NERC’s Standards Committee last week declined to advance a project to modify reporting requirements for cybersecurity incidents, seeking a fuller response to stakeholder criticism of the draft standard authorization request (SAR).
Project 2022-05 (Modifications to CIP-008 reporting threshold) aims to update reliability standard CIP-008-6 to “provide a minimum expectation for … the definition of attempt to compromise” as recommended in a NERC white paper published last year. The Standards Committee approved the draft SAR at its meeting in September and authorized its posting for a 30-day informal comment period, which ran from Nov. 2 through Dec. 5, 2022. (See NERC Staff, Stakeholders Feeling Work Crunch.)
NERC’s recommendation to the committee was to accept the revised SAR submitted by the SAR drafting team, but at last week’s monthly teleconference, several committee members objected to moving forward with the project as is. SPP’s Charles Yeung opened discussion on the measure by pointing out that respondents submitted “many negative comments about the scope” of the project. Although the initial comment period was informal and the SAR drafting team was not required to address comments in the final draft SAR, Yeung said it would be a mistake to move forward without considering the negative feedback.
“I know from the ISOs’ perspective, we felt that there [were] alternatives to CIP-008 revisions,” Yeung said. “I want to be sure that the Standards Committee is comfortable approving a SAR that had so many negative comments, and I believe … that the scope [of the project] is broad enough to be able to address all the concerns.”
Latrice Harkness, NERC’s director of standards development, told Yeung that the team “did review those comments … and determined that the SAR allowed the team multiple avenues to pursue the needed changes.”
Unsatisfied, Yeung responded that “there could be concerns further down the road … on what exactly is acceptable … because there [are] no real guardrails on how this will proceed.” He said he hoped for “a way for those concerns to be re-elevated during the drafting process and … have them addressed individually.”
Other participants sided with Yeung; Philip Winston, formerly of Southern Co., said the thought of giving the SAR drafting team too much freedom to define the project’s scope made him “uncomfortable” and that the SAR should be sent back to the team for refinement. Yeung proposed postponing approval of the SAR indefinitely and requesting the drafting team address their concerns in a response. This motion passed unanimously.
Formal Comments for Facility SARs
Members also voted to modify a proposal to accept two SARs for modifying NERC’s facility ratings standards, though in this case they did agree to move the SARs through to the next development stage.
The proposed SARs were proposed by NERC’s System Planning Impacts from Distributed Energy Resources Working Group and endorsed by the Reliability and Security Technical Committee at its last meeting in March. (See NERC RSTC OKs Standards Projects, Reliability Guidelines.) They are intended to modify existing reliability standards FAC-001-4 (Facility interconnection requirements) and FAC-002-4 (Facility interconnection studies) to require more consideration of potential reliability impacts from distributed energy resources (DER) before they are integrated to the electric grid.
Michael Jones of National Grid pointed out that because the proposal concerns DERs it could be seen as “reaching down into distribution,” and therefore concerns a wider array of industry players than measures that affect only the transmission system. As a result, he moved for the standard informal comment period to be replaced with a formal period that would obligate the SAR drafting team to respond to comments.
Jones said this idea would “help build consensus and save time during the actual development process” because the team would be aware of potential objections ahead of time, rather than having them emerge during later ballot periods. His motion, which passed unanimously, allowed solicitation of SAR drafting team members in addition to posting the SARs for a formal comment period.
Governors of the three states comprising the lower Colorado River Basin — California, Arizona and Nevada — announced Monday that they have agreed to a three-year water conservation plan aimed at protecting the drought-stricken Colorado River system.
The proposed plan still needs to go through a federal approval process, but if the Lower Basin Plan is approved, the three states would conserve at least an additional 3 million acre-feet of Colorado River water by the end of 2026, including at least 1.5 million acre-feet by the end of 2024.
Arizona Gov. Katie Hobbs, California Gov. Gavin Newsom and Nevada Gov. Joe Lombardo said the plan emphasizes substantial, near-term water conservation to reduce the risk of Lake Mead and Lake Powell dropping to critically low levels.
The plan would involve voluntary agreements with tribes, cities and agricultural water users in the three states, the governors said in a letter to Interior Secretary Deb Haaland.
“It’s never been more important to protect the Colorado River System, and this partnership is a critical next step in our efforts to sustain this essential water supply,” Lombardo said in a statement.
The conservation of up to 2.3 million acre-feet would be compensated through the federal Inflation Reduction Act, which includes drought mitigation funding. The remainder of the conserved water would be compensated by state or local entities — or be uncompensated.
“Thanks to the partnership of our fellow Basin states and historic investments in drought funding, we now have a path forward to build our reservoirs back up in the near-term,” Hobbs said in a statement.
But the Arizona governor noted that further action is needed to address the long-term issues of climate change and overallocation “to ensure we have a sustainable Colorado River for all who rely upon it.”
Review Process
The four states of the Colorado River’s Upper Basin — Colorado, New Mexico, Utah and Wyoming — joined the three Lower Basin states in sending a letter to Bureau of Reclamation Commissioner Camille Calimlim Touton, stating their support for submission of the Lower Basin Plan.
However, the Upper Basin States said they need time to thoroughly review the plan.
“Nothing in this letter should be construed as an Upper Basin endorsement of the Lower Basin Plan,” the letter states.
