Page 1036 – RTO Insider

October 4, 2020

CAISO Governors Say Hello, Goodbye

The CAISO Board of Governors on Thursday bid farewell to its retired CEO, greeted a new leader and passed a half dozen measures, including a plan to implement FERC Order 831 that one governor worried could lead to market manipulation.

The five-member board also named its new chair and vice chair.

Former CAISO CEO Steve Berberich | © *RTO Insider*

The meeting occurred as CAISO called for conservation to avoid shortfalls unusually late in the year. Triple-digit temperatures hit Los Angeles and inland areas of California last week, straining supply.

The late-season heat wave was a reminder of the grid emergencies in August and September, when resources ran short during record temperatures and forced CAISO to order rolling blackouts Aug. 14-15. (See CAISO: Blackouts May Continue, Calls Emergency Meetings.)

The summer shortages came up in several of Thursday’s policy discussions and when former CEO Steve Berberich delivered his last report to the board about events that had happened on his watch.

Berberich officially retired from CAISO on Sept. 29 but agreed to stick around to help with the transition. He told the board Thursday he wanted to “make sure [new CEO Elliot Mainzer] doesn’t drown in the firehose that is headed his way.”

The ISO, the California Energy Commission and the California Public Utilities Commission are preparing a report that examines the root causes of the energy shortages, Berberich told the governors. The report will delve into factors such as exports from the state during the shortfalls and failures of some load-serving entities to schedule supply in the day-ahead market.

“We will look into those contributing factors and make sure we are not living on the margin like we were this summer,” Berberich said. “Mr. Mainzer, I know, is going to make resource adequacy a top priority.”

The board honored Berberich with a resolution that praised his accomplishments during his nine years as CEO, including the creation of the now flourishing Western Energy Imbalance Market and the establishment of RC West, the reliability coordinator for most of the Western Interconnection.

The governors told Mainzer they were pleased he had accepted their job offer after seven years as head of the Bonneville Power Administration.

“Elliot, welcome,” Governor Ashutosh Bhagwat said. “We are very excited to work with you. These are exciting times — challenging times, but exciting times. And I know you are going to do an amazing job leading this organization.”

Mainzer thanked the governors for their expressions of support and said he was looking forward to getting to work. (See CAISO Retiring, Incoming CEOs Field Questions.)

New Chair, ESDER Phase 4

Later in the meeting, Bhagwat’s four colleagues chose him as their new vice chair and picked Angelina Galiteva as CAISO’s first female board chair in its 20-year existence. The positions rotate every two years.

The board approved CAISO’s fourth and last phase of its five-year effort to make it easier for energy storage and distributed energy resources (ESDER) to participate in its market. (See CAISO Finalizes ESDER Phase 4 Proposal.)

The ESDER initiative includes rooftop solar, energy storage, plug-in electric vehicles and demand response. It addresses a state-of-charge biddable parameter for storage resources; streamlines market participation agreements for non-generator resources; applies market power mitigation to storage resources; and sets a maximum daily run time parameter for DR.

The board also approved proposals on flexible ramping products, maximum import capability, reliability-must-run contracts, and changes to ISO rates and fees for next year.

Order 831 Initiative

The longest and most complex of the policy discussions, however, took place over an initiative meant to align the ISO’s practices with the requirements of FERC Order 831.

FERC issued Order 831 in 2016, two years after the polar vortex of 2014 pushed natural gas prices in the Northeast and Midwest to levels where marginal generation costs exceeded the $1,000 offer caps then in place. It required ISOs and RTOs to raise the hard caps on supply bids from $1,000 to $2,000, with offers over $1,000 requiring suppliers to justify their costs.

FERC approved CAISO’s Tariff changes to comply with the order on Sept. 21. (See FERC OKs CAISO Cost Recovery Plan for Gas.)

The board on Thursday approved a sta k eholder in itiative intended to help facilitate the order in California with import bidding rules and market parameters meant to “align the implementation of the order with some of the different characteristics of the Western grid,” said Greg Cook, the ISO’s director of market and infrastructure policy.

CAISO must implement the changes by March to comply with FERC’s ruling, he said.

The main differences between Eastern and Western markets, Cook said, is that it is rare to see natural gas prices as high as in the East because gas demand peaks at different times in varying parts of the West. Some areas are extremely hot in summer; others are bitterly cold in winter.

And CAISO, unlike other ISOs and RTOs, is heavily dependent on imported electricity, he said.

In response, CAISO maintains a power balance constraint to ensure that supply equals demand. If there is insufficient supply, the ISO relaxes the constraint and sets market prices at a bid cap of $1,000/MWh.

The initiative approved Thursday sets “appropriate levels of shortage pricing when energy costs exceed $1,000/MWh.” When that happens, and there is insufficient supply to meet demand, the “market will base prices on the price of the highest-priced cleared energy bid if the shortfall is no more than a small threshold value,” CAISO Vice President of Market Policy and Performance Mark Rothleder said in his written report to the board. “Market prices will be based on $2,000/MWh if the shortfall is greater than the threshold value.”

A second enhancement establishes rules for allowing import and virtual bids greater than $1,000/MWh, which Order 831 does not do. The proposal would allow CAISO to accept non-resource adequacy import and virtual bids above $1,000/MWh “only when the ISO has cost-verified a bid or the ISO has calculated a maximum import price that exceeds $1,000/MWh,” Rothleder wrote.

“For resource adequacy import bids, management proposes to reduce the price of bids priced above $1,000/MWh to the maximum import bid price index or the highest resource-specific cost-verified bid,” he said.

The ISO would calculate the maximum import price based on prevailing bilateral prices at the Palo Verde and Mid-Columbia trading hubs, whichever is higher.

“We picked those because those are the largest, most liquid trading hubs in the Southwest and Northwest, respectively,” Cook said.

CAISO’s Market Surveillance Committee previously supported the changes as an intermediate step but called for a stakeholder initiative on scarcity pricing to address situations similar to the August and September shortages. (See CAISO MSC Urges Scarcity Pricing for Emergencies.)

Cook said the ISO agrees with that assessment and intends to introduce a scarcity pricing initiative.

Governor Severin Borenstein, a professor at the University of California, Berkeley, took issue with the idea of using the higher-priced trading hub to set prices. Palo Verde can have higher prices and trades at a lower volume than Mid-Columbia, he noted.

“It seems that this is … not a very precise price index if we’re taking the maximum of two very different locations,” he said. He worried that CAISO is setting up a system by which traders could game the market with high bids at Palo Verde, which is less liquid than the Mid-Columbia hub.

