New Jersey Gov. Phil Murphy, who has made fighting climate change a focal point of his administration, announced on Tuesday that the state would invest $100 million in green transportation projects, many of which target disadvantaged or social justice communities.
The money will come from New Jersey’s participation in the Regional Greenhouse Gas Initiative and the state’s share of the legal settlement Volkswagen paid after being caught systematically cheating on air quality tests.
New Jersey is offering $9 million in grants for deployment of electric delivery and garbage trucks, like this Mack Truck with a Heil body. | Heil
Murphy’s office provided a breakdown of how the funds will be allocated:
$9 million in grants for local governments to improve air quality in disadvantaged communities through the deployment of electric garbage and delivery trucks;
$13 million in grants for low- and moderate-income towns to reduce emissions through the deployment of electric school buses and shuttle buses;
$5 million in grants for equitable mobility projects that will bring electric vehicle ride-hailing and charging stations to Gloucester City, Newark, Trenton and Woodbridge;
$5 million in grants for the deployment of fast charging infrastructure at 27 locations;
$36 million to reduce diesel and black carbon emissions in social justice communities by electrifying cargo handling and other medium- and heavy-duty equipment in port and industrial areas;
$15 million toward New Jersey Transit bus electrification; and
$15 million in “flex funding” to further the initiatives.
Jane Cohen, New Jersey Office of Climate Action and the Green Economy | New Jersey Govender’s Office
Murphy, who is up for re-election this year, also signed an executive order establishing the Office of Climate Action and the Green Economy. The department will address the impacts of climate change and transition the state to a green economy while making environmental justice and equity a priority. Jane Cohen, currently Murphy’s senior policy adviser on environment and energy, will be the office’s first executive director.
The Climate Office will also oversee the creation of the New Jersey Council on the Green Economy, which Murphy announced last month in his State of the State Address.
Under the governor’s executive order, the council will compile an initial report on its recommendations for developing a green economy strategy, to be delivered within a year. Ed Potosnak, executive director of the New Jersey League of Conservation Voters called the council’s creation a “terrific idea” that will create “good union jobs that cannot be outsourced,”
“Gov. Murphy’s announcement today gets us one step closer to realizing the 21st-century sustainable green jobs economy that most New Jerseyans say they want — and the future that we and our partners have been calling for,” Potosnak said in a press release.
New York regulators have proposed long-term natural gas planning procedures that could begin to address how utilities balance infrastructure needs with the state’s greenhouse gas reduction goals.
The New York State Department of Public Service (DPS) on Friday released a proposal to require that the state’s 11 local distribution companies (LDCs) file integrated resource plans every three years to supplement annual winter readiness reviews (20-00652/20-G-0131).
The IRPs would be a continuously updated model that considers load, peak demand and costs and investment opportunities for traditional natural gas solutions and for alternatives. Central to the proposal are requirements that the LDCs include “no-infrastructure” options and nonpipeline alternatives to address market demands and system needs.
According to the proposal, no-infrastructure options would include a mix of utility-sponsored demand reduction measures and contingency solutions, such as compressed natural gas or peaking services. In addition, utilities would need to improve infrastructure alternatives, such as energy efficiency, demand response and electrification.
“A comprehensive gas planning process is essential for protecting New Yorkers and ensuring they have the natural gas infrastructure they need and minimizing what they don’t,” said John B. Rhodes, chair of the state Public Service Commission, which will rule on the proposal. “It’s critical to ensuring reliability, keeping costs down and advancing State clean energy policies while combating climate change.”
A proposal for modernizing natural gas planning in New York state could shift some gas investments to renewable heating, such as the heat pump seen here. | Shutterstock
A coalition of clean energy advocates criticized the proposal, saying in a press statement that it does not provide clear metrics for gas reductions or address the needs of environmental justice communities, as required by New York’s Climate Leadership and Community Protection Act (CLCPA).
Some gas utilities in the state have placed a hold on new service connections, citing supply constraints. Those constraints, however, are not going to get any easier under CLCPA targets, and they are leading to customer hardships, according to DPS. (See Study: No Silver Bullet for Fossil-Climate Legal Tension.)
In a March 2020 order initiating a proceeding on gas planning procedures, DPS said that gas planning has not “kept pace with recent developments and demands on energy systems.” The gas planning proposal, released as part of that DPS proceeding, seeks to address multiple, conflicting priorities.
DPS said that utilities need to maintain reliability while adopting improved planning practices to meet current customer needs and minimize infrastructure investments to avoid stranded costs under the goals of the CLCPA.
Michaela Ciovacco, an organizer with New Yorkers for Clean Power, applauded a requirement in the proposal for modeling gas infrastructure investment costs based on fully depreciating them by 2050. Ciovacco said the next step would be to specify when gas infrastructure should be eliminated altogether.
“Without bolder signals that New York is phasing out gas, energy efficiency and clean heating solutions like heat pumps will not be scalable to reach our state’s energy and environmental goals,” Ciovacco said.