The submission of the Lower Basin Plan follows the Department of the Interior’s release last month of a draft supplemental environmental impact statement for near-term Colorado River operations. The comment period on the draft SEIS was scheduled to end on May 30.
But in response to the three states’ proposal, the department announced on Monday that it is withdrawing the draft SEIS. The Bureau of Reclamation plans to update the document to include analysis of the Lower Basin Plan as an action alternative. Officials expect to complete the SEIS process this year.
Risk Remains
A historic drought in the Colorado River Basin prompted the Bureau of Reclamation to declare its first water shortage for Lake Mead in 2021. The declaration meant water supply cutbacks to Arizona, Nevada and Mexico. Another Lake Mead shortage was declared last year.
Last month, Reclamation announced above-average projections for this water year and said downstream flows from Lake Powell to Lake Mead would be increased.
But “despite this year’s welcomed snow, the Colorado River system remains at risk from the ongoing impacts of the climate crisis,” Touton said.
According to the Interior Department, 40 million people, seven states, and 30 tribal nations depend on the Colorado River for drinking water and electricity.
Glen Canyon Dam at Lake Powell and Hoover Dam at Lake Mead generate on average 5 billion KWh and 4 billion KWh a year, respectively. As recently as this winter, federal water officials were warning that Lake Mead could reach the “dead pool” level for hydroelectric generation by 2025, with Lake Powell close behind, but conditions have improved.
According to the letter from the three governors, modeling shows that the Lower Basin Plan would provide greater protection for Lake Mead and Lake Powell than the alternatives analyzed in the draft SEIS.
The Lower Basin Plan would also allow the Basin states and the Bureau of Reclamation to turn its focus to Colorado River operations after 2026, the letter said.
Pennsylvania regulators last week agreed to set guidelines for electric vehicle charging rates, with deadlines and demand charges among the key issues to be decided.
Acting on a petition filed last year by a coalition supporting EV adoption, the Public Utility Commission voted 5-0 Thursday to direct its Law Bureau and Bureau of Technical Utility Services to prepare a proposed policy statement for consideration (P-2022-3030743).
In December, the commission responded to the petition by creating the EV Charging Rate Design Working Group, which included utilities, consumer advocates, state agencies, EV manufacturers, businesses, environmental organizations and trade organizations. The group’s recommendations report in March signaled agreement that EV rates should be voluntary, avoid cross-subsidization between customers or rate classes (i.e., residential, commercial, industrial) and allow the state’s 11 electric distribution companies (EDCs) to craft terms specific to their service territories.
But the report showed several key issues on which stakeholders were unable to reach consensus, including how quickly the rates should be instituted and how to prevent demand charges from squelching development of public charging sites.
Also undecided is whether the PUC should allow use of whole-house meters or require separate charging meters for time-of-use (TOU) rates and how to incentivize customers not using default electric service.
As of November 2020, Pennsylvania had more than 29,000 EVs, less than 1% of its more than 12 million registered vehicles, but more than double the number at the end of 2017. The International Council on Clean Transportation predicted in January that the incentives in the Inflation Reduction Act would give light-duty EVs a 48%–61% market share by 2030.
PUC Vice Chair Stephen M. DeFrank said electric vehicles will cause a “sea-change in the transportation sector” that necessitates a rethinking of the state’s electric rate structure. | Pa. PUC
“This impending sea-change in the transportation sector presents an opportunity for our electric utilities as increased consumption from EVs can work to defray traditional customer distribution system costs,” PUC Vice Chair Stephen M. DeFrank said in a statement Thursday, in which he was joined by Commissioner Kathryn L. Zerfuss. “It is incumbent on this commission and the regulated electric utility industry to consider and adopt rate structures that foster the most effective and equitable use of the distribution grid to the benefit of all consumers.”
Deadlines, Minimum Requirements
The commission’s order left unresolved whether the state’s EDCs will face a deadline for submitting EV rates. Currently, Duquesne Light, PECO (NASDAQ:EXC) and UGI (NYSE:UGI) have won commission approval for programs to promote EVs, including incentives, customer education and installation of public chargers.
ChargEVC-PA, the Alliance for Transportation Electrification and the NRDC called for a Dec. 31 deadline, arguing the expected load growth from EV adoption could increase system costs unless off-peak charging is encouraged by new rate design.
But utilities Duquesne, FirstEnergy (NYSE:FE), PECO and PPL (NYSE:PPL) opposed a deadline or “minimum filing requirements that are more prescriptive than those required for any other utility rate design proposal.”
Duquesne, FirstEnergy, the Office of Consumer Advocate, and the Coalition for Affordable Utility Services and Energy Efficiency in Pennsylvania proposed that EV charging programs be initially designed as pilots to acknowledge the “evolving nature” of EV adoption.
But NRDC contended limiting EV rates to pilots would undermine customer adoption. “Customers need a reasonable degree of certainty regarding the economics of EV charging (and the continued existence of EV rates altogether) to make significant investments in EVs, and pilot rates will not provide that,” the group said.
The Economics of Public Charging
Another issue before the PUC is how to create rules that encourage public charging sites.
Convenience store chains Sheetz and Wawa and other fuel retailers represented by the Pennsylvania Petroleum Association said the PUC should ensure that all operators of public DC fast chargers have “the same competitive risks and the same access to wholesale electricity rates” to prevent a competitive advantage for utility-owned chargers. Otherwise, they said, non-utility providers would effectively have to purchase electricity at retail and sell at retail. “Buying and selling at retail is not a viable business plan,” they said.
