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February 4, 2021March 9, 2025

SPIDER Group Explores Options After SAR Rejection

The rejection by NERC’s Standards Committee of the standard authorization request (SAR) for Project 2020-01 (Modifications to MOD-032-1) in December has left the group that submitted the request in a quandary regarding the next step for the project.

Members of NERC’s System Planning Impacts for Distributed Energy Resources (SPIDER) Working Group expressed frustration and confusion over the rejection at their conference call Tuesday. The group submitted a draft SAR for Project 2020-01 to the Standards Committee in December 2019 with the goal of “[providing] clarity and consistency for data collection [of] aggregate demand and DER [distributed energy resource] data,” and the committee approved the project and the SAR drafting team the following March. (See “Approvals,” NERC Standards Committee Briefs: March 18, 2020.)

However, committee members put the brakes on the project in light of the team’s decision not to change the SAR in response to negative comments received during the informal comment period that ended last April. (See “SAR Rejected over Industry Comments,” NERC Standards Committee Briefs: Dec. 9, 2020.) In the official rejection letter, Standards Committee Chair Amy Casuscelli said that “based on the comments received … there is insufficient stakeholder support for this project, and continued revisions of the SAR would not be productive.”

Members Dispute Committee Explanation

This explanation did not sit well with SPIDER members, many of whom had trouble understanding the decision to end a project they considered important to the future of the grid over an apparent technicality.

“How did they come to that decision?” asked Bradley Marszalkowski, senior engineer at ISO-NE. “I would argue that the fact that the SPIDER Working Group — which is made up of a wide range of industry professionals from all over the country — is saying that the SAR is needed would indicate that there is industry support.”

Ryan Quint, NERC | NERC

Members of the SAR drafting team who participated in the call also reported feeling “disappointed” and surprised, given that the standard drafting process does not require a response to an informal comment period at all. The team had intended to address the concerns after the Standards Committee accepted the SAR and made it the official standard drafting team (SDT).

“To be honest, I was a bit surprised myself,” admitted NERC’s Chris Larson, who represented the SAR drafting team in December’s Standards Committee meeting. Larson called the rejection by the committee of a previously accepted SAR “pretty uncharacteristic”; normally, in his experience, the committee would remand a problematic SAR to the drafting team rather than rejecting it outright.

Leaders Fear Future Friction

Currently the working group’s leadership is in what Ryan Quint, NERC’s senior manager for grid security and transformation, called an “informal information gathering” mode while it explores its options regarding the SAR. This process includes conversations with Standards Committee members to discuss their issues with the drafting team and to see if they might be open to reopening the project, either with the same or a different team.

Chris Larson, NERC | NERC

Members offered additional suggestions on the call, such as expanding industry outreach to explore the objections to the SAR and see how to address them. Others said that the best way forward might be to make sure that SAR drafting teams are properly following up on industry comments, since the group “can’t do the SAR drafting team’s job for them.”

Quint suggested that members take up the baton of industry outreach themselves, pointing out that several of the committee members that voted to reject the SAR in December belonged to organizations represented on SPIDER. The fact that representatives from the same bodies apparently don’t see eye to eye could be a sign that the disconnect over 2020-01 is not an isolated incident.

“You have technical experts on the call here saying, ‘Yes, we need this,’ and the leaders in your organizations that sit on these very high-level committees voted against it,” Quint said. “That’s a problem for folks [in leadership] who have to stay in a semi-objective position … I don’t know how to deal with that, when you have one organization with a very strong ‘yes’ and a very strong ‘no’ at different levels.”

February 3, 2021

Energy Siting Tops Maine Environmental Policy Priorities

Solar and offshore wind energy siting will be among the environmental priorities the Maine legislature will address this year, according to Hannah Pingree, director of the state’s Office of Policy Innovation and the Future.

“The issues of solar siting and offshore wind have really heated up,” Pingree said during a Committee on Environment and Natural Resources (ENR) preview hosted by E2Tech on Tuesday. Electric vehicles also will be a top priority, she said.

Policy considerations for siting solar and OSW will focus on balancing technological expansion and the needs of local industry, such as fishing and farming.

“The significant expansion of solar projects in our state is exciting, but needs to be balanced, especially with ensuring that we preserve our best farmland,” she said.

