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November 16, 2024

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PJM Members Lobby Board Ahead of Expected CIFP Filing

PJM members of all sectors have written letters to PJM’s Board of Managers urging that it direct PJM to file disparate changes to the capacity market in the wake of the critical issue fast path process (CIFP) that concluded in August with no proposals carrying the sector-weighted support of the membership.

American Municipal Power (AMP) called on the board to direct a narrower filing focused on reworking the nonperformance penalty rate generators pay should their units not meet their obligations during an emergency, as well as the corresponding annual stop loss limit, to be based on the Base Residual Auction (BRA) clearing price rather than the net cost of new entry (CONE).

AMP noted that although none of the CIFP proposals received sector-weighted support in August, the only proposal to receive a bare majority of support consisted of the changes to the nonperformance penalties. Shifting to penalties based on auction clearing prices also was endorsed by the MC in May, but was not included in a subsequent filing revising the capacity performance (CP) construct. (See FERC Approves PJM Change to Emergency Triggers.)

AMP said the August vote also showed considerable support for deeper changes to PJM’s capacity market, but also hesitation about making major changes with little time to conduct analysis and simulations to determine the potential effects.

“Many of the reforms discussed during the last five months still require more time for developing details and analyzing impacts. As AMP communicated early in the CIFP-RA process, the October 1 deadline is arbitrary and was an unnecessary impediment to developing a fully implementable set of reforms with broader support. Had more time been allotted the CIFP-RA process, stakeholders would have had adequate time to more fully understand the elements of each proposal and express their informed preferences,” the AMP letter said.

A broader consortium of power co-ops and industrial customers recommended a limited filing, followed by continued discussions with stakeholders on how to make changes to the core of the capacity market.

“The implications of those changes must be thoroughly evaluated in order for market participants, other stakeholders and this coalition in particular to understand the financial impacts on suppliers, load-serving entities and consumers. Implementation of reforms will require several capacity auctions in quick succession, and implementing these changes without fully considering their impact risks irreparable harm, and equally hasty and noncomprehensive follow-on mitigation efforts. Accordingly, additional time for consideration of all proposals is needed to ensure fair outcomes for everyone,” the letter said.

The PJM Industrial Customer Coalition (ICC) supported PJM’s proposal to increase modeling of winter risk, so long as the RTO continues to capture the reliability risks faced during the summer and the potential for electrification to exacerbate those risks. The ICC also supports the proposed expanded weather history, seasonal capacity testing requirements, adopting CP penalties and a stop-loss based on capacity prices, and requiring that generators report whether their fuel procurement contracts include firm service and potentially incorporating that into their accreditation.

Shell Energy North America argued the fast timeline for the CIFP process prevented a holistic and durable proposal from emerging and the discussion of market changes did not include full understanding of the barriers to investment in the capacity market. It stated that the forward markets have lost a significant amount of liquidity and seen a rise in the amount of risk investors take on. PJM’s proposed accreditation changes, new qualification standards for capacity resources and performance requirements would further increase market uncertainty, exacerbated by existing “regulatory uncertainty, administrative complexity and rule intervention.”

The Shell letter stated that many of the CIFP proposals would increase the administrative complexity of the capacity market and argued that future discussions should include the energy and ancillary service markets with the goal of increasing revenues from those markets to reduce reliance on the capacity market for maintaining reliability.

“Reliance on capacity markets as the primary mechanism for ensuring resource adequacy should be reduced over time as PJM transitions to a system with more intermittency. Energy and ancillary service market design enhancements can be administratively simple and transparent enough to effectively create market signals needed to address the unprecedented system changes and concomitant needs,” the letter said.

Several generators, including LS Power, J-Power and Talen Energy, submitted a letter recommending a “surgical filing” in October that includes portions of PJM’s proposal, while leaving the bulk of the capacity market intact. The recommended changes include shifting the reliability metric to expected unserved energy, a more granular hourly modeling in the reserve requirement study (RRS), seasonal capacity testing requirements, using weather history data going back to 1993 and more explicitly modeling the relationship between load patterns and weather in the RRS, fuel procurement contract reporting, and shifting the CP penalties to be based on the BRA clearing price with a corresponding market seller offer cap that reflects all capacity market risks.

The generators also recommend PJM continue to work with stakeholders to overhaul the capacity market in a way that improves transparency and replicability of market components, provides confidence that any changes will function as intended and has visibility into market risks and opportunities.

A letter from Talen Energy Marketing focused on how nonperformance penalties affected resources with long lead start times, arguing that not including an excusal for those generators unduly penalized them for operating according to the parameters included in their capacity offer.

“Shifting responsibility with respect to knowledge of the grid needs, including commitment and dispatch decisions, to generators by penalizing them during long start times, even if PJM dispatches them late or not at all, is untenable. It introduces risk that cannot be mitigated and likely will lead to the retirement of the very resources that are critical for reliability today and necessary for a reliable transition to a cleaner future,” Talen wrote to the board.

The East Kentucky Power Cooperative (EKPC) also encouraged a limited approach for any filing made in the near term, encouraging the board to revise the nonperformance penalty rate and to have resources dispatched consistent with their physical and fuel constraints. In the long term, EKPC recommended that the board direct staff to continue engaging with stakeholders to work toward a capacity model with hourly commitment.

Several environmental organizations and consumer advocates argued the cost implications the CIFP proposals would have for consumers was not adequately understood throughout the process and any filing should contain rules to protect against seller market power. It stated that PJM’s proposal includes a capacity performance quantified risk (CPQR) formula that would not include energy and ancillary service revenues, which it said would increase capacity costs without increasing reliability, would weaken the IMM’s ability to review capacity offers and would dilute the cost benefits of a seasonal capacity market with the design of the proposed demand curves.

The letter also said PJM’s proposal would not accurately reflect seasonal risk by not capturing the trend of increasing temperatures resulting from climate change and would zero out the capacity benefit of ties value by relying on a “binary, unrealistic and untested assumption” that no outside capacity will be available during critical hours.

