Page 1169 – RTO Insider

November 19, 2019

MISO Renewable Study Shows More Tx, Tech Needed

By Amanda Durish Cook

CARMEL, Ind. — MISO’s system can operate on 50% renewable generation if the RTO greenlights dramatically more transmission and ups reserve requirements, and if its members embrace new technologies, new study results show.

MISO laid out the possible realities of a 50% scenario at a special Nov. 14-15 workshop to discuss the third round of results of the RTO’s ongoing Renewable Integration Impact A ssessment.

MISO Renewable Study — Jordan Bakke, MISO | © *RTO Insider*

To reach 50% renewables, MISO could retire 17 GW of its existing thermal fleet and add about 100 GW of renewable capacity. Results show even at a 50% renewable penetration, “the majority of the thermal fleet remains available to maintain adequacy,” Policy Studies Manager Jordan Bakke said.

According to the study, renewables would reach 50% of the generation mix as utility-scale solar proliferates in MISO South while wind generation multiplies in the northwestern portion of the footprint. MISO also foresees distributed solar generation becoming more commonplace and concentrated near major cities.

The RTO also said the complementary characteristics of wind and solar generation — on a daily and seasonal basis, solar is generally available when wind isn’t as plentiful — “decreases the probability of not serving load during periods of high risk.”

MISO’s current generation interconnection queue contains 569 projects with 89 GW of estimated capacity, including 51 GW worth of solar and 22 GW of wind. According to a recent report, MISO expects about 3.5 GW of new wind generation to interconnect this year and more than 6 GW to come online throughout 2020.

MISO reported that it executed 43 generation interconnection agreements in 2019, breaking the previous record of 38 set in 2003. However, the RTO also reported 157 project withdrawals so far this year, just short of the record 168 withdrawals set in 2017.

President of Market Development Strategy Richard Doying said MISO now is nearing 20 GW of wind generation, which can have zero marginal cost.

“That is the right economic price, but it’s terrible for baseload generation,” Doying said at an Organization of MISO States meeting in October.

Pad Reserves?

The latest results also line up with earlier studies that conclude MISO’s daily loss-of-load risk compresses into a sharper risk during a smaller set of hours later in the day under a high-renewables scenario. (See MISO Renewable Study Predicts Later Peak, Narrower LOLE Risk.)

At 40% renewables, MISO may need to increase its reserve requirement to manage quick changes in load, the study found.

MISO research and development adviser Long Zhao said the RTO will need ramping capability to manage discrepancies between early evening reductions in solar generation and increases in wind generation and load. Going forward, sunset would probably be a particularly challenging time of day for MISO to manage, Zhao said.

When renewable generation climbs from a 40 to 50% share of the generation mix, it begins to nudge out nuclear and natural gas resources footprint-wide in economic dispatch. MISO envisions its footprint will contain a wind-dominated northern region, a southern region where solar and natural-gas fired generation begin jockeying for position, and a central region that draws on both types of renewables. It also found a significant increase in imports as renewables climb to 50% — more than 10 GW in some cases during summer days. Today, MISO does not exceed 5 GW in imports, even on summer days.

Veriquest Group’s David Harlan said he had a problem with MISO assuming that solar generation could replace the baseload generation of MISO South. He argued that solar’s production capability is simply not predictable enough for heavily industrial areas of the South.

“In MISO South, we have a heavy industrial load planned to be served by coal and nuclear and later by combined cycle,” Harlan said.

Clean Grid Alliance’s Natalie McIntire asked if the shorter and more pronounced loss-of-load risk is good or bad from MISO’s standpoint.

MISO adviser Brandon Heath said the sharper risk is simply a future reality. “It’s neutral. It’s not a good thing or a bad thing just yet,” he said.

Miles and Miles of Lines

It’s not until renewables take a 40% share of the generation mix that MISO foresees a need for transmission projects to “significantly reduce curtailment.” Without transmission solutions, renewable additions beyond a 40% penetration cannot continue displacing thermal generation because there isn’t enough transmission capacity, the RTO found.

“We see needs at the very beginning, but the needs are very small. We see energy adequacy needs when we get to 40%,” Bakke said.

MISO Policy Studies Engineer Yifan Li said while some areas might exhibit needs for local transmission solutions, there’s no need for anything major beyond the normal annual planning cycles until 40% renewable penetration.

“From the bulk amount of energy flow paths to deliver energy and reduce curtailment, an overall systemwide [extra-high-voltage] rebuild is not needed until the 40% milestone,” he said.

But McIntire pushed back on the idea that a 40% renewables mix is the inflection point for new transmission needs. She argued that MISO will require steady transmission buildout as renewable generation rises.

“I just don’t want us to minimize that message. We’re going to need significant transmission before 40%,” McIntire said.

Li agreed that annual transmission buildouts would continue to be needed, but at the 40% penetration level, MISO’s usual annual plans would fail to keep pace with transmission capacity needs.

“I like to compare it to a fever. … Our system is having a high fever around 40% renewables without significant amount of additional transmission,” he said.

At a 40% penetration, Li said, about 80 new transmission projects located all over the footprint might provide the necessary energy delivery. The bundle of projects includes 2,400 miles of 345-kV and lower-voltage lines, 320 miles of 500-kV lines, 270 miles of 765-kV lines and 410 miles of HVDC lines.

At 50% penetration, an additional 70 projects across the footprint could help, including 590 miles of 345-kV and lower-voltage lines, 820 miles of 500-kV, 2,040 miles of 765-kV and 640 miles of HVDC. Li said the transmission additions would be particularly helpful in reducing wind curtailment in the northern part of the footprint, where wind capacity will be ubiquitous.

“We evaluated more than 11,000 [transmission project] candidates,” Li said. MISO staff have repeatedly said the results will not be used directly in transmission planning. They also clarified the study was not conducted with the goal of carbon reduction, saying it only demonstrates the challenges the system might encounter as solar and wind generation flourish.

“That’s a lot of transmission,” McIntire quipped to laughter. She urged MISO to examine the benefits of co-located storage and other ways to maximize existing transmission capability before it starts studying new transmission plans.

Other stakeholders agreed that MISO was suggesting a need for a staggering amount of transmission. Some said the jump in transmission needs from a 30% to 40% share of renewables seemed too high to be believable.

No Agenda

“We do see these drastic needs at certain intervals. It’s a non-linear trend as we deploy renewables,” Bakke said. “That discontinuity at very high renewable levels requires more transfer capacity.”

Bakke said MISO will begin relying more on regional energy transfers, which in turn will become more unpredictable, leading to a need for increased EHV thermal line capabilities.

“Existing infrastructure becomes inadequate for fully accessing the diverse resources across the MISO footprint,” Bakke said.

Not only will the footprint eventually need new physical lines, but it will require more technology on transmission lines, including synchronous condensers, more transformers and HVDC capabilities, staff said.

“As we see more renewable integration, we see additional types of technology needed to help support the system,” Bakke said. “It’s a portfolio of solutions that best enable renewable deployment in the system.”

Bakke said MISO is making no proposals for new technology or lines as a result of the study. “We’re trying to point out where we see these issues … to see if our processes should change and what we need on the system long-term,” he said.

