Page 532 – RTO Insider

February 4, 2022June 14, 2023

Report Warns of Growing Cyber Dangers

A handful of high-profile cyberattacks grabbed headlines last year, but cybersecurity advisory firm Tenable said in a report this week that the biggest challenge for the security community continues to be “age-old security challenges in new infrastructure.”

“Organizations continue to struggle with protecting, or even defining, the perimeter. Migration to cloud platforms, reliance on managed service providers, software and infrastructure as a service have all changed how organizations must think about and secure the perimeter,” the 2021 Threat Landscape Retrospective said. “Fragmented security solutions and poorly defined security outcomes must be left behind to match the complexity of the modern attack surface.”

Tenable’s goal was to highlight the security issues that plagued the public and private sector last year. While big events drew most of the public’s attention last year — for example, the compromise of the SolarWinds Orion network management software that began in December 2020, and the ransomware attack against Colonial Pipeline in May — the firm said these hacks were the tip of the iceberg, with 1,825 total breach events detected from Nov. 1, 2020 to Oct. 31, 2021.

OT, IT in ‘Attackers’ Crosshairs’

While details on many of last year’s cyber incidents have not been disclosed due to security and privacy concerns, or the desire of companies involved to avoid embarrassment, Tenable’s analysis shows more than 260 terabytes of data was stolen comprising 1.8 billion files, documents or emails.

About 38% of all breaches that Tenable analyzed were the result of ransomware attacks, such as the one against Colonial that led to the shutdown of the company’s entire pipeline network and stifled the flow of petroleum products to the U.S. East Coast. (See Colonial CEO Welcomes Federal Cyber Assistance.) Meat supplier JBS suffered a similar ransomware attack; like Colonial, its leadership decided to pay the attackers to unlock their computer systems and prevent the release of sensitive data. The two companies’ ransoms amounted to the equivalent of around $16 million.

While the Colonial and JBS breaches garnered national attention and concern at the highest levels of government, the energy, infrastructure and utilities sectors accounted for only a small fraction of ransomware attacks and total breaches. As in 2020, Tenable found that attacks fell most heavily on the healthcare sector, which accounted for nearly a quarter of the year’s total events, followed by education, with 13%.

However, the firm warned that utilities and other critical infrastructure operators should not rest easy, since last year’s incidents “proved that information technology (IT) and OT [operational technology] environments are in attackers’ crosshairs,” along with critical infrastructure. And since many of the same software tools are used across multiple industries, successfully breaking into one common platform can render all its users vulnerable.

This is what happened with the SolarWinds hack, in which the breach of the Orion software — now attributed to Russia’s Foreign Intelligence Service — may have exposed the information of thousands of customers, including the Department of Energy and FERC. (See FERC, E-ISAC Report Details Reach of SolarWinds Compromise.) The same hackers have since been blamed for additional attacks, including breaches of Microsoft and computer services provider Pulse Connect Secure.

Zero-days Across Common Software

A common point of entry for hackers are zero-day vulnerabilities, defined by Tenable as software or hardware flaws that are “unknown to a vendor prior to [their] public disclosure, or [have] been publicly disclosed prior to a patch being made available.” The firm identified 105 zero-day vulnerabilities in 2021, of which 83% are known to have been exploited in the wild. The report said that details of these weaknesses “are often kept under wraps” to prevent them from being exploited.

Two-thirds of the discovered vulnerabilities originated with just three companies: 28% in Microsoft products, 21% from Apple, and 18% from Google. Thirty percent of the vulnerabilities were detected in web browsers and 26% were in operating system software, with the rest found in web apps, email clients, office suites and other software products.

2021 zero-day vulnerabilities by vendor | Tenable

Tenable warned that while these vulnerabilities are “primarily leveraged in limited, targeted attacks” and therefore usually have limited impact at first, cybersecurity professionals cannot afford to disregard their dangers.

“The true value of a zero-day vulnerability is often not defined by its exploitation prior to discovery, but by the blog posts and proof-of-concept code published in the weeks and months after disclosure,” Tenable said. “Zero-day vulnerabilities typically become more problematic for most organizations after they’ve made the transition to legacy status, particularly if an organization has not yet applied available patches before widespread exploitation begins.”

February 4, 2022

NRC Finds Cybersecurity Deficient at Davis-Besse

The Nuclear Regulatory Commission this week ruled that the Davis-Besse nuclear plant in northwest Ohio violated cybersecurity rules and ordered it to develop new procedures.

The plant also now faces a series of stepped-up inspections to make sure its staff are following the new cybersecurity procedures.

NRC noted in a letter made public this week that Davis-Besse and its owner Energy Harbor, headquartered in Akron, agreed to a cybersecurity “performance deficiency” during a Dec. 6 closed-door meeting with the commission but disagreed about how significant the lapses were. The company has 30 days to appeal.

