MISO will shut down its regional planning office in Metairie, La., by the end of next year, RTO officials confirmed Wednesday.
The move will leave MISO with three physical locations: Carmel, Ind., Little Rock, Ark., and Eagan, Minn. MISO said it will not renew the lease at the Two Lakeway Center office building in the New Orleans metro area when it expires at the end of 2019. By then, the RTO hopes to complete relocation of employees and equipment.
MISO Metairie office location | Google
MISO spokesman Mark Adrian Brown said every employee at the Metairie office has the option to relocate to one of the other three offices. He said RTO leadership first disclosed the closure to employees in spring to ensure they had enough time to make relocation plans.
MISO is assisting affected employees with the transition. “We are working with each individual to ensure they have the information and support they need during this process,” Brown said.
The RTO has maintained the Metairie location since 2012, the year before it officially integrated Entergy’s territories into its footprint.
The closure will save MISO money, but it’s not clear how much, as the RTO doesn’t disclose how much it spends on property. Brown said shuttering the space will help support the RTO’s “overall organizational health.”
“MISO carefully studied a number of factors in the decision-making process. MISO is a steward of our members’ resources, and we must always consider the most efficient solutions and opportunities that enhance the value we deliver,” Brown in an email to RTO Insider. He added that the move would bring employees together and allow them to collaborate in its remaining and more modern regional offices.
In a 2019 budget report to the Audit and Finance Committee of the Board of Directors, Finance Subcommittee Chair Mitchell Myhre of Alliant Energy said the closure will “provide financial benefits in 2019 and beyond.” In recommendations this year, the seven-member committee also said MISO should be open to decreasing its scope of operations to cut costs.
MISO’s 2019 budget has not yet gone before the larger stakeholder community. The Finance Subcommittee will present the 2019 budget to the Advisory Committee on Oct. 24. The RTO is recommending a $312.6 million total operating budget and $27.2 million capital expense budget. MISO’s base operating budget, at $269.6 million, represents a 2% increase from 2018. (See “MISO Spending Closely Tracks 2018 Limit; RTO Ups 2019 Budget,” MISO Board of Directors Briefs: Sept. 20, 2018.)
FERC on Thursday approved reliability standards for mitigating supply chain risks in industrial control system hardware, software and computing and networking services. The commission also ordered NERC to develop rules expanding the supply chain protections to include electronic access control and monitoring systems (EACMS).
The commission’s final rule, intended to build on existing critical infrastructure protection (CIP) standards, approved NERC reliability standards CIP-013-1 (Cyber Security – Supply Chain Risk Management), CIP-005-6 (Cyber Security – Electronic Security Perimeter(s)) and CIP-010-3 (Cyber Security – Configuration Change Management and Vulnerability Assessments). The final rule hews closely to the commission’s January 2018 Notice of Proposed Rulemaking (RM17-13). (See FERC Backs NERC Supply Chain Standards.)
| Pixabay
The new rules, effective 60 days after publication in the Federal Register, will be implemented over 18 months, as requested by NERC. The commission said the transition was needed because compliance will likely require technical upgrades, with implications for capital budgets and planning cycles that have longer time horizons.
Counterfeits, Malicious Software
The rules are intended to protect the bulk electric system from counterfeits or malicious software and tampering. They require affected entities to implement security controls addressing: software integrity and authenticity; vendors’ remote access; information system planning; and vendor risk management. FERC said the rules will cover 288 reliability coordinators, generator operators, generator owners, interchange coordinators or authorities, transmission operators, balancing authorities and transmission owners.
FERC acknowledged the rules did not cover the supply chain risks of EACMS such as firewalls, authentication servers, security event monitoring systems, and intrusion detection and alerting systems. The commission said NERC must propose rules to address the gap within 24 months. “Once an EACMS is compromised, an attacker could more easily enter the [electronic security perimeters] and effectively control the BES cyber system or protected cyber asset,” FERC said.
The commission also noted the standards generally don’t address physical access control systems (PACS) or protected cyber assets (PCAs). “We remain concerned that the exclusion of these components may leave a gap in the supply chain risk management reliability standards. Nevertheless, in contrast to EACMS, we believe that more study is necessary to determine the impact of PACS and PCAs,” the commission said. “Compromise of PACS and PCAs are less likely. For example, a compromise of a PACS, which would potentially grant an attacker physical access to a BES cyber system or PCA, is less likely since physical access is also required.”
