Page 1055 – RTO Insider

August 23, 2020

Are California Utilities Ready for Fire Season?

Lightning started most of the major wildfires now ravaging parts of California, but the fall season, when utility equipment tends to start fires, is coming fast.

Regulators and reliability coordinators want utilities to be ready, especially with regard to public safety power shutoffs (PSPS) to prevent fires ignited by electrical equipment.

On Thursday, WECC held the third and final webinar of its August workshops on wildfires in the West. It focused on vegetation management, following earlier sessions on weather monitoring and a high-level overview of wildfire preparedness. (See WECC Tackles Wildfires as Reliability Threat.)

California fire season — CPUC President Marybel Batjer | *CPUC*

The week before, the California Public Utilities Commission hosted sessions to hear from the state’s three big investor-owned utilities about plans for the upcoming fire season. Commission President Marybel Batjer singled out Pacific Gas and Electric, the state’s largest utility, for the harshest criticism.

After two years of catastrophic wildfires in 2017 and 2018, PG&E blacked out 2 million people across large swaths of the state to prevent fires in 2019, while its website crashed and communication faltered. Even so, its equipment started another major blaze, the Kincade Fire in Sonoma County, state investigators determined.

Amid the COVID-19 pandemic, families are depending on electricity more than ever while working and learning from home, Batjer said. PG&E and other utilities must treat PSPS as a measure of last resort and keep them as brief and targeted as possible, making sure residents are safe and local officials are well informed, she said.

“This is what we saw PG&E unable to adequately execute on last year,” Batjer said. “PG&E’s haphazardly implemented PSPS events of last fall cannot be repeated.”

“We need to understand from PG&E, ‘Are you ready?’” she said.

Michael Lewis, interim president of PG&E, told her, “We are ready.

“It is our intent not only to meet your expectations but to exceed them this year,” Lewis said.

PG&E has been conducting PSPS drills this summer with the aim to keep the events “smaller, shorter, smarter,” he said. The utility plans to reduce customer impacts by one-third. If current measures had been in place last year, nearly 300,000 fewer customers would have been blacked out, he said.

This year, with CPUC approval, the utility placed diesel generators at numerous substations so areas of its system can “stay energized without grid support,” Lewis said. It installed 800 weather stations and 220 high-definition cameras for greater “situational awareness,” he said. And it established the goal of restoring power within 12 daylight hours — a 50% reduction from last year — after a dangerous weather system has passed, including by using equipment that can scan power lines at night for faults.

PG&E created dedicated teams to work with “critical customers” such as hospitals and COVID-19 testing centers, he said. Low-income customers who rely on medical equipment, known as medical-baseline customers, are being provided with 3,000 batteries and solar panels to charge the units, PG&E told the commission.

IOUs Outline Efforts

Southern California Edison reported similar efforts to WECC and the CPUC.

Tom Brady, senior manager of emergency response at SCE, told WECC earlier this month that the utility had installed 650 miles of insulated wire in areas at high risk of fire.

SCE also placed 1,200 fuses and remote-controlled sectionalizing devices on its system to interrupt power more quickly and prevent ignitions. Sectioning off its grid also allows SCE to limit the extent of PSPS used to keep electrical equipment from starting fires during dry, windy conditions.

“We’re able to minimalize, sectionalize and isolate the smallest footprint possible so that we’re not interrupting a lot of customers,” Brady said.

San Diego Gas & Electric, a state leader in fire prevention, told the CPUC it was using sectionalizing devices, microgrids and grid-hardening techniques, including undergrounding wires, to prevent fires. Public outreach and providing generators to medical-baseline customers and mobile home parks are part of its efforts, CEO Caroline Winn told the commission.

SDG&E has been trying to improve its prevention efforts every year since 2007, when massive wildfires swept San Diego County, she said. The IOU was the first in California to use power shutoffs as a fire-prevention tool, followed by SCE and now PG&E. The weather conditions that once only plagued Southern California have moved north in recent years.

In past years, catastrophic fires sparked by the IOUs’ equipment mainly occurred in October and November. This year will be a major test of the IOUs’ efforts to prevent destructive blazes without widespread, prolonged blackouts.

“We share the commitment of Gov. [Gavin] Newsom, of our legislative leaders and all of our CPUC commissioners to ensure that the public safety power shutoffs are conducted responsibly and only as a last resort to prevent catastrophic wildfires,” Winn said. “We’re also mindful, as you mentioned Commissioner Batjer, of the current COVID-19 pandemic and the impact of power shutoffs to our customers who are spending more and more time at home working and learning.”

August 23, 2020January 17, 2024

Coastal States Seek Balance on Offshore Wind

Officials of East Coast states with ambitious offshore wind goals said Thursday they are trying to balance the urgency of getting turbines in the water with potential economies of networked transmission.

“States have initiated what I would say is a process of execution and planning simultaneously,” said Doreen Harris, acting CEO of the New York State Energy Research and Development Authority (NYSERDA) during a virtual panel discussion at the Business Network for Offshore Wind’s 2020 International Partnering Forum. “None of us are in a position to necessarily wait for the exact planning exercises to be concluded and installed before we move forward with our strong commitments to offshore wind.”