CAISO said prices at Palo Verde climbed to $1,500/MWh during the August emergency, and Southern California Edison said it had seen prices of $1,750/MWh.

Eric Hildebrandt, executive director of market monitoring at CAISO, told Borenstein that FERC must approve such high prices after the fact.

“The best we can do is encourage FERC to perform that kind of review,” Hildebrandt said.

CAISO Governor Severin Borenstein | *University of California, Berkeley*

Cook said it would “be very rare for these bilateral trading prices to exceed $1,000 MWh,” except in situations such as the August heat wave.

In the initiative, CAISO “wanted to ensure we wouldn’t discourage import bids” during times of tight supply, Cook said. If conditions support prices over $1,000/MWh, then the ISO wants the energy to be able flow into its market, he said.

Rothleder said it would be “too risky at this point” to limit imported supply based on prices, given the experiences of August and September. CAISO intends to address the liquidity issue in the future, including seeking guidance from FERC, he said. In the meantime, it will closely watch prices to make sure they “keep with reality,” he said.

The board, including a somewhat reluctant Borenstein, approved the Order 831 initiative unanimously.

“I think we have to do this,” Borenstein said of the measure, but he said he remained concerned about creating an “incentive to manipulate the prices at the trading hubs” and urged the ISO to find a solution.

October 4, 2020

Calif. IOUs Escape Blame for Fires so Far

More than 8,000 wildfires have burned nearly 4 million acres in California this year, but there’s little indication that utility equipment played a role in starting major blazes.

That differs markedly from the last three years, when equipment belonging to Southern California Edison and Pacific Gas and Electric was blamed for starting catastrophic fires including the Camp Fire, the state’s deadliest and most destructive blaze, in November 2018. (PG&E says its large-scale public safety power shutoffs this year have helped avoid catastrophes.)

So far, the only 2020 summer wildfire in which power lines might be implicated is the Bobcat Fire burning in the San Gabriel Mountains northeast of Los Angeles.

SCE Bobcat Fire — The Bobcat Fire burns in the mountains above Monrovia, Calif., near Los Angeles, on Sept. 10.

A Sept. 15 report by SCE to the California Public Utilities Commission said the utility experienced a line fault at approximately the same time and in the same area the Bobcat Fire started. However, the utility said a fire camera had recorded smoke from the blaze shortly before its relay tripped.

“The Bobcat Fire was reported in the vicinity of Cogswell Reservoir/Dam in the Angeles National Forest on Sunday, Sept. 6, 2020, at 12:21 p.m.” SCE told the CPUC. “The Jarvis 12-kV circuit out of Dalton Substation experienced a relay operation at 12:16 p.m. on Sept. 6, 2020. The Mount Wilson East camera captured the initial stages of the fire, with the first observed smoke as early as approximately 12:10 p.m., prior to the relay operation.”

The investigation of the Bobcat Fire is being conducted by the U.S. Forest Service, which on Sept. 15 “requested that SCE remove a specific section of SCE overhead conductor in the vicinity of Cogswell Dam,” the utility reported.

“While USFS has not alleged that SCE facilities were involved in the ignition of the Bobcat Fire, SCE submits this report in an abundance of caution given USFS’ interest in retaining SCE facilities in connection with its investigation,” it told the CPUC.

Lightning storms on Aug. 17-18 ignited massive wildfires, including the 980,000-acre August Complex, the largest fire in state history, USFS and the California Department of Forestry and Fire Protection (Cal Fire) reported.

The August storms also started three more of the five largest fires in state history: the SCU Lightning Complex, LNU Lightning Complex and the North Complex, all in Northern California, the agencies said.

The Creek Fire, in the Sierra Nevada foothills of Central California, rounds out the top five fires, all of which occurred this year, Cal Fire said. Its cause, and the cause of other major blazes, remains under investigation.

California still has at least another month of high fire risk. In Northern California, the late summer and fall fire season usually lasts until seasonal rains start in November. Major fires have broken out in drier Southern California as late as December in recent years.

“As we enter the fall season, which is known to have the largest wildfires, we want to remind everyone that now is the time to be prepared,” Cal Fire warned residents.

October 4, 2020

Vermont Working to Electrify Rural Transit

[contact-form][contact-field label=”Name” type=”name” required=”true” /][contact-field label=”Email” type=”email” required=”true” /][contact-field label=”Website” type=”url” /][contact-field label=”Message” type=”textarea” /][/contact-form]More than 200 people joined the annual two-day Energy Action Network (EAN) Summit online last week to hear ideas on how to tackle some of the clean energy challenges facing the mostly rural Vermont, including increasing bus ridership and incentivizing more fuel-efficient cars.

EAN comprises more than 200 nonprofits, businesses, public agencies and other organizations advocating for clean energy. Following is some of what we heard at the meeting.

Vermont transit — Clockwise from top left: Carolyn Wesley, EAN; Cara Robechek VEEP; Jack Hanson, Sustainable Transportation Vermont; state Sen. Andrew Perchlik; and Linda McGinnis, EAN. | *Vermont EAN*

‘Cultural War’

State Sen. Andrew Perchlik spoke about his proposed vehicle “feebate” program aimed at people buying new vehicles. It would provide a rebate if the vehicle has a mileage rating above average for its vehicle class and add a fee on the purchase if it is below average. House Bill 529, signed into law last year, called for a study of the proposal, which Perchlik said would be self-funding program and revenue-neutral for the state.

The electric Chevy Bolt, which gets 118 mpg equivalent, would be worth a $1,000 rebate, under the program he said.

“But if you really wanted a Cadillac CT5 that only gets 21 mpg, that price would be adjusted up $500. … In a truck example, if you wanted the Ford F-150 Raptor four-wheel drive that only gets 16 mpg, you would pay $250 more for that vehicle,” Perchlik said.

“We would adjust accordingly… to make sure that it’s meeting its goal of causing people to buy more efficient vehicles,” Perchlik said. “We also don’t want to make the penalty so large … that it creates a lot of pushback, especially as we’re just rolling out the program.”

He said the program has been implemented in Ontario but not in the U.S. “Part of the reason is that you get into a cultural war of truck owners not wanting to support Prius owners, for example.”

Junk the Clunker, Go Electric

Sue Minter, executive director of Capstone Community Action, a social advocacy organization, and EAN Senior Fellow Linda McGinnis promoted a “Replace Your Ride” program modeled on one in California to provide cash incentives to low-income Vermonters to trade in their older high-polluting vehicles for a range of clean transportation and shared-mobility options.

