PJM’s state advocates and regulators want the organization to focus on external candidates as it continues the search for a new CEO — someone capable of prioritizing policy goals above “comity” with neighboring RTOs and ISOs.
Leaders from the Organization of PJM States Inc., the New Jersey Board of Public Utilities, the Consumer Advocates of the PJM States, and attorneys general from Delaware, Maryland and D.C. sent letters last week to the head of the RTO’s search committee, Board of Managers member Neil Smith, detailing what qualities former CEO Andy Ott’s replacement should possess. (See PJM CEO Andy Ott to Retire.)
Ott announced his retirement effective June 30 after two decades with the RTO, during which time he helped launch the wholesale energy market and navigated the fallout of the GreenHat Energy default, the latter of which he described as one of his greatest challenges.
Interim CEO Susan J. Riley said last week she expects to be around “about four months” while the search committee picks a new leader — and everyone, whether inside PJM or not, is on the table.
Some stakeholders hope it’s the latter of those two categories, however.
Aside from an economic and policy background and commitment to ushering in a cleaner power grid, CAPS President Kristin Munsch said the new CEO should want to work with states’ environmental goals — not against — and build a stronger partnership with the Independent Market Monitor.
“Just as PJM recognizes the rights of states to their policies, PJM must recognize the right of the IMM to be an independent body,” she said. “Arguments parsing Tariff language distract from the larger questions of how to use competitive markets to provide affordable and reliable electricity service.”
Acknowledging the necessity for PJM “to constructively work” across its seams on the “shared mission of reliability, New Jersey BPU President Joseph Fiordaliso also contended that “PJM management too often elevates a desire for comity with its sister ISOs and RTOs over representing the public interests of its own constituent states.
“This issue is particularly important to states like New Jersey, which sit directly on the seam between PJM and the New York Independent System Operator, and which have been responsible for fully one-third of all PJM transmission costs allocated over the past 15 years,” Fiordaliso said.
He said stymying climate change must be top of mind for PJM’s new leader as the RTO stands at the precipice of “tectonic shifts in their mission.”
Fiordaliso said an outside candidate could serve as a “fair and neutral arbitrator” among stakeholders, noting that leaders from other RTOs and ISOs should be avoided because “the management of those organizations have struggled to balance the oft conflicting views of state and federal regulators.”
“In a more tangible sense, we recommend that the search committee work to identify candidates capable of driving two (sometimes conflicting) policy agendas at the same time,” he said. “This experience will ensure PJM’s best-in-class management of today’s electric grid and vigorous planning for the needs of tomorrow’s electric grid.”
The attorneys general agree that supporting grid innovation that complements aggressive climate change policies adopted in some PJM states will be a key focus for the new CEO.
“PJM’s president should also have the economic and policy background to understand that state clean energy preferences are not out-of-market distortions to PJM interstate markets, but instead are important market corrections,” the officials said in their joint letters. “These policies address pressing environmental externalities and will modernize our state economies, creating jobs as well as environmental benefits.”
Smith instructed PJM members to submit all recommended candidates to the committee no later than July 19.
VALLEY FORGE, Pa — PJM’s Merchant Transmission and Offshore Wind Task Force will soon bring potential rule changes for offshore wind development to the Planning Committee for consideration, RTO staff said Thursday.
John Reynolds, of PJM’s resource adequacy department, said stakeholders have so far offered three packages that address how transmission developers for single non-controllable AC lead lines could obtain capacity interconnection rights (CIRs) without committed generation.
The task force formed in February after the PC approved a problem statement and issue charge that would pave the way for existing and future offshore wind projects to develop throughout PJM, where researchers believe the potential is “big.” (See “PC Moves Forward on Offshore Interconnection Rights,” Big Prospects for Offshore Wind in PJM.)
Under existing rules, merchant transmission developers are only eligible to obtain transmission injection and withdrawal rights for DC facilities or controllable AC facilities connected to a control area outside the RTO. And because PJM does not offer CIRs to non-controllable AC lines, it is unable to perform stability or short-circuit analyses, as is typically done when a committed generation source exists.
Two of three packages introduce the concept of transferrable CIRs (xCIRs). In one plan, PJM would base the xCIRs on thermal studies only, while the second would allow requests for xCIRs based on all standard studies using a generic generator model. Both plans would make the rights transferrable to a generator project in the queue one year after the execution of the interconnection study agreement (ISA).
A third plan would modify the generator request to allow delayed submission of its data and use generic modeling instead for the feasibility and impact study. The official data would be due no later than 90 days into the study.
“These three are not the only ones we expect to have,” Reynolds said.
The task force has three more meetings scheduled before it returns to the PC for a first read of any draft language in September.
1st Read of Cost Containment Rules Coming in August
Mark Sims, PJM’s manager of infrastructure coordination, told the PC that staff will present Manual M14F draft language for a first read in August, concluding months of educational updates and coordination with the Independent Market Monitor.
The language will detail PJM’s expanded cost containment process, which will include an updated hybrid fee structure. Sims previously told the PC that PJM’s old tiered approach, approved in 2014, doesn’t account for the increased cost of the new comparison framework that involves an independent consultant’s review and legal and financial analyses. (See “New Fee Structure for Cost Containment Needed,” PJM PC/TEAC Briefs: June 13, 2019.)
Staff will seek endorsement of the language at the September PC and Markets and Reliability Committee meetings.
