Page 971 – RTO Insider

March 2, 2021

PJM Black Start Rules Inch Closer to Final Approval

PJM stakeholders narrowly endorsed a compromise proposal to settle the contentious black start unit issue at last week’s Markets and Reliability Committee meeting.

In a sector-weighted vote of 3.35 (67%), members endorsed a proposal originally put forward by PJM addressing black start unit involuntary termination, substitution rules, capital recovery factor (CRF) and minimum tank suction level (MTSL). The proposal now moves on to the Members Committee for final endorsement at its March 29 meeting.

At the January MRC, PJM’s alternative option 1 proposal failed with a sector-weighted vote of 2.48 (49.6%), while Dominion Energy’s alternate proposal also failed with 2.47 (49.4%), leaving the black start issue in limbo for a month as stakeholders attempted to find a compromise. (See “Black Start Packages Rejected,” PJM MRC/MC Briefs: Jan. 27, 2021.)

Susan Bruce, counsel to the PJM Industrial Customer Coalition (ICC), and Sharon Midgley of Exelon worked together after last month’s MRC on a compromise amendment PJM’s original proposal, which they asked stakeholders to endorse.

Bruce said the compromise proposal has a different “term of commitment” for black start resources: the “life of unit.” PJM’s option 1 had a commitment period of 20 years or greater if the unit offers more in the request-for-proposal process. The Dominion proposal had a commitment of the capital recovery period plus three years of a five-, 10-, 15- and 20-year period based on unit age at the time it entered black start service.

CRF Debated

PJM proposed future updates to CRF to be calculated at the time of the black start unit’s in-service date. The CRF would be calculated using depreciation as applicable under the tax code changes in the Tax Cuts and Jobs Act of 2017.

The CRF issue emerged as the most disputed portion of the black start unit discussions, with stakeholders voting to amend the issue charge at the OC in December to align with language in the problem statement after it was discovered the two documents did not match. (See Vote on PJM Black Start Compensation Deferred.)

Stakeholders are still working through the updates to the CRF table at the Market Implementation Committee, with tariff revisions scheduled to be voted on at its March 10 meeting. (See “Capital Recovery Factors Discussion,” PJM MIC Briefs: Feb. 10, 2021.)

Bruce said black start discussions became “a thorny issue” among PJM members after the issue charge was first endorsed at the Operating Committee meeting last May. (See “Black Start Issue Charge Endorsed,” PJM Operating Committee Briefs: May 14, 2020.)

Constructive conversations between stakeholders over the last month helped to get members in a place where a compromise proposal was possible and to “get the rules of the road correct” to fix issues in the tariff regarding black start, Bruce said.

“It started out as a cleanup endeavor, and it’s really warped into something quite different,” Bruce said.

Stakeholder Opinions

Midgley thanked the ICC and the public advocate stakeholders for their discussions and work to find compromises.

“We really do think this is a good compromise option and appreciate the efforts leading up to this point,” Midgley said.

Paul Sotkiewicz of E-Cubed Policy Associates thanked Bruce and Midgley. He said he had several conversations early in the stakeholder process with the ICC to find solutions, and while one wasn’t initially found, he appreciated that the group was willing to listen to the concerns of generation owners.

Sotkiewicz previously challenged the stakeholder process over the black start issue, but he said the compromise proposal is “workable for everybody.” (See Gen Owners Balk at Change to PJM Black Start Rates.)

“While it’s not our most desirable proposal, it does give us certainty going forward about what we’re all facing,” he said.

Alternative Proposal Pulled

Greg Poulos, executive director of the Consumer Advocates of the PJM States, was set to introduce an alternative proposal addressing the black start issue on behalf of the Delaware Division of the Public Advocate. The proposal, which was first raised at the January MRC, included the addition of language regarding CRF from the Independent Market Monitor’s proposal that failed at the OC. (See “Alternative Black Start Package,” PJM MRC/MC Briefs: Jan. 27, 2021.)

Poulos said that after receiving input from other stakeholders and PJM officials over the last month, it became clear the proposal did not have enough support to be endorsed. Poulos requested that it be pulled from the agenda before it faced a vote, saying the advocates decided to remove it from consideration after the ICC/Exelon compromise was put on the agenda.

Sotkiewicz said he applauded Poulos’s decision to pull the advocate proposal from the agenda, saying it “took an incredible amount of courage” to make the call and showed a good-faith effort by the advocates to work within the stakeholder process.

“At the end of the day, we’re getting to a place where we can find some common ground,” Sotkiewicz said.

March 2, 2021

PUCT’s Walker Steps Down from Commission

Under heavy fire from state politicians over her response to the massive Texas blackouts of Feb. 15-19, DeAnn Walker resigned as the chair of Texas’ Public Utility Commission late Monday afternoon.

In a 15-word press release, the PUC said the resignation was effective immediately. Her picture has been removed from the website.