“We’re anxious to see that first turbine in the water … but you always have to think about the ratepayer,” said Joseph Fiordaliso, president of the New Jersey Board of Public Utilities. “Shared transmission can be very helpful and economical in comparison [to transmission for individual developers] for all those states on the coast. We have said to our neighbors more than once we think that there could be a very good collaborative effort as far as transmission is concerned.”

Speaking at the Business Network for Offshore Wind’s virtual International Partnering Forum were, clockwise from top left: Rob Gramlich, Grid Strategies; Ken Seiler, PJM; Joseph Fiordaliso, president of the New Jersey BPU; Stephen Pike, CEO of the Massachusetts Clean Energy Center; and Doreen Harris, acting CEO of NYSERDA. | Business Network for Offshore Wind

New Jersey Goals

New Jersey, which has a goal of 7,500 MW of OSW by 2035, has awarded an 1,100-MW solicitation and will award up to 2,400 MW more early next year.

“Everyone who comes into [my] office has a different idea about transmission: Should the developer do it along with setting up the wind turbines? Should you have … independent transmission?” Fiordaliso said.

The BPU hired consultant Levitan & Associates to help it evaluate its alternatives, he said. The board’s studies indicate that “anything beyond 3,500 MW may … need a shared network of transmission. … Solicitations 1 and 2 can successfully be handled with bundled generation and transmission. Once we get to procurements 3 to 6, we are pursuing really a shared-network approach.”

Although the current solicitation calls for bundled generation and transmission, it also required applicants to include plans for using a shared network and to allowing others to use the applicants’ facilities, he said.

New England Looks for ‘Break Point’

The New England States Committee on Electricity (NESCOE) asked ISO-NE to identify the “break point” between existing or near-term transmission opportunities and long-term needs, said Stephen Pike, CEO of the Massachusetts Clean Energy Center. “They found there is roughly 8 GW of interconnection capacity in Southern New England that can be used before you need significant onshore upgrades; it was broken out to roughly 6 GW on AC and then 2-plus GW on HVDC technology.”

Those thresholds are coming fast, Pike said. “You could see that capacity essentially accounted for in the relatively near term, and … should we want to go to some sort of independent/shared transmission system, we need to start planning now for that. I don’t think we have a whole heck of a lot of time to waste. … I do think that we need to start that process in earnest in the very near term in order to be prepared for some of these … market triggers. I see 8 GW or even 6 GW being a really critical trigger.”

New York Seeks to ‘Accelerate’

NYSERDA issued a solicitation in July for up to 2,500 MW of OSW to meet New York Gov. Andrew Cuomo’s goal of 9 GW by 2035. (See NY Announces 4 GW in Clean Energy RFPs.)

Harris said the state is planning for the future grid and executing its radial transmission procurements simultaneously “to maintain New York’s market momentum and to utilize the existing federal lease areas that are available.”

“Acceleration … is our mantra,” she said, citing the state’s streamlined siting process for transmission and generation. “We are looking to install transmission much more quickly than had been the case historically.” (See Cuomo Proposes Streamlining NY’s Renewable Siting.)

New York currently has three 345-kV transmission projects in the siting process that are intended to eliminate choke points preventing upstate renewables from serving downstate loads. The Long Island Power Authority is looking to increase the island’s export capability to deliver OSW to the rest of the state by expanding its 138-kV backbone, Harris said. (See NY PSC Gets Update on Tx Planning, Investment Efforts.)

The strategy for offshore transmission “is very contingent on the availability and conversion of additional wind energy areas for offshore wind development, which really needs to be resolved in advance for us to conclude our grid study on the wet side of the equation [offshore transmission] to get on with detailed planning and execution,” she said.

A s tudy released in August by Wood Mackenzie for the American Wind Energy Association and the New York Offshore Wind Alliance said more leases in the New York B ight would create 30,000 construction jobs and deliver as much as $800 million in lease revenue for the federal government.

“For us, it’s a no-brainer from an economic development perspective,” she said.

She talked of the need to “balance” the economics, “which is to say that the most optimized wet offshore grid … may not ultimately result in the most optimized, cost-effective onshore grid. So, the balance of issues, particularly in spatially congested areas like New York, [is] critically important.”

Similarly, while running fewer cables would appear to be the most efficient and environmentally friendly approach, that would not be the case if those routes “run afoul of key maritime corridors or commercial fishing grounds or environmentally sensitive areas,” she said. “So, the question of financial efficiency needs to be balanced with the broad impacts as a whole.”

“We do sit in the middle. Although a single-state ISO, we are proximal to New England and PJM in a way that inevitably will bring these issues to bear. I would say it’s not the focus of our current power grid study, which is focused on the integration within New York. But these interties and cost allocation issues that President Fiordaliso mentioned are certainly paramount when we start to broaden our scope.”

Why not More Proactive?

Moderator Rob Gramlich of Grid Strategies asked why PJM had not taken a proactive view on planning, citing transmission built to serve wind generators in California’s Tehachapi Pass, Texas’ Competitive Renewable Energy Zones and MISO’s Multi-Value Projects. PJM has five coastal states that could develop OSW: New Jersey, Delaware, Maryland, Virginia and North Carolina. (See related story, Md. PSC Approves Larger OSW Turbines.)

“We don’t count on those megawatts being there until we have public policy,” responded Ken Seiler, PJM’s vice president of planning. He added, “If all the … five coastal states execute on some of the renewable portfolio standards they have in place right now, there will be [transmission] upgrades in other states that are not coastal.”