Budgets OK’d
The commission also approved NERC’s 2019 business plan along with almost $166 million in spending allocated for the U.S. share of funding NERC, its regional entities and the Western Interconnection Regional Advisory Body (WIRAB) (RR18-9).
The 2019 budgets include $62.5 million for NERC; $102.8 million for its seven regional entities’ funding and almost $630,000 for WIRAB.
Including funding from other sources, NERC’s 2019 budget is $79.1 million, an 8.4% increase over 2018. Most of the increase is attributed to expanding staffing and functions at its electricity information sharing and analysis center (E-ISAC). (See New NERC Chief Not ‘Smartest Guy in the Room’.)
NERC’s budget includes 205 full-time equivalents, an increase of six from 2018.
WASHINGTON — FERC on Thursday approved SPP’s proposal to allow generators to include major maintenance costs associated with the number of starts or run hours in their mitigated start-up and no-load offers in the RTO’s energy market (ER18-1632).
Under the changes, effective Jan. 15, 2019, generation owners will be required to submit each of their resources’ maintenance costs to SPP’s Market Monitoring Unit. If they’re validated, the MMU will then assign the costs by maintenance activity to either the resource’s start-up offer or the no-load offer.
Maintenance workers inspect a turbine. | Turbine Generator Maintenance
SPP said the proposal would not only result in more accurate compensation for generators’ costs, but also better help the RTO determine whether to dispatch resources and incent generators to run when dispatched.
Stakeholders had debated over what qualifies as major maintenance, and SPP decided to allow only activities agreed to in advance by the MMU and the resource owner to be eligible for cost recovery. Generation owners have 30 days to submit these to the MMU, which estimates that more than half of the 700 resources in SPP will apply to include major maintenance costs in their offers.
“We find SPP’s proposal to include a major maintenance cost component in mitigated start-up offers and mitigated no-load offer to be a just and reasonable means of addressing concerns over the recovery of costs resulting from the gradual deterioration of resources’ operating equipment in the SPP Integrated Marketplace,” the commission said.
The changes received support from the MMU, which had opposed earlier versions of the proposal, as well as City Utilities of Springfield and Golden Spread Electric Cooperative. No one submitted protests.
Chairman Kevin McIntyre did not attend Thursday’s open meeting and did not vote on the order.
While the deadline for compliance filings on FERC Order 845 remains at least three months away, PJM is making sure it’s prepared.
During an Oct. 16 conference call, PJM staffers Susan McGill and Michelle Harhai outlined 10 reforms included in the order, six for which the RTO has already drafted Tariff changes. The remaining four are in progress.
The order, expected to remove even more barriers to storage interconnection, explicitly revises the definition of a generating facility to include storage, permits interconnection customers to apply for interconnection service lower than the capacity of their generating facilities and requires transmission providers to provide interim interconnection agreements for limited operation of generating facilities prior to completion of the full interconnection process.
FERC on Oct. 3 granted an extension of the compliance filing deadline to 90 days while it considers multiple requests for rehearing of the order.
Energy storage | SDG&E
Takis Laios of American Electric Power said his company is finishing proposed revisions of PJM’s governing documents that it plans to submit for consideration.
PJM’s Pauline Foley said the revisions should be submitted “sooner rather than later” and cautioned Laios that because it’s a compliance filing, staff are trying to keep revisions “within the scope of [the order].”
“Anything beyond that would really be better handled in the stakeholder process,” she said.
Foley also noted that part of the challenge is marrying FERC’s order, which make assumptions about what’s already in grid operators’ tariffs, with what’s actually in PJM’s Tariff.
“The commission presumes that certain provisions are included in our Tariff, and a lot of the provisions when we originally made our 2003 compliance filing were not exactly as pro forma,” she said. With the expanded rules that FERC ordered, “we need to confirm that all of the provisions FERC presumes are there are actually there,” she said.
In response to a stakeholder question, Foley added that while “it’s not really practical to implement the order” before it’s fully been approved, interconnection customers can seek mutual agreements with transmission owners to utilize some of the impending rule changes.
MISO is hoping to avoid grid instability by possibly requiring inverter-based generation seeking to enter the interconnection queue to provide a specific set of calculations and documentation.
Under the plan, the owner of an inverter-based resource would be required to supply MISO its short-circuit ratio at the point of interconnection before completing an application. The RTO is also contemplating having a project owner either submit a manufacturer statement showing the inverter can operate stably or an Electromagnetic Transients Program (EMTP) study report confirming stable operation. Any project owner unable to prove stable operation will either have to add equipment to raise the short-circuit ratio or reduce the size of the project.
