The California Energy Commission last week added another $260 million for electric vehicle charging infrastructure to the state’s planned $2.5 billion investment in transportation electrification over the next decade. Questions remain, however, about whether the state can install enough chargers, sell enough EVs and build sufficient generation, storage and transmission capacity to meet its ambitious goals.
Former Gov. Jerry Brown set a target l in 2018 of putting 5 million zero-emission vehicles (ZEVs) on the road by 2030. Gov. Gavin Newsom issued an order Sept. 23 requiring all new passenger cars sold in California to be emissions-free by 2035. (See Calif. to Halt Gas-powered Auto Sales by 2035.)
The funding that the CEC unanimously approved Wednesday is part of its 2020-2023 update to its Clean Transportation Program. “I’m pretty excited about this investment plan, and I think it really aligns well with the governor’s executive order to set a course for 100% zero-emissions vehicles in the next 15 to 25 years,” Commissioner Patty Monahan said.
California currently has more than 725,000 electric vehicles and accounts for half of the nation’s EV sales, yet it remains far from Brown’s 5 million target, let alone meeting Newsom’s mandate.
1M+ Chargers
At Wednesday’s CEC meeting, Patrick Brecht, manager of the Clean Transportation Program, told commissioners California still needs to install about 188,500 level 2 chargers in the next five years to reach the 250,000 that Brown ordered the state to install by 2025.
State agencies have allocated funding for about two-thirds of the chargers including $1 billion for investor-owned utilities to install charging infrastructure and $800,000 from a settlement with Volkswagen over its diesel-emissions scandal. That still leaves a funding gap for nearly 67,000 units, Brecht said.
Closing the funding gap could leave the state with less than a quarter of the more than 1 million public chargers it may need to achieve its ZEV ambitions, according to the National Renewable Energy Laboratory (NREL).
In August, NREL research engineer Eric Wood told the CEC that if the state has 5 million EVs by 2030, it will need up to 1.15 million charging spots, including as many as 300,000 level 2 chargers for apartments, 358,000 chargers at workplaces and 413,000 chargers in locations such as shopping centers and movie theaters. (See California Needs Huge Number of EV Chargers.)
Additionally, NREL estimates that millions of future EV owners will likely need to purchase fast chargers for their homes.
Selling enough EVs also remains a problem. Automakers need to double the pace of EV sales to deliver 5 million by 2030, the California Air Resources Board (CARB), which regulates vehicle emissions, told the CEC in August.
At the time, five weeks before Newsom’s order, CARB presented a scenario in which all vehicles sold in the state would be EVs or plug-in hybrid vehicles by 2035, calling it an “extreme sales trajectory.”
‘You Can’t Even Keep the Lights On’
Procuring sufficient electricity to meet charging demand may be another obstacle to Newsom’s order.
California experienced energy emergencies in August and September, and CAISO anticipates capacity shortfalls through summer 2023. The state is waiting for hundreds of thousands of megawatts of battery storage to come online in the years ahead as it attempts to transition from its reliance on natural gas to wind and solar generation.
Load-serving entities are required to serve retail customers with 100% carbon-free energy by 2045 under Senate Bill 100.
After the governor’s order, EPA Administrator Andrew Wheeler wrote to Newsom questioning his decision.
“Your state is already struggling to maintain reliable electricity for today’s demands,” Wheeler said. “California’s record of rolling blackouts — unprecedented in size and scope — coupled with recent requests to neighboring states for power begs the question of how you expect to run an electric car fleet that will come with significant increases in electricity demand when you can’t even keep the lights on today.”
Others have expressed concerns about whether California can supply enough energy to charge so many EVs.
The U.S. Department of Energy asked its Pacific Northwest National Laboratory (PNNL) to study the impacts of a large influx of EVs on the bulk electric system.
Charts from the DOE study show increased EV demand for WECC in summer and winter. | PNNL
In October 2019, PNNL staff scientist Michael Kintner-Meyer presented preliminary findings at Infocast’s EVs and the Grid forum in Los Angeles. Kintner-Meyer said EV owners could either soak up the state’s abundant solar power in the daytime by charging at work or further strain the grid by charging their vehicles at home during peak demand in the late afternoon and early evening.
The shortages in August and September occurred in the early evening hours. CAISO calls the period the net demand peak time, when solar drops offline but demand remains high during heat waves. That time, around 7 p.m. in summer, is also called the neck of the duck in California’s “duck curve” load profile.
“Early-morning charging is beneficial for [California’s] duck curve, [but] coming home and plugging in for California is really detrimental,” Kintner-Meyer said at the Infocast summit.
In its final report released in July 2020, the PNNL team said the Western Interconnection likely will have sufficient resources to accommodate 9 million EVs by 2028 even if most people charge their cars immediately after getting home from work.
The study assumes normal operating conditions including weather — not the extreme heat events the West experienced in August and September.
Natural gas plants throughout the West, plus battery storage in California and hydropower in the Northwest, can probably provide sufficient energy under normal conditions to meet the additional peak demand from EVs, the authors found.
Transmission constraints into California, however, could prevent load centers such as Southern California from meeting EVs’ additional demand, the report said.
“At the maximum number of [light-duty vehicles], the authors found transmission congestion to be the limiting factor, which means that there are some available power plants in the WECC, but the electric power could not be delivered to the load centers because of transmission limitations,” it said. “The largest transmission congestions were in California.”
While the NPPL study said solar plus batteries could meet the state’s EV charging demand, CAISO leaders have warned that far more renewable generating capacity in addition to the current excess solar may be needed to charge batteries to meet evening peaks.
After the August blackouts, then-CAISO CEO Steve Berberich said that to avoid outages, the state needs 12,000 MW of battery storage and an “overbuild” of solar and wind generation to charge them. California currently has 200 MW of battery storage.
Resource planning, Berberich said, “must be reformed so that every hour of the year is properly resourced.”
CAISO spokeswoman Anne Gonzales said the trio of organizations responsible for grid planning must still determine what upgrades Gov. Newsom’s order will require.
“The governor’s order requiring new vehicles to be zero-emission beginning in 2035 will require a high level of analysis and collaboration among state agencies, load-serving entities and stakeholders,” Gonzales said in an email.
The California Public Utilities Commission assesses capacity needs and orders procurement by IOUs. The CEC forecasts long-term energy demand. And CAISO incorporates the information into its transmission planning process.
“We will continue our coordination with the state to ensure that these needs are factored into load forecasting and resource planning decisions, and then considered in transmission planning,” she said.
New England states called on ISO-NE last week to increase its transparency and the role of states in its decision-making, saying the current structure is incompatible with their clean energy efforts and is raising costs for ratepayers.
The New England States Committee on Electricity (NESCOE) made the demands Friday in an eight-page manifesto titled “New England States’ Vision for a Clean, Affordable and Reliable 21st Century Regional Electric Grid.” It lays out in more detail a critique released two days earlier by the governors of Connecticut, Maine, Massachusetts, Rhode Island and Vermont, who said ISO-NE is frustrating their efforts to reduce economy-wide greenhouse gas emissions. (See related story, New England Governors Call for RTO Reform.)
