SPP said Tuesday that it has hired Arkansas Public Service Commissioner Kimberly O’Guinn as its director of state regulatory policy. Beginning next year, she will be responsible for the grid operator’s state regulatory policy efforts and support its work on related RTO policy matters.
An environmental engineer with more than two decades of utility regulatory experience, O’Guinn was nominated to the PSC in 2016. She has presided over SPP’s Regional State Committee and is currently a member of the Organization of MISO States.
“I am very excited to be a part of the SPP team,” O’Guinn said in a press release. “My career has been dedicated to regulatory issues, which provided me an opportunity to work with SPP and its stakeholders during my tenure at the PSC.”
O’Guinn has also served in leadership roles with the Entergy Regional State Committee, the National Association of Regulatory Utility Commissioners, the Electric Power Research Institute’s Advisory Council, the Women’s Foundation of Arkansas, the American Association of Blacks in Energy, and Arkansas Women in Power. She holds a bachelor’s of in environmental engineering from the University of Oklahoma.
Paul Suskie, SPP’s general counsel and executive vice president of regulatory policy, said he is “thrilled” to welcome O’Guinn.
“As a former president of the [RSC], Kim is very familiar with SPP, and her experience as a nationally respected commissioner is a great asset to the organization,” he said.
O’Guinn previously served as the Arkansas Department of Environmental Quality’s director of communications and as permit engineer at the department’s Office of Air.
ALBANY, N.Y. — New York’s solar industry last week celebrated with state officials a mixture of favorable policies and new funding that are set to boost the industry in 2023 and beyond.
The New York Solar Energy Industries Association’s 2022 Solar Summit drew more than 500 people to the state capital, where speakers praised the state for a nation-leading energy transition plan but also bemoaned that it is one of the slowest and most expensive places to push forward generation projects.
New York surpassed 4 GW of installed solar capacity this summer and says it is on track for 6 GW by 2025 and 10 GW — or even more — by 2030.
Ben Healey of PosiGen Solar captured the mood of the gathering, saying “The tailwinds far outweigh the headwinds.”
Confluence Of Factors
Opening the summit Tuesday, NYSEIA Board President David Schieren said his group is pursuing a calling as well as business.
“Yes, it’s a profession; we’re making a living and maybe a little profit. But also we believe solar is one of the most important things we can do for society and our future,” he said. “We just have to stop burning fossil fuels.”
Doreen Harris, CEO of the New York Energy Research and Development Authority, said the state is “the No. 1 community solar market in the nation and the second-largest distributed PV market as well.”
“We have helped create more than 13,000 jobs in the solar industry,” she said. “We reduced the cost of solar by 70%. We in New York have provided over $1.4 billion in incentives, leveraging almost $7 billion in private investment by each of you, and have ensured at least 1,600 megawatts of solar are benefiting low- and moderate-income communities and households.”
Basil Seggos, commissioner of the state Department of Environmental Conservation, noted the confluence of factors in the renewable energy space on the brink of 2023 in New York: State leadership committed to change; federal funding to help make it happen; and popular support demonstrated by landslide voter approval of an environmental bond act last month.
While acknowledging challenges such as supply chain and labor shortages, he said: “I’m extraordinarily optimistic — I’m optimistic every day.”
Harris and Seggos co-chair the state’s Climate Action Council, which on Monday released the Scoping Plan of the landmark Climate Leadership and Community Protection Act, which requires the state to cut its greenhouse gas emissions by 40% from 1990 levels by 2030 and to achieve 100% emission-free electricity by 2040. (See related story,New York Climate Scoping Plan OK’d.)
“A plan is just a plan,” Seggos said. “Then it really shifts to us to begin implementing it; 2023 is going to be an extraordinary year.”
Others said they expect a domestic solar manufacturing sector to arise with the support offered by the Inflation Reduction Act and other recent federal legislation.
“The U.S. has really lacked a cohesive industrial policy for a long time, and what the IRA does is it starts building that foundation,” said Lindsay Cherry of Qcells. “The policy certainty that we have now is just unprecedented. I’m beyond excited for what’s to come.”
Dan Fadden of Greentech Renewables said setting up a U.S. manufacturing operation is a “holistic” challenge but “we’re going to make the numbers work. This has a lot of momentum. I think it’s a highly likely outcome that a lot of our supply chain will be domesticated probably over the next 10 years.”
Ahmar Zaman of New Energy Equity said: “Finally we have a 10-year ramp from the federal government’s perspective in terms of incentives.”
Limitations
Others spoke of the challenges facing solar, among them interconnection delays, rising interest rates and New York’s home rule. (See related story, Solar Industry Challenged by N.Y. Home Rule.)
Tom Vaccaro, National Grid’s director of transmission for renewables, said utilities are using essentially the same planning process as they have for a century and need to adapt rapidly to distributed and intermittent power sources. “We, as planners and utilities, need to do more work with all of you,” he said.
Dave Gahl of the Solar and Storage Industries Institute said transmission delays exist everywhere, with interconnection wait times nationwide doubling in the last decade and a long backlog of solar, wind and storage projects awaiting access to the grid. “Interconnection is having a national moment,” he said.