Jennifer Wallace-Brodeur of the Vermont Energy Investment Corp. (VEIC), a nonprofit organization that advocates for energy efficiency and renewable energy, joined Cara Robechek of the Vermont Energy Education Program (VEEP) and Peggy O’Neill-Vivanco of the University of Vermont to speak on combining and electrifying rural school and public transportation.

The Vermont Clean Cities Coalition at UVM is a transportation fuels resource for educators, consumers and providers of advanced transportation technologies.

An anonymous participant submitted a question about how the electric buses would handle the rough terrain that a lot of diesel- or natural gas-powered school buses cover in rural areas.

In 2017, Green Mountain Transit, Advance Transit and UVM demonstrated an electric transit bus to test out how it would do in winter conditions and a variety of routes. “We did find that there are different emission savings and fuel cost savings associated with different operating conditions. So, whether it be short routes in town with lots of stops and starts, or hilly routes, there’s definitely some pros and cons to all of that. Operating conditions do make a difference,” O’Neill-Vivanco said. (See Takeaways from the Zero Emission Bus Conference.)

Wallace-Brodeur said that buses can increase their power through regenerative braking when they’re going downhill.

“But they do draw on the battery a little bit more when you’re going up, so it’s a bit of a tradeoff there,” she said. “And we absolutely know that winter conditions will impact the range of battery electric buses. So that has to be factored in when you’re planning routes and the size of batteries and battery configuration.”

Analysts at UVM have found that all of the schools that are participating in the test could meet the needs of their daily school transportation routes, with an electric bus, despite the range decreases in winter, Robechek said.

Another question was how the program would overcome safety issues connected with merging school and public transit systems.

“In most of the world, and many cities in this country, school and public transit does take place on the same buses, including in Burlington, Vt., and it takes place on public buses, not on school buses,” Robechek said.

Nothing Beats a Free Ride

Jack Hanson of Sustainable Transportation Vermont (STVT) proposed that the state allocate $3 million out of the $641 million transportation budget for 2020 to fund fare-free transit, as a way to cut per capita emissions and enhance social justice.

“Vermont has a very serious problem of transportation emissions despite years of improvement, with nearly half of current emissions as a state coming from transportation. By far the largest share of those emissions is from our reliance on single-occupancy vehicles,” Hanson said.

Mass transit offers a drastic reduction in carbon emissions over single-occupancy vehicle gains, but it’s a challenge in a rural state to get people out of their cars and onto buses. Fare-free transit has proven effective in case studies around the world, he said.

For example, Advance Transit, which serves the Dartmouth area between Vermont and New Hampshire, saw a 76% increase in ridership in the first two years of fare-free transit and a nearly 300% increase since it was implemented in 2014. Green Mountain Transit, which serves the Burlington and Montpelier areas, projects that if fare-free was implemented under normal, non-pandemic conditions, it would see a 37% increase in ridership, Hanson said.

“So, who is currently paying transit fares in Vermont? Well, it’s the bus riders themselves, obviously,” Hanson said. “And this is a group of Vermonters that is disproportionately low-income and people of color. It’s a group that has some of the least impact on climate change … [and] many of these folks have limited mobility options.”

October 4, 2020April 9, 2024

Overheard at GTM’s Power and Renewables Summit

The Sept. 29 debate between President Trump and former Vice President Joe Biden didn’t draw rave reviews, but there was one bright spot, said Dan Shreve, Wood Mackenzie’s head of Global Wind Energy Research.

“Happily, climate change did get about 10 minutes of the debate last night, which is far more than what was seen in the last presidential election,” Shreve said during a presentation at Greentech Media’s annual Power and Renewables Summit last week. “So certainly, environmental concerns are top of mind for folks.”

By one account, the three debates in the 2016 presidential general election spent less than six minutes on climate change and other environmental issues. In 2000, by contrast, Al Gore and George W. Bush spent more than 14 minutes discussing the environment over three debates.

While Trump has dismissed concern over climate change and is promising to continue rolling back environmental regulations, Biden has proposed a $2 trillion plan to eliminate power sector carbon emissions by 2035 and make the U.S. the leader in electric vehicle production. (See Biden Offers $2 Trillion Climate Plan.)

“The stakes are exceptionally high” in this election, said Shreve, citing both the presidential race and the fight for control of the Senate.

The Biden plan would require 1,500 GW of new capacity — more than 1,100 GW of utility-scale solar, 243 GW of onshore wind and 142 GW of offshore wind — plus 410 GW of battery storage, an estimated $2.2 trillion in capital expenditures.

“There are some big changes in here, and that’s why we’re characterizing them as aspirational. The changes are so substantial and require so much collaboration — things that we haven’t had a great deal of here in the United States for some time,” Shreve said.

The $2.2 trillion doesn’t cover transmission and other infrastructure upgrades needed to support the additional renewables. The National Renewable Energy Laboratory’s 2018 interconnection seams study, which proposed three HVDC transmission connections between the Eastern and Western Interconnections, would cost about $250 billion, Shreve said.

The Climate Institute’s proposed North American Supergrid, which envisions 42,000 miles of new HVDC transmission, most of it underground, has a price tag of almost $500 billion, he added.

Winning legislative approval and finding funding isn’t the end of the battle, however.

“We’re running increasingly into wind and solar permitting issues,” Shreve said. “A great deal of NIMBY [not in my back yard] concerns being voiced through social media and a variety of different avenues. … This same thing happens when we start talking about transmission infrastructure” needed to deliver wind power to load centers.

Energy Vault, which stores renewable energy by raising and lowering 35-ton cement bricks, won a $110 million investment from Softbank. | Energy Vault

If emission-free resources supply 90% of the nation’s power needs, the remaining 10% could be filled by natural gas-fired generation, but that would require refining carbon-capture technologies that have yet to reach commercialization, Shreve said.

“There’s an enormous amount of R&D that has to happen and a tremendous amount of risk of those technologies [not] actually reaching some level of commercial success.”

Shreve said venture capital has been pouring into companies attempting to develop long-duration, high-energy-density storage applications that could be paired with wind, citing Gravitricity and Energy Vault, which received a $110 million investment from Softbank.

“They are still very early-stage technologies,” he cautioned.

National Grid CEO Discusses Electrification Challenges

In another session at the virtual conference, Badar Khan, president of National Grid US, said decarbonizing heating will be the biggest obstacle to addressing climate change. The utility serves 20 million people in Massachusetts, New York and Rhode Island.