Although New Hampshire Gov. Christopher Sununu (R) did not participate in Wednesday’s statement, NESCOE said the state did join in the vision document, saying the state shared its neighbors’ “interest in preserving efficient wholesale markets and in ensuring that transmission system planning achieves least-cost solutions.” New Hampshire also wants “to prevent or minimize any rate impact of other states’ policies” on its retail electric rates, NESCOE said.
The vision statement said ISO-NE should convene a “collaborative process” with states and other stakeholders in 2021 to consider changes to its mission statement and governance structure “to achieve greater transparency around decision-making, a needed focus on consumer cost concerns and support for states’ energy and environmental laws.”
It noted that the RTO’s mission statement, contained in its Tariff, “has no explicit relationship to or recognition of the need for consumer cost-consciousness.”
It also criticized the makeup of ISO-NE’s Joint Nominating Committee, which selects the RTO’s board members. The committee comprises seven incumbent board members, six market participants — one from each of NEPOOL’s sectors — and only one shared vote for the six New England states.
“This one-vote-for-six-state governments may have been comfortable in the late 1990s, when regional planning and markets had relatively marginal interaction with the requirements of state laws,” NESCOE said. “Today, it merits a relook.”
The statement includes repeated references to the RTO’s “lack of transparency,” which it says “undermines public confidence” in the organization. Neither ISO-NE board meetings nor NEPOOL stakeholder meetings are open to the public.
States and stakeholders only see “exceptionally high-level summaries of board discussions provided by ISO-NE management. This results in an unacceptable constraint on facilitating independent insight and review by stakeholders about what data, material and other resources the board considers in developing its guidance to management and how it balances divergent interests in their decision-making.”
NESCOE said the states and stakeholders should use the months before 2021 to consider best governance practices of other grid operators, but it added that the states “welcome any immediate actions by ISO-NE to address these or other governance issues that are within its discretion to provide greater transparency and accountability.”
While the boards of PJM and NYISO also meet privately, NEPOOL is the only RTO/ISO stakeholder body in the U.S. whose meetings are not open to the public.
ISO-NE spokesman Matt Kakley said in a statement to RTO Insider that “we have reviewed the NESCOE vision statement and look forward to speaking with the states on these issues.” The RTO had no immediate comment on what changes it has discretion to make or whether it would consider them.
The states and NESCOE will hold a series of online technical conferences this fall that will be open to the public to discuss the vision statement and solicit input. “The states intend to report to their respective governors in the first quarter of 2021 on findings and recommendations for action steps to advance this vision,” NESCOE said.
Market Design, Transmission Planning
NESCOE said the region needs a new “market framework” that meets states’ decarbonization mandates and maintains resource adequacy at the lowest cost using market-based mechanisms. It also must accommodate states’ long-term contracts for clean energy resources, integrate distribution-level resources efficiently and give states “the central role” in designing the market.
The states acknowledged the ongoing discussions around potential market changes, such as the proposed Forward Clean Energy Market (FCEM), which it said “may be one way” to support clean generation resources to meet their carbon-reduction laws.
New England ratepayers have seen escalating transmission charges — rising from $869 million in 2008 to $2.4 billion in 2019 — and will need to fund additional infrastructure to deliver onshore and offshore wind energy to load centers and facilitate distributed energy resources, NESCOE said.
It called for “a comprehensive long-term regional transmission planning process,” saying the RTO “currently does not conduct a routine transmission planning process that helps to inform all stakeholders of the amount and type of transmission infrastructure needed to cost-effectively integrate clean energy resources and DERs.”
It also recommended the RTO develop “multiple future resource scenarios (e.g., three to four) as the basis for assessing future regional transmission needs [using] identified time frames (e.g., 2030, 2040 and 2050).”
The New York Public Service Commission on Thursday designated the New York Power Authority’s (NYPA) $1 billion Northern New York (NNY) transmission line as a high priority for meeting the state’s renewable energy goals and adopted criteria for identifying other such “priority transmission projects” (PTPs) (20-E-0197).
The commission’s order bypassed NYISO’s public policy transmission planning process, referring the project straight to NYPA for development and construction in accordance with the Accelerated Renewable Energy Growth and Community Protection Act of 2020.
“Today, we are adopting well designed new rules to specifically expedite transmission investments that unbottle existing and new renewables … [and] the first investment under these new rules, NYPA’s Northern New York project, will complete a critical link in our upstate grid and unbottle at least 950 to 1,500 MW of renewable energy sources,” PSC Chair John B. Rhodes said.
The NNY project has an estimated cost of $1.05 billion, extrapolated from NYPA’s calculation that it would yield $99 million in production cost savings of per year. Based on production cost savings alone, the project has a positive 1.0 benefit/cost ratio, NYPA says.
NYISO’s public policy transmission map shows projects it identified to increase the flow of hydro and imports from Ontario from western to eastern New York, and increase the clean energy flow from upstate to downstate by about 1,000 MW. | NYISO
The commission amended Department of Public Service staff’s proposed criteria, taking for example, the first three and bundling them into one criterion for designating a PTP: “the transmission investment’s potential for unbottling existing renewable generation, as well as projects that are in the NYISO interconnection process, for delivery to load centers in the state, thereby reducing the amount of new generation that must be constructed to meet the CLCPA targets.”
The state’s Climate Leadership and Community Protection Act (CLCPA) requires that 70% of electricity generation come from renewable resources by 2030, and that generation be 100% carbon-free by 2040.
One key factor in expediting the project’s approval and bypassing the NYISO planning cycle was that its presumed earlier in-service date would result in benefits that would otherwise be lost forever, the commission said.
NYPA said the project will upgrade approximately 200 miles of 230-kV lines to establish a continuous 345-kV path and expand the deliverability of renewable generation from northern and western New York to load centers, while compounding the benefits from the Segment A and B projects already underway. (See NYISO Board Selects 2 AC Public Policy Tx Projects.)
Watch the Guiderails
The State Legislature provided guiderails for the prioritization task by recognizing two project implementation mechanisms, the commission said. While all projects that are ultimately included in the plan will be necessary to meet the CLCPA objectives, the act distinguishes one category of projects as “needed expeditiously,” while other necessary projects may be referred to NYISO’s established public policy transmission planning process.
“The folks that participated and gave comments in this proceeding were generally supportive, right?” Commissioner Diane Burman asked. “Anbaric was supportive of the staff criteria; [the Natural Resources Defense Council] and Alliance for Clean Energy New York [ACE NY] submitted comments supporting it. … For me, we also need to be mindful that the ISO process is a good one, [to which] we should be complementary in this process dealing with transmission investments.”
Use of the PTP designation outside of the NYISO process should be “few and far between,” Burman said.
Multiple Intervenors (MI), a coalition of large industrial, commercial and institutional energy customers, submitted comments pointing out that a PTP designation amounts to a choice to bypass the existing NYISO planning process and its associated benefits to customers, including its competitive construct, a high level of transparency, cost caps and an equitable cost allocation methodology. MI asserted that, in contrast, the PTP designation process is not competitive, does not involve evaluation of alternative solutions, is not fully transparent and does not include consumer protections.