Walker was subjected to sometimes harsh questioning during 7½ hours of testimony last week before the State Legislature. Afterward, more than a dozen lawmakers called for her resignation. (See “Legislators Focus on PUC’s Walker,” Texas Lawmakers Dig into Power Outages.)

Lt. Gov. Dan Patrick joined the chorus Monday, issuing a lengthy statement calling for Walker’s resignation and that of ERCOT CEO Bill Magness.

“Immediately following the storm, I pledged to the people of Texas that I would get to the bottom of the crippling power outages that began on Feb. 15, leading to tragic loss of life and billions in damages to homes and infrastructure across the state,” Patrick said.

He said he did not make the resignation calls lightly, saying that neither Walker nor Magness “adequately addressed the challenges” of a storm and freezing temperatures that took off half of the grid’s available generation at one point.

“These are two good people who have worked very hard. ERCOT’s job is to manage our electricity grid, and the PUC oversees ERCOT. The lack of adequate preparation by both the ERCOT CEO and the PUC chair prior to the storm, their failure to plan for the worst-case scenario and their failure to communicate in a timely manner dictates they are not the ones to oversee the reforms needed.”

DeAnn Walker testifies before the Texas Senate on Feb. 25. | *Texas Senate*

ERCOT acknowledged Patrick’s comments, saying the corporate secretary will work with what’s left of the Board of Directors “to consider the request.”

“Mr. Magness will continue to work with the Texas Legislature and any state agencies on investigations of the recent winter storm and its reform of ERCOT,” spokesperson Leslie Sopko said in a statement.

The ERCOT board is now down to seven members following the resignations of eight members before Walker’s. Under Texas law, the PUC chair is accorded a non-voting seat on the board. (See “ERCOT Board Loses 2 More Directors,” Texas Lawmakers Dig into Power Outages.)

In a resignation letter hand-delivered to Texas Gov. Greg Abbott, Walker said she believed stepping down “to be in the best interest of the state.”

“I testified last Thursday in the Senate and House and accepted my role in the situation,” she said, calling on others —the gas companies, the Railroad Commissioner, the electric generators, the transmission and distribution utilities, the electric cooperatives, the municipally owned utilities, ERCOT “and finally the Legislature” — to “come forward in dignity and duty and acknowledge how their actions or inactions contributed to the situation.”

Referring to the lack of action since less severe winter weather knocked out 14 GW of generation in 2011, she chided those named, saying they “had the responsibility to foresee what could have happened and failed to take the necessary steps for the past 10 years to address the issues that each of them could have addressed.”

Walker was appointed to the PUC as its chair in 2017 by Texas Gov. Greg Abbott. Her term was to expire in September.

She spent 15 years at CenterPoint Energy as director of regulatory affairs and associate general counsel before joining Abbott’s staff to advise him on regulated industries. Walker was also an assistant general counsel and an administrative law judge at the PUC from 1988 to 1997.

Commissioners Arthur D’Andrea and Shelly Botkin remain on the PUC.

March 2, 2021October 21, 2025

Counterflow: Winter Ain’t Over Yet

To paraphrase Jack Palance in City Slickers, winter ain’t over yet.

Weather Underground says March is the craziest weather month.[1]

Judging from the pair of marathon two-day hearings before the Texas House and Senate, the Texas tragedy has infinite complexities for everything connected to our industry.

But for now, I’d like to focus on the very short term — what lessons we might learn to give us actionable intel for the rest of the winter.[2] Not just for Texas, but for our industry everywhere.

1. Electric-gas interdependence. We now know that much of the loss of gas supply to gas generators was due to the blackout of electric supply to gas infrastructure.[3] This caused the vicious cycle of blackouts causing loss of gas supply to generators, causing more blackouts.

Oncor, the largest electric utility in Texas, said that before the storm it had a list of 35 critical gas facilities to protect from load shed. During the storm another 168 (not a typo) critical gas facilities were identified.

Texas outages — Jack Palance (grinning): Day ain’t over yet. | *Columbia Pictures*

So here’s the proactive measure that NERC, the Edison Electric Institute, the Natural Gas Supply Association and the Interstate Natural Gas Association of America can do on an emergency basis: Make sure that every electric utility knows the critical gas facilities in its service territory.

2. Water infrastructure. Ditto on this. Every electric utility should know the water treatment plants and other critical water infrastructure in its service territory.

3. Communications. The lack of timely, accurate information was a huge problem. Not only lack of communications but inaccurate information such as customers being told that there were rolling blackouts and they could expect service to return from time to time. So many of these customers chose to stay put instead of staying with relatives, friends, etc. And of course, during blackouts there is a huge question of how to get information to customers.

Every electric utility should be asking itself: During an emergency, how do we get timely and accurate information to mass media, to regulators, to elected officials and directly to customers? If the blackout has taken the ISP or home wi-fi down, what about text messages to the customer phone number on file?

