Fall in the MISO footprint was a study in record wind production — in more ways than one.
The quarter was defined by unprecedented hurricane activity and peak wind generation. MISO set an all-time wind output record of nearly 19 GW on Nov. 15, when wind accounted for nearly a third of all generation.
MISO Independent Market Monitor David Patton said during the RTO’s Markets Committee meeting Tuesday that installed wind capacity and output expanded by 33% and 30%, respectively, compared to last fall. But he said the record production came with a price, as more than half of the quarter’s real-time congestion was related to wind generation.
“As our wind output grows, the transmission congestion it’s causing is significant,” Patton said.
MISO acknowledged that though wind is taking an increasing portion of the resource mix, it continues to be curtailed during high production.
Patton said “dramatic” changes in wind output occurred several times during the fall, making MISO’s forecasting vital. He said that on Oct. 18, wind generation fell from 15.5 GW to 1 GW during the day. On Oct. 16, it dropped nearly 6 GW right before the evening peak.
| MISO
“If MISO doesn’t see this coming, it’s like losing six nuclear units at once,” he said.
Patton said average load was down about 7% compared to normal because of a combination of the COVID-19 pandemic and moderate fall temperatures. MISO estimated that the pandemic was tied to a 4% reduction in load this fall.
A blend of lower load, lower natural gas prices and high wind output contributed to a 14% decrease in energy prices from last fall, he said.
Pandemic-muted loads are also creeping back into the seasonal picture as infections soar and local officials again limit gatherings.
“We are moving back into COVID-19 load levels, where we are about 5% below load from a normal, non-COVID world,” MISO Director of Operations Planning J.T. Smith said.
Laura Pricing in Question
Pricing issues after Hurricane Laura made landfall in Louisiana on Aug. 27 continues to be a source of debate among staff, the Monitor and stakeholders.
Patton said the storm caused $90 million in congestion costs and “effectively created a dead zone in the Lake Charles area, destroying a significant amount of distribution system lines and transmission.” He said about $10 million of the congestion costs was from MISO pricing dead buses in the area at the $3,500/MWh value of lost load (VOLL).
“It wasn’t an area where we were resource-inadequate. … In theory, this is not a situation that warrants VOLL pricing,” he said. “We lost a lot of key transmission lines into the area, and we lost a lot of generation.”
Hurricane Laura impact | Potomac Economics
Patton said he is working with MISO to more appropriately price the area.
“I’m sure I’ll have more to report,” he told the Board of Directors.
MISO declared local conservative operations for a month after Laura’s landfall to support restoration efforts.
Patton said that by mid-September, three generating units in the area were again able to serve load, but total restoration was not complete until mid-October.
MISO encountered “modeling challenges” in the load pocket created by the storm, Patton said, noting the grid operator could not price conditions consistent with the aftermath until early September. During that time, prices during peak conditions only averaged about $20/MWh, even though industrial load was still going unserved, he said.
“For about a week after Hurricane Laura, the prices in the area should have been fairly high but they were inefficiently low,” Patton said. The RTO eventually established a reserve procurement constraint Sept. 8, but Patton said that by then, the tightest conditions had already passed.
MISO President Clair Moeller said it took about two to three days for the RTO’s operators to manually readjust reserve zones to get more accurate pricing following the storm. He said MISO’s pricing must be more automated and dynamic in the future.
NYISO’s Business Issues Committee voted Wednesday to recommend approval of Tariff revisions to streamline the ISO’s transmission planning and expand its scope to capture the grid’s ability to deliver energy from the future generation resource mix to the forecasted load.
The changes rename the Congestion Analysis and Resource Integration Study (CARIS) as the draft System & Resource Outlook and double the assessment periods to 20 years, consistent with the study period for proposed economic or public policy transmission projects. They also remove language requiring time-intensive staff work of little value, such as the evaluation of generic solutions to the same “top three” congested paths each cycle.
The new rules also will affect the ISO’s consideration of non-bulk power transmission facilities by incorporating transmission owners’ local transmission plans into the economic planning process.
| Fré Sonneveld/Unsplash
“We wanted to make this clarification because we are planning on working with transmission owners a bit closer in our model development just to make sure that we’re capturing all the information necessary and have the coordination we find necessary to produce the best study possible,” Manager of Economic Planning Jason L. Frasier said. If the Management Committee and Board of Directors approve the Attachment Y Tariff revisions, the ISO will make a Section 205 filing with FERC in January.
Clarification: Landfill Gas Covered under Tailored Availability Metric
The BIC also voted to recommend MC approval of a clarification to apply the ISO’s new Tailored Availability Metric (TAM) rules to landfill gas resources, as well as wind and solar. (See “Tailored Availability Metric OK’d,” NYISO Management Committee Briefs: April 29, 2020.)
FERC accepted the TAM rules in September for intermittent resources for implementation with the day-ahead market run for May 1, 2021 (ER20-2337).
The clarification will replace the terms “wind and solar resources” with “intermittent power resources,” which includes landfill gas, in section 5.12.14.3 of the Market Administration and Control Area Services Tariff.
