MISO is wrapping up its 2020 Transmission Expansion Plan (MTEP 20) with an eye on next year’s planning cycle that contains more aggressive renewable energy predictions.
MTEP 20 includes 514 projects costing slightly more than $4 billion. The most expensive project remains Ameren’s new Massac substation in Southern Illinois and the conversion of the nearby Joppa station from 230 kV to 345 kV, at an estimated cost of $112.4 million.
“At this time of the year, we’re ending MTEP 20 and starting MTEP 21,” planning engineer Scott Goodwin told stakeholders during a Planning Subcommittee meeting Tuesday.
MISO has closed the request deadline for special targeted study requests to be conducted under MTEP 21.
The Environmental Groups sector has requested the grid operator conduct two studies examining footprint changes if either LG&E and KU Energy or Memphis Light, Gas and Water join MISO within the next five years.
Transmission owners oppose the request. “We didn’t think MTEP is the place to evaluate new members. It’s about evaluating transmission projects,” Entergy’s Yarrow Etheredge said.
Goodwin said MISO will begin scheduling MTEP 21 subregional planning meetings to discuss project needs. The RTO will also soon release MTEP 21 economic models that draw on its new, 20-year futures scenarios, economic planner Nickolas Przybilla added.
The grid operator is relying on a combination of integrated resource plans and utilities’ public carbon-reduction commitments to predict resource siting under the new planning futures.
“It’s both the media and IRPs,” MISO Planning Manager Tony Hunziker said during a Planning Advisory Committee conference call Wednesday. “It’s recognizing that sometimes a press release precedes plans and also recognizing that not all utilities have to file integrated resource plans.”
Hunziker said MISO is drawing on the National Renewable Energy Laboratory’s Annual Technology Baselines to help predict when generation technologies are increasingly adopted.
MISO’s Future I expects solar expansion on par with the footprint’s current amount of wind generation. In Future II, the RTO foresees energy storage and electrification beginning to join solar on center stage. By Future III, electrification and storage take a consequential role in supply and demand, while wind and natural gas generation each taking a 30% share of the energy mix. Future III also assumes 50% renewable energy use.
Some stakeholders said MISO should not simply take utilities’ target announcements at face value and should rely on something more concrete to make future generation assumptions.
“I just don’t think we have evidence that utilities waffle a lot. I don’t think we have a record like that,” Clean Grid Alliance’s Natalie McIntire said. “When utilities make announcements, they tend to be well thought out.”
States, cities and utilities in the MISO footprint are fast piling up carbon-reduction goals.
Michigan is the latest state to announce a carbon-neutrality goal. Gov. Gretchen Whitmer late last month said the state will meet a net-zero emissions goal by 2050, if not sooner. The announcement late last month will likely cause utilities to rethink their IRPs.
Ameren and Entergy have also committed to carbon neutrality by 2050.
Queue Timeline Cutbacks Still in the Works
To reach those targets, MISO must make headway on the 106 GW of mostly renewable generation in its generator interconnection queue’s 705 projects.
The mammoth queue is down from a record 756 projects, totaling 113 GW, in August. MISO said about 20 interconnection customers in its South and West planning regions failed to provide proof of site control and were forced to withdraw projects.
To speed up queue processing, the grid operator plans to whittle down the three-part definitive planning phase and generation interconnection agreement negotiations from more than 500 days to a calendar year. (See Record Number of Entrants Line up for MISO Queue.)
MISO engineer Miles Larson said the RTO plans to cut about 140 total days from queue processing so it can catch up on projects and bring the four planning regions’ studies into the same queue-cycle year. MISO is currently processing queue cycles dating back to 2017.
“We continue to see an overwhelming support for reducing the [generation interconnection process] timeline,” Larson said during an Interconnection Process Working Group conference call Monday.
MISO wants GIA negotiations and execution pared from about 150 day to 100 days. That means some negotiations will simultaneously occur as staff wrap up final network upgrade studies.
Larson said MISO wants to arrive at a “repeatable and sustainable” process to keep the queue humming.
“The closer we can get our process to 365 days, the closer we get to aligning the DPP study process with the MTEP study process,” he said, referencing MISO’s plan to better match MTEP planning with network upgrades necessary for interconnections.
Larson said that for the cutbacks to stick, interconnection customers need to ready their generation projects as much as possible before entering the queue.
“MISO alone cannot reach the reduction goal,” he said. “In order to succeed in this effort, every entity needs to identify internal efficiency opportunities.”
This year’s official actions on supply chain risk management are only the beginning of the collective changes needed to grapple with foreign cyber threats to the utility sector, industry insiders at the Energy Bar Association’s Fall Conference said Tuesday.
Robert Kang, Southern California Edison | Energy Bar Association
“Utilities are now at the cyber front lines of protecting national security,” said Robert Kang, a senior attorney for Southern California Edison, citing the intelligence community’s most recent Worldwide Threat Assessment that accused China, Russia and other countries of “using cyber operations … to disrupt critical infrastructure.”
“That means we, along with the government, have to step up our engaging. … In terms of presentations that I give to the C-suite or to the board of directors, I think that’s actually key,” he added.
Kang said government engagement with utilities has been accelerating in recent years in several key areas. The first is in support of efforts by utilities to reverse engineer grid equipment in search of components made by suppliers suspected of assisting with online espionage — for example, China’s Huawei and ZTE, which have both come under increased scrutiny from regulators and lawmakers. (See FERC, NERC Offer Cyber Supply Chain Guidance.)
Utilities are often prevented from performing such examinations themselves by supplier contracts that prohibit reverse engineering, but Congress provided a potential workaround for the issue in the National Defense Authorization Act of 2020, which authorized DOE to form a task force to examine critical equipment for suspect components with the help of the National Laboratories. Kang said that “a number of utilities … are really looking forward to seeing [the] task force get stood up.”
Communication Within Entities Essential
Kang said the government’s ability to issue binding edicts — not just laws, but also NERC’s reliability standards — can be another powerful form of assistance for utilities, as such requirements can force entities to make needed improvements they might otherwise be reluctant to perform because of cost or convenience issues.
Howard Gugel, NERC | Energy Bar Association
Picking up this thread, Howard Gugel, NERC’s vice president of engineering and standards, admitted that while the organization had moved quickly to implement requirements for cybersecurity risk management, there is still a lot of work to make the topic central to the conversation.
“When we planned the system, we didn’t really think about what the cyber impacts … were, and also the [information technology] folks didn’t really think about [how] the stuff that they installed … could potentially impact the bulk electric system,” Gugel said. “[We’re starting] a conversation between the two groups to say [that] as we’re planning the system, we need to … understand what the cyber impacts could be, and also when we’re planning to do cyber installations, what could be the impact on the bulk electric system.”
