FERC on Thursday approved the full retirement of four NERC reliability standards and the modification of five others, in the name of “[enhancing] the efficiency of the reliability standards program.” The updates will result in the retirement of 18 reliability standard requirements overall (RM19-16, RM19-17).
The four standards to be retired in their entirety are:
FAC-013-2 — Assessment of transfer capability for the near-term transmission planning horizon;
NERC originally called for the retirement of 77 requirements in a Notice of Proposed Rulemaking submitted in January. (See “NOPR to Retire Requirements,” NERC Reliability Standards Get FERC Approval.) The requirements were found under NERC’s Standards Efficiency Review Project to “either provide little or no reliability benefit, [be] administrative in nature, or relate expressly to commercial or business practices; or are redundant with other reliability standards.”
FERC gave preliminary approval to 74 of the proposed retirements in January; however, decisions on two — FAC-008-3 Requirements R7 and R8 — were postponed, on the grounds that some elements did not appear to be redundant. In its final decision, the commission said it was “satisfied with NERC’s justification” for retiring R7 but “not persuaded” that retiring R8 is appropriate. Therefore, FERC remanded the proposed FAC-008-4 to address its concern over the remaining requirement.
The commission’s January NOPR also ordered the remanding of Requirement R2 to the proposed VAR-001-6; the requirement would “[require] transmission operators to schedule sufficient reactive resources to regulate voltage levels under normal and contingency conditions.” NERC decided at its February board meeting to withdraw VAR-001-6, leaving the currently effective VAR-001-5 in place and rendering moot the proposal to retire the requirement. (See “Other Approvals,” NERC Board of Trustees/MRC Briefs: May 14, 2020.)
MOD A Decision Deferred
The remaining 56 requirements constitute the entirety of NERC’s so-called MOD A standards, comprising the following:
MOD-001-1a — Available transmission system capability
FERC gave its preliminary approval of these standards’ retirement with the intent of replacing them with the North American Energy Standards Board’s (NAESB) Standards for Business Practices and Communications Protocols for Public Utilities, which the commission voted to adopt in February. (See FERC Backs Latest NAESB Rules.)
Because the commission is still accepting comments on the NOPR, it will defer decision on the MOD A standards until it has had time to assess industry input.
Texas RE COO Jim Albright, who will become CEO effective Jan. 1 | Texas Reliability Entity
“I am honored and humbled that the Board of Directors has selected me to be the next president and CEO for Texas RE,” Albright said in a statement provided to ERO Insider.
“We have an incredible team here at Texas RE, and I look forward to working with them and our partners at NERC, the other regions and the [Texas Public Utility Commission] as we tackle the rapidly evolving challenges presented by the modern power industry,” he said. “Ensuring electric reliability for Texans is not just a mission statement to me; it is my passion, and I am proud to be able to serve the people of Texas every day.”
The Texas RE is ERCOT’s regional entity and serves as the PUC’s reliability monitor for the ERCOT region. In his seven years as COO, Albright led Texas RE’s Compliance Monitoring and Enforcement Program and the reliability monitor department, and he chairs NERC’s Align Project, the largest implementation in its history.
“Jim has the knowledge and experience to lead Texas RE, where he has been a strong voice for [its] focus on reliability,” NERC CEO Jim Robb tweeted.
Texas RE Chair Fred Day said the board conducted a “very thorough” search for Lanford’s replacement and that the entity is “very fortunate to pass the baton of executive leadership to Jim Albright.”
“Jim was clearly the most capable of building upon Texas RE’s many successes while also providing a fresh vision for the organization’s future,” Day said. “He’ll provide a strong voice for our region at the NERC level while continuing to pursue innovative ways to communicate with our stakeholders and ensure electric reliability for all Texans.”
Albright was previously deputy executive director for the PUC, where he spent more than 15 years.
Seeking “a better understanding of the risks to bulk electric system reliability posed by … entities identified as risks to national security,” FERC on Thursday issued a Notice of Inquiry regarding reliability risks posed by BES equipment originating overseas (RM20-19).
The NOI seeks comments from utilities on:
the extent of the use in BES operations of equipment and services provided by entities identified as risks to national security;
the potential risks to BES reliability and security posed by such equipment and services;
what mandatory actions by the commission might mitigate those risks;
strategies the entities have implemented or plan to implement to address such risks, in addition to compliance with CIP standards; and
other methods the commission may employ to address this matter.
FERC’s NOI was formulated in response to President Trump’s executive order in May declaring a national emergency regarding foreign threats to the BES and restricting purchase of BES equipment by federal agencies, citizens and companies from suppliers suspected of connections with hostile nations. (See Trump Declares BPS Supply Chain Emergency.)
NERC responded to the order in July with a Level 2 alert seeking data on the presence of foreign-provided equipment in the BES, while at the same time, the Department of Energy issued a request for information on utilities’ practices for identifying and mitigating supply chain vulnerabilities. (See NERC Issues Level 2 Supply Chain Alert.) At FERC’s meeting on Thursday, Chairman Neil Chatterjee said the commission felt obligated to keep itself informed to the same level as other agencies.