The TAM rules change how the ISO measures the amount of unforced capacity (UCAP) intermittent resources can sell — calculated as installed capacity less the resource’s derating factor. While thermal resources’ derating is based on forced outages, intermittent resources’ derating is based on their historic performance during certain peak load hours.
The BIC also approved modifications to the Control Center Requirements Manual to incorporate tariff modifications made in November related to utilization of meter services entities (MSEs) for demand-side resources. (See “Other Approvals” in NYISO OKs Changes on Hybrid, Fast Start Resources, TCCs.)
California Gov. Gavin Newsom on Wednesday appointed Liane Randolph, a member of the state’s Public Utilities Commission, as the next chair of the California Air Resources Board.
CARB oversees vehicle emissions, among other roles, and has battled with the Trump administration in recent years. Its policies have influenced manufacturing in the automotive sector for decades and will continue to do so with the state’s adoption of electric vehicles. In September, the governor ordered that all new vehicles sold in the state must be emissions-free by 2035. (See Can California Meet Its EV Mandates?)
“Cleaner air is essential for California’s families, and Liane Randolph is the kind of bold, innovative leader that will lead in our fight against climate change with equity and all California’s communities at heart,” Newsom said in a statement.
Current CARB chair Mary Nichols is retiring at the end of this year and is being considered by President-elect Joe Biden as head of the U.S. Environmental Protection Agency, according to the Associated Press and other news outlets.
Randolph, 55, was named by former Gov. Jerry Brown to the CPUC in 2015 after years working in state government and in private practice as an attorney. She served as deputy secretary and general counsel at California’s massive Natural Resources Agency from 2011 to 2014 and as head of the state’s political watchdog, the Fair Political Practices Commission, during the tenure of Gov. Arnold Schwarzenegger, from 2003 to 2007.
In a statement released by the CPUC, Randolph said she was “beyond excited and honored to join the path-breaking team at CARB, which has been at the forefront of environmental progress for decades.”
During Randolph’s time at the CPUC, the commission has dealt with California’s mandate to switch to 100% clean-energy resources, the massive gas leak at the Aliso Canyon storage facility and the bankruptcy of Pacific Gas and Electric after it was blamed for catastrophic wildfires.
Randolph is a centrist on the CPUC, often reaching decisions that her colleagues support but may be more business-friendly than some would like. For instance, Randolph oversaw PG&E’s general rate case that awarded the utility a $1.3 billion rate increase over the next three years, much of it to harden the utility’s grid against wildfires. (See PG&E Gets $1.3B Rate Hike, Cancels Mass Blackouts.)
Commissioner Martha Guzman Aceves said she would vote for the decision to protect residents even though it would hit poorer households harder during the pandemic and economic downturn. Guzman Aceves also expressed doubt that PG&E would maintain and upgrade its long-neglected power lines.
Environmental justice groups had advocated for Guzman Aceves to be the next CARB chair, Politico reported.
Newsom named four other members to CARB: John Balmes, 70, professor of medicine and environmental health at the University of California, San Francisco, and at UC Berkeley; Belmont City Council member Davin Hurt, 45; Los Angeles attorney Gideon Kracov, 49; and Tania Pacheco-Werner, 36, assistant co-director of the Central Valley Health Policy Institute at California State University, Fresno.
Newsom will appoint Randolph’s successor on the five-member CPUC. All the appointments will require confirmation by the state Senate.
NYISO energy markets performed competitively in the third quarter of 2020, but the use of out-of-market actions to meet local and statewide reliability needs was a significant concern, the Market Monitoring Unit said Monday.
“One of the big themes in this quarter, partly because of relatively low load levels and low natural gas prices, was the frequent use of out-of-market [OOM] actions to maintain reliability and transmission security,” Pallas LeeVanSchaick of Potomac Economics said in presenting the Market Monitoring Unit’s State of the Market report for the third quarter to the Installed Capacity/Market Issues Working Group. “To the extent that you’re meeting reliability needs through out-of-market actions, you’re not providing efficient market signals for investment to meet those needs.”
NYISO system price diagram for the third quarter | Potomac Economics
For the second consecutive quarter, capacity costs constituted the majority of New York City’s all-in prices (62%), because of an increased locational minimum installed capacity requirement (LCR) and very low energy prices, he said. (See “Pandemic Reduced NYC Load by 11%,” NYISO Q2 Energy Prices, Load at 10-Year+ Lows.)
All-in prices ranged from $22/MWh in the North (Zone D) to $69/MWh in the city (Zone J). Prices were up in Zones A-F (1 to 11%) and in the city (21%), but down 18% in the Hudson Valley (Zone G) and 6% in Long Island (Zone K).
Average natural gas prices fell 15 to 24% from a year ago, resulting in the lowest quarterly average price for a third quarter since at least 2009.
NYISO all-in prices by region for the third | Potomac Economics
Average load fell slightly, but peak load also rose slightly. The COVID-19 pandemic may have reduced average load by about 3% for the quarter, the MMU said. Load reductions were largest in the city (6%), while many other regions saw increased load for the quarter, such as 2% in Long Island.
Nonetheless, load levels were comparable to levels in the same period a year ago as warmer summer weather largely offset the effects of the pandemic, the MMU said.