Both Gugel and Kang encouraged listeners to expand their knowledge beyond their job descriptions — for example, lawyers to talk with technology specialists and vice versa. These conversations can not only build rapport between different parts of an organization but can also help both sides develop useful insights to help the entity overall.
Recovery Systems also Under Threat
Patricia Hoffman, Department of Energy | Energy Bar Association
From the government’s perspective, Patricia Hoffman, principal deputy assistant secretary in DOE’s Office of Electricity, said the department has seen promising signs that the industry is taking the cyber threat seriously. She warned utilities that maintaining a strong defense against state-backed attackers with considerable resources at their disposal will require thinking several moves ahead.
“They want to gain access and persistence. Then they want to be able to prepare the battle space … to put malware on your system, and then be able to … not only execute [an attack], but prevent your ability to recover,” Hoffman said. “So, we want to keep that in mind as you move forward, and think about [your] opportunities and responsibilities … as an entity in this sector.”
FERC on Thursday proposed a policy statement inviting states to introduce carbon pricing in wholesale electricity markets but said it had no authority to initiate such programs itself (AD20-14).
Chairman Neil Chatterjee, a Republican, called the proposal — coming just two weeks after the commission’s technical conference on carbon pricing — a “landmark action.”
But Democratic Commissioner Richard Glick said that although the proposal is a “positive step forward,” the commission “consistently turns a blind eye” to climate change by refusing to assess whether new natural gas pipeline projects it has approved have a significant impact on greenhouse gas emissions. He noted that he was dissenting on several pipeline certificate orders Thursday, saying the commission’s position ignores a D.C. Circuit Court of Appeals order requiring such assessments.
Ravenswood Generating Station, a 2,480-MW fossil fuel plant in New York City
“I wouldn’t describe this draft policy statement as groundbreaking, but if it is finalized, it does provide the states some confidence that the commission will accommodate state carbon pricing decisions,” Glick said in remarks during the commission’s virtual open meeting. “There is an obvious opportunity for consensus here, but we can’t move forward if the commission continues to treat climate change differently than all other environmental impacts.”
Republican Commissioner James Danly dissented in part on the proposal, calling it “unnecessary and unwise.”
Jurisdiction
The statement would assert that the commission has jurisdiction over organized wholesale electric market rules that incorporate a state-determined carbon price and “also seeks to encourage regional electric market operators to explore and consider the benefits of establishing such rules,” FERC said in a press release.
The commission said the Sept. 30 technical conference highlighted the potential benefits of carbon pricing, including “technology-neutral, transparent price signals … and providing market certainty to support investment.” (See FERC Urged to Embrace Carbon Pricing.)
“As states actively seek to reduce greenhouse gas emissions within their regions, carbon pricing has emerged as an important, market-based tool that has wide support from across sectors,” Chatterjee said in a statement. “The commission is not an environmental regulator, but we may be called upon to review proposals that incorporate a state-determined state carbon price into these regional markets. These rules could improve the efficiency and transparency of the organized wholesale markets by providing a market-based method to reduce GHG emissions.”
In a teleconference with reporters, Chatterjee rejected the notion that the proposal represented an evolution in his thinking on climate change, saying he has been consistent since he joined the commission: that it is a real and existential threat and human-caused, and that “decarbonization should occur through market-driven” solutions.
FERC defined carbon pricing to include both “price-based” methods that directly establish a price on GHG emissions as well as “quantity-based” approaches under a cap-and-trade system.
The commission noted that 11 states — California and the 10 New England and Mid-Atlantic states in the Regional Greenhouse Gas Initiative — use a form of carbon pricing. PJM, NYISO and ISO-NE are also investigating it.
FERC said regional market rules incorporating a state-determined carbon price are within the commission’s jurisdiction over wholesale rates under Federal Power Act Section 205. “Whether the rules proposed in any particular FPA Section 205 filing do, in fact, fall under commission jurisdiction is a determination we will make based on the facts and circumstances in any such proceeding.”
The Analysis Group’s study concluded that New England needs a carbon price of $25 to $35/short ton by 2025, rising to $55 to $70 by 2030, to meet New England states’ carbon emissions goals. | Analysis Group
The statement noted that FERC “has long permitted generating resources to recover through wholesale rates the costs of complying with environmental regulations, including the costs of emissions pricing regimes,” citing its approval of the CAISO Energy Imbalance Market’s incorporation of a carbon charge on EIM imports into California.
The commission also cited the Supreme Court’s EPSA decision, which said the commission has jurisdiction over practices that “directly affect” wholesale rates as long as it doesn’t cover matters the FPA reserves for exclusive state jurisdiction. The court ruled that FERC’s actions under Order 745, which covers demand response compensation, “meet that standard with room to spare.”
“Because the decision about the carbon price would be determined by the state — which could select a price of zero, should it choose — state authority would be unaffected, further removing any doubt that rules that incorporate such a state-determined carbon price would comply,” the commission continued.
“Incorporating a state-determined carbon price into RTO/ISO markets could represent another example of the type of ‘program of cooperative federalism’ that the court noted with approval in EPSA,” FERC said.
Comments Sought
The commission will accept comments on the proposed policy statement until Nov. 16 with reply comments due Dec. 1.
FERC said it seeks comment on what information it should consider when reviewing such a filing, including:
How do market design considerations change based on how the state or states determine the carbon price? How will that price be updated?
How does the proposal ensure price transparency and enhance price formation?
How will the carbon price or prices be reflected in LMPs?
How will the incorporation of the carbon price affect generation dispatch? Will it affect how the market co-optimizes energy and ancillary services?
Does the proposal result in economic or environmental “leakage,” allowing production to shift to more costly generators in other states, without regard to their carbon emissions? How does the proposal address such leakage?
A Marker
Chatterjee said the proposal is a “marker signaling that this commission encourages efforts” to introduce carbon pricing in RTO/ISO markets.
“When it comes to our markets, fuel-neutral carbon pricing stands in stark contrast to other state policy tools, like subsidies, which can amount to hidden costs that degrade market efficiency and skew price signals, ultimately hurting the consumer,” he said. Glick and the chairman have battled over the commission’s orders setting price floors on capacity resources that receive subsidies, including over PJM’s expanded minimum offer price rule (MOPR), which was the subject of a compliance order Thursday. (See related story, FERC Acts on PJM MOPR Filing.)