The gasoline retailers added that utilities would also have a competitive advantage if they were permitted to impose demand charges on them but not on their own chargers, or if they were allowed to use ratepayer funds to own and operate chargers.
“If an electric utility chooses to own and operate EV charging stations, they should only be able to do so through a separate, non-rate regulated affiliate that cannot be cross-subsidized with their regulated business,” the retailers said.
PECO, however, said current state law may prevent the PUC from allowing “any rate designs tied to utility ownership of charging stations.”
EV charging networks Electrify America, ChargePoint and EVgo raised concerns over demand charges, which they said pose significant barriers to the deployment of public DCFC stations.
The working group noted that public charging sites “may initially experience low utilization and thus low electric load factors.”
“In such cases, standard demand charges may serve as an economic barrier to prospective development of public charging sites,” the working group said. “On the other hand, equity considerations demand that, in the long run, all types of utility customers, including EV charging owners, pay their fair share of the utility’s fully distributed cost of service. Moreover, DCFC demand charges can play a constructive function in disincentivizing localized overbuilding of DCFC stations that would inhibit stations from reaching economically self-sustaining utilization levels.”
PECO said the commission’s policy statement should consider the PUC’s separate energy storage proceeding (M-2020-3022877). “Energy storage has the potential to mitigate concerns regarding demand charges, as well as tangentially related rate designs for net metering,” the working group said.
Customer Credits and Retail Choice
Another complication for incentivizing off-peak charging is Pennsylvania’s retail customer choice law, enacted in 1996. As of last year, about 30% of the state’s residential customers were served by competitive suppliers.
The Consumer Advocate, ChargEVC-PA and Advanced Energy United said EV charging credits could be offered to only customers receiving default service unless electric generation suppliers (EGSs) agree to participate.
“Electric generation suppliers have no legal or regulatory obligation to align their own EV-specific rate plans with those of the default service provider or electric distribution company, meaning that alignment is not necessarily possible in scenarios where customers elect to shop,” PECO said.
PECO also raised a related issue, saying aligning supply and distribution rates for EV charging, “while desirable from a customer perspective for simplicity, may be challenging due to variances between system generation peaks and localized distribution peaks.”
The EGS Coalition — NRG Energy (NYSE:NRG), Interstate Gas Supply and Vistra (NYSE:VST) — was the only group to file comments opposing ChargEVC-PA’s petition. The coalition said EV-specific rate designs should be left to EGSs alone, contending the role of EDCs in electric supply “is limited to providing default service to non-shopping customers and does not include the offering of a range of alternative rate design options.”
ChargEVC-PA, however, said EGS’ position “is at odds with Pennsylvania law and precedent,” citing a 2020 PUC ruling.
ChargEVC-PA also challenged the EGS Coalition’s proposal that EDCs be required to make TOU rates the default for customers, and that customer education on EVs be handled exclusively by competitive suppliers and not by EDCs. The arguments are “directed more at enhancing market opportunities for EGSs than advancing EV adoption for the benefit of customers,” the petitioners said.
At Stake in EV Charging Rules: Pennsylvania’s $20 Billion Gasoline Industry
Electric vehicles have the potential to upend two billion-dollar markets in Pennsylvania: gasoline retailing and electric sales.
Pennsylvania’s 12 million registered vehicles consume an average of 4.9 billion gallons of gasoline annually,[1] a market worth $19.9 billion at the current midgrade price of $4.04/gallon.[2]
Pennsylvania electric customers consumed 143.3 million MWh in 2021, a retail market of $14.3 billion at an average price of 9.97 (cents/kWh).[3]
In an unmanaged charging scenario — chosen by the U.S. Department of Energy as a worst case — 12 GW of dispatchable generating capacity would be needed to meet the demand of nearly 6 million EVs — equivalent to half of Pennsylvania’s vehicles.[4]
Pennsylvania has more than 3,600 retail fueling locations, according to the Pennsylvania Petroleum Association, most of them with multiple pumps.[5] Assuming an average of six pumps per location, pumps would total almost 22,000.
In comparison, the state had 1,920 public EV chargers as of 2020: 1,355 Level 2 chargers, 114 DC fast chargers and 451 Tesla chargers.[6] S&P forecasts the U.S. will need to quadruple the number of chargers between 2022 and 2025 and grow them more than eight-fold by 2030.[7]
The New Jersey Senate approved two new commissioners — Christine Guhl-Sadovy and Marian Abdou — for the state Board of Public Utilities (BPU) Monday, bringing the five-member board to full strength as it heads the state’s ambitious clean energy program.
Former Commissioner Robert Gordon | NJ BPU
Guhl-Sadovy, who has a history of working in clean energy and most recently was cabinet secretary for Democratic Gov. Phil Murphy, will replace Robert Gordon, a Murphy appointee whose term expired March 15. The Senate backed her with a 22-14 vote that ran along party lines; Abdou, who drew support from both parties, was confirmed by a 30-0 vote.
Abdou, managing senior counsel at NRG Energy (NYSE:NRG), will replace Dianne Solomon, who was nominated by Republican Gov. Chris Christie in 2013 and whose term expires in October 2024. Abdou has also worked at Direct Energy and Hess Corp.
