002-4 (Facility interconnection studies). Proposed by the IRPS in a March 2020 white paper, the new standards add requirements that interconnection requirements and studies “evaluate the reliability impacts of newly interconnecting facilities and changes at existing facilities.”

In a statement, NERC said it “appreciates FERC’s focus on reliability matters and will continue to work with FERC and stakeholders toward assuring the reliability of the North American bulk power system.”

November 20, 2022January 29, 2024

Governance, Resource Adequacy Key to SPP’s Markets+

WESTMINSTER, Colo. — Steve Wright, a newly minted member of SPP’s Board of Directors who has promised to “strengthen the bridge” to the grid operator’s potential members in the Western Interconnection, put his words into action last week during a two-day development session for its RTO-light Markets+ service offering.

Stepping to the podium Wednesday to help open the meeting’s second day, Wright fondly recalled his time in the Pacific Northwest, where he served as the Bonneville Power Administration’s CEO before retiring last year as general manager of Washington’s Chelan Public Utility District.

“I was always very proud of the collaboration work we did at Bonneville. We did a lot of really important stuff,” Wright told stakeholders.

But that experience did little to prepare him for SPP’s bottom-up, stakeholder-driven governance structure.

“Just in my short time at SPP, I see collaboration on steroids. In fact, it’s almost collaboration to the point of deference to stakeholders and what they want,” said Wright, who joined the board in October. (See “Membership Elects 2 New Directors,” SPP Board/Members Committee Briefs: Oct. 25, 2022.)

Aly Koslow 2022-11-16 (RTO Insider LLC) FI.jpg

Aly Koslow, Arizona Public Service | © RTO Insider LLC

Collaboration is also important to Arizona Public Service (APS), said Aly Koslow, the utility’s director of federal regulatory affairs and compliance.

“We are really keenly focused on some of the collaboration benefits that we see [in Markets+],” she told RTO Insider. “The fact that we haven’t had a more organized day-ahead market to join for a long time has made reaching our individual clean-energy goals a little bit less clear.”

APS has a target of delivering 100% carbon-free energy by 2050. Koslow said the utility has a “good idea” about how it will reach 80% of that goal but said, “That last 20% is much more difficult to achieve. It’s going to be new technology, and it’s going to be collaboration.”

“That is a big part of why we are looking to potentially join a market,” she added.

Koslow was joined by dozens of other representatives from Western utilities at Tri-State Generation and Transmission’s headquarters outside of Denver. Like APS, the potential RTO stakeholders are comparing SPP’s Markets+ offering with CAISO’s Western Energy Imbalance Market (EIM) and its extended day-ahead market (EDAM).

CAISO has a head start, but SPP is attempting to close the gap with a transitional real-time balancing market similar to its Western Energy Imbalance Service (WEIS). (See SPP Briefs: Week of Nov. 7, 2022.)

“That is a part of the dynamic out here,” Garrison Marr, senior manager of power supply for Washington’s Snohomish Public Utility District, said Friday of the ongoing RTO evaluation. “The value proposition is really relative to our counterfactual today of an unorganized bilateral market that can be pretty inefficient as we move through the trading trajectory.”

If SPP has a leg up in the competition with CAISO, it’s the RTO’s governance model that gives stakeholders an enormous say over policies and processes. The grid operator says it gets that Western utilities place “high value” on having a voice in shaping the “ever-changing energy landscape” and that the “Western utility landscape represents many diverse interests that must be balanced in every decision.”

“These objectives are at the heart of who SPP is and how we do what we do,” SPP says in its draft Markets+ service offering. “Our customer-driven approach will ensure Western customers get the products and services they need at affordable rates they help control.”

“This whole voting system is designed to give you power, and the board sees itself as primarily managing process to make sure we get the process that leads to the decisions that lead to as much consensus as possible,” Wright said.

SPP’s potential market participants have responded positively. Mark Holman, managing director of Canadian power marketer Powerex and a vocal supporter of Markets+, said governance is one of two pillars of a successful market, along with resource adequacy.

Mark Holman 2022-11-16 (RTO Insider LLC) FI.jpg

Mark Holman, Powerex | © RTO Insider LLC

“What we want to see happen in any governance framework is that we never end up with a situation where a minority of participants that are very large can drive decisions, but also that we end up with a situation where a majority of participants, but a very small share of the footprint, can drive decisions,” Holman said.

SPP has proposed a five-member Markets+ Independent Panel (MIP), unaffiliated from market participants and stakeholders, that reports to the RTO’s Board of Directors and oversees a Markets+ Participants Executive Committee (MPEC). The MPEC would direct the market’s working groups — likely focused on operations reliability, seams and market design — and task forces; an ad hoc settlements group has already been proposed.

