New York Climate Scoping Plan OK’d

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’

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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.

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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.

December 20, 2022January 1, 2024

Synchronized Reserve Pricing Falls in PJM Markets After Overhaul

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.

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Monitoring Analytics President Joe Bowring | © RTO Insider LLC

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.

December 20, 2022

New England’s New Gen Giant Sees Future in Hydrogen, Not Renewables

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.

December 20, 2022December 12, 2023

FERC Denies Cotter’s CIP Complaint

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.

December 20, 2022

Avangrid Seeks to Terminate Commonwealth Wind PPAs

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.”

December 20, 2022

PJM MRC/MC Preview: Dec. 21, 2022

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.

Issue Tracking: Operating Reserve Demand Curve (ORDC) & Transmission Constraint Penalty Factors

2. Rules Related to Market Suspension (9:40-9:55)

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.

Issue Tracking: Rules Related to Market Suspension

3. Market Participant Default Flexibility (9:55-10:10)

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.

Issue Tracking: Market Participant Default Flexibility

Members Committee

Consent Agenda (1:35-1:40)

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.)

Issue Tracking: Operating Reserve Demand Curve (ORDC) & Transmission Constraint Penalty Factors

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.)

Issue Tracking: Variable Operating and Maintenance Cost

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.)

Issue Tracking: Critical Gas Infrastructure – Demand Response Participation

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.)

Issue Tracking: FTR Bilateral Transactions Review and Reporting Requirements

Endorsements (1:40-1:55)

Elections (1:40-1:55)

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.

December 20, 2022December 27, 2023

FERC Denies Tenaska’s Complaints over Wind Curtailments

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 specific reliability concerns, novel legal issues or other unique factors associated with the agreements.

December 20, 2022

TransWest Express to Join CAISO as Tx Owner

The CAISO Board of Governors voted Thursday to admit a merchant transmission project that plans to bring Wyoming wind to California as a participating transmission owner using a new subscriber model.

The admission of the TransWest Express is still “somewhat conditional,” requiring additional steps to complete, including signing up buyers in CAISO for the line’s wind energy, Neil Millar, vice president of infrastructure and operations planning, wrote in a memo to the board.

Assuming that happens, the project will expand CAISO’s reach hundreds of miles east and establish a new transmission-owner model, Deb Le Vine, CAISO director of infrastructure contracts and management, told the governors in Thursday’s board meeting.

“This is a unique opportunity that the ISO has to expand our grid and the way that participating transmission owners come into the ISO,” Le Vine said. “The uniqueness is that TransWest Express has already gone through a public solicitation and sold the rights to its transmission lines from Wyoming to California, and then they’ll be looking for off-takers for that wind generation — about 3,000 MW of wind that they’re looking at bringing in.”

Last year, TransWest conducted a FERC-approved open-solicitation process that offered firm, long-term transmission service to California via Utah and Nevada. It decided to allocate 100% of its capacity to Power Company of Wyoming, owner of a 3,000-MW wind farm being constructed in the south-central part of the state. FERC approved the arrangement in February.

Both TransWest and Power Company are wholly owned affiliates of The Anschutz Corp., a privately held company based in Denver and controlled by billionaire Phillip Anschutz, who made much of his fortune from fossil fuels and is now seeking to benefit from California’s clean energy mandate, which requires 100% of retail energy to be carbon-free by 2045.

To meet the 2045 goal, the state will need to import as much as 10 GW of out-of-state wind by 2040, at least half of it from Wyoming, according to projections by the California Public Utilities Commission and the California Energy Commission.

CAISO’s recent 20-year transmission outlook examined new transmission needed for the undertaking, predicting overall costs of $30 billion that includes $12 billion to carry wind from the Great Plains and Rocky Mountain states. (See CAISO Sees $30B Need for Tx Development.)

TransWest applied to join CAISO in July, saying in its application that it “intends to place under the CAISO’s operational control all of [its] project transmission lines and associated facilities … that will connect to the existing bulk power system in Wyoming and Utah as well as directly to the [CAISO]-controlled grid in Nevada.”

It would be CAISO’s first subscriber participating transmission owner (SPTO), a new model that would give the ISO control of power lines without increasing the ISO’s transmission access charge (TAC), currently more than $16/MWh. Some Western entities raised concerns about the SPTO model and asked that it be vetted in a stakeholder process, but CAISO chose to move ahead with the plan. (See TransWest Express Seeks to Join CAISO.)