“If states continue to pursue carbon pricing … they should have confidence that those proposals will be not be a dead letter on our doorstep, confidence that we recognize the benefits that such proposals, if properly designed, could bring to our markets, and confidence that we will bring our pragmatic, market-based lens to this conversation,” Chatterjee continued.
He cautioned that FERC would not take proactive action to set a carbon price, however. “I’ll say it again: The FPA does not give us authority to act as an environmental regulator. We have neither the expertise nor the authority to drive emissions policy in this space. So that is not the objective here today.”
The chairman praised Glick for working with him “to find common ground. It enabled this commission to provide bipartisan leadership and bring clarity to a difficult issue. That’s so crucial here where a broad set of voices have called on us to do just that.”
Danly: ‘Better to Wait’
“It’s better to wait to be in receipt of a plan rather than to issue this kind of a policy statement when we haven’t actually seen the kinds of programs that could be developed or proposed,” Danly said. “It’s certainly premature to opine on jurisdictional questions when we are denied the benefit of actually seeing details of what might be proposed.”
He said he concurred in part “because the substance of the policy statement really boils down to little more than an affirmation that utilities still enjoy the rights to file under Section 205 to propose tariff provisions.”
Danly noted that he also dissented on Order 2222 over similar concerns. “There I questioned the commission’s seizure of authority at the expense of the states and advocated that ‘we should allow the RTOs and ISOs … to develop their own DER programs in the first instance.’ Then the question of the commission’s jurisdiction will be ripe.” (See FERC Opens RTO Markets to DER Aggregation.)
“Without seeing a proposal,” Danly wrote, “the commission predetermines that any such proposal will be within the commission’s jurisdiction and ‘would not in any way diminish state authority.’ That may well turn out to be true, but I would have waited until we had an actual 205 filing before us rather than prejudging the issue based on unstated assumptions about how such programs might work. It is easy to imagine any number of RTO/ISO carbon-pricing proposals that would violate the Federal Power Act by impermissibly invading the authorities reserved to the states. This policy statement is not, as the majority’s order characterizes it ‘another example of the type of “program of cooperative federalism” that the court noted with approval in EPSA.’ There is no program. This is instead a nonbinding, blanket dismissal of potential jurisdictional concerns.”
Chatterjee and Glick rejected that characterization. “We are proposing a framework for applying our jurisdiction, not ‘prejudging’ particular matters or pre-emptively ‘dismiss[ing] … potential jurisdictional concerns.’”
“An overwhelming consensus emerged at the [FERC technical] conference that carbon pricing in markets is a powerful and cost-effective tool to drive down emissions and achieve state policy goals while preserving the benefits of competition. The policy statement reflects this consensus,” said Amy Farrell, AWEA’s senior vice president for government and public affairs.
“We are pleased to see that FERC is continuing to dig into the challenging but important issue of carbon pricing and seeking to meaningfully advance the conversation,” said EPSA CEO Todd Snitchler. “EPSA supports market-based tools including an economy-wide or regional price on carbon that would allow all power providers to compete to reduce emissions at the least cost to consumers while meeting reliability needs.”
“This is a constructive signal but has no immediate applicability since it was not adopted as official policy,” said the American Council on Renewable Energy, which was also among the groups seeking the conference. “Unfortunately, however, FERC acted with more force with regard to a compliance filing from wholesale power market operator PJM Interconnection on FERC’s minimum offer price rule order, which imposes new costs on ratepayers to subsidize fossil generation at the expense of more cost-effective renewable power.”
“While we’ll need to see future orders on compliance to determine the precise severity of this action, renewable energy investment decisions in the Mid-Atlantic region are already impacted by the MOPR, and preferential treatment for fossil fuel generators will only grow in subsequent auctions as costs for renewable power continue to decline,” added ACORE CEO Gregory Wetstone. “These policies take us in the wrong direction from where we need to be to address our climate imperatives and grow the renewable energy economy, and are being challenged in court by ACORE and allied groups.”
Michael Hanson has been in the wind energy workforce for 14 years. He started onshore, managing the operation, maintenance and repair of turbines at a number of sites before moving to the first offshore wind farm in the Western Hemisphere, the 5-MW facility off Block Island, R.I.
It takes a diverse village to run a successful wind farm, according to Hanson.
“You can cast a wide net and get good people from a variety of backgrounds,” said Hanson, operations and maintenance manager for GE Renewable Energy.
Hanson was part of a panel at the American Wind Energy Association 2020 Offshore Windpower Virtual Summit Tuesday that discussed the education and training needed to prepare the American wind energy workforce of the present and future.
Marjaneh Issapour| Farmingdale State College
Marjaneh Issapour, an electrical engineering professor and director of the Renewable Energy and Sustainability Center at Farmingdale State College in New York, said there are many different areas of expertise and credentials needed to “fully deploy the wind energy workforce in the United States.”
Issapour said about 47% of jobs in the field are entry-level, open to high school graduates or those who have completed apprenticeships or associate degrees. Another 41% require a bachelor’s degree, with only 12% requiring a master’s or doctorate.
Among the two job titles in most demand are wind technicians, representing 9% of the total, and wind engineers, representing 12%. “Wind engineer is a multidisciplinary expertise that is a cross … of mechanical, electrical and possibly civil engineering,” she said.
Nuria Soto | Avangrid Renewables
Nuria Soto, senior director of offshore operations for Avangrid Renewables, said 20 years ago there were no offshore wind technicians, and “now it’s an established industry” that is also moving very fast and also needs workers for OSW development, construction and operations.
“One of the main challenges is to ensure that the workforce is ready, and the supply chain is ready,” Soto said. “All these jobs will support the different phases of each project.”
In another panel, Mark Mitchell, director of generation projects for Dominion Energy, said the industry is generating an increasing number of jobs today.
This summer, Mitchell said, Dominion had more than 25 vessels operating with more than 400 people working on the utility’s two-turbine pilot project, now in operation, and early work on its 2.6-GW commercial-scale project.
Workers needed for the U.S. wind energy workforce | National Renewable Energy Laboratory
“We’ve got several hundred [people] working today offshore. It’s not just something in the future. It’s kind of here and now, creating many, many jobs,” Mitchell said.
Bruce Gresham | International Marine Contractors Association
Bruce Gresham of the International Marine Contractors Association said there’s “a mix of different levels of experience” needed to work on OSW facilities. Gresham added that tens of thousands of workers in the offshore oil and gas industry laid off during the COVID-19 pandemic have that kind of baseline experience.
“The younger generation is much more interested in working for the wind industry than the dirty oil industry,” he said.