Unchanged Load Model Selection Endorsed
Stakeholders unanimously endorsed PJM’s load model selection for the 2019 reserve requirement study (RSS) after staff said it remained unchanged from the year before.
Patricio Rocha Garrido, of PJM’s resource adequacy department, said the load model of 2003-2012 remains the best choice for studying the 2023/24 delivery year. Analysis shows minor deviation in megawatt distance between 2018 and 2019, but Rocha Garrido described this as “insignificant enough” to not alter the model.
PJM also recommends switching its peak week to a different period in July so that it occurs in the same month as the “world” peak, but not on the same dates — which historical data suggests is unrealistic. The “world” load models include dates from the neighboring MISO, NYISO, TVA and VACAR regions.
Dominion, FirstEnergy Supplementals
FirstEnergy has identified protection schemes using a certain vintage of relays and communication equipment that have a history of maloperation on its Shawville-Shingletown 230-kV and Elko-Shawville 230-kV lines in the APS/Penelec transmission zone.
The 51-year-old Homer City North 345/230/23-kV transformer in western Pennsylvania faces increased probability of failure because of obsolete parts, leaks, deteriorated control cabinet components, high levels of heating gasses and moisture, and type “U” bushings. Likewise, the 34.5-mile Armstrong-Homer City 345-kV line is deteriorating from woodpecker damage, top and bayonet rot, and weatherization.
FirstEnergy has identified a special protection scheme for the 51-year-old Homer City North 345/230/23-kV transformer in Pennsylvania. | FirstEnergy
Dominion Energy wants to add a new delivery point for Mecklenburg Electric Cooperative in Boydton, Va., to support a new data center campus with a total load in excess of 100 MW. The requested in-service date is April 1, 2020.
The company said its Chickahominy 500/230-kV, 840-MVA transformer has been identified for replacement as part of its ongoing transformer health assessment process. Dominion said it’s the last known Westinghouse shell transformer — built in 1987 — on its system. These transformers are considered suspect because of previous transformer failures that reduced basic insulation level ratings and forced remanufacturing.
VALLEY FORGE, Pa — Interim PJM CEO Susan J. Riley opened last week’s Market Implementation Committee meeting with an optimistic message about moving the organization forward after Andy Ott’s departure June 30.
“There’s a lot of work to do, particularly with our markets coming out of the whole FTR/GreenHat issue,” she said, referring to financial transmission rights trader GreenHat Energy’s default in June last year. “I’m here to assist with that and provide perspective to PJM. We’ve got to make these markets safe for participants.” (See Naive PJM Underestimated GreenHat Risks.)
Riley, a member of the Board of Managers, said she expects to serve as CEO for the next four months. She told the MIC that the organization is close to announcing the woman selected to be the RTO’s first chief risk officer, per the recommendation of the independent probe into how the GreenHat default unfolded.
“We are very excited to having her come on board,” she said. “There will be a lot more to come with ensuring the safety of our markets.”
5-Minute Dispatch and Pricing
Stakeholders unanimously endorsed a problem statement that criticizes the real-time security-constrained economic dispatch (RT SCED) and market pricing processes that PJM uses to send dispatch signals to generators and calculate LMPs.
Siva Josyula of Monitoring Analytics last month said a price publishing delay on April 8 — as well as a July 10, 2018, low area control error (ACE) event and corresponding Manual 11 revisions — call into question the transparency of PJM’s RT SCED processes.
The MIC will spend the next several months reviewing the issue and recommending necessary changes.
Laura Walter, senior lead economist for PJM’s advanced analytics and surveillance department, said Manuals 11 and 18 will clarify that storage resources can participate in the RTO’s markets and can dispatch and set price as seller and buyer. The revisions also note that stored megawatt-hours are billed at LMPs as wholesale.
In Manual 15, revisions detail business rules for cost offer development — specifically for hydroelectric resources and batteries and flywheels, PJM Senior Engineer Danielle Croop said. Staff also added definitions for efficiency factor, fuel cost, variable operations and maintenance (VOM) and ancillary service costs.
Efficiency factors measure the ratio of generation produced to the amount of electricity used to charge, Croop said. Fuel cost will use the average charging cost and will be defined in fuel-cost policies. Maintenance and operating cost inclusion and exclusion guidelines will be submitted in resources’ VOM templates, she said.
Modeling Units with Stability Limitations
The MIC is gearing up to discuss whether PJM should require generators to submit outage tickets during forced curtailments stemming from nearby transmission maintenance.
Bob O’Connell, director of regulatory affairs and compliance for Panda Power Funds, presented a first read of the problem statement and issue charge he promised to bring during an Operating Committee meeting in May. His concerns arose out of proposed revisions to Manual 10 that would require generators to use outage tickets for stability-related limitations — possibly encouraging price distortion. (See “Generation Outage Revisions Delayed,” PJM OC Briefs: May 14, 2019.)
O’Connell argues PJM’s decision to remove supply from the market to address stability constraints will result in some units committing at price-based offers, rather than cost. Under the RTO’s rules, only the affected generator would know of the constraint, O’Connell said, therefore gaining a competitive advantage over other units and possibly incorporating greater mark-ups into their offers.
As a solution, O’Connell suggested PJM implement a closed-loop interface around the affected resource that restricts the output to below the stated stability limit — and it must be used in each of the markets. He also encouraged the RTO to publicize stability limits on OASIS prior to contacting the affected generator.
