As roughly 600,000 Pacific Gas and Electric customers remained without power Thursday, the president of the California Public Utilities Commission called the situation “unacceptable.”
“The management and the response of the company, PG&E, to the [public safety power shutoffs] have been absolutely unacceptable,” CPUC President Marybel Batjer said during a commission meeting in San Francisco. “The impacts to individual communities, to individual people, to the commerce of our state, to the safety of our people has been less than exemplary.
CPUC President Marybel Batjer | State of California
“This cannot be the new normal,” Batjer said. “We can’t accept it as the new normal, and we won’t.”
She called for a review of the public policies that led to the largest blackout to prevent wildfires ever to hit the state.
Earlier this week, PG&E said it might de-energize lines serving roughly 800,000 customers — or approximately 2.4 million residents — in 34 counties of northern and central California. The utility shutoff power to 513,000 customers starting early Wednesday morning and 234,000 more on Thursday. (See Judge Admits PG&E Takeover Plan as Utility Blacks Out Millions.)
At the same time, it restored power to 126,000 customers, including many along California’s North Coast, as the gusting winds that prompted the outage subsided in some areas but picked up in others.
Following procedures established by the State Legislature and the CPUC in recent years, PG&E was trying to prevent fires sparked by electrical equipment in its service territory like those of October 2017 and November 2018, which killed at least 125 people and destroyed nearly 26,000 structures during similar dry, windy conditions.
“We faced a choice between hardship or safety, and we chose safety,” Michael Lewis, PG&E’s vice president of electric operations, said in a statement. “We deeply apologize for the inconvenience and the hardship, but we stand by the decision because the safety of our customers and communities must come first.”
Eighty-six people died in the Camp Fire of November 2018, which destroyed the town of Paradise and leveled more than 14,000 homes there, making it by far the deadliest and most destructive fire in state history. PG&E has acknowledged its equipment likely started the fire beneath a 100-year-old transmission line, which critics contend was poorly maintained. (See Cal Fire Pins Deadly Camp Fire on PG&E.)
Commissioner Genevieve Shiroma suggested this week’s massive shutoff wouldn’t have been necessary if PG&E had maintained and upgraded its infrastructure to prevent fires.
“The sheer magnitude [of PG&E’s public safety power shutoff] is indicative of the condition of the utility in terms of what we call the hardening — that means the condition of the poles, the lines, the wires, the transformers, the transmission lines — and the maintenance, or lack thereof, of the system and the vegetation management,” Shiroma said.
PG&E said about 600,000 customers in northern and central California remained without power Oct. 10. | PG&E
PG&E also came under fire at the CPUC meeting and elsewhere for the failure of its website to handle the crush of traffic from residents seeking information this week. State employees had tried to help PG&E address its website and server issues, the CPUC’s deputy executive director for safety, Elizaveta Malashenko, told commissioners.
Malashenko said the shutoffs affected about 2,400 miles of transmission lines and 24,000 miles of distribution lines. CAISO Seeking to Contain PSPS Spillover.)
Winds are expected to die down by Friday, Malashenko said. PG&E has 45 helicopters and 6,000 personnel assigned to restore power, but crews must visually inspect all lines before re-energizing them, meaning the work could take days, she said.
Southern California Edison shut off power to about 13,000 customers on Thursday at noon as wildfires flared and Santa Ana winds blew hot and dry in Los Angeles, San Bernardino and Ventura counties. It had plans in place to blackout up to 174,000 residents as of early Thursday morning.
San Diego Gas & Electric has also warned of possible shutoffs.
CARMEL, Ind. — MISO says it will wait another year before moving to tighten deliverability requirements in its capacity auctions, a decision that has irked stakeholders who say guaranteed deliverability to load is too essential to put on hold.
MISO’s Independent Market Monitor has argued that the RTO doesn’t properly account for capacity deliverability because its loss-of-load expectation (LOLE) study assumes that all capacity resources are fully deliverable on an installed capacity (ICAP) basis. However, MISO allows resources to demonstrate deliverability only up to the unforced capacity levels, which tend to be about 5 to 10% below full ICAP levels.
The Monitor has said MISO should require deliverability for all capacity resources based on full ICAP, after finding that one unit came up short by “tens of megawatts” in the 2016 Planning Resource Auction.
The RTO has so far developed possible solutions only for intermittent resources, citing the increasing number of wind curtailments in the footprint. It noted that curtailments rose to an all-time high of nearly 5 GW in May — although multiple stakeholders said it is missing key context on when such curtailments occur, arguing that curtailment at peak demand is very different from curtailment at 3 a.m.
At a Resource Adequacy Subcommittee meeting Wednesday, MISO adviser Darrin Landstrom said the RTO plans to estimate the average capacity factor for intermittent resources based on their transmission service request values, which will possibly reduce capacity credits.
But that solution wouldn’t apply to the capacity auction until the 2021/22 planning year, staff said. Landstrom said MISO would likely be unable to make a filing before the end of the year.
“I really don’t think it’s acceptable that MISO will delay a solution another calendar year,” Gabel Associates’ Travis Stewart said, urging staff to come up with a temporary solution in time for the 2020/21 planning year.
MISO has acknowledged that the Monitor might dispute capacity auction rights if the deliverability gap causes a “significant” change in clearing prices.
IMM staffer Michael Chiasson said MISO does not need to make a FERC filing to apply stricter deliverability requirements for conventional generation; it need only change its Business Practices Manuals.
But RASC liaison Patrick Brown said capacity resources need time to react to the change. He also said the RTO needs a year to make complex software changes to accommodate new deliverability requirements.
Complaint over Extended Outage Rule Change
MISO is sticking with a less aggressive plan designed to dissuade capacity resources from taking long outages that could risk supply and plans to submit a FERC filing later this month.
The provisional change would limit extended planned outages to a cumulative 90 days of the first 120 days of the planning year — June 1 to Sept. 30 — which MISO deems the most critical months in terms of demand. Resources that are unavailable for more than 90 days during the first four months of the planning year would be disqualified from auction participation. (See MISO Eases New Rules on Extended Outages.)
Tim Bachus, MISO’s capacity market administration analyst, said the temporary change is only meant for the 2020/21 planning year auction. He said he’s heard criticism that the proposal is too lenient, with some stakeholders asking instead for a 30-day outage limit.
“This is really a short-term fix … one, maybe two years total,” Bachus said. “We just want to address resources that take capacity payments but aren’t available at the most critical times.”