Seiler said OSW is just the latest development in PJM’s transformation. The RTO, which has interconnected 10 GW of wind so far, currently has 120 GW of proposed generation and storage in its interconnection queue, including more than 56 GW of solar, 13 GW of solar with storage, almost 13 GW of onshore wind and another 13.5 GW of OSW.

“We have traditionally [had] a West-East flow, with [coal] mine mouth units in the West feeding large load centers in the East,” and generation dominated by coal and nuclear, Seiler said. “Then we moved into the gas era with the Marcellus and Utica shale … which [resulted in the growth of gas-fired generators built] closer to the load centers. And now we’re talking about solar and offshore wind.”

Seiler said PJM planners are having ongoing discussions with their counterparts in Germany to learn about what Europe has done to accommodate its OSW.

One challenge will be determining who pays for the additional transmission, he said. “Cost allocation, obviously, is in the eye of the beholder. What may be fair to you may not be fair to me. … Either the cost causer pays, or the beneficiary pays. There’s two ways to do it, and there’s other ways [we could] come up with.

“We ideally would like to see federal policy around some of this that would help enable states and us to accomplish these goals. That doesn’t seem to be in the cards, at least in the near term. We’re going to have to collaborate, coordinate [and] communicate. This is all new to many of us. But it’s an exciting time, and I think we have the right people at the table to figure this all out.” (FERC has scheduled a technical conference for Oct. 27 on integrating OSW in RTOs and ISOs.)

Pike said meeting the states’ goals will require “multilevel coordination,” beginning with “engagement at the local level,” where the offshore transmission meets the land-based grid.

“You’re going to need that local layer; you’re going to need the state level, as well as states talking across regions; and you’re going to need it at the ISO level, working across ISOs,” he said. “I won’t try to convince folks that I know exactly what the process is moving forward, but I do feel as though we’ve taken a couple of good first steps.”

August 23, 2020

ISO-NE to Eliminate Performance Payments for EE

ISO-NE told stakeholders Friday it will file a rule change with FERC to eliminate capacity performance payments from energy efficiency resources, endorsing a proposal by LS Power.

Henry Yoshimura, the RTO’s director of demand resource strategy, told the New England Power Pool’s Budget and Finance Subcommittee that the change to Market Rule 1 would improve the design of the Forward Capacity Market.

In a memo to committee members, Yoshimura said the change is a recognition that EE resources “permanently reduce energy consumption [and] create a reduction of demand across all conditions and prices.”

ISO-NE performance — Most energy efficiency funding comes from surcharges to retail customers (listed as “other”) and Regional Greenhouse Gas Initiative revenues, with capacity markets providing 7 to 29% of total revenues. | *LS Power, using data from aceee.org and rggi.org*

Capacity performance payments, which are intended to provide resources with incentives to provide energy or reserves in real time, should be limited “to those resources whose performance could be at risk,” Yoshimura said, citing generators, imports, batteries and demand response. In contrast, EE has no real-time performance and thus can’t trip offline, Yoshimura said.

The RTO also will change its Financial Assurance Policy (FAP) to eliminate EE’s requirement to provide collateral for the FCM delivery financial assurance to cover negative capacity performance changes.

In a presentation to the NEPOOL Markets Committee in June, LS Power’s Mark Spencer said EE resources were charged $551,000, its pro rata share of the insurance pool, for a Capacity Scarcity Condition event on Sept. 3, 2018, because the actual event occurred during hours when EE is not measured and scored.

Had the event occurred during DR on-peak hours, at the current Pay-for-Performance (PfP) cap of $5,455/MWh, EE would have received net payments of at least $13.1 million, Spencer told the committee in July.

Spencer said most EE funding comes from surcharges to retail customers and Regional Greenhouse Gas Initiative revenues, with capacity markets providing 7 to 29% of total revenues. He said “long‐run expectations” of PfP to total funding are “likely less than 1%.”

The proposed change to Market Rule 1 will be presented to the MC in September.

RTO to Close Loophole on Prior Defaults

The RTO also presented a revision to the FAP to bar applicants with prior uncured payment defaults from rejoining the market under a new name. Action on the “Know Your Customer” changes was postponed at the NEPOOL Participants Committee meeting June 23 to evaluate stakeholder concerns.

“The ISO will evaluate relevant factors to determine if an entity seeking to participate in the New England markets under a different name, affiliation or organization, should be treated as the same customer or applicant that experienced the previous payment default,” the new language says. “Such factors may include, but are not limited to, the interconnectedness of the business relationships, overlap in relevant personnel, similarity of business activities, overlap of customer base and the business engaged in prior to the attempted re-entry.”

Applicants would not be required to cure a payment default that was discharged through bankruptcy.

The RTO will create a “frequently asked questions” document on the proposal and resume discussions at the Budget and Finance Subcommittee’s next meeting in October.

August 23, 2020

Memphis Moves Closer to Breaking from TVA

Memphis Light, Gas and Water took another step away from the Tennessee Valley Authority last week as staff recommended the utility issue its first ever request for proposals for new energy sources.

MLGW staff made the recommendation to its Board of Commissioners at a Wednesday meeting after conducting a yearlong review of resource alternatives to TVA.