MISO found that a diversity of technologies and geography improves the ability of renewables to serve load. Bakke said storage facilities, the load-taming abilities of electrification and other demand-side management can enable more renewable penetration. He also noted that thermal generation can begin scheduling outages during times where renewable output is predicted to be abundant.

The RTO also said the number and severity of thermal overloads starts to increase at a 20% renewable penetration and becomes widespread especially in the western portion of the footprint at a 50% penetration. It said it will need more thermal mitigations on higher-voltage lines. Likewise, it will encounter dynamic stability issues beyond a 20% penetration.

To counter small-signal instability, MISO said it may need must-run units equipped with power system stabilizers or specially tuned batteries to support grid reliability beyond a 30% penetration.

But MISO now says frequency response performance remains stable up to 60% renewable penetration. The newest result is even more optimistic than its July announcement that its grid can withstand major reliability risks even when renewables reach 40% of the generation mix. (See MISO: Grid Can be Stable at 40% Renewables.)

“We see needs on the thermal side greater than needs on the voltage side,” Bakke said.

WPPI Energy’s Steve Leovy said MISO may need to more thoroughly examine steady-state issues starting with the generation interconnection queue. He recommended the RTO screen for such issues there.

Where’s the Storage?

McIntire pointed out that much of future solar development is predicted to be solar paired with storage, which could change what system needs MISO identifies.

Examining how storage can help a future fleet mix will be included in the upcoming phase of MISO’s renewable impact study. Stakeholders have repeatedly asked the RTO to study heavy wind and solar generation balanced by storage facilities. Some stakeholders predicted that if storage is optimizing wind and solar generation, MISO won’t forecast nearly as many energy delivery issues.

McIntire urged that the next phase of the study examine other less traditional solutions.

“Largely you’ve been looking to transmission and the existing thermal generation,” she said.

Bakke asked stakeholders to send his team examples of nontraditional solutions for evaluation.

November 19, 2019

PJM MIC Briefs: Nov. 13, 2019

VALLEY FORGE, Pa. — The FERC to PJM Gens: Use or Lose Capacity Rights.)

The changes, endorsed by the Markets and Reliability Committee in April, require existing capacity resources not offered in three consecutive auctions to change to energy-only status. A resource receiving a must-offer exception must also file a plan showing how it will satisfy Capacity Performance requirements or forfeit its capacity interconnection rights. Resources would be granted exceptions for no more than two auctions. (See Load Interests Endorse PJM-IMM M u st-offer Proposal.)

Manual 15 Clarifications on VOM Costs

PJM offered a first read of Manual 15 revisions that clarify that market sellers can only change the format of maintenance adders — such as $/MMBtu, $/MWh or $/start — during the annual review period for energy offer components.

Staff will add section 2.6: Variable Maintenance Costs to reflect this after promising to do so in the proceedings for ER19-210, PJM’s filing to include variable operations and maintenance costs in energy offers. FERC partially accepted the RTO’s Tariff revisions in April but asked for more clarity on what maintenance costs sellers can include in their energy market offers. (See FERC to PJM: Clarify Allowable Costs for Energy Offers.) FERC accepted that compliance filing in August.

PJM will seek endorsement from the MRC in December and from the Members Committee and Board of Managers in January.

Border Rates

PJM presented a first read of revisions to Manual 27: Open Access Transmission Tariff Accounting that will reflect FERC’s recent order on border rate calculations (ER19-2105).

In June, PJM transmission owners submitted a filing that updates the yearly border charge to prevent network integrated transmission service (NITS) customers — network load located outside the RTO’s boundaries but served from within — from subsidizing border and non-zone service rate customers who use transmission service through and out of PJM. (See Settlement Hearing Set for PJM Border Dispute.)

FERC accepted the TOs’ filing subject to refund, with an implementation date of Jan. 1, 2020, but also set a paper hearing and settlement procedures for involved parties to work out their differences over the proposed methodology behind the rates.

Ray Fernandez, of PJM’s market settlements development department, said the manual revisions will move forward but acknowledged that refunds will be issued if changes to the methodology are approved in a settlement.

Fuel-cost Policies

Stakeholders from the MIC special session for fuel-cost policies brought updated proposals to the committee on Thursday, five months after a first round of debates among stakeholders produced no further consensus. (See PJM Stakeholders Still Divided on Fuel-cost Policies.)

PJM — Adrien Ford, ODEC | © *RTO Insider*

PJM moved off the status quo and offered an alternative package of rule changes that included a much desired “impact factor” when assessing penalties on market sellers for breaking their fuel-cost policies. A joint stakeholder plan and another sponsored by the Independent Market Monitor would also offer impact factors — though the specific calculations differ — and reduce penalties when market sellers self-identify violations.

Adrien Ford of Old Dominion Electric Cooperative said the joint plan aims to “encourage a culture of compliance” among market sellers.

“According to PJM, 75% of the penalties were assessed on generators that had no market impacts,” she said. “That’s why we want to introduce the impact factor. We are just trying to say, ‘Look, if there’s an impact, there should be a penalty. If there’s no impact, there should be a penalty, but it should be a traffic ticket approach.’”

PJM’s interpretation of the fuel-cost policy debate | *PJM*

While PJM’s plan would reduce penalties by 50% when market sellers self-identify, the RTO did not agree with stakeholders’ creation of a safe harbor provision that protects against situations “not contemplated by the fuel-cost policy.” Melissa Pilong, of PJM’s operations analysis and compliance department, said the provision would encourage market sellers to provide less detailed fuel-cost policies.

Then there’s the issue of temporary fuel-cost policies and PJM’s ability to revoke existing policies, potentially forcing market sellers to submit a zero cost-based offer. Current practice allows market sellers to provide temporary policies that include just heat rate and selling hub — a rule that PJM’s alternative package would eliminate.

“If a fuel-cost policy were to be revoked and mitigation would be offered at zero, the incentives for the generation owner would be, in many cases, submit a forced outage,” said E-Cubed Policy Associates President Paul Sotkiewicz, representing Elwood Energy. “From a reliability standpoint, I can’t imagine why PJM would want to do that.”

PJM staff bristled at the implication that they would revoke fuel-cost policies randomly and at will, noting that the RTO would act in good faith to discuss issues with a market seller first.

“We’ve never revoked a policy,” said Glen Boyle, a manager in PJM’s operations analysis and compliance department. “But we need to have the ability to do so.”

Ford said existing manual language about revocation “isn’t precise” and leaves too much undefined for market sellers.

“The market sellers are just looking to understand when and why something might be revoked and not be forced into a must-offer obligation or a must-offer of zero,” she said. “I don’t think it’s reasonable to have this unclear, looming threat that can really turn things completely upside down for a company. The more we talk about it, the more uncomfortable I am with the status quo.”

Boyle agreed that further consensus could be reached where the RTO allows temporary fuel-cost policies to be submitted alongside their permanent counterparts in the event that revocation occurred.

November 19, 2019

PJM Operating Committee Briefs: Nov. 12, 2019

VALLEY FORGE, Pa. — PJM staff told the Operating Committee last week that questions still remain about why their load forecast veered so far off course during a two-day spell of hot weather across the region last month.