The short-term proposal might tackle Wolverine Power Supply Cooperative’s late September complaint with FERC over MISO allowing a yearlong planned outage of a large resource in Michigan in the 2019/20 auction (EL19-102). The RTO currently issues no penalties for capacity resources that take extended outages.
The co-op said MISO’s Tariff flaw “was exposed most recently by the results of the 2019/2020 PRA that created a capacity shortfall in Michigan’s Lower Peninsula; yielded objectively unjust and unreasonable clearing prices well below the prices that would motivate new investment or keep older existing units in operation; and ensured that market participants were inadequately compensated for their actual capacity contributions.” Wolverine argued it’s not fair to consumers and market participants that MISO allows resources to set clearing prices even when their owners are aware they will be unavailable for the planning year, undercutting market principles and jeopardizes reliability.
New PRA Deadlines Approved
In a brief letter order Oct. 3, FERC gave MISO permission to shift its deadlines for its capacity auctions, allowing market participants more time to prepare data submittals and end the RTO’s practice of opening and closing the offer window in the middle of the night (ER19-2559).
Under the rule changes, demand response testing, submission of generator verification testing data, behind-the-meter registration, unforced capacity values and the posting of preliminary auction data will be due at different points in the winter instead of fall. MISO will also open its four-day offer window at 8 a.m. ET and close at 6 p.m. instead of the usual midnight-to-midnight run. (See “New PRA Deadlines Before FERC,” MISO Resource Adequacy Subcomm. Briefs: Sept. 12, 2019.)
The new deadlines will take effect beginning with the 2020/21 PRA. Some planning resource performance data, including generation verification test capacity, is due Oct. 31. Load-serving entities must submit their peak demand forecasts for the upcoming planning year by Nov. 1, the same date that MISO will publish the results of its annual LOLE study.
PJM’s grid coasted through an “uneventful” summer highlighted by a new record for weekend peak load and the lowest forced outrage rate in five years — the result of evolving resources and system planning, the RTO said in a report published Wednesday.
“The system would not have handled these high demands as smoothly a decade ago,” said Kevin Hatch, a supervisor in PJM’s dispatch system operations. “We are seeing generators that are increasingly responsive to our operational requests, a transmission system that is more robust, and the benefits of efficient and reliable resources through the capacity market.”
Summer demand peaked at 151,558 MW on July 19 in the midst of a hot weather alert — one of 13 called in the region during the season, which spanned June 1 through Sept. 15. The following day, the grid set a new weekend peak load record of 149,751 MW. The average LMP hovered around $25/MWh, with prices during the daily peak spiking to $45/MWh.
Although “relatively” mild weather enhanced the grid’s smooth performance, the report emphasizes the “excellent coordination and cooperation” of PJM members, including responsiveness to dispatch operations, system upgrades and the influx of more efficient generators via the capacity market. These newer resources have replaced aging equipment, driving forced outage rates below 3% this summer, the RTO said.
“We appreciate the cooperation and coordination with our member utility companies,” said Mike Bryson, PJM’s senior vice president of operations. “More efficient generators mean fewer outages, greater reliability and a more efficient system overall.”
Average forced outage rate | PJM
The report also credited lower fuel prices — combined with the season’s hottest temperatures occurring during periods of lower demand — for keeping LMPs down. Average daily gas and coal prices were 64 cents/MMBtu and 31 cents/MMBtu cheaper, respectively, compared to 2018.
No capacity emergency procedures occurred during the summer. PJM reported three spinning events and 13 hot weather alerts, the fewest recorded in a summer season since 2014. The grid experienced less than 80 post-contingency local load relief warnings, another five-year record low.
Two “notable” gas pipeline events caused temporary disturbances in PJM, according to the report. On Aug. 1, a 30-inch segment of the interstate Texas Eastern Transmission Pipeline in central Kentucky exploded, just a few miles south of a gas-fired generator that serves PJM. The explosion did not harm the unit, and operators isolated the damaged section, saving the grid’s supply of shale gas that flows through the region.
Six weeks later, a compressor station in Northern Virginia on the Dominion Energy Transmission pipeline failed during scheduled maintenance. PJM said a “spell of later summer heat” and the typical generator outage season meant that certain units downstream of the station lost gas supply temporarily. No emergency procedures were issued.
Shoulder Season Surprise
An unexpected hot weather alert on Oct. 2 forced PJM to call upon demand response resources to effectively manage the 126,000 MW peak load.
The RTO declared a pre-emergency load management reduction action just before noon in the American Electric Power, Baltimore Gas and Electric, Dominion and Pepco zones. This directive triggered a performance assessment interval — which measures the production of all resources with Capacity Performance commitments in the affected zones — that lasted approximately two hours.
“We count on our utility partners, generation resources and load management to perform during these tough days, and they did just that,” Rebecca Carroll, PJM’s director of dispatch, said in a statement last week.
Although the event occurred outside the summer season, PJM will address both the report and the DR event at its Operating Committee meeting Tuesday.
SPP staff told the Seams Steering Committee on Wednesday that MISO is pursuing a number of transmission projects to help it escape from under a settlement agreement that governs the connection between its two regions.
MISO said in July that it is evaluating nine projects to supplement or substitute for the contract path that links its Midwest and South regions over SPP’s system. (See MISO Studying Projects to Cut North-South Tx Reliance.)
“MISO wants to get rid of the settlement agreement — specifically, the $27 million in transmission payments they’re making,” Casey Cathey, SPP’s manager of reliability planning and seams, told the committee during its monthly meeting. “They have a stack of projects they’ve looked at. … They’re being very transparent.”
MISO Midwest and South footprints | MISO
Cathey said MISO intends to fold the projects into its planning efforts, which will be completed by the end of 2020. Similarly, he said, SPP would like to incorporate MISO’s work into its own planning processes and into the RTOs’ next coordinated system plan.
“This is an opportunity for us to have a coordinated plan to meet both MISO and the members’ intentions, but also for SPP to have a portfolio developed that addresses needs along the seam through a series of flowgates that help us to run the market more efficiently,” he said.
Cathey said he would be able to bring more details to the SSC’s December meeting.
Under the terms of a settlement agreement reached in 2015, MISO’s flows on the contract path are capped at 3,000 MW north to south and 2,500 MW in the opposite direction. MISO compensates SPP and six independent transmission owners party to the agreement — Southern Co., Tennessee Valley Authority, Associated Electric Cooperative Inc., Louisville Gas and Electric, Kentucky Utilities and PowerSouth Energy Cooperative — by applying a capacity factor for flows exceeding the previous 1,000-MW contract path in the RTOs’ joint operating agreement.