The grid operator’s staff have recommended a two-tiered voting structure, with the first tier requiring a 67% approval threshold from three sectors (investor-owned utilities, public power, and public interest organizations and independents). The second tier would be a regional vote with a 51% approval threshold.

Staff hope to have the structure in place when Markets+’s first development phase begins in April. If the Phase 1 participants are unable to agree on the MIP’s representation, SPP has proposed that a subcommittee of its board be used in the interim, with one of the directors staying on the MIP to smooth the transition.

Paul Suskie, the RTO’s general counsel, conducted a straw poll on governance preferences by asking for a show of hands. By a 17-13 margin, stakeholders indicated they would like to stand up an MIP before Phase 1 but were not opposed to the board subcommittee structure.

SPP plans to add a Markets+ State Committee (MSC), like the Regional State Committee in the Eastern Interconnection. The Western states will determine their level of involvement and the MSC’s composition during Phase 1.

Suskie told his audience that while in New Orleans earlier in the week for the National Association of Regulatory Utility Commissioners’ annual meeting, a FERC commissioner told him, “You have the fewest protests at FERC because you work it out with the stakeholder process.”

Staff said they have received a large set of comments supporting the proposal that a common resource adequacy program be a prerequisite for Market+ participation. The Western Power Pool is several steps ahead there, having begun a Western Resource Adequacy Program (WRAP), the West’s first regional reliability planning and compliance program, at the request of regional utilities. The WPP has filed a tariff at FERC and has asked for a response by mid-December.

SPP’s two-day Markets+ development session draws another large crowd. | © RTO Insider LLC

“We plan to respond to whatever may come, and I’m very confident that we will resolve the process in a positive manner. We’re very confident that we will be operating under the tariffs shortly,” WPP CEO Sarah Edmonds said, asking that those in the region “come forward” with contractual and financial commitments.

Fortunately for SPP, its staff have been working closely with WPP since 2019 in helping set up and manage the WRAP. A joint task force will be established early in Phase 1 to determine how the program will interact with Markets+.

Unlike CAISO’s EDAM, the WRAP will not have a separate, binding resource-sufficiency test.

“A lot of us are at this table for that reason,” Koslow said during the meeting. “If resource adequacy was great in CAISO, this conversation would not be happening. I’m really worried about what that might look like in EDAM.”

Referring to the “challenges we’ve had with resource adequacy in the EIM,” Russ Mantifel, Bonneville’s EIM program manager, said, “It would be great … if the best landing spot for everybody was as a member of WRAP.”

SPP plans to release the final service offering in late November after it addresses the comments received in Westminster and on the draft offering. It will engage through March with the entities who have committed to funding Phase 1; staff have projected that will cost $9.7 million and take about 21 months.

Those entities that commit to the funding will be eligible to vote on design decisions and ensure Markets+ keeps moving forward, staff said. During the phase, staff and stakeholders will work on the protocols and tariff language that will be filed at FERC. At the same time, staff will explore an opportunity to add Markets+’s energy imbalance market, with a target implementation date of June 2024.

SPP has assumed that by Phase 2, when the day-ahead market is designed, Markets+ will be about a 50-GW system with up to 30 balancing authorities and 90 market participants. The phase is estimated to take three years and cost about $130 million, staff said, based on their experience with the day-ahead Integrated Marketplace they launched in 2014.

Staff said they will look for ways to minimize costs for entities who choose to transition from Markets+ to SPP’s RTO West. They said seven parties are expected to decide whether to become RTO members by March.

November 20, 2022

Klamath Dams Set for Removal After FERC OKs Delicensing

FERC last week approved the surrender of the license for the 163-MW Lower Klamath hydroelectric project straddling the California-Oregon border, setting the stage for the largest dam removal and salmon restoration effort in U.S. history.

The commission’s decision marks a major victory for local tribes and environmental groups in the region, who for years have sought the breaching of the dams to restore salmon runs to an area of the Klamath River that saw fish populations decline dramatically with the completion of the first dam in 1918. For Northwest tribes, salmon represent a traditional source of food and a vital component of cultural identity.

During the commission’s open meeting on Thursday, Chair Richard Glick said some people might wonder why a hydro plant licensee would agree to remove dams “in this time for great need for zero-emissions energy.”

“First of all, we have to understand that this doesn’t happen every day. The last time there was approval for decommissioning dams was about 10 years ago,” Glick said.

The FERC chair pointed out that the dams were built during a time “when there wasn’t as much focus on environmental issues.”

“Some of these projects have a significant impact on the environment and a significant impact on fish and other wildlife, so when companies are contemplating going through the relicensing process, people recognize that now we have new information and different laws, and so on, and sometimes these relicensing processes can be rather expensive,” he said.