The two commissioners will join the BPU as it implements an extensive portfolio of clean energy projects in line with the policies of Murphy, who outlined a plan in February for the state to accelerate its carbon reduction programs and reach 100% clean energy by 2035. Murphy had previously set out a goal in the Energy Master Plan of 100% clean energy by 2050.
Electric Transmission Policy
The projects include a third solicitation for offshore wind projects to help the state reach a goal of 11 GW, and implementation of new solar incentive programs, including a permanent community solar and grid-scale solar initiatives. The agency also is overseeing a host of incentive programs to promote the purchase of electric vehicles and the installation of chargers, and a push to replace fossil fuel boilers and heating systems with electric systems.
Commissioner Dianne Solomon | NJ BPU
The BPU is also faced with engineering an upgrade to the state grid necessitated by increased amounts of variable renewable generation.
Last week, FERCappointed BPU President Joseph L. Fiordaliso to the Joint Federal-State Task Force on Electric Transmission. The agency focuses on topics related to planning and paying for transmission — including facilitating generator interconnection — that provides benefits from a federal and state perspective.
Fiordaliso, who was nominated by the National Association of Regulatory Utility Commissioners, has frequently expressed concern about the ability of New Jersey’s grid to handle the extra load of the state’s rapidly expanding clean energy generation sector. Fiordaliso and Commissioner John B. Howard of the New York Public Service Commission will replace Chair Jason Stanek of the Maryland Public Service Commission, and Chair Gladys Brown Dutrieuille of the Pennsylvania Public Utility Commission.
Both resigned from the task force effective May 1, 2023; Fiordaliso and Howard will serve the remainder of their predecessors’ one-year terms, which expire on Aug. 31, 2023.
The Task Force is comprised of all FERC Commissioners, as well as representatives from 10 state commissions.
Implications for New Jersey
Murphy nominated Guhl-Sadovy and Abdou in March, and they secured approval from the Senate Judiciary Hearing on March 20 in the face of some skepticism from both Democrats and Republicans. GOP lawmakers then stymied an effort to use an accelerated schedule to get the nominations approved at a senate session the same day.
Guhl-Sadovy joined the Murphy administration at the BPU, where she rose to the position of chief of staff to Fiordaliso, according to her biography on the state website. She helped “spearhead” Murphy’s clean energy agenda, working on the governor’s 2019 Master Plan, the implementation of the 2018 Clean Energy Act and the development of the state’s EV incentive plan, according to the website.
She previously had spent five years advocating for clean energy policies at the New Jersey branch of the Sierra Club, where she worked on the Beyond Coal campaign, which seeks to close all the coal-fired plants in the U.S. Subsequent to that, Guhl-Sadovy was political director for Planned Parenthood Action Fund of New Jersey and worked to elect pro-women’s health candidates, according to the site.
Guhl-Sadovy told the Judiciary Committee that she considered the position “the opportunity of a lifetime.”
“Climate change has far-reaching impacts globally and severe implications for New Jersey,” she said. “We cannot afford inaction. That’s why I’m proud to serve in Governor Murphy’s administration, where we have put New Jersey at the forefront of addressing climate impacts by investing in clean energy.”
Abdou joined NRG in 2016 and has worked on a variety of commercial issues affecting the company’s generation assets and provided legal support to both the development and energy services groups, according to Murphy’s office. The company generates electricity and provides energy solutions and natural gas to millions of customers, according to the company website. NRG operates 10 natural gas plants, a nuclear plant, a solar plant and four coal plants, according to the site.
Abdou said that after her career as a “corporate generalist,” she believed the skills she accrued would serve her well on the BPU.
“I do not take lightly the responsibilities of the position for which I have been nominated,” she said “While at present time I am not a subject-matter expert on the inner workings of the BPU, I pledge that if confirmed I will apply the same skills that I have used throughout my professional legal career — namely, I will educate myself on the facts, give due consideration to the facts at hand, and used a measured and balanced approach to reach a conclusion.”
More Than Science and Policy
Both Democrats and Republicans sitting on the Senate Judiciary Committee had concerns.
Sen. Jon M. Bramnick (R), said that when he interviewed Abdou he assumed that Murphy would pick someone “who wasn’t going to be fair or objective” but support his “fairly extreme” policies. He said he went through the policies with her “and I got no sense that you had a preconceived opinion prior to going on this board, your background was corporate, it was very objective, and actually the least political person I have met.
“You knew nothing about the politics, nothing about the process, actually nothing about the whales, nothing about the windmills, and nothing about electrifying the entire State of New Jersey,” Bramnick said in the hearing. “So, I felt that was a good start. Let’s be clear. We hope, and I am sure you will be, that objective person.”
Before supporting the two nominations, Sen. Paul Sarlo (D), said he supports clean energy, but has concerns that as commissioners they and their board colleagues need to take a broader view of the impact of their decisions than simply the science and logic.
“I don’t want people to think that we’re going there to make an eighth-grade science project,” he said. “We have to be practical. I implore all those who serve on the BPU: There’s much more to the science and the policy. There’s a practicality aspect, and there’s a cost aspect, and we have to make sure we balance the needs of both of them.”
CARMEL, Ind. — MISO this week said it will likely have little firm generating capacity to spare in managing typical summertime peaks this year.
John Harmon, director of market administration, said during a Reliability Subcommittee meeting Tuesday that the RTO is “continuing a trend where it increasingly relies on emergency resources, primarily in the form of load-modifying resources, and imports to manage peak loads.”