Avangrid used this slide at a technical conference Oct. 9 to show New York state policy goals and future resources. | Avangrid
In its comments, NYISO asked the PSC to designate priority transmission projects “in tandem” with the ISO’s public policy planning process, which has been used successfully to develop transmission in response to needs identified by the commission, including the Western New York and AC Transmission projects. The ISO also said it has taken recent steps to streamline its process, which can now be completed in approximately 18 months.
“We take notice of the fact that the NYISO only recently initiated the 2020 public policy planning cycle, under which it would be several months before NYPA could even submit the NNY project for evaluation,” the commission said in the order. “We conclude that this factual circumstance supports the finding that the NNY project is likely to be placed in-service earlier than a comparable project selected by the NYISO would be, even though the petition does not provide a specific in-service date.”
“The Northern New York project, which may be new to certain folks on the commission, is not a new project,” Commissioner John Howard said. “It has been sitting on the drawing boards for some time in different iterations, and consensus projects like that with clear economic and environmental benefits are easy to do. I think this process becomes much more difficult going forward as we design transmission infrastructure for projects that have yet to become reality, and how we allocate those costs becomes much more difficult.”
NYPA estimates the project will allow the state to annually avoid more than 1.2 million tons of CO2 emissions and approximately 160 tons of NOx emissions from downstate emissions sources. It should also provide more than $447 million in annual congestion savings upstate.
Climate Change Financial Risk, Modifying CES
The PSC also initiated a proceeding to consider requiring New York’s major utilities to disclose what risks climate change poses to their companies, investors and customers going forward (20-M-0499).
“For utilities with significant assets and changing physical infrastructure needs, increased transparency of climate-related financial risks would allow better planning and investment consistent with New York’s climate goal of a carbon-neutral economy by 2050,” the commission said.
The state’s largest electric and gas utilities have more than $52 billion in capital and in the past year raised $6.2 billion through debt issuances, the commission said.
The PSC also modified the state’s Clean Energy Standard (CES) to align it with the CLCPA, as indicated in a June white paper (15-E-0302), specifically adopting the 70% by 2030 target and expanding the renewable energy procurement programs of the New York State Energy Research and Development Authority (NYSERDA).
The commission said that average annual Tier 1 procurement targets of approximately 4,500 GWh per year over 2021-2026 “provide sufficient certainty to investors that will allow effective planning and other market-based activities to develop.” It therefore declined “to adopt minimum or maximum gigawatt-hour requirements for each solicitation, instead allowing NYSERDA to adjust annual procurement targets based on its annual review of the latest market data.”
The order also authorized NYSERDA to solicit enough offshore wind energy to meet the CLCPA target of 9 GW by 2035 and created a new methodology for extending Tier 1 renewable energy eligibility to renewable energy facilities that undergo repowering. It additionally created a competitive five-year Tier 2 program under the CES to preserve existing renewable baseline generation, as well as a new Tier 4 large-scale renewable program to value environmental attributes associated with renewable energy delivered into New York City that will be in addition to annual Tier 1 procurement targets.
The commission said its action will ensure that the state’s renewable energy programs provide substantial benefits for disadvantaged communities, including low- to moderate-income customers.
Dissent and Caution
Commissioner Burman delivered the only vote against the measure and called it an overly prescriptive “tortured exercise … that seems to chill how technologies … may work together with other renewable sources in a way that may actually help.”
While developers want regulatory certainty and NYSERDA needs flexibility to conduct important solicitations, “my concern is that we have solicitations and [requests for proposals] throughout the state … and we need to look much more carefully at the guardrails that need to be in place to ensure that we are doing this in a responsible and fiscally accountable way,” Burman said.
She also doubted that NYSERDA had enough qualified staff to oversee such complicated programs.
“We may have to look at hiring some outside entity to help us ensure the proper implementation of these solicitations,” she said. “What makes me deeply pause is that due to the complexities of some of NYPA’s contracts, they were unable to satisfy the entirety of their allocated ZEC [zero-emission credit] obligation, and therefore a few of the [load-serving entities] have ceased offering service in New York, and NYSERDA has amassed a ZEC-collection deficit of approximately $34 million and now is seeking to recover those funds. I just find that unacceptable.”
Commissioner Howard said he was uncertain the state will be able to finance all its clean energy programs completely through customer bills. He was also uncertain about the role of FERC “and their ability to stymie some of our initiatives.”
The newest commissioner also found it “ironic that environmental advocates or any other advocates for clean energy also decry any increases in utility bills for customers. It is yet to be seen if we can continue to do it the way we’re doing it. I look forward to a new era when we have a more progressive nature of how we capitalize our new energy future.”
The commission also approved a build-ready program for NYSERDA, which will focus on developing properties that are fundamentally different from those that private developers would typically consider for investment.
The PSC accepted NYSERDA’s “rules of engagement” regarding the agency’s work with site owners and private developers, rules designed to mitigate any competition with private developers.
The commission said it “declines to adopt the ACE NY proposal to create a formal mechanism whereby developers can propose potential build-ready sites to NYSERDA as doing so would add additional complexity to the site selection process and does not appear to be necessary at this time.”
FERC on Thursday declined to rehear its February order approving a NYISO proposal to apply buyer-side mitigation to energy storage resources (ESRs). The 2-1 ruling expanded on the previous order and drew another sharp dissent from Commissioner Richard Glick, the lone Democrat on the commission (EL19-86-001).
The commission continued to find that the New York Public Service Commission and the New York State Energy Research and Development Authority “failed to show that applying buyer-side market power mitigation [BSM] to electric storage resources in NYISO is unjust and unreasonable or unduly discriminatory or preferential” and asserted “that such mitigation does not inappropriately intrude on New York’s jurisdiction.”
Chairman Neil Chatterjee and Commissioner James Danly said the complainants failed to show that applying BSM to new electric storage resources offering into the NYISO capacity market is unjust or inconsistent with FERC Order 841.
They further said the commission’s denial of the requested exemption reflected reasoned decision-making based on substantial record evidence, including economic theory, and relied on the opinion of the NYISO’s Market Monitoring Unit that storage resources have the ability to suppress capacity prices absent appropriate mitigation.
“We continue to find that applying buyer-side market power mitigation to electric storage resources will protect the integrity of competition in the wholesale capacity market against unreasonable price distortions and cost shifts caused by out-of-market state support,” the order said.
Workers enter a container-size energy storage unit in New York. | NY-BEST
Glick said the commission “once again perverts buyer-side market power mitigation into a series of unnecessary and unreasoned obstacles to New York’s efforts to shape the resource mix.” It failed to justify the continued use of BSM measures against individual storage resources and explain its differing approaches to issuing exemptions from mitigation for different types of resources, he said.
“All told, today’s order aptly illustrates what a mess buyer-side market power mitigation has become in New York,” Glick said.
Free Markets
The commission said that under-mitigation of uneconomic entry can suppress capacity prices, over-mitigation discourages new entry, and that both extremes jeopardize long-term consumer interests.
Applying BSM to storage resources will protect the integrity of competition in the capacity market against unreasonable price distortions and cost shifts caused by out-of-market state support, the commission said, disagreeing with New York Transmission Owners’ contention that the commission presumed that storage resources participate in the capacity market on an aggregate basis.
“Rather, the commission was concerned with the combined effect that individual subsidized storage resources would have on clearing prices,” it said, noting that BSM “rules may change over time to protect the integrity of the capacity market.”