The MIC will be asked to endorse the problem statement at the August meeting and work on possible solutions during the committee’s meetings over the next few months.
Deadline Approaching for Gas Contingency Comments
PJM’s deadline for comments on its new Tariff language for gas pipeline contingencies comes and goes July 17 — but it appears many stakeholders remain unhappy with the latest draft.
On Feb. 19, FERC rejected the member-approved mechanism that would have implemented a process for market sellers seeking cost recovery for certain gas contingencies associated with the RTO’s instruction to temporarily switch to an alternative fuel or fuel source because of pipeline breaks or the loss of compressor stations (ER19-664.) The proposal included nine categories of switching costs, such as park-and-loan service charges and overrun charges. (See FERC Rejects PJM’s Gas Pipeline Contingency Proposal.)
Thomas DeVita, PJM’s senior counsel, said FERC staff dropped some hints about how to tweak the filing for better success the second time around. (See PJM Revisits Gas Pipeline Contingency Plan.) He said staff discouraged the RTO from submitting an itemized list of switching costs, as it did in the first filing, and instead focused on procedures surrounding “explicit authorization” to switch between pipelines and any new limitations on the amount of gas burned after the switch occurs.
Marji Philips, Direct Energy’s director of RTO and federal services, continues to believe the entire filing is fundamentally flawed and puts an unnecessary burden on load.
“If you want to have the right market response, you will look for other market incentives so that you’re not switching the cost of generation to load, because that’s what’s happening here,” she said. “The whole purpose of competitive markets is that the generator bears the risk, not load.”
She further argued that generators should be prepared to compensate during emergencies lasting 24 hours or more.
“If the conditions last longer than 24 hours, it’s no longer an emergency,” she said. “PJM shouldn’t be shifting the burden to load because the generator didn’t incorporate the risk into its CP offers. The generator guaranteed performance under CP, so it’s not load’s responsibility to cover the extra costs of that fuel.”
O’Connell agreed that mandatory operating instructions should only last for a set period of time, but he worried that memorializing such rules could encourage unsavory market behavior.
“One thing to address … the directive expires based on the rule, then 10 minutes later PJM issues the same directive,” he said. “Have we constructed a rule that can be worked around? Market participant perspective is that the market participant should be responsible for deciding what risks they care to take and what costs they care to incur, and if PJM overrides it, PJM should pick up the tab.”
It’s a sentiment Philips said she agrees with completely.
VALLEY FORGE, Pa. — Consensus on fuel-cost policies (FCPs) may elude PJM stakeholders as the Market Implementation Committee prepares for a vote on three divergent plans to restructure penalties and annual reviews.
The Independent Market Monitor and a collection of stakeholders want the RTO to ditch its yearly evaluation of unchanged FCPs and to consider extenuating circumstances when calculating fines for sellers who break those policies by failing “aggregate” market power tests.
“We are trying to go back to the way we did things before,” said Joel Romero Luna of Monitoring Analytics. “PJM or the IMM approved a fuel-cost policy and that remained in place until one of those parties or the participant said it was not good enough anymore.”
PJM argued that eliminating the annual review could allow ineffective policies to slip through the cracks, though it would consider a truncated analysis process as part of a compromise.
“We don’t want them [FCPs] to become stale,” said Glen Boyle, PJM’s manager of system operations analysis and compliance. “We want them reviewed once a year.”
When it comes to implementing an aggregate market power test, however, RTO staff said adopting such a process was “out of scope” of the MIC special session for retooling FCP rules.
PJM’s existing rules went into effect more than two years ago after months of contentious debate. In June 2017, the Monitor announced that it had rejected fewer than 5% of 479 FCPs during its annual review, accounting for roughly 11% of generating units. (See PJM Monitor Rejects Fuel-Cost Policies for 11% of Units.) Sellers without approved FCPs who offer into PJM’s markets currently face a penalty for doing so — though the Monitor proposes no longer allowing generators without an approved FCP to submit nonzero cost-based offers.
The Monitor wants to keep the current penalty factor when a unit fails the local/aggregate three-pivotal-supplier (TPS) test or submits an offer above $1,000/MWh. Romero Luna said the penalty should double when the unit either clears the day-ahead market or runs in real time on an incorrect cost-based offer and sets the marginal LMP, receives make-whole payments or offers above $1,000/MWh. Penalties would decrease to 10% when those two conditions don’t apply.
If a generator “self-identifies” the error and neither of the impact conditions apply, the penalty would drop 50%. If one or both of the situations occur, the penalty is reduced just 25%.
“We heard the current penalty didn’t have an incentive for people to self-identify errors that they made and that the penalties were too high,” Romero Luna said.
Under the Monitor’s plan, a self-identifying generator with a 500-MW output and average real-time LMP of $40/MWh would see its existing $24,000 penalty reduced to as little as $1,200.
Adrien Ford of Old Dominion Electric Cooperative said a joint proposal from stakeholders shares a lot of similarities with the Monitor’s plan — except that self-identified errors reduce penalties to 25% and it creates a “safe harbor” policy for “unusual situations not contemplated by the FCP.”
“We followed the IMM framework while adjusting the value and adding a cap,” she said. More specifically, the joint stakeholder plan applies the current penalty factor if a unit clears the day-ahead market or runs in real time on cost-based offers and is paid a balancing operating reserve or the cost offer is above $1,000/MWh — or a unit fails the TPS test for constraints. If none of these conditions apply, the full penalty is reduced 90%.