“Home heating is going to be the hardest sector to decarbonize because the current technologies beyond natural gas are just much more expensive. The good news is that plenty of people are working on solutions,” he said, referring to geothermal heat pumps, biogas from landfills and wastewater treatment plants, and “green” hydrogen made from renewable power.

“Whether it’s the electrifying pathway or the biogas/hydrogen pathway, we’re going to need to see a lot of innovation and policy support and a lot of customer engagement,” Khan said.

‘Bullish’ on the Future

Todd Glass, a partner in energy and infrastructure for the Palo Alto law firm Wilson Sonsini Goodrich & Rosati, said he’s “bullish” on the future.

“Renewables are becoming cheaper and cheaper, and the marginal cost of energy is lower than we ever thought it would be, especially 10 to 15 years ago when we were starting to do these types of things. The second thing is that the technology in the controls and dynamic pricing … these technologies with [artificial intelligence] and other things like that are driving innovation at the grid edge in a way that delivers value to customers.”

Glass said he’d like to “restart the conversation” from the beginning of utility restructuring 20 years ago, saying customers want “the opportunity … to be green.”

While two-thirds of the U.S. load is in restructured states, “one-third of the load has zero choice. That means they get whatever their utility serves up,” he said. “That is so stuck in the past and so contrary to the customers’ interest. For too long … utilities and captured utility commissions have deigned to speak for what customers want. I think we need to focus on what the customers actually want and put their interests first.”

‘Huge Opportunity’

Dan Seif, vice president of market development for 7X Energy, a Texas-based utility-scale solar and storage developer, said load-serving entities in Texas — particularly those not subject to retail choice — should be contracting for storage.

He said ERCOT’s interconnection queue has 200 MW of storage and is likely to hit 1 GW within two years. “The real issue that’s keeping it from … exploding and realizing the size of the queue is contractability of ancillary services, particularly” responsive reserve service (RRS), he said.

Seif said RRS represents two-thirds of the ancillary services that load-serving entities must purchase. “There’s a huge opportunity that’s kind of obvious for load-serving entities,” he said. “They should buy a portion of their load exposure from storage projects or solar and storage projects. All the big guys — Reliant [Energy], EDF [Renewables], the big monopoly utilities … Austin Energy, [Lower Colorado River Authority], Brazos [Electric Power Cooperative] — no reason not to put that into your portfolio and enable some of these storage projects.

“I think a lot of them are thinking about it, but maybe everybody is kind of looking to the left and right and saying, ‘You first.’”

Seif said some financial traders are looking at storage for arbitrage opportunities. But the “natural buyers” are LSEs, “as long as they think they’re going to have a lot of load for a while. And the monopolies have no excuse — the customers have nowhere to go.”

October 4, 2020March 11, 2025

RI Updates 2030 Load and Renewables Forecast

Brattle’s analysis also shows Rhode Island demand outlook similar to New England, with moderate load growth through 2030 and significant growth after because of heating and transportation electrification. | The Brattle Group

Rhode Island will need to add about 440 GWh of renewable energy annually to meet the state’s goal of 100% renewable energy by 2030, The Brattle Group said at the second in a series of three public workshops hosted by the state’s Office of Energy Resources (OER) on Sept. 29.

Equally daunting, the state will need to continue adding an average of 400 GWh a year to maintain the 100% target through 2050 as its load potentially doubles from the electrification of heating and transportation, Brattle said.

The consultants are helping state officials develop a plan by year-end for the clean energy target mandated in a January executive order by Gov. Gina Raimondo. (See RI Seeks to Lead with 100% Renewable Goal.)

Electrification Impact

At the first public meeting in July, the analysts said the state would need to add 360 GWh annually through 2030 to meet the target. The current estimate’s base case projects net load of 7,700 GWh in 2030, including electrification of 5% of light-duty vehicles (LDVs) and 5% of heating, based on an ISO-NE forecast, said Michael Hagerty, Brattle senior associate. The baseline also incorporates National Grid’s forecast for energy efficiency.

Michael Hagerty, Brattle | The Brattle Group

The baseline is bracketed by a low-demand scenario of 7,000 GWh and a high-demand scenario of 8,300 MWh, which assumes 15% LDV electrification and 10% heating electrification.

“In our low-demand scenario, we’re assuming that level of electrification does not occur,” Hagerty said.

The study says the state needs to add 4,400 GWh of renewable energy by 2030 to meet 100%. Last year, Rhode Island’s renewable electricity production of 930 GWh represented 13% of the state’s load. The state has 410 MW of renewables, including 230 MW of solar, including net metered resources, and 180 MW of contracted resources.

Current transmission queues list more than 12 GW of offshore wind, and 2.2 GW of onshore wind from Maine and 4 GW from New York. But the ISO-NE queue currently has no Rhode Island-based onshore wind because of wind quality and land availability, Brattle reported.

The costs of transmission and distribution system upgrades needed to accommodate the new renewables is “a source of significant uncertainty,” Hagerty said. “We’ve been reviewing these projections with renewable developers to make sure that they find them to be reasonable, and we’ve generally heard that they are.”

The limited availability of low-cost interconnection points for 1- to 10-MW scale distributed solar has resulted in increased interconnection costs, which might offset some of the cost declines seen in the industry, Hagerty said. An increase of $200 to $300/kW in system upgrades could increase distributed solar costs by $10 to $24/MWh, he added.

Wholesale Modeling

Brattle principal Dean Murphy outlined how the consultants are modeling the New England wholesale electricity market.

Dean Murphy, Brattle | The Brattle Group

“It’s important to recognize that the fundamental nature of this market is going to change substantially, even by 2030, and perhaps especially thereafter due to the significant addition of renewable energy generators across the system,” Murphy said. At 6% of regional load, “Rhode Island … is a very small component of New England overall, so it will be driven more by changes in other states that are also decarbonizing their electricity resources, albeit less quickly than Rhode Island.”

Because the output of renewables is highly correlated and difficult to store, once a lot of solar has been added to the system, incremental additions will have diminishing value. To capture how that dynamic will work out over time, Brattle uses an in-house model called GridSim.

Jurgen Weiss, Brattle | The Brattle Group

The study projects that gas-fired capacity will be kept around until 2040 but will be used much less than now as other renewable resources come online. In response to a question by an attendee, Brattle principal Jürgen Weiss acknowledged that gas generators will become increasingly dependent on capacity revenues to survive as their energy market revenue drops with lower utilization. He said the model accounts for the shift, ensuring all resources cover their fixed and variable costs.