He added that MISO could exhaust both its firm resources stack and emergency supplies if it encounters high outages and load in June and July. In August, a high-load, high-outage scenario would leave the grid operator with a slim 500 MW of emergency resources.
MISO expects to have 115 GW of accredited resources in June, 123 GW in July and 121 GW in August to meet respective peak loads of 115 GW, 123 GW and 120 GW. The grid operator projects “sufficient firm resources” to cover the summer forecasts. However, if it falls short of meeting demand even under typical conditions, it can declare emergencies so it can access more than 11 GW of emergency padding from load-modifying resources.
MISO normally experiences a little more than 15 GW in forced generation outages and nearly 22 GW in total outages during the summer months.
The spring months have been uneventful so far. MISO averaged a 71-GW systemwide load in March, peaking at 89 GW on March 20. Natural gas accounted for the biggest slice (38%) of the fuel mix, followed by coal (24%), wind (19%) and nuclear (15%). Average real-time prices fell from $42/MWh last March to $26/MWh.
The RTO called for conservative operations — requesting deferred maintenance on facilities so they could be returned to service — in Indiana, Kentucky and Illinois after an outbreak of tornados and high winds March 31-April 1. It also issued a footprint-wide severe weather alert April 4-5 as a swath of severe thunderstorms moved across the country.
Besides those exceptions, Harmon said, the system “performed as expected.” Load averaged 66 GW during the month, with a 78-GW peak April 4. The month’s real-time prices dropped from a $60/MWh average last year to $26/MWh. April’s fuel mix was natural gas (36%), wind (23%), coal (21%) and nuclear (16%).
MISO recorded an all-time solar generation peak of 2.7 GW on May 4.
General Electric will create an onshore wind turbine assembly line in New York in response to increased demand amid federal incentives, the company announced Tuesday.
The move will entail a $50 million investment in the main steam turbine and generator fabrication building in Schenectady. Approximately 200 new full-time employees will be hired for the operation, which is expected to start production by early fall.
The manufacturing line will assemble the machine head, hub, drive train and other key components of GE’s 6.1-158 turbine, a 6.1-MW low to medium wind-speed platform that has recorded more than 4 million operating hours worldwide. The company has received orders for the model totaling nearly 10 GW of nameplate capacity.
GE Vernova’s 6-MW wind turbines are shown in northern New York. The company announced Tuesday it would create a manufacturing line for the turbines in Schenectady, N.Y. | GE Vernova
The announcement came from GE Vernova, the portfolio of energy businesses that is scheduled for spinoff in early 2024. CEO Scott Strazik said the move was prompted by federal incentives for renewable energy development offered by the Inflation Reduction Act and, more recently, the domestic content guidelines to developers hoping to claim those incentives.
“We applaud the administration for the recent domestic content guidance, which gives us the certainty to move forward on this exciting project, and look forward to supporting additional guidance,” Strazik said in a news release. “We’re proud to expand our American manufacturing footprint and workforce to continue building and innovating energy technology that is cleaner by bringing wind turbine component assembly — and an estimated 200 new jobs — to New York.”
GE made a larger but less definitive announcement earlier this year near Schenectady: It will build two offshore wind component factories along the Hudson River with a combined workforce estimated at 870, but only if it receives sufficient orders for its products through the state’s offshore wind buildout.
Subsequent developments have been promising. All six developers submitting proposals in the latest New York solicitation indicated they would rely on GE as a local supplier. And last week, the IUE-CWA announced what it called a first-of-its-kind agreement with the company to not interfere with labor organizers at the two factories.
IUE-CWA Local 301 is the largest union at GE’s Schenectady campus, though its ranks have diminished greatly over the decades as the company has trimmed its presence in the city where it was born 131 years ago.
“The same GE campus that was established by Thomas Edison and Charles Steinmetz, which helped make GE an international brand, will help power America’s clean energy future and continue the great legacy of this campus for the next generation,” said U.S. Senate Majority Leader Chuck Schumer (D-N.Y.), who has been urging GE for years to bring wind turbine manufacturing operations to Schenectady.
New York state has some of the most ambitious climate-protection goals in the nation, and it hopes to build a green manufacturing sector within its borders as it slashes carbon emissions. It is providing GE Vernova with $2.5 million in tax credits to support the creation and retention of at least 160 jobs.
“We are proud to partner with GE Vernova to realize New York’s vision of [becoming] a leading manufacturing hub for wind technology and to bring us closer to achieving our nation-leading climate goals, securing a better and cleaner future for generations,” Gov. Kathy Hochul (D) said in a news release.
Also on Tuesday, GE Vernova announced the launch of an online marketplace offering more than 100,000 parts and related equipment for both its own and other manufacturers’ onshore wind turbines.
More than 54,000 GE wind turbines are installed worldwide, and the company has claimed the lead in U.S. onshore sales for the past five years.
FERC on Monday approved settlements with two demand response aggregators for allegedly bidding more resources than they could provide to CAISO’s market.
OhmConnect (IN23-6) agreed to pay a fine of $141,094 and disgorge $8,906 to the ISO, while Leapfrog Power (IN23-7) agreed to pay $73,880 and disgorge $46,120. Both companies agreed to heightened compliance monitoring in order to shut down enforcement probes over their DR bidding activities.