The commission uses a four-color code to signify the seriousness or significance of the citations it issues, which determines the subsequent level of future inspections the citations will bring.

A “green” citation indicates a minor infraction, without further significance, similar to a warning that law enforcement might issue to a speeding motorist. More serious citations are “white,” the next level, or “yellow,” leading to increasingly wider and more intrusive inspections. The fourth color is “red,” the most serious citation, typically leading to inspections of multiple systems, often plant-wide, all of it billed to the plant owner.

NRC stated the cybersecurity citation is “greater than green” but did not specify how much greater, meaning the citation is at least a “white” finding and could be “yellow” or even “red.” Cybersecurity violations are not publicly explained in detail, nor are appeals made public. Companies are by law not permitted to discuss publicly the details of cybersecurity violations. Energy Harbor did not return phone calls seeking comment.

The company is simultaneously opposing NRC findings on a maintenance issue at Davis-Besse that could affect the entire commercial nuclear industry.

Energy Harbor is fighting a preliminary citation that Davis-Besse’s failure over 15 years to inspect and clean electrical switches controlling the power output of the plant’s two emergency diesel generators (DGs) led to their failure to actually generate power when they were started during routine testing. In other words, the diesel engines fired up, but their generators did not produce power.

The preliminary finding was issued in December. (See NRC Preparing to Cite Davis-Besse Nuclear Plant on Safety Issue.)

Emergency DGs are crucial safety equipment capable of powering emergency cooling and other systems during a reactor shutdown and a simultaneous loss of power from the transmission grid. They are not often used, but when they are, they must work. That’s why nuclear plants have two, one of which is a backup.

An NRC “greater than green” citation that the electrical switches controlling the output of the generators require scheduled maintenance could have industry-wide significance because every nuclear plant is equipped with emergency DGs.

During a two-hour teleconference with NRC this week, the company’s engineers argued the that the failure of the electrical contacts in the switches was inherent in the materials used to make them and not because of lack of maintenance.

The commission is not expected to make a final ruling on the switches until March.

February 4, 2022November 9, 2023

California PUC Weighs Changes to Contentious Solar Plan

The California Public Utilities Commission said Thursday it will delay indefinitely a vote on its controversial plan to reduce net metering payments to rooftop solar owners as it considers rewriting the proposal.

The proceeding, led by former Commissioner Martha Guzman Aceves, is now in the hands of new President Alice Reynolds, who previously served as energy adviser to Gov. Gavin Newsom.

“The assigned commissioner [Reynolds] has requested additional time to analyze the record and consider revisions to the proposed decision based on party comments,” Administrative Law Judge Kelly Hymes wrote in an email to parties in the proceeding.

“The proposed decision, which was issued on December 13, 2021, will not appear on the commission’s voting meeting agenda until further notice,” Hymes said.

In an email to clients, ClearView Energy Partners said, “We regard [this] as perhaps the strongest indicator from the CPUC to date that significant changes to the proposed decision are likely. On this point, we reiterate our long-held view that the final decision may move more toward the recommendations from solar advocates.”

The “provision most susceptible to change” is a proposed $8/kW grid participation charge that has particularly irked homeowners, ClearView said.

California Sen. Diane Feinstein wrote to Reynolds on Jan. 25, recommending that the CPUC reconsider the grid participation charge “to spur adoption of this technology.”

“The fee structure should properly reflect the benefits of distributed generation and promote wide adoption of rooftop solar,” Feinstein said.

Newsom, too, has said he thinks the plan needs work. (See CPUC Takes Heat on Rooftop Solar Plan.)

Opponents of the plan spoke in public comments at the CPUC’s Jan. 27 voting meeting for more than eight hours, leaving only a short time at the end of the day for the commission to take up its scheduled business. (The net metering proposal was expected to be taken up at the meeting, the earliest date on which it could be heard, but the CPUC did not put it on the agenda.)

The proposed decision, released in December, would reduce electric bill credits for homeowners with rooftop solar arrays by up to 80% and add the monthly grid charge to their bills. (See California PUC Proposes New Net Metering Plan.)

In the decision, crafted by Guzman Aceves and Hymes, the CPUC said the current net metering scheme unfairly shifts costs from homeowners who can afford rooftop solar to those who cannot.

It “negatively impacts nonparticipating customers, is not cost-effective and disproportionately harms low-income ratepayers,” Hymes wrote.

Estimates of the annual cost shift have ranged from more than $1 billion to $3.4 billion.

Opponents, led by the solar industry, have contended it will decimate rooftop solar adoption.

Homeowners who purchase rooftop solar arrays and return electricity to the grid have never paid a connection fee and are compensated at full retail rates, which are more than utility-scale solar costs. California has approximately 1.3 million rooftop solar arrays as a result of the generous incentives, advocates argue.