“Although the executive order did not include any directives to this commission, I believe it is incumbent on us as the agency overseeing the reliability and security of the grid to fully understand these risks and take appropriate action,” Chatterjee explained.
Huawei, ZTE Prominent Concerns
Given their widespread use in BES-connected computer systems, Chinese hardware manufacturers Huawei Technologies and ZTE figure prominently in the NOI. The companies, which like other Chinese hardware makers are alleged to cooperate with China’s security services, have been viewed with concern by U.S. policymakers for some time. Sen. Angus King (I-Maine) asked NERC CEO Jim Robb last year whether he knew if any utilities had equipment manufactured by Huawei or ZTE in their systems, with Rob admitting he did not. (See Senators Call for Urgency on Energy Cybersecurity.)
Huawei headquarters in Shenzhen, China | Brücke-Osteuropa
However, Commissioner Richard Glick emphasized that FERC’s concern “goes further than” Huawei and ZTE, and that respondents should consider threats from a wider range of companies and countries, “including companies with ties to Russia and Iran.” He also noted that despite the frequent mentions of Huawei and ZTE, the NOI does not focus solely on hardware. Glick urged utilities to consider “software provided by entities with connections to adversaries” as equally dangerous and to give it due consideration in their responses.
Comments on the NOI are due 60 days after its publication in the Federal Register, with another 30 days for reply comments.
Western Energy Imbalance Market (EIM) stakeholders broadly support a proposal that would significantly expand the EIM Governing Body’s approval authority and grant it a “more collaborative” relationship with CAISO’s Board of Governors.
The plan, part of a broader straw proposal released by the EIM Governance Review Committee (GRC) this summer, would extend the Governing Body’s voting rights to cover any CAISO initiatives that impact the EIM and create a concept of “joint authority” with the ISO board.
EIM stakeholders strongly endorsed the thrust of the GRC’s proposal in comments during a virtual meeting Tuesday while pressing for more details regarding the shared authority.
Active and pending participants in the Western EIM | CAISO
The straw proposal states that EIM stakeholders seek “a more ‘bright line’ or at least [a] less complex and more objective set of rules for identifying those matters where the Governing Body has approval authority.”
Still, support for the idea is colored by uncertainty over how joint authority between the two rulemaking bodies will play out in practice, especially when they disagree over Tariff changes to be filed with FERC.
Under the EIM’s existing charter, which falls within CAISO’s Tariff, the Governing Body enjoys “primary” voting authority over rulemakings specific to the EIM and plays an “advisory” role to the Board of Governors regarding ISO rule changes that also impact the EIM.
That arrangement has sufficed under current circumstances in which the EIM and CAISO markets only intersect through real-time operations. But the overlap between the two markets is set to broaden with the proposed implementation of the extended day-ahead market (EDAM) in the EIM, expanding to include rules covering transmission use, congestion revenues, ancillary services, greenhouse gas accounting, convergence bidding and new market power mitigation mechanisms. (See CAISO Proposal Sets Course for EIM Day-ahead.)
“If EDAM is implemented, the Governing Body approval authority would be further expanded to include any proposed changes to the design or market rules governing the CAISO’s day-ahead market,” the straw proposal states. “The GRC also recommends that the EIM Governing Body be provided decision authority over any EDAM market design, thereby formally recognizing CAISO management’s current proposal in the ongoing EDAM initiative to bring the EDAM market design to both the board and the Governing Body for their joint approval.”
‘Jump Ball’ Fear
Matt LeCar, a principal with Pacific Gas and Electric, voiced concerns about a joint authority plan provision that would allow the EIM and CAISO to submit competing Tariff filings with FERC when they reach an impasse over the final project.
“We’re concerned, first of all, that may not be how FERC wants to participate in this process. Typically, FERC is dealing with issues that have already been resolved in a regional transmission organization or independent system operator,” LeCar said. “We’re really punting issues to FERC to decide that are more properly adjudicated among stakeholders within the West.”
LeCar said PG&E also worries that CAISO would not be appropriately staffed to defend both points of view before FERC. “We have a hard time seeing how you would segregate and put in place firewalls between types of staff working on one side versus the other.”
Jennifer Gardner, Western Resource Advocates | EIM Governance Review Committee
GRC member and Western Resource Advocates attorney Jennifer Gardner, donning her hat as a representative of the Western Grid Group and the NW Energy Coalition, expressed similar reservations about the provision.
She pointed to ISO-NE and PJM, where the RTO and stakeholder groups can file competing “jump ball” Tariff revisions. Some of those proceedings have resulted in FERC rejecting both proposals and instead creating its own “Frankenstein” version that includes elements of each, Gardner said. “We were just concerned with the uncertainty that this creates, and we really wanted any type of competing filings to be avoided wherever possible.”
David Rubin, NV Energy | EIM Governance Review Committee
“The preference here is for the stakeholder process here in the West to come up with a sort of a joint proposal,” said NV Energy Federal Energy Policy Director David Rubin, speaking for the 18 current and future EIM entities. Rubin was skeptical of the proposal’s plan for resolving deadlocks through an “iterative” process in which Governing Body and board members convene to discuss objections to a filing, then send it back to CAISO staff for further development before convening another stakeholder process designed to address remaining concerns.