Speaking at the committee’s Nov. 12 meeting, Rebecca Carroll, PJM’s director of dispatch, said staff’s backcasting analysis found that an early-arriving cold front in the ComEd and FirstEnergy zones on Oct. 2 impacted temperatures during the two-hour demand response event, accounting for a portion of the 4,500 MW of anticipated load that never materialized on the system. (See PJM, Stakeholders Baffled by DR Event.)

That same analysis, however, revealed that temperatures in the Mid-Atlantic and AEP zones were higher than initially forecast — meaning the missing load and unusual price signals have a different, unknown cause.

“According to all of our data, the load in AEP should have come in higher and quicker and more significant than what it did, even though we called the pre-load management in this area,” she said. “There’s several hundred megawatts we can’t account for.”

The trouble began Oct. 1, when PJM’s peak load exceeded its forecast by 5,500 MW, knocking the RTO into a spinning reserves event and triggering shortage pricing for three five-minute intervals. Carroll said PJM also called upon 800 MW of shared reserves from the Northeast Power Coordinating Council to compensate.

The following morning, operators lost a 765-kV line in the AEP zone, and 2,000 MW of generation called upon the day before failed to start. Those losses, in combination with a peak load forecast of 131,000 MW and anticipated congestion over the Hyatt transformer and the Peach Bottom-Conastone 500-kV line, prompted staff to call up 725 MW of long-lead DR resources for a pre-emergency load management event. The decision triggered a performance assessment interval (PAI) that lasted from 2 p.m. until approximately 4 p.m. in the AEP, Dominion, Pepco and BGE zones.

What should have happened next, according to several stakeholders, was a rise in LMPs for those zones, set by DR operating during the PAI. Instead, prices in the AEP zone tanked, and 4,500 MW of load never came onto the system.

PJM had hoped backcasting could solve the mystery of the missing megawatts, but Carroll said last week that more answers will likely come when the official DR data become available next month.

“I don’t buy this missing load argument,” said Dave Mabry, of McNees Wallace & Nurick. “I’m not sure we’ve got a missing load issue as much as we have a forecast issue. It seems like there is something else going on with the backcasting.”

Zonal contribution to load forecast error on Oct. 2, 2019 | *PJM*

Mabry suggested that a large industrial-use customer participating in DR could account for the “missing nodal load” — a possibility that Joseph Mulhern, a senior engineer at PJM, said staff were still considering.

“That’s one of the things that we are trying to look into now … mapping the nodes where we see this behavior to demand response customers,” he said. “It’s the first time we’ve looked into anything like this, so we aren’t sure what we will get or what the outcome will look like.”

He said staff attribute “a significant amount of missing load to DR,” but not all of it. He also said a lack of visibility at the distribution level and the rarity of 90-degree weather in October may also have played a role.

“When there is an unusual day that’s not got a lot of history, that can lead to errors,” he said.

Black Start Packages Anticipated in ‘Early 2020’

PJM’s Janell Fabiano said that stakeholders will present new rules for black start resource fuel requirements in “early 2020.”

Stakeholders began meeting in July 2018 to reconsider whether the existing fuel requirement of 16 hours proved sufficient given PJM’s focus on resilience in recent years. The group is also considering ways to mitigate high-impact, low-frequency events across all black start resources and fuel types.

The D.C. Office of the People’s Counsel, Calpine, PJM and Monitoring Analytics continue to work on four similar plans to define fuel assurance and tweak the hourly reserve requirement. Fabiano said stakeholders will bring the finalized packages to both the OC and the Market Implementation Committee for votes early next year. Changes will not move forward without support from both committees, she said.

Winter Weekly Reserve Target Endorsed

The OC endorsed weekly winter reserve targets for 2019 that remain unchanged from last year. The targets for December, January and February are 22%, 28% and 24%, respectively.

Part of the reserve requirement study, the targets help staff coordinate planned generator maintenance scheduling during the winter and cover against uncertainties associated with load and forced outages.

PJM also sets a 0% goal for its loss-of-load expectation (LOLE) in the winter, preferring instead to expect higher LOLEs throughout the summer.

PJM’s Operating Committee meets Nov. 12 at the Training and Conference Center in Valley Forge, Pa. | © *RTO Insider*

Preliminary Day-ahead Scheduling Reserve Requirement Approved

The committee also endorsed PJM’s new day-ahead scheduling reserve requirement (DASR) of 5.07%.

The DASR is the sum of the requirements for all zones within PJM and any additional reserves scheduled in response to a weather alert or other conservative operations.

PJM will seek endorsement for the change at the Markets and Reliability Committee and implement the new requirement in Manual 13 revisions.

Stakeholders Sunset NERC Ratings Initiative Task Force

Stakeholders approved PJM’s request to sunset the 2011 NERC Ratings Initiative Task Force.

The group held more than 30 webinars over three years to address a NERC alert that asked RTOs to “verify that field conditions are consistent with established ratings.”

The task force created an automated process to notify members of pending NERC outages. Since adopting the new procedures, PJM has received 1,386 outage and derate tickets, completing about 65% of submitted requests. About 9% impacted the system, according to PJM’s data.

OC Meetings Moving to Thursday in 2020

PJM’s standing committee week will look a little different in 2020.

The OC will convene on Thursdays, while PJM’s Planning Committee and Transmission Expansion Advisory Committee will move to Tuesdays. The MIC will remain on Wednesdays.

PJM Manuals Endorsed

Manual 03A: Energy Management system (EMS) Model Updates and Quality Assurance (QA) — Cover-to-cover periodic review. Adds a new section on PJM’s modeling philosophy.

Manual 3: Transmission Operations — Cover-to-cover periodic review. Updates dozens of terms and values in sections 1, 3, 4 and 5 and Attachments A and B.

Manual 14D: Generator Operational Requirements — Minor changes identified through the Distributed Energy Resources Ride Through Task Force that apply to distribution-connected generators connected to radial distribution lines of voltage less than 50 kV. The revisions also direct DERs to appropriate transmission owner engineering and construction standards, a standalone document on PJM’s website. The term “generating facilities” was also added in section 7.1.1: Generator Real-Power Control.

– Christen Smith

November 19, 2019February 12, 2025

NEPOOL Markets Committee Briefs: Nov. 12-13, 2019

In a two-day meeting last week, the New England Power Pool Markets Committee continued work on ISO-NE’s proposed Energy Security Improvements (ESI) proposal, with discussions on LNG supplies, market mitigation and a second demand curve.

The RTO has five months to file a long-term fuel security mechanism under FERC’s second extension since its original order last July (EL18-182). The new deadline is April 15, 2020.

The RTO’s lead analyst for market development, Ben Ewing, started the two-day meeting by presenting on the forecast energy requirement (FER) and clearing energy imbalance reserve (EIR) awards to clear the constraint.

The FER constraint ensures that the RTO can meet forecast load throughout the next operating day. It currently is applied after the clearing of the day-ahead market through the reserve adequacy assessment (RAA) process, an “out-of-market” approach, Ewing said.

Under ESI, the FER will be applied in the clearing of the day-ahead market — satisfied by physical generation, net scheduled interchange and EIR awards.