The settlement agreement expires in January 2021. At that time, the parties can give notice to terminate or revisit the settlement provisions. FERC approved the settlement in 2016. (See FERC OKs MISO-SPP Transmission Settlement.)
RSC-OMS Liaison Group Looks for Answers
Adam McKinnie, an economist with the Missouri Public Service Commission, said SPP and MISO state regulators have gathered initial feedback on the RTOs’ interregional planning processes and will spend the next couple of months evaluating that input.
Commissioners on SPP’s Regional State Committee plan to attend the Organization of MISO States meeting Oct. 24 in New Orleans. The SPP RSC-OMS Liaison Committee will also meet Nov. 17 in San Antonio during the first day of the National Association of Regulatory Utility Commissioners’ annual meeting, McKinnie said.
The Liaison Committee has commissioned an independent analysis to determine whether the RTOs are leaving efficiencies and benefits behind in their interregional planning processes. (See MISO, SPP States Ponder Look at Interregional Planning.)
Stakeholders responded to a request for information in September. Eight of the 14 stakeholders who submitted responses believe an interregional planning analysis will help the committee. Three others suggested additional work on current processes.
Stakeholders have been frustrated by the RTOs’ interregional work, which has yet to result in a joint project.
The commissioners “are looking for information to see what the effects would be from different changes,” McKinnie said. “They didn’t start with a solution. They said, ‘Hey, we need information.’”
The committee has also asked the RTOs’ market monitors to study the grid operators’ markets and operations issues. That work will be delivered by the end of November.
NERC’s Stakeholder Engagement Team (SET) has finalized its proposal to merge the Planning, Operating and Critical Infrastructure Protection committees, setting the stage for expected approval by the Board of Trustees on Nov. 5.
“That [demand from members] was pretty loud and clear,” Greg Ford, chairman of the Member Representatives Committee, said Thursday at the MRC’s premeeting informational conference call.
A new Reliability and Security Technical Committee (RSTC) would replace the Operating, Planning and Critical Infrastructure Protection committees under a plan the NERC board will consider next month. | NERC
The SET also eliminated a requirement that committee members have executive-level experience.
The membership also will include representation from each interconnection. “That was a request that came through load and clear as well,” Ford said.
The transition from the three committees to the new Reliability and Security Technical Committee (RSTC) — a revised name from the original proposal, which some stakeholders feared would be confused with the Reliability Issues Steering Committee (RISC) — was also extended into June.
Under the new schedule:
Nov. 5: The board will consider the proposal and RSTC charter and transition plan. If approved, the board will appoint the new committee’s chair and vice chair at the same time.
Nov. 6 to Dec. 6: Nominations will be open for sector representatives, with sector elections, if necessary, conducted by Dec. 20.
Dec. 9 to Jan. 3, 2020: At-large nominations will be accepted, with the Nominating Committee developing a slate of at-large members by Jan. 15 for presentation to the board.
Feb. 6: Board appoints RSTC sector and at-large members.
Feb. 7 to May 29: RSTC develops transition plan and work plans for RSTC and subcommittees.
March 3-4: OC, PC and CIPC meet. The RSTC will hold its first meeting March 4 to establish the Nominating Subcommittee, Executive Committee and perform other administrative items.
June 2020: OC, PC and CIPC will meet for final work plan approvals and to complete any other approvals. The RSTC will hold initial regular meeting with subcommittee reports and other agenda items.
Terms for the new committee members will expire in June of alternating years. The initial membership will be split between two- and three-year terms, after which terms will run for two years.
The proposed changes didn’t come without misgivings from some stakeholders. (See NERC Board Hears Debate over Committee Reorg.) But Ford said he was happy with the way the process played out.
“There was a lot of open, honest, good discussion all the way back to the first meeting [the SET] had,” he said. “I feel like we’re in a good place.”
He had special praise for the work of Exelon’s Jennifer Sterling and NERC Chief Engineer Mark Lauby. “I thought you herded us cats very well,” he joked.
MRC Governance Guidelines, EMP Task Force
Thursday’s preview of the MRC’s Nov. 5 meeting also included a discussion of revised Governance Guidelines, which were developed to reduce the number of documents guiding the committee to just two: the guidelines and the NERC Bylaws. The Approved Policy on Minutes of MRC Meetings, Framework for the Operation of the MRC and NERC MRC Reference Document would be eliminated.
NERC Director of Engineering and Standards Howard Gugel also provided a brief update on the Electromagnetic Pulse (EMP) Task Force’s Strategic Recommendations Report.
The Nuclear Regulatory Commission briefed FERC on its plans to replace its time-intensive inspections of licensees’ cybersecurity plans with a more “risk-informed” approach at the two agencies’ annual public meeting Sept. 25.
NRC published its cybersecurity rule (10 CFR 73.54) in 2009, with interim implementation due by December 2012 and full implementation in December 2017. The rule requires that nuclear power plant licensees provide high assurance that their digital computer and communication systems and networks are adequately protected against cyberattacks. It focuses on critical digital assets (CDAs) — those whose failure could result in an adverse impact on safety, security and emergency preparedness functions.
NRC and FERC commissioners at their annual joint public meeting | NRC
The commission has now completed full implementation inspections of almost two-thirds of its 57 licensees, Shana Helton, director of its Division of Physical and Cyber Security Policy, told FERC during the meeting at NRC headquarters outside D.C., in Rockville, Md. Each inspection is two weeks long and is conducted by teams of two regional inspectors and two technical support contractors.
NRC expects to inspect the remainder of its licensees by the first quarter of fiscal 2021. But it doesn’t plan to repeat the time-consuming inspections going forward, Helton said.
“We’re taking a look at our regulations, our guidance — but also our oversight,” she said in response to a question from FERC Commissioner Richard Glick. “We’ve had some very intensive [inspections]. … We feel that was an appropriate level of inspection for looking at the initial full implementation by licensees. But going forward … we think there are places where we could do more to further risk-inform as well as perhaps look at performance-based indicators and see if we could use those to influence our inspection programs. So that’s work that we’re going to be undertaking in the very near future.”
NRC Commissioner Jeff Baran (left) and FERC Commissioner Richard Glick FERC
The new approach resulted from feedback collected during a six-month cybersecurity assessment by NRC staff and cybersecurity specialists from Idaho National Laboratory.
The assessment, completed in July, recommended “a more risk-informed, graded approach” to identifying CDAs and providing more credit for existing plant programs addressing insider mitigation, physical security and configuration management.