The penalty calculation is assessed for each hour of the invalid offer and is capped at the calculated net energy margin for any impacted hour, Ford said.
The MIC will vote on the packages at its August meeting, just in time for the self-imposed Aug. 7 deadline set for the special session.
ERCOT staff and stakeholders are preparing to bring a first set of real-time co-optimization (RTC) policy principles to the Technical Advisory Committee in a key test of their efforts to improve the Texas grid operator’s market design.
The Real-Time Co-Optimization Task Force, which is responsible for developing the RTC principles to align the ERCOT market with the direction given by the Public Utility Commission of Texas, will present five key principles to the TAC for approval during its July 24 meeting:
KP 1.4: System inputs into RTC
KP 1.5: Process for deploying ancillary services (AS)
KP 1.6: AS imbalance settlement with RTC
KP 3: Reliability unit commitment
KP 4: Supplemental AS market (SASM)
Stakeholders will debate KPs 1.5 and 3 and their alternative positions before the committee.
“The votes at the July TAC meeting will be a good indicator of whether the RTC Task Force’s efforts will be efficient in moving key design decisions through the stakeholder process,” said task force Chair Matt Mereness, ERCOT’s compliance director, following the group’s meeting Friday.
The task force is following guidelines set by PUC Chair DeAnn Walker for RTC, a market tool that procures both energy and AS every five minutes to find the most cost-effective solution for both requirements. (See ERCOT Real-time Co-optimization Falls into Place.)
Mereness said it was “helpful” to “have the PUC set direction on a number of key design issues.”
The RTCTF is also trying to engage other RTOs on lessons learned with their design and implementation of RTC. It hopes to bring MISO, PJM and SPP to Texas for a meeting in September.
ERCOT Comes Close to June Demand Record
ERCOT’s system met near-record demand in June. | NextEra Energy Resources
The ERCOT system came about 1.5% shy of setting a new demand record for the month of June when it recorded a peak of 68.1 GW on June 19, compared to the all-time record set last year at 69.1 GW.
June’s peak set a high for the year that has since been broken in July. The system twice surpassed 70 GW on Wednesday, registering a peak demand of 70.5 GW for the hour ending at 5 p.m.
ERCOT is expecting a record peak demand this summer of 74.9 GW, 1.4 GW higher than the all-time record of 73.5 GW set last July. The grid operator has 78.9 GW of available capacity.
FERC on Wednesday ordered energy firm Vitol and one of its senior traders to show cause why they should not be fined for manipulating CAISO’s market to limit losses on the company’s congestion revenue rights (IN14-4).
The trader, Federico Corteggiano, had helped create software for CAISO’s CRR market and had engaged in similar market manipulation before while at Deutsche Bank, FERC’s Office of Enforcement said.
In the more recent instance, he sold power at a loss of about $4,500 to save Vitol more than $1.2 million on its CRRs, FERC’s enforcement staff alleged.
In its ruling, FERC proposed ordering Vitol to return the savings, with interest, and fining it $6 million. The commission proposed fining Corteggiano $800,000. The commission gave Vitol and Corteggiano 30 days to respond.
Vitol and Corteggiano disputed FERC’s findings in testimony and prior filings, saying the trades were intended to take advantage of high prices, not to benefit Vitol’s CRRs. FERC found the arguments unpersuasive.
In their report, FERC enforcement staff said that during five days in the fall of 2013, Vitol “sold one product — electric power — at a financial loss in CAISO’s day-ahead market to benefit its separate financial product — respondents’ congestion revenue rights. Corteggiano, co-head of Vitol’s financial transmission rights trading operation, was the architect of this scheme.”
In 2013, Corteggiano purchased CRRs through CAISO’s auction for the Cragview node, the point where CAISO transfers power from the PacifiCorp-West balancing authority area in far Northern California.
The LMP at Cragview reflects 100% of the congestion on the Cascade intertie, the FERC report noted. “Vitol’s CRRs would earn money from import congestion on the Cascade intertie and lose money from export congestion,” it said.
In mid-October 2013, CAISO partially derated the Cascade intertie — limiting exports while still allowing imports during portions of late October, November and December. In October, Cragview’s LMP hit an unusual high of more than $388/MWh. Export congestion accounted for about $350/MWh of that price, FERC said.
Vitol’s export CRRs would lose money every hour. The firm was able to buy counter-flow CRRs for November and December, mitigating its losses and flattening its position, FERC said. “However, because the monthly CRR auction for October had closed, it was too late to flatten Vitol’s CRR position for the last week of October.”
Corteggiano, who holds a Ph.D. in power system engineering, found a way to get around that problem — one he’d used before, FERC staff alleged.
“Corteggiano knew that he could likely eliminate the problematic export congestion for that week by importing physical power in the day-ahead market at Cragview. Working with other Vitol employees, Corteggiano arranged to buy [5 MW of] physical power in the Pacific Northwest and successfully offered it for import at Cragview. Vitol’s imports over the Cascade intertie achieved their intended purpose, preventing export congestion from occurring during the period of Vitol’s imports. …
“Respondents lost money on the imports, but by making them, [they] were able to eliminate the export congestion and thereby avoid the far larger financial losses they otherwise would have incurred on the CRRs at Cragview.”
