FERC has allowed MISO to avoid eight years of resettlement work on certain manual dispatches dating back to early 2009.
The commission last week did not act on MISO’s longstanding Tariff violation. The grid operator may have miscalculated on some make-whole payments to resources that were manually dispatched from January 2009 to May 2018 (ER18-1611).
Commissioner James Danly concurred with the decision while castigating FERC’s multiple other waiver approvals.
MISO said that during a 2018 quality check, it discovered that its settlement system was not technically handling manual redispatch as outlined in its Tariff. It said its software was setting dispatch instructions to a specific level, rather than a range of acceptable dispatch levels as described in the Tariff. The RTO also said its software was checking for economic dispatch statuses in both the day-ahead and real-time markets, when its Tariff does not require such a check for economic status in the day-ahead market.
The financial fallout from the eight-year inconsistency totaled just $1.6 million, or $200,000 annually, MISO said. The grid operator said manual redispatch was necessary in a little more than 1% of all make-whole payment hours since 2009.
MISO also said its Independent Market Monitor did not find any generators “intentionally making inflexible offers … to gain excess margins from the system during intervals that a resource was manually redispatched.”
MISO control room | MISO
FERC said that while the discrepancy amounted to a nearly decadelong Tariff violation, the amounts were too small to be reopened, calling resettlement counter to public interest.
“We agree with MISO that, based on the circumstances here, market resettlement and refunds are not an appropriate remedy,” FERC said. “We are persuaded that, to the extent resettlement of the market transactions at issue would be feasible, requiring such resettlement and associated refunds could create inequitable results by unfairly punishing market participants that followed MISO manual redispatch instructions and could undermine confidence in market outcomes.”
The commission cited its “broad authority” to determine remedies for Tariff violations. It also said that because it was not directing resettlement or refunds, it was not required to address MISO’s waiver of its Tariff during the discrepancy.
Danly said he agreed with the decision, unlike the nine waiver approvals issued during FERC’s open meeting Thursday. He said that in this instance, FERC did not exceed its legal authority by granting a backdated waiver that could violate the filed-rate doctrine and rules prohibiting retroactive ratemaking. Instead, he said, the commission confirmed the violation between settlement software and Tariff language and disregarded the request for waiver.
“I agree with this holding. In my view, this is the approach we should take in all situations where a utility has violated its own tariff,” Danly said, noting MISO’s “relatively small error and the extreme difficulty in resettling bills back to 2009 support this decision.”
Danly also said FERC should have first denied MISO’s waiver request, then made the finding that the RTO violated its Tariff to keep the commission’s decision-making process uniform and orderly.
In a 142-page ruling Thursday, FERC partly affirmed an administrative law judge’s decision on Pacific Gas and Electric’s proposed increases to its transmission rates, reversing the judge on the utility’s cost of long-term debt and other issues (ER16-2320).
The commission directed further briefing on PG&E’s return on equity and told the utility to recalculate its tariff rates based on the ROE and other factors.
PG&E filed its 18th revised transmission owner tariff in July 2016, which was followed by numerous objections. After an evidentiary hearing, the judge ruled in October 2018 on 11 disputed categories including ROE, capital structure and depreciation rates.
The judge found PG&E’s forecasted cost of long-term debt to be unreasonable, ordering it be reduced, and lowered its ROE from a proposed 10.4% to 9.13%, which the company said was too low and objecting parties said was too high.
A panel at last week’s Energy Bar Association annual Fall Conference examining FERC’s response to the D.C. Circuit of Appeals’ Allegheny Defense Project v. FERC ruling evolved into an in-depth Q&A with panelist David Morenoff, FERC’s acting general counsel.
Allegheny upended longstanding FERC practice by barring the commission from using tolling orders to delay judicial review under the Natural Gas Act and Federal Power Act. The July order by the D.C. Circuit Court of Appeals concluded that the commission’s use of tolling orders to stop the 30-day clock for acting on rehearing requests improperly prevents litigants from appealing its rulings indefinitely even as it allows gas pipeline companies to seize property under eminent domain and begin construction. (See D.C. Circuit Rejects FERC on Tolling Orders.)
Adrienne Claire, Thompson Coburn | Energy Bar Association
Moderator Adrienne Claire, a partner with Thompson Coburn, noted that FERC Chairman Neil Chatterjee and Commission Richard Glick asked Congress to provide the commission with a “reasonable amount of time to act on rehearing requests.” (In light of Allegheny, FERC must now respond to all rehearing requests within 30 days or they are deemed denied “by operation of law.”)