MISO interconnection engineer Warren Hess said the RTO will disallow use of its “momentary cessation” of active power output from inverter-based resources in order to prevent them from tripping offline unnecessarily. In that case, every generation resource would have to adhere to NERC’s PRC-024-2 standard, which requires generator owners to set their protective relays to ensure generating units remain connected during defined frequency and voltage excursions.
But stakeholders on an Oct. 16 Planning Subcommittee conference call said MISO might be requiring too much of inverter-based customers too early in the queue process. Some said the RTO should consider asking for short-circuit ratio values later in the queue process because those values will change as projects drop out of the queue. Consultant Roberto Paliza said such information should be provided at the end of the queue’s definitive planning phase, adding that MISO should make it clearer what performance standards it requires of inverter-based generation.
But Hess said that short-circuit calculations are relatively easy to provide once customers know the locations of their interconnections. He said MISO wants to avoid entering projects into the queue that ultimately cannot perform without causing harm.
“We are going to be here for guidance to help to calculate short-circuit ratios and coordinate with the applicable transmission owners. Since interconnection customers are deciding where to connect on the system, they should be responsible to work with the transmission owners to get short-circuit ratios for their inverter-based interconnection,” MISO Resource Interconnection Planning Manager Neil Shah said.
“Not doing anything is not an option,” agreed MISO Manager of Resource Interconnection Arash Ghodsian.
MISO staff also promised to work with interconnection customers and transmission owners to gather information and provide guidance on new interconnection requirements.
“This is going to be a two-way street,” Ghodosian said.
Staff said they plan to present draft Tariff language on the possible requirements at the Planning Subcommittee’s December meeting.
In two orders issued late last week affecting MISO’s generator interconnection queue, FERC rejected a maintenance fee for interconnection customers while also approving a new process for interconnecting external merchant HVDC transmission.
The commission on Oct. 12 rejected without prejudice MISO’s plan to create a new mechanism to allow transmission owners to calculate and recoup expenses related to the operation and maintenance of transmission owner interconnection facilities (TOIFs) (ER18-1731-001). TOIFs are “sole use” facilities that includes all infrastructure owned by the TO from the point of the change of ownership (on the system) to the point where an interconnection facility connects to the transmission system.
MISO proposed the “Annual O&M and Overheads Charge” because, while its current generator interconnection agreement makes interconnection customers responsible for all TOIF expenses, the RTO’s Tariff currently provides no method for TOs to recover those costs. The proposed charge would have been calculated by TOs and invoiced annually to interconnection customers, treating revenues from the charge as a revenue credit and subtracting it from a TO’s net revenue requirement.
MISO and the TOs contended their proposal was consistent with FERC’s cost-causation principles because the recovery mechanism ensured interconnection customers would pay their proportional share of maintenance expenses for interconnection facilities, eliminating the possibility that other customers would subsidize the facilities.
But the commission took issue with MISO allowing TOs to calculate the charge using estimated construction costs of the interconnection facilities from the GIA when they cannot determine the facilities’ actual costs. FERC said it wasn’t just or reasonable to allow use of estimates without requiring TOs to support their figures with a Section 205 filing. FERC also said MISO and the TOs did not provide evidence that the estimates would be a “reasonable proxy” for actual construction costs.
The commission additionally pointed out that MISO doesn’t file GIAs — which include the cost estimates — when they conform to its pro forma GIA template. It also pointed out the TOs don’t typically file detailed cost support for their GIA estimates of interconnection facilities. Consequently, MISO and the TOs essentially asked FERC to “accept the use of estimated values for the purpose of deriving a charge for operation, maintenance and repair of the facilities during their service lives without an opportunity to review the reasonableness of such estimates as a proxy for actual … costs,” the commission said.
FERC added that any future proposal should contemplate a partial-year charge for GIAs that expire midyear.
But FERC did accept MISO’s proposal to allow external merchant HVDC transmission projects to connect to its grid, effective July 18 (ER18-1410). The interconnection process is largely based on MISO’s existing queue rules but includes a separate pro forma “MHVDC” connection request form, a pro forma transmission connection agreement and a process for obtaining injection rights, which the project owner converts into external network resource interconnection service (E-NRIS) for its upstream generating facilities. In response to an initial deficiency letter from FERC, MISO explained that it relied on interconnection rules previously approved by FERC and an exhaustive stakeholder process to settle on the new process. (See FERC: MISO Merchant HVDC Procedures Incomplete.)