Zaman noted that the solar industry’s decade of strong growth came amid historically low interest rates. Rising interest rates were his biggest worry at the start of 2022, but the IRA helped assuage that.
The View from the Field
Downstairs from the policy discussions, some of the people who work in the solar power industry sat at trade show tables, promoting their goods and services. Several told NetZero Insider that business is strong and they expect it to get better, despite labor and supply chain constraints.
Project managers Olya Prevo-White and Chris Koenig of C.T. Male Associates said the design firm is doing a steady solar consulting business, handling permitting, site planning and other work for developers.
The firm began to actively seek solar work around 2010.
“There’s certainly a change, even between last year,” Preto-White said. “Maybe not in the amount of work we’ve done but in the confidence in the industry. Everybody seems to be excited for the growth.”
They have been quite busy for the last few years, Koenig said. They can take on additional work but some of the individual teams may be backlogged at any given time.
Jim Brown was promoting a new home energy storage product that LG Electronics Energy Storage Systems debuted in the U.S. market in September: the Home 8 ESS, a modular two-box system that contains a lithium-ion battery, inverter and power management system and can be monitored via smartphone app.
It’s a business-to-business sales model, Brown said, and solar installers can pitch it to their customers in a variety of ways: promoting green energy by storing power from home solar panels; not drawing from the grid when rates are high; and having a backup power source during a blackout.
With only 14.4 kWh of usable capacity, the Home 8 will not replace the grid. But it will keep a home running for several hours or even a couple of days, depending on how much current the homeowner draws, Brown said.
Brown likens it to an insurance policy.
“Residential energy storage is energy insurance,” he said. “There’s always a green element to it [but] it’s not necessarily part of the pitch.”
With LG having a significant presence in the electric vehicle market and with its appliances already present in many American homes, the company has the name recognition to capitalize on the growth in New York’s solar market, Brown said.
Devyn Smith of Schuler-Haas Electric Corp. said the Rochester-based firm runs into supply chain shortages at times.
“Material is brutal,” he said. “It’s gotten better as we moved farther away from COVID, but it’s still a major issue, especially the medium-voltage parts.”
Some key solar components are slow to arrive as well, but that is an issue for the energy performance contractor to deal with, not the electrical contractor.
Labor also is tight, Smith said, but the company works within its limits. “There’s a million projects going on in the state, so if we could find more guys we could do more work. We just book the work for the guys that we have and don’t overextend ourselves. For the industry as a whole, yes, it’s a problem. For us, specifically, it’s not.”
Convalt Energy business development manager Daniel Bryan and Chief Revenue Officer Robert Saffer were promoting the company and the photovoltaic factory it is developing near Watertown in northern New York. They expect it to begin production in late 2023. At full output, it will employ more than 300 people and annually produce residential and commercial panels with a combined 1.2 GW capacity. The company currently contracts for manufacture in Asia.
Saffer said the factory was on the drawing board before the IRA was signed into law, and there was no guarantee its domestic manufacturing incentives would come to pass.
“It was the cherry on top of the cake,” he said. “I don’t think we’d have 550 people here without the IRA.”
FERC rescinded RTO participation incentives for two American Electric Power (NASDAQ:AEP) affiliates last week on the grounds that Ohio law compels transmission owners to participate in an RTO (EL22-34).
The Ohio Consumers’ Counsel (OCC) argued in a Feb. 24, 2022, protest that AEP’s Ohio Power Co. and AEP Ohio Transmission Co., both PJM members, should not be permitted to continue charging a 50 basis point adder to their authorized return on equity (ROE). The commission agreed with the OCC that past commission orders have established a “voluntariness” requirement — that the adders are an incentive to join and remain members of transmission organizations and not applicable where state law requires participation.
However, the commission rejected the OCC’s challenge of RTO adders for FirstEnergy’s (NYSE:FE) American Transmission Systems, Inc. (ATSI) and Duke Energy Ohio (NYSE:DUK).
In its Dec. 15 order, the commission found that since both ATSI and Duke Energy Ohio reached their rates through integrated settlement packages — rather than having adders directly authorized by the commission — it would require evidence that the companies’ overall ROE is unjust and unreasonable for it to consider ordering changes.
“We do not know the precise trade-offs and concessions made by parties to those proceedings during the settlement process and the terms to which and conditions to which those parties would have agreed with respect to Ohio transmission assets had the commission policy on RTO adders been different. As such, we do not find it would be appropriate to change unilaterally a single aspect of such a comprehensive settlement,” the commission said.
Since Ohio law states that “no entity shall own or control transmission facilities … unless that entity is a member of, and transfers control of those facilities to, one or more qualifying transmission entities,” the OCC argued that the adders do not comport with subsequent court decisions and commission orders establishing that the purpose of the adder is to incentivize a voluntary action.
“In other words, the transmission owners are making consumers pay them higher profits to comply with Ohio law,” the OCC protest states.