Maine Environmental Policy — Lawmakers in Maine this year will be considering environmental legislation related to solar and offshore wind siting, electric vehicle adoption and landfills. | *Carol Boldt, CC BY-SA 4.0, via Wikimedia Commons*

The Maine Climate Council, which advises the governor and legislature on climate change, will continue its work from last year on an EV Roadmap, she added.

Maine’s climate plan “calls for, by 2030, a couple hundred thousand EVs to be on the road,” Pingree said. “That’s a tall order for our state, so there’s significant work to be done to plan for how to get these cars on the road.”

Pingree said the focus for OSW siting will be on ensuring any new development is planned for more than 20 miles offshore in federal waters. Gov. Janet Mills in late January announced that she will ask the legislature to approve a 10-year moratorium on new OSW projects in Maine-managed waters.

The governor’s administration is also working with the Bureau of Ocean Energy Management and environmental and fishing groups to identify the best place to site a floating OSW research array proposed for the Gulf of Maine, Pingree said.

Speaking during the committee session preview, ENR committee member and House Rep. Will Tuell (R) said he applauds the moratorium, and he is looking forward to supporting the interests of the fishing industry.

“Fishermen are still rather uneasy about offshore wind, where it’s going to be located and how effective that could be,” he said. “I’m interested in hearing a lot more … but we have to be mindful of the fishermen, and we have to remember that they were fishing the waters first.”

In a letter to fishermen announcing the proposed moratorium, Mills said “new commercial-scale offshore wind projects do not belong in state waters that support the majority of the state’s lobster fishing activity.”

Landfill Bills

State Rep. Ralph Tucker (D), who serves as ENR committee chair, said he anticipates the committee will have to handle about 79 different bills this session.

Among them, he said, “are a number of landfill bills.”

According to Tucker, there will be a “knockdown, drag-out fight” over out-of-state waste that is going to a state-owned landfill in central Maine.

He also said that recycling in the state is “in crisis.” Tucker anticipates a “big fight” over packaging stewardship, with dueling proposals.

One of the proposals, he said, would require packaging producers to contribute to the recycling of materials and reimburse towns. That bill, he added, is backed by the Natural Resources Council of Maine. The packaging stewardship policy approach supported by NRCM, according to its website, is called extended producer responsibility. The policy is designed to force manufacturers to take responsibility for recycling programs, which incentivizes them to design greener, safer packaging.

February 3, 2021

NY Munis Forge Way for Building Decarbonization

Some local-level sustainability leaders in New York state are making headway with the legal pathways that they believe will help decarbonize their buildings and meet emission-reduction targets.

The city of Ithaca expects to adopt an energy code supplement this spring that would require net-zero-carbon buildings and no fossil fuel use in buildings by 2030.

Speaking during a webinar hosted by New Yorkers for Clean Power on Thursday, Nick Goldsmith, sustainability coordinator for Ithaca, said the draft code offers both point-based and performance-based compliance for buildings.

The point-based option offers building developers a certain amount of flexibility by being fuel neutral. Developers must obtain six total points, with each point equating to an upgrade option that achieves up to a 10% emissions reduction. Installation of heat pumps for space heating, for example, would earn two to five points, while electric vehicle parking spaces would earn one to two points.

Ithaca’s draft code is open for public comment through Feb. 17.

New York Net Zero — New York towns and cities are looking at their local legal pathways for decarbonizing buildings within their jurisdictions. | *Shutterstock*

Amy Turner, senior fellow at Columbia Law School’s Sabin Center for Climate Change Law, said New York is in the early stages of understanding the legal pathways for municipalities to reach building decarbonization goals.

Changes to building codes are one of two pathways she cited as realistic options. The second option would be for municipalities to use “home rule/police powers,” which “allow cities and towns to regulate within their borders to protect the general welfare and manage their own affairs,” she said.

Berkeley, Calif., used police powers to become the first city in California to ban natural gas in new buildings. A similar approach in Brookline, Mass., however, was rejected by the attorney general because she “deemed the Brookline ordinance to be pre-empted by Massachusetts state laws,” Turner said.

The New York State Energy Conservation Construction Code is one of two building code options that cities and towns can employ, Turner said. Municipalities also can update the New York State Uniform Fire and Building Code, but that option presents a more difficult challenge than energy code updates. If a municipality wants to update a uniform code, she said, it must petition a statewide board and establish that there is a unique local circumstance that warrants the change.