FERC said MISO’s plan was reasonable: “Because the MHVDC connection customer will go through MISO’s full interconnection process alongside internal generation customers, no issues of undue discrimination or preferential treatment arise between the external generators that may use the E-NRIS converted from injection rights and internal or other external generators that obtain NRIS or E-NRIS, respectively, through MISO’s [generator interconnection process].”
PJM has already missed its Board of Managers’ deadline for revising how it forms prices in its energy market, evoking the question: How much longer will the process drag on?
In April, the board instructed RTO staff to identify changes that could be in place for this winter and asked stakeholders “to deliberate timely” so a proposal could be sent to FERC in the third quarter. (See PJM Board Seeks Reserve Pricing Changes for Winter.) Staff emphasized at a meeting of the Energy Price Formation Senior Task Force (EPFSTF) last Friday that the deadline has passed and asked stakeholders to prepare for a vote at the task force’s next meeting on Nov. 1.
“We’ve missed that [deadline] already, so we’re trying to work as expeditiously as possible to respect their request,” PJM’s Dave Anders said.
“I really want to be able to respect the board’s wishes, and I do respect them. I’m not sure if I can in good conscience honor them. I just don’t think we’re ready to vote,” Old Dominion Electric Cooperative’s Adrien Ford said. “I want to get this right, and I don’t want a board letter to be the reason we don’t get it right.”
“I don’t want to throw in the towel and say this will take as long as it takes,” Anders said in response to the hesitation. He asked stakeholders to come prepared to work toward a vote at the next meeting.
Part of the hang-up might be that PJM has presented all its arguments for why the market should be reformed, and stakeholders aren’t convinced. PJM’s Adam Keech asked what details the RTO hasn’t provided yet.
“There are a lot of eyes on what this group accomplishes,” he said.
“For me, the main thing that’s been missing and that’s always been missing is the motivation for this,” said James Wilson of Wilson Energy Economics, who consults for several consumer advocates within the RTO’s footprint. “I don’t really think you’ve made the case that reserves beyond [the minimum reserve requirement] are worth several hundred dollars.”
The task force has been attempting to resolve concerns that the energy market doesn’t properly attract resources with the benefits, or attributes, necessary for grid reliability. In July, PJM unveiled a proposal to procure reserves on a more granular level, along with implementing nodal reserve pricing, a real-time 30-minute reserves product and flexible sub-zone modeling. At a task force meeting last month, PJM’s Independent Market Monitor proposed revising the operating reserve demand curve to compare the value of purchasing reserves now to fill potential shortages later, rather than purchasing them later during the peak hours of the day. (See PJM Price Formation Group Talks Reserves.)
The Monitor’s Catherine Tyler revisited the proposal at last week’s meeting, explaining that the point of the plan is to avoid turning on more units than necessary while also capturing in prices the cost of operator actions taken to avoid reserve shortages. The proposal prompted skepticism for an apparent disconnect in how paying for reserves now could reduce scarcity risks later in the day.
Tyler said the Monitor’s proposal is “selectively targeting the times when the market would procure additional reserves,” unlike PJM’s.
FERC on Thursday approved reliability standards for mitigating supply chain risks in industrial control system hardware, software and computing and networking services. The commission also ordered NERC to develop rules expanding the supply chain protections to include electronic access control and monitoring systems (EACMS).
The commission’s final rule, intended to build on existing critical infrastructure protection (CIP) standards, approved NERC reliability standards CIP-013-1 (Cyber Security – Supply Chain Risk Management), CIP-005-6 (Cyber Security – Electronic Security Perimeter(s)) and CIP-010-3 (Cyber Security – Configuration Change Management and Vulnerability Assessments). The final rule hews closely to the commission’s January 2018 Notice of Proposed Rulemaking (RM17-13). (See FERC Backs NERC Supply Chain Standards.)
| Pixabay
The new rules, effective 60 days after publication in the Federal Register, will be implemented over 18 months, as requested by NERC. The commission said the transition was needed because compliance will likely require technical upgrades, with implications for capital budgets and planning cycles that have longer time horizons.
Counterfeits, Malicious Software
The rules are intended to protect the bulk electric system from counterfeits or malicious software and tampering. They require affected entities to implement security controls addressing: software integrity and authenticity; vendors’ remote access; information system planning; and vendor risk management. FERC said the rules will cover 288 reliability coordinators, generator operators, generator owners, interchange coordinators or authorities, transmission operators, balancing authorities and transmission owners.