‘Phantom Congestion’
While at Deutsche Bank, Corteggiano had figured out how to manipulate congestion costs at another partially derated intertie linking CAISO to northern Nevada, FERC staff said. He had bought CRRs that profited Deutsche Bank when there was export congestion on the Silver Peak intertie but lost money when there was import congestion.
“In January 2010, CAISO partially derated the Silver Peak intertie to 0 MW in the import direction and 13 MW in the export direction. Import congestion appeared on the intertie, and Corteggiano’s CRRs began to lose money. Corteggiano found that he could substantially alter or eliminate what he called ‘phantom congestion’ by trading small quantities of physical power in the opposite direction of the derate,” FERC enforcement staff said.
“Corteggiano testified that ‘phantom congestion’ is ‘congestion that is not triggered by market behavior or by physical flows in the system,’” the report said. “‘Phantom congestion’ is Corteggiano’s own description of a pricing outcome rather than an industry-recognized term.
“Corteggiano admitted to Enforcement in 2010 that he made unprofitable physical trades on behalf of Deutsche Bank to benefit CRR positions that otherwise would have been harmed by the congestion associated with partial derates at Silver Peak. This was the only time in his career that Corteggiano traded physical power, until he did so at Cragview in late October 2013,” FERC said.
Enforcement staff investigated Corteggiano’s conduct at Deutsche Bank, resulting in the settlement of manipulation allegations with Deutsche Bank, a civil penalty of $1.5 million and disgorgement of $172,645, plus interest, in January 2013 (IN12-4).
At the Cragview node, “Respondents’ manipulative trading enabled Vitol to avoid paying CAISO $1,227,143 on Vitol’s CRRs,” the report said. “Moreover, respondents caused $2,515,738 in market harm consisting of (a) $2,429,385 in reduced funding of CAISO’s CRR balancing account, and (b) $86,353 in losses suffered by the holders of CRR counter-flow positions at Cragview.
“Although Corteggiano was not identified by name in the Order to Show Cause in the Deutsche Bank enforcement matter, the public Enforcement staff report attached to the order explained his central role in the trading scheme and referred to him by name,” the report said.
CAISO’s CRR auction has cost ratepayers $860 million because of the difference between revenues and payments to CRR holders, the ISO’s Department of Market Monitoring has found. The ISO has tried to stem the losses through changes to its CRR auctions, which appeared to reduce the disparity between payments and income in the first quarter of 2019. (See Gas Spike Drove High CAISO Power Costs in Q1.)
WASHINGTON — House Energy and Commerce Committee members seeking details about foreign cyber threats were left wanting Friday as grid reliability officials declined to discuss specifics.
Appearing before the committee’s Subcommittee on Energy, NERC CEO Jim Robb, FERC Office of Electric Reliability Director Andy Dodge and Karen Evans — assistant secretary of the Department of Energy’s Office of Cybersecurity, Energy Security and Emergency Response (CESER) — all seemed hesitant to answer members’ questions directly. Instead, they often talked generally about their agencies’ efforts to protect the bulk electric system from cyberattacks. Sometimes they outright declined to answer, citing classified information.
Ranking member Fred Upton (R-Mich.) acknowledged the many security exercises the industry conducts, but he asked if any of them involved simulating cyberattacks against natural gas pipelines. Dodge said DOE held a classified security briefing, followed by a joint tabletop drill with FERC that “involved electricity industry officials, natural gas industry officials [and] all the RTOs and ISOs. And it was a rather extensive event. There were lessons learned … and the items from those we’re actively following up on.”
Neither he nor Evans said when the exercise was held. Upton followed up by asking them if their agencies were planning another exercise. Robb jumped in, speaking at length about NERC’s fifth Grid Security Exercise (GridEx), which will be held Nov. 13-14.
Rep. Scott Peters (D-Calif.) asked Evans if she knew “how many cyberattacks the electric grid sustains on … an average day.”
“It depends on how we talk about a cyberattack,” said Evans, who appeared to be choosing her words carefully. “We are in constant communications with the ISACs [information sharing and analysis centers], and we constantly monitor what is happening in the state of the sector as a whole. So beyond that, I am happy to come back in a more appropriate setting to give you more details if you’d like.”
“Well, you didn’t tell me a number,” Peters responded. “Do you know the number yourself?”
Evans repeated that it depends how you define a cyberattack. Peters followed up by asking if CESER was able to determine “how much of that activity is coming from state actors.” Evans gave a blank stare before smiling and saying, “So, again, I would be happy to talk about that more, but the way we are designing the system…”
“I’m not asking to tell me if it’s coming from state actors,” Peters interrupted. “I’m asking, do you know whether it’s coming from state actors? Is that something you don’t want to answer here?”
“I would like to answer that in a more appropriate setting.”
Similarly, Rep. Jerry McNerney (D-Calif.) asked Evans if she was “aware of any foreign governments embedding cyber weapons into our utility grid today to be used in possible future attacks.”
“I would reference back to the unclassified version of the Worldwide Threat Assessment,” Evans replied. “I think that the [director of national intelligence] has been very specific about what our adversaries’ capabilities are.” She said she has memorized the widely disseminated quotes from the report about Russia’s and China’s activities: They have “the ability to execute cyberattacks in the United States that generate localized, temporary disruptive effects on critical infrastructure…”
Rep. Ann M. Kuster (D-N.H.) asked Dodge whether FERC publicly discloses the names of utilities that have been assessed penalties for noncompliance with critical infrastructure protection (CIP) standards. Last month, Public Citizen filed a complaint with FERC requesting it release the names of two entities that violated 25 CIP standards between them (NP19-10, NP19-11). NERC issued penalties of $1 million against each of the entities.