4. Black-start units. We know that about half of ERCOT black-start units were out (same as in 2011, by the way). Whatever the reason — maybe diesel fuel freeze, maybe lack of proper maintenance, maybe gas supply was cut — this has got to be addressed. BTW there were references to basically the end of days if the grid had gone down and a black start would be necessary. That is hyperbole — as long as black-start units actually perform as they’re well paid to do.

5. Scheduled, maintenance, planned outages. Whatever the term, every electric utility should be monitoring these like a hawk during winter (and summer) months. Under no circumstances should the allowed megawatts exceed the megawatts assumed in the reliability model for the upcoming winter or summer. That is a recipe for disaster.

We’re all trying to deal with this in real time and I would greatly appreciate input on what I’ve got wrong and what I’ve left out. Thank you.

[1] https://www.wunderground.com/cat6/March-Weather-Madness-Most-Extreme-Month-Year.

[2] For the longer-term study, I hope FERC has a Word version of its August 2011 report because it could mostly just repeat that report in terms of what went wrong, recommendations, etc., this time around. The song remains the same.

[3] Kudos to Bloomberg reporters for flagging this long before the hearings. https://finance.yahoo.com/news/giant-flaw-texas-blackouts-cut-005229826.html#:~:text=(Bloomberg)%20%2D%2D%20When%20the%20Texas,to%20hospitals%20and%20nursing%20homes.

4. BTW, Twitter doesn’t count as effective customer communication. Only 0.4% of customers in the ERCOT footprint follow Twitter, and only 0.5% of customers in the Oncor footprint do.

March 2, 2021January 28, 2024

Revised Stakeholder Amendments on ORTPs Gain Support

When Congress passed the Energy Act of 2020 in December, the bill included a two-year extension of the 26% investment tax credit (ITC) used by solar power generators, a one-year continuation for the production tax credit (PTC) used by wind developers and a new 30% ITC for offshore wind projects that begin construction by the end of 2025. (See Wind, Solar, EE, CO2 Storage Win Tax Breaks.)

That legislative action brought ISO-NE and stakeholders back before the NEPOOL Markets Committee last week to discuss and vote on amendments that focused on offer review trigger prices (ORTPs), used for Forward Capacity Market (FCM) parameters for the 2025/26 capacity commitment period, to accommodate the changes.

No Support for ISO-NE Proposal

ISO-NE’s proposal, done in concert with consultants Concentric Energy Advisors (CEA) and Mott MacDonald (MM), would create two new ORTP categories: solar, and solar plus lithium-ion batteries. Tariff revisions would include ORTP values of $0/kW-month for solar and $6.964 for solar-batteries, down from its originally proposed $9.371. Another tariff revision would clarify that the weighted-average calculation is used only when an ORTP for the combination of technology types is not specified. New tariff language also detailed the values for solar-batteries in future Forward Capacity Auctions.

“In developing these ORTPs, [ISO-NE] has been responsive to stakeholder feedback and has revised its proposed ORTP for the combined solar-battery technology type to reflect the decoupled operation of the facility after five years, when the ITC benefit expires,” Deborah Cooke, ISO-NE’s principal analyst for market development, wrote in a memo.

The RTO’s responsiveness did not carry much weight when it came to the sector-weighted vote. The proposal did not garner any support.

Stakeholder Amendments Favored

Abigail Krich and Alex Worsley of Boreas Renewables presented three proposals regarding ORTP values for FCA 16, annual ORTP updates for FCA 17-18 and maintaining existing treatment of ORTP determinations for resources with a shared point of interconnection for FCA 16.

The first proposal would, like ISO-NE’s, change the ORTP for solar to $0. The second proposal said that if the tax law remains unchanged for solar developers, it would result in an ITC assumption of 26% for FCA 17 and 22% for FCA 18. Should the law change again in the next two years, it would be reflected in the final assumption used for the FCA 17-18 updates.

All three amendments passed with at least 73% support from stakeholders. The Participants Committee will vote on all proposals during its meeting Thursday. A filing at FERC is expected by the end of March.

IMM Memo

ISO-NE’s Internal Market Monitor said in a memo to the MC that the RTO will file a proposal for ORTP values under Section 205 of the Federal Power Act, “which will include a ‘jump ball’ alternate proposal of ORTP values from NEPOOL.” The Monitor added that ISO-NE would request FERC’s decision by May. Participants must submit retirement delist bids, permanent delist bids and test prices to the Monitor for FCA 16 by March 12.

“After reviewing these submissions, the IMM will issue its determinations on June 3,” the IMM wrote. “Given the close timing of the IMM determinations and the expected FERC order, there is insufficient time for participants to update their bids and for the IMM to perform additional review after issuance of the FERC order.”

The Monitor said participants would have two options for submitting delist bids and prices, and “as a threshold matter,” it assumes FERC will either:

approve the RTO-proposed ORTP values;
approve the NEPOOL-proposed ORTP values; or
rejects the jump ball filing.

According to the Monitor, the three scenarios pose disparate risks for participants submitting delist bids and prices. “Depending on the ORTP values approved by FERC, participants’ expectations of the supply mix may change and, in turn, the change in supply mix may affect future capacity market prices and even future energy market prices.”