“The challenge that we felt was that going back that second time certainly adds half a year to an already [one-]year, two-year process, and there are times where a market participant feels that the design becomes unjust and unreasonable and they bring it to FERC’s attention anyway,” Rubin said.
Meg McNaul, an attorney representing CAISO’s “Six Cities” municipal utilities (Anaheim, Azusa, Banning, Colton, Pasadena and Riverside), said that while her clients support the joint authority provision, they also think the decisional authority of the CAISO board should be “preserved” because participation in the ISO markets is not voluntary for entities located within its balancing authority area.
McNaul agreed with PG&E’s recommendation for a “reversionary approach” to restoring the board’s decisional authority if a large number of EIM participants opt to withdraw from the voluntary market.
“I think the topic of a reversionary interest is one that’s worth pursuing,” McNaul said.
Lone Skeptic
Chloe Lukins, program manager for the California Public Utilities Commission’s Public Advocates Office, represented the lone voice of dissent on the call, opposing the joint authority model because EIM membership is voluntary and members are not required to pay CAISO’s grid management charge, which largely funds the ISO’s operations.
“If the model does go through, it should be explained how it will be paid for,” Lukins said.
“Is there a presumption that there will be an additional cost to California, and, if so, can you elaborate at all about where you see those cost arising?” Governing Body member Doug Howe asked.
“I think that’s what we would like some clarity on … providing some more information if it will cost more. If it doesn’t, if you could provide that information, that would be good, too,” Lukins said.
Heat waves and capacity shortfalls in August and September have slowed an effort by the Western Energy Imbalance Market (EIM) to expand from a real-time interstate trading forum to a day-ahead market, CAISO and EIM entities told the market’s Governing Body at its Wednesday meeting.
The extended day-ahead market (EDAM) initiative is moving forward with a straw proposal on topics including resource sufficiency and transmission use. Comments had been due Sept. 10, but CAISO extended the deadline by two months to Nov. 12 at the request of stakeholders, said Mark Rothleder, vice president of market policy and performance.
“I think that’s a fair and good approach because I think people should factor in and consider the learnings of the August and September events,” Rothleder said. The extension is “providing everyone, including the ISO, time to consider [those] events.”
The EDAM initiative, one of CAISO’s highest priorities, is divided into three “bundles” of topics that the ISO is addressing in succession through next year. The market is expected to go live in 2024. (See CAISO Proposal Sets Course for EIM Day-ahead.)
“It’s very timely that we’re talking about resource sufficiency,” Rothleder said of the initial set of topics. “I think there is a nexus between resource adequacy discussions, both in California and across the West, that I think do come together in an important way in the resource sufficiency discussion in bundle 1 of this topic.”
| Ready.gov
The EIM includes 11 members across the West, with 10 more set to join in the next two years. The newest members are Seattle City Light and Arizona’s Salt River Project. On July 3, the EIM surpassed $1 billion in benefits for its members since its launch in 2014.
Jim Shetler, general manager of the Balancing Authority of Northern California, an EIM participant, spoke on behalf of all EIM entities about tapping the brakes on EDAM.
“We know there’s a lot of evaluation going on about the heat wave events of August and September,” Shetler said. “As these issues are being discussed and evaluated, we’ve been hearing some comments made by some parties about ‘the utilities are relying on exports from others too much’ and whether there’s a need to become more independent and self-sufficient.”
CAISO was faulted by some for its reliance on out-of-state exports to meet its evening peak demand, an apparent cause of the shortfalls and outages this summer.
The EIM entities support a robust resource adequacy program and a strong resource sufficiency test that applies the same metrics to all participants, Shetler said.
“However, we equally recognize that collaboration across the West is absolutely necessary in order for the region to reliably and efficiently manage the changing resources with the ever increasing variable renewables and decreasing dispatchable resources,” Shetler said.
The EIM was a first step in greater regional collaboration, he said. The EDAM is the logical next step, and EIM entities support the day-ahead market moving forward.
“We do not want to lose the momentum that has been established,” but the heat waves and blackouts have shown potential resource deficiencies and economic issues that could impact the EIM and EDAM, Shetler said. Taking time to address the issues will ensure an EDAM design “that meets the needs of all the market participants,” he said.
Governing Body member Robert Kondziolka asked Shetler if EIM entities are looking into the shortfalls and could brief the Governing Body on their findings.
“We’re in the middle of looking at what each one of the EIM entities have experienced as a result of the August and Labor Day weekend heat waves,” Shetler said. “We’re trying to summarize [the findings]” and plan to update the ISO and EIM once the analyses are complete, he said.
More than 150 industry representatives, state officials, legal scholars and analysts attended the 35th annual Independent Power Producers of New York (IPPNY) Fall Conference on Tuesday to discuss resource adequacy, carbon pricing and emissions limits, as well as the broader need to address social and environmental justice.
IPPNY President and CEO Gavin Donohue released a set of six principles to guide members on their varied approaches to the transition to renewable energy resources. Reliability comes first, followed by the need to use markets to achieve decarbonization, electrify the transportation and heating sectors, develop needed transmission infrastructure, diversify fuels and technologies, and examine economic impacts.