The Organization of PJM States Inc. (OPSI) submitted a letter stating the majority of member states support PJM’s proposed changes to reliability risk modeling and increasing testing requirements for generators, which they believe would improve the ability to ensure generators that rarely are dispatched would be operational for future events such as the December 2022 winter storm.

The variability that led PJM to back away from a longer 50-year historical weather lookback displayed the sensitivity of PJM’s modeling, leading OPSI to recommend PJM justify its approach annually and develop a plan to use appropriate data selection going forward. The states opposed PJM’s proposal to retain the exemption that intermittent, storage and hybrid resources have from the requirement that generators enter the capacity market, which OPSI said raises market power concerns. Instead, the organization recommended that a future capacity market design align with all resources’ operating characteristics and require that all generation participate.

“Allowing certain exempt resources to retain Capacity Interconnection Rights will not allocate and properly ration costly and scarce transmission access rights to resources relied upon by customers to ensure reliability,” OPSI said.

American Electric Power, Dominion and Duke Energy Kentucky submitted a letter calling for a transitionary period for fixed resource requirement (FRR) entities to adjust to any new market design, arguing the potential for the changes to be effective for the 2025/26 BRA — scheduled for June 2024 — leaves them with little time to coordinate with state commissions and make necessary changes to their integrated resource plans or generation fleets.

The utilities requested the board include an expanded FRR transition mechanism of at least four delivery years and an off-ramp for new FRR entities for the first five years after they elect to go that route, maintain the physical penalty option for CP penalties and expand it to be applicable to all RPM capacity resources, and maintain the ability to net performance during a performance assessment interval. The letter also argues that any proposal should include recognition of the impact accreditation changes could have on state resource planning.

PJM’s proposed changes to resource accreditation were particularly worrisome to the utilities, which stated they could face a reduction in the rating of their resources amounting to as much as 30% with less than a year to make up for the lost capacity. Paired with PJM’s proposed changes to the penalties FRR entities could face if they fail to procure adequate capacity or do not perform during an emergency, the letter states FRR entities could face “unjust and excessive penalties” if they’re not provided with time to adjust to market changes.

“These changes, combined with the expedited nature of the CIFP-RA process, make it very difficult for FRR entities to understand what their underlying positions and obligations will be under the new construct, thus creating greater uncertainty and introducing additional risk,” the letter said.

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Stakeholder Soapbox: Beware of Government-driven Climate Policy

By Kenneth W. Costello

Climate change presents a daunting challenge for economists, political scientists and policymakers: It features a global shared resource (namely, the atmosphere) magnified by massive uncertainty over both physical and economic processes; everyone contributes to its cause, and everyone potentially bears the costs of its consequences.

Three policy challenges ensue: (1) taking collective action, where cooperation of countries is essential to achieve targeted reductions in greenhouse gas emissions, (2) incentivizing individuals and businesses to reduce their GHG emissions, and (3) identifying the preferred institutional arrangement — namely, markets versus government — to alleviate the damages from climate change.

climate policy

Kenneth W. Costello |

A major problem is that when one country benefits from initiating reductions in GHG emissions, other countries also benefit. The reality that controlling climate change in one country cannot deprive others of the benefits motivates individual countries to avoid paying for mitigation, creating the problem of what economists call free ridership.

Since changes in GHG emissions affect the entire world, any successful coordination would require virtual unanimity rather than just coalition building. But as past experience has shown, reaching mutual consent among multiple heterogenous countries is a Herculean task. (How many U.N. Climate Change Conferences have we had? I lost count.)

Policymakers confront the task of trading off the risk of doing too little to combat climate change with excessive spending or regulating. The ideal policy position on climate change depends critically on the size and likelihood of negative outcomes, considering the best available scientific and other fact-based evidence.

Reasonable people can disagree over the cost of an overly active climate strategy versus the cost of a passive one. Disagreement starts with the credibility of the scientific evidence. People may question the sureness of the scientific evidence. They may also have trouble distinguishing scientifically sound evidence from advocacy evidence.

Disagreement may then shift to the relevance of this evidence for public policy. Here, self-interest motives and ideology play key roles. People tend to adhere to their prior beliefs irrespective of the scientific evidence. These beliefs carry over to the relative costs they place on an overly aggressive climate policy relative to an overly passive policy. All of these factors contribute to the difficulty of reaching political consensus.

For example, the preferred strategy depends (among other things) on people’s risk aversion to the damage that climate change can cause. Some people may struggle more with an incorrect scientific conclusion that climate change has a high risk when in fact it has a low risk; the opportunity cost is in the form of excessive resources allocated to slowing climate change, which inevitably results in lower economic growth and other social costs.

Climate policy certainly falls into a space where government action could very likely have bad consequences. This is especially true for green subsidies for renewable energy and energy efficiency, which although widely popular likely fails a cost-benefit test.

Subsidies encourage rent seeking by special interests and allow policy makers to determine which technologies to champion. Subsidies for renewable energy have been especially attractive because of their claim to improve air quality and create new jobs, while their costs are concealed in the larger government budget. It is harder to sell the public on, say, a carbon tax whose costs are more visible and concentrated on consumers.

Economists consider subsidies for almost anything to be economically inefficient, usually politically motivated, and lasting too long. Their preference is to have the government reallocate funds for basic research. But, not surprisingly, political forces have given higher priority to existing clean technologies with their strong lobbyists than to potentially future ones.

Rent seeking in the form of exploiting government to gain favors tends to concentrate the benefits to these groups while spreading the costs to the general population. A good example is interest groups pressuring state utility regulators and legislatures to use subsidies funded by utility customers and taxpayers to promote energy efficiency, distributed generation, electric vehicles, and other clean-energy technologies.