Participants can select one of two options for reflecting these risks in their bids and test price submissions. The first option is submitting one bid and supporting documentation that demonstrates one of the assumptions. The second option is that a participant submits one bid and all supporting documentation, reflecting the risks of the multiple possible outcomes. Pricing risk into one bid price is the Monitor’s preferred approach, as each year there is some uncertainty and regulatory risk associated with submitting bids well in advance of the auction.

March 2, 2021

CAISO Readies RA Enhancements for Summer

A stakeholder initiative to help ensure resource adequacy this summer is headed to the CAISO Board of Governors later this month with the goal of implementing its first phase of measures by June 1.

The initiative, which began in 2018 but was fast-tracked last year, proposes RA enhancements to avoid shortfalls like those California experienced in August and September, when energy emergencies and rolling blackouts highlighted weaknesses in the state’s RA planning and procurement.

A key proposal requires generators to find substitute resources during planned outages. Another part of the plan seeks to make sure storage batteries can serve as RA resources during times of strained supply. A third would expand CAISO’s backstop procurement authority to local areas that are resource insufficient.

“The objective of this ongoing effort is to ensure the CAISO’s resource adequacy rules and tools remain relevant and guide the procurement of capacity that can reliably and sustainably support the rapidly evolving needs of the grid all hours of the year,” a final written proposal said.

CAISO staff and stakeholders discussed the proposal during a call Feb. 23. The board will vote on the plan at its March 24-25 meeting.

The planned outage component “will require all planned outages for RA resources to bring full substitute capacity for the outage to be approved,” Karl Meeusen, senior adviser for infrastructure and regulatory policy, said in the session.

“We considered whether or not to have some sort of ‘hey, you got close enough’ standard,” he said. “However … because we have shaped monthly RA requirements,” CAISO decided that replacing 100% of the capacity on planned outages would better ensure “that the month-by-month RA obligations and requirements continue to be fulfilled on an everyday basis.”

A root-cause analysis of the Aug. 14-15 rolling blackouts found CAISO had 514 MW of planned outages that were not replaced on Aug. 14 and 421 MW of planned outages that were not replaced on Aug. 15. (See CAISO Issues Final Report on August Blackouts.)

CAISO Resource Adequacy — Red and white striped areas indicate planned outages that weren’t replaced Aug. 14-15, days when CAISO ordered rolling blackouts. | *CAISO*

Of those, “the largest planned outage [of a natural gas plant] had been approved for maintenance in June but had extended into peak summer months without providing replacement capacity,” the root-cause report said. “This outage was effectively a forced outage because the resource could not come back online even if the CAISO’s [restricted maintenance operations] notification would have canceled the planned outage.”

Under the plan, extensions of planned outages would be treated as separate outages and would also require substitute capacity.

Stakeholders generally opposed the planned outage substitution requirement, Meeusen said. Some said there is sufficient excess non-RA capacity, and substitution is not needed. Others contended there is not enough substitute capacity available.

Meeusen responded to the arguments.

“The presence of non-RA or the lack of substitute capacity should not relieve an RA resource of its obligation to be available to the ISO,” he said. “You have sold a product and service … to be available to the ISO’s market. That’s what [you are] being paid for. If you can’t do that, then what are the ramifications? Our proposal simply says that if you can’t do that, you find somebody that can.”

A lack of substitute capacity means a generator waited too long to contract for it or that resources are badly needed — a bad time to take planned outages, he said.

Meeusen emphasized that the first phase of the plan is likely a temporary solution for this summer, while a second more-permanent phase, with additional RA proposals, will go before the Board of Governors in the second and third quarters of 2021. A final draft of that proposal is due April 21.

A second fast-tracked summer 2021 initiative also is heading to the Board of Governors on March 24-25. It proposes changes to CAISO market rules meant to avoid shortfalls. (See CAISO Speeds Rule Changes to Avoid Shortfalls.)

Making Sure Storage Works

A lack of storage for renewable resources contributed to last summer’s shortfalls during severe Western heat waves in mid-August and during Labor Day weekend. That led to emergencies in the net-peak hour, when solar ramped down but demand remained high in the early evenings. Having more storage resources that are charged and ready for emergencies would help, CAISO and the California Public Utilities Commission (CPUC) said.

The CPUC ordered utilities to procure at least 3,300 MW of additional capacity this year, most of it storage. The ISO is expecting 1,800 MW of storage capacity to come online by Aug. 1, adding to the current 550 MW of dispatchable storage on its system.

“Increased levels of energy storage necessitate assurance of a minimum level of stored energy available during the net load evening peak to meet operational needs,” the proposal said. The plan’s primary requirement is that storage resources have a minimum state of charge (MSOC) to serve summer peaks and net peaks under strained conditions.