Soto said Avangrid’s internships are a good opportunity to see how a project is developed and understand different roles.
Hanson said the best training from his perspective is to come from an onshore facility. OSW turbines are “the biggest, most technologically advanced in the world, and having that experience on the smaller machines, I think is second to none.”
Michael Hanson | GE Renewable Energy
That does not diminish other experience, Hanson added.
“There [are] so many different jobs that are going on within a turbine — you can come from being an electrician or technician or a mechanic or someone from the oil and gas industry, or of course from another renewable energy field or utility,” said Hanson, who also mentioned technical college and military training.
“The maintenance and construction of generators at heights in a marine environment is a new industry,” said Andy Goldsmith, a technical adviser for IMCA. “But marine construction and going to sea … is not a new industry. Lighthouses and such … have been constructed for eons, let alone the oil and gas industry, which of course started back in the [19]60s.”
The U.S. energy industry is still wrestling with the economic and social impacts of the COVID-19 pandemic that gripped the world nearly nine months ago, experts said Tuesday.
Managing the magnitude of the pandemic was the first discussion at the Energy Bar Association’s 2020 Fall Conference, held virtually Tuesday because of the pandemic. The discussion covered load impacts and economic consequences for utilities, regulatory responses, consumer-side adjustments and fuel and supply chain price changes.
Panelists included John O’Brien, executive vice president for strategy and public affairs at Washington Gas, and David DesLauriers, vice president at Charles River Associates.
Frank Graves, a principal with The Brattle Group, said the COVID-19 burden has been “uneven” across the energy industry, with different utilities and sectors experiencing contrasting impacts.
Utility companies have weathered most of the economic impacts of COVID-19, Graves said, while some businesses in the energy sector, such as small oil and gas development companies, have experienced bankruptcy. He said utility stocks have trailed the S&P 500, remaining relatively sluggish throughout the summer versus the S&P 500’s overall growth of 10%.
“Even though we’ve improved a lot, we still aren’t very close to where we would like to be,” Graves said.
The U.S. Energy Information Administration forecasts that 2020 electricity consumption will drop by 2.2% relative to 2019 based on a 3.2% increase in residential sales, a 6.2% drop in commercial sales and a 5.6% drop in industrial sales.
Daily LMPs have been below past two-year averages by 10-70% in almost every month since February in every ISO/RTO, Graves said. The drop in LMPs is not solely due to COVID-19 consumption changes, he said, with lower natural gas costs — partially the result of the pandemic — likely playing a bigger role.
But the drop in LMPs will strain the viability for some coal and nuclear plants, Graves said. ERCOT prices were down 64% in September compared to the two-year historical average, while PJM and NYISO have seen declines of 33% and 32%, respectively, in the same period.
Graves highlighted the impact on regional electric loads, which declined by 7% in September compared with the previous four years, despite a return to relatively normal in mid-summer. The September decline was in line with the April (6.5%) and May (7.5%) declines at the height of the pandemic.
PJM and MISO accounted for most of the September decrease, with states in their footprints seeing among the largest surges in COVID-19 cases since mid-summer, Graves said. Warmer than normal temperatures in those regions also contributed to the decline, along with colleges and universities that have not reopened campuses.
“We haven’t been able to unpack this very much, but that’s a surprise that there’s a big drop in September when we’ve had some economic rebound over the last few months,” Graves said.
‘Devastating’
Sandra Mattavous-Frye of the D.C. Office of the People’s Counsel said the pandemic has been “the single most devastating event to impact our country” in more than a century and no sector, population or industry has gone unscathed, including the energy industry.
Mattavous-Frye said the unique nature of the pandemic provides challenges for the energy industry but affordable, safe and reliable utility service, along with strong consumer protections, remains her guiding principle as a consumer advocate.
She said three principles must be in place when dealing with the fallout from COVID-19.
First, there must be equitable cost sharing. While the financial stability of utilities must be ensured, it can’t be “business as usual” where ratepayers are expected to bear the entire cost — utilities must also carry a fair share, she said.
Second, public officials must implement enhanced and sustainable permanent consumer protections for underserved and low- to moderate-income households. Those protections must offer a comprehensive approach to service disconnections, including reasonable payment and billing plans.
Finally, industry participants should identify the short- and long-term negative impacts of the pandemic on all segments of the energy industry. She said forums like Tuesday’s event are a good start.
“I really believe it is an obligation to step outside of the box of our traditional regulatory roles with a shared commitment to overcome the challenges we are facing and explore viable options to address the problem head on,” Mattavous-Frye said.
Global Infrastructure Partners announced Tuesday it will sell generation developer and operator Competitive Power Ventures (CPV) to Tel Aviv-based OPC Energy and Israeli institutional investors. Terms were not announced.
Maryland-based CPV, which develops natural gas and renewable power generation, is one of about 40 portfolio companies owned by GIP, which invests in the energy, transport and water/waste sectors internationally.
The sale would include all of CPV’s 5.3 GW of generation in the U.S. as well as its development pipeline and asset management business, which operates more than 10.6 GW of fossil and renewable generation in nine states for 13 owner groups.
Incorporated in 2010 as the first private electricity company in Israel, OPC Energy generated about 5% of that nation’s electricity in 2018. It will own 70% of CPV and serve as general partner, with the remainder owned by three Israeli institutional investors: Clal Insurance Enterprise Holdings Ltd. Group (12.75% interest), Migdal Insurance and Financial Holdings Ltd. Group (12.75% interest) and Poalim Capital Markets (4.5% interest).
Pending regulatory approval, closing of the sale is expected in early 2021.
| Competitive Power Ventures
OPC said it plans to invest “significant capital” in CPV to fund future growth with a focus on renewable and combined-cycle gas generation. It said CPV’s leadership team will remain intact. “OPC has long recognized the potential in the U.S. electricity market,” OPC CEO Giora Almogi said in a statement.
Founded in 1990, CPV was acquired by GIP five years ago.
“We look forward to the opportunities created by our new partnership with OPC, which positions us well for our next phase of growth during a pivotal time as the U.S. transitions toward greener and lower emitting generating resources,” CPV CEO Gary Lambert said in a statement. ” … I am grateful to Global Infrastructure Partners for its confidence in CPV over the past five years, providing not only access to capital but credible execution and operations expertise that helped guide us through a significant growth period.”
Tom Rumsey, CPV’s senior vice president of external and regulatory affairs, told RTO Insider the company will continue to pursue natural gas generation investments as well as renewables.