Both firms were participating in the California Public Utilities Commission’s Demand Response Auction Mechanism (DRAM) pilot program, in which they contract with load-serving entities to provide a set amount of demand response every month. The program required them to tell the LSE they were working with how much DR they would have available in a month 90 days ahead of time.
Ohm’s allegedly problematic bids happened between January and June 2018, and it made $8,906 more than it should have, while Leapfrog’s came between February and August 2019, and it made $46,120 more than it should have.
The two have different business models, with the California-based Ohm focusing on home energy management via customers’ smart meters. It allows residential customers to earn rewards for their energy reductions, which it sells into the markets.
Ohm signed up to provide 109 MW of DR for the 2018 delivery year, but it was not able to sign up enough customers to provide that much, with shortfalls ranging from 32 to 63%.
Leapfrog connects electric vehicle, battery storage, smart thermostat and other flexible technologies to provide DR and enrolls them in the wholesale markets in aggregated portfolios. Leapfrog was a startup and it first bid into the DRAM program in 2018 for 2019 delivery, but it was never able to sign up enough customers to support its bids. Most of the bids it made from February to August exceeded the registered metered load of customers it had signed up, with shortfalls ranging from 54 to 98%.
CAISO’s tariff requires that market participants make bids from resources that are reasonably expected to be available and capable of performing at the levels specified in their bid and to remain so based on all information that is or should have been known to the market participant when their bids were made.
FERC Office of Enforcement staff determined that both Ohm and Leapfrog made a “substantial majority” of their bids when they could not reasonably expect to fulfill them during the relevant periods. In both cases their bids “exceeded the registered metered load of all” their customers.
Both firms stipulated to some facts laid out in the agreement, but neither admitted nor denied the violations that enforcement staff alleged.
Both firms cooperated with the investigations and FERC found that the deals they signed with its staff were fair and equitable resolutions of the matters concerned and are in the public interest because they reflect the allegations’ seriousness and are in line with the regulator’s penalty guidelines.
CAISO will distribute the $55,000 in disgorgements on a pro-rata basis to its network load.
LANSING, Mich. — A Michigan House task force to investigate winter power outages will hold its first hearing June 9, with further sessions expected through the summer.
Rep. Helena Scott (D), chair of the House Energy, Communications and Technology Committee, said the newly formed Energy Reliability, Resilience and Accountability Task Force was created in part to hear from residents across the state who lost power in February and early March, in some cases for more than a week. While the committee held a hearing some months ago about the outages, many people were unable to attend that session in Lansing, Scott said.
The task force’s “Dependable Energy Listening Tour” will include hearings in both the Upper and Lower Peninsula to hear from as many people as possible who were affected by the outages.
Scott also said the task force will also look at how to upgrade the current transmission system by 2035, improving overall state oversight of its grid infrastructure and ensuring it takes less time to restore power after outages.
At the previous hearing, top executives of DTE Energy (NYSE: DTE) and CMS Energy (NYSE: CMS) outlined problems they encountered in trying to restore electric service. Almost 1 million customers were affected, mostly DTE and CMS customers.
The first hearing held by the bipartisan, nine-member task force will be in Lansing at the Anderson House Office Building. A schedule for other hearings has not yet been published.
A group of 14 environmental, climate change and utility activists issued a statement praising the new task force, saying Michigan has relied on coal and other polluting energy sources for too long. “We must begin creating the ‘grid of the future’ now,” the statement said.
Responding to the task force, CMS spokesperson Katie Carey said the utility has as a “top priority” to “strengthen our system in the face of intensifying storms caused by climate change. In order to do that, we file electric distribution plans with the Michigan Public Service Commission which show where we are replacing poles, wires, upgrading substations, undergrounding power lines, increased tree trimming and new technology to benefit customers by having fewer, shorter and less frequent power outages. We will work with this group on the overall goal to continue our efforts to create meaningful, positive change for the planet and for Michigan.”
DTE has also said it is increasing tree trimming and taking other measures to reduce the likelihood of blackouts and reduce the time to takes to restore power.
Washington’s Department of Ecology on Monday issued a water quality certificate for a pumped storage project along the Columbia River, sparking protests from area tribes and some environmental organizations because the location contains sites sacred to the Yakama Nation.
Ecology issued the certification with conditions to ensure the construction and operation of the proposed Goldendale Energy Storage Project meet state water quality requirements.
“Conditions include following specific best practices, requirements for getting future Ecology permits and monitoring and notification requirements,” the agency said in a statement.
Opponents have 30 days to appeal the Ecology Department’s decision.
Boston-based Rye Development is hoping to build Washington’s first pumped storage project for $2 billion in southern Klickitat County near the John Day Dam and commence operation between 2028 and 2030. The project is designed to generate 1,200 MW of energy. (See Wash. Pumped Hydro Project Faces Permitting, Obstacles.)
The project would include two lined 600-acre water reservoirs that are 60 feet deep and separated by 2,100 feet in elevation. One reservoir would be on the river shore, the other atop a cliff adjacent to the Tuolumne Wind Project. An underground pipe would connect the reservoirs, with a subterranean electricity generating station along the channel. Water would flow from the upper reservoir to the lower one to power the four-turbine generator station and would then be pumped back up to the upper reservoir in a closed-loop system.
The water quality certification is one of many approvals needed before the project can be built.