Dodge said that over the past year, the commission has received “a number of” requests for critical energy/electric infrastructure information, including the identities of entities that have violated CIP standards, under the Freedom of Information Act. “We review them in excruciating detail, and we’ve determined which ones to release [and] which ones not to release,” he said. “We are still working through that, and we have released the names of some entities where we did not believe it would be a threat to security of that entity.”
Throughout the hearing, the panelists emphasized that interagency collaboration and information sharing between government and industry was critical to protecting the grid. Several representatives asked what Congress could do through legislation to help facilitate that.
“The most important thing from our perspective would be for government to be able to more rapidly declassify information, to get it into actionable insights that we can get out to industry,” Robb said. “Industry doesn’t need to know the origin, we don’t need to know the sources, we just need to know the what’s.”
CARMEL, Ind. — MISO’s Independent Market Monitor has a different opinion of the RTO’s summer supply picture three weeks into the season.
Although MISO predicts a 70% chance that it will declare an emergency to call on load-modifying resources (LMRs) this summer, it said its base case shows a 19% reserve margin, with 149 GW of resources on hand to cover a 125-GW projected peak. Its planning reserve margin is 16.8%. (See MISO Foresees Summer Emergency, LMR Use.)
But Monitor David Patton said that while his base case of MISO’s capacity picture also shows a more than 2% excess beyond the planning reserve margin, a more realistic scenario including outages shows a 12.2% margin and an even lower 8.3% margin when accounting for resources that are unavailable to cover emergencies because of their long notification times.
Patton first shared his concerns at the June Board Week in Traverse City, Mich. (See Emergencies Prompt MISO to Re-examine LMR Protocols.) He expanded on them during a Market Subcommittee meeting Thursday, saying, “The way in which we calculate these margins aren’t as accurate as they could be.”
Patton said some hot, high-demand days this summer show margins dipping as low as 2%.
“These margins would raise concerns for some RTOs, but MISO has the unique advantage of having huge import capacity in many directions. … It’s a powerful shock absorber in terms of reliability,” Patton said.
“Our intention is not to scare anybody,” he added, saying he would be concerned if MISO’s footprint were more isolated, like New York’s or New England’s.
MISO staff said that while they don’t dispute the results of the Monitor’s analysis, they haven’t calculated their own additional summer scenarios to compare against it. However, they pointed out that their base case calculations and the Monitor’s were about equivalent.
Patton has called for changes to “an accumulation of rules that aren’t optimal.” He said MISO should carry reserves on the regional dispatch transfer limit on transmission between MISO Midwest and South to temper regional emergency conditions. The suggestion is one of Patton’s State of the Market recommendations this year. (See MISO Monitor Poses 6 New Market Recommendations.)
“It’d be a win-win for the joint parties and MISO,” Patton said. The joint parties are neighboring transmission systems Southern Co., Tennessee Valley Authority, Associated Electric Cooperative Inc., Louisville Gas and Electric, Kentucky Utilities and PowerSouth Energy Cooperative.
Patton wants more transparency around MISO’s decision-making when emergencies are declared and clearer emergency declaration protocols.
“These regional emergencies just began at the end of 2017, beginning of 2018. So, you have [control room] operators exercising a lot of discretion. It’s important to think about what triggers these emergencies,” Patton said.
“There’s nothing written down on what they’re supposed to be doing and how they’re supposed to be weighing these factors. … It should be clear how those factors should be weighed and processed. … We should write down what these triggers are.”
But he also praised MISO operators for taking relatively few out-of-market actions when compared to other RTOs/ISOs. MISO appropriately keeps its out-of-market actions confined to emergency situations, Patton said.
Extended Outages and the Capacity Auction
Patton has continued his criticism of MISO’s capacity auction availability requirements, which he said are too generous.
“We approved and cleared a unit that’s going to be on planned outage for the entire planning year,” Patton said at the June Market Subcommittee meeting, referring to a large generator in Michigan. MISO as a rule does not divulge which generators have taken outages.
“We’ve seen a number of units cleared that won’t be available over the summer peak” over multiple auctions, Patton continued at last week’s meeting.
Had MISO not counted the Michigan generator on extended outage as available in the 2019/20 planning year, Patton said, Michigan’s Zone 7 would have cleared near the $240/MW-day cost of new entry.
“Zone 7, as we sit here right now, is incapable of meeting its local clearing requirement,” argued the Coalition of Midwest Power Producers’ Mark Volpe at Wednesday’s Resource Adequacy Subcommittee meeting. He said MISO should immediately work with stakeholders to remedy the situation by creating some availability requirements.
“This is about reliability,” Volpe argued. “Resource adequacy in MISO is broken. This should not be permitted to persist.”
MISO Director of Resource Adequacy Coordination Laura Rauch said any new availability requirements should be worked through carefully to avoid unintended consequences.
RASC Chair Chris Plante said “it doesn’t seem right” for MISO to fully accredit a resource that’s on a planned outage for the entire year.