Those who support the CPUC’s proposed decision, including the state’s large investor-owned utilities, argue utility-scale solar is more cost-effective and can serve far more consumers that rooftop arrays.

Hymes said in her email Thursday that she would update parties on the next steps.

“After additional analysis is conducted, I will issue a subsequent ruling providing information on the proceeding schedule and details regarding the oral argument hearing,” she said.

February 4, 2022December 20, 2023

Coalition Forms for Consumer Choice in Retail Energy Markets

Six independent power producers and electric retailers announced Thursday they have formed a new organization to promote renewable energy and lobby states for greater customer choice.

The Retail Energy Advancement League (REAL) said it will push for more consumer control over the purchase, production and consumption of electricity, data usage and energy services.

REAL spokesperson Kate Philips said the organization believes “customer empowerment can be a lever” for aiding the transition to a low-carbon power system. Philips said REAL’s set of principles include putting control of energy decisions in the hands of consumers and a belief that “advanced competitive retail energy markets” can aid in the “modernization” of energy markets.

The founding companies of the group are IPPs Calpine Energy, NRG Energy (NYSE: NRG) and Vistra (NYSE: VST) and green retailers CleanChoice Energy and IGS Energy. Retailer Constellation Energy (NASDAQ: CEG), which separated from Exelon this week, serves as a founding associate member.

“Americans deserve easily accessible energy choices that reflect their lifestyle goals and choices,” said NRG CEO Mauricio Gutierrez, chair of REAL. “It’s time to allow competitive energy markets to drive innovation and put the power in the hands of people.”

REAL’s Board of Director’s include Gutierrez, Vistra CEO Curt Morgan, CleanChoice Energy President and CEO Tom Matzzie, IGS Energy President and CEO Scott White and Calpine Energy President and CEO Jim Wood. Its first CEO is expected to be announced at the National Association of Regulatory Utility Commissioners’ Winter Policy Summit in Washington later this month.

Maryland, Pennsylvania, Arizona

The group says it believes “competitive retail suppliers should be the entities tasked with helping customers achieve their energy goals.”

Philips said companies are motivated more today to invest in clean energy solutions, and a market that “enables regulated utilities to focus on maintaining and improving the state’s power infrastructure” can promote investment in new technologies.

REAL plans on having a “strong presence” in state capitals across the country, Philips said, and wants to work with other groups with shared goals. REAL is already teaming up with the existing Choose Who You Use electricity consumer campaigns in Maryland, Pennsylvania and Arizona.

Philips said polls consistently say customers want choice in their energy decisions. She said REAL will look to make policy decisions “based on what’s best for our customers in states across the country.”

“We think the market works better when the satisfying the consumer is the driving incentive, and not just whatever monopolies can convince regulators to let them charge their monopoly customer base,” Philips said. “Whenever they are polled, people say they want choice — and do not understand why energy is the single sector where they don’t have it. Every state that offers customer choice, but has chosen to put limits on it, has a waiting list out the door.”

Listening to Consumers

REAL officials cited a 2018 survey by Consumers Union, publisher of Consumer Reports, that gauged consumers’ attitudes toward their utility companies.

The findings included customers agreeing with the statement “I want to be able to choose my electricity provider” by a 10-to-one margin, with 76% supporting increased use of renewable energy. The survey also found that an additional 48% of all Americans would be willing to pay $5 more per month to buy 100% renewable energy.

Travis Kavulla, vice president of regulation for NRG Energy, said in a Twitter thread on Thursday that there is “a lot of work to be done” to make sure customers that already have a choice in their energy provider are “educated and empowered” in knowing their options and finding ways to improve their options.

“In every other part of our society we empower individuals to make the decisions that are best for their families and their businesses,” Kavulla said. “The electric sector stands out like a sore thumb — even at a time when we are more and more relying on it to drive a transition.”

February 4, 2022February 9, 2024

GSA, DOD Gear up to Meet Biden’s 100% Clean Energy Goal

The U.S. government, which buys more than 9 TWh of electricity per year from competitive retail markets, issued a request for information Thursday in its first step toward ensuring all that power will be carbon-free by 2030.

President Joe Biden set that goal in December, with his executive order on federal sustainability and energy procurement (EO 14057). The order calls for each federal agency to “increase its percentage use of carbon pollution-free electricity, so that it constitutes 100% of facility electrical energy use on an annual basis, and seek to match use on an hourly basis to achieve 50 percent 24/7 carbon pollution-free electricity, by fiscal year 2030.” (See Biden Calls for Federal Procurement of 100% Clean Energy by 2030.)

The RFI is a joint effort by the General Services Administration and the Department of Defense and particularly seeks input from power providers and other stakeholders in the PJM, ERCOT, ISO-NE, MISO and NYISO markets. The deadline for submitting comments is March 7.