OOM a High Priority
“In New York City we saw out-of-market commitments daily to maintain adequate reserves to satisfy N-1-1-0 criteria for some of the 138-kV load pockets as well as for the 345-kV system,” LeeVanSchaick said. “Again, that’s important because those are some of the same areas where reliability needs are being identified by [NYISO], as well as where you have byway deliverability bottlenecks that could make it harder for generation to interconnect in certain areas.”
NYISO has greatly reduced the use of OOM actions to manage congestion in upstate New York over the last two years by modeling most 115-kV transmission constraints in the day-ahead and real-time market models, he said.
Frequency of NYISO out-of-merit dispatch by region by month | Potomac Economics
In New York City, some local reliability needs are met by Consolidated Edison making manual commitments. In other cases there are constraints in NYISO software that cause a resource to be committed OOM but do not result in prices reflecting local grid needs. So, “it’s not that the NYISO doesn’t see the constraint; it’s that there is no local reserve requirement that sets a clearing price that can be paid to all resources for providing local reserves, so you have to commit something out of market,” LeeVanSchaick said.
Bid production cost guarantee (BPCG), or uplift, payments totaled $20.6 million, up 16%; 26% of BPCG payments were to New York City units, and 63% were to Long Island units, for local reliability needs, the MMU said.
The report lists modeling reserves dynamically and having local reserve requirements to reflect N-1-1-0 criteria as high-priority recommendations.
“Without meeting these requirements through the market, as opposed to out-of-market actions, it’s going to be really difficult to get people to invest in resources that have flexible characteristics and are located in the right areas where they’re needed most,” LeeVanSchaick said.
Mapping Congestion
Day-ahead congestion revenues totaled $84 million, down 34% from a year ago, primarily because of lower gas prices, the report said. Congestion fell by nearly 42% in New York City from the prior year.
But Long Island accounted for the largest share of congestion (33%) this quarter, up 69% in the day-ahead market ($11.4 million) and 11% in real-time ($2.2 million) from a year ago. Load increased on Long Island, with higher residential cooling needs from the pandemic and the hotter-than-normal summer weather.
Real-time price map at generator nodes shows NYISO system congestion. | Potomac Economics
“The system congestion map indicates that eastern Long Island has a lot of areas that don’t have natural gas service,” LeeVanSchaick said. “The generation in the eastern half of Long Island is in large part higher-cost than in other areas.”
Looking ahead is challenging, he said, because lower NOx limits will take out some generators in the Astoria and LaGuardia areas of Queens, which support areas to the east where there aren’t many generators. That will lead to some reliability needs starting in 2023 that could be met through some other generation or transmission. A similar situation in the Greenwood Heights area in Brooklyn will lead to reliability issues beginning in 2025, he said.
States that have set goals to reduce greenhouse gas emissions have yet to implement sufficient policies to meet their pledges, the Environmental Defense Fund said in a study released Wednesday.
Twenty-five states and Puerto Rico, which have pledged to meet the U.S. commitment under the Paris Agreement on climate change, are on a trajectory to reduce emissions by about 18% below 2005 levels by 2025, well below the 26 to 28% reduction promised, EDF said.
EDF’s study focused on 25 states and Puerto Rico, which have made commitments to reduce their carbon emissions in line with the Paris Agreement. | EDF
Based on emissions data from Rhodium Group, the study included Puerto Rico and 24 states that created the U.S. Climate Alliance after President Trump announced his intention to withdraw from the 2015 international agreement. It also included Louisiana, whose governor separately announced the state would meet the 2025 Paris target and eliminate net emissions by 2050.
EDF said the gaps are even larger when compared with the reductions the U.N. Intergovernmental Panel on Climate Change (IPCC) says are needed to avoid the worst consequences of climate change. The study said the states and Puerto Rico are on track to reduce emissions by only 11% from 2010 levels by 2030, rather than the 45% IPCC says is needed.
“While many states have taken important steps on climate, they are not moving fast enough to turn commitments into the policies that will lock in the needed reductions in pollution,” said Pam Kiely, EDF’s senior director for regulatory strategy. “Making a climate commitment is only the starting point — not the finish line. Even under a new president with a meaningful climate agenda, state policies are essential for securing significant and immediate reductions in climate-warming pollution. … It’s also time for states that haven’t made a climate commitment to join the effort.”
This chart shows different trajectories the states analyzed by EDF could take to meet the 2030 emission reduction target of the U.N. Intergovernmental Panel on Climate Change. While all of the pathways result in the same emission level in 2030, delaying action until 2025 would result in a cumulative reduction of only 2,540 million metric tons of carbon dioxide equivalent — less than half as much as the reductions under the accelerated pathway. | EDF
EDF’s study recommended the establishment of declining, enforceable limits on GHG emissions, citing the model of the Regional Greenhouse Gas Initiative. It also said a well designed carbon price “can enable much greater ambition by securing the most cost-effective reductions, jumpstarting innovation and accelerating early action.”
“Regardless of the specific suite of policies deployed, it is imperative that states focus on the targets they have set, acknowledge their current emissions gaps and take action to achieve quantifiable reductions in pollution needed to limit warming over the coming decades,” EDF said.