“We completely agree in concept; we’re looking at the potential unintended impacts [of a solution] and how likely it is this will occur again in the next planning year,” Rauch said.
MISO staff said they will provide the RASC a timeline for when new availability requirements could be implemented.
WESTBOROUGH, Mass. — State and regional officials last week updated the Environmental Business Council of New England (EBCNE) on the rapid progress of renewable energy development across the region.
The debriefing took place at the Massachusetts Division of Fisheries and Wildlife headquarters, the first state-owned building to achieve net zero energy use. Director Mark Tisa said he was proud of having served as the agency’s lead on its construction in 2012, and that the LEED Platinum certified building sits on 1,000 acres of protected and open space, a small slice of the more than 225,000 acres of such land under its management in the state.
“We’re very lucky to live and work in this region, in this sector, with these leaders that you’ll hear from today,” said Catherine Finneran, director of environmental affairs at Eversource Energy, introducing the speakers. “They’re really leading innovative programs that are ahead of many other states and regions to tackle both energy and environmental challenges that we face as a region.”
“When we think about the resource mix, what’s been proposed in the region, we think of this as the generator interconnection queue … for many years it was dominated by gas-fired generation,” said Eric Johnson, ISO-NE director of external affairs, who serves as president of the Connecticut Power and Energy Society.
Natural gas “has actually dropped to about third place in the queue, and by far the largest resource now is wind, primarily offshore wind,” he said.
“Most of the wind used to be proposed in Maine, but now we’re seeing a lot of that happen in southern New England, in the offshore space, with Massachusetts alone at over 6,000 MW,” Johnson said. “We see that in Rhode Island and Connecticut.”
The region will not need 20,000 MW of new resources on a system that peaks at 28,000 MW, so not every project that developers propose will get built, but every proposal must go through the RTO’s study process, he said.
“Battery storage was not even in my presentation a couple years ago, then it showed up at about 50 MW, then 100 MW, then 200 MW, then 800 MW, and now it’s out of date as soon as we print it,” Johnson said. “So now we have almost 2,400 MW of battery storage in New England, and a lot of that is driven by policy direction set by the states.”
New England has also experienced tremendous growth in solar, he said: “In 2010, we had 40 MW of solar on the system, and if you go in the control room now, that doesn’t even show up. That’s noise.”
Commissioner Judith Judson of the Massachusetts Department of Energy Resources responded to a question about the Edgartown Conservation Commission having the previous day denied a permit for Vineyard Wind’s cables to come ashore on Martha’s Vineyard — and about the Bureau of Ocean Energy Management in June having declined to issue its final environmental impact statement on the 800-MW offshore wind project.
“We’re absolutely committed to offshore wind. We just doubled down on it very recently, and I think developing projects is challenging,” Judson said. “That is a fact. I think siting large projects is challenging because of the amount of neighbors and the amount of entities impacted. Hopefully we can work through those challenges … you sometimes get setbacks. We’re out now with our second solicitation for offshore wind, and I’m hoping for a robust response. It’s unfortunate and no one wants to see these types of delays.”
Rhode Island Office of Energy Resources Commissioner Carol Grant said, “The offshore industry comes from Europe, and honestly, their interactions with different states have them scratching their heads sometimes. They’ll say, ‘Really, we’ve dealt with the feds, now there’s another state and another state and another state.’”
Matthew Mailloux, energy adviser in the New Hampshire Office of Strategic Initiatives, said his state has formed an offshore wind task force, begun the formal lease application process with BOEM, and initiated a regional collaboration on offshore wind with Maine and Massachusetts, aided by EBCNE.
Mailloux said a letter from Gov. Chris Sununu to BOEM in January led to creation of the agency’s Intergovernmental Renewable Energy Task Force.
Dan Burgess, director of Maine Gov. Janet Mills’ Energy Office, touted his state’s direction toward offshore wind.
“The previous administration, in power for eight years, had not focused on offshore wind, but we’re bringing it back,” Burgess said.
He highlighted the revival of the Maine Aqua Ventus project to test a floating turbine off the coast, which he said is “important because the water is too deep off Maine for fixed-bottom turbines.”
Burgess also said that a bill in the Maine legislature (LD 1646) to have the state take over and own the Central Maine Power and Emera Maine utilities “has gotten a lot of attention” and will be the subject of a Public Utilities Commission study.
Anne Margolis, assistant director of planning for the Vermont Department of Public Service, said her state has a strong focus on modernizing rate design and getting people to use electricity at times of lower demand.
“We’re distinct from the [Public Utility Commission]. … We’re the body that advocates on behalf of ratepayers and the state’s energy policies,” she said, adding that one utility, Green Mountain Power, serves 75% of load, and that Vermont represents 4% of New England load.
Margolis complimented ISO-NE’s Johnson on the RTO’s recent Grid Transformation Day and said she appreciates the grid operator “flagging a potential issue” and offering a solution. (See ‘Grid Transformation Day’ Highlights ISO-NE Challenges.)
Massachusetts’ Judson asked, “How do we think about a grid that is no longer big power plants going on the transmission, stepping down onto distribution, but now is small generation, in aggregate large amounts of generation on a system that was never designed for that?”
Electricity constitutes 27% of the energy use in Massachusetts, behind transportation at 44% and thermal (building heating) at 39%.