Public Safety

Mark Thielking, director of energy and sustainability for Bedford, N.Y., said his town is looking at using police powers to improve emissions from buildings in its jurisdiction.

He said that the town has been working on building emissions for more than a decade, but voluntary action on transitioning to cleaner building technologies is “slow, expensive and not equitable.” (See Study: No Silver Bullet for Fossil-Climate Legal Tension.)

Bedford’s municipal leaders believe it’s possible to translate the legal foundation behind public benefits, such as safe sidewalks or clean drinking water, to cleaning up existing buildings. In those examples, “there was a harm that was happening in the public citizenry and that’s why a law was passed,” he said. “Now, we have a list of harms coming from buildings; GHG emissions or air pollution from burning home heating oil.”

The town’s own experience cleaning up its water supply is illustrative of how it could protect its citizens from building emissions and air pollution. Thielking said the town built a clean water plant to address contamination of its water supply. To do that, Bedford sought financial support from a state authority called the Environmental Facilities Corp. (EFC), which provides assistance to local governments to carry out public health and safety mandates.

EFC has issued $37 billion in water financing over the last 30 years, and Thielking believes such funding can help with clean building mandates.

“Clean drinking water is available to everybody; that is a right by local law,” he said. “Similarly, this high-performance building upgrade process would be available to every building as well. It’s not about credit quality, being wealthy or even owning your building.”

February 3, 2021

Virginia Grades Dominion IRP Incomplete

Virginia regulators have graded Dominion Energy’s proposed integrated resource plan as incomplete, saying the company must provide more information on how it will comply with the Virginia Clean Economy Act (VCEA) approved by lawmakers last year.

Dominion Energy Virginia filed the 2020 IRP on May 1, little more than two weeks after Gov. Ralph Northam signed the act into law. (See Va. 1st Southern State with 100% Clean Energy Target.)

The law requires Dominion to:

retire all carbon-emitting electric generation plants by the end of 2045;
participate in a renewable energy portfolio standard (RPS) program; and
seek commission approval by the end of 2035 to construct or acquire 16.1 GW of solar and onshore wind, 5.2 GW of offshore wind and 2.7 GW of energy storage.

Dominion Energy Virginia, which owns 27,100 MW of generation, has proposed building 2.6 GW of wind generation off the coast of Virginia and is about halfway through a plan to add 3,000 MW of solar generation. Its proposed IRP for 2021-2045 would quadruple the amount of solar and wind generation in its previous 15-year plan. (See Dominion Undecided on FRR Option.)

Dominion IRP — Dominion Energy solar farm in Louisa County, Va. | *Dominion Energy*

But that didn’t go far enough, the State Corporation Commission said in an order Monday (PUR-2020-00035).

“The commission recognizes that Dominion did not have an extended opportunity to conform its 2020 IRP to address all the interrelated aspects of recent legislation. The commission, however, cannot conclude, based on the record in this proceeding … that Dominion’s 2020 IRP, as filed, is reasonable and in the public interest for purposes of a planning document,” it said.

More Detail in Updates

The commission said the utility’s 2021 and 2022 updates to the plan must improve the modeling of alternative plans for complying with the VCEA and explain how its plan will address environmental justice issues.

The 2020 plan included four alternatives for complying with the act, but commission staff and other commenters challenged the company’s modeling and the reasonableness of the results. “With few exceptions, Dominion’s VCEA plans are substantially similar and do not model multiple paths to compliance with the VCEA,” the commission said.

It said Dominion would “substantially overbuild” the capacity it needs to meet peak load and energy requirements. One of the plans included capacity in excess of projected load of 1,800 MW in 2027, rising to 7,400 MW by 2045.

The VCEA plans also produced more renewable energy credits (RECs) than required by the RPS program. “Dominion’s modeling of the VCEA’s RPS Program requirements did not consider monetizing or banking excess RECs or model the RPS Program deficiency payments.”

Dominion did not update its forecasts of future energy, capacity and fuel prices to reflect the passage of the act, regulators said.

Several commenters, including Appalachian Voices and the Sierra Club, criticized the plan for modeling 970 MW of new natural gas-fired combustion turbines to be added between 2023 and 2024 in all VCEA plans. The company said the resources were “placeholders” to address potential reliability problems from the addition of large amounts of intermittent generation. “In the future, the company should also include one or more plans without such ‘placeholder’ additions to address reliability concerns for comparison purposes and to improve transparency in the company’s planning processes,” the commission said.