The study cited New Mexico Gov. Michelle Lujan Grisham (D) as setting a good example, saying she is “engaging in a robust data analysis, transparently laying out the emissions gap and setting a course to enact comprehensive emission-reduction policies to ensure the gap is closed.”
The study says that although the IPCC has also called for net-zero carbon dioxide emissions by 2050, the amount emitted before that year is also crucial. “Carbon dioxide can remain in the atmosphere for thousands of years, so emissions entering the atmosphere over the next few years will continue to warm the planet for many decades to come,” EDF said. “The earlier we reduce emissions, the better the chance we have at achieving temperature stability at desirable levels.”
NERC’s Standards Committee voted Wednesday to reject the standard authorization request (SAR) for Project 2020-01, submitted by the System Planning Impacts of Distributed Energy Resources (SPIDER) Working Group last December to revise reliability standard MOD-032-1 (Data for power system modeling and analysis).
Wednesday’s meeting represented the second attempt to bring the SAR to the committee for approval, after it was removed from the agenda of last month’s meeting to give members more time to review comments received during the informal comment period that ended Apr. 24. (See “SAR Team Members Sail Through,” NERC Standards Committee Briefs: Nov. 19, 2020.) Following the vote, the SAR will be sent back to the SPIDER group with a written explanation for its rejection.
Marty Hostler, reliability compliance manager for the Northern California Power Agency, made the motion to reject. Hostler said he was seriously concerned about the SAR drafting team’s response to the informal comment period — or rather the lack thereof, as the team made no changes to the SAR between the end of the comment period and submitting it for approval. Along with Sean Bodkin of Dominion Energy, who seconded his motion, Hostler said that even though the team was not required to respond to the many negative comments received, it was unacceptable to ignore them.
Representatives from NERC pushed back on the motion unsuccessfully. Howard Gugel, NERC’s vice president of engineering and standards, suggested that industry participation in the comment period was low because the SAR had been endorsed by the Planning Committee, replaced earlier this year by the Reliability and Security Technical Committee (RSTC).
“I would not state that just reading the comments … necessarily indicates that industry is not in support of it,” Gugel said. “[My] opinion is that [because] the RSTC endorsed it, they felt that they didn’t need to comment on it.”
NERC’s Chris Larson, who served on the SAR drafting team, added that it did take note of the comments but saw no need to revise the SAR, as it expected to be given “appropriate flexibility” to address the concerns after being made the standard drafting team (SDT). This argument did not convince the committee, however. Hostler said there was no good reason for delay when the team knew action would be needed eventually, while Robert Blohm of Keen Resources said this logic created a mechanism by which “you could avoid rejecting any SAR.”
“You could say, ‘Well, yeah, there’s a lot of opposition, but trust us, we’ll take care of it … when we have to do the drafting,’” Blohm said. “[It] kind of lessens the impact of the whole SAR development process.”
Smoother Road for Project 2020-04
Hostler raised a similar objection to the SAR for Project 2020-04 (Modifications to CIP-012), asking that the drafting team be given more time to revise the document in reaction to concerns raised in its informal comment period, which ended in May. This time he failed to gain support, however, with Bodkin noting that industry comments in this case were not as negative or numerous as those received for the Project 2020-01 SAR. Bodkin’s motion to approve the SAR and appoint the SDT passed.
Bodkin also successfully moved to accept the recommendation of NERC’s Standards Efficiency Review project to review the ERO’s reliability standard template. The evaluation will be carried out by the Standards Committee Process Subcommittee (SCPS) — which Bodkin chairs — and is intended to “ensure the template facilitates a systematic approach to developing an effective and efficient results-based standard.” The SCPS will also review SDT training modules and reference manuals to remain consistent with changes to the template.
PMOS Charter Change Questioned
The committee agreed to revise the scope document for the Project Management and Oversight Subcommittee (PMOS), primarily intended to “allow for better alignment” with the committee’s charter.
Bodkin questioned Charles Yeung, executive director for interregional affairs at SPP and chair of the PMOS, about a note added to the new charter that meetings are open to any interested parties, “subject to any preregistration meeting requirements included in the meeting announcement.” He worried that this might discourage industry participation in NERC, though Yeung suggested that the benefits could outweigh this risk.
“[As] a chair in a meeting, if somebody didn’t preregister [and just walked in], wouldn’t you want to be able to turn them away?” Yeung asked.
“Nope. As the chair of the SCPS, if somebody comes in, if they’re an interested party in the subject matter and they want to participate, I would definitely invite them,” Bodkin replied. “[If], say, somebody just came in to heckle, I could eject them under the professional conduct policy that we have. But I would not want to prevent somebody who actually has a vested interest from coming in just because they didn’t register.”
Others pointed out that the Standards Committee charter itself contains identical language in its section on meetings. Gugel said this wording is not intended to discourage participation but to comply with security restrictions that hosting entities might have in place; for example, some companies require background checks for anyone entering their premises. The new charter, including the questioned language, was approved by the committee.
SPP staff said this week that stakeholders’ overall satisfaction with the RTO’s services and staff’s performance in three specific areas all rose during 2020, even as survey responses dropped.