“[It is] important to note that something similar is already the case since there are resources that don’t generate much electricity but stay in the market to provide reliability,” such as older dual-fuel units, he said. “If they have been built, you don’t necessarily need higher capacity prices since the capital cost is sunk and you just need to cover their going-forward costs,” Weiss said.

“Solar may be an excellent complement to wind, in part because it does generate more in the summer, when there is a summer peak for load in the daytime,” Murphy said. “A blend of these two kinds of resources is likely to be better than either one in isolation.”

Natural gas-fired capacity will be maintained into 2040 but will be used a lot less as other renewable resources come online. | The Brattle Group

Environmental Justice

OER Commissioner Nicholas Ucci told the workshop that his office is including social and environmental justice considerations in its work on clean energy.

“Folks should be comforted by the fact that we are accounting for many if not most of those categories in the 4600 framework, either analytically, qualitatively or by other means,” Ucci said, referring to the Public Utilities Commission’s Docket No. 4600, an investigation into the changing electric distribution system.

“One piece of good news is that, unlike in the past when dirty stuff was located in places that hurt particularly vulnerable populations, here we’re talking about locating renewable energy resources — and their negative impact on surrounding communities is considerably less than coal-fired power plants,” Weiss said.

How those vulnerable populations are protected from potential rate increases is a separate and important topic, Weiss said. “But we’re cleaning up Rhode Island’s electricity system, so the trajectory is to remove harm that might have been inflicted in the past. One can also ask whether the policies that are implemented to achieve the 100% renewable electricity target could be used to help those communities that are disadvantaged.”

For environmental justice, “the first step is to look inward,” Ucci said. “A lot of our state agencies are starting to connect with local grassroots organizations to better understand their perspectives [and] working to educate and train ourselves.”

October 4, 2020

FERC Accepts WECC Violation Settlement

FERC on Wednesday approved a settlement between WECC and an unnamed entity in the Western Interconnection for violations of NERC’s Critical Infrastructure Protection (CIP) reliability standards (NP20-21). The settlement does not involve a monetary penalty. NERC notified the commission of the agreement Aug. 30 in a Notice of Penalty (NOP), which FERC indicated in a notice that it would not review.

The NOP was submitted prior to NERC and FERC’s decision last month to end public disclosures of CIP violations and therefore follows the previous practice of redacting from public filings data considered to be critical energy/electric infrastructure information (CEII). (See FERC, NERC to End CIP Violation Disclosures.) Going forward, the organizations will treat CIP noncompliance information filed to the commission as CEII in its entirety (AD19-18); it is unclear whether NERC will continue to provide public information about CIP violations in any form.

Security Gaps in Remote Access Measures

WECC’s settlement with the unnamed utility involves two infringements of CIP-005-5 (Cybersecurity — Electronic security perimeter(s)) and one infringement of CIP-007-6 (Cybersecurity — Systems security management).

Both of the CIP-005-5 violations relate to requirement R2, mandating that entities “allowing interactive remote access to [high- and medium-impact bulk electric system] cyber systems” must implement two-factor authentication (2FA) and that intermediaries that ensure remote access programs do not come in direct contact with the BES cyber systems themselves. The entity made WECC aware of the violations via self-report in February and March 2017.

In the February incident, after multiple users reported lost or damaged security devices, the utility allowed those users to bypass its 2FA system before a planned replacement system had been activated. As a result, cyber assets covered by CIP-005-5 were accessible by passwords alone for some employees. In a few cases, even some users who had not reported issues were still not asked to verify their identities via 2FA. WECC determined the root case of the violation to be failure to assess the risks or consequences of bypassing 2FA and described the risk level as “serious and substantial.”

WECC Violation Settlement — The entrance to WECC headquarters in downtown Salt Lake City | © *ERO Insider*

Details on the March case are less clear because of redactions, but WECC indicated that the entity was not using an intermediate system to block access to applicable cyber assets, although in this case, 2FA was not breached. Staff were also aware of the potential vulnerability and implemented several alleviation measures, including active monitoring of failed login attempts and regular patching of computers used to access the affected systems. As a result, WECC assessed the risk level as moderate, identifying the root cause as failure to clearly understand the compliance requirements or validate them for completeness.

Mitigation measures in the first case include developing a new process for creating, issuing, tracking and revoking hardware tokens, and training staff in their use; the entity also removed any previously granted password-only access. For the second instance, the entity changed its electronic access policies to ensure all interactive remote access goes through the same intermediary and revised its system architecture to ensure consistent policies are followed in future hardware deployment. WECC certified completion of the plans in September and October 2019, respectively.

Patch System Review Finds Holes

The entity’s violation of CIP-007-6 arose from requirement R2 of the standard; specifically, the utility reported in October 2017 that it had discovered “significant gaps in evidence to confirm compliance” with provisions related to high- and medium-impact cyber assets. The identified gaps include:

an inaccurate and incomplete control center patch source list;
patch evaluations not completed every 35 days;
patch installation or mitigation plans not completed within 35 days of patch evaluations; and
procedures ensuring that mitigation plans were completed on schedule not established and administered.

According to the entity’s records, the issues dated back at least to July 1, 2016, when the standard became enforceable. WECC attributed the violation to the entity “underestimating the resources and effort required to establish and operate a compliant security patch program” under the new standard, and determined that the issues posed a serious and substantial risk to BES reliability.

To address the violation, the entity consolidated patch source lists and updated them to include all software and firmware that might be covered by the relevant standard, and implemented standardized manual patch processes for all applicable cyber assets, among other measures. WECC verified completion of the mitigation plan in January 2020.

To justify its argument that no monetary penalty was needed, WECC cited the fact that the entity was cooperative through the process, reported all violations in a timely manner and made no effort to conceal the violations. The regional entity also observed that there was no indication the infringements were intentional.

While WECC acknowledged previous compliance issues with both CIP-005-5 and CIP-007-6, it argued that they did not serve as a basis for aggravating the penalty. The earlier CIP-005-5 violation was of minimal risk and occurred in 2011, and therefore was “not indicative of broader compliance issues,” while the current CIP-007-6 infringement was related to a lack of resources rather than flawed implementation of the patch management program, as in the earlier violation.

October 1, 2020

Experts: Foresight Key to Insider Threat Defense

Experts at ReliabilityFirst’s Insider Threats Webinar on Wednesday warned that many common insider threat mitigation strategies can actually increase the risk of attacks and urged utilities to take a different approach to internal security.