The assessment team also was tasked with developing a near-term plan to develop “a further risk-informed approach to scoping critical digital assets related to emergency preparedness as well as those related to balance of plant, with a focus of aligning with the [NERC] critical infrastructure protection standards,” Helton said.
Inspector General Audit
Following an audit of the cybersecurity inspections, NRC’s inspector general also recommended a risk-influenced approach, noting that the number of CDAs identified has far exceeded what was expected when the rule was finalized a decade ago.
The audit, released in June, called for identifying performance measures similar to those used in NRC’s Reactor Oversight program, saying it would make the inspections “more efficient and reliable without diminishing the level of assurance.”
The audit cited the National Institute of Standards and Technology’s Guide to Industrial Control Systems (ICS) Security, which identified as potential metrics vulnerability assessment and patching, equipment changes, equipment configurations, and antivirus software management.
“Current cybersecurity inspections are largely programmatic and compliance-based. The principal focus of the inspection procedure is verifying that the key cybersecurity program elements have been established and are working together effectively in a viable program,” the IG wrote. “The broad scope inspection, while effective, cannot be sustained beyond the current commitment. The current inspection program is resource-intensive for both the licensees and the agency, and requires a wide range of hours to complete, depending on conditions at each facility inspected.”
Difference between estimated and actual inspection resources, 2018 | NRC
The audit also identified a need to address staffing challenges in the inspection program, which relies on providing cybersecurity training to regional inspectors who are also responsible for fire protection and other issues. “Since inspectors perform other, non-cybersecurity inspections, maintaining cybersecurity expertise can be difficult,” the auditors said.
They also noted that about 26% of NRC’s regional Divisions of Reactor Safety staffers are currently eligible for retirement, a percentage that will increase to 32% by the end of FY 2020.
“If staffing levels and skillsets do not align with cybersecurity inspection workload requirements, NRC’s ability to adapt to a dynamic threat environment and detect problems with licensees’ cybersecurity programs could be compromised,” the IG said.
The audit concluded that NRC’s cybersecurity inspections “provide reasonable assurance” that licensees are meeting the agency’s regulations.
Findings: ‘Very Low Safety Significance’
Helton agreed. “Our staff has found that in most instances, licensees understand what it takes to fully implement the NRC’s cyber requirements and have adequately implemented their cybersecurity programs,” she said. The inspections so far have resulted in findings of “very low safety significance” mostly concerning documentation, she added.
“Licensees may have controls in place, [but] they might be a little bit different than what was described in their cybersecurity plan,” she explained. “In those cases, they’ve been of very low safety significance because they do have appropriate alternative measures in place, and there’s substantial defense in depth. But they need to reflect that in their cybersecurity plans.”
From Analog to Digital
While most of the U.S. nuclear fleet was built more than 40 years ago and is largely analog, upgrades at those plants are increasingly using digital technology.
“There can be challenges with trying to replace an analog design, from the standpoint that the component may or may not be produced any longer and manufacturers are moving more and more toward using digital [technology] where they can,” Helton said. “So we rely on licensees’ configuration management processes. As they acquire a new system, they do need to look at the cybersecurity involved with that.”
The control room simulator (left) shows the analog controls typical of the current nuclear fleet. The control room for Southern Nuclear’s new Vogtle units (right) feature digital controls. | NRC
Companies seeking licenses for new reactor designs with more sophisticated and integrated digital assets must submit cybersecurity plans with their applications.
NRC is currently working with licensee Southern Nuclear on the AP1000 design it is using for Vogtle Units 3 and 4 “to better understand key design elements of the plant and the licensee’s schedule for implementing cybersecurity requirements,” Helton said. Southern’s cyber controls must be in place prior to Vogtle’s receipt of nuclear fuel on site.
FERC Chair Neil Chatterjee asked how NRC’s cybersecurity incident reporting rules compare with NERC CIP requirements.
Helton said there are several reporting requirements in 10 CFR 7377. “Anything that is having an impact directly on the safety and security of the plant, we’ll hear about it within an hour,” she said, adding other incidents carry four-hour reporting requirements.
CAISO, ISO-NE and NYISO look to be the pacesetters in opening the country’s organized electricity markets to greater participation by distributed energy resources, according to filings submitted to FERC on Monday.
The filings came in response to the commission’s request for information on how RTO/ISO interconnection processes accommodate aggregated DERs. (See FERC Sends DER Data Request to RTOs.)
Glendora, Calif., Sam’s Club solar panels | Walmart
In its Sept. 5 letter, which included 11 questions, FERC said it was seeking information in particular on distribution-connected DERs aggregated to participate in wholesale markets. The submissions provided a flavor of how disparate the treatment of DER aggregations across the markets is, an issue FERC will likely attempt to tackle in its rulemaking (RM18-9):
CAISO, PJM, MISO and SPP said their interconnection processes do not differ based on whether the DER is a qualifying facility under the Public Utility Regulatory Policies Act. NYISO said QFs connecting to distribution facilities to participate in ISO markets are subject to the ISO’s interconnection procedures, regardless of whether the distribution facility is subject to a FERC-jurisdictional open access transmission tariff. ISO-NE said QFs selling all their output to the host utility follow state interconnection processes rather than the RTO’s rules.
All the grid operators said their interconnection processes are the same for DERs seeking to participate in wholesale markets regardless of whether they are interconnecting behind a retail customer meter. CAISO said that DERs, by definition, must have points of interconnection on the distribution grid. ISO-NE said DERs seeking to inject power into the system are subject to its Tariff if the interconnection is to an OATT distribution facility and to the state interconnection process if connected to a non-OATT distribution facility. NYISO said behind-the-meter resources that only reduce consumption and are not injecting power are not subject to the ISO’s interconnection procedures.
ISO-NE, NYISO, PJM and SPP said their interconnection process allowed studies for bidirectional service, although all but ISO-NE limited them to storage facilities. CAISO and MISO said they defer to the practices of the host distribution providers.
None of the grid operators was able to provide definitive data in response to the commission’s request for the number of DERs in each footprint that directly participate in wholesale markets versus the DERs that don’t participate. All but PJM offered up some data, however:
CAISO referred to state data showing that California leads the nation in distributed generation. Its more than 1 million solar projects had a combined nameplate capacity of 8,431 MW as of July 31.
ISO-NE said DERs participating in its wholesale markets consist of 1,649 MW of “settlement only” resources (generation assets of less than 5 MW that are often connected to the distribution system) and 3,813 MW of demand resources (price-responsive demand, energy efficiency, load management, BTM generation and storage that reduce end-use demand). Although it said it lacked “visibility” on DERs outside its markets, it estimated there are 1,975 MW of solar PV generation not participating. It said it lacked similar estimates for combined heat and power facilities and batteries.