Glick added that, while the Klamath dam removals “make sense” from the perspective of wildlife protection, tribal concerns weighed heavily as well.

“I think it’s a very important issue,” Glick said. “A number of years back, I don’t think the commission necessarily spent a lot of time in thinking about the impact of our decisions on tribes, and I think that’s an important element that I think is in today’s order and a number of orders recently. And I think for [the] good we’re making progress on that front. Still a ways to go, but I think we’re making the right progress there.”

A Model for Other Removals?

Culminating a process that began more than 15 years ago, last Thursday’s 174-page order authorizes Klamath River Renewal Corporation (KRRC) and PacifiCorp — the dams’ previous owner — to remove four hydroelectric developments along the river, including the J.C. Boyle Dam in Oregon and the Copco No. 1, Copco No. 2 and Iron Gate dams in California (P-2082-063).

“Never before have so many large dams been removed from a single river at one time in the U.S.,” the Congressional Research Service said in a report last March, noting that the project could become a “proof-of-concept for other major dam removals.”

The Lower Klamath Project was originally part of the 169-MW, seven-dam Klamath Hydroelectric Project, built between 1918 and the early 1960s. In 2007, PacifiCorp decided not to seek relicensing of the four lower dams following a long-running dispute over water rights and the health of salmon runs in the Klamath Basin. The utility determined that new mitigation measures that would have been required under renewed licenses for the four aging structures would be too costly to implement.

For years the dams operated under a series of interim licenses, until FERC in June 2021 approved transfer of their licenses to the KRRC, a group comprising the Yurok and Karuk tribes, area farmers, ranchers, fishermen and environmental groups. The states of California and Oregon assumed roles of co-licensees to ensure that KRRC’s decommissioning and restoration efforts had sufficient backing. (See Klamath Hydro License Transfer Approved.)

Under the terms of the transfer, PacifiCorp has continued to operate the dams until decommissioning. Three dams further upstream, which have been modernized with fish ladders to facilitate salmon runs, will remain in service.

Opponents of the dam’s removal said the reservoirs created by the projects play an important role in irrigation, flood control and wildfire protection, as well as recreation and hydroelectric production. While acknowledging those concerns in its order, the commission noted that California, Oregon and the KRRC have committed to addressing many of them, including monitoring wells currently located near the reservoirs for declines in water levels and modifying the region’s fire management plans to account for the loss of a ready water supply, including an increase in storage tanks and installation of remote, camera-monitored fire-detection systems to allow for “precise triangulation” of wildfires.

The commission acknowledged that dam removal could have mixed effects on property values, with the loss of value for formerly waterfront properties potentially offset by increased values because of improved water quality and “an enhancement of the natural riparian environment.”

The commission also noted that commenters such as Siskiyou County, Calif. — home to the three of the dams — raised concerns that removal could result in a significant reduction in their tax revenue. “While it is possible that revenues related to the presence of the project will be lost, we have previously stated that the termination of any business venture reduces tax revenues to governments but is not a reason to deny a surrender application,” FERC wrote.

Terms of Surrender

FERC’s order requires the Lower Klamath co-licensees to submit an owner’s dam safety program within 30 days, which will be effective from the termination date for each facility until removal. And, at least 60 days prior to any construction activities, the licensees must provide the secretary of the commission with final decommissioning design documents and an independent board of consultants’ review of those documents.

Within 30 days of completing decommissioning, the licensees must submit to the secretary a final decommissioning report, with photographs, which documents that the dams have been decommissioned in accordance with FERC’s order.

“The surrender of the license for the Lower Klamath Project shall not be effective until the commission’s Division of Dam Safety and Inspections – Portland Regional Engineer has issued a letter stating that the project’s facilities have been decommissioned in accordance with this surrender order and the commission’s Division of Hydropower Administration and Compliance is satisfied with the required monitoring in accordance with this surrender order,” the commission wrote.

November 18, 2022

FERC Enforcement Continues to Ramp up Activity

FERC approved 11 settlements last fiscal year that resulted in market participants paying a total of about $57.52 million in penalties and disgorgements for alleged violations, Office of Enforcement staff told commissioners at their open meeting Thursday.

The amount represented more than a sevenfold increase over the previous fiscal year’s $7.9 million, though the bulk of the money came from a massive settlement with Salem Harbor Power Development, which in June agreed to pay nearly $43.8 million in penalties and disgorgement (IN18-8). Enforcement had alleged that the company behind the Salem Harbor gas plant in Massachusetts misled ISO-NE about the construction timeline of the project and took more than $100 million in capacity payments before it was in operation. (See Developer in ISO-NE Hit with FERC Fine for Capacity Market Fraud.) The case also cost ISO-NE $500,000 for mishandling the project’s delays. (See FERC Investigation Faults ISO-NE in Capacity Market Fraud.)