“When we typically think about security controls, we’re talking about disabling somebody’s access or … doing something else punitive to them,” said Dan Costa, technical manager of enterprise threat and vulnerability at Carnegie Mellon Software Engineering Institute. “[But] the likelihood of that insider [causing] some harm against the organization might be best mitigated by … retraining, rebalancing somebody’s workload, [or] having coworker conflict training and mediation sessions available. … Organizations where employees are happy about working there … tend to experience less insider events than those that do.”

Insider threats — defined by Costa as the “potential misuse of authorized access to an organization’s critical assets … in a way that has the likelihood to have some negative outcome” for the organization — are a unique hazard for any company, in that by definition, they originate from those in whom the entity has already placed a great deal of trust. As a result, these incidents are potentially more damaging than external attacks and more likely to be overlooked by management.

They are also frequently overlooked by outsiders: As Costa noted, many organizations prefer to handle insider threat events internally, which means that without legally mandated reporting, the number of attacks reported in publicly available statistics may be deceptively low. Carnegie Mellon’s own statistics, which are based on court records, show a far higher incidence of insider threat events since 1996 in the finance and insurance industry, which has relatively strong fraud prevention laws, than in the utility sector.

Insider Threat Defense — Insider threat incidents by industry or sector since 1996 | *Carnegie Mellon University*

Even if Carnegie Mellon’s record of 29 insider incidents in the utility sector over 24 years is taken at face value, they must still be viewed seriously, given the fact that more than a third of these attacks led to financial impacts in the six figures.

“Insiders … know what is valuable to your organization; they know what is mission-essential to your organization,” Costa said. “They know how it’s protected; they know how to bypass or circumvent those protections; and insiders that are sufficiently motivated to intentionally cause harm to the organization are uniquely positioned to do so.”

Looking for Warning Signs

The vulnerability doesn’t end with current employees, as illustrated in the attack suffered by instrumentation developer Omega Engineering at the hands of former network administrator Timothy Lloyd. Steven McElwee, chief information security officer at PJM, described how Lloyd struck back at his former employer in 1996 when he was demoted, then fired.

“Because of his privileged access as a network engineer, and because of some temper issues, he didn’t handle it very well,” McElwee said. “So he wrote six lines of code … very simple, very elegant, and it was a time bomb. When he was fired, and he left the organization, it successfully deleted all of the source code for Omega engineering. It was a devastating blow to the company, and I don’t think they ever really recovered from it.”

Financial impact of insider threat incidents in the utility sector since 1996 | *Carnegie Mellon University*

Omega later reported spending nearly $2 million repairing the damage from Lloyd’s attack and losing almost $10 million in revenue, resulting in 80 layoffs. Quoting a line from the film “Batman Begins,” (“It’s not who I am underneath, but what I do that defines me.”) McElwee listed several behaviors that should have tipped managers off that Lloyd was likely to cause issues and led them to take additional precautions.

“First of all, he was demoted. That was a sign. … He was on someone’s radar as a problem employee,” McElwee said. “Second, he was considered to be a hothead. So, they might have expected a strong reaction when they were firing him and been able to take some additional precautions. Third, someone knew he was going to be fired. All of these factors should have raised lots of red flags.”

Support, not Punishment

Given cautionary tales like Omega’s, organizations might feel the best defense is to cut off insider attacks before they begin by locking down potentially difficult employees’ access to critical assets as soon as problems emerge, or by transferring, demoting or even terminating these workers. But participants in the webinar warned that these tactics are likely to backfire, creating the very situation they are intended to prevent.

Presenting Carnegie Mellon’s models for the incitement of insider fraud and sabotage events — the two most prominent types of incidents in its research — Costa observed that the vast majority of insider attacks have multiple contributing factors.

In the case of fraud, an individual may begin with no malicious intent toward their employer but move over time toward a decision to steal from the workplace because of family issues, financial pressures, resentment toward the company and other issues. Sabotage may stem from feeling underappreciated and mistreated by coworkers and management.

Both situations can be aggravated by punitive measures such as reassignment, demotion or firing. An employee considering theft of company property may feel that such steps leave them with no legitimate option for solving their issues, while one thinking of sabotaging the workplace may feel insulted by attempts to remove their access and move forward with their plans.

“It’s this combination of concerning behavior and then maladaptive organizational responses, [and] these cycles that start to happen between more concerning behaviors exhibited and more maladaptive organizational responses,” Costa said. “There’s a tipping point where eventually the insider becomes motivated to cause harm to the organization.”

This does not mean that organizations should overlook warning signs for fear of pushing employees into a downward spiral, or that there are no situations where removing an insider’s access is appropriate. However, speakers emphasized that the most effective way to reduce the amount and impact of insider attacks is to understand the pressures that lead employees to cross the line and address them where possible.

“Everyone has vulnerabilities … and not all kinds of vulnerabilities are going to cause issues in their organization,” said Benjamin Gibson, a senior physical security analyst at the Electricity Information Sharing and Analysis Center. “It’s some of these confluences of factors … where you start raising the red flag. … Part of the program is to identify where the vulnerabilities are, know where the people might have vulnerabilities, and knowing can help mitigate [them].”

October 1, 2020

SPP Delays Staff’s Return to Offices by 3 Months

SPP leadership has delayed staff’s return to their offices until at least Jan. 4 — a three-month delay from the previous target of Oct. 5 — because of increasing COVID-19 diagnoses in Arkansas.

COO Lanny Nickell said in a Thursday email that SPP’s officers decided to postpone the return to the RTO’s Little Rock headquarters until 2021. The White House Coronavirus Task Force on Tuesday said Arkansas has the nation’s seventh highest rate of new cases: 194 per 100,000. Arkansas on Wednesday reported 942 new cases and 19 deaths, raising its totals to 80,945 and 1,369, respectively.

SPP has delayed by three months staff’s return to its corporate headquarters. | *WER Architects*

“It wasn’t an easy choice. Like many of you, we’re eager to get back to normal, but case numbers are still high across our state and in Little Rock,” Nickell said. “Especially given our office’s open floor plan, which could exacerbate the effects of exposure should any of our staff become sick, we’re doing all we can to safeguard the health of our employees and our ability to serve you.”

Nickell also said SPP’s system loads have largely returned to pre-pandemic levels. He said the grid operator has sufficient capacity and reserves to meet demand this fall and that delayed generator maintenance has not resulted in an increase in unplanned outages.

October 1, 2020September 26, 2025

CAISO Floats EIM Base Schedule Rule Changes

CAISO launched a two-part initiative Wednesday that would alter how Western Energy Imbalance Market (EIM) participants submit their base schedules.

