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.”
The escalating battle between bondholders and shareholders to control Pacific Gas and Electric when it exits bankruptcy played out before federal Judge Dennis Montali on Monday, just as PG&E announced it could shut down power to much of Northern California this week to prevent wildfires.
PG&E said portions of 30 counties could be affected by the public-safety power shutoff including most of the urbanized San Francisco Bay Area with 7.75 million residents. The warning did not include the city of San Francisco, where PG&E is undergoing Chapter 11 reorganization as it faces billions of dollars in liability for earlier wildfires.
There was no mention of PG&E’s unprecedented announcement in Monday’s hearing in the U.S. Bankruptcy Court, where Montali often sounded skeptical of the effort by bondholders to end PG&E’s period of exclusivity — the time it has to file and solicit support for its Chapter 11 plan of reorganization. The bondholders hope to wrest control of California’s largest utility from its shareholders with their own plan to settle the claims of wildfire victims and others..
Judge Dennis Montali | U.S. Bankruptcy Court
In exchange for a nearly $30 billion investment, the bondholders would gain a controlling stake in PG&E while wiping out the value of current shareholders’ stock.
Montali said repeatedly he didn’t think the fight over PG&E’s future was doing much good for the victims of wildfires started by PG&E equipment. Blazes in 2017 and 2018 blamed on PG&E included November’s Camp Fire, which killed 86 people and burned down the town of Paradise. Liability for the fires drove the utility into bankruptcy in January.
“Why should we in effect have a corporate control battle when we really ought to be taking care of the victims?” Montali asked attorney Abid Qureshi, who represents the bondholders, formally called the Ad Hoc Group of Senior Unsecured Noteholders.
Qureshi, like other lawyers, said the bondholders’ plan offered fire victims roughly $5 billion more than PG&E’s latest proposal — $13.5 billion compared to $8.4 billion — and would settle the cases without the delay of legal proceedings to estimate damages and to determine liability in the Tubbs Fire, which killed 22 people and destroyed part of the city of Santa Rosa in October 2017. Those proceedings are underway in federal and state court.
The bondholders’ plan recently won the support of the Official Committee of Tort Claimants, which represents fire victims in the bankruptcy case. Others now pushing to end PG&E’s exclusivity include the main group of bankruptcy claimants, called the Official Committee of Unsecured Creditors, as well as consumer watchdog The Utility Reform Network and the International Brotherhood of Electrical workers, PG&E’s largest union. (See Creditor Group Joins Call to End PG&E ‘Exclusivity’.)
PG&E has the support of a group of insurers and investors that hold about $20 billion in subrogation claims, which the company agreed to settle in mid-September for $11 billion. (See PG&E and Insurers Agree to Settle Wildfire Claims.)
Montali ruled Aug. 16 against the bondholders’ first bid to end exclusivity. In Monday’s hearing, he asked lawyers to tell him what had changed that would make him reverse course.
Qureshi argued that the increased support to end exclusivity was a major difference.
“Every creditor constituency in this case that has taken a position on whether to terminate exclusivity with one exception [the subrogation claimant] … is in favor of terminating exclusivity,” the attorney said. Because the bondholders’ plan also offers the subrogation claimants $11 billion, only PG&E and its shareholders are opposed to ending exclusivity, he contended.
Later in the hearing, lawyer Cecily Dumas told Montali that the fire victims she represents are willing to accept the $13.5 billion the bondholders have offered and also urged him to allow the bondholders’ plan to compete with PG&E’s proposal.
In response, the judge elaborated on his concerns about admitting the bondholders’ reorganization plan.
“I’m trying decide whether to listen to the pleas [from] you and everybody else … by even letting that other plan in,” he said. “To be blunt about it, my fear is that having the competing plan turns what was designed to protect the victims into a battle over corporate control … between two different money interests and has nothing to do with paying victims.
“Why do you want to be sitting there waiting to get your victims paid watching a corporate battle that has nothing to do with paying the victims?” he asked Dumas.
She replied that PG&E’s plan isn’t as well-funded as the bondholders’ proposal, and the utility may not be able to pay more than the $8.4 million it proposed.
“There’s risks associated with the debtors’ plan that are made easier by the bondholder plan frankly because they have more resources to throw at it.”
Montali said PG&E’s opening bid was unlikely to be its final offer. He said he would take the new motion to end exclusivity under consideration and issue a ruling later.