The utility could begin the RFP process in October, with approval from its board and the Memphis City Council. The MLGW board and the city council meet every two weeks. Neither entity has announced an intention to hold a vote on the matter.

MLGW President J.T. Young announced that the utility will hire a consultant to help manage the bidding process. Young was also clear during the meeting that MLGW had not yet decided whether it would depart TVA.

Earlier this year, the city-owned utility said it was eyeing MISO membership or joining another wholesale supplier as a more economic alternative to TVA, its electricity provider for 81 years. (See Memphis Muni Mulls Move to MISO.)

MLGW currently accounts for about 10% of TVA load and pays about $1 billion a year for power. To split with the federally owned corporation, Memphis would likely procure some of its own resources and look to a new wholesaler for the rest. MLGW doesn’t currently generate any of its own electricity.

Memphis Light Gas and Water — Memphis riverfront | *TVA*

“This historic decision sets up MLGW to provide more value to customers in Memphis and be a national leader on clean energy,” Southern Alliance for Clean Energy (SACE) Executive Director and MLGW adviser Stephen Smith said in an emailed statement. “By seeking bids on alternative power supplies, the people of Memphis … will lock in lower-cost and cleaner, more efficient energy, giving Memphis more control of its own future. This also serves as a significant ‘shot across the bow’ to TVA that MLGW is setting the stage to break loose from TVA’s dictatorial long-term contract arrangements.”

An MLGW-commissioned Siemens study found that certain combinations of self-supply and MISO wholesale market offerings could save Memphis about $150 million per year from 2025 to 2039, while cutting carbon emissions by as much as 50% by 2030.

TVA said it “respects and supports” the utility’s decision to explore an RFP from alternative suppliers, though it touted itself as the better option over self-supply and the markets across the Mississippi River.

“We are excited about the opportunity to engage in the RFP process — to put the facts on the table — and prove that TVA in partnership with MLGW is the best option for the people of Memphis and Shelby County,” TVA said in a statement. “When it comes to energy costs, Memphis starts from a position of strength. In partnership with TVA, MLGW today provides the third-lowest energy costs in the nation among its peers. TVA’s commitment is to keep energy costs stable over the next decade.”

MLGW said its electricity rates are competitive when compared to other major U.S. cities.

Citizens have said a parting with TVA would bring desperately needed affordable energy to Memphis, where about a third of its residents live at or below the poverty line.

“In the past, and especially now during the COVID-19 pandemic, I see parents being forced to decide between paying to keep the lights on or buying medicine or shoes for their kids. That’s not how it should be in the future, when Memphis buys or produces its own power and takes control of its own power supply,” Pearl Eva Walker, an organizer with grassroots social justice group Memphis has the Power, said in a press release.

SACE has recommended that MLGW issue two RFPs: one for a large-scale energy-efficiency program on a five-year horizon, creating savings as the municipality navigates leaving TVA, and another for clean resources and supporting infrastructure beyond a five-year horizon.

August 23, 2020

MISO AC Works on Sector Rules as FERC Timeline Ticks

MISO’s Advisory Committee is on a tight schedule to redesign the RTO’s sector setup.

The committee met virtually Wednesday to discuss possible design elements, a month after FERC said MISO’s creation of the Affiliate sector as a repository for new difficult-to-define members was fair only on a temporary basis.

FERC approved the sector late last month but gave MISO until March 2021 to work out a more permanent member-sorting process and representation model that affords full participation to all members. The commission said the RTO should be swift in forming a long-term equitable solution and said it would investigate the arrangement if left unrevised, a warning that had Commissioner Richard Glick crying foul. (See New MISO Sector Gets FERC OK — with a Catch.)

The Affiliate sector currently contains North Dakota coal-lobbying group Lignite Energy Council, coal trade organization America’s Power, and several chambers of commerce and mining organizations. It also contains conservative lobbying group Center of the American Experiment and sustainability and conservation trade association Minnesota Forest Industries.

The AC is now asking whether the new sector should be allowed to vote on recommendations to the MISO Board of Directors. The sector cannot vote for the time being, but it can offer opinions during discussions with the board during the committee’s quarterly meetings.

The Union of Concerned Scientists’ Sam Gomberg said he would be concerned if MISO discussions took a more political turn. He said the RTO has historically been very good about minimizing politics in its guided policy conversations.

MISO sector rules — Lignite Energy Council headquarters in Bismarck, N.D. | *LEC*

Some AC members argued that the Affiliate sector’s miscellaneous status means that members would not reach enough of a consensus to cast votes. Others said all MISO sectors should have a vote.

“Voting is more de minimis and often a rarity. We do a lot of things by consent,” AC Chair Audrey Penner said. “When we do vote, we’re voting on pretty important issues.”

AC votes are nonbinding and advisory in nature to the board and MISO staff.

The committee has already decided the board will have the final say in creating new sectors and MISO will be the final arbiter when a disagreement occurs over whether an organization is a good fit for a certain sector. Sectors must also establish their membership criteria and post them on the public MISO website. (See MISO Members Make 1st Rules on Sectors.)

The AC is now asking if it should consolidate some of its 10 other existing sectors. With 11 sectors, MISO has more than any other RTO or ISO. The committee is asking how many is too many.