Gabe Murtaugh, lead policy developer at CAISO, said that with the expected retirements of aging natural gas plants in the next few years, “it’s absolutely going to be necessary that we have a few thousand megawatts of [additional] storage generation, and … it’s also critical that we get those few thousand megawatts of storage generation charged” before they are needed.

The MSOC plan also proved controversial among CAISO stakeholders. In response to their concerns, the ISO made several changes including applying the MSOC only on days when system conditions are very tight and only applying it to RA storage resources.

CAISO does not intend MSOC as a permanent fix; it intends to ask FERC to authorize its use of two years, Murtaugh said in his presentation. At the same time, the ISO is planning to launch a new stakeholder initiative focusing on energy storage enhancements to develop a long-term means for ensuring there is sufficient storage to meet high summer demand, he said.

Local Backstop Procurement

CAISO is also proposing to expand its statewide backstop procurement authority to local areas and sub-areas that are resource deficient. The third element in the RA plan was the least controversial, the ISO said in its final proposal.

“While most parties did not comment on this element in the draft final proposal, of the nine entities that did offer comments, a majority of commenters supported this policy as a common-sense expansion of the CAISO’s backstop authority to ensure local reliability needs in the face of increased reliance on availability limited resources,” the paper said.

Supporters included CalCCA, which represents the state’s community choice aggregators and resisted an earlier CPUC proposal to name Pacific Gas and Electric and Southern California Edison as central procurers for load-serving entities (LSEs) in their jurisdictions, including CCA’s.

Regarding the ISO’s local backstop plan, “CPUC Energy Division staff were … supportive as long as the local-capacity-requirement technical studies clearly identify what use limitations exist in each local area and sub-area so that LSEs and the new central procurement entity could utilize this information to direct procurement upfront,” the proposal said.

CAISO said it would be best to make its criteria clear.

“The CAISO will continue to outline the requirements for all applicable local areas and sub-areas, and these will be clearly described in the LCR reports by charts and graphs with the energy needs during peak as well as year-round conditions, before LSE procurement begins,” it said. “These graphs will also show transmission capability during emergency conditions for the applicable local areas and sub-areas.”

March 2, 2021

States Seek More Input, Visibility into ISO-NE Governance

The latest in a series of state official-led online technical forums to discuss ISO-NE’s governance issues publicly on Thursday focused on transparency in the RTO’s decision-making.

Anne George, vice president of external relations and corporate communications at ISO-NE, said the RTO has “a strong tradition of outreach and engagement with the New England states, as well as NEPOOL stakeholders.”

Katie Dykes, commissioner of Connecticut’s Department of Energy and Environmental Protection, acknowledged that the RTO does “a terrific job of providing responsive and professional outreach to all the states.” She added, however, that there is a difference between the outreach George referenced and the “opportunity for dialogue and real transparency with respect to insights and visibility into how the actions and decisions of the executive team and the ISO New England board are actually taken.”

ISO-NE Governance — The current governance structure of ISO-NE | *ISO-NE*

Neither ISO-NE Board of Directors nor NEPOOL stakeholder meetings are open to the public. According to the vision statement from the New England States Committee on Electricity (NESCOE), which spurred the forums, states and stakeholders only see “exceptionally high-level summaries of board discussions provided by ISO-NE management.” The result is “an unacceptable constraint on facilitating independent insight and review by stakeholders about what data, material and other resources the board consider in developing its guidance to management and how it balances divergent interests in their decision-making.” (See “‘Lack of Transparency’ Criticized,” States Demand ‘Central Role’ in ISO-NE Market Design.)

George said she did not want to speak for the RTO’s board but signaled that its members are not blind to current events.

“The point is that [board members] heard you all through the vision statement, and they’re willing to have those conversations,” George said.

Another conversation centers on the makeup of ISO-NE’s Joint Nominating Committee, which selects the RTO’s board members. The committee comprises seven incumbent board members, six market participants — one from each of NEPOOL’s sectors — and only one shared vote for the six New England states.

Dykes said the concept of a shared vote between “six sovereign states” creates barriers and challenges to meaningful participation in the board selection process. She asked George if the process would be “enhanced” if each state had a vote.

“All the states kind of understand what their representative is going into the process to convey; I think that that seems to work well,” George said. “Sometimes more is not always better.”

Christina Belew — Massachusetts assistant attorney general, vice chair of the NEPOOL End User sector and member of the JNC — said participating in the stakeholder process is “expensive, time-consuming and requires specialized technical knowledge to be effective.”

“As anyone who has done it knows, these are very real barriers to participation by end users,” Belew said. ISO-NE established the Consumer Liaison Group, which holds quarterly meetings open to the public to help consumers understand what is happening at the RTO “and how that might affect their pocketbooks.” However, it is not designed to be an advocacy group and has no budget, staff or formal role in the stakeholder process.

Belew said the National Association of State Utility Consumer Advocates has looked at ISO-NE governance issues. One of its recommendations would be establishing a tariff-funded consumer advocacy group with a role in the stakeholder process. She added that this is not a “revolutionary idea,” as PJM created a similar group in 2013 and since 2017 it has been funded under its tariff.