This inevitably leads to cost subsidization, which (among other things) is unfair to both utility customers and taxpayers who do not benefit. Unfortunately, the evidence confirms that an increasing number of states have been at the vanguard of bad policies that have inflicted a regressive-tax-type wound on lower income people. The reason is that lower-income households spend a larger percentage of their incomes on electricity, and these policies tend to increase electricity prices. For the electric industry, an obsession with climate change threatens policy objectives long adhered to by state utility regulators.

But isn’t it also true that a fixation with climate change, bordering on irrational climate hypochondria, can deprive impoverished people, especially in less-developed countries, of the resources required for survival or progress? This makes little economic sense and reflects the insensitivity to the plight of poor people from those in wealthy countries absorbed with climate change and renewable energy, and the ridding of fossil fuels. Fossil fuels have been a vital factor in the economic growth of less developed countries. There is a serious “equity” problem here.

Relevant to climate action is also the intergenerational issue of whether people today should sacrifice under an aggressive climate policy to benefit people in the far-out future, who are likely to have a much higher standard of living. Some climate activists view anything less than an all-out effort to attack climate change as a social injustice.

In economics, public choice theory predicts that government, composed of bureaucrats and politicians, lacks the necessary information and the right incentives to pursue policies that are in the public good.

We see numerous real-world examples where actual public policies in all areas of society deviate far from what so-called “blackboard economics” would say is ideal. Such divergence typically results from information deficiencies, institutional realities, and the government’s incentive to serve its self-interest and appease special interests rather than the public good. Can we then expect any climate policy dominated by interest-group politics to be in the public good?  What we have seen up to now says no.

Either for ideological or monetary reasons, climate advocates want to shape future climate policy, and the sooner the better. Their self-interest motive benefits only themselves, not the broader public interest. Their vision of the future entails filling up their pockets (e.g., clean-energy vendors) or satisfying their followed doctrine (e.g., environmentalists). They have relentlessly lobbied politicians and bureaucrats at all levels of government for special favors. This reality by itself warrants nongovernmental options to address climate change.

Given the problems faced by government-driven climate policy — a particular one that I have mentioned is subsidies for clean energy — more attention should focus on measures that strengthen market signals for individuals to adapt to climate change. These measures may include adaptation based on the pricing mechanism, companies satisfying the demands of consumers and investors for clean products, and governmental assistance for basic research in clean-energy technologies (for instance, nuclear power, renewable energy, and hydropower) and climate engineering. Consumers and investors can reveal their preference for financial assets or products and services that explicitly account for climate change. They have done so already, and we should expect this development to proliferate in the future. But, so far, regretfully market-centric approaches have taken a back seat to government-driven climate policies.

We will surely see in the years ahead more political posturing in mitigating climate change. So much talk and money has been expended on government-driven climate policy. What have we gotten out of it? I would say probably very little in terms of global temperature – no more than a rounding error. Don’t expect things to improve in the future.

The bottom line: spending a lot of money on climate change with status quo policies will likely have a negative social return. The sooner we realize that, the better off we will be.

Kenneth W. Costello is a regulatory economist and independent consultant.

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ERCOT IMM Raises Concerns over Newest Ancillary Service

ERCOT’s Independent Market Monitor says the grid operator’s recent implementation of its first ancillary service in 20 years has nearly doubled the amount of required online reserves, resulting in “enormous” increases in market costs and shortage pricing when the market is long.

Carrie Bivens, the IMM’s vice president, told stakeholders Friday that procuring and deploying the ISO’s newest ancillary service (AS), ERCOT contingency reserve service (ECRS), has reduced supply and liquidity in the day-ahead market and “significantly” raised demand for AS products. That has resulted in inefficient day-ahead AS price spikes, she said.

“We’re seeing a disconnect between the operational realities and the pricing outcomes,” she said during a Wholesale Market Working Group meeting. “It’s also causing reliability issues, in our opinion, by increasing the challenges with managing congestion because fewer megawatts are available for scheduled dispatch to manage congestion … we’ve seen that on a few days you’re seeing a huge increase in market costs.”

Carrie Bivens, Potomac Economics | © RTO Insider LLC

AS services have incurred $1.56 billion in costs this year through August, Bivens said. ECRS, which began June 10, is responsible for almost 39% of those costs, or just over $608 million.

She said while the costs are substantial, they are much lower than the effects of removing the additional reserves from real-time market dispatch. Increasing online reserve procurements with ECRS “likely” raised the real-time market’s energy value by $8-10 billion in three months, Bivens said.

“Price spikes in the day-ahead market are not necessarily reflective of the underlying conditions,” she said. “The huge costs that we are really keying in on are the ones from [the] real-time market by removing those reserves. Taking megawatts that would have been available for energy dispatch and making them unavailable is reducing the supply available … that is causing this increase in real time energy prices, even though we have tons of reserves.”

The new AS is economically dispatched within 10 minutes of deployment, using capacity that can be sustained at a specified level for two consecutive hours. ECRS essentially meets the same reliability requirements that previously were met solely by responsive reserve service (RRS), the IMM pointed out.

ECRS has resulted in a 2,500-MW increase in online reserve procurements, moving the MWs behind the high ancillary services limit (HASL). Bivens says that has resulted in artificial pricing shortages when total reserve levels are high and a negative effect on congestion management, as more MWs needed to address congestion are reserved for ECRS or RRS.

She said the artificial tightness is “episodically mitigated” by the operators’ deployments, which interferes with day-ahead market decisions, whether to self-commit resources in real time and resource offers — all of which are based on expectations of real-time prices.

IMM staff arrived at the $8-10 billion figure by simulating the real-time energy market with reconstructed offer curves for lower ECRS procurements. Their analysis cleared the input MW quantity at the generation requirement’s original SCED execution. Once a baseline scenario was done, staff modeled incremental 25% releases of ECRS in subsequent scenarios and calculated energy cost reductions.