“At some point in the near future, the question of New York’s reliability — generators’ ability to perform with quick, fast-starting, environmentally responsible units — is going to collide with the state’s public policy goals,” Donohue said.
Following is some of what we heard at the virtual meeting.
State Leadership
Ali Zaidi, chair of climate policy and finance in the office of Gov. Andrew Cuomo, highlighted three new initiatives this year to improve administrative efficiency and speed up the pace of the clean energy transition.
“The first is significant reform to our approach to permitting renewables within the state. You will be seeing soon proposals for how those changes get made here just a few months after the passage of the [siting] law,” Zaidi said.
The Office of Renewable Energy Siting the following day proposed draft regulations for permitting new wind and solar energy projects, as directed by the Accelerated Renewable Energy Growth and Community Benefits Act included as part of this year’s state budget.
Second is the governor’s “build-ready” initiative whereby the New York State Energy Research and Development Authority (NYSERDA) will prepare existing or abandoned commercial sites and brownfields to bundle with renewable energy contracts to provide de-risked package deals for private developers.
And third is the effort to speed up transmission infrastructure permitting and construction under the Public Service Commission’s grid study program, Zaidi said. (See NYPSC Launches Grid Study, Extends Solar Funding.)
“We know that if we want to decarbonize the entire economy, we need to help the grid reach further and deeper into the economy; specifically that means electrifying a greater share of the economy year over year,” he said. To that end, the governor this year launched an initiative to invest $1.5 billion in preparing the infrastructure to support electric vehicle charging stations, he said. (See NYPSC Approves $700 Million for EV Chargers.)
Asked what the administration’s thinking is on the upcoming carbon pricing conference at FERC and how it fits in with the state’s future, Zaidi said the technical conference would focus on state-of-the-art methods for evaluating the social costs of carbon and the implications for the power sector.
“Those are important conversations to have … and over the summer, we have proposed draft regulations on the social cost of carbon, which is going to be important in thinking about how those social costs are shaping decisions within state agencies,” Zaidi said.
Social Justice
The Climate Leadership and Community Protection Act (CLCPA), signed by Cuomo in July 2019 and enacted this year, calls for 70% of New York’s electricity to come from renewable energy resources by 2030 and for electricity to be 100% carbon-free by 2040.
Raya Salter, NY Renews | IPPNY
“This landmark climate legislation has really shaken the ground and reset the table for the environmental conversation in New York state,” said Raya Salter, member of the New York Climate Action Council and lead policy organizer for NY Renews, a coalition of more than 200 environmental, justice, faith, labor and community groups.
Climate justice emanated from environmental justice as people became more aware of the climate crisis, and the concept eventually assumed economic aspects with the idea of a Green New Deal, she said.
“People are gravitating toward this idea of how can we make sure that we address the climate crisis yet make sure that folks get jobs [and] health care,” Salter said. “The origins of the term, however, are not as lefty as people may think. It still comes from a central-left, neoliberal or neoclassical economic idea that Milton Friedman came up with: … make these investments, and market-based mechanisms will help us drive our economy and address the climate crisis.”
The CLCPA is unique in terms of renewable portfolio standards, not only edging out California as being the most aggressive, but it includes justice provisions, she said. For example, no less than 35% of state spending on climate change will be directed toward disadvantaged communities.
IPPNY CEO Gavin Donohue | IPPNY
Donohue asked whether NY Renews would be open to amending the CLCPA to open the industry up to more innovation and allow, for example, carbon capture and sequestration as an offset for IPPNY members, and allow them to use other technologies.
“Because NY Renews is a coalition, I can’t speak on behalf of it unless we have an official position. … However, I think innovation is opened up rather than constrained by the CLCPA,” Salter said.
On carbon pricing, the effort needs a revenue stream.
IPPNY Chairman Chris LaRoe, senior director for regulatory affairs at Brookfield Renewable, asked what initiatives or policies do Salter or NY Renews support to help existing renewable resources across the state benefit those communities in need of environmental justice: Is there a way for them to support each other, such as increased delivery into those areas?
“I think that’s right,” she said. “Certainly NY Renews has been a part of the large-scale renewable clean energy standard docket before the Public Service Commission. … Yes, we want to alleviate transmission constraints; yes, we want to see more in-city and in-state development of clean and resilient power.”
Investing in Reliability
NYISO Executive Vice President Emilie Nelson moderated a panel on capacity markets, public policy and the age of intermittency.
“When we think about New York specifically, we see the energy and ancillary services markets working together to provide sufficient revenues for the resources needed for reliability,” Nelson said. “With that idea, and considering that we’re working on a transitioning grid and there are significant environmental mandates that need to be satisfied … where do we start?”
Pallas LeeVanSchaik, vice president of Potomac Economics, which serves as the ISO’s Market Monitoring Unit, urged policymakers to retain the existing capacity market framework as “indispensable” for achieving the CLCPA’s goals.