NYISO said it had 3,678 facilities providing 1,431 MW of demand response capability and one BTM net generation resource as of July 31, 2018. For non-ISO resources, it cited data from the New York State Energy Research and Development Authority estimating there are about 90,000 BTM solar PV installations in the state with a capability of 1,479 MW. NYSERDA also has estimated there are 300 to 400 non-solar distributed generation facilities, primarily combined heat and power facilities and energy storage, totaling 200 MW.
MISO said the resources participating in its markets include DR resources (28 resources with a combined target demand reduction of 672.6 MW), load-modifying resources (7,326.5 MW) and emergency DR resources (66 resources totaling 2,163.3 MW). It said it had no data on what share of those resources are connected on the distribution versus the transmission system. (It noted that its LMR data includes transmission-connected generators beyond the scope of FERC’s queries). MISO cited the Organization of MISO States’ recent survey of utilities, which estimated almost 195,000 installations totaling 4,698 MW of DERs are not participating in the MISO market. (See OMS: 4.5 GW of Unregistered DERs in MISO.)
SPP said it has no DERs directly participating in its Integrated Marketplace, adding that it does not consider cogeneration facilities as DERs. It said it did not know how many DERs in its region are “part of the regulated retail environment.”
None of the RTOs was able to provide data on what share of the distribution facilities within their footprints were subject to a FERC-jurisdictional OATT. MISO, however, said it will begin tracking facilities that provide wholesale distribution service “in anticipation of DERs.”
All the grid operators said they were engaged with state or local authorities regarding the interconnection process for DERs or had done so in the past.
Below are individual summaries of the grid operators’ responses.
CAISO’s ‘Great Lengths’
CAISO offered a robust response in keeping with its status as one of the most advanced incorporators of solar and other renewable resources.
“CAISO and its participating transmission owners have gone to great lengths to ensure that distributed energy resources can easily access and participate in the CAISO’s wholesale markets for energy and ancillary services,” it said. “The CAISO Tariff allows distributed energy resources to access the wholesale markets quickly. The CAISO allows DERs to participate as standalone resources, aggregations and DR resources. The CAISO continually works to ensure that its Tariff keeps pace with emerging technologies and grid trends.”
The ISO has been conducting a stakeholder process since 2015 on energy storage and DERs (ESDER), which has generated three sets of Tariff changes. It is now in its fourth phase of ESDER development.
California leads the nation in distributed generation. | California Distributed Generation Statistics
In 2016, FERC approved what the ISO called its “first-of-its kind” process that allows DERs too small to meet the ISO’s minimum capacity requirements — 100 kW for storage resources and 500 kW for conventional generators — to pool their resources and participate jointly in the CAISO market. The smaller resources can sell energy and ancillary services in CAISO as a distributed energy resource provider (DERP).
“Moreover, each CAISO transmission owner that is FERC jurisdictional and operates distribution facilities has a wholesale distribution access tariff (WDAT) with the express purpose of enabling DERs to interconnect to the distribution grid and still participate in the CAISO wholesale markets,” the ISO said. “These transmission owners actively participate in CAISO stakeholder processes and update their WDATs to remain consistent with the CAISO Tariff.”
A DER planning to participate in CAISO submits its interconnection request to its utility distribution company (UDC), with the applicable process set forth in the UDC’s tariff, the ISO told FERC.
“The UDC performs all of the interconnection studies and administers the interconnection process, including the construction of network upgrades to mitigate any impact on the distribution or transmission grids. If the DER seeks a deliverability capacity allocation to be eligible to provide resource adequacy capacity, the CAISO performs the deliverability studies and informs the UDC of the results.”
Before the DER goes live, it must complete CAISO’s new resource implementation process to analyze the resource in the ISO’s network model, register its scheduling coordinator and execute a participating generator agreement.
The process doesn’t change if the DER is a QF or if it connects behind a retail customer meter, CAISO said. Whether participating individually or through an aggregation, all DERs interconnect to the distribution system under the applicable tariff of the UDC.
The California Public Utilities Commission’s Rule 21 establishes the interconnection rules for state-jurisdictional utilities, requiring WDATs and DERs to mitigate any reliability impact on the CAISO grid.
CAISO said it doesn’t keep data on the number or capacity of DERs in its market.
“DERs execute the same participating generator agreement that transmission-connected resources execute, and the CAISO’s Master File and network models consider the voltage level of the point of interconnection, not whether that interconnection is considered transmission or distribution,” the ISO said. “Determining whether each participating generator is interconnected to the transmission or distribution grid would require significant time and resources.”
The ISO said “DERs’ ability to participate in the CAISO markets has been a settled issue in California for many years. Recent regulatory coordination efforts have focused on modern, complex issues like [distributed energy resources aggregation], multiple-use applications and accounting for net energy metering resources.
“In addition, the CAISO continues to pursue discussion with transmission owners, UDCs and local regulatory authorities on managing the transmission-distribution interface with a high volume of DERs.”
ISO-NE: DERs 19% and Growing
ISO-NE prefaced its response with a summary of DER participation in its markets, noting that its 7,437 MW of DERs account for about 19% of the region’s total electrical capacity, most of it solar PV and energy efficiency. The RTO projects that by the end of 2028, installed PV nameplate capacity will exceed 6,700 MW and energy efficiency resources will reduce summer peak load by about 5,400 MW.
The RTO urged the commission to “afford regional flexibility” in any final order.
Schedule 23 of the ISO-NE OATT governs interconnections of small generating facilities (20 MW or less).
ISO-NE said it coordinates with the relevant TO regarding the status of the distribution facility in order to direct the DER developer to the applicable interconnection process. New or increased generation interconnections of 5 MW or greater require a “proposed plan application.” Interconnections greater than 1 MW, but less than 5 MW, require a notification, unless the RTO determines the proposed plan will have a cumulative impact on facilities used for the provision of regional transmission service, in which case, an application is required.
New England distributed energy resources as of Sept. 1, 2019 | ISO-NE
The RTO requires an interconnection agreement for each POI, although each interconnection may include multiple units or devices. Two or more interconnection requests may be studied in a cluster if the conditions for clustering are triggered. Clustering is available when there is an interconnection queue backlog of two or more requests in the same part of the RTO’s transmission system and none of the requests will be able to interconnect without significant transmission upgrades.
ISO-NE does not allow a single interconnection request for multiple generating facilities. However, it permits aggregation of multiple points of interconnection and multiple units behind a single POI for DR resources and alternative technology regulation resources.