‘Strong and Dry’ Winds
Meanwhile, PG&E said meteorologists in its emergency operations center “continue to monitor a potentially widespread, strong and dry wind event Wednesday morning through Thursday afternoon. The event will impact northern, central, coastal and Bay Area counties across much of PG&E’s service area.”
PG&E is the latest of California’s three major utilities to use power shutoffs to prevent fires. San Diego Gas & Electric and Southern California Edison have used the tool for years during hot, windy conditions, though not on the scale PG&E announced Monday.
October and November are prime fire season in California, when air and vegetation are bone dry and powerful winds, including Southern California’s infamous Santa Ana winds, fan infernos.
Public utility commissions from coal-producing states are urging FERC to finish work on its docket opened in January 2018 to solicit information on the issue of grid resilience (AD18-7).
FERC has received letters from at least six state commissions, beginning in late August with the Public Service Commission of West Virginia, which urged “the FERC to move AD18-7 … to a high priority and consider the need for mechanisms and market rules to assure not just a low-cost, but also a reliable, resilient, fuel-secure power supply mix.”
The West Virginia PSC’s letter was followed throughout September by similar ones from the Alabama, Montana, South Carolina, Wyoming and Kentucky commissions. Though not listed in FERC’s eLibrary, Bloomberg reported that the Tennessee Public Utility Commission also sent a letter urging the federal commission to act.
Six of the states — excluding South Carolina — were responsible for 64% of total U.S. coal production in 2017, according to the Energy Information Administration. Wyoming (41%) and West Virginia (12%) ranked Nos. 1 and 2.
South Carolina, which does not produce coal, ranks third in the U.S. in nuclear power generation, getting almost 60% of its power from the source, according to EIA.
Dave Johnston coal-fired plant in Wyoming
FERC opened the docket in January 2018 after it rejected the Department of Energy’s Notice of Proposed Rulemaking to make cost-of-service payments to generators — such as coal and nuclear plants — that have a 90-day on-site fuel supply and are able to provide “essential reliability services.” In its order rejecting the NOPR, the commission directed “the RTOs/ISOs to provide information … that will inform us as to whether additional actions by the commission and the ISOs/RTOs are warranted with regard to resilience issues.”
It received dozens of comments later in May. (See Don’t Rush on Resilience, Commenters Urge.) Its roster of commissioners has changed a few times since then, with the death of Kevin McIntyre, the departures of Cheryl LaFleur and Robert Powelson, and the arrival of Bernard McNamee.
“The lack of a concluding report or order leads many people following this proceeding to assume that no additional steps will be taken by the commission,” the Kentucky Public Service Commission wrote. “In other words, can we assume that no decision is the commission’s decision? If that is the case, communication from the commission needs to occur to provide certainty to affected stakeholders.”
As Avangrid is one of the commenters in the docket, Commissioner Richard Glick is prohibited from working on it until Nov. 29 under an ethics pledge he signed, meaning the commission lacks a quorum to act on the issue at least until then. (See Glick Recusal May Mean No MOPR Ruling Before December.)
That could change, however, if the Senate confirms FERC General Counsel James Danly, President Trump’s nominee to fill McIntyre’s seat.
It could also depend on McNamee. FERC ethics officials have cleared him to participate in the proceeding, but they cautioned in January that “we must exercise continued oversight to ensure that Docket No. AD18-7 does not develop in such a way as to replicate or closely resemble” the DOE NOPR, on which McNamee worked while he was with the department. McNamee received a waiver from the White House on Aug. 29 to work on dockets in which parties are represented by his former employer, McGuireWoods, but not on those in which he himself participated prior to joining the commission.
Each of the state commissions warned FERC that accelerating retirements of coal-fired and nuclear facilities could jeopardize electric reliability and increase prices.
Alabama, Montana and Wyoming used two identical paragraphs: “In the meantime, substantial baseload retirements, especially coal-fired units, and the evolution of the electric power sector, are bringing increased attention to grid resilience and fuel security. Nationwide, 40% (126,000 MW) of the nation’s coal fleet has retired or announced plans to retire. By the end of 2020, some 67,000 MW of coal-fired generating capacity in ISO/RTO footprints will have retired. This total includes more than 10,000 MW that have announced intentions to retire this year and in 2020. The four ISO/RTO regions with the most coal retirements through 2020 are PJM (36,200 MW), MISO (14,800 MW), ERCOT (5,800 MW) and SPP (5,000 MW).
“In addition, 20% of nuclear units (21 of 105) have retired or announced plans to retire by 2030, amounting to over 17,000 MW of capacity.”