“In our comments earlier this year in the [resource adequacy model] proceeding, we calculated just the outstanding obligations for capacity would reach $25 billion by 2040, so [leaving the organized capacity market] would involve huge risks to ratepayers and would also greatly increase market risk for suppliers,” he said.
Considering the reduction in capacity value since state renewable energy contracts were signed up to the summer of 2020, “our estimate is in the hundreds of millions of dollars of additional capacity costs to cover this shortfall … and that’s just in 2020 alone,” LeeVanSchaik said.
Kathleen Spees, principal at The Brattle Group, said that markets can play the main role in achieving state clean energy goals, rather than a secondary, supporting role, with buyer-side mitigation central to the discussion.
The graphs show what costs customers might face from buyer-side mitigation in New York. Energy and AS prices decrease in some cases because excess capacity depresses prices in tight hours; and because higher contract payments (from lack of capacity payments) cause energy prices to be more negative in over-generation hours. | The Brattle Group
NYSERDA and the Department of Public Service this year engaged Brattle to explore alternatives to the existing capacity markets under the resource adequacy proceeding (Case No. 19-E-0530). Brattle provided qualitative analysis in May and updated quantitative analysis in July.
“Not just New York, but many of the states are concerned about buyer-side mitigation rules resulting, as they’re intended to do, in excluding policy resources from clearing in the capacity market,” Spees said. “The outcome of that is to keep capacity market prices higher than they otherwise would be.”
Carbon pricing would be “way better” if applied economywide, across regions, but Brattle prefers the Forward Clean Energy Market as it put forth in a paper last September, she said.
William Hogan, research director of the Harvard Electricity Policy Group (HEPG), which examines alternative strategies for competitive electricity markets, recommended increasing the importance of scarcity pricing.
Clockwise from top left: Emilie Nelson, NYISO; William Hogan, Harvard Electricity Policy Group; Matthew Schwall, IPPNY; Kathleen Spees, The Brattle Group; and Pallas LeeVanSchaik, Potomac Economics. | IPPNY
“What I am trying to do is dispel the notion that the arrival of intermittent renewables with zero variable costs means that the energy market becomes unimportant, which is wrong; but what it does mean is that scarcity pricing becomes much more important,” Hogan said.
ERCOT is implementing much more aggressive scarcity pricing than what New York is doing, he said.
Examining ERCOT performance for summer 2019, Hogan said that “the tightest conditions frequently occurred earlier than the time of peak demand, so intuitively you would expect that net demand matters more than peak demand.”
Nelson asked panelists for an alternative to carbon pricing.
“I’m a hawk on this subject, so I think carbon pricing is necessary but not sufficient,” Hogan said. “We should be focusing our research and development on new technologies and innovation, not deploying the ones we currently have. We need something way better and that’s going to be transferrable to India.”
LeeVanSchaik agreed, but with a twist: “Even if [carbon pricing] by itself doesn’t achieve the goals of the CLCPA, in concert with other things, it certainly will allow the state to achieve those goals at a significantly lower cost.”
The coronavirus pandemic continues to clamp down on MISO’s spending, with the RTO again predicting to be millions under budget by the end of the year.
Staff told the Board of Directors during its meeting Thursday that they expect MISO’s base operating expenses to be about $6.6 million, or 2.5%, below budget. That’s a slight decrease from the $7.3 million variance the RTO reported to the board in June. The RTO budgeted $264.7 million in base operating expenses this year. (See Pandemic Pause Leaves MISO Under Budget.)
MISO has reduced expenses through slimmed-down employee training and travel expenses, a product of social distancing measures aimed at slowing the virus’s infection rate. The grid operator also has a higher-than-normal employee vacancy rate, as the pandemic complicated its usual hiring tempo.
Carl Nystrom, MISO’s senior director of corporate planning and analysis, said building maintenance expenses are also down this year because the facilities are less populated and offices used less often. However, he said the grid operator is buying a new air filtration system and equipment to improve ventilation in its Carmel, Ind., headquarters.
MISO CFO Melissa Brown | MISO
CFO Melissa Brown said MISO expects to bill its members for 703 TWh of energy in 2020, a 3.3% reduction from 2019’s 727 TWh. Lower load levels during pandemic lockdowns have now inched back to near normal.
“In 2021, we are forecasting a return to normal,” Brown said, adding that MISO expects to collect on about 730 TWh next year.
MISO has a 45-cent/MWh Tariff revenue rate in effect for 2020 and will have a 44-cent rate in effect for 2021.
The grid operator said it expects continued pandemic-related cost savings to persist through at least early 2021. Brown said MISO anticipates pared-down travel and an embargo on in-person stakeholder meetings through June 2021.
“Obviously if the pandemic eases before then, we could have travel pick up,” she said.
MISO is planning for a $379 million budget in 2021, a 3% increase from 2020. Next year’s budget includes a $270.2 million base operating budget, a $50 million investment budget and $58.7 million in other operating expenses.
“Likely in 2022, we expect to see upward pressure on our budget,” Brown said. She attributed the increase to a more normal travel schedule, rebounding employee training activities, technology upgrades, and increased costs from running the old and new market systems in parallel during the new platform’s testing phase.
CEO John Bear said technology costs are trending toward subscription-based payments instead of lump-sum investments.