FERC acknowledged the rules did not cover the supply chain risks of EACMS such as firewalls, authentication servers, security event monitoring systems, and intrusion detection and alerting systems. The commission said NERC must propose rules to address the gap within 24 months. “Once an EACMS is compromised, an attacker could more easily enter the [electronic security perimeters] and effectively control the BES cyber system or protected cyber asset,” FERC said.
The commission also noted the standards generally don’t address physical access control systems (PACS) or protected cyber assets (PCAs). “We remain concerned that the exclusion of these components may leave a gap in the supply chain risk management reliability standards. Nevertheless, in contrast to EACMS, we believe that more study is necessary to determine the impact of PACS and PCAs,” the commission said. “Compromise of PACS and PCAs are less likely. For example, a compromise of a PACS, which would potentially grant an attacker physical access to a BES cyber system or PCA, is less likely since physical access is also required.”
Budgets OK’d
The commission also approved NERC’s 2019 business plan along with almost $166 million in spending allocated for the U.S. share of funding NERC, its regional entities and the Western Interconnection Regional Advisory Body (WIRAB) (RR18-9).
The 2019 budgets include $62.5 million for NERC; $102.8 million for its seven regional entities’ funding and almost $630,000 for WIRAB.
Including funding from other sources, NERC’s 2019 budget is $79.1 million, an 8.4% increase over 2018. Most of the increase is attributed to expanding staffing and functions at its electricity information sharing and analysis center (E-ISAC). (See New NERC Chief Not ‘Smartest Guy in the Room’.)
NERC’s budget includes 205 full-time equivalents, an increase of six from 2018.
All three of California’s big investor-owned utilities this week shut down power or warned customers they might need to because of dry, windy conditions that could lead to wildfires, prompting one consumer group to call for a probe into the practice.
It was the first time Pacific Gas and Electric has cut off power to consumers in Northern California based on fire hazards. Southern California Edison and San Diego Gas & Electric have taken such steps before when the hot Santa Ana winds picked up, as happened Monday and Tuesday.
California’s investor-owned utilities have been cutting power to residents during the state’s fall fire season. | Bureau of Land Management
With large fires becoming more the norm, and the state asking utilities to de-energize lines during severe weather conditions, California’s summer and fall fire season is becoming a time of rolling blackouts in fire-prone areas.
Some ratepayer advocates, however, criticized the utilities this week for jumping the gun. They said the power outages may have been more about avoiding liability and sending a political message than about protecting residents.
“We clearly think it’s blackout blackmail,” said Jamie Court, president of Consumer Watchdog, an advocacy group based in Los Angeles.
The IOUs and Gov. Jerry Brown had urged state lawmakers this year to do away with California’s unique system of holding utilities strictly liable for wildfire damage to private property. But the bill Brown signed in September, SB 901, left that strict-liability standard, often called inverse condemnation, unchanged.
The new law requires utilities to file wildfire mitigation plans with the state that include procedures for shutting down power in extreme weather to prevent fires. (See California Wildfire Bill Goes to Governor.)
“They didn’t get inverse condemnation [changed],” Court said. “They want to get out of liability forever for everything, and this is the way they send a signal. The biggest power a utility has is the ability to turn off power.”
‘Last Resort’
PG&E spokeswoman Angela Lombardi said the decision to cut off power this week was solely about wildfire prevention.
“Power safety shutoff will only be done as a last resort,” Lombardi told RTO Insider. “It’s only in the interest of public safety.”
The company took the unprecedented step Sunday and Monday of shutting off power to about 60,000 customers and notifying 37,000 others they could lose power because of gusting winds and dry vegetation in the northern San Francisco Bay Area and the Sierra Nevada foothills near Sacramento. (See PG&E Shuts down Power to Prevent Fires.)
State fire authorities have blamed PG&E’s equipment for sparking numerous fires in Northern California during the 2017 fire season, one of the most destructive in California’s history. The utility is facing billions of dollars in damages for those blazes, which occurred during times of high winds and low humidity.
, National Weather Service
In Southern California, San Diego Gas & Electric notified 4,700 customers Sunday their power could be shut off “with the onset of Santa Ana winds and extremely low vegetation moisture forecasted for the next two days.” The company ended up cutting power to 360 customers living in the foothills near the Cleveland National Forest and had restored power to most as of Tuesday. A red-flag warning remained in effect.