Independent Power Producers and Exempt Wholesale Generators sector representative Travis Stewart said the sheer number of people participating can make the AC’s quarterly “hot topic” discussions before the board chaotic. He said a more structured discussion with fewer representatives per sector could yield more streamlined discussions.

Some members said sectors don’t need to be thinned or merged; instead, they need more face time with the board. A few proposed that sector representatives form a liaison committee to the board in order to get more access to and interaction with it.

“MISO does have a very different access to the Board of Directors. And this is my personal view: It’s much more controlled,” said Beth Soholt, representative of the Environmental and Other Stakeholder Groups sector. “Other RTOs have unfettered access to their boards.”

August 23, 2020

SPP Seams Steering Committee Briefs: Aug. 20, 2020

SPP has identified a couple potential joint projects with MISO but none with Associated Electric Cooperative Inc., staff told stakeholders Thursday.

The RTOs’ coordinated system plan (CSP) study has focused on three options to address a need along the high-wind Iowa-Nebraska border, Neil Robertson, SPP interregional relations senior engineer, said during the Seams Steering Committee’s meeting Thursday. Robertson said the RTOs still need to complete work in the “cost estimate realm” and that he expects a “determination” on any jointly funded projects by September.

“I can’t project the [CSP’s] final determination,” he said. The RTOs have conducted three previous joint studies since 2014 but have yet to come up with a project to which both could agree. (See MISO, SPP Staff Recommend 2020 Joint Study.)

SPP and MISO are on track with their plans for a 2020 coordinated study. | *SPP, MISO*

The 2020 joint CSP with AECI failed to find any projects that provided benefits to both organizations, Robertson said. A final report will be published in a few weeks, he said.

AECI Wolf Creek Agreement Filed with FERC

A separate project with AECI, the 345-kV Wolf Creek-Blackberry line in Kansas and Missouri, cleared another hurdle with a completed cost-of-use agreement between the entities and its subsequent filing at FERC, Robertson said. SPP filed the agreement (ER20-2708) and associated Tariff revisions (ER20-2707) shortly after the SSC meeting, asking for a response within 60 days.

SPP’s Board of Directors suspended the project in April while awaiting the completed agreement. Anxious to relieve congestion on the eastern edge of the RTO’s footprint, stakeholders in July agreed to not lift the suspension and issue a request for proposals. Once the agreement is filed at FERC, intervenors will have 20 days to file any protests while staff prepares the RFP. (See “Agreement on Competitive Project’s Path Forward,” SPP Board of Directors/MC Briefs: July 28, 2020.)

The project was approved by SPP’s board last year and was included in the RTO’s 2020 Transmission Expansion Plan passed in January. Part of the 105-mile project, projected to cost $152 million, would be on the AECI transmission system and constructed by the cooperative. The RTO cannot allocate funds to AECI without FERC approval.

SPP Nears $100M in M2M Settlements

SPP has closed in on $100 million in market-to-market (M2M) settlements accrued from MISO, adding $11.43 million during May and June. That pushed SPP settlements in its favor to $93.85 million since the two neighbors began the process in March 2015.

High wind energy and spring storms led to constraints on temporary and permanent flowgates, with more than 1,500 binding hours during the two months. SPP accrued $5.32 million in settlements in May and $6.11 million in June, the latter being the second highest in a month.

SPP is nearing $100 million in market-to-market settlements. | *SPP*

Settlements have been in SPP’s favor for the last nine months and 48 of 64 months total. The M2M process allows the RTOs to dispatch electricity on the most economical routes when congestion leads to constrained flowgates.

MISO’s Independent Market Monitor in June made several recommendations to improve flows across the seam in its annual market report. The recommendations include increased use of automation in the M2M relief requests, SPP’s improved day-ahead modeling of MISO’s M2M constraints, and MISO’s reduction or elimination of its generator shift factor cutoff that limits its relief on M2M constraints. (See IMM Issues 5 Recs in MISO State of the Market Report.)

The RTOs’ staff will likely assess the recommendations, solicit stakeholder input and share the results before acting on the Monitor’s recommendations.

SSC Prepares to Become Seams Advisory Group

Staff assured SSC members, concerned they may lose input responsibilities into revision requests, that the stakeholder group is still very important to the RTO, despite its pending conversion from a committee to an advisory group.

“An advisory group is just a category of groups,” said Erin Cathey, senior market design analyst. “Advisory groups have specialized skills and expertise in the area. They have a significant and important impact in many areas of the governing documents. As we identify impacts from a revision request, we will route them to the seams group following the same process tomorrow as we do today.”

The SSC will become the Seams Advisory Group as part of a reorganization of the Markets and Operations Policy Committee stakeholder groups. The MOPC endorsed the proposed changes in July. (See “Members OK MOPC Reorg, Strategic Roadmap,” SPP MOPC Briefs: July 15-16, 2020.)

The reorganization is designed to reduce meeting costs and make better use of everyone’s time through more virtual meetings. In that respect, the SSC is already ahead of the game.

Clint Savoy, the committee’s staff secretary, said, “This year has shown us we can be effective, though we have longer meetings virtually.”

The committee is modifying its scope for submission to the Corporate Governance Committee in November. Should the board approve the scope statements and new structure, it will become official early next year.