Staff shared the results of SPP’s annual stakeholder satisfaction survey and other assessments during the Board of Directors’ meeting Monday.
Scored on a 5-point scale, stakeholders gave SPP an overall 3.87 rating for 2020, a 0.25 increase from 2019. A year ago, overall satisfaction was only up 0.03 points. Stakeholders gave staff similar boosts of between 0.24 and 0.27 points when asked their satisfaction with responsiveness, accuracy of information and problem resolution.
However, the survey’s response rate fell from 18.6% a year ago to 13.6% this year. SPP sent out 1,283 invitations to the survey, with 174 stakeholders responding.
“Sometimes, people’s response rate is related to whether they feel anyone is responding to them,” board Chair Larry Altenbaumer said. “We want people to understand this is an important part of the process. We need to demonstrate that more effectively than we have in the past … to increase those numbers in the future.”
Staff reminded the board during its yearly metrics review of organizational effectiveness that they take all the comments received from the surveys and assign them to managers for action. SPP also makes periodic progress reports to the Markets and Operations Policy Committee.
Lanny Nickell, SPP | SPP
“I know there is an ongoing activity, but we haven’t done as good a job as sharing with members the activities we do,” Altenbaumer said. “Too often, it comes across as a one-shot deal in December.”
Directors and members also reviewed evaluations of the board and the organizational groups’ self-assessments. The directors’ and Members Committee’s average rating of the board (4.25 out of 5) was identical to 2019. SPP extended the survey to the MOPC for the first time this year; the committee gave the board an average rating of 3.79.
Members Committee representatives rated the board’s performance lower than the directors did in all 23 assessed categories, ranging from 0.09 to 1.13 points lower.
“It’s important for those of us on the board to understand what would drive [the Members Committee] to say this,” SPP CEO Barbara Sugg said. She said staff would bring back thoughts on the gaps to the January board meeting.
COO Lanny Nickell will bring a proposed set of key performance indicators (KPIs) based on actual data to the same meeting. He shared a strawman that would reduce the number of KPIs to four: working together, responsibility and economics, keeping the lights on today, and keeping the lights on in the future.
SPP’s key performance indicators for 2021 | SPP
Wolf Creek-Blackberry Timeline Tweaked
The board approved a consent agenda that added another year for regulatory approval to the 345-kV Wolf Creek-Blackberry competitive project. Staff determined that the current Jan. 1, 2022, deadline gave Kansas regulators only 66 days instead of the normal 180 to verify whether the potential transmission owner has gained utility status and, with it, the right of eminent domain. Staff recommended the deadline be extended to Jan. 1, 2023.
In September, the board lifted a suspension of the project and authorized the Oversight Committee to create an industry expert panel to evaluate responses to a request for proposals, which staff have since issued. (See “Board Lifts Suspension on Competitive Upgrade,” SPP Board of Directors/MC Briefs: Sept. 22, 2020.)
SPP expects to award the project a notification to construct next October. It is expected to cost $152 million, which members will fund according to load-ratio share.
With its sign-off of the consent agenda, the board approved the Corporate Governance Committee’s nomination of ITC Holdings’ Alan Myers as the MOPC’s vice chair. Myers will serve alongside acting MOPC Chair Denise Buffington, of Evergy.
Myers has chaired the Economic Studies Working Group since 2008 and will commence another two-year term in January following the board’s approval of his CGC nomination.
Also approved as stakeholder group chairs were: American Electric Power’s Richard Ross (Market Working Group); AEP’s Brian Johnson (Project Cost Working Group); Evergy’s John Anderson (System Protection and Control Working Group); Oklahoma Gas & Electric’s Jerad Ethridge (Model Development Working Group); and City Utilities of Springfield (Mo.)’s Russell Moore (Operations Training Users Forum).
Ross, Ethridge and Moore are all incumbents.
OG&E’s McAuley Says Goodbye
The meeting was the last as a Members Committee representative for Greg McAuley, OG&E’s director of RTO policy and development and one of the more vocal proponents of more equitable cost allocations for transmission upgrades. McAuley is returning to his native Florida to spend more time with his elderly mother.
“He has been one of the truly great contributors to SPP,” Altenbaumer said. “Please note there were many times we didn’t agree on things, but he always approached those discussions constructively.”
McAuley thanked staff and stakeholders for welcoming him into the SPP community when “I was new to the role.”
“The professionalism of this group is incredible. Your leadership, and Barbara’s now, is really doing some good work,” McAuley said in response to Altenbaumer. “Hopefully, our paths will cross in the not-too-distant future.”
“I’m saddened to see you leave the SPP family,” Sugg told McAuley.
April Board Meeting to be Virtual
Altenbaumer concluded the year’s final virtual board meeting by telling directors and members to expect more of the same in the first half of 2021. SPP had hoped to return to in-person meetings by April, but Altenbaumer said that after conferring with Sugg, they concluded it was too soon to end virtual meetings.
“While we were hopeful of getting through this surge and benefiting from a widespread vaccine, we just aren’t that confident that it’ll be the scenario we’ll face in April,” he said.
SPP’s current schedule lists the July and October board meetings as being held in-person at its Little Rock, Ark., headquarters.