“We think that having a stable funding mechanism and a staff to track the issues would increase participation by New England consumer advocates in the stakeholder process and would allow those who already participate to do much more, particularly if they had access to funds for consultants and things like that,” Belew said.

Next Steps

Massachusetts Department of Public Utilities Chair Matthew Nelson requested written comments on the forum’s topics and discussions. Those comments will be accepted through March 26 and posted publicly on the New England Energy Vision website. Additionally, she said the states would issue a joint summary of the issues identified and explain the potential solutions.

A technical forum on environmental justice will be held on a to-be-determined date.

March 2, 2021

Vistra Stock Plunges After Market Losses

Vistra Texas power producer Vistra said Friday that it expects to take up to a $1.3 billion financial loss because of the state’s massive power outage and its subsequent effects on the ERCOT market.

That would more than erase the Irving-based company’s gains from 2020, when net income was $624 million.

As a result, Vistra’s shares lost almost a quarter of their value Friday. The stock closed at $17.25, down $5.51 from the day before.

Vistra losses — Vistra CEO Curt Morgan | © *RTO Insider*

“Let’s start with the elephant in the room. We had a rough week last week, to say the least,” CEO Curt Morgan told financial analysts, speaking from Austin, where he was delivering testimony to state legislators. (See Texas Lawmakers Dig into Power Outages.)

Vistra is the largest generator in ERCOT with 18.3 GW of capacity. At times during the grid’s recovery from the widespread outages, the company said its Luminant subsidiary was providing 25 to 30% of the ISO’s generation. It would have been more had it not been for frozen coal piles, transportation problems, curtailed gas supplies and a glitch in ERCOT’s market systems that temporarily and incorrectly kept prices below the $9,000/MWh scarcity cap, far above the normal $25/MWh prices.

ERCOT required increasing amounts of collateral from traders to back their purchases in the power market.

Vistra said it posted a “significant” amount of collateral to back purchases in the ERCOT market. It has about $1.5 billion of cash and liquidity on hand, down from $2.4 billion at year’s end, CFO Jim Burke said.

The company won’t know how large its market losses will be until ERCOT completes its settlement of invoices, any corrective actions and possible litigation.

“I was pulling my hair out. I thought we were long. I thought we were in a good position,” Morgan said. “I look back on that every day and every night when I can’t sleep, and I say to myself, ‘What could we have done different, Curt?’ And I think those decisions, as I play them over and over again, were right.”

Vistra reported fourth-quarter ongoing operations of adjusted earnings before interest, taxes, depreciation and amortization (EBITDA) of $802 million, up from the previous year’s fourth quarter of $775 million. For the year, adjusted EBITDA was almost $3.8 billion, up from nearly $3.4 billion in 2019.

The company uses adjusted EBITDA as a measure of performance because it says that analysis of its business is improved by visibility to both that metric and net income prepared in accordance with generally accepted accounting principles.

March 2, 2021

FERC Approves $205,000 NorthWestern Settlement

FERC has accepted a settlement between WECC and NorthWestern Energy for violations of NERC reliability standards, under which the utility will pay $205,000 to the regional entity in addition to performing other mitigation activities.

NERC submitted the settlement to FERC in a notice of penalty in January, which the commission on Friday indicated it would not review (NP21-6), letting the penalty stand. The NorthWestern penalty was the only settlement publicly disclosed by NERC in January, but because of a rule change last year, the organization may limit or withhold disclosure of information relating to violations of the ERO’s Critical Infrastructure Protection (CIP) standards. (See FERC, NERC to End CIP Violation Disclosures.)

Tree Growth Leads to Line Failure

NorthWestern’s settlement stems from violations of FAC-003-4 (transmission vegetation management), specifically requirements R2, which requires applicable transmission owners and generator owners to keep vegetation from encroaching on a line’s minimum vegetation clearance distance (MVCD), and R6, which mandates that 100% of transmission lines be inspected at least once a year for vegetation encroachment. The violation of R2 was self-reported, while WECC discovered the second violation via a subsequent compliance audit.

In its self-report submitted Aug. 21, 2018, NorthWestern told WECC it had discovered two encroachments into the MVCD of its 230-kV transmission line, each of which caused a high-voltage flashover resulting in a sustained outage.

FERC NorthWestern Settlement — NorthWestern Energy generating facilities in Montana: The violation occurred on a 230-kV line between a substation in Billings and nearby Huntley. | *NorthWestern Energy*

The first encroachment was addressed on Aug. 10 when a crew performing a line patrol found a tree growing within the MVCD and removed it at the groundline, causing a flashover and outage that was restored within several hours. The next day a tree-clearing crew returned to remove additional trees along the same line. However, during clearing operations a second flashover and outage occurred, which the utility believed was caused by a different stem of the tree removed the day before. NorthWestern re-energized the line the same day after the remaining trees were cleared.