The details of the case were included in Enforcement’s annual report for fiscal year 2022 (Oct. 1, 2021, to Sept. 30). Even without the Salem Harbor settlement, Enforcement still collected about $5.8 million more than it did in FY21, when FERC Chair Richard Glick lauded the office for its aggressiveness. (See FERC Enforcement Rebounds from COVID Slowdown.)

“I think the office is back in terms of being active [and] making sure it fulfills its responsibilities that the commission gives it,” Glick said Thursday, using similar rhetoric as he did last year. “It’s important to have the cop on the street so that people … think twice before they engage in market manipulation, before they try to evade a commission rule.”

Glick highlighted the fact that, of the total amount, about $34 million were returned to customers through disgorgement. But Enforcement’s Division of Audits and Accounting, he noted, also directed about $158 million to be refunded or prevented from being collected as a result of 51 findings of noncompliance. This amount was also up significantly over FY21, when it directed $18.5 million.

New investigations were also up, with the office’s Division of Investigations opening 21, compared to 12 in FY21. According to the report, “12 involved potential market manipulation, nine involved potential tariff violations and seven involved potential misrepresentations prohibited by the commission’s Duty of Candor rule. The 21 investigations involved a wide range of additional issues, including NERC’s Rules of Procedure, ISO/RTO must-offer requirements and Section 205 of the” Federal Power Act.

While it does not disclose the specifics of these investigations, the report provides some examples of those that were closed without enforcement action. Five of these were based on 10 referrals from RTO market monitors, and often the office could not find sufficient evidence any rules were broken, or it found minor, unintentional rule violations that it determined did not cause any substantial harm to the markets. The other five referrals that resulted in new investigations remain open.

“Ensuring that our energy markets are free from manipulation so that they can continue to serve consumers is a top priority at FERC, and it requires vigorous oversight and enforcement efforts,” Glick said.

November 18, 2022January 9, 2024

Former NRG CEO Faces Tough Questions at Senate ENR Hearing

Joe Manchin (Senate ENR Committee) FI.jpg

Sen. Joe Manchin | Senate ENR Committee

Sen. Joe Manchin (D-W. Va.) opened the Thursday confirmation hearing for three key posts at the Department of Energy by asking the nominees “a pretty simple, yes or no” question.

“Do any of you believe that the United States of America can be energy independent within the next 10 years without a robust clean fossil [fuel] energy program?”

And one after the other, David Crane, Jeffrey
Marootian and Gene Rodrigues all answered “no,” during the hearing of the Energy and Natural Resources Committee.

The question was particularly pointed for Crane, the controversial former CEO of independent power producer NRG, who was recently named to lead DOE’s new Office of Clean Energy Demonstrations (OCED), where he will oversee the development of both carbon capture and hydrogen hubs funded by the Infrastructure Investment and Jobs Act.

Marootian, who previously was head of the District of Columbia’s Department of Transportation, has been tapped as assistant secretary for energy efficiency and renewable energy, while Rodrigues, a former executive at Southern California Edison, will be assistant secretary for electricity delivery and energy reliability.

Sen. John Barrasso

| Senate ENR Committee

Both Manchin, committee chair, and Sen. John Barrasso (R-Wyo.), the committee’s ranking member, had tough questions for Crane, who was infamously fired from NRG in December 2015 after the company’s stock fell 63% in 11 months. He has also been outspoken on the need for utilities and corporate America to move faster on decarbonization and during his tenure at NRG closed several of the company’s coal plants.

Given the financial losses at NRG, Barrasso asked Crane, “Why should we believe that you’re going to manage the American people’s money better than you managed the NRG money?”

While dramatic, the losses at NRG were “actually consistent with [losses at] other companies in the industry” at that time, Crane said. According to a 2016 article in Greentech Media, Dynegy, an NRG competitor, saw its stock’s value tumble 50% in the same time period.

Crane also countered that his long experience “at the intersection of big capital and big energy projects” gives him the skillset needed at the OCED. He also pledged to Manchin that he would implement the carbon capture and hydrogen provisions of the IIJA “with the same vigor that I implement every other provision.”

Those provisions, along with the Inflation Reduction Act’s expansion of the 45Q tax credits for carbon capture “are catalyzing a response that I think is going to be very good for the industry,” he said.

Similarly, Crane said the response to DOE’s call for initial proposals for $7 billion in hydrogen hub funding, which closed on Nov. 7, was “extremely enthusiastic,” ensuring that the projects chosen will meet the IIJA’s requirements that hubs be located in different regions and use different fuel stocks, including fossil fuels. (See DOE Opens Solicitation for $7B in Hydrogen Hubs Funding.)