Real-time ECRS deployments were maintained so that none of its additional capacity was released if deployments exceeded the release percentage. The simulation did not model congestion, ramp limitations, controllable load resources’ dispatch or the power balance penalty curve.

“We wanted to show is this a small problem or is this a big problem?” Bivens said. “This is an order of magnitude type of analysis and what this is showing is that indeed it is a large problem.”

Jeff Billo, ERCOT’s director of operations planning, pushed back against Bivens’ presentation and the IMM’s call for a holistic review of ECRS, among other recommendations. He acknowledged inefficiencies and additional market costs but said ERCOT is getting the reliability it needs.

“When I look at the data that was presented, I don’t see anything that backs up those recommendations other than ancillary services are really expensive or they’re causing outcomes in the market that are really expensive. I don’t see any data showing that we’re getting more than we actually need,” he said. “I also don’t agree with the term artificial scarcity because this is a reserve product that we are buying, so it is meant to be held in reserve. It’s not artificial, it is on purpose. We are reasonably reserving megawatts that we may need for various conditions that may occur on the system.”

“I think we just want to make sure that you’re buying what you need to be reliable, and no more than that,” Bivens responded. “And also, I think we need to ask the question of the ECRS that we got this summer, ‘Was it worth $10 billion?’ That’s something that I think I would ask people to think about.

“A lot of these megawatts, particularly during the summer, they’re going to be online anyway,” she added. “All you’re doing, and why I’m calling it ‘artificial scarcity,’ is you’re taking megawatts that would have been online for energy and putting them behind the HASL. And that’s what’s causing the cost increase. It’s not that we’re getting more megawatts. It’s just how we’re treating them.”

The IMM recommends ERCOT reduce the ECRS’ two-hour duration requirement to a single hour to encourage more storage participation. Its other recommendations include:

    • Reducing ECRS’ frequency recovery MW procurement;
    • Removing the 2,800-MW floor on RRS;
    • Changing the non-spin error requirement from six hours ahead to three; and
    • Using 10-minute ahead net load errors for ECRS methodology.

The recommendations are based on the 2023 AS methodology and will be updated when ERCOT staff publishes its 2024 for the services, Bivens said.

The Texas grid operator launched ECRS in June. It was the first daily-procured ancillary service introduced to the market in more than 20 years.

ECRS’ development began as a protocol change, approved in 2019, designed to address forecasting errors from the increased penetration of renewable resources or to replace deployed reserves. The change also modified responsive reserve service to be primarily a frequency response.

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FERC OKs MISO Removal of Annual Reviews for Long-term Tx Projects

MISO is off the hook for having to conduct annual cost-benefit analyses of its major transmission projects, FERC has ruled.

FERC on Friday allowed MISO to cut the portion of its Tariff requiring it to conduct annual benefit reviews of its long-term transmission projects. The RTO still will conduct its more comprehensive triennial reviews (ER23-2478). The commission’s approval was effective Sept. 24.

FERC said it was persuaded the annual reviews “have become less useful over the years given the development of alternative sources of similar information.” The commission said it didn’t think the discontinuation of the reviews would affect project transparency in MISO.

In July, MISO proposed eliminating the four limited annual reviews required of it for long-term transmission projects. That will leave the RTO conducting two triennial reviews of projects following project approval. It said the move will “drive administrative efficiency for MISO, its stakeholders and regulators.”

According to MISO, removing the limited reviews will allow it to spend more time planning portfolios of other long-range transmission projects. It also said the annual reviews usually only uncover “minimal data changes” year-over-year and said info on transmission projects’ progress is available to stakeholders on its website, through its Transmission Expansion Plan (MTEP) quarterly status updates and contained in its variance analyses. MISO performs variance analyses on projects only when they materially change in cost, schedule or design from MISO approval.

MISO’s triennial review requires it to calculate economic benefits of major projects, such as congestion and savings and the ability for the RTO to carry a smaller amount of reserves. It also requires MISO to evaluate achieved public policy targets, like the amount of new renewable energy the line can bring to the system, and perform five-year historical examination of the line’s effect on the fleet mix, interconnection trends, energy prices, fuel costs and margin requirements.

On the other hand, the limited reviews required MISO to calculate the latest data available of the economic benefits and five-year historical trends.

The Organization of MISO States supported the pruning of reviews, saying its remaining reporting requirements are sufficient to stay up to date on transmission projects. However, the group of state regulators requested FERC order MISO to “consistently and accurately” update its long-range project dashboard and quarterly status reports on its MTEP portfolios to ensure they’re useful. OMS said MISO has been inconsistent in updating actual project costs and in-service dates, which limits regulators’ ability to question transmission developers’ cost containment efforts.

FERC, however, said the OMS concerns were beyond the scope of the proceeding and declined to address them. MISO said FERC should disregard the OMS request because it’s already working to upgrade its admittedly outdated MTEP project portal, the database it maintains for approved projects.

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NYISO Stakeholders Discuss Enhanced Regulations for Information Sharing

RENSSELAER, N.Y. — NYISO soon could significantly tighten its security and information protection requirements, according to a presentation given to stakeholders last week.

Troutman Pepper, an energy law firm, advised the Transmission Planning Advisory Subcommittee and Electric System Planning Working Group meeting that as digitization grows, enhancing NYISO’s critical energy and electric infrastructure information (CEII) protection has become increasingly important.

Kat O’Konski, an associate at Troutman Pepper, said, “there is a pressing need” to improve CEII requirements because both “physical and cyber assaults on the grid are at a record high.” (See Feds Charge Idaho Man in Dam Attacks; NERC’s Cancel Details Grid Threats to House Energy Subcommittee; DERs’ Deployment Leads to Increasing Cyber Threats.)

Troutman wants to toughen measures around NYISO’s data dissemination by requiring third parties working with and around the ISO’s supply chain to implement more stringent protocols for CEII sharing and access.

These enhancements include mandatory cyber-training for certain workforces and obtaining cybersecurity risk insurance, as well as recommending that sensitive data be stored in multiple geographically isolated data centers to provide an added layer of redundancy.