The commission also said it had not “conflated lower prices resulting from normal supply and demand (competition) with artificial downward price manipulation or … made any finding regarding the per se exercise of market power. … ESRs that receive out-of-market support are not competing on an equal basis with those resources that do not receive similar out-of-market support.”
Glick said the ruling was illogical; instead of promoting true competition, the commission’s approach to buyer-side market power “has degenerated into a scheme for propping up prices, protecting incumbent generators and impeding state clean energy policies.”
Although the specifics of the mitigation regimes vary among the Eastern RTOs, they all generally force new entrants to bid at or above an administratively determined estimate of what a new resource “should” cost, while existing resources are permitted to bid at a lower level, Glick said.
The more the commission interferes with state public policies under the pretext of mitigating buyer-side market power, the more it will force states to choose between their public policy priorities and the benefits of the wholesale markets that the commission has spent the last two decades fostering, Glick said.
“New York provides the perfect example, as the Public Service Commission has begun a proceeding to consider ‘taking back’ from NYISO the responsibility for ensuring resource adequacy,” Glick said.
He noted that numerous states are considering leaving the other Eastern RTOs’ capacity markets, which also have rules that hinder states’ exercise of their resource decision-making authority.
“We got to this point largely because of the commission’s misguided belief that it must ‘protect’ capacity markets from the influence of state public policies,” Glick said. “And the end result will be profoundly inefficient, no matter how many times my colleagues use the words ‘market’ and ‘competition.’ … It is becoming increasingly clear that, unless something changes, the commission’s effort to ‘protect’ NYISO’s capacity market may ultimately be what dooms it.”
FERC last week accepted PJM’s proposed Tariff revisions on five-minute pricing to resolve inaccuracy and dispatch misalignment issues.
In its order issued Oct. 13, the commission determined that PJM’s revisions were “just and reasonable enhancements to its pricing and dispatch methodologies” (ER20-2573). The RTO had calculated current prices based on a future dispatch interval, which FERC said contributed to a misalignment between pricing and dispatch.
PJM’s proposed short-term fixes revise the locational price calculator (LPC) to use the reference real-time security-constrained economic dispatch (RT SCED) case for the same target time. For example, the LPC would calculate prices for the interval from 11:55 a.m. to 12 p.m. using the RT SCED solution for a 12 p.m. target time.
Resource offers, parameters and ancillary service assignments would be inputs to the RT SCED cases. Offers for 11 a.m. to 12 p.m. would be effective through 12 p.m., with offers for 12 to 1 p.m. used for the dispatch target time of 12:05 through 1 p.m.
PJM control room | PJM
The commission said it agreed with PJM that the proposal to modify the LPC pricing program to use the approved RT SCED dispatch case for the same target time will better align pricing and dispatch intervals.
“Specifically, we find that PJM’s proposal will more accurately ensure that prices appropriately reflect the costs of the marginal resources consistent with the future timing of the dispatch instructions they receive,” the commission said.
In April 2019, the commission ordered PJM and NYISO to revise their tariffs to allow fast-start resources to set clearing prices, contending the current rules were not just and reasonable. (See FERC Orders Fast-start Rules for NYISO, PJM.) PJM submitted a compliance filing in July 2019 that the Independent Market Monitor, state commissions and consumer advocates argued didn’t provide clear evidence that it would implement fast-start pricing correctly. Those commenters noted that PJM uses a different market interval to compute dispatch instructions and calculate prices.
FERC delayed PJM’s follow-up fast-start compliance filing in January, giving the RTO until July to make a filing as members continued working on the issue in the stakeholder process. (See PJM, IMM at Odds on 5-Minute Dispatch, Pricing Rules.)
Several months of heated debate led to members endorsing short-term fixes aligning the LPC to use the reference RT SCED case for the same target time at the June MIC meeting. (See PJM 5-Minute Dispatch Proposal Endorsed.)
PJM’s accepted plan for short-term fixes to its fast-start pricing | PJM
Stakeholders officially endorsed the Tariff changes in an unusual unanimous sector-weighted vote at the Markets and Reliability Committee’s July 23 meeting while encouraging PJM to continue to pursue both intermediate and long-term changes. (See PJM Stakeholders OK 5-Minute Dispatch Proposal.)
In last week’s order, FERC rejected the Monitor’s arguments that PJM’s proposal “creates a systematic delay between the dispatch signal and pricing that undermines the incentive to follow dispatch” and that this mismatch “occurs for any price fluctuations due to changes in load or transmission constraints, not just shortages.”
“PJM’s proposal would better align calculated prices that determine real-time, five-minute settlements for generators with the timing of when they are expected to achieve their indicated dispatch levels,” the commission said.
FERC encouraged PJM to continue to work with stakeholders on long-term reforms in its efforts to address the pricing and dispatch misalignment.
The Tariff revisions took effect on Thursday. Approval of the PJM’s fast-start proposal is still pending.
Permits are the first things needed to continue developing a sustainable supply chain for the U.S. offshore wind industry. All else flows from that starting point, a panel told the American Wind Energy Association’s Offshore Windpower Virtual Summit on Wednesday.
“I’m tired of talking about potential; I want to talk about actual … and for that we need certainty and transparency,” said Aaron Smith, CEO of the Offshore Marine Service Association (OMSA), based in New Orleans.
Aaron Smith, OMSA | AWEA
Any time the U.S. maritime industry has had certainty and transparency, it has built and even overbuilt to the market need, from launch barges, to multipurpose supply vessels, to LNG carriers, Smith said.
“Every time there’s certainty and transparency, we have built to that market, but you need to have that transparency, and you need to have that certainty, and the first step to getting there is to have those permits being issued,” Smith said. “Permits equal certainty, equal a supply chain. So, that’s what we need to see. If we can have the certainty in investment, then we can capitalize on it.”
The first big OSW project in the permitting pipeline is the 800-MW Vineyard Wind project south of Martha’s Vineyard off Massachusetts, on which the U.S. Bureau of Ocean Energy Management expects to issue a final decision in December. (See Developers Seek 1-Mile Spacing for Vineyard Wind.)
Emmanuel Martin-Lauzer of Nexans High Voltage USA agreed with Smith, saying the U.S. market is difficult for investors to put money into without timely and predictable permits.
Despite the very slow start in the U.S. compared to Europe, Nexans, which has several offices around the country and in Canada, is adding submarine cable manufacturing capability to its existing facility in South Carolina.
Jones Act and More
OSW supply chain factors other than permitting include workforce training, the Jones Act requirement that vessels working coastal trade be built in the U.S., local content requirements, and the potential of benefiting from oil and gas industry assets and experience.
Maria Ravn, MHI Vestas OSW | AWEA
Moderator Maria Ravn, U.S. global supply chain management lead at turbine manufacturer MHI Vestas Offshore Wind, relayed an audience question on how the lack of Jones-compliant vessels is affecting planning or projects timelines.
Joris Veldhoven, Atlantic Shores | AWEA
“Is it a known fact that there are no available large installation vessels for turbines and foundations, at least for the monopile foundations?” said Joris Veldhoven, treasurer and commercial director of Atlantic Shores Offshore Wind, a joint venture created by Shell New Energies and EDF Renewables to develop a lease area off New Jersey.