The two AEP utilities unsuccessfully argued that since its affiliates set a single transmission rate uniformly across several states, the removal of the adder in one state would effectively “privilege one state’s mandate over another states’ decision to leave RTO membership up to the utility.” The company also claimed that an Ohio-only remedy would be impractical as it would require AEP to disaggregate its transmission operations for each state, eliminating efficiencies that benefit customers.
The precedent for the voluntariness requirement was established with the commission’s Order 679, which established the adders to comport with Federal Power Act Section 219, which requires that incentives be given to utilities that join transmission organizations.
In 2018, the 9th Circuit Court of Appeals ruled that PG&E is entitled to an adder as its participation in CAISO is voluntary, finding that “the voluntariness of a utility’s membership in a transmission organization is logically relevant to whether it is eligible for an adder.” (See PG&E Deserves $30M ISO Adder, FERC Says.)
The protest also points to FERC’s 2021 order that Dayton Power and Light Co. (NYSE:AES) is ineligible for an adder under Ohio law (ER20-1068).
The OCC estimated the cost of the adder at more than $26 million across the four utilities, which it told FERC is likely conservative as it only takes into account over-earnings on projects in PJM’s Regional Transmission Expansion Plan. The commission granted the protest’s request that refunds be issued to customers of Ohio Power and AEP Ohio for the amount they were charged going back to the Feb. 24 filing date.
Danly Dissents
Commissioner James Danly dissented with the commission’s finding that the AEP utilities no longer receive the RTO adder.
He argued that the FPA does not limit the incentives to those who join and remain members of an RTO voluntarily and that the 9th Circuit Court of Appeals only interpreted FERC’s Order 679, not the underlying federal law. The ruling does not address whether the commission exceeded the FPA by limiting the incentive to voluntary participants, Danly added.
“The Federal Power Act does not limit incentives to only those utilities that ‘voluntarily’ join a transmission organization. The commission improperly added this non-statutory requirement in Order No. 679. We had no authority to do so then or now,” Danly wrote.
Christie Concurs
Commissioner Mark Christie issued a concurrence in which he noted that a majority of commissioners voted in April 2021 to limit the RTO adder to three years after a utility joins a transmission organization.
“Over a year and a half later, we have yet to take a final vote to implement that limit. As long as we do not, consumers will continue to pay these adders at a time when consumers are already facing rapidly rising monthly power bills,” he said.
ALBANY, N.Y. — New York’s Climate Action Council approved its Scoping Plan for meeting the state’s decarbonization goals Monday, saying the plan will save the state more than $100 billion and create hundreds of thousands of jobs.
But three members of the 22-member council opposed the plan, citing concerns over cost, electric reliability and feasibility.
The scoping plan was mandated by the 2019 Climate Leadership and Community Protection Act (CLCPA), which calls for a 40% cut in economywide greenhouse gas emissions from 1990 levels by 2030 and an 85% cut by 2050. The 445-page plan is the result of more than two years of work by seven sector-specific advisory panels and the Just Transition Working Group and was informed by 11 public hearings and more than 35,000 written comments.
‘Diverse and Divergent’
Net present value of benefits and costs of three scenarios relative to business-as-usual reference case | New York Climate Action Council
Council members who supported the plan said that acting on climate change would ultimately be cheaper than inaction.
Paul Shepson, dean of the College of Marine and Atmospheric Sciences at Stony Brook University, said the document is the product of compromise between “diverse and sometimes divergent interests” but is “nonetheless a great statement of New York’s commitment to achieve climate stabilization.”
RuthAnne Visnauskas, CEO of New York State Homes and Community Renewal, said the “process has been exhaustive; it has been comprehensive, thoughtful and inclusive.”
Raya Salter, executive director of the Energy Justice Law & Policy Center, said “true credit belongs with the thousands of protesters who demanded that this be the people’s plan.” She added that more work needs to be done and future advocates should remember to “keep a true north to climate justice.”
Anne Reynolds, executive director for the Alliance of Clean Energy New York, sought to address the “naysayers” in the room, saying that she believed the plan addressed all the concerns raised.
Cost Concerns
Voting against the plan were Dennis Elsenbeck, head of energy and sustainability at law firm Phillips Lytle; Gavin Donohue, CEO of the Independent Power Producers of New York (IPPNY); and Donna L. DeCarolis, president of National Fuel Gas Distribution.
Elsenbeck said the plan “fundamentally missed the economics of sustainability” and was not ensuring that “state investments drive substantial return on [New York’s] economy and environment.”
Donohue said a scoping plan should identify the most cost-effective and technologically feasible path to meeting the state’s climate goals. “This document does not do that. The ramifications of this plan do not just impact the energy sector, they will affect the entire New York State economy. Reliability is paramount and is not adequately addressed,” he said.
New York greenhouse gas emissions by sector | New York Climate Action Council
“We may achieve our 2030 goals if absolutely everything goes as anticipated by the plan,” he added. “Getting from 2030 to 2040 is going to need magic since the pathway and timetable for identifying and developing zero-emission dispatchable resources so that they are operating by 2040, is missing.”
DeCarolis said that the “plan fails to use the existing natural gas system for decarbonization,” and that consumers, particularly those in Northern and Western New York, should be given the option to use existing infrastructure to avoid higher costs.