Annual targets for carbon-free electricity (CFE) procurement across these markets include:

A minimum of 100-250 GWh for each of the five RTOs and ISOs or
500-1,000 GWh for ERCOT and PJM or
more than 1,000 GWh for PJM only.

In a press release announcing the RFI, Federal Chief Sustainability Officer Andrew Mayock said that leveraging that kind of “scale and procurement power” will allow the Biden administration to “accelerate the development of America’s emerging clean tech industries,” create jobs and help American businesses compete in global markets.

The RFI guidelines use a broad definition of carbon-free electricity, ranging from solar, wind and geothermal to nuclear, “renewably sourced hydrogen” and fossil fuels with carbon capture and storage “that meets EPA requirements.”

But the guidelines clearly lean toward renewables and set high standards for potential projects. For example, the government would prefer carbon-free procurements that provide “new or previously underutilized generation sources” and that are located within a grid operator’s service territory. The expectation is that these procurements could spur 10 GW of new clean energy development across the country by 2030, the RFI says.

Further, to avoid any appearance of greenwashing, the RFI also requires new renewable projects to come with bundled renewable energy credits (RECs), indicating that the government wants to ensure the RECS are retired, rather than being sold to offset a utility’s or corporation’s carbon emissions.

The government expects the CFE procurements “to be integrated into existing electricity procurements in a phased approach over several years, through both the transition of existing retail supply contracts, and where appropriate, new power generation procurements,” the RFI says.

The GSA and DOD want to start phasing in contracts for clean power this year, with deliveries beginning in 2023.

Noting that the DOD is one of the largest electricity users in the U.S., Deputy Secretary of Defense Kathleen Hicks said the RFI will signal to the market the government’s intent to play a leading role in the energy transition. “It’s not just critical to addressing the threat of climate change, but also to our national security as we work to secure U.S. competitiveness in rapidly shifting global energy markets,” Hicks said.

24/7 Clean Power

The big question now is whether and how individual RTOs and ISOs will be able to meet the government’s goals. While ambitious, figures on current renewable generation and projected growth suggest the CFE procurement targets are achievable.

PJM generation by fuel source | Monitoring Analytics

According to figures from FERC, renewable energy represented 85.9% of new generation in the U.S. in the first 10 months of 2021, and the National Renewable Energy Laboratory has reported that interconnection queues across the country are backed up with 750 GW of wind, solar and storage projects.

Coming up with 250 GWh may not be a big stretch for ISO-NE, which at present supplies about 500 GWh to the federal government and had almost 19,500 GWh of renewables, including hydro, in its generation mix in 2021, 19% of its generation.

Similarly, at 7,500 GWH per year, PJM is the government’s top retail market power provider and, as of 2020, was producing more than 30,000 GWh from wind and solar. PJM is planning to change its rules for connecting new wind and solar projects to the grid so that shovel-ready projects will go to the head of the queue. The proposed changes would also streamline approval for projects that do not require a facilities study or any network upgrades. (See PJM PC/TEAC Briefs: Jan. 11, 2022.)

The bigger challenge may be meeting the executive order’s requirement that 50% of the power procured be able to match demand hour for hour around the clock. For example, the RFI guidelines do not include energy storage as part of annual calculations of 100% carbon-free energy but can be included as part of a portfolio of resources to meet the 24/7 power matching requirements.

February 4, 2022June 14, 2023

ERCOT’s Jones Works to Regain Texans’ Trust

One day at a time, one person at a time.

That is what it will take ERCOT to regain the trust of Texans scarred by last February’s disastrous winter storm, interim CEO Brad Jones told RTO Insider on Tuesday night.

To illustrate his point, Jones related his chance encounter with a woman following a town hall meeting in the Dallas suburb of Coppell. It was one of three dozen or so stops on his listening tour that eventually became a “blur,” but one of few he won’t soon forget.

He and another staffer were walking to their car in the parking lot, hoping they wouldn’t find their tires slashed. A woman then approached Jones and the staffer, who reacted warily.

“Living in Austin, I assumed she was going to ask us for money,” Jones recalled. “She grabbed both my hands and told me her story, what she had been through and how it had affected her family. I told her how important it was to us to ensure that doesn’t happen again.

“And then she said the most amazing, most Texan thing to say,” he said. “She said, ‘I will pray for everyone in ERCOT,’ and then she disappeared back into the darkness. Being true to my promise to that woman is why I’m here.”

Jones followed that up with a second story dating back to a conservation alert last summer, when ERCOT asked its consumers to reduce their energy usage to compensate for a drop in wind production amidst thermal maintenance outages.

Speaking from the grid operator’s operations center in Taylor, where he keeps a cot in his office, Jones said a buddy happened to be in town during the conservation alert and visiting his Austin home. The friend called his girlfriend in San Antonio to see how she was doing.