“I think that’s a reality that all the developers can work around and are working around; all the projects along the East Coast are certainly maturing their development plans in sight of this,” Veldhoven said. “It has the potential to be a gamechanger … but when it comes to local content, even beyond the offshore scope, a lot of local content development is going on in spite of this.”
Smith said the question appeared targeted to wind turbine installation vessel (WTIV) fleets, and that floating platforms and jack-up heavy-lift vessels — and vertical lifts — don’t need to be Jones-compliant.
When Danish shipping company Maersk applied to do the installations for Vineyard, for example, it was going to use a foreign-flagged ship being supplied by U.S. feeder vessels, “so, that is a perfectly legal way for these operations to happen; so, no, there is no impact,” Smith said. “Now, how do we ensure that we have the U.S. feeding vessels? I know of at least four different companies that are looking to invest in this space, but they need certainty.”
Shipowners and builders have not yet seen the certainty to invest in feeding vessels, and some wonder if there is going to be a strict adherence to the Jones Act on this matter, or if WTIVs would be used to transport and install turbines and foundations, Smith said.
Diversification and Training
Edward Anthes-Washburn, New Bedford Port | AWEA
Edward Anthes-Washburn, executive director of the New Bedford Port Authority, which hosts the main OSW terminal for the state of Massachusetts, said Gulf of Mexico infrastructure tailored to oil and gas drilling can be repurposed for OSW, and that companies are looking at the downturn in oil and gas as an opportunity to diversify.
“Especially right now, with the price of oil so low, they’ve been cutting in half the deep-water drilling operations, so there’s a lot of equipment,” Anthes-Washburn said. “In the U.S. market, there’s a lot of expertise that exists in the gulf, and that’s what our target will look like 10 years from now — it will be a combination of northern Europe and southern Louisiana.”
Nexans’ Martin-Lauzer said that repurposing the feeder barges and jack-up feeder barges developed in the gulf wouldn’t necessarily cost much more because those jack-up vessels are very expensive by the day, and using feeder vessels would actually minimize the amount of time the jack-up rig has to be offshore.
Emily Kuhn, Renewables Consulting Group | AWEA
And the skills needed to run those vessels and operate the heavy machinery already exist in the Gulf, with “200 of 800 vessels out of action now because of the downturn in the oil and gas sector,” Smith said.
Emily Kuhn of The Renewables Consulting Group said the Northeast also has a skilled workforce, but that more people will be needed for an estimated $80 billion in OSW construction contracts over the coming decade, and the sooner people can start being trained for such jobs, the better.
“So that when the time comes, we don’t have a non-U.S. labor force coming in and taking the jobs … training can help make the U.S. on a par with more experienced workforces around the world,” Kuhn said. “The jobs will follow the infrastructure and … the jobs do not end up moving to Europe.”
FERC staff expressed confidence Thursday that the North American bulk power system has sufficient reserves to make it through the winter comfortably.
But they also said utilities must be prepared for further impacts from the COVID-19 pandemic and constraints on the availability of natural gas and fuel oil.
Winter 2020/2021 temperature forecasts | National Oceanic and Atmospheric Administration
Presenting FERC’s 2020/2021 Winter Energy Market and Reliability Assessment, Louise Nutter of the Office of Electric Reliability told the commission that the impact of the pandemic in winter is hard to judge in advance. While many of the worst disruptions — natural gas and crude oil prices, and electric load reductions because of stay-at-home orders — have eased since spring, further impacts depend “on whether COVID-19 cases rise across the United States and whether states increase mitigation measures.”
Staff highlighted several areas in which the pandemic appears to have brought lasting, or at least ongoing, change. The first is the shape of the daily demand curve, with weekday loads peaking “later in the morning and earlier in the afternoon compared to before the pandemic” — a phenomenon already noted by NERC regional entities earlier this year. (See Sagging Demand Cushions NPCC’s Summer Outlook.)
Utilities are also continuing to take the coronavirus into consideration in the form of new procedures to keep their personnel safe from infection through, for example, guidelines requiring social distance during operations and expanding stocks of personal protective equipment. These have been in place for many entities since before summer; however, with no firm idea of when the crisis will end, utilities are having to adjust what most assumed to be temporary measures to last indefinitely. (See NERC Planning Lessons Learned on COVID-19 Response.)
Finally, these pandemic-related scheduling issues also caused many entities to forgo maintenance planned for spring until autumn. (See COVID-19, Hurricanes Among Biggest Summer Threats.) Most of this work has been completed during “a compressed fall maintenance season,” but utilities have expressed concern about the possibility of the remaining maintenance interfering with winterization activities, along with unforeseen complications from the delay.
Reference Margins Looking Good
Outside of potential coronavirus issues, FERC said all regions appeared set to meet their reference margin. SERC-E, representing North and South Carolina, had the lowest reserve margin; however, its expected reserves of 22% still comfortably exceed NERC’s reference margin of 15%.
Weather is the primary driver of confidence, with the National Oceanic and Atmospheric Administration predicting normal temperatures or higher for most of the U.S. aside from the upper Northwest and Upper Midwest, which were assessed a 33% probability of below-normal temperatures. The mild conditions are expected to drive down demand for natural gas for heating in most areas, freeing up stockpiles and pipelines to be used for power generation.
On the generation side, the report predicts current trends of “increasing gas and renewable capacity with decreasing net capacity of coal and nuclear plants” to continue, with solar, wind and natural gas-fired plants comprising nearly all the capacity to be added by February 2021. Even with these additions, the share of electric generation coming from gas nationwide in the winter is projected to decrease from 38% last winter to 34% this year; NYISO and PJM are the only regions expected to grow their shares of gas-fired generation.
Gas Bottlenecks Possible for New England
New England represents the area of greatest concern for FERC, holding “the greatest risk of fuel shortages and related market stress” because of the widespread use of natural gas for both heating and power generation, which can produce bottlenecks on cold days even in the milder conditions predicted for this winter. Peak load for ISO-NE is forecast to hit 23,373 MW in the 2020/21 winter season, higher than last year’s peak of 22,319 MW but still within the regional capacity of about 31,000 MW.
Strains on natural gas supply lines could be exacerbated this year because of decreased demand for oil, which has reduced the availability of natural gas derived from oil production. Gas is also expected to be even more prominent in the resource mix than usual this winter because of the recent retirement of two nuclear plants — the 680-MW Pilgrim facility in Massachusetts in May 2019 and New York’s 1,000-MW Indian Point Unit 2 in April 2020.
California, the only other region highlighted in FERC’s report, may see oversupply conditions when generation from hydro, wind and solar facilities exceeds load, a regular occurrence in late winter. In February, for example, CAISO curtailed 157 GWh of energy, 8% of which came from solar generation; by contrast, in July the ISO curtailed only 31 GWh.
Asked by Commissioner Richard Glick whether CAISO is taking steps to reduce curtailments so that renewable generation capacity is used as much as possible, a staffer from FERC’s Office of Energy Policy and Innovation said the ISO is looking at “a number of possible solutions, [including] increasing the flexibility of existing resources through enhancing demand response initiatives, reducing minimum operating levels for generators and greater regional coordination through the Western Energy Imbalance Market.”