FERC and the U.S. Army Corps of Engineers are reviewing a hydropower license and a permit to fill federally regulated waters, respectively. Under the Clean Water Act, the federal agencies require a water quality certification from the Ecology Department before making their decisions.
FERC also released a draft federal environmental review April 6 and is accepting public comments through June 6.
The pumped storage project would be on private land that Rye Development leases from NSC Smelter, which owns the former site of the Columbia Gorge Aluminum smelter site one mile upstream from the John Day Dam. The site is within a large strip of land in southern Klickitat County that the county has zoned for renewable energy projects.
Tribal and environmental opponents issued a press release protesting against the state certification.
While the project is not on Yakama reservation land, it is on property used for sacred ceremonies, and it has a historical connection to the tribe. The project area includes a longhouse, an ancient village site and other sacred sites. Since 1855, the tribe has had treaty rights to fish and hunt in the area, as well as the right to protect burial grounds and religious sites across a vast area in south central and southeastern Washington.
The Yakama, the Nez Perce Tribe, the Confederated Tribes of Warm Springs and the Confederated Tribes of the Umatilla Indian Reservation oppose the project. This year, the Affiliated Tribes of Northwest Indians, representing 57 tribal governments, and the National Congress of American Indians joined the opposition.
“A clean energy future must uphold federal trust and treaty obligations that consider the cultural and health impacts of these projects on sacred sites,” Alyssa Macy of the Warm Springs nation, who is also CEO of Washington Conservation Action, said in a press release from several tribes and environmental organizations. “These parts of our identity — the land, the roots and the water — are a part of our collective history, and we must not erase them.”
“Pumped storage is a critical tool in facilitating our transition to clean energy. However, the current siting of this project reinforces the exploitation of our tribal neighbors and should have been rejected,” said Sept Gernez, acting director of the Washington State chapter of the Sierra Club.
VALLEY FORGE, Pa. — PJM last week offered stakeholders a series of suggestions for how the RTO could overhaul its capacity market in the wake of significant resource failures during the December 2022 winter storm.
The suggestions accompanied a presentation of PJM’s initial lessons learned from Winter Storm Elliott, intended to inform stakeholders as they consider capacity market changes through the critical issue fast path (CIFP) process.
The analysis is a precursor to the RTO’s anticipated July report on the storm’s impact, PJM’s Glen Boyle said during a May 17 CIFP meeting.
Elliott was the latest in a series of events showing that winter comes with significant risk, Boyle said, and PJM is recommending that stakeholders evaluate how it can improve its modeling to better account for the drivers of winter risk — namely, high loads and generation failures.
Citing the widespread failure of capacity resources to perform, despite high penalties under the capacity performance (CP) structure, PJM recommended revising capacity market incentives — including financial risks, strengthening accreditation requirements, increasing the frequency of testing and additional visits to generating sites.
Paul Sotkiewicz, president of E-Cubed Policy Associates, questioned the value of site visits, saying generators in other RTOs that conduct them regularly have told him the staff sent to facilities often don’t understand plant operations.
“Just because you send someone out there, doesn’t mean they know what they’re looking at,” he said.
PJM also found that market participants required education — both during the storm and in the penalty settlement process — on performance assessment intervals (PAIs), including what they are, how they function and where they are laid out in the governing documents.
The storm analysis also revealed instances in which the penalties weren’t aligned with dispatch basepoints, which Boyle said in part reflects a generator’s performance obligation not taking in account the generator’s characteristics, such as ramp rates.
Calpine’s David “Scarp” Scarpignato said many of the rules and procedures under discussion following Elliott were put in place deliberately. By not creating a penalty carve-out for generators’ ramp-rates, he said it was hoped that operators might find ways to start their units faster than their stated capabilities. Creating an exemption for ramp-rates would also risk allowing generators to be excused for hours, which would be unfair to resources that have fast-start capabilities.
“These rules are thought out; this isn’t something that accidentally happened, and I don’t want to lose sight of that,” he said.
PJM was a net exporter of energy throughout much of Winter Storm Elliott, which Boyle said led to increased obligations for capacity resources under the current balancing ratio formula. Many of the complaints filed at FERC seeking relief from penalties during Elliott argued that exporting during a PAI constitutes a tariff violation and effectively puts generators on the hook to provide capacity to resources outside PJM that haven’t paid for the service.
“The way I view exports is that a generator who signed up for a capacity commitment is being paid by PJM load-serving members and they have an obligation for that in exchange for that payment … and if they fail to provide that service, a penalty obligation is appropriate,” said ODEC’s Mike Cocco. “Here you have people outside the PJM system that are not paying these generators.”
PJM is also recommending a reevaluation of how resources whose offers cannot currently be translated into a performance obligation to benchmark performance against during a PAI can be fit into the framework. Those resources are not currently eligible for bonus payments or for excusal from penalties. Boyle said this mainly applies to resources with zero-cost offers.
Given that the current process for penalty excusals requires a large amount of manual work and case-by-case review, PJM also recommends that stakeholders consider options for streamlining the process.
A significant portion of the bonus penalties stemming from Elliott are being distributed to energy efficiency and demand response resources, which PJM said warrants an evaluation of whether their performance matches their reliability contribution.
PJM will continue to investigate poor performance of nonretail behind-the-meter generation (BTMG) during the storm and provide further recommendations on how to either make improvements or alter how those resources participate in the capacity market.