NEPOOL rules prohibit RTO Insider from quoting stakeholders’ comments during the meeting. However, after the meeting, ISO-NE and other speakers approved the quotes attributed to them to amplify their written presentations.

“Including the FER in the day-ahead will provide a clear market solution to ensuring we’re able to meet the forecast load in real time and will better signal the cost of having a reliable operating plan, and provide compensation and incentives for those resources we’re relying on for meeting that reliability requirement,” Ewing said.

The day-ahead clearing typically results in excess supply to meet the FER and operating reserve requirements, making supplemental commitments in the RAA process rare — with zero in 2019 to date, he said.

The RTO is proposing to begin compensating that excess “online” capacity — the capability, or headroom, of scheduled generators above what they cleared in the day-ahead market.

The FER would create a second demand curve in addition to the existing one for bid-in energy demand of market participants. Similarly, it would result in a second constraint, simultaneously clearing physical energy supply offers and energy options to satisfy the FER.

The day-ahead LMP would remain the incremental cost to satisfy another unit of bid-in energy demand. The FER price is the incremental cost to satisfy another unit of forecast demand.

“An online EIR approach is reasonable and practicable, and we will be glad to consider refining it further as technology permits,” Ewing said.

“I think this is a big step toward resolving some of our issues,” Brett Kruse, vice president of market design at Calpine, told RTO Insider after the meeting.

Interchangeability between the different products has been an issue for Calpine all along the design process, he said.

“I’m not sure that some product bifurcation isn’t necessary, but I’m finally getting an appreciation of why [ISO-NE planners] are doing things without regard to which option they get paid for, and why they currently think that they should all get one price,” Kruse said.

The schedule calls for further discussion by the MC over the next few months and a vote on Tariff language and submitted stakeholder amendments at its March 2020 meeting ahead of a vote in April by the Participants Committee.

Enhancing ESI Impacts Analysis

ISO-NE economist Chris Geissler and Todd Schatzki of Analysis Group presented enhancements to the modeling used in the impact assessment of ESI, with Schatzki taking the lead for a “look under the hood” at the specifics of three key changes to the modeling: evaluation of non-winter months independent of winter months; enhancements to the model’s fuel inputs and logic; and adding price-responsive demand (PRD) to EIR.

The RTO is responding to stakeholder concerns and will evaluate non-winter months independent of winter months but will not aggregate the studies into a single annual case, he said.

“Separate analysis of winter months will allow continued focus on the energy security outcomes that are of greatest concern during the winter months and will enhance the information given to the committee as it deliberates the proposed rule changes,” Schatzki said.

Modeling of fuel supply accounts for storage and delivery limitations, while modeling EIR ensures that there is enough energy available to meet the forecast energy level in each hour, he said.

The planners are analyzing resource-level fuel inventory based on multiple parameters:

- - Initial, beginning of winter, inventory levels;
  - Trigger levels for replenishment: balancing costs of refilling too frequently (holding costs) and costs of refilling too infrequently (lost revenues);
  - The replenishment lag: one day for trucks, four for barges; and
  - Replenishment rate: Different replenishment rate for resources relying on trucks and barges. The rate is projected to be 33% higher with ESI.

“Re-evaluation of fuel parameters will allow the model to better represent potential market and reliability impacts associated with ESI,” Schatzki said.

The New England States Committee of Electricity (NESCOE) submitted a memo expressing its concern that a market power analysis “might not show a problem if it fails to evaluate the conditions that could create vulnerability to exercise of market power (such as a tighter supply/demand balance), or if it fails to model ‘real world’ conditions.”

Schatzki said changes in global LNG prices could affect the LNG supply at the terminal.

“In principle, if LNG prices went way down or way up, that might affect the LNG storage decision and the eventual in-winter supply, given the resulting risk of forward committing to LNG supplies,” Schatzki said. “A lot of that procurement happens in advance of the winter.”

Schatzki said his company’s analysis was “very conservative.”

“We assume every day that the terminal, in this case Repsol, is full every day,” Schatzki said. “And whether that’s a reasonable assumption or not … we made the conservative assumption that there is fuel available.”

On EIR, Schatzki said that properly accounting for day-ahead energy and EIR interactions requires modeling PRD.

“Without price-responsive demand, the model cannot substitute between energy and EIR, but including price-responsive demand allows the model to endogenously solve for energy and EIR quantities,” he said.

Market Power Analysis and Mitigation

Concurrent with discussions regarding conceptual mitigation approaches, ISO-NE will conduct a market power assessment (MPA), according to a memo submitted by Mark Karl, the RTO’s vice president of market development.

The central purpose of an MPA is to determine whether market power is an empirically supported concern. If so, an MPA helps to identify the specific conditions, frequency and extent to which individual participants may be able to profitably exercise market power, the memo said.

ISO-NE Chief Economist Matt White said the memo addresses stakeholder concerns by laying out what the RTO expects External Market Monitor David Patton to address in his market mitigation analysis:

- - How mitigation of co-optimized day-ahead energy and ancillary services are implemented in other regional markets where Potomac Economics is also the EMM, and the EMM’s perspective on the effectiveness of those mitigation measures;
  - Whether and how the mitigation lessons from those regions could be usefully applied to the co-optimized day-ahead energy and ancillary services market proposed by ISO-NE;
  - Any expectations regarding potential competitiveness of the proposed day-ahead energy and ancillary services market in New England, given the information presently available and Potomac Economics’ experience; and
  - Its perspectives on must-offer requirements for resources with capacity supply obligations (CSOs).

“Our understanding is this is a voluntary market, and if there is any change that will be known to stakeholders before moving forward,” White said.

Stakeholder Proposal Updates

Jeff Bentz, NESCOE director of analysis, reiterated the states’ position.

“We continue to believe that the possible modifications to the strike price formula, a must-offer requirement as part of a market power mitigation approach and no [replacement energy reserves] in the non-winter months, benefit consumers and will do so without adversely impacting the changes ISO-NE is trying to achieve,” Bentz said.

“Our main concern continues to be market power and mitigation, and the must-offer requirement is only a component of this, so we look forward to the continued work on mitigation in the following months,” he said.

Christina Belew, of the Massachusetts attorney general’s office, confirmed that the office has withdrawn its alternative prop o sal prepared by London Economics that recommended a simple auction format of sealed bids with a uniform clearing price.

With respect to proposed amendments to ISO-NE’s ESI design, Belew said, “We wanted to let you know that the three amendments we offered in September are still in play, and depending on how ESI develops over the coming months, we may re-urge one or more of them, perhaps offer new ones.

“Like NESCOE, we have requested additional analysis that we haven’t received yet, so the results are going to inform our actions,” Belew said. “We expect to be back with substantive comments after the first of the year.”

NESCOE Intent on EER Revisions

Bentz presented NESCOE’s proposal for Tariff revisions regarding energy efficiency resources (EER) and related capacity obligations during scarcity conditions.

He said that NESCOE is seeking stakeholder feedback and intends to move forward in proposing a Tariff change that would implement Shaping Option A as taken from the Demand Resources Working Group final report issued in July.

Shaping Option A would estimate hourly EER performance as a function of established on-peak EER savings and system load levels.