The entity responsible for processing the interconnection request is determined by the status of the facility to which the DER generating facility plans to interconnect. Facilities that are part of the administered transmission system — existing pool transmission facilities (PTF), non-PTF and distribution facilities governed by the OATT — are subject to the RTO’s interconnection procedures.
The interconnection studies assess the impact of the small generating facility’s interconnection on both the transmission and distribution systems of the interconnecting TO.
MISO: DER Interconnections ‘Untested’
MISO told FERC it doesn’t keep track of resources at the distribution level and couldn’t tell the commission the number or megawatt volume of DERs in its footprint.
The RTO said that, save for DR resources, it’s not home to many DER installations and that it “does not anticipate significant penetration levels in the near future.”
It said its existing interconnection rules only apply to DERs seeking to connect to distribution facilities that provide wholesale distribution service — which it deems as part of its transmission system for interconnection purposes. It noted that DERs must follow interconnection queue rules to participate in its capacity auctions.
“To date, however, MISO has not received nor processed a request from a DER to interconnect to such a facility. … The application of current rules to DERs remains untested in practice, and MISO’s responses consequently are to some degree hypothetical,” the RTO told FERC.
DERs not currently participating in MISO markets | Organization of MISO States
A connection to facilities that are not providing wholesale distribution service doesn’t require a trip through MISO’s interconnection queue. DERs would instead seek interconnection permission from distribution owners. In MISO, it’s left to distribution owners to determine and alert MISO as to whether an interconnecting DER would impact the transmission system.
MISO also said it has yet to receive any requests to interconnect aggregated DERs, nor does it yet have rules in place as to how it would study aggregations for interconnection.
The RTO noted it’s beginning work on a DER participation model with stakeholders and OMS and said its interconnection rules will likely require “carefully considered adjustments.”
“As MISO continues developing its DER aggregator participation model, MISO may reexamine the scope and applicability of MISO’s interconnection process under various scenarios,” the RTO added.
New Rules Pending for NYISO
NYISO prefaced its response by referring to its June 27 filing of proposed Tariff revisions to establish a new model allowing individual generating facilities located at the same bus to aggregate as a single resource to participate in the ISO markets (ER19-2276). (See NYISO Management Committee Briefs: April 24, 2019.)
Under the proposal, which is pending before FERC, an aggregation could consist of two or more generation, DR or DER resources with a maximum injection of 20 MW.
The proposal would expand the definition of “small generating facility” to include injections into the grid from generating units and energy storage of the same or different technologies located behind a single meter.
NYISO noted that DERs do not participate much in its markets currently except through DR programs that reduce the amount of energy that LSEs must obtain in the markets.
NYISO proposed expanding the definition of “small generating facility” to include net injections into the grid from generating units and energy storage. | NYISO
The ISO said it coordinates with TOs on a case-by-case basis to determine whether a proposed interconnection is to a distribution facility subject to the Tariff.
“The voltage of the facilities is not the sole criteria for making this determination,” it said. “While generally facilities 45 kV and above are considered transmission, and facilities below 45 kV are considered distribution facilities, this is not always the case.” How the TO operates its distribution system — whether radial or networked — is also important in this determination.
The proposed rules would also stipulate that generating facilities located at separate points of the grid may participate in an aggregation so long as all the facilities are electrically located at or downstream from the same transmission node.
The ISO said it will not perform additional studies based on an existing facility’s determination to participate in an aggregation, regardless of whether they were subject to the small generator interconnection procedures (SGIP), standardized interconnection requirements (SIR) or utility interconnection procedures.
NYISO said it anticipates a substantial increase in the number of existing and new distribution-connected generating facilities that will seek to participate in its wholesale markets.
“Once such generating facilities begin to enter into service and start making wholesale sales, they will trigger the distribution facility to which they are interconnected as subject to the commission’s interconnection jurisdiction going forward, which will increase the distribution facilities in New York subject to the commission’s jurisdiction for interconnections for purposes of making wholesale sales,” it said.
PJM: No Specific Aggregation Processes
PJM’s Tariff does not outline specific aggregation processes, so each FERC-jurisdictional DER would require its own interconnection service agreement. Those outside the commission’s authority require a wholesale market participation agreement. Tariff revisions would be required to accommodate aggregations of new and existing DERs at multiple points of interconnection, the RTO said.
The process for DERs interconnecting to both types is the same, PJM said, except that those seeking connection to non-jurisdictional facilities must execute any additional steps required by state regulators.
PJM said it has engaged in conversations with authorities in D.C. and several states — including Ohio, Pennsylvania and Michigan — regarding DER ride-through capability. The RTO produced a report comparing state interconnection procedures, including how they might apply to wholesale DER, with the help of state commissions. It also participated in Maryland’s PC-44 grid transformation proceeding, which “examined the applicability of Maryland jurisdiction to the interconnection of wholesale DER.”
Bidirectional service studies are only conducted for energy storage devices capable of charging from the grid. PJM also does not consider BTM generation as eligible for wholesale participation.
The RTO doesn’t keep track of how many DERs currently exist within the region, nor does it maintain data or estimates on which distribution facilities are subject to FERC jurisdiction versus those that are not.
DERs not Participants in SPP Markets
No DERs directly participate in SPP’s market, the grid operator said in its filing. The RTO said it would consult with the interconnecting utility and the appropriate TO to determine whether an aggregate or individual affected-system study would be appropriate.
“The affected-system study is strictly for the purpose of determining impacts to the SPP transmission system,” SPP said. It said it considers each interconnection point as a separate request, to be studied individually.
SPP said its Tariff allows individual DERs looking to join an aggregation to be studied under a cluster study, if the customer requests it.
“The DER’s decision to participate in an aggregation would not trigger the RTO/ISO interconnection process,” the grid operator said. “To the extent that the interconnecting utility determines that the aggregation would create the possibility that the DER could impact the SPP transmission system, the utility would have an obligation to inform SPP and to determine whether additional studies would be needed.”
U.S. annual installed DER power capacity additions by DER technology, 2015-2024 | Navigant Analysis
The grid operator said distribution utilities would be responsible for determining whether proposed DER facilities are under SPP’s functional control and, if so, they would direct the customer to submit an interconnection request to the RTO. If the facilities are not under SPP control, the utility would determine whether there is a potential impact to the transmission system and notify SPP of the request. The RTO and interconnecting utility would jointly determine whether a study is necessary and which entity would conduct it.