Troutman requested that its proposals to tighten NYISO’s security and information-sharing procedures be approved quickly but some stakeholders were skeptical about the proposed implementation timeline and whether the CEII protections were more restrictive than protective.

Doreen Saia, an attorney with Greenberg Traurig, said Troutman was unrealistic to expect its proposals could be approved before the end of the year, given the number of meetings and the upcoming holiday season, as well as considering the breadth of the proposal.

Stu Caplan, partner at Troutman Pepper, asked what a realistic timeline would be. Saia responded that her firm would need at least a month or more to review the requirements, but that multinational organizations likely would need even more time to comply with the requirements, particularly those related to geographic data storage.

Glenn Haake, vice president of regulatory affairs at Invenergy, concurred with Saia, noting how multinational companies might struggle with these requirements, particularly if the rules vary by country of origin.

O’Konski sought to mollify these concerns by noting how Troutman’s proposals are intended to create a single set of CEII standards applicable for everyone.

Kevin Lang, partner at Couch White, in reference to expanding the list of personnel required to obtain CEII clearance, said Troutman needs to consider that not every NYISO market participant has the same level of resources as transmission owners and to ensure its requirements are not preventing smaller businesses from accessing the ISO’s data.

There was a consensus on the need for enhanced CEII protections and no one opposed the measures outright, but stakeholders wanted to guarantee a balance between security and accessibility.

Troutman will return with a more detailed proposal and requested feedback be sent to either Caplan or O’Konski by Sept. 28.

System & Resource Outlook

NYISO updated stakeholders that the base case lockdown date for the biennial System & Resource Outlook report has been set for Oct. 15.

The base case serves as the foundational set of initial conditions, scenarios and assumptions used in the Outlook’s modeling.

The 20-year forecasting report examines how New York’s transmission system develops, performs, and responds to the state’s aggressive climate and energy legislation. (See “System & Resource Outlook,” NYISO Previews New York City Transmission Needs Assessment.)

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FERC Directs J.P. Morgan to Declare Affiliations of Two Holding Firms

FERC issued an order Thursday finding J.P. Morgan Investment Management qualified as an affiliate of Mankato Companies and IIF US Holding 2, through which it is tied to other firms, including El Paso Electric.

The order came after a Section 206 briefing process FERC started after consumer group Public Citizen questioned the investment bank’s ties to firms it said were not appropriately disclosed.

Public Citizen said the investment bank effectively controlled IIF, through Mankato and other subsidiaries. The two legal entities share employees and effectively let the investment bank make decisions on running IIF.

FERC found the relationship between J.P. Morgan Investment, IIF and Mankato was such that there is liable “to be an absence of arm’s length bargaining in transactions between them,” so it’s appropriate to consider them affiliates for the protection of investors and consumers.

The two firms share operations under an Investment Advisory Agreement and a Partnership Agreement, which delegate J.P. Morgan Investment broad duties to run IIF. A J.P. Morgan Investment employee sits on the board of directors of Onward Energy as a representative of IIF.

“We emphasize that in the market-based rate context, an assessment of affiliation is necessary to understand the relationships between entities to ensure that rates are just and reasonable, to protect against the exercise of market power and to protect customers from affiliate abuse that can result from affiliate transactions, regardless of the presence of fiduciary duties,” FERC said.

Employees of J.P. Morgan and J.P. Morgan Investment signed the partnership agreement and investor advisory agreement for both firms. That at least shows J.P. Morgan was empowered to execute documents that bind IIF into agreements, including agreements with the investment bank itself.

The investment agreement between the firms authorizes J.P. Morgan as investment adviser to “have full authority to undertake and perform any and all acts deemed necessary or appropriate by it in connection with the rights, powers and duties delegated to it.” The partnership agreement explains J.P. Morgan has the power to manage IIF’s business and affairs, to make business decisions, to act on its behalf and take any actions it deems appropriate.

“These rights and powers allow J.P. Morgan Investment to make virtually every major decision on behalf of IIF US Holding 2,” FERC said.

The commission directed Mankato to file a change in status and update its asset appendices to reflect J.P. Morgan Investment as an affiliate. The firm’s market power analysis will need to be updated to reflect the affiliation.

The order drew a concurrence from Commissioner James Danly, and a response to that from Chairman Willie Phillips.

Danly wrote to make clear that while he supports the outcome of the order, he takes issue with the majority’s reasoning. He argued concurrences should be the same as a dissent as a result.

“I disagree with the means by which we arrive at that conclusion,” Danly said. “I do not believe that we need to disclose privileged information to the extent we do to justify our conclusion. We could and should have been more measured.”

Phillips said concurrences amount to the opposite of a dissent and Danly cited no precedent supporting his view that concurrences should be treated that way on review by the courts.

“Commissioner Danly is, as ever, entitled to his opinion,” Phillips said. “I write separately to stress that I do not share that opinion and to underscore that Commissioner Danly is not stating the commission’s view on this issue. As Commissioner Danly correctly notes in his concurrence, it is our agency’s ‘institutional decisions — none other — that bear legal significance.’”

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ISO-NE Must Include Pumped Hydro in Inventoried Energy Program, FERC Rules

ISO-NE must include pumped storage resources in its Inventoried Energy Program (IEP), FERC ruled on Thursday, siding with Brookfield Renewable Trading and Marketing in the company’s complaint against the RTO (EL23-89).

The IEP is intended to compensate resources for storing extra fuel they otherwise would not procure during periods of winter reliability risk. (See FERC Approves Updates to ISO-NE Inventoried Energy Program.) The D.C. Circuit Court of Appeals ruled in 2022 the IEP cannot extend to nuclear, coal, biomass and hydroelectric resources because the program would not result in a change of their fuel storage behaviors.