Sen. Martin Heinrich (D-N.M.) also quizzed Crane on what metrics the OCED would use “to ensure that those large demonstrations are truly addressing the key risks, to be able to move those things towards adoption [and] deployment scale?”

Crane said his office would be focusing not only on the technical side of the demonstration projects but “more on the commercial offtake. These projects not only have to operate within their ring fence, but they have to be commercially sound. …

“The Department of Energy has a lot of negotiating influence in these public-private partnerships” for demonstration projects, Crane said. “But what we can’t do is structure projects that the private sector would never replicate. I will tell you, in my two months at the DOE, the word ‘replicability’ has passed my lips more often than it has in my previous 63 years.”

From Baseload to Grid-edge

Thursday’s hearing was the first meeting of the Energy and Natural Resources Committee since last week’s midterm elections, which left Democrats in control of the Senate, and Manchin likely to retain leadership of the committee.

The hearing also underlined other key trends in energy policy in Congress and at DOE. First, the administration continues to promote its commitment to an all-of-the-above approach to decarbonization, which includes at least the potential for carbon capture and sequestration and green hydrogen to provide economic growth for the struggling fossil fuel communities Manchin and Barrasso represent.

DOE is also focused on making the projects it funds with IIJA dollars commercially viable, which has resulted in the agency recruiting industry leaders like Crane and Rodrigues.

By contrast, Marootian, whose most recent position was as a special adviser to the Office of Energy Efficiency and Renewable Energy, clearly does not have the depth or breadth of experience of Crane or Rodrigues. For example, when Heinrich asked him if DOE would help to set standards to accelerate the deployment of advanced conductors and other grid-enhancing technologies, he said only that he would be “delighted” to work on the issue.

Rodrigues, on the other hand, smoothly navigated grid-related questions from Republicans and Democrats. Responding to a query about baseload power from Sen. John Hoeven (R-N.D.), Rodrigues said that the complexity of ensuring the reliability of the U.S. electric grid means “we need a mix of resources that can be used in different ways. Baseload energy is critically important.”

A top priority for the Office of Electricity, he said, will be “ensuring that each and every state’s policy decisions, policy preferences and decisions made around the resource mix that they want to serve their constituents — that the grid is enabled to take those resources and affordably get them to the American people.”

At the same time, Rodrigues also stressed the importance of developing grid-edge resources, like vehicle-to-grid technologies, to increase reliability.

While technological barriers still need to be overcome, Rodrigues said, “if and to the extent the grid is able to accept [grid-edge] resources, to integrate them, then we will have ways to increase reliability, increase affordability.”

The Office of Electricity will work to advance these technologies, Rodrigues said, “to ensure that the visibility of these resources, the controllability of these resources and … [the] policies are in place to ensure that consumers recognize the value of being a beneficial part of how we control our grid.”

November 18, 2022December 12, 2023

NERC Warns Winter Margins Tight in Multiple Regions

NERC staff called the organization’s 2022-2023 Winter Reliability Assessment, issued on Thursday, a “serious warning” that highlighted the possibility of “bigger problems” compared to last winter in several regions, with extreme weather once again posing a major risk to grid reliability.

“When we look at events over the last several years, it’s really clear that the bulk power system is impacted by extreme weather more than it’s ever been,” said John Moura, NERC’s director of reliability assessment and system analysis, in a media call on Thursday. “And so, as we transition our system rapidly, it’s vitally important that we’re planning and operating a bulk power system that is resilient to … the extreme weather we’re seeing, which includes both generation and transmission solutions.”

The regions where NERC identified potential for insufficient electricity supplies during peak winter conditions are MISO; ERCOT; Alberta; the Maritimes region, which contain parts of Canada and the U.S.; and SERC-East, which includes North and South Carolina. In addition, the assessment marked New England as at risk of constraints to the natural gas transportation infrastructure during cold weather, which could lead to outages of gas-fueled generation sources.

Demand Rising as Capacity Falls

NERC’s winter assessments are released each year and cover the months of December through February, based on demand and generation availability forecasts provided by regional entities, utilities and other stakeholders. In Thursday’s call Mark Olson, NERC’s manager for reliability assessments, emphasized that “almost all areas are well prepared for … average winter years” and observed that some regions do, in fact, appear to be in a better position than they were last year.

For example, the WECC-Western Power Pool assessment area had a lower risk of supply shortfall based on its improved hydropower outlook from last year, while SPP was assessed at lower risk because of added natural gas and wind generation since last winter.

However, for a significant fraction of the North American electric grid, questions exist about the ability to maintain needed levels of service in the face of extreme conditions that might affect the functioning of generators while driving up demand for electricity for heating. ERCOT faces the biggest potential shortfall, with NERC calculating that under the region’s projected reserve margin could fall as much as 21% below demand in the most severe scenario.