“What would be a reasonable amount of time in your opinion? What’s feasible?” Claire asked.
Morenoff said Chatterjee developed “great respect” for members of Congress and their staff from both parties through his extensive experience working on Capitol Hill, “so he leaves to Congress the question about what will be the reasonable amount of additional time if Congress were to respond to that call and take action.”
Morenoff pointed to two bills introduced into Congress last spring, H.R. 6982 and H.R. 6963, to address rights to timely rehearing of FERC decisions under the NGA and FPA, respectively. The two bills would set rehearing time frames to 90 days under the NGA and 120 days under the FPA, “perhaps reflecting the relative greater complexity that we often see in rehearing requests under the FPA with respect to particularly the organized markets,” he said.
“I think that those provide a really good starting point for discussions that are proceeding on the Hill,” Morenoff said.
In response to Claire’s question about what changes FERC has already made in response to Allegheny, Morenoff said that, even before Allegheny, Chatterjee had directed commission staff to expedite actions on rehearing requests, especially regarding landowner requests in gas pipeline certificate proceedings.
David Morenoff, FERC | Energy Bar Association
“We have been doing coordination among not only the sections across [FERC’s Office of the General Counsel], including the rehearings section that we set up in February, but among the various program offices at FERC that work closely on a rehearing request … and I think that’s just more important now as we try to move even more quickly to cover that same ground in a post-Allegheny world,” Morenoff said.
Allegheny also prompted FERC to begin issuing two types of new notices in response to rehearing requests, Morenoff said. The first states that “rehearing may be deemed denied, period,” while the second says that “rehearing may be deemed denied and the commission intends to issue a further order on the merits addressing arguments on rehearing,” he said. (See FERC will not Seek SCOTUS Review of Tolling Decision.)
“We’ve been trying to move quickly on those second orders, but I think both of those notices indicate that the commission is going to put more emphasis on our underlying orders more often because, as we’re trying to move more quickly, the old kind of standing rehearing order that would have a lengthy background section, then summarize the order in detail, then summarize all the arguments raised in rehearing, that probably isn’t possible anymore given these time frames,” Morenoff said.
‘Uphill Battle’
“One of the issues that was percolating a few years ago was whether in the absence of a quorum, FERC could even issue a merits order on rehearing, much less a tolling order,” an audience member said. “Do you think the Allegheny decision gives us any insight into how the courts might resolve that issue?”
“I don’t think that Allegheny sheds a great deal of light on that subject, but I think it’s a very important question because regrettably we’ve had less time recently with five commissioners that all of us inside and outside would like,” Morenoff responded. He noted that when the commission realized it would be dropping below quorum in 2017, it issued an order that covered the delegation of additional responsibilities to staff.
“At the time, based on the research we had done, we felt quite confident that as long as there is a proper delegation from the quorum of the commission, there’s quite a good deal that can be done by staff,” he said.
Claire turned to the broader panel to pose a hypothetical question about how the Supreme Court would have responded had FERC appealed Allegheny, a step the commission said last month it would not take.
“I think there’s a decent chance the court would’ve granted review because it has a pretty high rate of granting petitions when the government is asking it to do so,” said Erin Murphy, an Environmental Defense Fund attorney.
But Murphy thought FERC would have faced a “pretty uphill battle” on appeal because the court, while potentially sympathetic to FERC’s arguments about the tolling orders as a longstanding policy matter, would still doubt that the rehearing delays complied with what Congress was “trying to accomplish” when it set rehearing request deadlines under the NGA.
“There’s certainly arguments about congressional acquiescence, and there’s a lot of water under the bridge at this point, but I think that there’s just that dynamic of [the rehearing delays] feeling like circumvention that would’ve been hard to overcome at the court,” Murphy said.
NERC prepares the list of risk elements annually to help regional entities and utilities plan for the year ahead. Risk elements are identified according to the ERO Enterprise Guide for Compliance Monitoring through compliance filings, event analysis and data analysis. The organization also solicits input from ERO Enterprise staff and committees, such as NERC’s Reliability Issues Steering Committee (RISC), and reviews the State of Reliability report as well as other publications.