More Findings
Additional significant conclusions from the report include:
Natural gas consumption by the electric power sector is expected to average 24 Bcfd, down 20% from winter 2019/2020. This represents a departure from the 5% average growth annually since winter 2015/2016 and is attributed to lower anticipated electricity production both from the mild weather and continuing coronavirus-related load decreases.
U.S. exports of LNG should average 9.4 Bcfd, up 22% from winter 2019/20 levels thanks to increased U.S. liquefaction capacity and rising international demand. Gross U.S. LNG imports are expected to average 367 MMcfd, a 13% year-on-year increase.
Natural gas storage inventories are expected to begin the winter withdrawal season at 3.95 Tcf, “the third highest inventory level in the past 10 years,” and end the season at 1.34 Tcf, representing the third-lowest level in the last decade.
FERC on Thursday approved most of PJM’s compliance filing on its expanded minimum offer price rule (MOPR) while reversing its position on state-directed default service auctions (EL16-49-003, et al.).
The commission said it agreed with PJM and commenters to exclude “independently evaluated, non-discriminatory, fuel-neutral, competitive state-directed default service auctions from application of the expanded MOPR.”
“Based on the record in this proceeding, we find that competitive and non-discriminatory state-directed default service auctions — i.e., those state-directed default service auctions that qualify to be excluded from the definition of state subsidy under PJM’s proposal — do not require mitigation at this time.”
The commission also rejected PJM’s proposed revisions to the market seller offer cap as beyond the scope of the compliance proceeding.
In March, PJM made a 683-page filing proposing Tariff revisions in response to FERC’s December order expanding the MOPR to new and existing state-subsidized resources. The order included exceptions for existing demand response, energy efficiency, self-supply and resources receiving payments under renewable portfolio standards. In June, PJM submitted proposed additional Tariff revisions to comply with the commission’s April 16 order on rehearing.
More than two dozen companies and coalitions had filed responses to PJM’s compliance filing, taking issue with the RTO on auction timing, floor prices, unit-specific rules and self-supply exemptions. (See Commenters Weigh in on PJM MOPR Compliance Filing.)
The order was supported by Chairman Neil Chatterjee and Commissioner James Danly, both Republicans, while Democrat Richard Glick issued a six-page dissent.
“At this point, there is not that much left to say,” Glick wrote. “This proceeding has been one of the commission’s all-time worst, both in the baffling decisions it reached and the bumbling way in which it got there. Today’s order only digs the hole deeper.”
| Richard Glick via Twitter
Glick said he was relieved that the commission had reversed its treatment of state default service auctions, calling its original position “a harebrained idea.”
“Even parties that have cheered on the commission’s general MOPR zealotry have balked at applying MOPRs to default service auctions,” he noted.
But he said the commission’s limited rehearing may be moot because of its suggestion that New Jersey’s default service auction would constitute a state subsidy based on the possibility that the auction winners would have to comply with the state’s renewable portfolio standard.
“The commission’s discussion of the [New Jersey] auction provides every reason to believe that the grant of rehearing on state default service auctions will end up being almost meaningless. Several other PJM states’ descriptions of their default service auctions also mention renewable portfolio standards or similar programs applying to entities that provide default service. Taken seriously, the commission’s discussion of the [New Jersey] auction would seem to suggest that payments from those other states’ auctions would also trigger the MOPR.”
Glick predicted “the PJM MOPR saga will ultimately be remembered as a model case of egregious commission overreach. The majority has taken MOPRs, already a controversial topic, and thoroughly weaponized them as a tool for increasing prices and stifling state efforts to promote clean energy. The result is an unsustainable construct that will eventually collapse under its own weight. The commission’s contortions on default service auctions and its failure to address the most important questions implicated by today’s order are just the latest indicator of that inevitable result. At this point, the only real question remaining is how much damage the commission’s arrogant approach to the states will do in the meantime.”
Chatterjee insisted the ruling was a “market protective reform.”
“I’m proud of the actions the commission has taken to protect the integrity of the PJM capacity market,” Chatterjee said. “Markets are, in my view, simply the best way to pave the way towards our energy future.”
He said that when renewable resources and new technologies are given the chance to compete, they can thrive in the marketplace, but there has to be transparent and efficient markets as a baseline. He said creating a baseline is the “core aim” of the MOPR.
Here is a summary of the commission’s 162-page order.
Resources Subject to the Expanded MOPR
FERC accepted PJM’s proposed Tariff revisions to apply the MOPR to any capacity resource that receives or is entitled to receive a state subsidy.
It accepted PJM’s position that sellers involved in bilateral transactions should be permitted to choose the competitive exemption in cases where the rights and obligations of multiple off-takers are in equal shares. “Consistent with the directives of the December 2019 order, we reiterate that only the portion of the resource receiving a state subsidy will be subject to mitigation,” FERC said.
It also accepted PJM’s proposal regarding resources not subject to the must-offer requirement. “We disagree with the Market Monitor that the entire capacity of such a resource must be offered into each auction, including incremental auctions, to maintain its status as an existing resource, because the rehearing order did not require that,” FERC said.
The commission also rejected the Monitor’s argument regarding fixed resource requirement (FRR) resources, approving PJM’s proposal that resources in FRR capacity plans will not lose their status as cleared capacity resources with state subsidies solely because they participate in such a plan instead of the Base Residual Auction (BRA) for a given auction.
Definition of State Subsidy
FERC accepted PJM’s proposed definition of state subsidy, which incorporated the commission’s definition. The commission rejected the Environmental Defense Fund’s complaint that the definition is vague and does not put market participants on notice of what is considered a state subsidy, calling it “essentially an out-of-time rehearing request of the December 2019 order,” which defined state subsidy.
General Industrial Development and Local Siting Support
The commission accepted PJM’s proposal to exclude generic industrial development and local siting support from what is considered a state subsidy, rejecting a proposal by Dominion Energy. “Dominion incorrectly suggests that any subsidy that is widely available would be exempt, regardless of whether it met the criteria for general industrial development or local siting support subsidies laid out in the December 2019 order,” FERC said. “The December 2019 order, as reiterated in the rehearing order, found that only payments which were designed to provide an incentive or promote general industrial development in an area or siting facilities in one locality over another are exempt.”
Bilateral Contracts with Self-supply
PJM’s proposal to exclude from the MOPR some voluntary bilateral contracts entered into by self-supply entities also won FERC’s approval.
“We agree that, where the otherwise unsubsidized resource contracts with a self-supply entity and the transaction meets the requirements under PJM’s proposal, the unsubsidized seller does not have the ability to enter into a contract below cost, nor would the unsubsidized resource have guaranteed cost recovery if it offered the capacity into the market below cost,” FERC wrote.
The commission rejected a proposal by American Electric Power and the Organization of PJM States Inc. (OPSI) to include an exemption for all bilateral transactions as “unnecessary.”
“The commission expressly found in the December 2019 order that private, voluntary bilateral transactions did not need to be mitigated.”
It also disagreed with the contention by some intervenors that energy-only bilateral sales to self-supply entities cannot convey a state subsidy. “Rather, if an energy-only bilateral contract entered into by a self-supply entity meets the requirements set forth in PJM’s proposal, then that contract is excluded from the definition of state subsidy. Otherwise, as the rehearing order found, the expanded MOPR applies to bilateral contracts entered into by self-supply entities. The record provides no basis for generally distinguishing bilateral contracts for energy from other bilateral contracts entered into by self-supply.”