“Under the current implementation, such resources are guaranteed to always incur a penalty during any event that occurs outside of on-peak or seasonal peak hours, which contradicts the language in the FERC order,” Bentz said.

FERC ruled in May 2014 that energy efficiency capacity performance payments should be calculated only for capacity scarcity conditions occurring during peak hours (ER14-1050).

Providing certainty to EERs is important to New England states, he said.

EERs are not similarly situated to other capacity resources because they do not actively perform in real time — they represent a predetermined level of load reduction that is constant as a percentage of that resource’s load — and therefore are not able to respond to the ISO-NE proposal’s performance incentive.

NESCOE will work with the RTO to create the appropriate Tariff and manual changes needed to implement Shaping Option A and present those changes at next month’s MC meeting ahead of a vote in January 2020. The organization will then seek a Participants Committee vote in February.

IMM Reports Q3 Energy Costs down 27% Y-o-Y

The RTO’s Internal Market Monitor issued a quarterly report showing summer 2019 energy and capacity market costs down significantly, with energy costs at $967 million, down 27% from a year ago, driven by a decrease in natural gas prices and lower loads.

Wholesale market costs totaled $1.74 billion, a 26% decrease from $2.36 billion in summer 2018, IMM David Naughton said.

COO Vamsi Chadalavada reported earlier in the month that prices in the region’s energy markets have been hitting historic lows. (See NEPOOL Participants Committee Briefs: Nov. 1, 2019.)

Naughton highlighted that two new rule changes went into effect on June 1: delayed commercial operation rules; and must-offer requirements for do-not-exceed (DNE) dispatchable capacity market resources such as wind. Early market reaction has been consistent with expectations, he said.

The first change shifted responsibility for covering “undemonstrated” capacity from the RTO to the participant, to address new resources that fail to meet their commercial operation target. Late resources that fail to shed their CSOs in secondary markets face a failure-to-cover charge for the “undemonstrated” capacity.

Over the first three months, 19 resources, predominantly demand response, were charged $500,000 for capacity shortages. Charges declined as resources reacted by offloading CSOs.

In addition, he said three new gas-fired generators with a combined CSO of more than 1,000 MW achieved commercial operation and did not incur failure-to-cover charges: Canal 3 (333 MW), Bridgeport Harbor 5 (484 MW) and the Medway Peaker (195 MW).

Naughton said wind generation offer behavior changed as expected now that DNE dispatchable generators with CSOs must offer all of their expected real-time generation into the day-ahead market. DNE wind generators increased their quantity of energy offered in the day-ahead market and offers reflected the expected level of real-time production, Naughton said.

Cleared volumes increased in the first month but declined to pre-rule change levels as offer prices began to increase, while cleared virtual supply at wind nodes decreased from 25% to 16% of real-time wind production.

State Changes to GIS, Rules

The MC by a show of hands unanimously approved sending changes to the NEPOOL Generation Information System to the GIS Operating Rules Working Group.

The Maine Public Utilities Commission and the Massachusetts Department of Energy Resources requested the changes, which relate to the Maine renewable portfolio standard and the Massachusetts Clean Peak Standard (CPS).

The Maine Legislature in September made several changes to the state’s RPS that require changes to the GIS.

The CPS was signed into law in August, and the addition of the CPS certificates to the GIS would require, at a minimum, the addition of “CPS Resources” and “Clean Peak Standard” to various provisions of the rules, NEPOOL Counsel Lynn M. Fountain said.

The changes to the GIS and the rules related to the CPS would become effective on July 1, 2020.

Sunset of Fuel Security Reliability Review

The MC voted to recommend the PC approve the sunset of the fuel security reliability review provisions following Forward Capacity Auction 14, one year earlier than currently planned.

The RTO’s assistant general counsel, Chris Hamlen, presented the proposed changes to Market Rule 1.

The MC in September approved amending Market Rule 1 to limit the retention of resources needed for fuel security to a two-year maximum.

The RTO wants the change to become effective prior to March 13, 2020, the FCA 15 deadline for retirement delist and permanent delist bids.

— Michael Kuser

November 17, 2019

Online Voting Tops WECC MAC Charter Proposals

By Holden Mann

Members of the Western Electricity Coordinating Council’s Member Advisory Committee heard a number of proposed changes to the MAC charter at Wednesday’s meeting, most prominently a plan to authorize electronic voting.

The idea to allow electronic voting arose in last December’s strategic planning meeting, when members discussed ways to improve efficiency, said Utah Office of Consumer Services Director Michele Beck, who presented the proposals to the committee. As proposed, the measure would permit the MAC chair to call for a vote on specific issues discussed in at least one previous committee meeting, with seven to 10 calendar days’ notice before voting begins and at least three business days for members to submit their votes.

WECC voting — Utah Office of Consumer Services Director Michele Beck | *NASUCA*

In response to questions from some members about the wisdom of conducting committee business online, Beck emphasized that the electronic voting system is not envisioned as a replacement for MAC’s current approach. Online voting would initially be limited to “yes or no” votes, and normal quorum rules would still apply. The requirement that the issue under consideration was discussed at a prior meeting would ensure that MAC members have had an opportunity to suggest amendments or modifications before the vote.

“This is … a way to keep the business of the MAC moving forward, in particular in a case where we have … a very fulsome discussion in one meeting, that folks want to think on it a little further before making their actual vote, and it keeps our work moving forward in between meetings,” Beck said. “[But if] MAC representatives aren’t committed to that process, then … it won’t increase our efficiency and we should delete it.”

Also discussed at the meeting was a proposal to change the way MAC measures nonparticipation. Under the current standard, if a member has not attended six consecutive meetings, the chair may designate the position as vacant. However, this rule was created when MAC met every month; the committee now meets about every six weeks, and some members have expressed concern that this could result in seats being effectively unfilled for prolonged periods.

Several alternative measurements were proposed, with most members supporting vacating a seat after four consecutive missed meetings. This would ensure that the chair has the ability to remove a member after six months without contributing.

“Unless they’re ill, which would be an extenuating circumstance … [if you miss] four meetings, you’re out of here. There’s no excuse for that,” said Grace Anderson of the California Energy Commission. “I would be as clear and strong as possible here and say, definitely not less than four meetings would be a good approach.”

Other proposals brought to the committee included standardizing the formats of documents on WECC’s website, implementing term limits for MAC members and updating the charter to formalize the role of liaisons with other committees. These generated less discussion at the meeting, but Beck left the door open for members to request changes via email. Suggested changes will be considered for incorporation into the final version of the proposals, on which MAC members will vote at the next meeting in December.

November 17, 2019

National Grid Vows to Expand NY Gas Service

By Michael Kuser

National Grid’s U.S. division saw half-year profits rise 16% on new rate agreements and cost-cutting measures, but the company is now facing political pressure from New York Gov. Andrew Cuomo over its decision to deny natural gas service to residents of New York City and Long Island under a moratorium on new hook-ups.

“I’m confident that we’ll be able to address the issues raised by the governor in his recent letter within the expected time scales,” CEO John Pettigrew told analysts last week on a call covering the first half of the U.K.-based company’s accounting year ending Sept. 30.

Cuomo on Nov. 12 gave the company 14 days to connect all customers or he would seek “to revoke National Grid’s certificate to operate its downstate gas franchise.”