Appalachian Voices and the Natural Resources Defense Fund also criticized Dominion for not modeling any energy efficiency targets after 2025. The VCEA set EE targets through 2025 and directed the commission to set targets after that date. “The commission has not yet set the post-2025 energy efficiency targets,” regulators said. “We agree, however, that assuming those targets would be zero after 2025 was unreasonable and direct the company to continue to model energy efficiency targets after 2025.”

Staff, the Attorney General’s Division of Consumer Counsel and other commenters also faulted Dominion for not including a least-cost VCEA compliant plan.

Glen Besa, retired director of the Virginia chapter of the Sierra Club, took issue with Dominion’s inclusion of a 300-MW pumped storage facility, which he contends is uneconomic, while staff said the company included a second tranche of offshore wind not mandated by the act.

Environmental Justice, Bill Impacts

The commission noted that the 2020 plan was the first in which Dominion was expected to address environmental justice in its long-term planning. “In addition to addressing environmental justice in more specific contexts, such as requests for certificates of public convenience and necessity for particular facilities at known locations, the commission finds that the company should address environmental justice in future IRPs and updates, as appropriate,” it said. “As one example, the company may consider the impact of unit retirement decisions on environmental justice communities or fenceline communities.”

Regulators were also skeptical of Dominion’s analysis of its plan on customer bills. The company projected residential bills would increase by $52.40 and $55.02 per month by 2030. Commission staff said the utility understates likely increases because it projects that it will recover a declining percentage of its costs from the residential class over the next decade. Based on current allocation factors, staff estimated bills would rise by $64.27 to $67.32 monthly based on the company’s compliance with the act.

Commissioner Angela L. Navarro, who was appointed in December and confirmed last week, did not participate in the order.

Dominion spokesman Rayhan Daudani said the company “will carefully review the commission’s order and incorporate its direction in our next IRP filing. We appreciate the commission’s acknowledgement of the vital role electric reliability plays and look forward to working with our regulator to make our strong record of reliability even better.”

Commenters will have a chance to discuss the IRP on Feb. 12, when the commission will hold a public hearing at 10 a.m. on Dominion’s RPS plan (PUR-2020-00134). The deadline for registering to speak is Feb. 10.

February 3, 2021November 30, 2023

PG&E Cuts $1B Deal for Cell Sites on Transmission Towers

Pacific Gas and Electric said Tuesday it had agreed to sell rights to install wireless communications equipment on 700 transmission towers and other infrastructure for $973 million, plus future licensing revenues on 28,000 other towers and equipment that could bring in millions more per year.

The deal with a wholly owned subsidiary of SBA Communications will help PG&E recover from years of wildfires sparked by its equipment and its ensuing bankruptcy, which ended in June, the utility said in a statement.

“When we emerged from Chapter 11, we made a commitment to achieve financial stability and bolster our overall financial health and we’re delivering on that objective,” PG&E interim CFO Chris Foster said. “Strategically selling non-core assets like these is one way we’re continuing to follow through on that commitment, reduce our financing needs and strengthen our balance sheet.”

California’s largest utility paid fire victims and insurance companies tens of billions of dollars as part of its plan to exit bankruptcy, including giving fire victims a 22% stake in the company. (See PG&E Trying to Move Forward from Bankruptcy.)

The utility said the deal will help ratepayers and fire victims.

“PG&E estimates that approximately half of the net sale proceeds will be returned to electric transmission and distribution customers in the form of lower monthly bills,” it said. “Furthermore, the net transaction proceeds are expected to help partially offset future equity issuances and dilution of PG&E shares, a substantial portion of which are held by the fire victim trust established to compensate victims of 2015, 2017 and 2018 fires.”

The license agreement with SBA will be for 100 years, though PG&E will retain the right to terminate it for individual cell sites for regulatory or operational reasons, the company said. It also allows SBA to enter sublicensing agreements with wireless providers that attach equipment to transmission towers and other utility structures, giving PG&E a portion of those future revenues, the utility said.