“We will be expensing things in the year instead of amortizing them,” Bear said of future budgets.
In a long awaited order, FERC on Thursday ordered RTOs and ISOs to open their markets to distributed energy resource aggregations now largely limited to providing demand response (Order 2222, RM18-9).
The commission voted 2-1 in favor of the order at its monthly opening, with Democratic Commissioner Richard Glick joining Republican Chairman Neil Chatterjee. Republican Commissioner James Danly dissented, saying the order intrudes on state jurisdiction.
The commission said that existing RTO and ISO rules are unjust and unreasonable because of their barriers to broader participation by aggregated DERs in capacity, energy and ancillary service markets. DERs are generally too small to meet the minimum size requirements to participate in the markets and also may be unable to meet certain qualification and performance requirements because of their operational constraints, the commission said.
Removing the barriers will improve competition and allow grid operators to avoid the dispatch of more expensive resources to meet system needs, FERC said. DERs can locate where price signals indicate they’re most needed, reducing congestion costs, it added.
The final rule largely follows the commission’s November 2016 Notice of Proposed Rulemaking (RM16-23, AD16-20). That NOPR also led to Order 841, which removed barriers to energy storage, in February 2018. The commission said then that it needed more information before it could take action on DERs, ordering a technical conference for later that year. (See FERC Rules to Boost Storage Role in Markets.)
100-kW Threshold
Order 2222 defines DERs as resources located on the distribution system or a distribution subsystem, or behind a customer meter, including energy storage, thermal storage, intermittent generation, distributed generation, DR, energy efficiency and electric vehicles and their charging equipment.
It requires RTOs and ISOs to allow DER aggregators to register as market participants under participation models that accommodate their physical and operational characteristics. Grid operators must set minimum size requirements for DER aggregations of no more than 100 kW.
Their revised tariffs must cover technical issues such as:
locational requirements for DER aggregations;
distribution factors and bidding parameters;
information and data requirements;
metering and telemetry requirements;
coordination among the regional grid operator, the DER aggregator, the distribution utility and the relevant electric retail regulatory authority (RERRA);
modifications to aggregations; and
market participation agreements.
Chatterjee called the order “a landmark, foundational rule that paves the way for the grid of tomorrow.”
“DERs can hide in plain sight in our homes, businesses and communities across the nation. But their power is mighty,” he said during the open meeting. “Some studies have projected that the United States will see 65 GW of DER capacity come online over the next four years, while others have even projected upwards of 380 GW by 2025. While these estimates and analytical frameworks vary, there is no doubt that investments in these advanced technologies will only accelerate in the years to come, continuing the seismic shifts we’re seeing in our energy landscape.”
Chatterjee also cited the potential for EVs to eventually provide energy, spinning reserves or frequency regulation while plugged in.
No Opt Out
The commission declined to allow local or state regulators to prohibit DERs from participating in the wholesale markets through an opt-out, citing the D.C. Circuit Court of Appeals ruling upholding the commission’s similar position regarding behind-the-meter storage under Order 841. (See FERC Storage Order Survives State Challenge.)
But in recognition of potential cost impacts, the commission created an opt-in mechanism for small utilities, similar to that in Order 719-A for DR. It says RTOs/ISOs must not accept bids from aggregations that include DERs that are customers of utilities that distributed 4 million MWh or less per year unless the RERRA allows it.
The commission also declined to assert jurisdiction over the interconnection of DERs to distribution facilities for aggregations. It “does not require standard commission-jurisdictional interconnection procedures and agreements or wholesale distribution tariffs in connection with DER aggregations,” FERC staff said in a presentation at the meeting. “Rather, state or local law would govern distribution-level interconnections for DERs participating in RTO/ISO markets.”
“If we granted all state regulators the option [to prevent DER aggregation], we’d have a checkerboard approach where some states in an RTO would opt out and some wouldn’t, and it would artificially limit the amount of DER energy and capacity participating in these markets,” Glick said at the meeting. “States still have significant authority to protect distribution system reliability. States will continue to exercise their jurisdiction over interconnection of aggregate DER facilities. … I believe this is a fair compromise.”
Danly Dissent
Danly said he dissented because “regardless of the benefits promised by DERs, the commission goes too far in declaring the extent of its own jurisdiction and because the commission should not encourage resource development by fiat.”
“Why promulgate a rule at all?” Danly asked. “Reluctance to govern by fiat is counseled particularly in a case like this in which the generation resources the majority seeks to promote, by their very nature, inevitably will affect the distribution system, responsibility for which is assigned, with no ambiguity, to the states. We should allow the RTOs and ISOs (or the states or the utilities) to develop their own DER programs in the first instance. If the promises of DERs are what they purport to be, the markets will encourage their development. And if those programs result in wholesale sales in interstate commerce, then the question of the commission’s jurisdiction will be ripe. Commission directives are unnecessary to encourage the development of economically viable resources. I have greater faith in the power of market forces and in the discernment of the utilities and the states.”
The rule will become effective 60 days after publication in the Federal Register, with RTO and ISO compliance filings due nine months after publication.
Reaction
Reaction to the order was generally positive.