The base schedule is the hourly forward energy plan that CAISO uses as a baseline to measure energy balance deviations for market settlements in the EIM. Rules set out three deadlines by which EIM entities must submit the resource plans behind their hourly base schedules.

By the first deadline, at T-75 (75 minutes before the operating hour), all participating and nonparticipating resources must submit their base schedules, and participating resources must submit their energy bids. CAISO’s market software then evaluates each 15-minute interval within that hour for capacity and flexible ramping capability.

A second deadline follows at T-55 after CAISO validates initial base schedules. At that point, market entities can review and update their schedules, which is followed by another set of validations.

At T-40, entities are required to submit final, financially binding base schedules, used by CAISO to balance against the load forecast and set the baseline for determining imbalance energy for the operating hour.

CAISO’s proposal would push the financially binding base schedule deadline from T-40 to T-30, a move that would require the ISO to update its market software to shift the start of the EIM’s real-time pre-dispatch (RTPD) process from T-37.5 to T-29, while retaining the current RTPD completion time of T-22.5. CAISO’s final base schedule test would also be moved to after the T-30 deadline.

CAISO’s proposal would shift the EIM’s final base schedule deadline from T-40 to T-30, shortening the real-time pre-dispatch interval. | CAISO

The ISO committed to examining the change as part of its EIM implementation agreement with the Bonneville Power Administration. A portion of BPA’s customers operate under “slice of system” contracts that provide them with a percentage of the output from the federal Columbia River Power System rather than a fixed volume of energy. Slice nominations can be updated after T-40, potentially exposing BPA to imbalance charges under the existing rules once it begins transacting in the EIM in 2022.

“It would create the ability for EIM entities to submit more accurate final base schedules as the deadline is simply closer to the operating hour,” Danny Johnson, CAISO lead market design developer, said during a call to discuss the proposal Wednesday. “Ideally this reduces the financial impact of imbalance settlement, and it would provide more accurate base schedules to the RSE [resource sufficiency evaluation].”

Johnson added that while the proposal “was precipitated by the EIM implementation agreement, I do want to clearly point out that this change is available to all EIM participants.”

John Walker, an analyst with Portland General Electric, asked whether CAISO would consider moving any of the other base schedule submission timelines in light of the T-30 change.

“Right now, all we’re proposing is that T-40 to T-30 [shift]. I think maybe at some future date we’d think about moving around the other timelines associated with the base schedule submission process, but not within the scope of this initiative,” Johnson responded.

Accounting for Start-up Energy

The second part of the straw proposal would allow EIM participants to factor start-up energy into their hourly resource plans and base schedules. The ISO’s Tariff currently prohibits those participants from submitting base schedules that show energy above zero but below a resource’s minimum load (Pmin).

The proposal notes that some EIM resources have multi-hour start times and minimum loads in the hundreds of megawatts, but existing rules prevent those resources from accounting for start-up energy in their base schedules for the EIM’s RSE ahead of an operating hour.

“This leaves the EIM entity with two options: either exclude this energy from the base schedule, which results in no inclusion in the RSE, or reallocate this energy to other online resources,” the proposal says. “Neither of these options allows the EIM entity to accurately capture a potentially significant amount of energy produced while a resource is starting.”

The proposed plan would entail CAISO altering the logic of its base schedule aggregation portal and the RSE to allow entities to include start-up energy in their base schedule submissions.

“This will allow EIM entities to capture start-up energy in their schedules. The start-up energy will not be hit with uninstructed imbalance energy” charges, Johnson explained.

While the energy will be counted as part of the EIM entity’s RSE for the balancing test, CAISO clarified it would make no changes to the EIM’s capacity, flexible ramp and transmission feasibility tests. A resource operating below its minimum load will still be prohibited from providing ancillary services.

CAISO acknowledges that the changes would create a discrepancy between how start-up energy is treated for EIM and ISO resources. But the ISO noted that it already creates balanced day-ahead schedules through its Integrated Forward Market (IFM) while EIM entities produce their own balanced schedules, allowing the latter to include start-up information in the submission of their base schedules.

“To achieve similar treatment for the CAISO, the IFM would need to include this start-up energy within its optimization. Any after-the-fact inclusion of this energy to balanced day-ahead schedules would potentially create upward flexibility, at the expense of downward flexibility,” CAISO said. “As the CAISO schedules are already balanced, the CAISO does not believe this additional upward flexibility is worth the potential risk of failing the RSE in the downward direction.”

CAISO said it believes inclusion of start-up energy in the day-ahead market should be addressed “holistically” either through its existing extended day-ahead market initiative or some other future effort. (See CAISO Proposal Sets Course for EIM Day-ahead.)

The ISO additionally proposes to implement “after-the-fact” monitoring criteria to ensure participants don’t abuse the market based on the change, including looking for a non-monotonically increasing pattern of base schedules below Pmin over consecutive hours; the lack of a base schedule in an hour following an interval with a base schedule below Pmin; and base schedules remaining below Pmin for an “unreasonably” long period based on the resource’s technology and start-up profile.

Brian Holmes, a director with Utilicast, asked whether resource owners would be given an after-the-fact opportunity to explain why a resource might have been flagged under the criteria, such as a failure to start up.

“I don’t think we want this to be unnecessarily punitive,” Johnson said.

CAISO Senior Manager Brad Cooper said the ISO hopes to implement the start-up energy portion of the proposal by next spring, with the T-30 slated to follow next fall.

Kristina Osborne, CAISO stakeholder engagement and policy specialist, said the proposal will likely fall under the EIM Governing Body’s primary approval authority. She said stakeholders should provide feedback on the proposal and the RTO’s proposed classification by Oct. 14.

The proposal will go before the Governing Body on Dec. 3 and the ISO’s Board of Governors later that month.

October 1, 2020

PUC Reconsidering Texas RE as Reliability Monitor

Texas regulators are raising concerns about its contract with Texas Reliability Entity as ERCOT’s reliability monitor, questioning whether they are getting their money’s worth and whether there is enough transparency for ratepayers.

The issue came tumbling into the open during the Public Utility Commission’s Sept. 24 open meeting, when it considered a proposal related to oversight of wholesale market participants. Commissioner Shelly Botkin had filed a memo asking to discuss draft amendments to its rules that would make having a reliability monitor discretionary and allow ERCOT to assume the responsibilities (50602). (See “PUC to Consider Reliability Monitor Rule Change,” Texas Reliability Entity Briefs: Sept. 3, 2020.)

“My main concern I have is making the reliability monitor discretionary,” she said. “It doesn’t seem to be an option to me. … If you want to have flexibility in the rule, I understand that, but it’s something I could not get over.”