She said the plan is based on an “undue reliance on electrification” and that, without a quantitative analysis of the economic impacts stemming from forcing consumers to electrify, the CAC cannot say for certain whether “consumers will pay more for a less reliable system.”
Donohue also pointed to consumer impacts from the plan, saying that consumers should not be “fooled because we don’t know what the costs will be,” pointing out that the CAC has not conducted a comprehensive cost or price study.
Both DeCarolis and Donohue also cited concerns about regulation.
Donohue said that there is immense “uncertainty” about how the state will be able to permit all the generation and transmission projects needed. Without “regulating our energy properly,” New York will not be able to stay competitive with other states, he said.
DeCarolis told members that the plan “relies too heavily on energy sources prone to energy disruptions.”
Protecting Disadvantaged Communities, Creating Jobs
The council said plan “prioritizes disadvantaged communities and the creation of good, family-sustaining, union jobs accessible to all New Yorkers.”
The council said it examined several pathways to reducing GHG emissions “governed by foundational principles of ensuring reliability [and] cost-effectiveness.”
The council concluded that:
Achieving deep decarbonization is feasible by 2050 but will require action in all sectors. “Every sector will see significant transformation over the next decade and beyond, which will require critical investments in New York’s economy.”
Energy efficiency and end-use electrification are essential. About 1 to 2 million efficient homes must be electrified with heat pumps by 2030 and 3 million zero-emission vehicles (predominantly battery electric) will be needed by 2030.
The cost of inaction exceeds the cost of action by more than $115 billion. GHG emission-reduction strategies will improve air quality, increase “active transportation,” and energy efficiency investments for low- and moderate-income homes. Reducing emissions also avoids the economic impacts of societal damages from climate change.
New jobs from Climate Act investments will outnumber displaced jobs by a ratio of 10 to 1 in 2030, with up to 211,000 jobs expected to be created by 2030 and 318,000 by 2040.
Net direct costs are estimated to be up to 0.6% of New York’s economy in 2030 and 1.3% in 2050. The federal Inflation Reduction Act is expected to reduce the costs of decarbonization.
Chair Comments
NYSERDA President Doreen Harris and Department of Environmental Conservation Commissioner Basil Seggos took questions from reporters after the council meeting concluded.
“The burden now shifts to the agencies, chiefly the DEC, to chart a path forward,” Seggos said, citing the agency’s finalization last week of regulations on handling of air pollution control permit applications and incorporating climate change considerations in all activities.
“What we’ve learned as a council is that there are higher degrees of uncertainty with respect to how we reach our goals,” Harris said. The reason the council will periodically reconvene is because the “truth is that 2050 will be very different than what any one of us can predict, so it is important to keep long term objectives in mind.”
Other Reaction
Advanced Energy Economy applauded the plan.
“New York now has a plan for removing most carbon emissions from the state’s economy, an ambitious and laudable goal that will increase clean energy use, put more New Yorkers to work, and support local economies,” said Angela Kent, policy principal at AEE. “With a decarbonization plan in hand, Gov. [Kathy] Hochul and state leaders should act swiftly to implement the plan’s recommendations, especially in order to make it easier for clean energy projects to connect to the grid, and create new financial incentives for communities to switch to clean energy.”
Anbaric praised the council for supporting transmission upgrades. “With 9 GW of offshore wind power coming online by 2035 — and a recommendation for up to 19 GW of new offshore wind — New York urgently needs a shared and open-access transmission system to ensure offshore wind power is delivered efficiently, affordably and reliably to the highest demand centers,” Mid-Atlantic President at Anbaric Janice Fuller said.
Synchronized reserves have seen a drop in prices since PJM implemented market overhauls at the start of October, the RTO says.
According to a presentation given during the Market Implementation Committee’s meeting Dec. 7, the average clearing price in both the day-ahead and real-time markets was less than $2/MWh for the first two months of the new market rules. In October, the day-ahead prices were $0 for over 95% of the hours, while in November that lowered to 87%.
The presentation said the “significantly reduced” prices are believed to be caused by the lowering of the offer cap from $7.50/MWh to 2 cents, and by the must-offer requirement expanding the pool of resources providing synchronized reserve services. In the real-time market, prices were at or below 2 cents for about 72% of the hours in September, prior to the changes being implemented, while that share climbed to 96% in October.
The changes, approved by FERC in May 2020, aligned the day-ahead and real-time market products with the aim of eliminating the practice of PJM having to go out-of-market to procure reserves. Both the commission and PJM indicated then that they believed the changes would lead to increased pricing. (See FERC Approves PJM Reserve Market Overhaul.)
The commission partially reversed its previous order in January, saying that changes it had made to PJM’s operating reserve demand curve (ORDC) were a mistake. The downward sloping ORDC approved by FERC in 2020 would have allowed LMPs to exceed $12,050 during extreme shortages. (See FERC Reverses Itself on PJM Reserve Market Changes.)
Dana Guernsey, co-founder of distributed energy resource provider Voltus, said the price fall appears to have caught most by surprise. While she said two months of data are still not enough to be sure of the impact, if the lowered prices persist, they may not provide the appropriate incentives for some resources to continue to provide reserves.