New York Public Service Commission Chair John Rhodes on Oct. 11 signed an order directing National Grid subsidiaries Brooklyn Union Gas (KEDNY) and KeySpan Gas East (KEDLI) to connect 1,100 of 3,300 customers that had been denied natural gas service connections (Case 19-G-0678).

“A decade ago, National Grid identified the need for incremental gas supplies to serve low growth in the downstate region,” Pettigrew said.

National Grid relied on a pipeline being developed by Williams Co. called the Northeast Supply Enhancement project, otherwise known as the NESE pipeline, which includes an underwater line across New York Bay to service the city and Long Island.

“In May this year, following further delays to permits for this project, and therefore the potential lack of incremental supply to serve that load, we took the difficult decision to stop processing applications for new or expanded gas services in our service territory,” Pettigrew said.

Badar Khan, recently appointed interim president of the U.S. business, was managing the situation in New York and was unable to join the earnings call, Pettigrew said.

Following the PSC order last month, the company has sought to expand demand response and energy efficiency programs, and to arrange for compressed natural gas to be delivered by barge and truck to service those mandated customer hook-ups, he said.

“So in terms of the downstate New York, as I’ve said earlier, the projections are that we’re going to see demand increasing over the next decade,” Pettigrew said. “So the work that we’re doing is really to understand what are the options that are non-pipeline options and potentially how far can that stretch out. The costs are recoverable through our rate filings in terms of provision of service to customers.”

The CEO highlighted the company’s $300 million Metropolitan Reliability Infrastructure project for the Brooklyn gas system, expected to be complete in December 2020.

“On the electricity side, we’ve invested $110 million in the Gardenville substation rebuild in upstate New York,” Pettigrew said. “This substation is critical to the local region, providing residents and businesses with affordable sources of renewable power and is vital to system reliability.”

National Grid reported it successfully completed a rate filing for Massachusetts Electric with new rates going into effect Oct. 1.

The company said that in the second half of the fiscal year, it will continue work on moving its KEDNY/KEDLI rate filing at the PSC, as well as grid modernization, electric vehicle and advanced meter infrastructure plans across its jurisdictions.

“With the KEDNY and KEDLI rate case, we provided data to support a four-year settlement with a proposed base return on equity of 9.65%,” the company said.

National Grid also announced a goal to become net zero for its own carbon dioxide emissions by 2050.

“We set ourselves a target in 2008 to reduce them by 80% by 2050,” Pettigrew said. “Actually, when we got to the end of the last fiscal year, we’d achieved 68% reduction against 1990, so we thought it was really right to demonstrate a more ambitious target … [and] we also know that we’ve got a role to play in enabling net zero more broadly in the economy.”

Quotes courtesy of SeekingAlpha.

November 17, 2019

PJM Analysis of Transource Alternative Challenged

By Christen Smith

VALLEY FORGE, Pa. — Transource Energy’s alternative configuration for its Independence Energy Connection project doesn’t pass PJM’s cost-benefit test, LS Power said last week.

Sharon Segner, vice president of LS Power, told the Transmission Expansion Advisory Committee on Thursday that her company’s review of the newly proposed path for the eastern segment of the project only carries a benefit-cost ratio of 1, far below PJM’s 1.25 threshold.

PJM Transource — Transource’s proposed alternative plan for the eastern segment of its Independence Energy Connection project | Transource Energy

PJM’s analysis, however, produces a 1.6 cost-benefit ratio. Nick Dumitriu, of the RTO’s market simulation department, said the new configuration — which scraps plans for a nearly 16-mile-long transmission line in favor of tying into existing infrastructure in York County, Pa., and Harford County, Md. — will cost $496.17 million and realize $844.81 million in congestion benefits.

Segner said PJM’s base case used to calculate the ratio doesn’t consider the impact of a nearby project that would alleviate congestion on the Hunterstown-Lincoln 115-kV line. PJM plans to present both projects to the Board of Managers in December for inclusion in the Regional Transmission Expansion Plan, Dumitriu said.

“We just want to get to the right answer, and I think that’s everyone’s objective,” Segner said. “These areas are somewhat interrelated, and that’s where it gets kind of complicated. … We have reason to believe the cost-benefit ratio will look pretty different when the Hunterstown project is in the model.

“It may make sense to go ahead with the settlement version, but it should be based on the correct analysis,” she added.

Transource filed the second configuration for the IEC East project with Maryland and Pennsylvania regulators last month after settling with landowners and state officials long opposed to the original route. (See Transource Files Reconfigured Tx Project.)

PJM selected the original configuration for the $383 million IEC — its largest market efficiency project to date — during the 2013/14 long-term planning window to address congestion in the AP South interface. The RTO has since reviewed its benefits to the grid six times, determining in each round that the project remains the most effective way to reduce load costs.

The RTO’s most recent analysis, completed in September, determined the original configuration would generate a $856 million reduction in congestion costs over the next 15 years, with a benefit-cost ratio of 2.1 — well above PJM’s 1.25 threshold required for inclusion in its RTEP.

Protesters argued, however, that the need for the eastern segment of the project could be met by using towers for existing 230-kV lines. Maryland’s Power Plant Research Program urged the state’s Public Service Commission to suspend the project while PJM studied the market efficiency of this alternative and three others — a request that was granted in January. (See More Info Needed on Tx Line Options, MD PSC Says and Cancel Transour ce Line, Md. Panel Says.)

PJM’s analysis determined that the protesters’ preferred configuration would require upgrades at the Furnace Run substation in York County in order to alleviate potential reliability violations. The plan will cost $125 million more than the original IEC and produce $12 million less in congestion benefits to the region, according to PJM’s most recent market efficiency update.

Still, Transource and the protesters have settled on the alternative configuration, despite the reduced benefits and additional cost. Both plans sit before regulatory agencies in Maryland and Pennsylvania awaiting a final decision.

Meanwhile, PJM must update its RTEP to include the alternative plans for the IEC.

“We are going to give the board the complete picture of what’s going on,” said Ken Seiler, PJM’s vice president of planning. “There’s a lot of moving parts and a lot of variables, and we will make sure the board has the right information.”

Seiler added that “at some point,” the plans must move forward. “The area is congested and will be congested until we get some of these projects built,” he said.

Alex Stern, manager of transmission strategy and policy for Public Service Electric and Gas, agreed.

“At some point, you need to focus on what needs to get done,” he said. “I think PJM is doing that and obviously that’s part of prioritizing, and you need to prioritize what’s in the best interest of planning and developing a cost-effective grid versus what’s in the best interest of needlessly perpetuating a competitive process.”

November 17, 2019

MTEP 19 Advances to MISO Board Committee

By Amanda Durish Cook

MISO’s 2019 Transmission Expansion Plan (MTEP 19) will advance to the Board of Directors without any recommended changes tacked on by the RTO’s Planning Advisory Committee.

The plan cleared the committee’s October email vote with six sectors in favor, none opposed and three abstentions. The PAC’s vote is only considered advisory.

The $3.97 billion, 479-project plan now moves to the board’s System Planning Committee for a comprehensive review Friday. The full board will vote whether to approve it at its Dec. 10 meeting as part of MISO Board Week in Indianapolis.