August 21, 2020

NERC Board of Trustees/MRC Briefs: Aug. 20, 2020

NERC’s Member Representatives Committee (MRC) on Thursday unanimously elected Jane Allen to fill one of two open seats on the organization’s Board of Trustees.

Allen has a long experience in the energy industry, having served in various posts in Deloitte Canada’s energy and resources division from 1996 to 2017, as well as on the management committee and board of directors. Upon leaving Deloitte, Allen joined Hydro One, where she worked as senior vice president for strategy and innovation from 2017 to 2019. She has also served on the boards of the Energy Council of Canada and Oakville Hydro.

The election means the board now has two Canadian trustees again, with Allen joining current Trustee Colleen Sidford, who has been the sole representative from Canada since the departures of David Goulding and Fred Gorbet earlier this year. (See “Search for Canadian Trustee,” NERC MRC Briefs: Feb. 5, 2020.)

Nominating Committee Chair Kenneth Defontes told the MRC the committee will now move to finding a replacement for Jan Schori, who will complete her 12th year as trustee this year, making her ineligible for another term. Working with executive search firm Russell Reynolds, the committee will narrow its “long and robust” initial list of candidates to a shortlist by October, with interviews scheduled for Nov. 2-3. As with the Canadian search, all interviews will be conducted virtually.

NERC Bylaw Revisions Move to FERC

NERC’s management submitted revisions to the organization’s bylaws relating to membership structure and composition of the MRC, along with criteria for excluding potential independent NERC trustees. Following their unanimous approval by the MRC and board, the revisions will now be submitted to FERC for approval.

The most significant impact of the revisions is the creation of an additional sector to be represented at the MRC. This new “Associate” sector would accommodate candidates that do not fall into an existing industry sector, which NERC’s bylaws currently define as “a group of members that are [bulk power system] owners, operators, users or other persons and entities with substantially similar interests, including governmental entities.”

The creation of the new category is intended to address a growing tension between the description of NERC’s membership as open to anyone with “an interest in the reliable operations of the BPS” and the requirement that members group themselves into one of the defined sectors. According to NERC management, some sectors have effectively been diluted by the addition of members that don’t necessarily belong; for example, the Small End-Use Electricity Customer sector has “become a catchall for candidates … that do not fit elsewhere.”

Under the revised bylaws, membership language regarding most sectors would be changed to allow a majority of members to veto an entity’s inclusion in their sector. Entities that do not meet a sector definition would still be eligible to become members in the Associate sector, with all the rights and duties of other sectors except the right to nominate and elect MRC representatives. Associate sector members could also serve as representatives and proxies of other sectors on the MRC.

Additional sector-related updates would eliminate the voting representation of regional entities on the MRC in light of their “unique role in working with NERC to fulfill a common mission,” and clarify that the Florida Reliability Coordinating Council will participate in the same sector as RTOs and ISOs, rather than the Small End-Use sector.

The revised bylaws also allow NERC officers who are not also NERC employees to serve as independent directors of the organization, a change chiefly aimed at clarifying the status of the board chair and vice chair. A set of minor updates bring the organization in line with New Jersey corporate law regarding remote attendance at meetings and actions taken without approval by the MRC and board, and remove outdated or inoperative language.

Budget, ROP, Standards Actions

The board voted unanimously to approve the 2021 business plans and budgets of NERC and the REs, to renew NERC’s $4 million unsecured line of credit with PNC Bank and to accept the organization’s second-quarter unaudited financial statements.

Board Chair Roy Thilly praised the budget, which aims to keep spending and assessment flat in light of the COVID-19 pandemic, as a “major action” and said the board was “very pleased” with the work of the Finance and Audit Committee. But he reminded attendees to prepare for the increased budgets projected for 2022 and 2023. (See NERC: Post-COVID Budget Rises Likely.)

“We need to make sure we have the resources to meet our mission, which is an incredibly important mission, as has been reinforced by the pandemic and the dependence on reliable electricity,” Thilly said.

Also receiving unanimous approval were NERC’s proposed revisions to its Rules of Procedure (ROP), ordered by FERC in response to the ERO’s five-year performance assessment. (See NERC Seeks Comments on Proposed ROP Changes.)

The board also agreed to modify WECC’s regional variance for reliability standard PRC-006-4, governing underfrequency load shedding, updating the preamble to indicate requirements R14 and R15 do not apply in the Western Interconnection, clarifying the meaning of the term “planning coordinator” in the interconnection and aligning the variance with NERC’s current drafting conventions.

Finally, the trustees also approved the Northeast Power Coordinating Council’s revisions to its regional standard processes manual. The changes are primarily concerned with removing and clarifying outdated language and establishing closer alignment with NERC’s standard processes manual.

November Meeting Goes Web-only

After previously deferring a decision on the final board and MRC meetings of the year, Thilly confirmed that they will be held virtually rather than in Atlanta as originally planned because of the ongoing COVID-19 pandemic. (See “COVID-19 Prompts Further Meeting Changes,” NERC Board of Trustees/MRC Briefs: May 14, 2020.) The meetings are scheduled for Nov. 4-5, with the customary pre-meeting and informational webinar planned for Oct. 7.

While the February board and MRC meetings are, for the moment, still scheduled to be held in Manhattan Beach, Calif., as normal, Thilly admitted that the board considers it “quite unlikely” the gatherings will be held in person. Several replacement options are under consideration, such as another all-online gathering, or a hybrid structure where trustees, and potentially the MRC, would meet behind closed doors with observers listening remotely.