“PJM set out to reform their market to accurately reflect the reliability value of reserves, but the prices we’re seeing do not actually create efficient market signals … at a time when reserves are more and more important,” she said.
She noted that a 2018 price formation paper published by PJM explained the stated focus of the changes was to enhance the reserve markets “by more directly aligning the reliability value of reserves with the clearing price for them and strengthening incentives for performance when reserves are deployed.”
Ken Schisler, CPower Energy senior vice president of regulatory affairs, agreed that the scale of the price fall was more significant than expected.
“The drop in pricing is deeper than many at PJM and in the industry anticipated. We are keeping an eye on pricing, and in the meantime we are evolving our portfolio and market participation based upon the price signals the market is sending us,” he said.
Throughout the discussion of how the changes were expected to function once live in the markets, it was imagined that they would likely lead to prices increasing. Guernsey hypothesized that FERC revisiting its 2020 order and removing the ORDC provisions, but leaving the rest of PJM’s proposal, may have distorted the intent and functionality of the changes.
“Maybe the original price formation proposal got edited so many times along the way that now we’re seeing unintended consequences,” Guernsey said. “It seems like the original goals not only were not accomplished, but we might even be seeing the opposite effect take hold.”
She suggested that PJM consider increasing the offer cap above the newly adopted 2-cent maximum.
“The offer cap is meant to reflect the expected value of the penalty for failing to provide synchronized reserves. I don’t understand how a 2-cent penalty is a healthy market signal if the goal is reliable reserve resources,” she said.
Independent Market Monitor Joe Bowring said that, based on the data to date, the market prices appear to be the result of market fundamentals; supply increased significantly and prices decreased. Bowring said he does not believe the price decline will have an overall significant impact on demand response providers, as more than 95% of their revenues are derived from the capacity market.
Increasing prices is not the goal of the market design, and higher prices are not by definition more efficient, Bowring said; prices should reflect the actual supply and demand of reserves.
He said that there is no evidence that the price decrease was a result of removing the $7.50 adder and also argued that the previous adder was not accurate.
“The $7.50 was always an incorrect number. There was never a logical basis for the markup. It wasn’t based on costs,” he said.
The Japanese company that just bought up a significant portion New England’s energy generation doesn’t see its decarbonization future in renewables, its CEO said at a conference last week.
JERA Americas, the U.S. division of Japanese energy giant JERA, recently purchased two gas plants in Massachusetts and Maine.
The deal was approved by FERC, despite objections from consumer advocates that it would threaten competition by giving the company too large a share of the generation market in New England, particularly in Southern New England, where it now controls 18% of generating capacity. (See FERC Approves New England Generation Deal Over Competition Objections.)
JERA Americas CEO Steve Winn made some of the first public comments about the company’s plans for its newly increased footprint in the region last week at the New England Energy Summit.
The company is interested in the Northeast because it shares similarities with Japan, he said, including relatively high population density, limits on the potential for new construction and decarbonization goals.
But the company’s goals aren’t necessarily aligned with that of regional policymakers who have pushed for building more renewables.
“Our focus on decarbonization is really on low-carbon fuels,” he told the conference.
JERA owns around 5 GW of renewables globally, made up of small projects in Asia and Europe, but Winn said the company doesn’t see that as nearly enough to meet its decarbonization goals.
In part, he said, that’s because the company’s home country has limited interest in wind and solar.
“Unlike some parts of North America, renewable resources are hard in Japan. It’s very mountainous. There’s not a lot of uncovered land at the moment,” he said.
So instead, the company is focusing on making its fuel cleaner by modifying natural gas plants to burn hydrogen, both in Japan and the U.S. That includes its Linden project in New Jersey, which will be modified to use up to 40% hydrogen.
Hydrogen could very well fit into the company’s plans in New England as well, Winn said.
“We’re looking at both blue and green hydrogen,” he said. And he added that if the company can’t make hydrogen for its plants locally, it can just bring it in from abroad. “We run a very large fleet of ships right now,” he said.
Overall, Winn said, reliability is one of the company’s main focuses, which was why it bought the Canal Generating Station in Sandwich, Mass., the bigger of its new purchases.
“For us, reliability and the low-carbon transition are tied together. And Canal was bought with that in mind,” he said. “We can provide reliability to the market.”
The company is also planning to offer up its newly acquired New England plants as possible interconnecting points for renewables. Canal could be a connection point for offshore wind coming off Cape Cod, and the Bucksport plant in Maine has an existing transmission interconnection that could link renewables to the grid, the company said in a recent separate press release.
“We are committed to transitioning the existing units to greener forms of energy as well as employing the attributes of the sites to enable renewable energy development in New England,” JERA said.
FERC on Thursday rejected a complaint by cybersecurity activist George Cotter, who last year accused NERC of seriously neglecting the cybersecurity needs of the bulk electric system (EL21-105).
The commission said Cotter did “not provide any legal basis to conclude” that NERC had neglected to follow relevant statutory or regulatory requirements, as he alleged.