CPV Three Rivers Energy Center near Chicago is expected to go into operation in 2023. | Competitive Power Ventures
“We are very focused on reducing carbon emissions from the power sector, but policy must align with technological capability,” he said. “As we’ve seen in California, without dispatchable power to augment and facilitate the growth of renewables, reliability is difficult if not impossible to maintain. Highly efficient and operationally flexible natural gas resources are exceptional partners to today’s renewable technologies, specifically wind and solar. We have very aggressive development programs for both.”
Portfolio
CPV’s portfolio includes an 805-MW combined cycle plant in Connecticut and three combined cycle plants totaling 2,500 MW in PJM, with a fourth, the CPV Three Rivers Energy Center, a 1,250-MW combined cycle plant in Grundy County, Illinois, southwest of Chicago, under development.
CPV, GE Energy Financial Services, Osaka Gas USA, Axium Infrastructure and Harrison Street announced the financial closing on Three Rivers in August. The $1.3 billion plant is expected to commence operations in 2023.
CPV is also developing a 100-MW solar project in Pennsylvania and a 50-MW solar farm in Massachusetts.
Most of CPV’s generating capacity is in PJM. | Competitive Power Ventures
CPV attracted some undesirable attention in 2016 over its development of the Valley Energy Center, a 680-MW combined cycle plant in Orange County, N.Y., when Peter Galbraith Kelly Jr., then the company’s head of external affairs and government relations, was indicted in a federal bribery case involving two former aides of Gov. Andrew Cuomo. (See Competitive Power Ventures Lobbyist, Former Cuomo Aides Named in Bribery Indictment.)
Kelly was sentenced in October 2018 to 14 months in federal prison after pleading guilty to creating a $90,000-a-year “low-show” job at CPV for the wife of Joseph Percoco, then Cuomo’s executive deputy secretary. Percoco received a six-year sentence.
Kelly pleaded guilty to defrauding CPV by falsely claiming that Percoco had obtained state ethics approval for his wife to work at CPV. She was paid $285,000 over the course of three years through a consultant in an effort to hide the payments, according to trial testimony. Kelly also made sure that Percoco’s wife’s photograph and full name were not included in promotional materials for CPV.
A 2019 outage event in the United Kingdom highlights the need for both comprehensive underfrequency load shedding (UFLS) protection and an understanding of the impact of a “rapidly changing portfolio” of generation resources on reliability of the electric grid, according to a “lessons learned” notice from NERC.
The incident began Aug. 9, 2019, with a lightning strike on a 400-kV transmission line north of London that caused a single-phase-to-ground fault. The fault was detected and isolated, and the line was reclosed within 20 seconds. During that time, a steam turbine at the combined cycle plant in nearby Little Barford tripped offline, removing 244 MW of generation from the grid. At the same time, the Hornsea offshore wind farm, operated by Danish energy company Ørsted A/S, unexpectedly reduced output from 799 MW to 62 MW.
Parameters measured at Hornsea Onshore Station — MW and MVAR | NERC
After grid control systems reduced generator output — including 150 MW of distributed energy resources (DER) as part of the rate of change of frequency (ROCOF) scheme, an additional 350 MW of DERs tripped offline, resulting in a cumulative loss of nearly 1,500 MW of generation within one second of the fault. Within 58 seconds, frequency had declined from the European standard of 50 Hz to 49.1 Hz.
After another 33 seconds, as frequency was recovering to 49.2 Hz, a combustion turbine at the Little Barford plant — generating 210 MW — tripped offline, causing another frequency decline. As grid frequency passed below 49 Hz, more DERs tripped, and then operators at Little Barford took a second 187-MW combustion turbine offline. By this point, the cumulative generation loss stood at 1,878 MW and frequency had declined to 48.8 Hz, triggering UFLS schemes that disconnected 931 MW of load. This allowed the frequency to stabilize and begin to recover.
Frequency throughout the event | NERC
Poor Understanding of Weak Conditions
Post-event analysis found a number of issues with the performance of both Ørsted and local grid operator RWE. One of the most important was “limitations in [RWE’s] knowledge” of the Hornsea plant’s control system and “the interaction between its onshore and offshore arrangements,” which caused the loss of 727 MW of generation.
Simplified transmission map for southeast England | NERC
At the time of the transmission line fault, the wind farm was operating in a “weak” system condition due to a number of transmission facility outages already in progress. In addition, one of the undersea cables between the wind farm and land was out of service. As a result, when the voltage control algorithm called for increased output due to the line fault, an oscillation began that led to the overcurrent protection system intervening to reduce output.
The second major contributor to the outage was the Little Barford combined cycle plant, which accounted for more than 640 MW of lost generation capacity. Three issues led to the plant’s shutdown. First, the steam turbine went offline during the initial fault due to a speed sensor input error. The combustion turbine subsequently tripped off after a problem with the steam bypass system led to a buildup of steam pressure, which led operators to take the second combustion turbine offline about 27 seconds later. The cause of the initial speed sensor input error has yet to be determined, but the steam bypass system has since been repaired.
The last significant loss of generation — about 500 MW — came from the shutdown of multiple DERs. Although the initial 150-MW loss was part of normal phase shift protection procedure, the additional 350 MW was unexpected. Investigators determined that some of these DERs tripped offline due to incorrect ROCOF settings, while others were found to have had their UFLS triggered at 48.9 Hz instead of the correct setting of 47 Hz.
Study Needed on Behavior of Renewables, DERs
Corrective actions recommended by RWE in the aftermath of the event included reviewing its operational criteria to “determine whether it would be appropriate to provide for higher levels of resilience in the electric system,” along with reviewing the time scale for anti-islanding protection to “reduce the risk of inadvertent tripping and disconnection of embedded generation.” The utility also recommended an industry-wide review, involving regulators, utilities and other stakeholders to establish communication protocols for future events.
NERC’s analysis focused on the implications of the widespread adoption of renewable energy and DERs on grid reliability, in particular their “increasingly complex controls” that make it difficult to “predict resource responses to network faults.” The organization noted several potential flaws in RWE and Ørsted’s procedures:
Overreliance on self-certification of the models for generating resources, including DERs;
Insufficient understanding and coordination of the interactions between onshore and offshore wind generation control systems, particularly the performance of wind farms in weak system conditions;
Inadequate coordination between transmission planners, generation and transmission owners, reliability coordinators and equipment manufacturers to accurately model their connected resources;
Outdated tools, techniques and simulation approaches to planning and operations, particularly related to weak grid conditions and inverter-based resources; and
Inadequate understanding of the impact of tripping multiple DERs on grid reliability.