Most of the letters were authored by the commission chairs. The Alabama letter, sent by Commissioner Jeremy Oden, appeared to leave intact some language that was intended to be modified, ending with “I/We request…”
Kara B. Fornstrom, chair of the Wyoming Public Service Commission, said the effort was organized by the American Coalition for Clean Coal Electricity (ACCCE), a trade group that supports policies benefiting “coal-fueled electricity and the coal fleet.”
“As part of our outreach, we regularly share information with stakeholders, including utility commissioners, about coal retirements, resilience and fuel security,” ACCCE CEO Michelle Bloodworth said. “Because of the important voice that utility commissioners have, we appreciate the fact that these commissioners agree with the need for FERC action on resilience and hope that other stakeholders will also urge FERC to take action.”
None of the other commissions responded to requests for comment Monday.
In a response on Sept. 19 to the South Carolina Public Service Commission’s letter (which was also not posted in eLibrary), FERC Chairman Neil Chatterjee noted that “several regions are concurrently taking action to improve reliability and resilience, such as introducing new products and services, and developing market rule changes.”
“I also note that the commission already has taken some steps that address resilience of the bulk power system such as approving procedures for utilities to share spare transformers in the event of a system emergency,” Chatterjee wrote. “Further, FERC staff has begun outreach to state utility commissions to discuss how we may exchange information on these issues. The commission continues to work with all stakeholders to ensure that well-developed market rules and reliability standards are in place.”
Pacific Gas and Electric said Tuesday it will cut power to 800,000 customers in portions of 34 northern counties to reduce wildfire risk during a severe wind event.
PG&E said it would implement Public Safety Power Shutoff just after midnight on Wednesday morning. The power will be turned off in stages, depending on the timing of the wind conditions, beginning with counties in the northern part of the state.
“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, senior vice president of 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.”
The 2013 Rim Fire consumed 257,314 acres.| U.S. Department of Agriculture.
Based on the latest forecasts, PG&E anticipates the event to last through mid-day Thursday. Peak winds, measuring 40 to 55 mph, are forecasted Wednesday morning through Thursday morning. Isolated gusts may be between 60 and 70 mph.
Among the areas affected will be Oakland, Berkeley, San Jose, Stockton, Santa Cruz, Redding and Santa Rosa.
The utility has been notifying potentially impacted customers via automated calls, texts and emails. It said customers may be affected even if they are not experiencing extreme weather conditions because of the interconnected grid.
Before restoring power, PG&E said it must inspect equipment for damages and make any necessary repairs. However, that process cannot begin until the severe weather event has subsided. Given the prolonged event period and the miles of power lines that will need to be inspected, customers are being asked to prepare for an extended outage. PG&E will work with state and local agencies to provide updated timelines following the conclusion of the event.
PG&E will open Community Resource Centers in several locations beginning Oct. 9, at 8 a.m. to support customers in affected areas. The locations of those centers can be found here.
The New England Power Pool Participants Committee on Friday voted narrowly not to approve ISO-NE’s recommended installed capacity requirement (ICR) values for Forward Capacity Auction 14 in February 2020.
The motion to support the ICR values including Mystic Units 8 and 9 fell short with 59.97% in favor, just below the 60% threshold for approval (Generation 0%; Transmission 16.79%; Supplier 3.36%; Alternative Resources 9.29%; Publicly Owned Entity 16.79%; and End User 13.74%).
The motion to support the ICR values excluding Mystic Units 8 and 9 failed with a 59.66% vote in favor (Generation 0%; Transmission 16.79%; Supplier 3.05%; Alternative Resources 9.29%; Publicly Owned Entity 16.79%; and End User 13.74%).
NEPOOL rules prohibit RTO Insider from quoting stakeholders’ comments during the meeting. However, Margo Caley, the RTO’s senior regulatory counsel, confirmed after the meeting that ISO-NE will file the ICR values with FERC on Nov. 5 without NEPOOL support.
Excluding Mystic 8 and 9, ISO-NE is proposing a net ICR of 32,495 MW for FCA 14 (2023/24), a reduction of 1,255 MW from FCA 13.
COO Vamsi Chadalavada reported that Exelon has until Jan. 20 to decide whether to retire Mystic 8 and 9 for FCA 14, which will acquire resources for delivery year 2023/24.
The Reliability Committee on Sept. 25 had also rejected the proposed ICR calculations, with unanimous opposition from the Generation and Supplier sectors. (See Supply Side not Buying ISO-NE’s ICR Numbers.)