“When we electrify the heating of buildings, we get a huge leverage effect from the investments we’ve already made. … Combine that with energy efficiency, and you’re getting massive benefits,” Judson said. “We invest a tremendous amount in [energy efficiency]; [we’ll] invest $2.7 billion over the next three years … whereas California invests around $1 billion on a grid three times as large … but we get great returns.”
The DOER projects $9.3 billion in savings from the state’s EE investment over the next three years.
“We still have these times of the year when we’re overly dependent on natural gas, where our system, because of demands for heating and generation, has to switch to oil and other resources,” Judson said. “We continue to need to think about that reliability constraint on our system. If you can do LNG, that can be something in the short term, that may be one solution, but how do you have that storage capability for that type of fuel given that longer term … you’re planning to transition away from it.”
CARMEL, Ind. — MISO’s Independent Market Monitor intends to reduce its monitoring of physical withholding by small behind-the-meter generators in the footprint.
Most of MISO’s BTMGs are about 2 MW, and the Monitor is proposing only monitoring for physical withholding by units of at least 10 MW. It would still not recommend enforcement action for any possible economic withholding from BTMGs.
“Excluding these resources will improve efficiency, allowing for more focus on resources that may have market power,” the Monitor explained.
IMM staffer Michael Chiasson told the Resource Adequacy Subcommittee on Wednesday that he would only scrutinize aggregated nodes of BTMG for physical withholding if one of those groups contained a generator larger than 10 MW. Groups that contain multiple smaller generators that exceed 10 MW combined would still be left alone.
According to the Monitor’s count, MISO contains 826 BTMGs, with 547 of those serving as load-modifying resources. BTMG comprises just 5,089 MW of MISO’s Generation Verification Test Capacity and 4,582 MW of unforced capacity.
Minnesota Public Utilities Commission staff member Hwikwon Ham asked if the Monitor foresees large groups of small BTMGs exercising market power.
“We still think that they’re unlikely to have market power,” Chiasson said. “If we do see something that’s alarming, that doesn’t prevent us from taking action and filing a recommendation with FERC. Our hands really aren’t tied here.”
“Is this in the spirit of [ERCOT’s philosophy that] ‘small fish swim free?’” MISO’s Michael Robinson asked.
Chiasson said he wasn’t familiar with ERCOT’s controversial protections for small generators that control less than 5% of the Texas wholesale energy market. Such generators are dubbed too small to hold market power and are exempt from penalties for market power abuse.
“The small fish can be pivotal in certain circumstances,” Customized Energy Solutions’ David Sapper said.
MISO staff said that if supplies ever became so scarce that small BTMGs become pivotal suppliers and rake in higher prices, they would deserve the high compensation for providing a critical service.
Staff said the new BTMG physical withholding rule would likely be included in a monitoring rule update filed at FERC before fall.
Additionally, the Monitor plans to add default technology-specific avoidable costs for solar generation and battery storage at $64.11/MW-day and $109.59/MW-day, respectively.
Most of MISO’s capacity market participants elect to use the Monitor’s default avoidable costs, saving time and effort rather than calculating and documenting individual refence levels for generation. The Monitor relies on the same values PJM currently uses, although PJM does not maintain values for solar and storage.
MISO Reviews OMS Survey
MISO staff took time to reassess with stakeholders the results of last month’s annual Organization of MISO States resource adequacy survey.
The survey forecasts a generation surplus of about 3 to 6 GW in 2020, about 1 to 4 GW in 2021 and about 1 to 3.4 GW in 2022. The range of possibilities in 2023 and 2024 varies the most, with the forecast indicating anything from a 1.3-GW shortfall to a 7-GW surplus in 2023, and a 2.3-GW shortfall to another 7-GW surplus in 2024. This is the sixth iteration of the survey. Last year’s forecasted a possible 0.1-GW shortfall in 2020. (See Supply Future Brighter, OMS-MISO Survey Shows.)
“Quite a few resources have firmed up their availability over the last year,” MISO’s Stuart Hansen said. “We’re resource-sufficient for the next three years. It’s 2023 and 2024 when we may have a problem area.”
But Hansen said that even in those years MISO by no means has a guaranteed adequacy risk. He said changes in load and new resource additions from the approximately 100-GW interconnection queue could come online and mitigate possible shortfalls.
“Every single year, we’re going to see this change,” he said, adding that 2020 “looked bad” from last year’s perspective but has since become “3 GW long.”
MISO is circulating survey results with state public service commissions in its footprint.
“I’m not too concerned,” Hansen said of forecasted potential deficits. “This survey is a tool to open dialogues with state commissions [and] utilities.”
The Coalition of Midwest Power Producers’ Mark Volpe asked why MISO is initiating outreach on the survey with state commissions when it is market participants that respond.
Hansen said the RTO is simply ensuring states are aware of the survey’s resource adequacy results. He said MISO does not cross-check survey results against states’ integrated resource plans.
Volpe also asked if MISO may recalibrate survey results based on new public announcements regarding retirements and new plant construction.
“We may look at that, but we do have a cutoff period. At some point, those would become part of the 2020 survey. If you’re asking if we would open it up now, probably not,” Hansen said.
But Hansen reassured stakeholders that the survey results include the Illinois Pollution Control Board’s June 20 announcement of the retirement of 2 GW of coal-burning generation in the state. Southern Illinois’ Zone 4 is one of three local resource zones in MISO that could experience capacity shortfalls from 2020 to 2024.