SDG&E, widely considered a state leader in wildfire prevention, has de-energized lines a number of times in the past because of hazardous fire conditions.
Southern California Edison issued warnings this weekend that it might have to shut down power as hot, dry Santa Ana winds began blowing from the desert to the ocean. The winds are typically a harbinger of Southern California’s wildfire season, which tends to peak in the fall but has become more of a year-round problem in recent years with drought and climate change.
CPUC Monitoring
Court, with Consumer Watchdog, said the conditions that prompted the utilities to shut down power were not sufficient to cut off power, especially to schools and to the elderly and infirm, including those who rely on oxygen machines.
“If there are no fires or firefighters in an area, there is no reason for a utility to shut down power unless they know they have faulty equipment or problems with vegetation management,” he said.
Consumer Watchdog sent a letter to California Public Utilities Commission (CPUC) President Michael Picker on Tuesday urging him to launch an investigation of PG&E’s power shutdown and to “investigate each and every time a utility turns out the lights due to high winds.”
In an email, CPUC spokeswoman Terrie Prosper said the commission had been monitoring this week’s power shutdowns and warnings.
“We will do a post-event review, including the factors that went into PG&E’s decision to de-energize, customer outreach and notification and restoration times.”
In general, Prosper added, “the state’s investor-owned utilities have general authority to shut off electric power to protect public safety under California law, specifically California Public Utilities Code (PU Code) Sections 451 and 399.2(a).
“The utilities have recently developed programs to exercise this authority during severe wildfire threat conditions as a preventative measure of last resort,” she said.
PJM’s Board of Managers said Tuesday it will conduct an “independent review” into GreenHat Energy’s massive default in the RTO’s financial transmission rights market.
The investigation comes amid pressure from PJM members for answers regarding the June default, which — with losses expected to exceed $100 million — is likely to be the RTO’s largest ever. (See PJM Reeling from Major FTR Default.) The board said it will throw open its books in response.
GreenHat listed its address as 826 Orange Ave., Suite 565, Coronado, Calif. — a UPS store between a nail salon and a RiteAid. | Google
“Examiners will have complete access to PJM records and staff for interviews and documentation review,” according to a news release.
The default highlighted flaws in the FTR market that allowed GreenHat traders, who had already been linked to a 2013 energy-market scandal, to amass the largest-ever portfolio of positions — 890 million MWh — on $600,000 in collateral. PJM has since identified “lessons learned” following a workshop staff conducted with independent experts and addressed many of the gaps through stakeholder-endorsed rule revisions, but member questions still remain. (See Doubling Down – with Other People’s Money.)
PJM analysis shows the continuing downward trajectory of GreenHat’s FTR portfolio. | PJM
The board has formed a special committee, chaired by board member Susan Riley, that also includes members John McNeely Foster and Mark Takahashi, along with “independent third-party experts.” Among the experts are Robert Anderson, executive director of the independent nonprofit Committee of Chief Risk Officers, and Neal Wolkoff, CEO of Wolkoff Consulting Services. Wolkoff was previously chairman and CEO of the American Stock Exchange and chief operating officer of the New York Mercantile Exchange. The Philadelphia firm of Schnader Harrison Segal & Lewis LLP has been retained as counsel.
The committee promises to answer outstanding questions about the default and highlights four goals:
examine the facts and circumstances associated with GreenHat’s participation in the FTR market and its subsequent default
assess PJM’s actions in connection with GreenHat
review lessons learned and make recommendations for the future of FTR markets
address questions raised by the members concerning the circumstances of the default
PJM members pressed the board for an independent investigation at their Oct. 3 meeting of the Liaison Committee. The committee, which bans media attendance, is an opportunity for PJM members to meet directly with the board several times throughout the year.
East Kentucky Power Cooperative’s Chuck Dugan, the committee’s chair, detailed members’ concerns in an Oct. 10 letter to PJM CEO Andy Ott. Dugan said several questions about the default were raised at the meeting and members are “pleased” the board agreed to the investigation.
The letter outlines six questions members have about PJM’s awareness, responsiveness and transparency regarding GreenHat’s portfolio, including why staff, after apparently learning about the potential default in February 2017, failed to inform members and instead proposed modifications to the RTO’s credit policy for members’ endorsement as if they were unprovoked.
Dugan acknowledged the investigation “will require time” but requested progress reports at upcoming Members Committee meetings. A PJM spokesperson could not provide a target date for completing the investigation.