In related business, the PC approved by a show of hands a 941-MW value for the Hydro-Québec interconnection capability credit (HQICC) for FCA 14, including the capacity associated with Mystic, and a 943-MW HQICC excluding it.
Nautilus Power proposed amendments to recalculate the HQICC and ICR values without the RTO’s gross load forecast methodology, but the proposals all failed on a show of hands.
Energy Market down for September
ISO-NE CEO Gordon van Welie had nothing to report, but Chadalavada did report on monthly operations results and other items.
The energy market value in September, through Sept. 25, was $182 million, down $139 million from August 2019 and down $221 million from September 2018, Chadalavada said.
September natural gas prices over the period were 2.6% higher than August average values, he said.
Average real-time hub LMPs ($20.97/MWh) over the period were 11% lower than August averages, while average natural gas prices and real-time hub LMPs for the month were down 29% and 49%, respectively, from September 2018 averages.
The average day-ahead cleared physical energy during the peak hours as percent of forecasted load was 99.6% during September, down from 101.3% during August, with the minimum value for the month of 95.4% recorded on Saturday, Sept. 7.
ISO-NE Draft 2020 Work Plan
Chadalavada presented a memo on the RTO’s draft 2020 Work Plan, which takes account of FERC’s Aug. 30 ruling granting ISO-NE another six months, until April 15, 2020, to file a long-term fuel security mechanism (EL18-182). (See FERC Extends ISO-NE Fuel Security Filing Deadline.)
The RTO plans to devote most of its planning resources to the Energy Security Improvements (ESI) project from October 2019 through April 2020, with a focus on:
core day-ahead ancillary services design;
impact assessment of day-ahead ancillary services;
conceptual framework for mitigation of day-ahead ancillary services; and
forward market construct.
Additional work, such as changes to net commitment period compensation rules, will be needed beyond the initial filing to enhance the mechanism, he said.
Energy Security Improvements dominate the RTO’s markets-related priorities for 2020. | ISO-NE
Chadalavada said the RTO would work closely with stakeholders on day-ahead ancillary services design but that changes to the core design would require extra time.
The RTO is working with Analysis Group to assess the market impacts of ESI and anticipates having a draft impact analysis available for stakeholders in February.
Chadalavada said the RTO will provide stakeholders information about the prospective mitigation design approach before April 2020 but that a detailed mitigation design and market rules will require a later filing.
The RTO will also explore whether a forward market construct would improve the region’s energy security needs, but a detailed review will not be complete before the April filing, he said.
Consent Agenda
The Participants Committee voted to approve in a single vote three items on the consent agenda:
A revision to Market Rule 1 section III.13.2.5.2.5A (Fuel Security Reliability Review) that limits the retention of resources needed for fuel security to a two-year maximum, removing a provision that could extend a resource’s retirement beyond the two-year fuel-security retention period.
Clean-up revisions to Market Rule 1 section 13 were identified during the price-responsive demand implementation process. They remove the requirement for the RTO to publish the quantity of demand capacity resources at the end-of-round price for each capacity zone as the FCA is being conducted. The revisions also clarify the energy market offer requirements of demand response resources that participate in the FCA.
Changes were approved for operations manuals M-11, M-20, M-35, M-REG, M-RPA and M-36 to comply with FERC Order 841, which is intended to encourage electric storage participation in the wholesale markets. The manual changes pertaining to enhanced storage participation became effective upon PC approval. Changes related to Order 841 compliance will take effect in December, while those related to setting the maximum discharge limit of an electric storage facility when it has less than one hour of available energy would be effective in two phases in December and March 2020.
The PC also approved two items concerning FERC Order 1000 compliance and intraregional planning that would have been on the consent agenda but for time constraints:
The first item was revisions to the ISO-NE Tariff: Attachment K, Schedules 12 and 12C of section II, the Selected Qualified Transmission Project Sponsor Agreement, and sections I.2.2 and I.3.9, as recommended by the Transmission Committee.
The last item approved was revisions to Market Rule 1 section III.12.6 and section I.2.2 (Definitions), as recommended by the Reliability Committee.
Chadalavada said that 21 companies have achieved qualified transmission project sponsor (QTPS) status, and that one company is currently moving through the QTPS application process.
Based on the results of the Boston Needs Assessment to date, the RTO will release its first request for proposals for a competitively developed transmission solution in late 2019 or early 2020, and anticipates a Tariff filing by Oct. 11, he said.