Speaking on behalf of the PJM Public Power Coalition, Customized Energy Solutions’ Carl Johnson said nonretail BTMG is governed by an agreement made prior to the creation of the capacity market and that performance during Elliott demonstrates that arrangement may need to be reconsidered.
Sotkiewicz said the recommendations and issues identified lack a focus on PJM operations during emergency conditions. Changes to market structures will have little impact if accurate forecasts aren’t developed and enough resources committed to maintain reliability, he said.
Morris Schreim, senior adviser for the Maryland Public Service Commission, questioned how improving the incentives for generators to perform would function while gas supply remains an issue, to which PJM’s Mike Bryson said a fuel assurance requirement will likely be part of PJM’s CIFP package.
Clearway Energy Presents CIFP Proposal
Clearway Energy presented a series of proposed changes to CP and the capacity market focused on tying the performance expectations for wind and solar resources to how they typically operate. Under the current methodology, in which resources have a flat obligation for all times and conditions, that expectation would usually be inaccurate, said Autumn Lane Energy’s Pete Fuller, representing Clearway. For solar, he said resources are below their obligation throughout the night and above it during most days.
By tying performance baselines to a renewable resource’s individual engineering characteristics, operators will be incentivized to ensure their facilities are operating at the peak of their capacity during emergencies, with all solar panels cleaned and ball bearings greased.
Fuller said Clearway echoes PJM’s desire for more frequent PAIs to make it easier for generators to evaluate and manage their risk. However, they disagree with PJM’s approach of creating a fixed number of ‘tier 2’ performance assessment intervals. Rather than using an “arbitrary number,” Fuller said additional performance hours should be pegged to system conditions.
“There may be a way to look at approaching a reserve deficiency or approaching stress on the system and defining that numerically,” he said.
Clearway’s approach to performance baselines for wind and solar would continue to calculate a resource’s annual reliability contribution through PJM’s existing effective load carrying capability (ELCC) methodology or a similar system, but would determine its output for purposes of performance assessment intervals on meteorological data and the operational characteristics reflected in its accreditation.
Fuller gave three ways of setting performance obligations under the proposal:
a real-time dynamic baseline with five-minute granularity, which has the advantage of high accuracy;
a baseline set with day-ahead forecasting, which would be less computationally intensive, but less accurate with hourly granularity; and
creating a baseline using known characteristics of resources, such as not giving solar resources an obligation at night.
Monitor Adds Detail to Proposal
Independent Market Monitor Joe Bowring discussed the market clearing process in his CIFP proposal, saying the market clearing process would account for the hourly availability of resources and ensure that generators can cover their net annual avoidable cost.
“The proposal addresses the two functions of the capacity market: ensuring that there is enough energy to meet the load in every hour, and ensuring that generators have the opportunity to cover their avoidable costs — the so-called missing money,” he said.
Under the plan, resources would provide their expected hourly available megawatt profile and PJM would provide the expected hourly load plus reserve margin. The market clearing process would result in a single clearing price for each relevant location and identify the resources needed to reliably meet the load.
During the actual delivery year, if a resource’s energy output matched the modified availability factor in its capacity market offer, it would receive the capacity clearing price in for each hour. If a resource did not perform, it would not be paid. Generators that didn’t fully clear the auction would be eligible for make-whole payments, exactly like the status quo rules.
PJM’s Walter Graf said that since the Monitor’s proposal treats every hour the same, if the grid were to be in emergency conditions and shedding load in one hour, an underperforming capacity resource would receive less than its full capacity revenues; however, it would be able to make that up by overperforming when the grid is not stressed.
“The most fundamental concern I have with this model is that of pricing,” Graf said. “I think what you’re attempting to do in the auction is attempting to identify the least-cost [clearing] resources,” but then compensate every megawatt-hour at the marginal cost of the highest clearing resource. He said he was concerned that the mismatch between value and compensation introduces opportunities for strategic bidding, doesn’t support a competitive equilibrium and doesn’t incentivize resources to offer at their costs, but instead submit a low offer to clear fully.
Bowring said he disagreed with each of the assertions and that PJM’s proposal fails to address the identified issues as fully as the Monitor’s proposal. He pointed out that the current design, and the design favored by PJM, pays a single clearing price for the entire year, based on the marginal cost of the highest clearing resource, which is the same thing as paying the same price in every hour. The Monitor’s proposal, unlike the PJM proposal, does not pay the capacity price to resources that are not available in an hour. Bowring said the proposal recognizes that the PJM energy market provides the required hourly and locational incentives to produce when conditions are tight and prices high. Though he doesn’t believe it’s currently necessary, he said it would be straightforward to add differential penalties to the model.
Calpine’s Scarp questioned why the proposal verifies performance for each hour if each hour is treated the same, suggesting the process could be simplified by using resources’ equivalent forced outage rates (EFORd).
“Why do all this accounting and measure all these things when really you’re only interested in one number at the end of the year,” he said.
Bowring responded that EFORd is not as comprehensive a metric of availability as the proposed Modified Availability Factor. An hourly approach is essential, considering the growing role of intermittent resources, which, unlike thermal resources, are not available in every hour, he said.
Bowring said the hourly approach is preferable to ELCC, which is also based on hourly data, and the hourly approach pays resources only when available. Paying for performance is not possible when using only a simple average approach, he said.