The PAC proposed no changes to the expansion plan, with a pair of motions to convert the Helena-to-Hampton Corners project into a market efficiency project and to delay MISO’s first storage-as-transmission project for more analysis both failing in the same email vote. (See Changes Proposed for MTEP 19 as PAC Vote Nears.)

MTEP 20 Gains Unique Study

At the same meeting, MISO proposed to conduct a special North Region operational limitation impact study for MTEP 20 in addition to the usual slate of planning studies.

Project Manager Sandy Boegeman said the study, added at stakeholders’ behest, will analyze the Minnesota-Wisconsin transfer limitation, known as MWEX.

“Due to the voltage stability nature of this constraint and its location between high renewable penetration areas and customers in the eastern areas of MISO, it presents a valuable opportunity to better understand the implication of a non-thermal constraint within the MISO footprint,” the RTO said.

“This study got a fair amount of support from stakeholders. And we think we have the bandwidth to do this,” MISO Director of Planning Jeff Webb said. The RTO will discuss the scope and objectives of the study at the PAC early next year, he said.

MISO promised unique, targeted studies to identify possible transmission projects in lieu of a fresh set of planning futures for MTEP 2020. (See “Special MTEP 20 Studies,” Changes Proposed for MTEP 19 as PAC Vote Nears.)

Even with MTEP 19 not yet finalized, MISO is already expediting a substation expansion for MTEP 20. Michigan Electric Transmission Co. is planning to expand its Riverview substation to accommodate new load requested by Consumers Energy near the city of Kalamazoo, Mich. The RTO said the 18-month project deserved fast-track status to avoid overloads. It will add the substation expansion to the Appendix A list of projects in MTEP 20.

November 17, 2019

NYPSC OKs Rebuilding Upstate Tx Lines

By Michael Kuser

The New York Public Service Commission on Thursday granted the New York Power Authority a certificate of environmental compatibility and public need to rebuild about 86 miles of upstate transmission lines (Case 18-T-0207).

The NYPSC held its regular monthly session in Albany on Nov. 14.

The Moses-Adirondack 1 and 2 lines extend from the St. Lawrence Power Project’s Moses-Saunders Power Dam switchyard in Massena to the Adirondack substation in Croghan. Thursday’s order also grants NYPA the right to build several upgrades to both the switchyard and the substation.

“I see this as a smart, careful, timely project that’s valuable for the statewide system needs and the statewide renewable energy needs,” PSC Chair John B. Rhodes said. “It’s well designed, has good minimization of impact with the very good use of existing right of way, attention to land use, attention to habitats and as a result is, on balance, very much in the public interest.”

NYPA proposed to divide the project into two phases, the first consisting of replacing 78 miles of the two lines currently configured as single circuits on separate wooden H-frame structures with two new single-circuit lines on steel monopoles.

The initial operating voltage would be 230 kV, with the second phase involving replacing the remaining length of the transmission lines with two single circuits on steel monopoles and upgrading the Moses-Saunders switchyard and the Adirondack substation to operate at 345 kV.

NYPA proposed to construct the project entirely within an existing right of way, except for a 1-mile reroute at the State University of New York at Canton campus.

CES Budget for 2020

The commission also approved a 2020 operating budget of nearly $13 million for the New York State Energy Research and Development Authority to run the state’s Clean Energy Standard and related programs (Case 15-E-0302).

NYPSC Transmission Lines — Commissioner Diane Burman

The order authorizes NYSERDA to reallocate up to $12,138,093 of uncommitted system benefits charge, energy efficiency portfolio standard and renewable portfolio standard funds and $824,791 of previously authorized — but unspent — 2018 CES compliance period funding to cover administrative costs for next year’s RPS and zero-emission credit programs.

Commissioner Diane Burman dissented on the CES budget, saying, “I appreciate the work that NYSERDA does, but this budget request seems very bulky to me.”

The commission performs good due diligence by “not just accepting from utilities a bulky budget, and we work with them in streamlining that as much as we can and really trying to figure out what is absolutely appropriate and necessary,” Burman said.

Consent Agenda

The PSC approved nearly $5.2 million in sales of street lighting by National Grid to three municipalities in order for the towns to install and profit from more energy-efficient lighting. The sales were for Utica ($4.1 million), Dunkirk ($1 million) and Medina ($70,000).

Burman abstained from several items on the consent agenda, including those related to National Grid’s natural gas subsidiaries in Brooklyn and Long Island, and to Consolidated Edison’s gas business, because “we are not addressing some of the core issues around gas, and therefore, looking at these in isolation is very troubling to me.”

The National Grid items were for tariff filings to modify the companies’ gas tariff schedule to establish non-firm demand response service classes. The Con Ed items regarded revisions to its daily delivery service to institute a voluntary physical storage program, and to interruptible gas service program violations or strike rules.

Rhodes on Oct. 11 signed an order forcing National Grid subsidiaries Brooklyn Union Gas (KEDNY) and KeySpan Gas East (KEDLI) to connect 1,100 of 3,300 customers that had been denied natural gas service connections (Case 19-G-0678). KEDNY has approximately 1.2 million customers, and KEDLI has 590,000 customers.

National Grid found itself at odds with Gov. Andrew Cuomo last week when he issued a letter demanding that its gas subsidiaries connect all customers to whom it had denied service under a moratorium on new hook-ups or he would seek “to revoke National Grid’s certificate to operate its downstate gas franchise.” (See related story, National Grid Vows to Expand NY Gas Service.)

Commissioner Tracey Edwards said she wanted “to make sure that the definition of critical care customers is inclusive, so that it speaks to areas of refuge; it speaks to hospitals and nursing homes. I want to make sure that it includes assisted living facilities and homeless shelters, so I would like some follow-up information to make sure we’re looking at critical care in an overall perspective and not leaving anyone out.”

Burman also concurred with comment on items related to municipal tariff filings to modify the municipalities’ electric tariff schedules to include rules and regulations governing the purchase of renewable energy from new distributed generators and to implement net metering schemes.

The two items “appear to be addressing in a proper way the need for these tariffs. … These cases as well as others have sought to modify the tariffs on a voluntary basis because they’re not subject to the utility tax,” Burman said. “I’m flagging this because I want us to be looking at how the munis are doing it differently. … However, we really do need to watch if there are any negative ramifications to the customers, especially on the cash-out that goes to the developers.”

Burman concurred on a petition by 1115 Solar Development for compensation according to the Alternative 2 capacity value calculation set in the Value of Distributed Energy Resources (VDER) transition order, noting that a PSC staff white paper on the subject from last January did not mean that the commission thought of it “as a done deal.”

November 15, 2019March 12, 2025

GridEx V Throws New Tech Curveball

By Holden Mann

A simulated social media hack was among the surprises lobbed at participants in GridEx V, the latest entry in NERC’s series of exercises testing industry preparedness for cyber and physical attacks.

More than 425 organizations across industry and government participated in the two-day exercise, which began on Wednesday with a distributed play model representing a wide array of threat vectors that Steve McElwee, PJM’s chief information security officer, called a “true doomsday scenario.”