“SBA will have the exclusive rights to sublicense and market potential additional attachment locations on approximately 28,000 of the utility’s other electric transmission towers to carriers for attachment of wireless communications equipment,” with licensing fees split between PG&E and SBA, the utility told the U.S. Securities and Exchange Commission in a filing Tuesday.

“PG&E is not selling any transmission towers as part of this transaction,” it said in its statement.

FERC and the California Public Utilities Commission have both approved the installation of wireless antennas on transmission towers as a secondary use, PG&E said.

SBA CEO Jeff Stoops said that with 5G networks expanding, the “transaction adds a significant portfolio of high-quality, exclusive locations to our outstanding existing U.S. macro tower portfolio, and SBA expects these assets to generate approximately $39.5 million in tower cash flow in their first full year in our portfolio.”

“We are also particularly pleased about the opportunity to work closely with PG&E over the coming years to maximize wireless deployments across their extensive network of transmission towers.”

February 3, 2021

Study: Biomass Better for Carbon Capture than Energy

Biomass is more valuable for its carbon-capture ability than for its energy production, according to a new global roadmap of strategies to achieve net-zero emissions by 2050.

The study released last month by the Innovation for Cool Earth Forum (ICEF), an annual gathering hosted by the government of Japan since 2004, proposes a new term, biomass carbon removal and storage (BiCRS), to supplant bioenergy with carbon capture and storage (BECCS).

“This topic has been part of the global dialogue on climate change in a number of ways for many years, and it sparks some controversy,” said David Sandalow, inaugural fellow at Columbia University’s Center on Global Energy Policy (CGEP) and chair of the ICEF roadmap project.

Nearly 500 people attended a virtual webinar Tuesday hosted by CGEP, moderated by Sandalow and featuring several authors of the report.

Biomass Carbon Capture — Comparison of the carbon-removal value of biomass with the energy content equivalent value of biomass for a range of carbon prices. | *ICEF*

New Tech

“BECCS is something that exists in models, but it doesn’t exist much in reality,” said Roger Aines, energy program chief scientist at Lawrence Livermore National Laboratory. “The number of total operating facilities is small around the world, and most of the ones that are moving a lot of CO₂ are basically ethanol plants that are catching CO₂ from fermentation.”

The existing knowledge base of converting biomass to energy is based upon a very small number of facilities, and most of them are actually computer simulations, he said.

“One of the big focuses of this report is that the value [of biomass] is in removing the carbon, and we should look at all the ways you can remove carbon,” Aines said.

Biochar — charcoal produced by burning biomass — is an already established method. A brand new concept, bioliquid production, uses pyrolysis to make oil, which is then directly injected underground, Aines said.

“If we’re trying to manage carbon on the planet, we need to make … benefits available to these kinds of technologies so that they can make money doing the jobs they want to do; we just need to add these technologies into the carbon systems that exist in the world today,” Aines said.

Julio Friedmann, CGEP senior research scholar, said policy could drive procurement of low-carbon steel.

“In thinking about the value of biomass, one of the things we spent a lot of time talking about was the idea of biocoke, meaning biomass-based substitutes for coking substances in primary steelmaking and ironworks,” Friedmann said. “That’s something that’s very hard to decarbonize, and biomass could be one of the few things that provides that optionality.”

Possible Harms

The controversy that Sandalow spoke of comes from concerns that using biomass for carbon sequestration harms food security, biodiversity and forests.

“That is absolutely the top thing we worried about when we wrote this report,” said Colin McCormick, adjunct professor at Georgetown University. “We wanted to say, ‘If this is going to happen, what controls are needed, what monitoring is needed, what knowledge is needed to avoid these bad outcomes?’ And you’ll note that a big part of the report is the policy recommendations.”

“The focus is on waste and residue biomass as ones that likely have zero to no impact on food prices or on biodiversity because they are typically byproducts of things that are already happening on the land,” said Daniel Sanchez, an environmental scientist at the University of California, Berkeley.

Counting One, Two, Three

A participant asked how composting compares as a way to store carbon.

“Composting doesn’t tend to be as long-term a source of carbon storage as something like biochar tends to be, but it also highlights something that we tried to emphasize here: that it has another great benefit in that it encourages other long-term carbon storage in soil,” Aines said. “As we think about BiCRS, we want to think about the net carbon for the entire process, and encouraging carbon in soil is a terrific benefit.”