Chair DeAnn Walker did not hold back as she shared her thoughts on Texas RE serving another four-year term as reliability monitor. She suggested using their contract’s severance clause to give 30 days’ notice of its termination.

“I don’t think we have the authority … to make Texas RE our reliability monitor,” Walker said.

Citing a section in the state’s Public Utility Regulatory Act (PURA), she read aloud from the statute:

“‘The commission shall adopt and enforce rules relating to the reliability of the regional electrical network … or may delegate to an independent organization responsibilities for establishing or enforcing such rules. …

“‘The commission has complete authority to oversee and investigate the organization’s finances, budget and operations as necessary to ensure the organization’s accountability and to ensure that the organization adequately performs the organization’s functions and duties. …

“‘The organization shall fully cooperate with the commission in the commission’s oversight and investigatory functions.’”

Texas Reliability Entity — PUC Chair DeAnn Walker discusses the Texas RE reliability monitor contract. | *Texas PUC*

Walker said the statute “clearly says” the commission “may delegate” the reliability monitor’s function to an “independent organization.” That “independent organization” would be ERCOT, not Texas RE, she said.

The PURA repeatedly refers to ERCOT as “the independent organization,” never “ERCOT,” PUC spokesman Andrew Barlow noted.

“What has become clear to me today is that if we delegate the contract, it has to be to an independent organization, and we only have one of those. And that’s ERCOT,” Walker said. “As to us having ‘complete authority to oversee and investigate’ the [reliability monitor’s] finances … we have absolutely none over Texas RE. … I don’t think that contract is consistent with the statute.”

Texas RE holds a $5.3 million contract for the 2020-2023 term, an increase from the previous $4.3 million contract for 2016-2019. The increase did not sit well with Walker.

“To say it was a difficult process with Texas RE is an understatement,” she said of the PUC sending out bids for the new contract. “We raised concerns with [the increase]. We raised concerns because other entities had concerns with it. We were told that’s the price; that’s the actual costs.”

Walker said that in digging into the contract, the PUC discovered that Texas RE had included overhead costs that will increase by $80,000 over the contract’s term.

“The overhead includes part of the CEO’s salary, the board’s salaries, [and] the board’s and CEO’s travels to NERC meetings. … I don’t believe their travel to NERC meetings benefits the state under the reliability contract one bit,” she said.

Barlow said the commission is calling the contract’s value and efficacy into question because of the “return on investment” — Texas RE’s monitoring led to $1.7 million in penalties during its previous contract and almost $150,000 this year — and “somewhat duplicative” work. The Texas RE uses ERCOT data for analysis rather than generating its own, he said.

“The PUC has lawyers and engineers that are fully capable of doing the analysis [the Texas RE] currently handle[s],” Barlow said. “As the PUC continues its ongoing modernization efforts by assessing our own internal organization and scrutinizing major contracts, we’re working to ensure we’re the best stewards of taxpayer resources and protectors of consumer interests.”

“I could sit there all day long and complain that this money shouldn’t be spent this way. The answer I get is, ‘Thank you very much, you’re ex officio,’” said Walker, who, as the PUC’s chair, sits on Texas RE’s Board of Directors.

Texas RE CEO Lane Lanford, who is retiring at the end of the year, said he supports Walker’s “diligence in tracking Texas RE’s expenses along with those of all publicly funded organizations.”

“Ratepayers have a right to know how their money is being spent,” he said in a statement provided to ERO Insider. “As the PUCT considers a new vision for the Texas reliability monitor, Texas RE will continue to assist if needed to ensure the mutual goal of a highly reliable and secure bulk power system within the Texas Interconnection.”

Texas RE is funded through regional assessments, collected by NERC, on load-serving entities’ pro-rate share of net-energy-for-load usage within its regional footprint. Lanford said its reliability monitor finances are “firmly separated” from its NERC activities as the ERO’s delegated regional entity, which is its primary role. The reliability monitoring function is funded through ERCOT’s system administration fee, as stipulated by the PUC’s rules.

“We have a contract I was not comfortable with, that there is not enough transparency to ratepayers and what they were having to pay, and whether we were getting the benefit and whether we were getting the information we needed to maintain that contract,” Walker said.

She expressed further frustration with a Texas RE cash account that she said holds about $250,000 in unspent funds encumbered by the organization’s nonprofit status. She told Botkin and Commissioner Arthur D’Andrea that she had asked whether Texas RE could use the funds to offset the reliability contract, but no action was taken on it.

The PUC may be limited in its options for finding an alternative to Texas RE as the reliability monitor. Commission staff, ERCOT and Potomac Economics, which serves as the grid operator’s Independent Market Monitor, were all mentioned as possible replacements.

“I think we should, and could, look at ERCOT,” Walker said, noting that the grid operator served as the reliability monitor before Texas RE was created in 2010 and was included in the PURA as being able to monitor reliability until a 2015 revision.

Funding issues make it unlikely the PUC would bring the monitoring contract in-house. Texas RE currently dedicates four employees of its approximately 64 staffers to the reliability monitoring function.

“To hire the four here, we would need the money,” Walker said. “We currently don’t have the funding from the legislature to perform the functions that we have within PURA. We scrape by doing the best that we can. For $5.3 million, we could handle a ton of staff to get this done here.”

As for Potomac, Walker said that “in all honesty, we’ve had our issues with Potomac in the past.”

Long-time IMM Director Beth Garza stepped down from her position in December during ongoing contract negotiations with the PUC, citing the need for the commission to have the director it wants. Garza has been replaced by former ERCOT staff Carrie Bivens. (See Bivens Steps in as New Director of ERCOT Monitor.)

“I have come to the conclusion the [PURA] didn’t require us to have a reliability monitor, but we, through our own rule, created that requirement,” Walker said. “I think the rule does need to change, but it needs to change in a different way than what [has been proposed]. We’ll probably have to take comment to get there.”

In the meantime, the thought process will continue. The PUC next meets in open session Oct. 12.

D’Andrea said he supports giving 30 days’ notice to Texas RE, saying “it’s a really bad idea to have a rule where, when you read it, it pretty much creates a no-bid contract.”

“There’s only one entity out there that can win this [request for proposals], and we all know who it is,” he said. “It’s an entity over which we have no control.”

Botkin asked for more time to consider the issues.

“I’m concerned about canceling with no replacement. I’m fully aware there are not a lot of options out there,” she said.

Walker also asked for more time to study the contract.

“We have to be good stewards of the ratepayers’ money,” she said.