If upgrades are required, SPP would tender an agreement to the customer for construction. The three-party construction agreement would be between SPP, the customer and the TO, which would own the upgrade. SPP would not be a party to any interconnection agreement.
Responding to FERC’s question on how it defines the physical boundaries of a distribution facility when determining whether it is already subject to SPP’s OATT for making wholesale sales, the RTO said its interconnection procedures only apply to facilities under its functional control.
“Any resource, regardless of whether it interconnects to the SPP transmission system or not, may make wholesale sales … as long as it meets the other requirements under the Tariff for market registration and transmission service reservations, as applicable,” it said.
The RTO said that whether energy storage resources are required to support charging activities would be determined by its interconnection study process, unless the customer indicates that it will not charge from the system.
If the facility is not an energy storage resource, the study process would only evaluate the effect of energy’s injection into the system. If the facility includes network load, it may be subject to the Tariff’s provisions for block-load additions, which is separate from the interconnection study process.
Asked how it would address individual DERs in an aggregation trying to interconnect to distribution facilities, some of which are subject to the Tariff, the RTO reiterated that only facilities under its functional control would be subject to its procedures.
Amanda Durish Cook, Rich Heidorn Jr., Tom Kleckner, Michael Kuser, Robert Mullin, Hudson Sangree and Christen Smith contributed to this report.
SACRAMENTO, Calif. — The federal judge overseeing PG&E’s mammoth bankruptcy opened the door to a competing takeover plan Wednesday, potentially allowing a group of bondholders to seize control of California’s largest utility from its current investor owners.
The move to end PG&E’s exclusivity period — the time it has to offer its own Chapter 11 plan unopposed — occurred as all eyes were fixed on PG&E’s decision to shutoff power Wednesday to at least 513,000 Northern California customers in an effort to prevent the type of deadly fires that drove it to seek bankruptcy protection in January.
“[PG&E’s reorganization] plan is on track as well as can be expected for now,” U.S. Bankruptcy Court Judge Montali wrote in his order ending exclusivity. “That said, the parties most deserving of consideration [the fire victims], speaking through the [Official Committee of Tort Claimants] have changed their position from the last time the court considered terminating exclusivity, and spoken loudly and clearly that they want their and the Senior Noteholders’ proposed plan to be considered.”
“The coming weeks will permit ample time to explore and resolve issues regarding both plans consistent with the more traditional plan vetting processes well-known by bankruptcy professionals,” Montali wrote.
The judge instructed the bondholders to file their plan by Oct. 17. In its preliminary form, the bondholders’ plan proposed investing more than $29 billion in PG&E in exchange for a controlling interest in the utility. It includes a provision for paying wildfire claimants about $13.5 billion, insurance companies $11 billion and local governments $1 billion.
As Montali filed his order, PG&E had come under intense scrutiny for its decision to shut down power to large swaths of its Northern California service territory, citing gusty winds that could cause utility-sparked conflagrations like those of the past two fall fire seasons.
The unprecedented public safety power shutoffs (PSPS) — affecting as many as 800,000 customers and millions of residents in 34 counties — were by far the largest yet in a state struggling to protect its residents from fires that have turned dramatically more deadly and destructive in recent years.
PG&E faces billions of dollars in potential liabilities for the North Bay (or wine country) fires of early October 2017 and the Camp Fire of November 2018, which combined killed nearly 120 people and destroyed tens of thousands of homes. Those fires started in weather conditions similar to Wednesday’s. (See related story, Fearing Wildfires, PG&E to Cut Power to 800,000.)
“The safety of our customers and the communities we serve is our most important responsibility, which is why PG&E has decided to turn power off to customers during this widespread, severe wind event,” Michael Lewis, vice president of PG&E electric operations, said in a statement. “We understand the effects this event will have on our customers and appreciate the public’s patience as we do what is necessary to keep our communities safe and reduce the risk of wildfire.”
High winds in Northern California prompted PG&E to intentionally blackout much of its territory. | National Weather Service
The utility said its decision to turn off power was based on “forecasts of dry, hot and windy weather including potential fire risk. Based on the latest weather forecasts and models, PG&E anticipates that this weather event will last through midday Thursday, with peak winds forecasted from Wednesday morning through Thursday morning and reaching 60 to 70 mph at higher elevations.”
Afterward, PG&E crews must inspect lines to make sure it’s safe to restore power, meaning the outage could last into the weekend.
Soon after midnight Wednesday, PG&E began its intentional blackout of approximately 513,000 customers in the Sierra Nevada foothills east of Sacramento, on the state’s North Coast and in the mountainous landscape north of San Francisco. The first phase of its planned three-phase outage was completed about 4 a.m.
PG&E said it would turn out the lights for 234,000 more customers in the San Francisco Bay Area and elsewhere at midday on Wednesday, though it postponed that move for at least several hours. It said it was considering shutting down power to around 42,000 customers in the far southern part of its service area, where it abuts the area served by the state’s second largest investor-owned utility, Southern California Edison.
SCE said it was weighing shutting down transmission and distribution lines that serve nearly 174,000 customers Wednesday, but it had not done so as of 3 p.m. PT.
The winds that spread wildfires each fall in California are known as Santa Ana winds in the south and Diablo winds in the north. They fan blazes in vegetation dried out by the long rainless months of the state’s Mediterranean climate.
Winds blew at 10 to 45 mph from the north and east in PG&E’s territory, the National Weather Service reported Wednesday as it issued a red-flag warning. Gusts tend to blow hardest across Northern California’s ridgetops, whipping wildfires into fast-moving firestorms that are nearly impossible for firefighters to control.
San Diego Gas & Electric began shutting down power proactively after a series of massive fires there last decade. SCE followed, as did PG&E starting last year. It considered shutting down power to the area scorched by the Camp Fire, which destroyed the town of Paradise and killed 86 people, but opted not to. (See Fire Season Starts in Calif. with Power Shutoffs.)
Typical PSPS events have generally affected anywhere from a handful of customers to more than 5,000, according to records kept by the California Public Utilities Commission starting in 2013. PG&E upped the ante when it shut down power to 48,000 customers in late September, but this weeks’ events dwarf that number.
CAISO said it did not expect “any impact to the bulk electric system for the duration of this event.”
A federal court temporarily waived Ohio’s preregistration law for petition circulators last week after a group collecting signatures for a statewide ballot referendum against nuclear subsidies claimed its opponents were stalling their efforts through harassment and bribery.
Ohioans Against Corporate Bailouts filed a lawsuit in the U.S. District Court for Southern Ohio that accused supporters of the state’s nuclear subsidies of offering bribes to undermine its attempt to collect 266,000 signatures by an Oct. 21 deadline.