“We’re learning continually about the [WebEx] platform and its capabilities, so hopefully it will be a continuous improvement as we move through,” Thilly said. “I know that we all miss meeting together in person, and while these meetings, with staff’s hard work, are going well, it is a challenge, and we miss the relationship-building and time to talk that we have when we meet in person. So we hope to get there as soon as possible.”

August 21, 2020

Balloting Opening on Cloud Services Standards

Balloting on the second draft of NERC’s proposed Critical Infrastructure Protection (CIP) standards on cloud computing will be held from Sept. 11 to 21.

The commenting period on CIP-004-7 and CIP-011-3 (Project 2019-02), which also ends on Sept. 21, began Aug. 6.

On Wednesday, the standard drafting team (SDT) held a webinar explaining the revisions and answering questions on the standards, which are intended to offer increased flexibility and lower-cost options for entities to manage their bulk electric system cyber system information (BCSI) by allowing use of third‐party data storage and analysis systems.

The ballot on the first draft of the standards closed Feb. 3, with stakeholders rejecting CIP-004-7 by a 36-210 vote and CIP-011-3 by a 29-219 vote.

NERC Cloud Services Standards — | *Shutterstock*

The team is “in alignment” with the industry feedback, SDT Vice Chair Josh Powers, of SPP, said Wednesday. In response to the comments, Powers said the team:

restored to CIP-004 all BCSI access-control-related requirements that had been proposed for CIP-011 (requirement R6);
clarified the intent of the BCSI vendor risk assessment in CIP-011 as a security and technical control method related to the vendor’s services and not the vendor;
broadened a new requirement for “key management” to focus on “electronic technical mechanisms to protect BCSI” and moved the requirement to CIP-011 R1;
added more specific use cases concerning entities engaging “vendor services to store, utilize or analyze BCSI”;
reverted to the term “method(s)” where it had been called “procedure(s)” or “process(es)”; and
left unchanged the current CIP-011 requirements regarding BES cyber asset reuse and disposal, which the team acknowledged was outside the scope of the standard authorization request.

Questions

In response to a question about whether the standards require data encryption for BCSI in all locations, Powers said “the expectation isn’t that it’s encrypted everywhere but it’s protected everywhere. So whatever information protection program is set up by the responsible entity, it must be protected everywhere,” including email and file sharing sites.

One questioner asked whether the SDT discussed the option of updating CIP-013 to cover requirement R1 in CIP-011 regarding supply chain risk.

SDT Chair John Hansen, of Exelon, said the team had detailed discussions with the leaders of the project revising CIP-013. “Both groups agree there was a gap in CIP-013 when it comes to BCSI in the cloud, and we took it on in CIP-011 revisions,” he said. “Longer term, I think we’re still going to be having more discussions on where that mostly will live. Right now, it will have to remain in CIP-011.” (See CIP Teams Compromise on Cloud Risk Assessment.)

Another questioner challenged CIP-011’s citing of vendors’ physical and electronic security management documentation, such as plans or diagrams as evidence of their protections. “Please reconsider because [it is] very unlikely to get this information,” the questioner said.

“It’s understood that certain details might not be divulged, but there should be a certain amount of transparency for you to entrust somebody with your sensitive information,” responded team member William Vesely, of Consolidated Edison of New York. “I would find it very difficult to trust an entity that doesn’t have any form of transparency. … In the measures, it’s pretty open on the various technologies and information that could be provided … so I think there’s enough leeway to address that.”

The team said it had not created a vendor questionnaire similar to what the North American Transmission Forum developed for CIP-013. “There are a lot of publications coming out that get to the heart of that question,” Hansen said. “A lot of good information is already out there.”

August 21, 2020April 11, 2024

ReliabilityFirst Talks Operational Resilience

Operational resilience was the topic of discussion during ReliabilityFirst’s monthly Technical Talk with RF on Monday.

Bheshaj Krishnappa, program manager of risk and resiliency for ReliabilityFirst, focused his presentation on why resilience should matter to stakeholders, highlighting traditional risk management versus resilience and its limitations.

The Global Risks Interconnections Map titled “Systems Thinking in a Connected World” shows societal impacts like cyberattacks, social instability and national governance failure as having less impact on risks but are becoming more permanent as “disruptors.” | ReliabilityFirst

Krishnappa said operational resilience is an indicator of a company’s preparedness during challenging times, and ReliabilityFirst is working on identifying factors to increase resilience and create awareness among its stakeholders. He said one of the most important efforts is ReliabilityFirst’s tool characterizing the operational resilience of a stakeholder’s bulk power system infrastructure to cyberattacks.

Traditional risk management is centered around how to reduce risk, rather than looking at enhancing the ability to deal with systemic risk, Krishnappa said. It is important to recognize that all risks cannot be identified or anticipated across all areas, and quantifying risks is a “very big challenge,” he said.

“Until we quantify risk, we are not in a position to handle it adequately,” Krishnappa said.

Krishnappa spoke about the proliferation of black swan events, which used to be rare but are now increasing in frequency. He cited extreme weather conditions causing problems, including record-high temperatures in California that reached as high as 130 degrees Fahrenheit, leading to rolling blackouts across the state.