FERC’s Office of Enforcement last week found that ALLETE overbilled its wholesale transmission customers through improper accounting practices.
ALLETE, which owns Minnesota Power, inappropriately billed its customers for environmental mitigation costs imposed on it after it violated the Clean Air Act, FERC said in an audit report Dec. 4. The audit covered Jan. 1, 2016, to Sept. 3, 2020 (FA20-2).
The commission gave the Duluth, Minn.-based utility 60 days to submit a refund analysis identifying the improperly recovered expenses. ALLETE wrote that it accepted FERC’s audit findings and recommendations Nov. 19. But it said FERC’s finding on accounting for environmental costs “overlooks important policy considerations that should inform the proper accounting of related expenses.”
ALLETE’s Duluth, Minn., headquarters | ALLETE
FERC investigators found that the utility used an account earmarked for its labor and general management to record environmental mitigation projects after a failure to comply with the Clean Air Act. The commission said the ensuing solar projects should have been accounted for in an account reserved for projects donated after their completion and not included in its wholesale annual transmission revenue requirement (ATRR).
EPA struck a settlement with the company in 2014 over emissions at three coal-fired power plants in Minnesota. The settlement required ALLETE to pay a $1.4 million civil penalty, install pollution-control technology and spend $4.2 million on projects benefiting the environment and local communities.
FERC Enforcement staff found several other accounting irregularities at the utility. They said it also:
applied state-approved depreciation rates to assets included in its transmission formula, though it had not filed those depreciation rates with FERC.
overstated transmission plant balances in its ATRR by miscalculating the pre-funded allowance for construction funds.
inappropriately recorded proceeds from long-term debt in accounts reserved for miscellaneous deferred debt.
misclassified distribution assets in transmission plant accounts and transmission assets in distribution plant accounts.
improperly recorded $26,000 worth of lobbying expenses in 2016 and 2017 in an account for office supplies when they should have gone into an account reserved for civic, political and related expenses. Audit staff said some lobbying costs were incorrectly recovered as part of ALLETE’s ATRR.
wrongly recorded various administrative and general expenses “in a manner contrary to the commission’s accounting regulations.”
did not report all the required information in FERC filings.
In addition to calculating customer refunds with interest, the commission prescribed that the company update its policies within a month and provide more employee training on accounting procedures. FERC also asked for progress updates on the corrective actions in quarterly reports.
“Integrity and compliance are core values at ALLETE. We take audits of this nature seriously and believe they help improve systems and procedures, and we look forward to implementing and improving compliance measures,” ALLETE Manager of Corporate Communications Amy Rutledge said in an emailed statement.
Rutledge said FERC auditors during the process “expressed their appreciation about ALLETE’s high level of cooperation and collaboration.” She also said that FERC’s findings affect only Minnesota Power’s transmission and wholesale customers, “all of whom have been notified regarding the plans for refunds.”
“FERC identified no systemic issues in ALLETE’s accounting practices, and the findings related primarily to differences in interpretation of FERC regulations,” Rutledge said.
Planned reserves will fall below reference margins in MISO and Ontario within the next five years, NERC told the Midwest Reliability Organization in a preview of its Long-Term Reliability Assessment (LTRA) on Tuesday.
Mark Olson, NERC’s manager of reliability assessments, said Ontario, part of the Northeast Power Coordinating Council, will fall below its reference level in 2022, with MISO projected to drop below the threshold in 2025.
“Although MISO is over the reference margin level in 2022, their anticipated reserve margins are falling throughout the [first five-year] period, and they drop below the reference margin level in 2025,” Olson said. But he noted that the RTO has more than 100 GW of planned resources in its interconnection queue and ranks with PJM and ERCOT as having the most solar and wind planned. “Resource and transmission planners can develop these prospective resources to meet their current projected shortfall,” he added.
Olson also noted that MISO is among the areas for which a reduction in expected operating reserves is causing an increase in projected loss-of-load hours in non-peak months.
MISO is among the areas facing an increase in projected loss-of-load hours in non-peak months. | NERC
The LTRA, which considers reliability over a 10-year horizon, will be released next week, after the expected approval Thursday of NERC’s Board of Trustees, Olson said. It will include study process or methodology changes since last year’s assessment. (See NERC Sees Opportunities, Challenges in Grid Evolution.)
MRO heard briefings from all four of its assessment areas: MISO, SPP, Manitoba Hydro and SaskPower.
MISO
MISO’s Stuart Hansen, who also spoke at the MRO briefing, said the RTO is actually projected to fall slightly below its 18% reserve margin in 2024. “But there’s no huge need for concern,” he said. “We will see additional retirements in the coming decade, but we do have plenty of new units that we’re studying in our interconnection queue, which is at record-high numbers right now. So, that will in all likelihood help maintain” the margin.
Planned reserves will fall below reference margins in MISO and Ontario within the next five years, NERC says. | NERC
The RTO’s planning reserve margin increased to 18% from 16.8% in the 2019 LTRA because of changes in load shape, generation verification test capacity, and retirements and new resources, Hanson said.