Louis Finkel, senior vice president of government relations for the National Rural Electric Cooperative Association, said the group — which had challenged Order 841 before the D.C. Circuit — was happy that FERC included the opt-in for small utilities.
“It is important that the commission has recognized the challenges that this order could pose for small utilities, including virtually all distribution co-ops,” Finkel said. “We look forward to carefully reviewing FERC’s decision in the coming days with the hope that it does indeed preserve state and local regulatory authority over retail electricity sales and local distribution service. Local control is critical, because every co-op is different and is uniquely positioned to meet the specific needs of the community it serves.”
Kelly Speakes-Backman, CEO of the Energy Storage Association, said the order builds on the foundation of Order 841 for distributed energy storage.
“Energy storage is increasingly located on local electric grids, in households and businesses, and is often integrated with distributed generation and controllable loads,” she said. “Enabling these flexible resources to participate together as ‘virtual power plants’ in wholesale markets is a victory for enhancing grid reliability, enabling a more resilient grid and lowering costs for consumers.”
The Advanced Energy Management Alliance said “a participation model for consumers and distributed energy resources enables crucial cost savings, flexibility, resilience and environmental benefits to the grid. … AEMA has been working through ISO stakeholder processes to encourage development of distributed energy resource participation but has also worked with state regulators and utilities to develop solutions through retail and state markets.”
Gregory Wetstone, CEO of the American Council on Renewable Energy, praised the ruling but said the commission was working at cross purposes by “continuing to erect barriers to the entry of new technologies in PJM and NYISO through the use of minimum offer price rules.”
“While today’s order on distributed energy resources follows in the forward-thinking footsteps of Order No. 841 on energy storage, no market can be free until arbitrary resource-specific price floors are eliminated,” he said.
The Northern Maine Independent System Administrator (NMISA) is asking New England transmission owners to eliminate through-and-out (TOUT) transmission charges for transactions between it and ISO-NE, similar to the reciprocal discount currently used by the RTO and NYISO.
NMISA CEO Ken Belcher and consultant Steve Garwood of PowerGrid Strategies outlined the proposal to the New England Power Pool Transmission Committee on Tuesday, saying it would eliminate pancaked transmission charges between the two regions, “consistent with FERC’s longstanding policy of eliminating seams issues where possible.”
NMISA, which serves a peak load of about 138 MW in Aroostook, Washington and Penobscot counties, is not directly interconnected with the rest of New England. Its two regions — Versant Power’s Maine Public District (MPD) in the north and the Eastern Maine Electric Cooperative in the south — connect to ISO-NE through the transmission facilities of New Brunswick’s NB Power. (Versant Power was formerly known as Emera Maine.)
Officials said the change would result in a “de minimis” impact on transmission rates for both regions while improving market efficiency and liquidity and increasing generation competition by reducing the costs for Northern Maine to access ISO-NE generation and for the RTO to use the region’s wind resources.
Had the proposal been in effect during 2019, it would have increased the June 1, 2020, regional network service rate by 4 cents/kW-year (0.03%), NMISA said, while MPD would see a 1.3% increase.
| NB Power
Northern Maine currently purchases about 70,000 MWh annually from ISO-NE, producing $67,000 in transmission revenue not subject to the discount. By reducing the seams costs, that could rise to 659,000 MWh, producing non-discounted charges of $633,000, NMISA said.
Increasing south-to-north transactions also would reduce congestion at the Orrington-South interface, potentially reducing curtailments of Northern Maine’s wind power exports to the RTO, the ISA said.
Northern Maine’s renewable exports are currently worth $2.5 million in renewable energy credits. That could increase by $750,000 through scheduling optimization, NMISA said. “Also, there is potential for further development of renewables up to 100 MW in Northern Maine for delivery to New England based on unused existing transmission capacity. Exporting the energy from these new resources to ISO-NE is unlikely to occur absent implementation of the proposed discount,” it said.
In its first presentation on the proposal at the joint Transmission/Reliability committees meeting in August, NMISA said MPD would have lost $164,546 in TOUT revenue had the charge been eliminated in 2019. In response to a question, it acknowledged that the revenue would have been $874,546 had MPD not already been discounting its export point-to-point rate. “However, absent continuation of the discount, it is unlikely that the same level of transactions would occur as occurred during 2019,” NMISA said.
Garwood said Northern Maine will ask ISO-NE’s Participating Transmission Owners Administrative Committee (PTO AC) at its Sept. 22 meeting to issue a notice of intent to eliminate the TOUT.
ISO-NE Proposes Tariff Revision on Transmission Charge Exemption for Storage
ISO-NE shared proposed Tariff revisions it intends to include in its third compliance filing on FERC Order 841 after the commission last month said the RTO had failed to demonstrate that a storage resource that is self-scheduled to charge at a fixed megawatt quantity is providing a service that warrants exempting it from transmission charges. (See FERC OKs Most of ISO-NE 2nd Storage Compliance.)
Jennifer Wolfson, an attorney for ISO-NE, presented the revisions on behalf of the RTO and PTO AC. Addressing FERC’s concern with self-schedules, she said that “a charging self-scheduled” storage dispatchable asset-related demand (DARD) provides similar services as “a charging pool-scheduled” storage DARD.