“Composting is probably the No. 1 thing that farmers may really be doing in this country to begin to mitigate climate change,” said Cynthia Rosenzweig, senior research scientist at the NASA Goddard Institute. “It’s really important because it improves the fertility of the fields that it’s stored in.”

Issues with composting include determining the baseline for a farmer’s carbon in the soil, how to assign values to the amount of carbon stored, and to how much credit or monetary value is given to the farm, Rosenzweig said.

In doing carbon accounting, it’s important to differentiate among avoided carbon, reduced carbon and removed carbon, Friedmann said.

“Adding compost may allow you to avoid using fertilizers — that would be an avoidance — and it may be that using a bio-hydrogen can substitute for fossil hydrogen and get you a carbon reduction; but we really wanted to focus on the removal part, of the transfer of CO₂ from the air to the lock-up,” he said.

February 3, 2021

METC to Pay $125,000 for NERC Violations

FERC last week approved a settlement between ReliabilityFirst and ITC Holdings subsidiary Michigan Electric Transmission Company (METC) for violations of NERC reliability standards, along with a separate settlement between RF and Michigan Power (NP21-5).

The METC violation carries a $125,000 penalty, but no monetary damages were assessed for the Michigan Power infringement.

NERC submitted both settlements to FERC in a spreadsheet notice of penalty in December, which FERC indicated on Friday it would not review. In the same docket, NERC filed a separate spreadsheet NOP. The documents in that filing were not accessible, likely because it contains information on violations of NERC’s Critical Infrastructure Protection (CIP) standards, which are to be kept confidential in accordance with a policy agreed between FERC and NERC last year. (See FERC, NERC to End CIP Violation Disclosures.)

ITC Admits Facility Misratings

RF’s settlement with METC stems from a violation of FAC-008-1 (Facility Ratings Methodology). The issue was discovered by ITC Midwest (ITCM) via an internal control review in Jan. 2017, with METC filing a self-report to the regional entity on behalf of ITCM in July of that year.

METC NERC Violations — ITC Holdings’ headquarters in Novi, Mich. | *ITC Holdings*

During its internal review, ITCM discovered that a relay thermal limit in the Tiffin to Arnold 345-kV circuit “did not match the published equipment rating.” As a result, the facility rating had to be reduced at two locations. After finding the misrating, ITCM worked with METC and ITC’s other Michigan operating companies to conduct a root-cause analysis and an extent-of-condition review aimed at identifying “how ITCM and the Michigan groups calculated, considered and applied relay thermal limits” in ITC’s facility ratings database.

The review determined that the Michigan companies’ rating methodology did not account for relay thermal limits on transformers; only transmission lines were addressed. In addition, the methodology also did not include delta-connected current transformers, which were found to have contributed to the misrating of the relay thermal limit.

As a result, ITC committed to review all 254 substations in its footprint. The work was still underway at the time of the settlement, with completion expected by the end of 2021. As of August, the company had completed reviews of 184 substations; ratings changes have been required in about 7% of examined facilities.

Along with the ongoing review, ITC has already completed a number of additional measures, including updates to its facility ratings database and ratings methodology to account for relay thermal limits. RF considered these actions a mitigating factor in determining the penalty amount, in addition to the moderate risk posed by the violation and the fact that it was identified and reported before any harm occurred. On the other hand, the RE also noted that the company has a history of compliance issues under FAC-009-1 (Establish and Communicate Facility Ratings), which supports an increased penalty.

Because some of the affected facilities are in MRO’s footprint, the settlement amount will be divided between the two REs based on net energy for load in each region. NERC calculated MRO’s portion at $41,250.

Michigan Power Overlooks Voltage Changes

Michigan Power’s settlement arises from an infringement of VAR-002-4.1 (Generator Operation for Maintaining Network Voltage Schedules).

During a spot-check in December 2018, the utility discovered it had not maintained the reactive power schedule as required and had also failed to satisfy notification requirements since November 2017, the month the entity entered a reduced dispatch agreement (RDA) with Consumers Energy. Under the RDA the utility was required to reduce its output at the request of Consumers, which would notify it of required reductions at the beginning of each day.

Michigan Power performed the megawatt reduction according to schedule but neglected to “reduce the output of MVARs as needed to maintain the reactive power schedule.” As a result, the entity was found to have failed to maintain its voltage on 254 of the 284 occasions in question.