To illustrate one approach to modeling DERs, NERC cited PJM’s use of publicly available data, from sources such as the Energy Information Agency and its own Generator Attribute Tracking System, combined with data requested from transmission owners. The RTO uses this information to generate behind-the-meter solar forecasts that are factored into its load forecast and to notify TOs of generation resources that may be available to help with a transmission emergency.
In addition, Thomas Bialek, the chief engineer for San Diego Gas & Electric, warned in January that the behavior of residential rooftop solar panel users is often very different than that expected by system planners. This creates “hidden loads” that can’t be accounted for in planning, he said. (See Rooftop PV’s ‘Hidden Loads’ Challenge Grid Planners.)
The NEPOOL Markets Committee last week debated 13 amendments to proposed updates to parameters for Forward Capacity Auction 16 (2025/26).
Many of the amendments, which were discussed during the last half of the committee’s Oct. 6-8 virtual meeting, challenged revenue figures proposed by Concentric Energy Advisors (CEA) and Mott MacDonald, two consulting firms hired by ISO-NE to update the FCM parameters.
Deborah Cooke, the RTO’s principal analyst for market development, presented responses to stakeholder questions about updates to the net cost of new entry (CONE) and offer review trigger prices (ORTPs).
Abby Krich and Alex Worsley of Boreas Renewables presented four amendments on behalf of RENEW Northeast, including capital costs and the investment tax credit for the ORTP calculation for offshore wind. A capacity offer below the ORTP triggers a unit-specific review by the Internal Market Monitor to verify the resource’s cost.
RENEW said the RTO’s proposal to use $5,876/kW (2019$) for the overnight capital cost of OSW and assumption of a 0% tax credit results in an ORTP of $52.46-$52.67/kW-month, which RENEW believes is double the actual cost. [Editor’s note: An earlier version of this article did not include ISO-NE’s updated figures.] RENEW has proposed using a lower overnight capital cost of $3,000/kW (2019$) and a higher tax credit of 18%.
Krich said $3,000/kW is a reasonable, middle-of-the-range estimate of expected costs for OSW projects in New England. A capital cost of up to $3,200/kW would still result in an ORTP of $0.
CEA said the RENEW analysis is “inappropriate,” and its estimated ranges should be revised upward. CEA challenged RENEW’s use of data from European and Chinese projects.
Krich told RTO Insider after the meeting that ISO-NE’s cost was accurate “8-10 years ago,” but they are no longer appropriate.
‘More Reasonable’ EAS Revenues
Ben Griffiths, an energy analyst for the Massachusetts Attorney General’s Office, offered a summary memo and presentation that outlined “a straightforward optimization model to more reasonably estimate” energy and ancillary services (EAS) revenue available to a storage device. Griffiths said the AG’s model produces “an operational schedule for storage that maximizes revenues” from participation in three of the RTO’s markets — energy, 10-minute spinning reserves and regulation — while respecting the storage device’s technical limitations.
The Block Island Wind Farm, off Rhode Island | Block Island Ferry
Griffiths added that the AG disagrees about the “reasonableness of the CEA EAS revenue estimates for battery storage resources.”
A reasonable operator using a battery for energy, reserves and regulation should be able to earn $54.87/kW-year, assuming the Forward Reserve Market (FRM) sunsets, and $59.11/kW-year, assuming the FRM is maintained, Griffiths wrote. CEA’s contrasting estimates average EAS revenue from these three markets at $45.71/kW-year with an FRM sunset and $55.26/kW-year assuming it is maintained.” (See “Support for Forward Reserve Market Sunset,” NEPOOL Markets Committee Briefs: Oct. 6-8, 2020.)
Griffiths said these revenue estimates are “conservative” and the AG’s office “fully expects that more advanced dispatch schemes could yield higher revenues.”
NEPGA Proposes Amendments on Amortization Period, Owner’s Cost
The New England Power Generators Association (NEPGA) proposed changing the amortization period for the net CONE reference unit (a GE 7HA.02 gas-fired combustion turbine) to 15 years from 20 years. NEPGA’s Bruce Anderson said the 20-year amortization period fails to reflect the risks faced by developers, which creates “a finite period concluding in economic obsolescence.” There is “no evidence that the reference unit would be able to sustain its annual cash flows in real dollar terms for 20 years,” he added.
Anderson said NYISO recently reduced its reference unit’s economic life to 17 years to recognize the potential impact of New York state law and policy. In New England, most states have renewable portfolio standards requirements that involve the procurement of energy from non-carbon-emitting resources.
Additionally, NEPGA put forth an amendment that would take a “bottom’s up approach” to the owner’s cost. NEPGA proposes $12.45 million in owner’s cost — almost five times Mott McDonald’s $2.5 million estimate, which Anderson said is “woefully inadequate” to cover the known owner’s costs, let alone any contingencies.
NEPGA said its figure takes into account initial screening studies and work sufficient to qualify for the FCA and obtain a capacity supply obligation (CSO), plus activities necessary to install the equipment, interconnect it and ensure successful commercial operation. NEPGA said it ignored costs associated with electrical interconnection, network upgrades, gas interconnection, gas pipeline upgrades, initial fuel inventory and financing costs, while Mott McDonald said its estimate captured these activities and contingencies.
At NEPGA’s request, CEA and Mott McDonald updated their dispatch to include seasonal intraday fuel price premiums ranging from 4% in summer to 20% in winter.
NEPGA had asked for time on the agenda to amend the net CONE proposal to include an intraday premium in the event CEA and Mott McDonald chose not to account for it in their updated modeling. NEPGA said it will evaluate the consultants’ proposed intraday premium accounting and could bring forward an amendment at the November committee meeting.
NESCOE Amendments Look at Reference Unit, PfP
While NEPGA sought to shorten the reference unit’s assumed life, NESCOE said it should be increased. NESCOE’s two amendments would boost the useful economic life of the reference unit to 25 years and escalate pay-for-performance (PfP) revenues to account for inflation.
NESCOE proposed that the net CONE resource should be increased to reflect the expected economic life of the reference unit and that PfP should be increased for inflation, reflecting the recalculation of the performance payment rate (PPR) every three years. There are no corresponding Tariff language revisions since these amendments are changes to input assumptions in the analysis.
Calculating net CONE using a 25-year life for the resource reflects a better balance between the physical life of these facilities and a reasonable expectation of their economic life, NESCOE said. The estimated reduction in net CONE is $0.63/kW-mo. Adjusting PPR revenues for inflation is more consistent with the treatment of other revenues with an estimated reduction in net CONE of $0.12/kW-mo., it added.
PJM stakeholders last week unanimously endorsed an installed reserve margin (IRM) of 14.4%, down from 14.8% required in 2019, along with new winter weekly reserve targets.