With both outages restored and the line cleared, the utility ordered a follow-on inspection across all of its bulk electric system transmission lines in case it had missed any other potential vegetation issues. This inspection was completed by Aug. 15, identifying nine additional areas in danger of encroachment and requiring corrective action plans to resolve.

Inspections Leave Room for Improvement

After NorthWestern submitted its self-report to WECC, the RE ordered an investigation from Nov. 27, 2018 through March 20, 2019, to identify potential noncompliance with Requirement R6. The investigation found that while the utility did conduct annual vegetation inspections, these “[relied] solely on … aerial patrols.”

Ground patrols were performed in areas where aerial inspection found potential problems, but WECC said this system was insufficient because the patrols were conducted “during the late to early spring season, [when] much of the vegetation is devoid of foliage.” This meant inspectors had trouble foreseeing the risk that vegetation might pose following periods of high rain later in the year.

Both violations posed a “serious and substantial risk to the reliability of the bulk power system,” according to WECC. While no load was lost because of the R2 violation that caused two outages Aug. 10-11, the RE noted the affected line connected to other 230-kV lines, as well as a switchyard handling both 100-kV and 230-kV lines. As a result, the outages led to a risk of “cascading or widespread outages.”

The R6 violation was assessed at the same risk level because it had led directly to the R2 violation. In addition, the fact that NorthWestern’s subsequent inspection found additional areas of concern clearly demonstrated that its annual aerial patrols were not enough to satisfy the requirements of the standard.

The utility submitted a mitigation plan to address these violations to WECC in June 2019. The plan built on the vegetation removals from the affected line, along with the full aerial assessment, with improvements to the utility’s vegetation management program. Features of the new plan include a second annual aerial inspection conducted in mid-summer; a requirement for ground assessments at water crossings; and technology enhancements to improve data collection consistency, assessment results and response time.

WECC confirmed the completion of NorthWestern’s mitigation plan on Dec. 31, 2019. The RE’s penalty assessment was based on the violation risk factor, which was high for the R2 violation and medium for the other, and the violation severity level, which was severe in both cases. In addition, both infringements lasted more than 160 days, exceeding the time horizon expected for remediation of one hour in the case of R2 and one day in the case of R6.

Mitigating credits were applied in light of the utility’s cooperation throughout the process and the timeliness of its initial self-report from the date of discovering the R2 issue. In addition, it did not fail to complete any applicable compliance directives, submitted all requested documentation on time and made no apparent attempt to conceal the violation. WECC determined that NorthWestern’s management was not involved in and did not condone the actions that led to the noncompliance.

March 2, 2021

Mass. Bill Taps Tax Refunds for Climate-vulnerable Countries

Massachusetts could be the first state to allow residents to donate their tax refunds to help developing nations build resilient communities.

Massachusetts state Reps. Antonio Cabral (D) and Tram Nguyen (D) re-introduced legislation last month that would include a new section on tax forms asking taxpayers whether they want to donate their state tax returns to the Least Developed Countries Fund. Parties to the United National Framework Convention on Climate change created the fund in 2001 to help the world’s least developed countries prepare for natural disasters and make communities more resilient to adverse weather.

The bill was held up in committee during the last legislative session, when much of the state’s focus was on COVID-19 alleviation and recovery.

The bill establishes the Massachusetts Fund for Vulnerable Countries Most Affected by Climate Change, a voluntary tax-return contribution option that would be incorporated into the United Nations Least Developed Countries Fund. Cabral told NetZero Insider that he is optimistic the bill will pass this year, as there is a major focus on climate legislation in the state.

“A lot more people are not only talking the talk but also walking the walk,” he said. “But this is a new concept, and it takes time for people to get their heads around it.”

Government entities can contribute to the international fund, but individuals cannot. For that reason, it remains largely underfunded, Larry Yu, chair of the Climate Reality Project Boston chapter, told NetZero Insider.

The U.S. contributes less than 10% of the fund, but the Massachusetts bill, if passed, would pave the way for other states to contribute as well, Yu said.

“Then the contribution becomes more significant,” he added, as climate change is causing increasingly intense natural disasters.

Massachusetts Tax Refund Bill — A Massachusetts bill would allow taxpayers to allocate refunds to help developing countries hit by climate-related natural disasters, like Tropical Cyclone Idai, which caused flooding on the Mozambican coast, as seen here. | *Shutterstock*

In 2019, Cyclone Idai killed more than 1,000 people in Zimbabwe, Malawi and Mozambique, and left millions more without food or access to services. Water shortages in Eastern Africa are displacing thousands of people from their homes.

“That [natural disaster] didn’t really hit the news in the [U.S.],” Yu said.

The bill, and addressing climate change in general, is a matter of “moral responsibility, not foreign aid,” Adil Najam, professor of international relations and earth and environment at Boston University, told NetZero Insider.

The least developed countries are 48 of the poorest countries in the world, the majority of which are in Africa and Asia. They are also the countries least responsible for contributing to the climate crisis.