He said MISO and its stakeholders are addressing any concerns through the resource availability and need (RAN) initiative. He also noted that wind and solar represent 84% of the 104.1 GW in the interconnection queue. The high proportion of intermittent resources “kind of highlights the need for this RAN effort, to make sure that we’re capturing all of our resource adequacy risks accurately and that we’re relaying that information to our members so that they can better plan the system,” he said.
SPP
Chris Haley, senior planning specialist for SPP, said the RTO has seen no major changes since 2019’s assessment, but he noted it continues to add wind, setting a new wind peak of 19,176 MW on Nov. 23. The RTO now has 25.5 GW of wind in total.
Haley also noted SPP’s coordination plan with ERCOT, which addresses operational issues for the DC ties between the Texas and Eastern interconnections. SPP has the ability to recall the capacity of any switchable generation resources that have been committed to satisfy the resource adequacy requirements contained in SPP’s Tariff. “We did have an instance in [summer] 2020 where we did recall some of that capacity,” he said.
The RTO’s 2019 loss-of-load-expectation study results indicates the region may need to increase its current 12% planning reserve margin by 2024 to maintain its one-day-in-10-years metric.
Saskatchewan, Manitoba
Suman Thapa, a senior engineer for SaskPower, highlighted major transmission projects under construction in the province. He said a 230-kV tie line with Manitoba expected in service by mid-2021 “will facilitate our new long-term … contracts with Manitoba.” The company is also testing a new 230-kV phase-shifting transformer on its line to North Dakota, expected in service by March 2021.
In June, Manitoba Hydro placed a 500-kV line from Dorsey (near Winnipeg) to the Iron Range near Duluth, Minn., into service. “That’s a significant interconnection,” the utility’s Kelly Hunter said. “It improved our Manitoba-MISO transfer capability … from an export-import perspective, and we think it adds resilience to both systems.”
The company also is completing work on the Keeyask hydroelectric generating station, a 630-MW addition.
Hunter said the new plant and the additional import capability from the Manitoba-Minnesota transmission line may prompt the retirement of the Selkirk natural gas plant (33 MW summer/118 MW winter).
Unlike its neighbors to the south, the Manitoba system is evolving slowly, Hunter said, and will likely remain dependent on hydropower. Solar PV has become unattractive for the winter-peaking region as incentives have expired and it has added no wind since 2011, he said.
“The economics [for wind] really are not that favorable right now because we already tend to be an exporter,” he said. “Any additional wind we built would probably end up being sold outside the province. And if we sell it into MISO, we’d be competing with wind energy that’s subsidized by the [U.S. production tax credit.] So, it just doesn’t make economic sense for us.”
NERC asked questions for this year’s LTRA regarding regions’ use of inverter-based resources. Almost two-thirds of Manitoba’s resources are inverter-based, including 138 MW of wind, 35 MW solar PV and 4,184 MW of hydro, including Keeyask.
That creates a challenge in ensuring an adequate short-circuit ratio at the HVDC inverter bus, which the company has addressed with 13 synchronous condensers, Hunter said.
The New York State Energy Research and Development Authority (NYSERDA) this month issued a request for proposals seeking contractors to conduct site reuse planning studies for retired power plants.
The $5 million solicitation is just one manifestation of the huge effort the state is mounting to implement the Climate Leadership and Community Protection Act (CLCPA), which requires the state to switch to 100% zero-emission electricity by 2040 and reduce greenhouse gas emissions to 85% below 1990 levels by 2050.
At least 10 state agencies have roles in the transition, led by NYSERDA, the state Department of Environmental Conservation and the Climate Action Council, a 22-member committee that will prepare a scoping plan for achieving the state’s energy and climate goals.
The council’s work will be informed by more than 100 stakeholders — including manufacturers, farmers, generators, labor unions, environmental groups and trade associations — in advisory panels for Agriculture and Forestry; Energy Efficiency and Housing; Energy-Intensive and Trade-Exposed Industries; Land Use and Local Government; Power Generation; Transportation; and Waste. The RFP is related to the work of an eighth group reporting to the council, the Just Transition Working Group, which is considering issues of displaced workers, environmental justice and economic redevelopment.
At a meeting last week, the working group reviewed a straw proposal for the principles the state should follow, which it will present to the council on Dec. 15. In addition to the redevelopment of industrial communities, the 10 principles include topics such as “stakeholder-engaged transition planning”; preservation of culture and tradition; equitable access to “high quality, family-sustaining jobs”; climate adaptation planning; and protection of natural systems and resources.
Support for Power Plant Communities
The RFP is expected to result in $4.75 million in spending on consultants providing affected plant-site municipalities with technical assistance and $250,000 for a site reuse “toolkit” that could be used by other communities.
The deadline for responding is 3 p.m. Jan. 13; an informational webinar for prospective bidders will be held at 10 a.m. Dec. 15. NYSERDA expects to invite communities to apply for assistance in the first quarter of next year.
At the Just Transition Working Group’s meeting Thursday, Steve Ryan, director of business engagement for the state Department of Labor, briefed the panel on the department’s Rapid Response program, which offers résumé development, interview coaching and training opportunities.