The organization asked the court to immediately suspend a state law that requires it to disclose the identities of its petition circulators to the secretary of state on a “Statement of Receiving or Providing Compensation for Circulating a Statewide Issue Petition,” called Form 15. Failure to file the form is a fifth-degree felony under Ohio law, however, the group said the mandate violates free speech rights.
The group alleges that its opponents accessed the referendum circulators’ identities through public records requests and used it to target them, offering cash bribes to abandon the campaign or buy their signatures. The suit, filed Oct. 7, also asked for another 90 days to collect signatures.
Perry nuclear power plant | FirstEnergy
At a hearing on Friday, Judge Edmund Sargas Jr. suspended the Form 15 requirement through Oct. 25, saying that without injunction, “the plaintiffs will suffer irreparable harm.”
“The interests of the public would be best protected by the enforcement of plaintiffs’ First Amendment rights, and any third-party injury could be minimized by statutory mechanisms for detecting and deterring election fraud,” Sargas said.
Advanced Micro Targeting, a Nevada-based company that manages the referendum effort, said in a declaration filed Wednesday that its employees spend up to eight hours processing Form 15s for each new hire. Some 15 to 20 potential employees have been lost because of the “time and burden” involved with the process, and the company says it will not take on future statewide referendum efforts “in light of significant diversion of time, energy and resources” necessary to comply with state law.
The “draconian” Form 15 mandate, one-month delay in getting the petition approved and interference from “well-funded and overly aggressive” opposition has further complicated the referendum effort, the group said in court documents.
“This administrative requirement only serves to make our petition circulators targets,” Chris Finney, an attorney for the organization, said in a press release. “One of our circulators was called less than hour after they filed their Form 15 with the state of Ohio and received an offer to quit working for the campaign if they would take a buyout bribe.”
Sargas rejected the organizations’ two other requests — to waive state laws that require government approval of petition summaries and certain signature distributions across counties — but did not explain why.
If the referendum is approved, voters would decide whether to overturn House Bill 6, which would provide $150 million annually to First Energy Solutions’ two nuclear plants starting in 2021. The suit names as defendants Ohio Secretary of State Frank LaRose, who is responsible for certifying or rejecting the ballot measure. Also named was Columbus City Attorney Zach Klein, who is responsible for enforcing violations of the Form 15 requirements in the state capital.
The group’s suit does not identify those who took part in the alleged bribery attempts. The referendum drive is being opposed by groups calling themselves Ohioans for Energy Security and Generation Now.
FES did not respond to requests for comment on the allegations Wednesday. Attempts to obtain comments from Ohioans for Energy Security and Generation Now also were unsuccessful.
However, Carlo LoParo, a spokesman for Ohioans for Energy Security, told Cleveland.com the lawsuit was a “desperate act.”
“It’s now clear why they’ve peddled irresponsible rumors and made unsubstantiated charges over the past few weeks. They can’t get Ohioans to sign their jobs-killing petition,” he said.
State Attorney General Dave Yost said in a letter to the U.S. attorneys in Columbus and Cleveland that media reports of harassment and intimidation concerned him and that he intended to use all of his office’s resources to “protect the integrity of the petition process.”
Petition “supporters have a right under law to collect signatures without interference,” he said in a press release. “My job as attorney general is to call balls and strikes like I see them, and this one is a wild pitch. It’s time to knock it off.”
The federal suit is the latest twist in the organization’s sprint to gather nearly 266,000 signatures over three months to get the referendum on the November 2020 ballot. (See Ohio Nuke Ballot Petition Approved.)
FES asked the state Supreme Court to block the vote last month, arguing that the new ratepayer fees — ranging from 80 cents up to $2,400/month — are equal to a tax, making the legislation ineligible for being overturned by voters. (See FirstEnergy Solutions Challenges Nuke Vote in Ohio Supreme Court.)
LaRose, in an answer filed with the Supreme Court last month, denied the company’s assertion that he had any legal duty to stop the petition.
A New York court on Tuesday rejected a challenge to the state’s zero-emission credit program, dismissing a suit by Hudson River Sloop Clearwater and others against the Public Service Commission’s 2016 decision to establish the program to subsidize economically unviable nuclear plants.
Acting Justice Roger D. McDonough of the New York Supreme Court in Albany County dismissed all of the suit’s main complaints in a decision that could still be appealed to the state’s highest court, the Court of Appeals.
In their suit, the petitioners argued that the PSC had already authorized the retirement of the R.E. Ginna nuclear plant before implementing the ZEC program and that it failed to properly assess the potential impact of the James A. FitzPatrick plant retiring. They also complained that the PSC’s Tier 3 category for existing renewables under the Clean Energy Standard (CES) was arbitrary and capricious and that it failed to follow its own ratemaking guidelines for monopolies in developing the program.
James A. FitzPatrick Nuclear Power Plant in Scriba, N.Y. | Entergy
“There was adequate administrative support for PSC’s adoption and implementation of Tier 3 … [and] the PSC has offered a rational basis for their ZEC pricing methodology in the unique circumstances presented herein,” McDonough wrote in his ruling.
He also refused to award any costs, fees, disbursements or attorneys’ fees to the petitioners.
Part of the legal challenge concerned the commission’s decision to use the federal government’s social cost of carbon metric to determine how much to pay nuclear power plants for the value of their avoided carbon emissions.
“This ruling affirms that the social cost of carbon is an appropriate and effective tool for state policymakers,” Richard Revesz, director of the Institute for Policy Integrity at NYU School of Law, said in a statement. “New York was right to use the [SCC] in valuing the environmental benefits of avoided carbon emissions. The court ruling could help provide guidance for other states pursuing climate policies.”
The institute had filed an amicus brief arguing that the commission used the SCC exactly as intended, to internalize the external cost of carbon emissions.
The PSC created the program in August 2016 as part of the CES, which set a goal of reducing greenhouse gas emissions by 40% by 2030.
The commission said the program avoided the issues behind the U.S. Supreme Court’s April 2016 ruling in Hughes v. Talen, which voided Maryland regulators’ contract with a natural gas plant as an intrusion into federal jurisdiction over wholesale power markets.
In a briefing to the court, the Coalition for Competitive Electricity, Dynegy, Eastern Generation, NRG Energy, Roseton Generating and Selkirk Cogen Partners — independent power producers that compete with the nuclear plants — and co-plaintiff EPSA claimed the ZEC program “is not an environmental measure … [but] merely a mechanism to benefit the owners of the nuclear power plants.”