Once built, TransWest will consist of 732 miles of transmission lines in three linked segments: a 405-mile, 3,000-MW HVDC system between Wyoming and Utah; a 278-mile, 1,500-MW HVAC line between Utah and Nevada; and a 49-mile, 1,500-MW HVAC transmission line in Nevada. It will connect in Utah to lines serving the Los Angeles Department of Water and Power (LADWP) and in Nevada to CAISO’s grid and balancing authority area.

The project is in an “advanced stage of development, focused on pre-construction matters including tower design and testing; interconnections; contracting with engineering, procurement and construction contractors; and financing,” the application said. “All major permits have been acquired, and 100% of the easements/authorizations to build on private lands have been secured.” Major parts of the project could be in service by 2026, it said.

Just before Thursday’s vote, TransWest Express COO Roxane Perruso thanked the ISO management team for “working with us on our application to become a participating transmission owner and the innovative subscriber PTO model. We think that this is a win-win for everyone … [that] avoids the need for a 39th balancing authority in the West and … particularly a generation-only BA.”

December 19, 2022

NYISO Capacity Accreditation Implementation Worries Stakeholders

RENSSELAER, N.Y. — NYISO stakeholders last week expressed reluctance to approve the ISO’s proposed implementation of its new capacity accreditation construct, with some saying they did not fully understand all of the changes and others saying it would be applied unequally.

The proposed revisions include the implementation details and technical specifications necessary for establishing capacity accreditation factors (CAFs) and capacity accreditation resource classes (CARCs), such as updated calculations for translation factors, demand curves and resource-specific derating factors.

Although the proposed revisions were ultimately approved, several stakeholders at the Business Issues Committee meeting Wednesday opposed the motions emphatically.

Jay Goodman, an attorney with Couch White, said his clients don’t oppose the capacity accreditation project outright but are “concerned with committing to implement it by May 1, 2024,” because it “will not be applied equally and accurately to all capacity providers at that time.”

Goodman said that they “perceive the capacity accreditation process as a work in progress” and that “numerous outstanding issues should be addressed or resolved prior to this vote taking place.”

They are also concerned that all thermal units will be treated as a single CARC, despite them having a “diversity of operating characteristics,” he said.

Daymark Energy Advisors CEO Marc Montalvo, representing the Utility Intervention Unit, explained that his abstention was “not because of a lack of faith in the ISO or the quality of their work” but “as much as a timing issue,” as well as a “feeling that [stakeholders] do not yet have a complete understanding of all the moving parts.”

Adam Evans, a staffer at the New York Department of Public Service, asked that “if there is remaining work that needs to done, then why would it not be included in what folks are voting on today?”

Doreen Saia, an attorney with Greenberg Traurig, recommended that NYISO edit the motion to avoid this “devolving into conversation about project prioritization” and alleviate concerns raised by stakeholders.

With guidance from Saia, NYISO then edited the motion recommending approval by the Management Committee and Board of Directors to say that the ISO is committed to addressing the capacity accreditation work plan as presented and any associated enhancements as necessary.

The proposed revisions now go to the MC this Wednesday. NYISO anticipates filing the summary of the final capacity accreditation implementation details with FERC within 90 days of MC approval.

Aggregated Hybrid Storage

The BIC also voted to recommend that the MC approve NYISO’s proposed tariff modifications that support the market participation of aggregated hybrid storage resources (HSR), generators co-located with storage resources that are all behind a single point of injection.

The changes would incentivize developers to couple generators with storage resources and, also, update the co-located storage resources (CSR) to allow for additional use cases, such as limited run-of-river hydro or landfill gas.

NYISO is targeting the third quarter of 2023 to file tariff modifications with FERC, anticipates making necessary software design updates throughout 2023 and plans on fully implementing the changes in 2025.

December 19, 2022June 14, 2023

FERC, NERC See Progress on Winter Weatherization

FERC Chairman Richard Glick said Thursday that regulators and industry have made “remarkable” progress on recommendations in response to the February 2021 winter storm but that he isn’t ready to declare “Mission Accomplished.”

FERC and NERC staffers told the commission during a presentation at the monthly open meeting that progress has been made on all 28 recommendations in the FERC-NERC report issued in November 2021, thanks to efforts by the ERO, Texas Railroad Commission (RRC), North American Energy Standards Board (NAESB) and National Association of Regulatory Utility Commissioners (NARUC), as well as ERCOT, MISO and SPP.