It also rejected requests to require PJM to allow a competitive exemption for self-supply transactions that are shown to be competitive or that the RTO and the Monitor review self-supply contracts and determine whether the contract conveys a subsidy.
“If a state-subsidized resource is truly competitive, the resource can use the resource-specific exception to offer less than the default offer price floor, thereby permitting resources to show they are truly participating competitively and protect market integrity,” FERC said.
FRR Revenue
FERC approved PJM’s proposal that any revenue for providing capacity as part of an FRR capacity plan or through bilateral transactions with FRR entities will not be considered a state subsidy.
It disagreed with the Monitor’s contention that any FRR revenue should be considered a subsidy even if it does not meet the definition.
Market Seller Offer Cap Provisions
FERC rejected PJM’s proposed revisions to the market seller offer cap, saying the cap has “never been a subject of this [Federal Power Act] Section 206 proceeding.”
“Neither the December 2019 order nor the rehearing order directed changes to the market seller offer cap provisions or found that sellers should be able to offer above the default market seller offer cap without a resource-specific review, as currently required by the Tariff.”
The commission said it understood PJM’s concern that sellers may be left without a valid offer under potentially conflicting Tariff provisions when the default or resource-specific offer price floor for a resource is higher than the cap for such a resource. “In such a circumstance, we find that the resource should submit an offer using the resource-specific review process,” FERC said.
Self-supply Exemption
FERC accepted PJM’s proposal regarding the self-supply exemption. It rejected a request for clarification by Southern Maryland Electric Cooperative, saying “an executed bilateral contract alone is not one of the eligibility criteria for the exemption.”
RPS Exemption
The December order, as modified by the rehearing order, directed PJM to include an exemption for renewable resources receiving support from state-mandated or state-sponsored RPS programs.
PJM’s proposed RPS exemption was accepted in part, with the commission requesting a modification directing the RTO to modify Tariff language related to eligibility for exemptions to state that “a capacity resource may qualify for the exemption if it is the subject of an interconnection service agreement that is executed by the interconnection customer on or before Dec. 19, 2019.”
DR/EE/Storage Exemption
FERC directed PJM in the December order to include a DR, energy efficiency and storage resource exemption that would meet at least one of three criteria to be eligible: have successfully cleared an annual or incremental capacity auction prior to Dec. 19, 2019; have completed registration on or before Dec. 19, 2019; or have a measurement and verification plan approved by PJM for the resource on or before Dec. 19, 2019.
The commission mostly accepted PJM’s proposal, directing further compliance on the RTO’s proposal regarding utility-based residential load curtailment programs. FERC directed PJM to remove a parenthetical statement “(or for utility-based residential load curtailment program, based on the total number of participating customers)” from Attachment DD, section 5.14(h)(7)(a).
“The rehearing order requires aggregators and curtailment service providers (CSPs) to be considered to have previously cleared a capacity auction only if all the individual resources within the offer have cleared a capacity auction either on their own (i.e., individually) or as part of an offer from an aggregator or CSP,” the commission said.
Competitive Exemption
The December order directed PJM to include a competitive exemption for both new and existing resources, other than new gas-fired resources, that certify to the RTO that they will forego any state subsidies. The rehearing order further clarified that the competitive exemption is available to state-subsidized resources “receiving or entitled to receive a state subsidy that certify they will forego the state subsidy,” noting that all resources seeking to use the competitive exemption must certify whether or not they receive, or are entitled to receive, a state subsidy.
FERC ordered PJM to submit an additional compliance filing, directing the RTO to modify its proposal regarding the gaming provisions that dictate “under what circumstances a resource that elects the competitive exemption and then accepts a state subsidy will forfeit its capacity revenue.”
The commission also rejected PJM’s proposal that, going forward, any capacity resource that cleared an auction before it received or became entitled to receive a state subsidy shall be deemed a cleared capacity resource with state subsidy, rather than a new capacity resource with state subsidy.
Default Offer Price Floors
FERC approved PJM’s proposed gross cost of new entry (CONE) values except for the energy efficiency value, which it deferred to a separate proceeding on reserves, in which the commission found the RTO’s methodology for calculating the energy and ancillary services offset (E&AS) unjust and unreasonable (EL19-58). A compliance filing that includes a new proposal for EE gross CONE in that docket is pending before the commission.
FERC accepted PJM’s proposed gross avoidable-cost rate (ACR) values and its proposal to adjust the Tariff-stated gross CONE values for combustion turbine and combined cycle resources annually using the applicable Bureau of Labor Statistics Composite Index.
The commission accepted in part, and rejected in part, PJM’s proposal regarding default offer price floors for generation-backed DR. Specifically, FERC accepted PJM’s proposed gross CONE and ACR values for generation-backed DR diesel resources but rejected the RTO’s proposal to use those values for other types of behind-the-meter generation because it was not consistent with prior orders.
“We have already found that behind-the-meter generators should have the same costs as front-of-meter generators of the same type,” the commission said. “The rehearing order found that behind-the-meter generators should not receive special treatment and that parties failed to present evidence ‘why a specific type of generator should have fundamentally different going-forward or construction costs depending on whether it exists behind or in front of the meter.’”
Resources not Subject to the Must-offer Requirement
FERC directed PJM in the December order to propose default offer price floors for all other types of resources that participate in the capacity market, with the rehearing order clarifying specifically that the RTO should propose default offer price floors for seasonal resources.
The commission approved PJM’s proposal that the offer price floor should be applied regardless of the actual sell offer quantity or the resource’s status as a seasonal Capacity Performance resource, for both the default offer price floors and the resource-specific offer price floors.
“We agree with PJM to base the offer price floor on the capacity resource’s full capacity capability ensures cost recovery, and no more, for each megawatt-day offered and cleared,” the commission said.
The December order directed PJM to maintain the “resource-specific exception,” expanding it to cover existing and new state-subsidized resources of all resource types and to permit “any resource that can justify an offer lower than the default offer price floor to submit such offers for review.”
PJM proposed two options for sellers seeking the resource-specific exception: an offer that considers only costs related to participating in the capacity market and meeting a capacity commitment, and an offer that considers all costs and permissible revenues.
“The first option is not consistent with the rehearing order, which found that behind-the-meter resources should not be treated differently solely because they are behind-the-meter and directed that all resources of a particular technology type should be treated the same,” the commission said, approving the second option.
Certification
PJM proposed that each seller inform the RTO whether its resource is state-subsidized during the pre-auction registration process. It included provisions that the information must be provided no later than 120 days prior to the annual capacity auction for each seller other than DR and EE resources, which would have a 30-day deadline.
The commission accepted PJM’s certification proposal in part, approving the RTO’s proposed deadlines, but created a stipulation that if any changes in a state subsidy status occurs within 30 days of the auction, sellers will have five days to notify the RTO of the change.
Fraud or Material Misrepresentations
PJM proposed that if it or the Monitor suspects “misrepresentation or omission in the relevant certification,” either entity may request additional information to be provided within five business days.