The energy infrastructure in Massachusetts impacts the rest of the world, Cabral said.

The bill is not addressing the question of who is at fault, Najam said. Instead, he added, it addresses shared responsibility.

Donating state income tax returns to the fund is “something easy to do, but very meaningful,” he said.

March 2, 2021February 2, 2024

Lidar Project to Unearth Nev. Geothermal, Lithium Potential

Federal agencies have teamed up to conduct detailed surface and subsurface mapping of a large swath of western Nevada, a project aimed at revealing sites with a high potential for geothermal energy or lithium.

The U.S. Geological Survey and the Department of Energy in September announced the project, called Geoscience Data Acquisition for Western Nevada (GeoDAWN). The study will use light detection and ranging, or lidar, for surface mapping of the area, and geophysical techniques, including aeromagnetic surveys, to look beneath the surface.

DOE officials said last week that the $10 million project is well underway, with completion expected next year. The data will be made public when the project is finished.

The project area includes a roughly 200-mile-long piece of the Walker Lane geologic area, a fault system that runs near the Nevada-California border. The GeoDAWN area also extends into a portion of central Nevada and up to a section of the state’s northern border.

The GeoDAWN area has a high potential for discovery of new geothermal energy resources, according to USGS. The study will also look for spots with large amounts of critical minerals including lithium, which is needed for lithium-ion batteries such as those used in electric cars.

The project will reduce the risk for companies interested in geothermal exploration, said Susan Hamm, geothermal technologies office director in DOE’s Office of Energy Efficiency and Renewable Energy. The project could potentially lead to the establishment of new geothermal energy plants within the next decade, she said.

“It’s going to generate many exciting leads,” Hamm told NetZero Insider.

Finding geothermal clues

GeoDAWN will combine a number of techniques to look for geothermal potential and minerals. In addition to lidar and aeromagnetic surveys, the project will use airborne radiometry and geochemical analysis of rock and brine samples.

Lidar involves bouncing laser beams off the surface of the Earth from an aircraft and measuring how quickly the light returns. The data can be used to produce highly detailed maps of the Earth’s surface.

Magnetic surveys, also conducted from an aircraft, detect small changes in magnetic fields and can spot underground features such as faults.

Many geothermal resources are hidden or “blind,” meaning there’s no surface feature such as a hot spring to show where they are, Hamm said.

Fault patterns are one indicator of where a geothermal resource might lie. Researchers are still discovering what other features are associated with a geothermal resource.

The study will also examine areas where geothermal resources have already been found, for example, during mining operations. Machine-learning will be used to look for the features of those areas at other sites.

“It couldn’t be more exciting,” Hamm said.

Building on Past Work

The project will build on past research on geothermal resources in Nevada.

Researchers from the Nevada Bureau of Mines and Geology previously combined several sets of geologic and geophysical data for a large area in central Nevada. The data included characteristics of surface faults and measurements of gravity and temperature gradients.

The study led to the creation of a geothermal potential map, pointing researchers to two previously undiscovered, blind geothermal systems. At one of those sites, in Gabbs Valley, temperatures of 255 degrees Fahrenheit were found at a depth of 500 feet.

NBMG Director James Faulds said information acquired through the GeoDAWN project will be an important addition to data used in the earlier study. NBMG, which is housed at the University of Nevada, Reno, serves as the geological survey for the state and has provided technical assistance to the project.

New geothermal hot spots may be discovered through GeoDAWN, and the project’s findings will help rate promising geothermal sites already identified, Faulds told NetZero Insider.

GeoDAWN will also help Nevada catch up on lidar data collection. Up until recently, only 6% of the state had been covered by high-resolution lidar, the lowest percentage of any state, according to Faulds. GeoDAWN will bring that figure up to around 31%, he said, with other projects adding about another 9%.

The USGS 3D Elevation Program (3DEP) is working to achieve nationwide lidar coverage by 2023. Faulds said 3DEP has provided matching funds to others interested in lidar projects, such as local water authorities, but that hasn’t been much help for the vast amount of federal land in Nevada. Faulds said he encouraged federal agencies to talk to each other about ways to get more lidar coverage for the state.

In addition to USGS and the DOE Office of Energy Efficiency and Renewable Energy, partners in GeoDAWN include the Bureau of Land Management and the U.S. Department of Agriculture’s Natural Resources Conservation Service.

Mapping Lithium Potential

Nevada lags in lidar data acquisition despite having what may be the most geothermal potential among the 50 states, based on its geology, Faulds said. The state is second only to California in the production of geothermal energy.

Nevada also stands out in terms of lithium potential.

The U.S. is heavily dependent on imports to meet its lithium needs, according to USGS, and currently the only domestic source of lithium is in Nevada.

In contrast to geothermal resources, no one has made a map of lithium potential in the state, Faulds said.

“That is … badly needed to better evaluate where some of those sort of hidden and additional lithium resources might be,” he said.