“She blasted back, ‘I’ll be a lot better when that [expletive] at ERCOT lets me turn up my air conditioning,’” Jones said. “I understand that frustration and anger. I also applaud that she believes it was a responsibility that every Texan should take on, to help other Texans.”

Of course, it will take more than prayers and Texans’ conservation measures for ERCOT to comfortably meet demand during the current winter storm. Nor do staff see this week as a test; they see it as normal business, Jones said.

“After listening to [customers’] stories, it makes it so much easier to discuss with them the improvements we’re making and to build confidence in what we’re trying to achieve,” Jones said. “One afternoon or evening in Midland is not going to change the people of Midland and rebuild their trust, but it’s a place to start, right? I’ve told them that in order for us to rebuild their trust, it’s not operating one winter well or five winters well. It’s 100 winters well, but we have to start somewhere.”

ERCOT Grid Conditions (ERCOT) Content.jpg

ERCOT’s operating reserves Thursday morning. | ERCOT

So far, so good. The grid operator’s December inspections of power plants found nearly complete compliance with the state’s new winter readiness regulations. Staff reported almost 7 GW of generation outages Thursday afternoon, below what staff say is normally 10 to 12 GW.

The grid operator’s conservative approach to the grid has resulted in more than 9 GW of reserves Thursday afternoon, thanks partially to wind resources’ overperformance. Wind was accounting for about 27% of the grid’s production during the middle of the day Thursday.

“The grid remains strong, reliable, and it is performing well in this winter weather event,” Public Utility Commission Chair Peter Lake said during a Thursday press conference.

ERCOT is currently expecting demand to peak around 73.5 GW Friday morning, which would exceed last year’s record winter peak of 69.2 GW before the load sheds began. Experts and academics have concluded demand could have reached 77 GW or higher last year, had the grid operator not been forced to cut load and compensate for the loss of about 50 GW of generation.

Local customer outages reached 70,000 at one point Thursday but had dropped to almost 37,000 as nightfall approached, according to PowerOutage.us. Texas Gov. Greg Abbott said 10,000 restoration crews are currently at work, with another 2,000 expecting from neighboring mutual assistance utilities.

Of more concern are natural gas supplies. As has been frequently noted, the state’s gas industry has not been required to winterize its facilities yet, something that is a year or two off. Bloomberg reported Thursday that 5% of the country’s gas production has been knocked offline by the freezing weather and that production declines will continue.

Jones has a plan there. Given the lack of transparency into the natural gas transportation system, he told the ERCOT Board of Directors last month that he wants to add a gas desk in the operations center to monitor gas availability or restrictions. (See ERCOT Preps for 2nd Cold Snap of Year.)

“That covers the biggest weakness we have,” Jones said, noting ISO-NE and NYISO already have similar desks. ERCOT first looked at the idea in 2015, but Jones thought it a wasted effort “because we’ll never get the information we need from the gas companies.”

However, with the new Texas Energy Reliability Council, power and gas representatives are in the same room for twice-weekly meetings, exchanging information and conversation.

“It’s really encouraging. I think we can fill that [information] gap,” Jones said.

February 3, 2022June 14, 2023

ERCOT Issues Watch as Winter Storm Nears

ERCOT issued a watch on Wednesday as cold weather began to tumble into the state, saying it is taking action ahead of an expected increase in demand to ensure grid reliability. The watch is effective through Sunday.

“We are ready for this storm. We will be prepared for this,” interim CEO Brad Jones said during a press conference Tuesday with other Texas officials, including Gov. Greg Abbott (R).

The grid operator’s weather forecasts indicate a “potential for significant frozen precipitation behind this week’s cold front,” Jones said in a statement.

The National Weather Service has issued a winter storming warning for Central Texas and a winter weather advisory for the rest as part of a 2,000-mile-long stretch of ice and snow that The Weather Channel has dubbed Winter Storm Landon. Temperatures are expected to be the lowest so far for the Lone Star State.

ERCOT currently expects demand to peak at 71.97 GW on Friday morning. That would break the record peak of 69.2 GW before the grid nearly collapsed during last February’s winter storm.

Jones said during the press conference that ERCOT expects to have about 86 GW of capacity to meet demand on Friday. The grid operator continues to operate conservatively, increasing operating reserves, bringing more generation online sooner if needed and procuring more ancillary services. It has also delayed generator maintenance and asked that units return from maintenance before the front hits.

Staff recently completed hundreds of winter-readiness inspections of generation, transmission and distribution facilities to check their compliance with new regulations. ERCOT said it found only three with deficiencies.

Greg Abbott (Office of the Texas Governor) Content.jpg

Texas Gov. Greg Abbott during Tuesday’s press conference, with PUC’s Peter Lake and ERCOT’s Brad Jones (left to right). (Office of the Texas Governor) | Office of the Texas Governor

“We feel very comfortable about their level of readiness,” Jones said.