RF attributed the violation to “the entity’s lack of awareness of the constant output of MVARs to the grid” and a misunderstanding of the notification requirements in its contract with Consumers. However, the RE noted that Michigan Power is “inherently lower risk” because it has no record of misoperation and is not a black start resource, and that Consumers had not identified any system voltage issues caused by the violation. The utility has also committed to updating its operation requirements to ensure that MVAR is maintained during future adjustments. For these reasons, the entity elected not to apply a monetary penalty.

February 2, 2021

CAISO Advances Summer Readiness Plan

CAISO introduced a straw proposal Wednesday that aims to attract supply this summer and head off shortfalls like those that led to rolling blackouts in August and energy emergencies in September.

Propelled by those concerns, the ISO is moving ahead on its “market enhancements for summer 2021 readiness” stakeholder initiative at an unusually fast pace. It began advancing the measure in earnest in early January and scheduled it to be adopted by the Board of Governors in late March, with implementation scheduled for June 1.

The proposal took the form of a slide presentation only, not a written proposal as would normally be the case, because of time constraints. It is part of a series of fast-tracked measures being pursued by the ISO and the California Public Utilities Commission in anticipation of summer heat waves and capacity deficiencies as the state transitions from fossil fuels to renewables.

It and other measures are intended to address issues identified in a root-cause analysis of the summer shortages submitted to Gov. Gavin Newsom by CAISO, the CPUC and the state Energy Commission at Newsom’s request. It identified a variety of problems including transmission constraints, questionable exports from the ISO during tight supply conditions and market practices that undermined supply. (See Summer Readiness Sought by CAISO, CPUC.)

“This initiative’s goal is to prepare the CAISO’s operations and market ahead of this summer,” James Friedrich, market design policy specialist, said in his presentation. The “initiative is part of several measures to better access available supply, protect grid reliability and avoid rotating power outages during extreme heat waves. In addition to reliability, the CAISO has the responsibility to ensure its markets are operated efficiently, including mitigating market power and ensuring rational price formation.”

CAISO Summer Readiness Plan — | *Shutterstock*

The proposal deals with import incentives during tight load conditions, scarcity pricing enhancements and coordination with the interstate Western Energy Imbalance Market (EIM), among other changes. (See Western EIM Questions Performance in Shortfalls.)

For example, it proposes reviewing the performance of the ISO’s resource sufficiency evaluation (RSE) as part of its EIM participation. The re-evaluation would address defects identified in prior workshops such as accounting for resources that are derated as part of the capacity test and eliminating the double counting of mirror resources.

Two proposed enhancements seek to improve market incentives during times of tight supply. One would improve day-ahead market scheduling incentives, and a second would improve real-time incentives.

Another part of the straw proposal involves increasing the real-time market’s prices under certain conditions, including when the ISO issues a day-ahead market alert, or a warning or emergency in real time. The proposal would scale prices to the $2,000/MWh threshold established by FERC in Order 831. The order required ISOs and RTOs to raise the hard caps on supply bids from $1,000 to $2,000; offers over $1,000 require suppliers to justify their costs.

CAISO’s Market Surveillance Committee said in September that the ISO needs to consider implementing scarcity pricing to obtain energy during heat waves and supply shortages. (See CAISO Adds Scarcity Pricing to Policy ‘Roadmap’.)

Making sure storage resources are charged in strained conditions is another component of the straw proposal. Hundreds of megawatts of additional storage are scheduled to come online by this summer. A lack of storage for renewable resources last summer led to shortages when solar ramped down in the evening but demand from air conditioning remained high.

Comments on the straw proposal are due this Wednesday, with a final proposal expected by the end of the month.

February 2, 2021

Decommissioning Fund for Comanche Peak Tops $1.3B

The Texas Public Utility Commission last week approved a change to the decommissioning funds for Vistra Energy’s Comanche Peak Nuclear Power Plant.

During its Jan. 29 open meeting, the PUC signed off on an order that allows Vistra’s Luminant subsidiary to continue its annual decommissioning funding amount of $20.1 million for the plant’s two units. However, the order adjusts the funds’ allocation to 72.3% from 57.1% for Unit 1 and to 27.7% from 42.9% for Unit 2 (50945).