Cotter, a former chief of staff at the National Security Agency, filed his complaint in October 2021, originally as a response to FERC’s proposal for incentivizing public utilities to invest in cybersecurity improvements (RM21-3). However, because the submission was “styled as a complaint,” the commission re-docketed it as a complaint proceeding.
The original filing concerns a number of alleged issues with NERC’s Critical Infrastructure Protection (CIP) standards. Cotter called FERC’s proposed cybersecurity incentives a “distinct challenge to overall transparency” of the CIP standards and an attempt at hiding a “major decision [by the commission] to protect regional entities’ control of pre-existing non-CIP reliability standards from potential conflict/interference from CIP standards.” He called on FERC to address the shortcomings in the standards that he claimed to have identified.
Cotter Claimed Deep Standard Flaws
According to Cotter’s narrative, the creation of NERC’s reliability standards following a mandate in the Federal Power Act of 2005 created “two sets of, apparently, non-interfering standards” comprising the CIP standards on the one hand and the non-CIP standards on the other.
As part of the effort to create the CIP standards, Cotter argued, FERC Order 706 allowed NERC to exclude “communications and networks” from the CIP family “to support the fiction that the [CIP standards] secured the” bulk power system, in spite of the “enormous dependencies of non-CIP … standards on precisely the same resources.” Cotter said that omitting this important element of cybersecurity made the grid significantly more vulnerable to intrusion.
George Cotter, author of the complaint against NERC’s Critical Infrastructure Protection standards
| National Security Agency
The response to subsequent security incidents, including the penetration by Russian intelligence of the supply chains of three vendors providing control systems for U.S. utilities in 2012, was hampered by FERC’s further unnecessary interference, in Cotter’s telling. The commission’s decision to implement version 5 of the CIP standards in 2016 impeded the investigation into these attacks and constituted “a low-water mark in the early history of cyber warfare” for which “FERC will forever bear the fundamental responsibility.”
“With every opportunity to plug the vulnerability that risks much of the nation’s national security and critical infrastructures, FERC is determined to continue fogging up this huge advantage to the nation’s adversaries in this legislation,” Cotter said in the filing. “Regulatory procedures adopted by FERC intended to prevent public knowledge of utility security flaws, vulnerabilities, incidents, and compliance audits have obscured all but a slow leakage of industry and FERC efforts to maintain the status quo.”
Cotter also suggested that the introduction of the CIP standards created a bifurcated regime, with “non-CIP reliability standards still largely controlled by regional entities.” By this Cotter apparently meant the existence of regional variants on national standards, which are developed by REs and submitted to NERC for approval.
To address these issues, Cotter argued that “FERC must accept that 4,000 … independent and semi-independent utilities cannot collectively secure the grid” and must also accept — along with government officials — “the reality of ‘deterrence’ as the first line of defense of the electric system.” This new approach would also include training National Guard and military reserve units as first responders to incidents with electricity providers. Cotter also called for the adoption of the National Institute of Standards and Technology’s cybersecurity framework by utilities, and for regulators to “orient their cybersecurity standards decisions on ‘vulnerabilities’ vs. ‘threats.’”
NERC Noted No Basis
In a response filed last year, NERC asserted that Cotter’s allegations “rest on various misunderstandings regarding legislative history, commission issuances, and NERC activities.” The organization said that these misunderstandings are the reason for the “gap in reliability standards” that Cotter claimed. NERC said that contrary to Cotter’s description, there is no division between CIP standards and others in NERC’s library, that it does not suppress information on CIP violations, and that its compliance monitoring and enforcement regarding the CIP standards is not deficient.
Moreover, Cotter’s description of the non-CIP standards as controlled by REs reflects a “complete misunderstanding of … [RE] activities.” NERC pointed out that “there are fewer than 20 regional variations in effect across North America,” all of which were approved by NERC and “applicable governmental authorities.” The organization called for FERC to dismiss the complaint on the grounds that it lacks a “basis in fact and law for the positions taken,” and does not demonstrate any action by NERC that is inconsistent with applicable laws under FERC’s jurisdiction.
In its decision, FERC sided with NERC, citing multiple apparent problems with the complaint. First, the commission said that Cotter provided no proof or analysis in support of his allegations, notably for how the actions and inactions he described violated the Federal Power Act. FERC echoed NERC, saying there is no difference between CIP and non-CIP standards in terms of enforcement.
In addition, the commission dismissed Cotter’s claim that communication networks are excluded from the CIP standards, saying the exemption referenced is “limited [in] nature” and sets out criteria for networks that must be included in the enforcement. Moreover, regarding regional standard variants, while FERC acknowledged that “uniformity of reliability standards should be the rule rather than the exception,” it noted that regional variants must be “more stringent than the continent-wide reliability standards [or] necessitated by a physical difference in the” BPS.
FERC also pointed out that several of Cotter’s suggested solutions require action by entities such as the U.S. Congress, states, and the military, over which FERC does not have jurisdiction. Regarding the other solutions, the commission concluded that Cotter’s request would require it to direct NERC to create a new standard or modify existing standards. Because of the lack of factual basis for Cotter’s claims, FERC concluded there is no need for such a standard at this time.