Left: NERC’s risk-period scenario for MISO, showing a potential for load shedding under extreme conditions; Right: the same projection for ERCOT. | NERC

No other region approaches ERCOT’s assessed risk: The closest is the Maritimes — comprising the Canadian provinces of New Brunswick, Nova Scotia and Prince Edward Island; and Northern Maine, which is not part of ISO-NE — which has a potential 8.6% shortfall. MISO could come short by as much as 7.6%, while Alberta, which is in WECC’s footprint, has a potential 1.1% deficit.

John Moura, NERC | NERC

One reason the possible shortfall in Texas is so high, Olson said, is that unlike other regions, ERCOT has “very little transfers that can come help in the event that they do [have] energy emergencies.” Demand in Texas is also very sensitive to cold weather because of electric heating demand, which “significantly uses more electricity” as the temperature drops.

On the other hand, Olson pointed out that ERCOT has implemented a number of improvements to cold weather performance since the winter storms of February 2021 that “also should improve the fuel availability to the natural gas-fired generators.” Moura added that while NERC only assesses the readiness of the bulk electric system, he was “sure” that those responsible for regulating the natural gas supply “have made strides” in preparing their system.

For MISO, reserve margins have fallen by more than 5% since last winter, largely because of more than 4.2 GW in nuclear and coal-fired generation retirements. While 2.25 GW of demand response and wind generation with nameplate capacity of 3.2 GW have been added, Olson reminded listeners that the inherent uncertainty around the weather impacts the availability of these resources.

“If wind comes in below projections … that can drive whether there is an energy emergency or not in MISO,” Olson said. “If it’s low, it’s more likely to have emergencies, and if it’s high, it can alleviate some of those concerns.”

Coordination Recommended

NERC’s assessment includes several recommendations to utilities to lower the risk of energy shortfalls this winter. The first is for balancing authorities and reliability coordinators to work with generator owners to ensure adequate fuel supplies both for normal and extreme conditions; this includes filling storage capacity, preparing fuel delivery systems, and coordinating with fuel providers to make sure additional fuel can be secured when needed. GOs should keep BAs and RCs apprised of their fuel levels and readiness as well, while RCs and BAs should actively monitor fuel adequacy and be prepared to step in with “proactive steps” to assist if needed.

The ERO also said policymakers at the state and provincial levels should be aware of energy risks for the winter season as well, and delay generation retirements if they are likely to negatively impact reliability. State regulators can also support environmental and transportation waivers requested by grid operators (GOPs) in the event of cold weather, in addition to issuing public appeals for electricity and gas conservation.

Finally, the assessment recommends that grid operators, GOs and GOPs implement the mitigations in NERC’s recent Level 2 alert related to cold weather preparations, as well as any additional recommended winterization steps for their facilities.

November 18, 2022

NY OSW Proposal Advances After Revisions

Sunrise Wind cleared a significant regulatory hurdle Thursday after the New York Public Service Commission approved a certificate of environmental compatibility and public need for the project planned off the coast of eastern Long Island.

Long Island commercial fishermen initially had raised objections to the offshore wind project but joined in support after nearly a year of negotiations and revisions to the plan.

One PSC commissioner hailed the outcome as a precedent in what will be a series of offshore wind projects churning through the application process in New York, where state law mandates 9 GW of OSW be online by 2035 and where some models predict the need for 20 GW by 2050.

In fact, the U.S. Bureau of Ocean Energy Management earlier in the week issued a draft environmental impact statement for Empire Wind 1 and 2 off western Long Island that found the cumulative impact of offshore wind projects in the New York Bight would have a major negative impact on the fishing industry, to a degree “beyond what is normally acceptable.”

Sunrise Wind

Sunrise Wind is a joint venture of Orsted (OTC:DNNGY) and Eversource (NYSE:ES), which have begun construction of the 124-MW South Fork Wind project in the same vicinity. Sunrise would stand about 30 miles offshore from Montauk and generate up to 924 MW of energy. The cables that would carry that power to land were a point of contention for the Long Island Commercial Fishing Association.

“LICFA raised several concerns at the outset of the case, noting that its constituency of 300 commercial fishers was potentially impacted more than any other group by the submarine cable pathway and landing site,” Michael Clarke, the PSC administrative law judge presiding over the proceeding, said during Thursday’s PSC meeting.

“After 10 months of settlement discussions, Sunrise committed to various design changes that will significantly reduce impacts arising from the project, including those affecting benthic resources and water quality, as well as those potentially affecting the commercial fishing industry,” he said.

A critical change was bringing the export cable onto Long Island with one bore at the landfall site rather than the three that were part of the original plan, Clarke said.

The revised plan also requires substantial outreach and notice to the fishing community during construction, he said.