Among the responses cited by David Huff, of FERC’s Office of Electric Reliability, and Kiel Lyons, of NERC, were:

ERCOT’s inclusion of the February 2021 extreme winter weather conditions in calculating its base peak demand forecast for its 2022/23 Winter Seasonal Assessment; SPP incorporating a 90-10 load forecast and including limited fuel supply scenarios in its 2022/23 Winter Assessment; and MISO’s move to a seasonal capacity construct in winter 2023/24.
the Public Utility Commission of Texas’ work with the RRC to adopt an electric supply chain map of critical interdependent natural gas and electric infrastructure, which identify types of natural gas infrastructure to prioritize for protection from firm load sheds.
the PUC’s actions advancing new transmission beyond the Texas Interconnection’s current 1,220 MW of asynchronous DC ties to SPP (820 MW) and Mexico (400 MW). Southern Cross Transmission would provide a 2,000-MW link between the Texas Interconnection and the SERC Reliability region, while Grid United’s Pecos West project would add a 1,500-MW HVDC line between ERCOT’s West Texas region and El Paso in WECC territory (Project 53758). (See ERCOT Board Gives Southern Cross Project a Boost.) The FERC-NERC report said such links would increase the region’s import capacity during emergencies and improve its black start capabilities.
NERC’s September 2022 cold weather preparations alert and the ERO’s cold weather preparedness webinars and workshops, and the incorporation of more comprehensive extreme weather scenarios and energy assessments in NERC’s 2022/23 Winter Reliability Assessment. NERC’s Reliability and Security Technical Committee will hold a summit Jan. 31-Feb. 2 on the progress made toward implementing the recommendations.

Fourth Winter Event in 10 Years

The storm marked the largest firm load shed event in U.S. history, at 23,418 MW, and was the fourth event in 10 years in which reliability was jeopardized by unplanned generating unit outages in cold weather.

NERC initiated Project 2019-06 in response to a January 2018 cold weather event, when below-average temperatures resulted in 183 generating units in SPP, MISO, the Tennessee Valley Authority and SERC experiencing either an outage or a failure to start over a five-day period.

FERC/NERC

The rules — which require generator owners (GOs) to protect their units from freezing, and transmission operators (TOPs) and balancing authorities to revise their emergency operating plans — were approved by FERC in August 2021, several months after the February 2021 storm. (See FERC Approves Cold Weather Standards.) They don’t become effective until April 1, 2023 — too late for this winter.

Glick recalled that he and NERC CEO Jim Robb vowed that the findings on the storm would result in significant change and not “gather dust” like prior reports. (See FERC, NERC Release Final Texas Storm Report.)

“I think it’s remarkable when you think about the short time period [since the report] that we’ve made progress on all 28 recommendations,” Glick said. “Now, I want to make it clear: We’re not hanging the ‘Mission Accomplished’ banner. There’s still a lot more that needs to be done here … before we can feel more comfortable about where we stand in terms of Texas, but also elsewhere, in terms of preparedness for significant winter storms.”

‘Heavy Lift’

In late October, NERC filed for FERC approval of new reliability standards concerning freeze protection for generation and natural gas facilities impacting the bulk power system (RD23-1).

NERC said proposed reliability standards — EOP-012-1 (Extreme Cold Weather Preparedness and Operations) and EOP-011-3 (Emergency Operations) — build on the first round of cold weather standards approved by FERC in 2021, creating “a more comprehensive framework of requirements” on generator preparedness for cold weather operations and requiring TOPs to minimize the use of manual load sheds that could exacerbate emergency conditions and threaten reliability.

The report prompted Project 2021-07 (Extreme Cold Weather Grid Operations, Preparedness, and Coordination), which broke the recommendations into two phases, tackling four of them in the standards approved by NERC’s Board of Trustees in October and pending FERC approval. (See NERC Board Approves New Cold Weather Standards.)

SPP attorney Matthew Harward, the head of the standards drafting team, provided an update on the project at the Standards Committee meeting Dec. 13.

The recommendations in the second phase “are basically further identification of cold weather critical components and systems, and then the implementation of freeze-protection measures on each of those elements identified,” Harward said. “Those are GO requirements, and additional GO requirements that will be in the standard are that they must account for the effects of precipitation and wind when determining their lowest temperature [at which they are] able to operate.

“There are quite a few that will impact the BA and the data specifications between the BA, the RC [reliability coordinator], the TOP and the GO. A big one of that is that BA operating plans will need to prohibit critical natural gas infrastructure loads from participating in demand response programs,” he added.

The BAs, TOPs, RCs and transmission providers also will have new rules concerning how critical natural gas infrastructure is involved in manual and automatic load shedding.

“So we have some heavy lifts that the team is dealing with. We have a lot of participation from industry … which we feel is a good thing, but it also makes up for a lot of conversation; there’s a lot of opinions out there.”

Harward said his team is confident it can complete phase 2 and make its recommendations to the board by Sept. 30, 2023.

“It’s going to be a little more challenging than maybe we initially thought, but we are definitely up for the challenge,” he said.