Abbott, who is up for re-election and fending off primary challengers to his right, has said since November that the lights will stay on this winter, a promise echoed frequently by Peter Lake, his appointed chair of the Public Utility Commission.

On Tuesday, Abbott acknowledged that “no one can guarantee that there won’t be a ‘load-shed event.’” He went on to say that outages will likely be at the local level because of icing power lines and trees falling onto lines.

“But what we will work and strive to achieve — and what we’re prepared to achieve — is that the power’s going to stay on across the entire state,” Abbott said.

Jim Wright, chair of the state’s natural gas regulator, the Texas Railroad Commission, countered concerns that the industry remains a weak link by saying that inspections have found 98% of natural gas facilities have been winterized. He said the 10 to 12 GW of gas plant outages during an earlier cold snap “were not anything out of the normal.”

However, the Houston Chronicle reported that its review of the inspection reports indicated that only 41% of the oil and gas facilities had successfully tested their weatherized equipment or procedures.

Jones said ERCOT is already aware of gas restrictions affecting as much as 2.6 GW of energy production this week, primarily in the Dallas-Fort Worth area.

ERCOT issues a watch when extreme cold weather is imminent and expected to have a negative effect on its footprint.

The Texas grid operator previously issued an operating condition notice Jan. 27 and a notice of “extreme cold weather event with potential icing conditions” on Monday. (See ERCOT, SPP Prep for Latest Wintry Blast.)

SPP Declares Resource Advisory

SPP raised its initial cold weather advisory issued Monday to a resource advisory on Tuesday for its entire Eastern Interconnection footprint. The notice was effective Wednesday through Saturday.

The RTO declared the advisory because of outages, wind forecast uncertainty, cold weather and icing’s effects on generation resources. Resource advisories do not require conservation measures but do serve notice to utilities in the grid operator’s balancing authority that SPP may use greater unit commitment notification time frames. This includes committing the footprint’s long-lead resources to account for possible icing on wind units.

A spokesperson said SPP does not currently expect to progress to more extreme advisories or alerts at this time. “We are relying on our diverse fuel mix and coordinating closely with our members,” Meghan Sever said.

The National Weather Service is predicting up to a quarter-inch of ice and as much as 6 inches of snow in central Oklahoma. Flights out of the state are being canceled, and schools began closing on Wednesday.

Kansas and Missouri are also expected to see signification snow fall this week.

February 3, 2022January 18, 2024

Western EIM Nears $2B in Total Benefits

CAISO’s Western Energy Imbalance Market closed 2021 with yearly economic benefits that were more than double those of any prior year, bringing the market’s cumulative savings for its participants close to $2 billion since it launched in 2014.

“The Western EIM’s outstanding performance last year provides further tangible evidence of the value of broad regional market coordination,” CAISO CEO Elliot Mainzer said in a statement announcing the results.

The record figures were a product of extreme weather in the West, high natural gas prices and more entities joining the EIM, CAISO said.

The fourth-quarter results announced this week showed benefits of $204 million for the WEIM’s 15 participants, which span much of the Western Interconnection. That brought last year’s annual benefits to $739 million, far exceeding 2020’s previous record of $325 million. The record year swelled the market’s total benefits to $1.93 billion.

Much of last year’s benefits came in the third quarter, which by itself exceeded the total annual benefits of $297 million in 2019 and came close to 2020’s annual figure. The unprecedented savings of $301 million in Q3 2021 resulted from summer heat waves in California, the Desert Southwest and the Pacific Northwest that triggered high demand amid tight supply, pushing electricity prices higher.

Transfers between WEIM balancing authority areas (BAA) provide access to lower-cost supply in the 15-minute and real-time markets, saving many participants millions of dollars per quarter. The Balancing Authority of Northern California (BANC), for instance, accumulated $72.5 million in benefits in Q3, while CAISO saved $54 million.

Q4’s winners included CAISO, with $55.5 million in benefits, and PacifiCorp, which saw nearly $40 million in benefits.

A graph shows quarterly and cumulative benefits for WEIM participants since the market started in 2014. | CAISO

The WEIM provides a market for excess renewable resources such as wind and solar that would otherwise be curtailed.

The market saw its largest yearly expansion in 2021. New members that joined included the Los Angeles Department of Water and Power, Public Service Company of New Mexico, NorthWestern Energy, Turlock Irrigation District and BANC members Modesto Irrigation District, City of Redding and Western Area Power Administration-Sierra Nevada Region.

The expansion boosted benefits for all participants, the ISO said.

“The quarterly benefits have grown over time as a result of the participation of new BAAs, which results in benefits for both the individual BAA but also compounds the benefits to adjacent BAAs through additional transfers,” it said in its fourth-quarter report.