Following the D.C. Circuit ruling, ISO-NE submitted — and FERC approved — a version of the IEP which excluded the specified resources, including pumped storage. Brookfield Renewable, which operates a 633-MW pumped hydro storage facility in western Massachusetts, filed a complaint over the exclusion of the resource type in August.

In FERC’s ruling on Thursday, the commission said the D.C. Circuit ruling does not preclude the inclusion of pumped storage because these facilities fall under the category of electric storage facilities, which are allowed to receive payments in the IEP.

“As the ISO-NE tariff currently permits battery storage electric storage facilities to be eligible to participate in the Inventoried Energy Program, it is unduly discriminatory to prohibit pumped storage electric storage facilities, which similarly store energy to later inject the energy into the system, from being eligible to participate in the Inventoried Energy Program and receive those payments,” the commission wrote.

FERC wrote that IEP payments likely would incentivize pumped storage facilities to alter their behavior and boost reliability in the region.

“Allowing pumped storage electric storage facilities to be eligible to participate in the Inventoried Energy Program, similar to other electric storage facilities, can alter their incentives and thus their behavior by providing an incremental financial incentive to store energy,” the commission wrote in the Sept. 21 ruling.

FirstLight Power and the New England Power Generators Association both submitted comments in August supporting Brookfield’s complaint, while a group of consumer-owned power companies opposed it.

The consumer-owned power companies argued the complaint was attempting to relitigate previous findings and that including pumped storage in the IEP would not result in more stored energy.

“Brookfield’s complaint fails to show that any system-wide incremental energy production would result from extending the IEP’s incentive compensation mechanism to pumped storage hydro facilities,” the group wrote.

In its complaint, Brookfield argued pumped storage operates in the same way as any other type of electric storage.

“The fact that one ESF [electric storage facility] may use pumped storage technology and another ESF may use a chemical battery is irrelevant because they both are able to provide the identical winter reliability service through the IEP,” Brookfield wrote. “Because all ESF technologies operate under the same economic principles, the same incentive exists for all ESFs to provide reliability service through the IEP.”

ISO-NE told FERC it did not oppose the inclusion of pumped storage in the IEP but said it believed the D.C. Circuit ruling prevented their inclusion in the program.

“The D.C. Circuit’s Belmont decision did not differentiate between pondage and pumped hydroelectric resources, but instead simply indicated that ‘hydroelectric’ resources must be excluded from the IEP,” ISO-NE wrote. “The Belmont court did not provide any exception for pumped hydroelectric resources to participate in the IEP as ESFs.”

ISO-NE had said it needed a FERC order by Sept. 22 to include pumped storage in the IEP for the upcoming winter.

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NJ’s Push Toward Clean Cars Rule Sparks Vigorous Debate

New Jersey’s planned adoption of California’s Advanced Clean Car II (ACC II) rules stirred a heated exchange Thursday as business groups argued the state is far from ready for a sudden surge in electric vehicle use and environmentalists argued climate change threats demand the rules be in place by 2024.

Groups representing car dealers, gas station convenience stores, the petroleum industry, businesses and other sectors at an online public hearing on the rules organized by the New Jersey Department of Environmental Protection said mandating EV sales would disenfranchise numerous low-income consumers who already struggle to buy a car.

The three-hour online hearing, the only one scheduled, drew more than 40 speakers. It came as ACC II supporters are urging the administration of Gov. Phil Murphy (D) to have the rules in place by the end of the year so they can impact the 2027 model year. The eight-week-long public comment period will end Oct. 20. (See NJ Sets Advanced Clean Cars II Proposal in Motion.)

ACC II calls for a steady increase in EV sales as a portion of all new light-duty vehicle sales, until they account for 100% in 2035. But, business groups argue, that mandate would push up the price of used cars as consumers looked for a cheaper alternative to the higher-priced clean energy-fueled vehicle, framing the rules as a big government intervention in what should be a decision by the market.

“New Jersey and all the other ACC II states will be a 100% EV sales market when consumers want to buy only EVs, not when government mandates it,” said Jim Appleton, president of the New Jersey Coalition of Automotive Retailers (NJCAR).  “Frankly, we believe this plan will frustrate and cause a consumer backlash that will slow our roll to an EV future, not accelerate.”

He argued that if consumers face a mandate for sales increases when they find the prices high, or access to the charging infrastructure unreliable, they will simply “hold on to their older cars longer or opt into the used car market which is not regulated by ACC II.”

Other opponents argued the state’s grid is not ready to provide the amount of electricity needed to serve hundreds of thousands — perhaps millions — of EVs. And they questioned the impact on carbon reduction, saying much of the electricity still might be generated with natural gas.

‘Shackles of Saudi Arabia’

Supporters of the rules — including EV manufacturers, health care professionals and some businesses — made up the majority of speakers at the hearing, however. They argued that recent extreme weather events — including the hottest summer on record — show the state needs to rapidly stoke EV adoption.

Pam Frank, CEO of ChargeEVC, a nonprofit coalition that promotes EV growth, said that with 123,000 EVs on the road in June, the state still is far from its goal of 330,000 EVs by 2025. A draft Strategic Climate Action Plan released by the DEP last week said the state would need 4.5 million light-duty EVs by 2035 to meet the state’s clean energy goals, accounting for 73% of all light-duty vehicles.

“Allowing the markets to set policy for the kinds of cars we drive will just not get us where we need to be as quickly as possible,” Frank said. “This is not a ban on [internal combustion] engine vehicles,” she said. She added most New Jerseyans buy used vehicles and that market would continue regardless of the new rules.

Supporters of ACC II argued EV prices already are declining and consumers would benefit because powering electric vehicles is cheaper than running on fossil fuel.

“Let me state emphatically that there’s nothing worse for New Jersey’s businesses than high oil prices,” said Sean Mohen, executive director of Tri-County Sustainability Alliance, which promotes sustainability in South Jersey. He argued that oil production cuts by Russia and Saudi Arabia had pushed up gas prices to their highest level this year, and demonstrated the need to focus more on electricity.