The net after-tax value of the units’ trusts total more than $1.3 billion, with nearly $624 million allocated for Unit 1 and $692.5 million for Unit 2. The plant said external and internal analyses indicates it will cost $1.729 billion to decommission and completely dismantle the facility in 2019 dollars, assuming a 10% contingency.

The commission said Comanche Peak “demonstrated that the funds in its nuclear decommissioning trusts are being invested prudently” and are following its investment guidelines.

Comanche Peak Decommissioning Fund — Comanche Peak Nuclear Power Plant | *The Nuclear Decommissioning Collaborative*

Unit 1, which began operating in 1990, is licensed until February 2030. The license for Unit 2, which opened three years later, expires in 2023.

While numerous nuclear plants have received extensions of their original 40-year licenses, others have been shut down as uneconomic, and five reactors totaling 5.1 GW of capacity — Indian Point 3 in New York, and Byron (two units) and Dresden (two units) in Illinois — are scheduled to close this year.

“Given Comanche Peak is one of the youngest plants in the country, significant decisions on license renewal are a few years away, but the plant is currently well positioned, and we have no plans to close it prematurely,” a Vistra spokesman told the Houston Chronicle in 2019.

Other Action

In other actions, the PUC approved a financing order that allows Entergy Texas to issue $539.9 million in transition bonds to recover hurricane-related costs (37247).

It also denied the city of Seymour’s request to overturn an administrative law judge’s December ruling allowing four people to intervene in its request for a declaratory order confirming that Tri-County Electric Cooperative has no grandfathered corridor rights for retail service within its city limits (49726).

Also last week, the commission announced it had promoted agency veteran Connie Corona to the new position of deputy executive director. She was previously the PUC’s chief program officer, guiding the market analysis, customer protection, infrastructure, rate regulation and legal divisions.

“Connie is a walking encyclopedia of industry knowledge who makes everyone around her more focused, productive and effective,” Executive Director Thomas Gleeson said. “We are truly fortunate to have her in such a critical role on our team.”

February 2, 2021

SPP Successfully Launches Western Market

SPP successfully launched its Western real-time balancing market at midnight Sunday, making it the first RTO with power markets in both the Western and Eastern Interconnections.

The RTO has said its Western Energy Imbalance Services (WEIS) market will lower wholesale electricity costs, increase price transparency and mitigate congestion for its participants. The market joins the reliability coordinator services SPP has been offering 12 entities in seven states since 2019; the grid operator will expand its RC function in April. (See SPP Expands its Western RC Footprint.)

“This will be a historic moment for SPP to launch this market … on time, and under budget,” CEO Barbara Sugg told stakeholders last week.

SPP Western Market — SPP celebrated its WEIS market launch Monday. | *SPP*

The WEIS market centrally dispatches energy from the region’s participating resources every five minutes. It is contract-based and does not require its participants to be SPP members. However, most of its participants have since indicated they are committed to evaluating becoming RTO members. (See Western Utilities Eye RTO Membership in SPP.)

WEIS market participants include:

Basin Electric Power Cooperative
Deseret Power Electric Cooperative
Municipal Energy Agency of Nebraska
Tri-State Generation and Transmission Association
Western Area Power Administration (WAPA)
Wyoming Municipal Power Agency

WAPA’s agreement includes the firm loads and resources of Pick-Sloan Missouri Basin Program–Eastern Division in the Upper Great Plains Western Area balancing authority footprint, the Loveland Area Projects and Salt Lake City Area Integrated Projects in the Western Area Colorado Missouri balancing authority footprint.

“Our electricity markets have played a big role in lowering costs, integrating renewables and enhancing reliability in the East, and we’re excited to see a new part of the country begin to see similar benefits,” Sugg said in a statement. “I’m hopeful this is just the beginning of valuable partnerships between SPP and western utilities that will help them and the customers they serve meet their financial, reliability and renewable-energy goals.”

SPP has long eyed expansion into the Western Interconnection. It explored a relationship with the Mountain West Transmission Group several years ago, but the effort was scuttled by Xcel Energy’s decision to join CAISO’s Energy Imbalance Market.

The RTO became the Western Interconnection Unscheduled Flow Mitigation Plan’s administrator in 2018 and it has been hired by the Northwest Power Pool to develop its regional resource adequacy program. (See NWPP Program Taking Shape for Q3 Launch.)