FERC on Thursday said that MISO’s Tariff was silent on the issue of whether a generation project can switch from wind to solar while in the RTO’s interconnection queue (ER19-1823-003).
It also said that there was no requirement in Order 845 that requires grid operators to study projects that opt to change fuel types.
The issue stems from a Leeward Renewable Energy Development wind project currently in the definitive planning phase (DPP) of MISO’s generator interconnection queue. The developer wants to convert the project to using solar energy while also retaining its position in the queue.
Leeward said MISO was disregarding its own Tariff when it refused to perform an analysis to determine whether switching the project would constitute a material modification. Borrowing a phrase from Order 845, Leeward argued that the switch would result in “equal to or better” electrical performance.
Order 845 allows interconnection customers to make certain technological advancements to their generation projects without triggering a material-modification rule. Under the order, a customer can offer evidence that a requested technological change results in “equal to or better” performance. MISO must evaluate such claims and render a decision before projects can proceed.
| Leeward Renewable Energy Development
Order 845 also dictates that changes between wind and solar technologies should not automatically be treated as non-material modifications because “such changes involve a change in the electrical characteristics of an interconnection request, and the transmission provider would likely need to evaluate the impacts of such changes.”
MISO argued that it should not have to evaluate “mid-DPP fuel change requests” under Order 845 and said its Tariff doesn’t permit fuel type changes to projects after they enter the DPP.
But FERC said the Tariff allows Leeward to at least make a case for a fuel change in its generation project. It said Order 845 didn’t change MISO’s pre-existing material-modification provisions in its generator interconnection procedures. While Order 845 doesn’t require the grid operator to study fuel type changes, FERC said MISO also doesn’t have language in its generator interconnection procedures to preclude itself from studying fuel change requests.
“We find that the question of whether these pre-existing Tariff provisions allow an interconnection customer to submit a fuel change request after its project enters the DPP is therefore outside the scope of MISO’s Order No. 845 compliance filing,” FERC said.
The commission added that its decision was without prejudice to MISO making any filings to “further address the permissibility of, and requirements for, fuel change requests.”
FERC on Thursday left MISO transmission owners’ ability to self-fund network upgrades intact over a protest from the American Wind Energy Association and the dissent of Commissioner Richard Glick (EL15-68-005, et al.).
MISO in August 2018 reinstated TOs’ rights to self-fund network upgrades necessary for new generation. That meant generator interconnection agreements signed between June 24, 2015, and Aug. 31, 2018, could be revised to allow TOs to fund network upgrades and bill interconnection customers. (See MISO Gauging Aftershocks of TO Self-fund Order.)
The change came after the D.C. Circuit Court of Appeals remanded FERC’s 2015 decision barring TOs from electing to provide initial funding for network upgrades.
AWEA argued that the commission’s ultimate decision is “patently discriminatory” because it will allow those who had never applied for the self-fund option to do so and treat different interconnection customers differently. The association pointed out that before mid-2015, only one MISO TO has ever opted to self-fund a network upgrade.
FERC disagreed with the claims of discriminatory treatment.
“The fact that transmission owners may not have elected transmission owner initial funding in GIAs they were a party to prior to the interim period … does not, by itself, support a finding that such transmission owners should be barred from electing transmission owner initial funding on an ongoing basis,” FERC wrote.
AWEA also argued that FERC strayed from its usual mode of “preserving the sanctity of contracts.” It said the commission “has previously only departed from that precedent in extreme circumstances, such as fundamental industry restructuring and reorganization of a bankrupt utility.” The association contended that TOs shouldn’t be allowed to self-fund upgrades under multiparty facilities construction agreements because MISO’s original compliance filing didn’t mention such agreements.
FERC disagreed, noting that prior orders found that MISO’s facilities construction agreements and multiparty facilities construction agreements should be treated like GIAs.
Glick said the commission’s order didn’t “meaningfully” address AWEA’s concerns about the possible discrimination of some interconnection customers.
“Today’s order … doubles down on the unwise decision to permit the reopening of numerous previously negotiated interconnection agreements, despite considerable evidence that allowing transmission owners and affected-system operators to retroactively elect to self-fund the network upgrades associated with those agreements will result in substantial harm to interconnection customers and could lead to project terminations,” he wrote.
AWEA also argued that resource owners may have already started depreciating network upgrade investments in their books. FERC said that since 2015, generation owners have been put on notice that TO self-funding could again become a possibility.
Glick said that FERC stumbled by simply reversing its 2015 decision after the D.C. Circuit’s remand. He pointed out that the commission five years ago found that allowing TOs to unilaterally elect to fund upgrades could deny interconnection customers the “opportunity to finance network upgrades with more favorable rates and terms.”
He also said FERC’s decision to treat GIAs, facilities construction agreements and multiparty facilities construction agreements similarly was done without “any additional analysis or meaningful response to arguments raised by protesters.”
MISO members last week said the RTO’s footprint could benefit from transmission line ratings that change with the weather and other factors.
Clean Grid Alliance’s Natalie McIntire said static, conservative line ratings might be unnecessarily limiting transmission capacity and the amount of new generation resources that can interconnect to the MISO system.
“There might be transmission limitations that might exist for a small number of hours every year,” she said during a Advisory Committee conference call Wednesday.
McIntire also said it would be helpful if MISO transmission owners offered more information on how they form line ratings and for the RTO to identify the circuits that stand to benefit the most from more flexible ratings.
“As we’re all trying to make the most efficient use of the system, it would be helpful for MISO to tell us which are the lines that have the most potential gap between the static and dynamic ratings,” she said. Dynamic line ratings (DLRs) will ensure that consumers “get the most from their investment,” McIntire said.
DTE Energy’s Nick Griffin said MISO and its TOs should concentrate first on congested flowgates with the largest impact. “It doesn’t have to be broad range right at first,” he said.
Other members said MISO should establish a standard method for TOs to report the latest line ratings.
Organization of MISO States Executive Director Marcus Hawkins said transmission ratings in the RTO aren’t formed transparently. He has asked stakeholders to decide how large a role the grid operator should take in managing line ratings.
“MISO really could play a critical role in deciding where these enhanced ratings could be most beneficial and most cost-effective,” Hawkins said last month during an Advisory Committee teleconference.
Independent Market Monitor David Patton has said temperature-adjusted ratings would save the RTO about 10% of its total transmission congestion. He has estimated that MISO stands to save more than $150 million on an annual basis but says TOs remain reluctant to adopt DLRs because it involves investing in equipment and manpower with little return. Entergy already uses ambient-adjusted ratings in MISO South.
“The costs of not utilizing our transmission network is large,” Patton said during MISO’s Market Subcommittee meeting in April.
The Monitor and TOs have been discussing the possibility of DLRs in nonpublic Reliable Operations Working Group meetings.
The TOs said they’re working on their own benefit analysis of DLRs. Some cautioned that while some lines’ ratings could go up, some could also be lowered.
Transmission Owners sector representative Stacie Hebert said changes to facility ratings could result in higher cost recoveries and additional risk to TOs’ equipment.
Some stakeholders have said that while it’s true that lines can carry more capacity in below-freezing temperatures, it’s the generation component that’s often lacking in emergency conditions. That is especially true in MISO South, which is less prepared for arctic blasts.
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.