“It’s time for America and New Jersey to throw off the shackles of Saudi Arabia for both climate and business reasons,” he said.

Accounting for Health Costs

As adopted by California last August, ACC II requires car manufacturers to provide an increasing percentage of zero-emission vehicles (ZEVs) for sale each year. It defines zero-emission vehicles as battery-electric, hydrogen fuel cell or plug-in hybrid.

The regulation starts with a 35% ZEV sales requirement for model year 2026, increasing to 68% in 2030 and reaching 100% in 2035. ACC II also includes increasingly stringent standards to reduce tailpipe emissions of gasoline-powered cars and heavier passenger trucks.

State officials announced the process for adopting ACC II in February, setting off a vigorous campaign between supporters and opponents over the rules’ merits. A coalition of 100 businesses two weeks ago submitted a letter to state Senate President Nicholas Scutari and Assembly Speaker Craig Coughlin, both Democrats, urging them to reject the rules and instead take legislative action on the issue. (See NJ Businesses Demand Halt to EV Sales Promotion Rules.)

If New Jersey approves the rules, it would be the ninth state to do so. Maryland last week joined Massachusetts, New York, Oregon, Vermont, Virginia and Washington in adopting the California rules. (See Maryland Moves Ahead with Advanced Clean Car and Truck Rules.)

Richard Lawton, executive director of the New Jersey Sustainable Business Council, which represents companies seeking a sustainable economy, said the state should be clear about the motives of some opponents to ACC II.

“EV technology represents a competitive threat to industries and companies who have a vested interest in maintaining the monopoly power of fossil fuels, and [they] are using their economic and political power to raise as many barriers to entry as possible,” he said.

“This is perfectly rational for them, but not for the rest of us,” he said. “Top economists have called climate change the largest market failure in history. So relying on market forces alone to address this market failure would be self-defeating, and frankly, naive.”

Rural Difficulties

Several supporters focused on the health benefits of EVs, saying ACC II especially would improve the quality of life for minority communities that have long suffered the effects of vehicle pollution in urban areas and neighborhoods next to highways.

“Air pollution resulting from transportation in New Jersey is first and foremost a health issue, and discussions of costs that don’t include health costs is imbalanced,” said Dr. Elizabeth Cerceo, chair of health and public policy for the American College of Physicians New Jersey. “When this is factored in, the social and mortality cost of carbon, it outweighs the cost of EV transition. The supposition that the market should dictate the decision ignores the lives lost and the illness caused by fossil fuel pollution.”

But Mary Jo Foley, speaker for the Rural and Agriculture Council of America, argued that adopting ACC II would unfairly and excessively impact the nearly 850,000 residents of the state who live in rural areas.

“New Jersey’s rural and agricultural communities will be hardest hit by this proposal,” she said. “Internal combustion engine vehicles are a necessary part of everyday life for rural Americans, where it’s not an easy task to find an electric vehicle charging station.”

She added that “there will be massive increased demands in the New Jersey power grid, which also likely means higher prices for New Jersey electricity consumers who already pay some of the highest rates in the country.”

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‘Challenging’ Grid Conditions Led to CAISO’s Summer Emergency Alerts

CAISO’s issuance of energy emergency watches and alerts on three days in July came under conditions that mirrored those during California’s September 2022 heatwave, officials said.

Several “challenging evenings of grid operations” led the ISO to issue a Stage 1 energy emergency alert (EEA 1) on July 20, followed by EEA watches on July 25 and 26, CAISO CEO Elliot Mainzer told the Board of Governors on Thursday.

The period was marked by high demand from a record-setting heat wave in the Southwest, Mainzer said, while demand was “high but not excessive” in California and hydro conditions in the Pacific Northwest were below average.

In the Southwest, record-breaking temperatures included an average high in Phoenix of 114.7 degrees for the month of July, compared to the previous record of 109.8 degrees in July 2020.

“In many ways, conditions were the mirror image of what we saw last September when California was on the edge with a historic heat wave, and other regions were able to supply us with large quantities of power to help maintain reliability,” Mainzer said in a report to the board.

So far, the three alerts are the only times CAISO triggered the emergency alert system this year, Mainzer said. No Flex Alerts — in which consumers are asked to voluntarily conserve energy — have been issued in 2023.

In addition to Mainzer’s report to the board, CAISO also released last week a summer market performance report for July that goes into more detail on the EEA events. A Sept. 27 meeting has been scheduled to discuss the report.

July 20: EEA 1

Energy emergency alerts range from EEA 1, which includes calls for conservation measures and demand response, to EEA 3, in which rotating blackouts may be ordered. An EEA watch is a preliminary step before CAISO declares an alert.

When an energy emergency alert or watch is issued, CAISO has access to additional resources, such as the emergency load reduction program (ELRP), in which electricity customers are paid to voluntarily reduce their demand, and the state’s Strategic Reliability Reserve.

CAISO issued an EEA 1 at 7:30 p.m. on July 20 in response to “rapidly evolving grid conditions observed during real-time operations,” according to the monthly performance report. The July 20 conditions came up relatively unexpectedly, in contrast to grid events in 2020 and 2022 that were projected far in advance, the report said.

One and two days ahead, the market seemed able to meet the projected demand for July 20, although with thinning capacity margins.

But as the system approached net load peak on July 20, “the anticipated supply did not fully materialize,” the report said.

CAISO said reasons for the decreased supply included resource outages and derates; fewer imports due to potential fire impacts; and resources not dispatched due to congestion.

At the same time, demand was high from the desert Southwest, which experienced record-breaking high temperatures this summer. As a result, net imports were reduced during the net load peak.

Another issue was that a display of resource availability overestimated the amount of resource dispatch capability available — mostly due to storage resources that were providing multiple services, CAISO said.

As a result of the EEA 1, CAISO deployed resources from the ELRP. Normal operations resumed around 8:30 p.m.