Defections, Delays

This week’s upbeat news for CAISO arrived days after three more Colorado utilities — Xcel Energy’s Public Service Company of Colorado, Platte River Power Authority and Black Hills Colorado Electric — said they had decided not to join the WEIM as previously planned and would instead join SPP’s Western Energy Imbalance Service, a smaller but growing competitor. (See Colorado Utilities Choose WEIS over WEIM.)

Colorado Springs Utility had announced last May it would join the WEIS instead of the WEIM. A month later, the other Colorado utilities paused their plans to join the WEIM to explore other options. The decision made Colorado the only state in the Western Interconnection without any active or planned WEIM participants.

The Bonneville Power Authority, which was scheduled to go live in the WEIM on March 2, said last week it would postpone joining until May 3 to address technical and training issues among its large base of generation and transmission customers, most of which are publicly owned utilities. (See BPA Postpones Western EIM Entry by 2 Months.)

Two other Pacific Northwest utilities, Avista and Tacoma Power, said BPA’s decision would not delay their market entry on March 2. Tucson Electric Power is also scheduled to join the WEIM this year. Next year’s planned entrants are Avangrid, El Paso Electric and the Western Area Power Administration’s Desert Southwest Region.

By next year, WEIM participants are expected to represent nearly 80% of load in the Western Interconnection.

CAISO is going through a stakeholder process to see if it can create an extended day-ahead market for the WEIM, further expanding the capabilities of the market.

February 3, 2022

MISO Begins Dynamic Line Ratings Work

MISO foresees a relatively easy shift to incorporate transmission owners’ dynamic line ratings but says it will have to settle on a weather forecasting method.

Operations manager Brian Kiefer said MISO’s real-time systems can comfortably host transmission lines’ varied ratings required under FERC Order 881.

“We’re in good shape there,” he told stakeholders during a Jan. 28 Reliability Subcommittee meeting.

Order 881 requires transmission providers to establish ambient-adjusted line ratings into transmission service and near-term markets. (See FERC Orders End to Static Tx Line Ratings.)

Kiefer said the commission’s requirement for 10 days of hourly forecasted ratings for short-term transmission requests will be new for the industry. Stakeholders asked whether TOs would have to furnish their own temperature forecasts or whether the RTO will provide that data to make ratings forecasts more uniform.

“We’re looking at what sort of data we can provide to our members to make implementation easier, and that includes weather data,” Kiefer said.

He said MISO will probably create a new ratings data interface for its TOs.

Reliability Subcommittee Chair Ray McCausland predicted that stakeholders will form a task team to assign responsibilities and hammer out compliance details.

Kiefer said he expects FERC will require dynamic line ratings be implemented by summer 2025. He said MISO will likely form a pilot project in the meantime to implement TOs’ temperature-adjusted ratings as they are finalized.

The grid operator has said “increasingly complex operating days require more complete understanding of equipment reliability” under emergency line ratings. MISO also said more than 60% of ratings for transmission facilities are “identical ratings across severity categories,” meaning some TOs’ normal and emergency ratings have the same values.

Multiple stakeholders have told the RTO that reliability should come first when applying dynamic transmission ratings. Stakeholders have also warned that raising ratings on one facility might have downstream impacts on other transmission facilities in the system.

Stacy Hebert, a TO representative, has also said that implementing ambient adjusted ratings sets is not a guarantee that a facility won’t bind.

Staff and TOs last year identified about 500 candidate facilities that have bound on congestion quarter-to-quarter. About 25% of those facilities are already in an ambient-adjusted ratings program.

MISO Independent Market Monitor David Patton has extolled the benefits of ambient adjusted transmission ratings several times in public stakeholder meetings. He has said the grid operator could realize several hundred million dollars in annual savings if TOs fully implemented the ratings.

He reported that MISO’s real-time congestion costs more than doubled from late 2020 to late 2021 as more transmission elements began binding year-over-year. Patton attributed the sharp increase to the costs of re-dispatching the system to manage constraints caused by high wind output and natural gas prices. Ambient adjusted ratings and a plan for grid reconfigurations could ease constraints, he said.

Patton has also rejected the idea that TOs can’t use dynamic ratings on transformers. Last year he asked that MISO examine individual transformers to see if they can handle ambient adjusted ratings. Some board members have observed that many of the system’s transformers are probably antiques.

MISO and its transmission owners have been working since late 2020 to establish more dynamic line ratings.

February 3, 2022January 18, 2024

Initial MTEP22 Portfolio has $3.3B in Costs

MISO’s first version of its 2022 Annual Transmission Plan (MTEP 22) portfolio and will cost $3.3 billion, staff said during the first of a series of subregional planning meetings this week.

The figure is a tick higher than 2021’s package, which slightly exceeded $3 billion and was approved by the Board of Directors in December. (See MISO Wraps Annual Transmission Package.)