During the Oct. 6 Planning Committee meeting, PJM’s Patricio Rocha Garrido reviewed the 2020 Reserve Requirement Study (RRS) results, which determined the IRM and forecast pool requirement (FPR) for 2021/22 through 2023/24 and establishes the initial IRM and FPR for 2024/25. The results are based on the 2020 capacity model, load model and capacity benefit of ties (CBOT).
The 2020 capacity model is putting downward pressure on the IRM, Garrido said, with the average effective equivalent demand forced outage rate (EEFORd) of 5.78%, compared to 6.03% in the 2019 RRS. Garrido said the lower average EEFORd was caused by the increased representation of combined cycle units and gas turbines.
The CBOT — the help PJM can expect from imports during peak loads — is estimated to increase pressure on the IRM. Garrido said imports from neighboring RTOs have decreased from 1.6% in 2019 to 1.5% in 2020.
“We’re getting a little less help from our neighbors,” Garrido said.
The FPR is essentially the same as 2019, Garrido said, coming in at 1.0865 (8.65%) instead of 1.086 the previous year.
| PJM
Garrido said the study results will also be used in the 2022/23, 2023/24 and 2024/25 Base Residual Auctions (BRA). He said delays in the 2019 BRA for 2022/23 necessitated the use of data from the 2020 study.
The PJM and world load models used are based on the 2002-2014 period that were approved at the August PC meeting. (See “Load Model Selection,” PJM PC/TEAC Briefs: July 7, 2020.) Analysis from the 2020 PJM Load Forecast Report released in January was also used.
Erik Heinle of the D.C. Office of the People’s Counsel asked if the IRM and FPR would be updated after the first BRA was conducted to make sure the modeling is kept accurate.
Garrido said the driver of FPR is load uncertainty, so the results of the BRA wouldn’t matter for the FPR and does not necessitate a recalculation. Garrido said the recalculation is triggered by a new load forecast, which will be released in January.
Garrido also won a same-day endorsement after conducting a first read of the 2020/21 winter weekly reserve targets, which are slightly changed from last winter.
The targets for December, January and February are 23%, 27% and 23%, respectively, compared to 22%, 28% and 24% last year.
Part of the reserve requirement study, the targets help staff coordinate planned generator maintenance scheduling and cover against uncertainties by ensuring that the loss-of-load expectation (LOLE) for winter is “practically zero,” according to the study. For the entire year, PJM sets the LOLE at one occurrence in 10 years.
Interconnection Queue Initiative
Ken Seiler, vice president of planning, discussed PJM’s plan for a series of workshops to explore ways to improve the efficiency and effectiveness of its interconnection queue process.
Seiler said more than 660,000 MW of generation requests has been studied since the inception of the interconnection process in 1999. More than 70,000 MW has been energized in that time.
“The process has served us well, but the process continues to change,” Seiler said. “We believe it’s time to take a look at some changes within the queue.”
Seiler said the interconnection process has seen many improvements over the years, including automation of tools and additional staffing. PJM currently has 122,000 MW in the interconnection queue with 88% of the megawatts made up of renewable generation sources.
The most recent queue that closed at the end of September has more than 560 projects, Seiler said, with more than 40,000 MW of energy requesting to be interconnected. Of the 560 projects, he said, 500 are either solar or storage.
Based on feedback from stakeholders and the increasing volume and size of the interconnection requests, Seiler said PJM decided it was time to take a “fresh look” at the interconnection process. Four workshops are proposed, including a review of the interconnection process, stakeholder presentations, PJM’s response to the stakeholder presentations and paths forward.
Adrien Ford of Old Dominion Electric Cooperative asked if PJM is looking for feedback on how stakeholders should proceed at looking at the interconnection process or on things that need to be changed in the process.
Seiler said PJM is looking for both things that need to be changed and a process forward to make the changes. He said the RTO has already identified things that need to be changed, but there are also hidden problems that can be identified by stakeholders.
“We want to hear what everyone has to say and what objectives are there and what the end goal is,” Seiler said. “We want to hear everything before locking down a plan to move forward.”
Sharon Segner, vice president of LS Power, said she appreciated the idea of having the workshops but wondered why the RTO hadn’t drafted a problem statement and issue charge to start an official stakeholder process. Segner said it costs time and resources for members to address issues, but with a formal stakeholder process there’s an opportunity to change rules instead of simply having discussions.
Seiler said there hasn’t been a defined problem that would necessitate a solution, so PJM wanted to identify problems through a workshop first before initiating the stakeholder process.
Dave Anders of PJM said a similar workshop method was conducted when stakeholders began looking at the energy price formation issue in 2017. (See PJM Stakeholders Explore Price Formation, Seek Transparency.) Anders said the workshops are designed to expose areas of interest for members to address in the stakeholder process.
ELCC Data Submission
Andrew Levitt of PJM’s market design and economics department provided an overview of the effective load-carrying capability (ELCC) data submission requirements and the applicable deadlines for intermittent and limited duration resources.
ELCC, which is already used by MISO, NYISO and CAISO, evaluates reliability in each hour of a simulated year and compares a resource mix with limited resources against one with unlimited resources.
Members endorsed a joint stakeholder proposal at the September Markets and Reliability and Members committee meetings to use the ELCC method to calculate the capacity value of limited-duration, intermittent and combination (limited-duration plus intermittent) resources. The proposal was endorsed over the objections of the Independent Market Monitor and other stakeholders who said the proposal was flawed and could have profound and unforeseen effects on the capacity market. (See ELCC Method Endorsed by PJM Stakeholders.)
PJM is attempting to make a FERC filing by Oct. 30 to satisfy a paper hearing procedure started last year to investigate whether the RTO’s 10-hour minimum run-time requirement for capacity storage resources is unjust and unreasonable. (See FERC Partially OKs PJM, SPP Order 841 Filings.)
Levitt said PJM needs data submittals from certain resource types by Nov. 1 to release ELCC results by December, the soonest FERC is likely to approve the October filing. Levitt said ELCC could be in place for the 2022/23 BRA.
Under the new rules:
“Immature” and planned solar and onshore wind projects that intend to deliver capacity in 2022/23 must provide estimates of hourly historical production back to June 1, 2012, based on site conditions and historical weather. PJM defines an “immature” resource as solar and onshore wind projects that came into service after June 1, 2012.
Immature and planned offshore wind, landfill gas and hydro without storage that intend to deliver capacity in 2022/23 must provide estimates of hourly historical production back to June 1, 2012.