Sunrise must submit a fisheries compensation plan with a claims process for loss of commercial fishing gear and a monitoring plan that ensures the impact on fisheries and fishing operations are minimized.

In September, Sunrise, LICFA and five state agencies signed off on a joint proposal. With that, Clarke said, there is no publicly stated opposition to the power line.

PSC Chair Rory Christian and several of the commissioners praised the successful effort to bridge a gap and bring New York one step closer to operating an offshore wind industry that will help it meet its climate-protection goals.

Among them was Commissioner John Howard, who called the joint proposal (and the delicate process that yielded it) a model for future planning and review.

He then voted against approving the certificate as a protest against its cost structure. Long Island Power Authority customers would pay 13.5% of its costs, he said, while upstaters would derive no benefit and bear 50% of the cost.

“I’m going to do this every time a project comes up that is based on a load-share ratio financing scheme,” Howard said. “Everybody pays. Sometimes the biggest beneficiaries pay the least. In this case, I believe that is the case.

“If we’re going to ask everyone in the state of New York to pay, that decision should be done not through a regulatory fiat but directly through legislation.”

Howard’s was the sole no vote on Sunrise. He previously has voted against matters involving the Champlain Hudson Power Express line from Quebec to New York City for the same reason and did so again Thursday.

Later Thursday, Sunrise Wind spokesperson Meaghan Wims said:

“Sunrise Wind has reached a major milestone with the approval of a key state permit needed to build this important New York clean energy project. The New York Public Service Commission’s approval affirms that Sunrise Wind can be built while minimizing community and environmental impacts and helping New York State achieve its vision for a 100% clean energy future. We thank the PSC and its staff for its diligent review of the proposed project, which included extensive analyses and contributions by experts across multiple state agencies as well as input from the Long Island community, resulting in an unopposed project submission.”

Wims said Sunrise will next submit its environmental management and construction plans to the state Department of Public Service. Once they are approved, Sunrise can obtain a notice to proceed, allowing construction to start.

BOEM is targeting Dec. 16 for release of the draft environmental impact statement for Sunrise Wind.

Wims said Sunrise expects to be fully permitted at the state and federal level by the end of 2023.

Empire Wind

BOEM on Monday released its draft environmental impact statement on the construction and operation plan submitted for Empire Wind 1 and 2.

That opened a 60-day public comment period that will lead to a final impact statement and inform BOEM’s decision to approve, approve with modifications or reject the plan submitted by Empire Offshore Wind LLC, a joint venture of Equinor (NYSE:EQNR) and BP (NYSE:BP).

Combined, the two wind farms would include up to 147 turbines with a capacity of 2.1 GW. Some 260 miles of inter-array cables and 66 miles of export cables buried 6 to 15 feet below the seabed would connect the turbines to two offshore substations and two onshore substations via three landfall points.

The draft study includes comparison of eight alternative design scenarios that emerged during the review process, each of them tweaking construction techniques or placement of turbines or cables in some manner. The overall projected impacts were the same for all scenarios in every analysis, however.

The draft study found Empire Wind’s adverse impacts would be greatest on fishing, cultural resources and ocean views.

Cumulatively with other offshore wind projects planned in the region, the wind farm would have major negative impact for commercial fisheries and minor to moderate negative impact on recreational fishing due to new structures installed in the ocean that would result in navigational hazards, damaged or lost fishing gear and space-use conflicts.

The cumulative impacts would be “beyond what is normally acceptable” but mitigation, including financial compensation and uniform spacing and layout of turbines, could reduce the impacts.

The cultural impact of the project — its effect on historic sites and archaeologically significant places above or below water — will range from negligible to major, BOEM said, depending on the effectiveness of mitigation measures.

An unobstructed view of the sea is a key part of the heritage of multiple historic districts, for example, and they will lose that once scores of wind turbines dot the horizon, with blades reaching up to 951 feet above the water and warning lights glowing at night. The developers have agreed to use non-reflective white and light-gray paint on offshore structures, and to seek permission to use a hazard light system that turns on only when a plane or surface vessel is in the area.