The draft MTEP 22 spending breaks down to $611 million worth of baseline reliability projects, $172 million in generator interconnection projects, and $2.5 billion worth of “other” projects, the catch-all classification the RTO uses for projects that address either load growth, aging equipment or other reliability needs.

The grid operator will perform independent analyses through May on the project recommendations to determine whether it finds the same issues that transmission owners identified. Staff will meet with the TOs over any discrepancies.

In August, MISO will release a clearer picture of the recommendations. They will be updated through early December, when the board will take up the transmission planning package for consideration.

The RTO won’t conduct market congestion planning or special economic planning studies this year, leaving those assessments to its ongoing long-range transmission plan. That planning effort might produce its first project approvals for the Midwest in June. (See MISO Promises Long-range Tx Project Reveal Soon.)

“For this year, the economic planning is incorporated into the long-range transmission plan,” said Thompson Adu, transmission expansion planning senior manager.

Transmission planning is more important than it’s ever been in MISO, which has a packed generation interconnection queue comprised almost exclusively of renewable generation and battery storage.

The queue currently has 856 projects totaling 134.3 GW, about 10 GW higher than the system’s current summer peaks. Last fall, developers’ requests to join the system pushed the queue to a 153-GW high, crushing all previous records. (See MISO Warns Queue Won’t Stay at 150-GW High.)

The RTO’s Central region of Illinois, Indiana and northeastern Missouri is responsible for 52 GW of potential generation, much of it solar, spread across more than 300 active projects. Network upgrade costs for just the projects from the 2018 and 2019 cycles, excluding affected system upgrade costs, have been estimated at more than $2 billion.

“Especially in the Central [region], we see the largest number of solar, storage and hybrid projects,” MISO engineer Forrest Tingo said.

MISO South accounts for more than 200 active projects, representing 36.5 GW. The South’s 2020 cycle of generation requests faces $759 million of network upgrades before they can connect to the system.

Clean Grid Alliance’s Natalie McIntire asked whether the region is experiencing costly network upgrades comparable to those of the MISO West planning region, where upgrades come at too steep a cost for most generation developers to proceed. The West’s collection of generation hopefuls in the queue are currently burdened with almost $1.8 billion in estimated network upgrade costs.

Staff said the South’s upgrade costs are trending higher simply because of the number of projects.

Year’s First Expedited Requests Approved

MISO also recently authorized five expedited transmission project reviews in Arkansas, Louisiana, North Dakota and Kentucky.

Staff found no adverse impacts after studying two new substations in northeastern Arkansas and southwestern Louisiana.

Entergy Arkansas has requested to build the Sandy Bayou 500/230-kV substation along the existing Driver-to-Shelby 500-kV transmission line to serve up to 550 MW of new industrial load. The utility hopes to have the $91-million substation in service by June 2024 and said work should begin immediately outside of the MTEP 22 cycle. The substation will be located near the Arkansas-Tennessee border.

Asked whether the Arkansas project is connected to Memphis, Light, Gas and Water’s possible migration from the Tennessee Valley Authority to MISO, staff said no. (See Memphis Moves Closer to Breaking from TVA.)

Memphis recently received bids from more than 20 companies hoping to provide alternative energy sources to the city. Should the city become a MISO member, it would need new transmission links to the system.

The RTO will conduct its next board meeting in Memphis this March. The grid operator has historically held its spring Board Week in New Orleans, but staff said the city’s meeting venues are fully booked.

Southern Renewable Energy Association’s Simon Mahan noted during Tuesday’s South subregional planning meeting that the new substation will be situated near a possible long-range transmission line in MISO South. He asked whether the substation would supplant the need for long-range transmission in the region.

“It’s too early to say how it affects it,” MISO’s Bill Kenney responded.

Cleco’s request for the $15-million Cole substation on an existing 230 kV line in Louisiana drew less stakeholder interest. The utility said the project will address new industrial customers and is estimated to be in service by October 15.

The new substations will not be open to competitive bidding because they’re considered load-growth category projects.

MISO also recommended expediting two requests for transformer upgrades from American Transmission Co. in eastern North Dakota and from Michigan Public Power Agency in western Michigan. Both said load growth required that the projects begin ahead of the MTEP 22 cycle.

Staff will discuss its approvals based on its reliability analyses during the March Planning Advisory Committee meeting.

Kentucky utility Henderson Municipal Power and Light (HMPL) requested the fifth expedited project, a reroute of four 69-kV transmission lines in northwest Kentucky to make way for highway construction. The municipal utility expects the project to cost about $3.8 million.

MISO said HMPL plans to complete the project by the end of June, five months before MTEP 22 receives a vote before the board.

MISO engineer Andenet Leyew said during a Jan. 19 Central Technical Study Task Force meeting that staff didn’t uncover any adverse reliability impacts when analyzing the project. He said the RTO will allow the project to move ahead out of the usual annual cycle, though it will still be considered part of MTEP 22.