Along with utility companies and regulators, the drill included representatives from farther-flung sectors, such as natural gas, electrical equipment manufacturing, telecommunications and even finance, in an attempt to game out the broader social impacts of an attack on the shared electrical grid.

An unnamed staffer at NERC’s Electricity Information Sharing and Analysis Center (E-ISAC) participates in day one of GridEx V. | NERC

Stacking the Deck

“One of the important design parameters that we use when we develop GridEx is we essentially break the system,” NERC CEO Jim Robb said in a media briefing Thursday. “That’s how the electricity industry learns: We break things, and then we figure out how to fix them and prevent the breakage from happening next time. So, it’s purposefully an overwhelming act of violence.”

This year’s challenges included the takeover of one utility’s Twitter account by malicious hackers that then used it to spread disinformation to the public and other participants, which one player described as the major “curveball” of the scenario. Additional threats included technological incursions such as the use of rogue USB devices and ransomware, which — along with physical attacks such as intruders in headquarters buildings and vehicle fires at regional facilities — put essential infrastructure out of commission. Utilities were tested both on their ability to handle the initial attacks and their capacity to ride out the damage and get their systems back online.

NERC CEO Jim Robb (left) with Southern Co. CEO Tom Fanning at a press briefing | NERC

The distributed play exercise was joined in its second day by a similarly comprehensive but more targeted scenario in Thursday’s executive tabletop session, which presented an attack on the northeastern part of the North American grid. Test designers decided on this scenario, the first region-specific exercise in the history of GridEx, in hopes of gaining deeper insights than were available in previous years. The northeastern setting gave participants the opportunity to explore characteristics of the region such as U.S.-Canada relations, the interdependence of the electric and natural gas sectors, and the impact of a prolonged outage on financial players in New York City.

“There are very few cyber-only or physical-only incidents, and as our world grows more interconnected and our infrastructure grows more interdependent with other systems and functions, we must look at our risks [from] both a physical and cyber perspective,” said Brian Harrell, assistant director of the Cybersecurity and Infrastructure Security Agency at the Department of Homeland Security. “The scenario is real, it’s relevant, and it focuses on industry and government partnerships and how we [can] collectively get better.”

Fighting Back

As Harrell suggested, risk is not the sole focus of GridEx. The scenario also provides a sandbox for the public and private sector to test mitigation tools without danger to the general public. This year’s scenario was no different, with participants aiming to address vulnerabilities identified in previous GridEx iterations.

One focus for industry players in this year’s scenario was to actively engage with the vendor supply chain. Vulnerabilities often center on specific equipment, yet in the public report following GridEx IV, NERC called out utility operators for failing to engage with vendors to the degree they did with other utilities, government, and law enforcement. (See Ukraine Attacks, ‘Fake News’ Color NERC GridEx IV Drill.) The criticism spurred greater efforts in this year’s exercise, though participants acknowledged that considerable work is still needed.

Kevin Wailes (left), Lincoln Electric, and Brian Harrell, DHS, at a press briefing | NERC

“The supply chain issue is extraordinarily complex and hard to think about over time, because the threat vectors change continuously and … a good device today may be exposed tomorrow,” said Southern Co. CEO Tom Fanning, co-chair of the Electricity Subsector Coordinating Council. “So, it isn’t [enough to] have certified equipment in our supply chain. … We must have a process of cyber hygiene and collaboration over time.”

On the public side, GridEx V provided a chance to test out the responsibilities granted to the Department of Energy since the last exercise under the FAST Act, amended in 2018 to designate the department as the lead agency on cybersecurity for the energy sector. The change gave broad new authority to DOE to coordinate with state and local governments, in addition to utilities, and GridEx provided an opportunity to test the practical limits of these powers prior to a real emergency.

“What we don’t want … is to be in an actual situation where we’re figuring out the right policies and how we share that information, and what type of information [to share], so that we can have the situational awareness to advise the president,” said Karen Evans, assistant secretary in DOE’s Office of Cybersecurity, Energy Security and Emergency Response.

Ongoing Development

The GridEx exercises have expanded considerably since the first iteration in 2011, which involved just 75 industry and government organizations across the U.S. and Canada. Unlike that scenario, which was inspired by the Stuxnet attack in Iran and focused exclusively on cybersecurity, GridEx now aims to include the widest possible range of participants so that every aspect of the system can be tested.

ERCOT staff participate in GridEx V. | ERCOT

This has led to criticism that the scenarios presented are unrealistic, with participants in previous years comparing the prepared situations to a “disaster movie” rather than helpful practice for recovery. NERC acknowledged these issues but said they overlook the true goal of the exercise.

“The grid is designed with a tremendous amount of redundancy, it operates in real time, and the loss of even a major power station in many cases is not a catastrophic consequence because the industry is prepared for that and designs around it,” Robb said.

“That makes a scenario [such as the one] we’ve laid out implausible but still worth testing,” he added, citing the potential to uncover unsuspected vulnerabilities and suggest new avenues of cooperation.

NERC will release its report on GridEx V by March 2020.

RTOs Take Part

RTO officials also gave their take on the exercise Thursday.

Keri Glitch, MISO’s vice president and chief information security officer, said the scenarios included “network breaches caused by an internal source, a potential intruder in the headquarters building, as well as a vehicle fire near a regional facility.”

“Our employees and industry partners collaborated well and learned a lot from the drill,” Glitch said.

About 120 CAISO employees took part in the exercise, along with representatives from federal, state and local agencies and 39 RC West participants, IT Enterprise Support and Campus Operations Director Matt Turner said.

“We assessed how employees reacted and communicated the scenario injects, which included a plan to return to normal operations. During the simulation, we injected additional issues, such as making key personnel unavailable, to evaluate the depth we have on the team and their ability to adapt to the situation,” Turner said. “Our exercise is designed to push the limits, as far as we could, to identify areas for improvement.”

New York state was “hit” hard during GridEx V, which included a “focused regional attack in the Northeast,” according to NERC CEO Jim Robb. Above, New York Power Authority staff participate in the exercise. | NYPA

SPP said more than 200 staffers took part, after more than a year of preparation by the RTO’s leadership team. “SPP’s incident coordination team led IT, operations and other staff in response to simulated threats to system reliability, communications channels and cyber assets, all in the interest of strengthening defenses, enhancing resilience and refining emergency response procedures,” spokesman Derek Wingfield said. “In the weeks leading up to the go-live of our Western reliability coordination service, GridEx also gave us the opportunity to test our preparedness alongside some of our new customers in the Western Interconnection.”

NYISO, ISO-NE and ERCOT also confirmed their participation. “Physical and cybersecurity measures are a constant practice of vigilance and focus of attention,” NYISO CEO Rich Dewey said.

“Past GridEx exercises have proven to be valuable training opportunities for many departments within ISO New England, and we look forward to practicing and improving our response capabilities,” RTO spokesman Matthew Kakley said.

While PJM regularly conducts simulator drills with its transmission owners and other critical players, GridEx allows the RTO to test its operations under extreme conditions, McElwee said. “It’s far beyond any situation we’ve experienced.”

Amanda Durish Cook, Tom Kleckner, Michael Kuser, Hudson Sangree and Christen Smith contributed to this article.