The World Economic Forum Global Risks Report 2020 plotted infectious diseases as a “less likely” risk. The information was plotted before the emergence of COVID-19. | ReliabilityFirst

The effects of the COVID-19 pandemic and lockdowns have also given pause to planning for risk management, Krishnappa said, with few people being able to accurately predict the impacts the pandemic would have on society and business. He said ReliabilityFirst also continues to deal with physical and cyberattacks on infrastructure.

Krishnappa pointed to a passage from the International Risk Governance Center’s 2020 Critical Infrastructure Resilience: Lessons from Insurance policy paper to emphasize his points: “Resilience enhances the risk management toolkit in several aspects and may lead to higher safety and security, in particular in a complex, interconnected risk landscape. We consider resilience-based strategies as an answer to systemic risk in a complex risk landscape.”

The “R4 Framework” of ReliabilityFirst includes “robustness,” “redundancy,” “resourcefulness” and “rapidity.” | ReliabilityFirst

To highlight the complexities of planning for risks, Krishnappa included a graph from the World Economic Forum’s Global Risks Perception survey from 2019 that plotted the most dire perceived risks. He said infectious diseases was placed as one of the least likely risks, while extreme weather and natural disasters were considered more likely.

Krishnappa said the graph would probably change today with infectious diseases moving to the high likelihood category.

“This shows us that the quantification and identification of risks is difficult,” Krishnappa said.

ReliabilityFirst’s focus is on facilitating conversations with stakeholders on resilience indicators, Krishnappa said, including where they stand on risks, what their posture is and what are the areas of improvement. He said it seeks to foster “healthy internal discussions.”

“It is important to continually assess the current resilience posture — where I am, where I need to go — which motivates stakeholders to take relevant measures,” Krishnappa said. “Sometimes we are so focused on creating the best solution that we forget that the problem itself might change.”

August 21, 2020

Md. PSC Approves Larger OSW Turbines

The Maryland Public Service Commission on Thursday approved Skipjack Offshore Energy’s decision to use fewer, larger turbines in its offshore wind project, rejecting objections by Ocean City officials.

The PSC awarded offshore wind renewable energy credits (ORECs) for the 120-MW Skipjack project and the 248-MW US Wind project in May 2017.

Skipjack had initially proposed using Siemens’ 8-MW turbine but said the selection was subject to change because of continuing improvements in turbine design. In June 2019, Skipjack notified the PSC that it would switch to General Electric’s new 12-MW Haliade-X turbine, prompting the commission to solicit comments and hold a public hearing on the change. Skipjack said the Haliade-X would produce more power in medium-wind speeds and increase the project’s capacity factor.

The Maryland Energy Administration, the Office of People’s Counsel and the commission’s technical staff all supported the switch to the larger turbine, saying it is more efficient and could reduce costs for ratepayers.

In its order Thursday, the commission concluded that the change is consistent with the Maryland Offshore Wind Energy Act and the public interest because it will allow Skipjack to use only 10 or 12 turbines instead of 15.

The order selecting Skipjack “includes dozens of conditions whose purpose was to mitigate risk to ratepayers and maximize value to the state of Maryland. Included therein is the requirement that Skipjack utilize ‘best commercially reasonable efforts to minimize the daytime and nighttime viewshed impacts’ of its project, ‘including through reliance on best commercially available technology at the time of deployment,’” the commission wrote.

Maryland PSC offshore wind — GE’s 12-MW Haliade-X offshore wind turbine prototype | GE

It also said the Haliade-X is “well-suited to the wind conditions in the Mid-Atlantic where low- to medium-wind speeds predominate.”

Ocean City contended the larger turbines would have a negative visual impact because they are three times taller than the highest building in the city.

With the new design, the diameter of the turbines’ rotors will increase from 590 feet to 721 feet, and the tip height will increase from 641 feet to 853 feet. But the commission noted the 12-MW turbine layout will take up just 7% of the visible horizon from Ocean City versus 18% in the 8-MW configuration. In addition, the nearest turbine will be 21.5 or 22.7 miles from shore versus 19.5 miles as originally planned.

The commission rejected Ocean City’s request to order Skipjack to move the wind farm to 33 miles offshore.

“First, the Maryland Offshore Wind Energy Act of 2013 requires that offshore wind turbines be placed between 10 and 30 miles off the coast of the state. If the project is located beyond those geographical constraints, it is not eligible for ORECs approved by the commission,” the PSC said. “Second, the Skipjack project must also be located within the specific area of federal waters leased to Skipjack by [the U.S. Bureau of Ocean Energy Management]. BOEM determined the location of the Delaware Wind Energy Area through a multiyear research and review process, which included intergovernmental stakeholder input, including state and local governments along the Delmarva coast. BOEM also considered the location of shipping lanes and other existing uses of the federally regulated outer continental shelf. That multiyear endeavor should not be easily disregarded by the commission.”

The PSC, however, scolded Skipjack for what it said were “deficient” outreach efforts to stakeholders. “Skipjack’s engagement with Ocean City appears meager. For example, Mayor [Richard W.] Meehan testified that Skipjack has not provided routine outreach to Ocean City representatives or stakeholders for the past several years.”

It ordered the developers to “re-engage” with stakeholders and provide the commission reports on its efforts every six months.