ISO-NE and the PTO-AC contend that all charging megawatts of a self-scheduled storage DARD supply voltage support and reactive control. “A self-scheduled resource is required to follow ISO dispatch instructions, without delay, to consume at the requested megawatt level; therefore, when it charges it provides real-time balancing of supply and demand and operating reserve,” they say. “A charging self-scheduled storage DARD, in contrast to other load, helps address reliability concerns given that the ISO can dispatch the load off if needed to address a contingency.”
The Tariff revisions state that storage will be exempt from transmission charges only if its charging load does not include station service load or any other load and “is providing one or more of the following services: reactive power voltage support, operating reserves, regulation and frequency response, balancing energy supply and demand, or addressing a reliability concern.”
The Transmission Committee will vote on the proposed Tariff revisions on Oct. 27, with a Participants Committee vote expected Dec. 3.
Last week, RTO officials outlined their plans for responding to two other directives from FERC’s Aug. 4 order. (See “Order 841 Compliance Update,” NEPOOL Markets Committee Briefs: Sept. 8, 2020.)
President Trump’s nominees to FERC, Allison Clements and Mark Christie, said just enough to satisfy senators on both sides of the aisle during their confirmation hearing Wednesday.
Neither nominee gave away how they might decide on the commission’s thorniest issues, including carbon pricing, capacity markets and downstream greenhouse gas emissions from natural gas pipelines. Instead, they both said they did not want to “prejudge” any matters before they are sworn in and repeatedly committed to considering each matter that came before them on a case-by-case basis.
Both Republican and Democratic members of the Senate and Energy Natural Resources Committee were pressed for time because of votes on the Senate floor and did not press the nominees further for more clues. They gave no indication that they would oppose either nominee.
Clements, a Democrat and energy policy adviser for the Energy Foundation, and Christie, a Republican and chair of the Virginia State Corporation Commission, were nominated by Trump in late July. (See McNamee Leaves FERC.)
“Both nominees made multiple references to the need for objectivity, the importance of reliability and resiliency, and the central duty of the commission to ensure just and reasonable rates for consumers,” ClearView Energy Partners said. “We thought both nominees were circumspect in their responses … and steered clear of any remarks that might be construed as potentially prejudging an issue pending before the commission.”
President Trump’s nominees to FERC, Virginia SCC Chair Mark Christie and Energy Foundation consultant Allison Clements, are sworn in before their confirmation hearing Sept. 16. | Senate ENR Committee
Several Republicans, most notably Sen. Cory Gardner (Colo.), did focus on Clements and her previous work for the Natural Resources Defense Council’s Sustainable FERC Project. When Gardner asked her to “name an issue” on which she disagreed with her former colleagues, Clements without hesitation answered nuclear generation, which she said “plays an important role in providing carbon-free, reliable power to the system. That’s a place where many of my very well studied and smart colleagues might disagree with me.”
“Could you name another one, perhaps?” Gardner replied. He tried to get Clements to say whether she disagreed with the NRDC on its “fossil fuel agenda,” but she wouldn’t bite.
Democrats, meanwhile, tried to determine where Christie would side on the GHG dispute, which has caused tension at FERC. Democratic Commissioner Richard Glick has repeatedly dissented from the commission’s approvals of natural gas infrastructure, contending that they ignore a D.C. Circuit Court of Appeals ruling that said it must consider the effects of downstream GHG emissions in its environmental impact statements.
Senate ENR Chair Lisa Murkowski (R-Alaska) | Senate ENR Committee
Christie, however, demurred, telling Sen. Martin Heinrich (N.M.) that he did not “want to prejudge that issue because that is a legal question about what does the law require and what does the D.C. Circuit opinion require.” He often sounded like McNamee, a fellow Virginian, repeatedly stressing the importance of “the law and the facts,” a phrase that the former commissioner often used in his public appearances.
One of the few mentions of the RTOs came when Christie answered to a question about market manipulation from Sen. Maria Cantwell (D-Wash.). Christie acknowledged that Washington has been considering whether to allow its utilities to join an RTO with CAISO and advised that, having “lived in PJM world for the past 16 years, it is absolutely essential that you have an Independent Market Monitor in these RTO capacity markets. … We have an outstanding market monitor in PJM, Dr. [Joe] Bowring.”
Christie was president of the Organization of PJM States Inc. in 2007 when it pressed FERC to separate PJM’s Market Monitoring Unit into an IMM. In March 2008, FERC approved the current monitoring structure, with Bowring as head of his own independent firm.
Committee Chair Lisa Murkowski (R-Alaska) said she hopes to have both nominees confirmed before Congress adjourns at the end of the year. ClearView expects that to happen, albeit most likely after Election Day. “We did not observe any statements by either nominee that would appear to imperil their eventual confirmation,” ClearView said. “That said, we cannot foretell how a potentially contested presidential race could impact the day-to-day functioning of the U.S. Senate in a lame duck session.”
If confirmed, Clements’ term would end in June 2024 and Christie’s in June 2025.