Avangrid has moved to terminate power purchase agreements for Commonwealth Wind, a 1.2-GW offshore wind project it is developing in Massachusetts, saying the deals have become financially untenable and that the other parties refuse to renegotiate.
In the dismissal motion it submitted to the state Department of Public Utilities on Friday and in a public announcement, the company said it remains committed to Commonwealth Wind. But it said the project should be wrapped into the state’s 2023 offshore wind power solicitation, at which point Avangrid could submit a bid that would be financially sustainable and proceed on a timetable that would meet the state’s 2030 climate protection goals.
Avangrid said the bid it submitted in September 2021 and the PPAs it subsequently negotiated with three electric distribution companies (EDCs) in April 2022 were overtaken by factors including high inflation, sharply higher interest rates, the war in Ukraine and supply chain shortages.
On Oct. 20, Avangrid asked the DPU to put its review of the PPAs on hold for a month so it could renegotiate them. The three EDCs — Eversource Energy, National Grid and Unitil — opposed this, saying they had no intention of renegotiating.
Mayflower Wind Energy on Oct. 27 made a similar request to delay review of the PPAs for 400 MW of wind power it is developing off the Massachusetts coast.
The DPU denied the requests Nov. 4, saying the developers could move forward with the PPAs in place or move for dismissal, but not renegotiate them. Mayflower withdrew its request Nov. 7, saying it would continue with the PPAs and seek to resolve issues through conversation. It declined to comment Monday on its plans or the status of those talks.
But Avangrid on Nov. 14 said it would continue with the proceedings and seek ways to make Commonwealth financeable and economically viable. (See: Mass. OSW Projects to Continue Through Regulatory Process.)
On Friday, Avangrid moved for dismissal, saying the EDCs had refused to meet with it on the matter.
“No interest is advanced by approving PPAs that cannot and will not lead to the development of offshore wind energy generation,” the company’s attorneys wrote. “Instead, the commonwealth should conduct a robust fourth solicitation under Section 83C as soon as possible.”
In its public statement Friday, Avangrid emphasized its commitment to clean energy in Massachusetts, including its 800-MW Vineyard Wind I project slated to come online late next year. It said it remained committed to Commonwealth Wind and was disappointed the EDCs had refused to discuss it.
The DPU is reviewing Avangrid’s dismissal motion. Danielle Burney, spokesperson for the Massachusetts Executive Office of Energy and Environmental Affairs, which oversees DPU, said in an email that the offices of Gov. Charlie Baker and Lt. Gov. Karyn Polito were displeased with Avangrid’s move.
“The Baker-Polito administration is disappointed by Avangrid’s request to the Department of Public Utilities to dismiss the review of the Commonwealth Wind contracts,” Burney wrote. “But [the administration] remains committed to the deployment of commercial-scale offshore wind and advancing clean, affordable energy on behalf of the Commonwealth’s residents and businesses, while reducing greenhouse gas emissions and meeting the state’s emissions goals, including achieving net zero in 2050.”
Below is a summary of the agenda items scheduled to be brought to a vote at the PJM Markets and Reliability Committee and Members Committee meetings Wednesday. Each item is listed by agenda number, description and projected time of discussion, followed by a summary of the issue and links to prior coverage in RTO Insider.
RTO Insider will be covering the discussions and votes. See Jan. 3’s newsletter for a full report.
Markets and Reliability Committee
Consent Agenda (9:05-9:10)
B. Endorse proposed revisions to Manual 10: Pre-Scheduling Operations resulting from a periodic review.
C. Endorse proposed revisions to Manual 14D: Generator Operational Requirements resulting from a periodic review.
D. Endorse proposed revisions to Manual 27: Open Access Transmission Tariff Accounting resulting from a periodic review.
E. Endorse proposed clarifying tariff and Operating Agreement (OA) revisions as endorsed by the Governing Documents Enhancements and Clarifications Subcommittee (GDECS).
Endorsements (9:10-10:10)
1. Energy and Reserve Market Circuit Breaker (9:10-9:40)
Adrien Ford of Old Dominion Electric Cooperative will present the main motion for a proposed “circuit breaker”: a mechanism for limiting extremely high prices. David Scarpignato of Calpine will present an alternative motion for a proposal.
Stakeholders have expressed mixed opinions on the issue, with a poll conducted in the Energy Price Formation Senior Task Force yielding less than 50% support for each of the seven packages then under consideration. Discussion was tabled during the November MRC so that ODEC and Calpine could attempt to form a compromise package. (See “Support for Circuit Breaker Remains Mixed,” PJM MRC Briefs: Oct. 24, 2022.)
The committee will be asked to endorse a proposed solution.
PJM’s Stefan Starkov will review a proposal addressing the treatment of long-term market suspensions, meant to provide a solution for settling real-time market prices when they cannot be determined. (See “Market Suspension,” PJM Market Implementation Committee Briefs: June 8, 2022.)
The committee will be asked to endorse the proposed solution.