July 25 and 26: EEA Watch

Factors similar to those that occurred on July 20 led CAISO to issue an EEA watch on July 25, effective at 7:30 p.m.

The ISO said it was seeing high external demand, wildfire threats to transmission, and the loss of about 2,000 MW of California resources “due to outages between the day-ahead and real-time markets.”

During peak hours, congestion on the Path 26 transmission lines made it difficult to send supply from the northern part of the system to Southern California, where it was still hot.

Another EEA watch was issued for July 26, from 6 to 10 p.m.

The report also discussed the flexible ramping product used by the real-time market. The EEA 1 on July 20 was sparked by a ramping shortfall as solar resources went offline in the evening hours.

The ramping product doesn’t procure capacity in response to unexpected outages or loss of imports, and so it had limited success addressing emerging uncertainty issues during the July events, CAISO said.

September 2022 Heat Wave

This year’s highest peak demand so far was 43,545 MW on July 25 at 6:27 p.m., well below the record peak of 52,061 MW on Sept. 6, 2022, during last year’s California heat wave. CAISO declared an EEA 3 that day but rotating blackouts were avoided after the governor’s Office of Emergency Services sent out a text alert at 5:45 p.m. urging consumers to conserve electricity.

Within 20 minutes, demand plunged by 2,385 MW and blackouts were averted. (See CAISO Reports on Summer Heat Wave Performance.)

Overall, operational conditions this summer have been “significantly less strained” compared to last year, CAISO said.

The state has been better positioned in terms of resource adequacy because of a record snowpack and strong hydro production, along with the addition of significant amounts of generating and storage resources.

Mainzer said August was another month with “a set of interesting conditions West-wide.” CAISO expects to release a market performance report for August next month.

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FERC Approves PJM Cost Recovery for NERC Penalty

FERC ruled last week that PJM can go to its customers to recover a $140,000 penalty leveled against the RTO this year by ReliabilityFirst, with Commissioner James Danly “reluctantly” concurring but calling for an investigation into PJM’s reliability violations and “manifest failures” to ensure reasonable electricity rates (ER23-2327).

PJM agreed to the penalty as part of a settlement with RF approved by FERC in April over several violations of NERC reliability standards — some at the Quad Cities and Dresden nuclear plants in Illinois, and others stemming from coordination issues at transmission facilities owned by FirstEnergy Utilities (NP23-13). (See PJM Hit With $140K Penalty for NERC Violations.)

According to a guidance order issued by FERC in 2008, RTOs and ISOs may “request recovery of penalty costs by spreading those costs among their members and/or consumers on a case-by-case basis.” Such requests must meet several criteria to be eligible for commission approval, including:

    • Whether the RTO or ISO involved had a compliance program in place.
    • Whether the violations were due to intent or gross neglect.
    • Whether management was involved in the violations.
    • The ability of the organization to pay the penalty.
    • The fairness of the RTO’s or ISO’s proposed assessment mechanism.

On June 30, PJM requested that FERC approve the recovery of the $140,000 RF penalty from its customers. The RTO explained that while it previously would have paid penalties from its administrative cost recovery rates, a change to its tariff in January 2022 meant the rates would no longer be “sufficient to absorb penalty costs.”

PJM claimed its proposed recovery was consistent with the criteria in FERC’s 2008 guidance order, noting that it possesses “a robust internal compliance program,” that all the violations were inadvertent and no harm to the grid resulted, and that management was not involved in the violations. The RTO said its proposal would allow “a broad allocation of the costs,” with a low impact on individual consumers; according to PJM, if recovered in a single month, the resulting additional cost to consumers would be around a fifth of a cent per MWh.

Public Citizen objected to PJM’s request, stating that putting the cost of the penalty on consumers would be “unjust and unreasonable. Instead of recovering the cost from consumers, the consumer advocacy group suggested that “PJM executives and PJM’s Board of Managers should be financially responsible for the penalties.”

This approach would be consistent with a FERC ruling last year against ISO-NE over construction delays at a Boston-area generating plant, Public Citizen said. In that case, ISO-NE agreed to a $500,000 civil penalty that was paid for through a reduction in executive compensation. (See FERC Investigation Faults ISO-NE in Capacity Market Fraud.)

PJM in turn pushed back on this suggestion, pointing out that the 2008 order on cost recovery was not applicable to the ISO-NE violation, which did not concern recovery of a NERC penalty. Furthermore, PJM said, FERC did not require ISO-NE to pay its penalty from executive compensation; the ISO made that decision on its own. The RTO reiterated that its proposed recovery mechanism is valid under the 2008 order and suggested Public Citizen has a problem with the order itself, not with PJM’s use of it.

FERC sided with PJM on the applicability of its 2008 order and said commissioners were “not persuaded” by the arguments of Public Citizen. The commission said that because PJM had “adequately addressed the factors identified by the guidance order,” it would grant the RTO’s request for cost recovery, effective Aug. 30.

But commissioners’ reactions to the decision were mixed, as Danly’s concurrence demonstrated. While the commissioner agreed PJM had “met its relatively light burden” of proof regarding its ability to recover costs, he argued in his filing that not only does the RTO have a history of “undercutting or dismantling core market design principles essential for just and reasonable rates,” the case makes clear that “PJM also is not very good at reliability.”

“I would treat PJM like the public utility that it is and … investigate PJM’s manifest failures to ensure or at least advocate for just and reasonable rates — and now to also investigate whether PJM is complying with existing reliability rules,” Danly said. “The commission should not hesitate to enquire whether a public utility serving as [an RTO] should continue in this critical role when rates and reliability failures suggest it is not doing very well.”

Danly suggested that the commission has authority to conduct such an investigation under Section 206 of the Federal Power Act. Although FERC has not taken this action on its own, Danly pointed out that “any entity with standing” could file a case, and wondered if this would “have more of an effect … than a $140,000 penalty that we pass through to ratepayers.”