Workforce for New York’s traditional power generation (2016-2019) | New York Just Transition Working Group
The department had deployed the program for workers at the Somerset Operating Co., the state’s last coal-fired generating plant, which retired in March, and Indian Point nuclear plant, which shut down Unit 2 in April and will close its remaining unit next spring.
Ryan said the laid off workers appreciate the help. “We provide that hope. Because many of them have no idea where their next employment is going to be,” he said.
James Shillitto, president of the Utility Workers Union of America Local 1-2, which represented 400 workers at Indian Point, said site redevelopment is an easier challenge than retraining laid off workers and finding them new, well paying jobs. “Retraining workers is a little bit more difficult because you have people in various levels of their lives. You have the ones that need to hang on for five or six more years to retire, and the ones that are going to work another 20 to 25 years.”
Gas turbines and steam turbines nearing retirement | NYISO 2018 Power Trends
The state Worker Adjustment and Retraining Notification (WARN) Act requires businesses to give 90 days’ advance notice for large layoffs or plant closures. “Typically, what happens with Rapid Response is it’s triggered by a WARN notice. But in these cases, as with Indian Point, we’re going to know well in advance what’s coming so we should have a framework where we can begin that process without waiting for a WARN notice,” Labor Commissioner Roberta Reardon said. “We need a long runway: as long a runway as we can get with both the employers and the workers to do the kinds of negotiating … or training to really have the best impact.”
Deliverables
Public Service Commission Chairman John B. Rhodes said the working group has two main deliverables, including an inventory of power plants at risk of closing, an effort to identify issues affecting plant site reuse.
The second deliverable is identification of problems and opportunities presented by site reuse. Among the problems: the local economic effects of lost salaries and reduced property tax revenues for local governments and schools. Also to be considered: environmental remediation and restoration.
Plant sites — often on lakes or rivers because of the need for cooling water — can be repurposed as parks or commercial or mixed-use developments. Their access to transmission lines and cooling water has also made them attractive to data centers — a use the owners of the Somerset plant are pursuing. They can also provide interconnection points for new renewable generation.
Jobs Mapping
The state also has begun early work on an assessment of job-loss-threatened power plant workers’ skills to identify retraining paths and match them with job openings in clean energy and elsewhere.
As of 2019, the state had 800 workers in oil-fired generation, almost 5,400 in natural gas and more than 3,800 in nuclear. It also had more than 65,000 workers in transmission and distribution.
As of 2018, 76 of New York’s 106 gas turbines (2,356 MW) were older than 46 years; nationally, 95% of such units have deactivated by this age. Similarly, 95% of steam turbines nationally retire by age 62.5. By that measure, 11 out of 46 units (866 MW) are at retirement age. By 2028, more than 8,300 MW of gas and steam turbine-based capacity in New York will hit retirement age.
About 35% of the state’s generating capacity has been added since 2000. “There’s been in recent years about 2,000 MW of natural gas combined cycle generation [added],” Emilie Nelson, executive vice president for NYISO, told the working group. “The plant staffing required for those types of facilities tends to be lesser than some of the older plants. We have about 2,000 MW of large-scale wind on the system. A lot of the solar that we have thus far is behind the meter, so [it requires] a little different type of support from a job perspective.”
Policy Drivers
In addition to the CLCPA, New York’s transition is being driven by Regional Greenhouse Gas Initiative regulations adopted Dec. 1 to reduce the carbon dioxide emissions cap by 30% from 2020 to 2030. The changes also expand the program to cover peaking units above 15 MW, a reduction from the current 25-MW threshold.
Summer 2020 generating capacity in New York | NYISO 2020 Power Trends
The Department of Environmental Conservation’s “peaker rule” will be phased in between 2023 and 2025, affecting 3,300 MW of capacity. The rule has two compliance options for plants that cannot meet emission limits on pounds of NOx per megawatt-hour: stopping operation during summer ozone season, or replacing their output with energy storage or renewable generation at the same interconnection.
The 2020 NYISO Reliability Needs Assessment identified transmission security needs beginning in 2024 and resource adequacy needs by 2027. The ISO’s first quarterly short-term assessment of reliability (STAR) report found an additional transmission security need in New York City for 2023. In addition, city regulations will bar combustion of Nos. 6 and 4 fuel oil by 2020 and 2025, respectively, affecting 2,946 MW.
“This is manageable if we’re thoughtful and look ahead,” Rhodes said.
Putting it All Together
Lara Skinner, executive director of The Worker Institute at Cornell University, which performs research and education on current labor issues, noted that the Labor Department’s Rapid Response program was created to respond to individual business closures. “When we think about this transition to a zero-carbon economy, we’re taking about a massive transition. A major economic transition with significant labor, social, community impacts — economic impacts,” she said.
Skinner suggested panel members review U.S. Sen. Tammy Duckworth’s (D-Ill.) proposed “Marshall Plan for Coal Country Act,” which would modify bankruptcy rules to require companies that shut down to provide health care and pension benefits to former workers and give free tuition at public colleges for their children.
“Today’s meeting demonstrates to me that there’s some really great thinking happening around the broader impact of the transition in New York state,” Skinner said. “For me, it raises the question of how do we link all of this up? And how do we think bigger and broader about this transition and make sure that our approach to the transition is going to be comprehensive and cohesive?”