The commission accepted PJM’s proposal and declined to direct the RTO to remove Tariff references describing the Monitor’s role as “advice and input.”
“Contrary to the Market Monitor’s contention, stating that the Market Monitor will provide advice and input to PJM does not mean that the Market Monitor’s role as independent evaluator is diminished or change the fundamental roles between PJM and the Market Monitor related to the capacity market,” the commission said.
Waiver Request and Auction Schedule
The December order directed PJM to provide revised dates and timelines for the BRA associated with delivery year 2022/2023 (2019) and related incremental auctions, along with revised dates and timelines for the BRA associated with delivery year 2023/24 and related incremental auctions, as necessary.
The commission granted PJM’s waiver allowing the pre-auction process to begin two weeks after FERC issued the order, with the next annual capacity auction to be conducted in six and a half months.
Replacement Capacity
The rehearing order clarified that capacity from state-subsidized resources cannot serve as replacement capacity “bilaterally procured to fulfill a capacity commitment for an unsubsidized resource.”
The commission determined that it’s not consistent with prior orders to allow a state-subsidized resource to evade the MOPR through a bilateral transaction, regardless of the term of the transaction. The order acknowledged PJM’s concern that the change “would inhibit the ability for capacity market sellers of jointly owned resources to replace resources within their own portfolios.”
But the order said the modified provision that removed the phrases “short term” and “one year or less” from Attachment DD section 4.6(e) was just and reasonable and followed the Monitor’s position that this provision should extend to replacement capacity within portfolios as well.
“It is not consistent with the prior orders, or just and reasonable, to allow a supplier to game the expanded MOPR by switching the capacity obligations within its portfolio to alternative resources,” the commission said.
The commission accepted only the proposed changes to existing Attachment DD section 5.14(h), which are related to the replacement rate, and accepted PJM’s proposal to change the name of the section to “Minimum Offer Price Rule for Certain New Generation Capacity Resources that are not Capacity Resources with State Subsidy.” All other changes in the section were rejected as being outside of the scope of the filing.
The rehearing order clarified that the December order did not direct any changes to PJM’s pre-existing MOPR and that the RTO’s compliance filing “should not contain any substantive changes to that section unrelated to the replacement rate.” But the rehearing order explained that state-subsidized resources should be subject to the MOPR regardless of their location with respect to the expanded MOPR.
When the governors of Connecticut, Maine, Massachusetts, Rhode Island and Vermont released a joint statement Wednesday calling for reforms to ISO-NE, it read less like an olive branch and more like a precursor to a seismic shift in relations between the states and the RTO.
The governors said they “require” changes to market design, transmission planning and RTO governance, which they said are stunting their efforts to reduce economy-wide greenhouse gas emissions. The New England States Committee on Electricity (NESCOE) will specify the reforms in a soon-to-be-released document. (See related story, New England Governors Call for RTO Reform.)
“I think it’s clear that the governors are saying what’s happening right now can’t and won’t persist. ‘We will change it,’” said Theodore Paradise, senior vice president of transmission strategy and counsel at Anbaric. “‘Let’s try to work together to change it,’ but sort of the next step — hidden or embedded in this language — is ‘we will get there, one way or the other.’ This is really not an optional conversation or a request. This is more of a directive of what we as a region are going to do.”
Katie Dykes, commissioner of Connecticut’s Department of Energy and Environmental Protection, said, “The best path for us is one that centers on coordination and cooperation with our neighboring states,” and the governors’ statement speaks with “a unified voice” about what states expect from the RTO in the future.
Dykes said the federal government “unfortunately” has taken a step back on climate change leadership, leaving New England states on “the front line for combating climate change.”
“It’s very important that states have appropriate involvement in the design of market-based mechanisms to achieve our decarbonization policies,” Dykes said. She added that “ratepayers are being saddled with duplicative costs. We have a market design that is actively preventing our state from getting credit for clean energy resources that we have had to procure outside of this market because the market is not designed to incentivize investment in the resources that we need. It’s inefficient. It’s unnecessarily costly. It cannot continue.”
Dykes said the nonpublic NEPOOL stakeholder process needs to be open to state lawmakers so that “very knowledgeable folks who participate in the NEPOOL discussions engage with some of the policymakers at the state level who have concerns and preferences around what our grid should look like and what value should be provided for our ratepayers.”
Ari Peskoe, director of the Harvard Electricity Law Initiative, said the statement was “a long time coming.”
“It was good to see a real strong statement from the governors about what they do want to see and what they think the future of the sector should look like,” Peskoe said. “I thought that was a real positive step forward that five governors were willing to sign on to this.”
As for New Hampshire not being a signatory, Peskoe said it “is the clear laggard state in terms of clean energy ambitions” and that Republican Gov. Christopher Sununu “has, at best, been lukewarm on clean energy.” The five other governors lead states with “aggressive, clean energy targets.”
“What I’ve seen from NESCOE in the past was wanting to reach consensus before issuing any sort of statement, and that had the effect of weakening the group’s ambitions,” Peskoe said. “I thought it was interesting that this time [NESCOE] decided they weren’t going to wait for New Hampshire to call for the regional clean energy solution.”
Advanced Energy Economy Director Caitlin Marquis, whose work in part focuses on ISO-NE, said she is “cautiously optimistic that this is a positive development, and that the ISO will be similarly willing to work constructively with the states to address some of the concerns.”
Marquis added that there is a carrot-and-stick aspect to it.
“I think it’s an ask that the ISO engage and the states get a bigger role,” Marquis said. “If they’re able to come to some alignment on the concerns the states have on clean energy, there could be a constructive path forward there. I think the New England states have been clear that they don’t have an issue with a carbon price but want an economy-wide solution. There are some specific concerns with an ISO carbon price, and I do think there’s frustration that that message has not gotten through.”
MISO and SPP state regulators appear intent on completing their work to improve the RTOs’ interregional coordination before 2021 arrives.
The Seams Liaison Committee (SLC), comprising regulators from the Organization of MISO States and SPP’s Regional State Committee, met virtually and briefly Monday, deciding to develop a decision matrix to help them prioritize the various recommendations offered up for their consideration.
Admitting he may have had “reckless optimism about wrapping up at the end of the year,” Arkansas’ Ted Thomas, SLC co-chair along with Texas’ DeAnn Walker, said the matrix should “do good,” given the difficulty of holding in-depth discussions over the internet.
“The joy of virtual meetings,” he said.
Thomas, Walker and OMS Executive Director Marcus Hawkins will work together on the decision matrix. They hope to have a workable format that they can discuss with the full RSC and OMS on Oct. 26 and 29, respectively.
Walker said she wanted to have an “orderly way” to step through the recommendations made by the RTOs’ market monitors. That came into clearer focus, she said, as Hawkins went through a list of recommendations and the grid operators’ responses. (See MISO, SPP Respond to Monitors’ Studies.)
SPP responded to recommendations for coordinated transaction scheduling, interface pricing and the MISO Independent Market Monitor’s report on market-to-market (M2M) coordination. Staff added clarifying remarks and noted which recommendations are included in SPP’s 2020 Market Roadmap.
MISO detailed its responses to the same recommendations, noting whether they have been included in its Integrated Roadmap or the IMM’s 2019 State of the Market report.