PJM’s Colleen Hicks will present a proposal to allow the RTO flexibility to allow market participants to continue operating in markets after a default under certain circumstances. (See “1st Read on Proposal to Allow Flexibility for Market Participation During Defaults,” PJM MRC Briefs: Nov. 16, 2022.)
The committee will be asked to endorse a proposed solution and corresponding tariff and OA revisions.
B. Endorse proposed tariff and OA revisions supporting the transmission constraint penalty factor solutions package. (See “TCPF Adjustments Permitted for Issues with Ongoing Solution,” PJM MRC Briefs: Nov. 16, 2022.)
C. Endorse proposed revisions to Manual 15: Cost Development Guidelines and OA Schedule 2 addressing the development of variable operations and maintenance costs. (See “MRC Approves VOM Package,” PJM MRC Briefs: Nov. 16, 2022.)
D. Endorse proposed revisions to the tariff, Reliability Assurance Agreement (RAA) and OA to prohibit critical natural gas infrastructure load from participating in demand response programs, pursuant to the recommendations included in the FERC/NERC report on the February 2021 winter storm in the south central US. (See “Reworked Language on Critical Gas Infrastructure Participation in Demand Response Presented,” PJM MRC Briefs: Oct. 24, 2022.)
E. Endorse proposed corresponding tariff and OA revisions supporting the financial transmission rights Bilateral Review and Reporting solution. The changes would require that FTR bilateral agreements be reported to PJM within 48 hours of their execution, accompanied by certain data, including FTR start/end, quantity, source and price. (See “Other Committee Actions,” PJM MRC Briefs: Nov. 16, 2022.)
Michele Greening will review the proposed next year’s sector representatives for the Finance Committee, sector whips and the vice chair of the committee. The MC will be asked to elect the proposed representatives.
FERC on Thursday denied a Tenaska complaint alleging that several grid operators adopted operating guides that resulted in unduly discriminatory curtailment of a wind farm it owns and operates.
The commission said in its order that Tenaska failed to show unjust, unreasonable and unduly discriminatory or preferential behavior under the Federal Power Act. Because it denied the complaint, FERC also rejected Tenaska’s requested relief for $9 million in lost revenue from the alleged curtailment (EL-22-59).
Tenaska filed its complaint in May, charging that MISO, SPP, Associated Electric Cooperative Inc. (AECI) and Tennessee Valley Authority had adopted operating guides that curtailed the Clear Creek Wind Project in a manner inconsistent with their tariffs.
The 242-MW facility sits within AECI’s Missouri footprint. The cooperative is the wind farm’s sole purchaser of power.
AECI is a generation and transmission cooperative and is classified as an “unregulated transmitting utility” without a tariff on file at FERC. TVA serves as the NERC-registered reliability coordinator for AECI’s balancing authority and MISO and SPP neighbor the cooperative’s transmission system.
FERC found MISO had not treated Tenaska in an unduly discriminatory manner, noting the company did not present any evidence that MISO has curtailed the wind farm. It also pointed out that the project is not located in MISO’s footprint; that Tenaska does not take transmission service from MISO for the project; and that MISO determined that no affected system network upgrades were required for the facility to operate.
The commission ruled SPP, AECI and TVA had not treated Tenaska unreasonably, although their collective actions did result in the Clear Creek project’s curtailment. However, according to the SPP-AECI joint operating agreement and SPP’s tariff, the wind farm is subject to limited operation until SPP can complete network upgrades on its system.
“Therefore, such curtailment is permissible to manage congestion and ensure the reliable operation of the transmission system,” the commissioners wrote.
FERC noted Tenaska’s facility is subject to limited operation because it entered commercial operation before SPP was able to complete the necessary network upgrades on its system. Because of that, the commission found Tenaska is “differently situated from other interconnection customers who are not subject to limited operation.”
The commission also disagreed with Tenaska’s argument that SPP should be required to file its operating guides with FERC. It said SPP’s operating guides are the mechanism by which the Tenaska facility’s limited operation was set and do not significantly affect rates, terms or conditions of service. FERC upheld SPP’s and AECI’s request to not publicly release the guides.
Commission Accepts Late Agreements
The commission accepted four of five late agreements filed by Cheyenne Light, Fuel and Power, a subsidiary of Black Hills, effective Dec. 14, 2021 (ER22-109).
The late agreements were discovered after a comprehensive review of the utility’s effective transmission and wholesale energy contracts to ensure any jurisdictional agreements were properly filed. They included a consolidated facilities agreement, an interconnection agreement, an Air Force agreement, an operating agreement and a large generator interconnection agreement (LGIA).
FERC only rejected an LGIA with Silver Sage Windpower, which dated to 2009. The LGIA contained seven non-conforming provisions, but the utility said it did not change the fact that a transmission provider under the commission’s large generator interconnection process is only paid for its actual costs in facilitating the interconnection. That meant the Silver Sage agreement only provided for collection of pass-through costs associated with the generation’s interconnection, Cheyenne Light said.
The commission said Cheyenne Light had not demonstrated that the deviations from the pro forma LGIA are necessary to address specificreliability concerns, novellegal issues or other uniquefactors associated with the agreements.