Among other findings in the draft BOEM report:

The project generally would have a major disruptive impact on scientific research and surveys, particularly National Ocean and Atmospheric Administration surveys supporting commercial fisheries and protected-species programs. The structures placed in the sea would preclude aerial sampling and affect performance of survey gear.
The planned upgrades to regional ports for support of construction, operations and maintenance would have major beneficial impacts.
Air quality would be degraded by emissions caused by construction of the project and by routine maintenance once the project is complete. But emission-free wind power would displace fossil fuel power generation, and the net impact on air quality would be positive.
Birds would experience minor positive and minor negative impacts: Some would lose shore habitat; some would be killed by spinning rotors; and some would gain increased forage opportunities.
Minor to moderate economic and employment benefit is predicted, mainly from the creation of a support facility onshore in Brooklyn.
Environmental justice, a frequently stated goal of New York’s clean energy transition, would gain a minor boost through increased economic activity and see minor to moderate negative impact from the increased traffic, gentrification, air emissions, noise and land disturbances that activity creates.
Search and rescue efforts might be hindered during emergencies. The project would create underwater reefs favorable to sportfish, which would improve for-hire recreational fishing options, and could increase the number of vessels operating in the area. That would increase the chance of an accident, after which aircraft would have to fly less-effective search patterns, lest they crash into a tower or rotor blade, increasing the likelihood of preventable loss of life.
Sea turtles would likely experience some impact from the project, but not enough for a population-level impact.

Equinor welcomed the draft report, saying via email:

“We appreciate all the hard work from the Bureau of Ocean Energy Management staff and cooperating agencies to achieve this critical milestone. We look forward to reviewing the Draft Environmental Impact Statement and receiving feedback from the public on the Empire Wind Project. This is a major milestone in our effort to help New York State achieve its offshore wind ambitions.”

The New York State Energy Research and Development Authority, which is shepherding New York’s offshore wind sector into existence, said Thursday in a statement:

“The availability of BOEM’s Draft Environmental Impact Statement for Empire Wind is a major permitting milestone and a culmination of years of research and collaboration to understand and minimize impacts to the environment and to support vital fisheries. We commend BOEM and Equinor on this important achievement that will ensure the project moves forward responsibly in support of New York’s goal for at least 9,000 megawatts of offshore wind by 2035. The development of Empire Wind is expected to bring billions in economic benefits to the state, including investments in frontline and historically underserved communities, offshore wind component manufacturing in Albany, and a staging and assembly facility at South Brooklyn Marine Terminal and will deliver significant amounts of clean renewable energy to New York’s electricity grid once completed.”

November 18, 2022June 14, 2023

Public Citizen: Natural Gas Exports Driving up US Gas, Power Prices

A surge this year in U.S. LNG exports — some with long-term contracts to Asia — is driving up domestic natural gas prices and contributing to uncertainty about the reliability of the electric grid as winter begins, according to consumer watchdog Public Citizen.

LNG exporting companies must seek approval from the Department of Energy as well as from FERC. But DOE is not scrutinizing the impact of the growing exports on domestic markets, Public Citizen’s Tyson Slocum said in a news conference Thursday.

Public Citizen and seven other consumer groups less than a month ago appealed to DOE to use its statutory authority and order a “substantive analysis” as required by the Natural Gas Act to determine the impact of additional U.S. export terminals on domestic markets.

In a letter to Energy Secretary Jennifer Granholm, the consortium said that the exports are “binding American household energy bills to global calamities, resulting in a domestic energy pricing crisis.” They argued that DOE must develop a better analytical tool to measure the impact of unbridled LNG exports. The letter also noted that LNG exporters are charging European customers whatever the market will bear.

“To protect our European allies from price-gouging, DOE must condition any export authorization utilizing a global energy security justification to be subject to a cost-of-service standard tied to the landed delivery price,” the groups reasoned.

Slocum argued that DOE’s reliance on an economic study rather than a detailed analysis of every LNG export application is at the heart of the problem.

“The Department of Energy relies almost exclusively on a 2018 macroeconomic study,” he said. The study “concludes that exports at roughly the same levels that are being exported today will provide net economic benefits. They projected no increase in costs in natural gas prices domestically.

“And the report that the Biden administration relies upon from 2018 states that even if domestic energy prices were to increase, the income that families would receive from their stock ownership in LNG export terminals would exceed any increase in their monthly energy bills, which is a preposterous and wholly unsupported assertion,” he said.

In response to a question, Slocum said the consumer groups have been talking to congressional members about the issue.

John C. Allaire, a veteran environmental manager for the oil and gas industry who is now opposing a proposed LNG terminal in Texas, said China was the second largest importer of U.S. LNG last year. “But they’re not our friends,” he said. “It’s not in the interest of the U.S., but we don’t have a long-term plan. Our plan is to get it out of the ground and sell it to the highest bidder.”

DOE’s efforts to jumpstart the production and use of hydrogen in the U.S. through $8 billion in matching grants to assist industry and local governments create hydrogen hubs is likely to further complicate matters. At least two of the hubs DOE wants to fund will produce hydrogen from natural gas.

Because blue hydrogen producers will be dealing “with increasingly expensive feedstock costs to acquire that natural gas, and they’re going to be in direct competition with LNG exporters, I just don’t see that LNG exports are consistent with these efforts to try and build a domestic hydrogen production economy in any sort of meaningful way,” said Slocum.

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.