Draft RFP templates are being updated based on stakeholder feedback and will be reposted for Planning Advisory Committee comment in mid-October.
Price-responsive demand energy market activity by month | ISO-NE
ISO-NE and NESCOE Budgets OK’d
The PC unanimously supported the RTO’s proposed 2020 operating and capital budgets, as well as the 2020 budget of the New England States Committee on Electricity.
Kenneth Dell Orto, chair of the Budget and Finance Subcommittee, led the presentations.
ISO-NE’s 2020 operating budget of $201.7 million, including depreciation and excluding the true-up, is an increase of 1.9% or $3.7 million compared to this year’s operating budget. Including the true-up, the budget results in a 5.4% increase to the revenue requirement compared to 2019. The RTO’s 2020 capital budget remained unchanged at $28 million.
NESCOE’s 2020 budget is $2,421,056, up from $2,350,787 this year, and conforms to the five-year pro forma planning, he said.
Litigation Report
NEPOOL Secretary David Doot, an attorney with Day Pitney, highlighted three items from the monthly litigation report.
First, FERC on Sept. 19 launched a rulemaking to overhaul its regulations under the Public Utility Regulatory Policies Act, the 1978 federal law enacted to spur competition in the U.S. electricity sector (RM19-15, AD16-16). (See FERC to Reshape PURPA Rules.)
Second, the commission ruled that a New Hampshire law requiring the state’s utilities to purchase power from biomass and waste generators encroaches on federal jurisdiction under the Federal Power Act and PURPA (EL19-10). (See FERC: NH Bill Encroaches on Fed. Powers.)
FERC last week said that SPP’s proposal to add the defined terms “load-serving entity” and “non-load-serving entity” to its membership agreement became automatically effective (ER19-2524).
The commission said that because it lacked a quorum and did not act on SPP’s request within a 60-day period, the revisions are effective by “operation of law,” under Section 205 of the Federal Power Act.
Chairman Neil Chatterjee and Commissioner Bernard McNamee filed a joint statement Friday saying they would have accepted SPP’s proposed revisions, effective Oct. 1, as requested.
FERC is currently down to three commissioners while it waits for two seats to be filled. However, Commissioner Richard Glick is precluded from acting on proceedings involving his former employer, Avangrid, until Nov. 29. (See Glick Recusal May Mean No MOPR Ruling Before December.)
In a statement, Glick said that while Avangrid was not a intervenor in the docket, “The substantive issues presented relate directly to a contested issue in another pending proceeding” (EL19-11).
Invenergy is among the many intervenors in SPP’s membership exit fee docket. | Invenergy
SPP’s revisions are related to a complaint filed last year by the American Wind Energy Association and the Advanced Power Alliance over the RTO’s membership exit fee. FERC in April agreed with AWEA and APA and ordered the grid operator to lower its exit fee to $100,000, a 67% reduction from current levels. Avangrid Renewables is among the many intervenors in that docket. (See FERC Tells SPP to End Exit Fee for Non-TOs.)
Chatterjee and McNamee said they agree with SPP that defining the LSE and non-LSE terms “provides clarity to members as to which level of withdrawal deposit will apply in the event that a member submits a notice of intent to withdraw.” LSEs would also be subject to an additional fee based on their net energy-for-load share of the RTO’s financial obligations and future interest.
SPP has requested a rehearing of FERC’s April decision, although it made a compliance filing reducing the fee as ordered in August. (See “Directors Lower Exit Fee to $100K,” SPP Board of Directors/MC Briefs: July 30, 2019.) The RTO said the commission’s conclusion that SPP’s exit fee was a “barrier to membership” was incorrect. “All that the exit fee does is require that members have ‘skin in the game,’ thereby serving as the quid pro quo for the privilege of obtaining voting rights,” SPP said.
Several LSEs — including American Electric Power, Evergy, Golden Spread Electric Cooperative, the Nebraska Public Power District and Xcel Energy — also requested rehearing. “While the commission is wrong that the existing exit fee formula is unjust and unreasonable, it is arbitrary and capricious to conclude that the complete elimination of any exit fee for non-transmission owners would be just and reasonable,” they said.
The commission issued a tolling order on June 17 giving it more time to consider the rehearing requests.
President Trump last week nominated FERC General Counsel James Danly to fill one of the two vacant seats. There has been no nominee for the other vacancy. (See related story, Dems, Enviros Upset Over Solo FERC Nomination.)