This year’s report identifies the following risk elements for the coming year:
remote connectivity and supply chain;
poor quality models impacting planning and operations;
loss of major transmission equipment with extended lead times;
inadequate real-time analysis during tool and data outages;
determination and prevention of misoperations; and
gaps in program execution.
While the COVID-19 pandemic did not gain its own spot on the list, drafters incorporated its impacts into several of the risk elements. Although NERC and other organizations had prepared contingency plans for a pandemic, the arrival of an actual crisis exposed some mistaken assumptions. (See Pandemic Poses Long-term Reliability Challenges.)
“Pandemic risk differs from many of the other threats facing the BPS because it is a ‘people event,’” the report says. “The fundamental risk is the loss of staff critical to operating and maintaining the BPS such that firm loads could no longer be served reliably and securely. Regions may consider reviewing requirements related to personnel training in order to address this risk.”
Remote Work Raises Cyber Risks
The coronavirus impacts are particularly visible in the entry for remote connectivity and supply chain, which highlights entities’ shortfalls in addressing cybersecurity. Cyber hygiene became an unexpectedly pressing issue this year when many entities transitioned to a remote work posture, greatly expanding the “attack surface” for malicious actors who may try to exploit employees distracted from best practices by family or personal challenges. (See PPE, Testing Top Coronavirus Concerns for NERC.)
“Regardless of the sophistication of a security system, there is potential for human error,” the report notes. “If security has increased the difficulty in performing personnel’s normal tasks, personnel may look for ways to circumvent the security to make it easier to perform their job.”
Notable cybersecurity issues unconnected to the pandemic include supply chain risk, which continues “to be a focal point of the federal government” with actions this year including President Trump’s emergency declaration in May and subsequent inquiries from FERC Opens Supply Chain Cyber Risk Inquiry.) These risks can both “create issues within individual entities [and] collectively … cause disruptions within the [bulk electric system].”
New Risks to Modeling, Rating
| NERC
In calling out utilities’ inadequate modeling, the report focuses on new technologies, such as distributed energy resources and inverter-based generation. Shortcomings in utilities’ approach to both resources have been frequently noted by NERC and the REs in recent years; for example, in a joint report issued in August, NERC and WECC warned that many utilities in the Western Interconnection use outdated models, or none at all, for their solar and wind generation resources. (See NERC, WECC Warn of Inverter Modeling Gaps.)
In addition, the report’s “Gaps in program execution” section notes that inaccurate, outdated facility ratings pose a significant challenge to creating useful planning models. Rating violations may occur because of change management systems that are either not enforced or not rigorous enough to document all relevant updates. This year also saw many utilities introduce travel limitations and physical distancing requirements in light of the pandemic, which “complicated … inspection and maintenance programs,” NERC said.
The remaining areas revisit last year’s report. In the “Loss of major transmission equipment” section, NERC urges utilities to prepare for scenarios that can “reduce contingency margins” while personnel seek replacements for equipment with long manufacturing lead times. These include aging infrastructure, natural disasters and deliberate attacks such as an electromagnetic pulse, along with pandemic-related supply chain complications.
Under “Inadequate real-time analysis during tool and data outages,” the report notes the need for registered entities to “be able to demonstrate how their real-time assessment is sufficient … during the loss of primary tools or data sources.” The final section, “Determination and prevention of misoperations,” aims to remind utilities that protection systems that operate at the wrong time can be just as dangerous to the BPS as those that fail to operate at all.
Data Submittal Schedule Released
Alongside the CMEP Implementation Plan, NERC last week also published its Periodic Data Submittals (PDS) Schedule for next year. The PDS is updated annually to inform registered entities of data submittals required by NERC’s reliability standards, along with their deadlines. Data requests issued under sections 800 and 1600 of NERC’s Rules of Procedure are not included in the list.
Next year’s PDS largely carries over the schedule from 2020. Exceptions include the addition of two standards — BAL-001-TRE-2 (Primary frequency response in the ERCOT region) and TPL-007-4 (Transmission system planned performance for geomagnetic disturbance events) — that became effective in 2020 but were not included in this year’s schedule. In addition, PRC-004-WECC-2 (Protection system and remedial action scheme misoperation) and PRC-016-1 (Remedial action scheme misoperation) will become inactive in 2021 and have been removed from the schedule.
CIP-008-6 (Cybersecurity — Incident reporting and response planning) and PRC-012-2 (Remedial action schemes) are set to take effect next year as well. However, they were not included in the schedule for 2021.
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.”