All energy storage resources, hybrids and hydropower with non-pumped storage must provide relevant physical parameters, including MWh of storage.
Manual 14C Update
Mark Sims, PJM’s manager of infrastructure coordination, provided a first read of changes to Manual 14C: Generation and Transmission Interconnection Facility Construction.
Sims said minor changes are being proposed to Manual 14C as part of the biennial cover-to-cover review. Some of the changes include an update of the with the latest Tariff provisions clarifying the filing process for title transfers and associated title documentation in Section 5.
New sections on cost tracking for baseline projects and another for supplemental cost tracking are also being proposed, Sims said.
PJM will seek approval of the changes at the Nov. 4 PC meeting.
Transmission Expansion Advisory Committee
IEC Project Status
Questions over the status of the controversial Independence Energy Connection (IEC) transmission project were raised during a market efficiency presentation at the Oct. 6 TEAC meeting.
Nick Dumitriu, senior lead engineer for PJM, provided an update on the 2020/21 long-term market efficiency window. Dumitriu said the 2020 Market Efficiency Analysis Assumptions whitepaper was shared with the PJM Board of Managers for consideration at their Sept. 15 meeting.
Dumitriu said a preliminary market efficiency base case was posted Sept. 4, and a retooled base case is expected to be posted by the end of October. The final base case and congestion drivers will be posted in December before the start of the 2020/21 long-term window.
LS Power’s Sharon Segner asked if Transource Energy’s Independence Energy Connection running between Maryland and Pennsylvania will be examined by PJM during the reevaluation analysis scheduled to be completed between October and December as part of the Regional Transmission Expansion Plan (RTEP).
Transource’s proposed alternative plan for the eastern segment of its Independence Energy Connection project | ea
PJM selected the $383 million IEC — its largest market efficiency project to date — during the 2013/14 long-term planning window to address congestion in the AP South interface. The RTO has since reviewed its benefits to the grid several times, determining in each round that the project remains the most effective way to reduce load costs. (See Updated: Transource Files Reconfigured Tx Project.)
Tim Horger of PJM said the RTO has continued to look at the status of the project and is “taking seriously” the project review.
Horger said PJM is deferring a review of the project pending a ruling from the Pennsylvania Public Utility Commission. Transource is seeking the PUC’s approval of land acquisition, siting and construction for a 230-kV line in Franklin and York counties. The record closed with the filing of reply briefs in late September (Docket # A-2017-2640200).
Horger said an update on the project will be provided at the November TEAC meeting.
Segner said PJM has an Operating Agreement requirement to continue reevaluating projects until all required permits have been received.
Horger said the project is in a unique situation where a CPCN has been issued by one of the states involved in the permitting process. He said there are “a lot of moving parts” involved in the project, including reliability impacts.
“LS Power would maintain the position that you have an obligation to follow your Operating Agreement under all circumstances,” Segner said.
A big part of $612 million intended to provide battery backup to homes in high fire-threat areas has been gobbled up by customers who use electricity to pump well water instead of helping the low-income and medically vulnerable residents it was meant for, the California Public Utilities Commission said Thursday.
The CPUC approved $830 million for its Self-Generation Incentive Program (SGIP) in January, with $612 million dedicated to “equity” and “equity resiliency” subsidies to aid residents who face repeated public safety power shutoffs (PSPS) by utilities to prevent wildfires. Thousands of the program’s targeted customers rely on electrically powered medical equipment to keep them alive. (See California PUC Devoting $1.2B to Self-generation.)
In its decision, the CPUC authorized investor-owned utilities to collect $166 million annually from ratepayers from 2020 to 2024. However, the commission did not include income criteria for the well-pump grants, which are part of the program, nor did it prevent customers from applying for funds for their vacation homes.
“We were seeing some second-home residents” receive the hefty grants, which pay the full cost of battery storage and solar cells to charge the units, said Commissioner Clifford Rechtschaffen.
The program’s “very clear focus was on helping the most vulnerable customers and communities in high fire-threat areas and ones that had been affected by multiple PSPS events,” Rechtschaffen said. “In particular, we targeted medical baseline customers, low-income customers and critical care facilities in disadvantaged communities.”
“The program provides very, very generous subsidies,” he said.
Portable solar and batteries are meant to help medically vulnerable customers during power shutoffs under the state’s SGIP program. | Edison International
More than eight months after the decision took effect, with one of California’s worst fire seasons in full force, the state’s three large investor-owned utilities haven’t started reaching out to medically vulnerable customers, Rechtschaffen said.
Instead, developers of storage systems have targeted households with wells, regardless of income, and scooped up much of the funding that was supposed to last through 2024. Commissioner Martha Guzman Aceves said an informal analysis by her staff showed that only a small percentage of the storage contractors were licensed by the state.
Pacific Gas and Electric has already committed its $270 million share of the multi-year program and has hundreds of customers on a waiting list, Rechtschaffen said. Southern California Edison and San Diego Gas & Electric have doled out 50% and 60% of their shares, respectively, he said.
Half the applications have been for well-pump programs, while 30% have been for medically vulnerable customers, he said.
In his proposed decision, Rechtschaffen wrote that “if current trends continue, incentive awards to electric-pump … customers threaten to severely limit the … funds available to the many other types of eligible residential and non-residential customers.”
He proposed adopting income eligibility criteria for grants that haven’t already been funded, requiring households to show they fall below 80% of an area’s median income and that a well provides water for their primary residence.
“Requiring electric-pump well customers to meet the same income eligibility restrictions required of most other …. residential customers levels the playing field and helps ensure that other types of customers with critical resiliency needs have the opportunity to use equity resiliency budget funds,” he wrote.
The decision would apply the new criteria to grants that were submitted but not fully funded as of Aug. 17, when Rechtschaffen issued a letter advising utilities of the commission’s concerns.
Several commissioners expressed unease about applying new rules retroactively to those who have already filed for funding.
“We evidently made a serious omission” in not restricting the funds based on income, said Commissioner Genevieve Shiroma. But “to now go back and say, ‘Oops,’” and change the rules for pending applications, “I’m very uncomfortable with that,” she said.
CPUC President Marybel Batjer said she shared her colleagues’ worries about retroactivity but believes the program must be fixed.
“I’m very concerned about the equity program and it being oversubscribed so quickly when this was [planned] to be a three-year rollout,” Batjer said. “On balance, I think we have to address it. And I agree, Commissioner Rechtschaffen, with your assessment, but I do feel we need more consideration on this item.”
The commissioners voted unanimously to put off a decision until their next meeting on Oct. 22 so they could gather more information and weigh their options.