New Service Moratoria
DPS on Friday also released a proposal on how utilities impose moratoria on new service connections. The proposal would require LDCs to attempt to offset gas demand through energy efficiency and demand response.
“Moratoria impose significant hardship on customers, and for that reason are a last resort, to be avoided and mitigated to the maximum extent practical,” staff wrote in the proposal, which would ensure consumers have notice of the need for such measures and when they would be implemented.
National Grid’s Brooklyn Union Gas found itself at odds with Gov. Andrew Cuomo in 2019 when the company issued a moratorium on new gas hook-ups that it attributed to supply concerns. The company resumed hook-ups under a settlement with the PSC. (See Online Protesters Reject NY Gas Supply Plans.)
Filing Requirements
The gas IRP process would include stakeholder engagement through technical conferences, comment periods and public meetings.
Each utility’s plan would include a demand forecast with a 20-year horizon, with peak day, peak hour and annual load projections. A supply forecast covering the same 20-year horizon would identify the supply portfolio for everything from pipeline contracts to contingency solutions such as compressed natural gas and demand-side resources such as electrification.
Proposals for new gas pipelines would be allowed within the long-term planning process, but DPS said they should be screened against non-pipeline alternatives. New pipelines that address immediate threats to reliability would be exempt from that screening process.
The proposal calls for “novel approaches” to building the supply portfolio, for example, peak pricing or payments for electric options that reduce gas demand. DPS said utilities should look for market examples of “imaginative solutions to demand-supply gaps,” and identify available renewable natural gas from landfills, wastewater treatment and anaerobic digestion.
DPS acknowledged that while utilities have expressed interest in renewable gas alternatives, “more work needs to be done to specify the environmental, and perhaps other, standards that should be applied to nontraditional methane to qualify a source as ‘renewable gas.’”
As part of its proposal, DPS invited interested parties to propose renewable gas standards in the gas planning proceeding for future commission consideration.
DPS also proposed establishing a best practices working group to calculate the “avoided cost of gas” for comparison with energy efficiency and other purposes. The working group would be open to interested parties but would also include state gas utilities, DPS staff and NYSERDA.
A stakeholder forum is scheduled for 1 p.m. March 25 to discuss the two proposals.
Initial comments on the proposals are due on May 3, with reply comments due June 4.
ERCOT, MISO and SPP cut loads Monday as an unprecedented winter storm shut down wind turbines and fuel shortages idled gas-fired generation, reducing supply in the face of record winter demand.
SPP initiated its first rolling blackouts in its history, while ERCOT did so for the first time in a decade. For MISO, it was the second load-shedding event in less than six months. ERCOT prices have been touching the $9,000/MWh cap since Saturday, while MISO saw prices close to $1,000/MWh.
In a press conference Monday, Dan Woodfin, senior director of system operations, said multiple generators began tripping offline Sunday night in “somewhat rapid progression due to the weather” after the grid operator had set a new winter peak record of 69,150 MW earlier that evening.
At 1:25 a.m. CT, ERCOT declared a level 3 energy emergency alert and asked transmission owners to take 16,500 MW — or about 3.3 million homes — of load offline based on load-ratio-share basis.
About 34 GW was unavailable as of noon, including a significant number of gas units because of restrictions on the gas system and wind facilities because of icing on turbine blades.
“As more generators tripped offline, we had to implement more of these controlled outages to protect the system as a whole,” Woodfin said. “It became such a big number that the transmission providers are having difficulty with their normal rotations. They just don’t have enough options that don’t have critical facilities like hospitals and first-responders. They’ve kind of used all the circuits that they can to balance supply and demand.”
He added that ERCOT has seen a slow down in the number of generators tripping offline. “We don’t think these outages will be multiday outages. We think they should be able to come back in a number of hours.”
The last time ERCOT had to institute rolling blackouts was in 2011, just days before Super Bowl XLV was played in Dallas. In its annual seasonal assessment of resource adequacy for the winter, released in November, ERCOT had said it expected to have enough installed capacity to meet a forecasted 57.7 GW of demand, in part because of a record amount of new wind resources. (See ERCOT: Record 5 GW of Installed Wind Capacity.)
“We are doing everything in our power, not just ERCOT, but the generation owners and the transmission owners, trying to keep the situation reliable,” Woodfin said. “We’re trying to reduce the length of these outages as much as we can to make sure the system as a whole can operate.”
“Every grid operator and every electric company is fighting to restore power right now,” ERCOT CEO Bill Magness said in a statement.
The sustained deep freeze also brought MISO South its second load-shedding event in less than six months.
MISO said the frigid temperatures contributed to generation and transmission outages, leaving it no choice but to direct rotating power outages. The blackouts began Monday morning for some customers in Southeast Texas, MISO said.
“We fully committed every available operating asset before the event to lessen the impact on our system, but conditions eventually deteriorated to a point where demand exceeded supply,” Executive Director of System Operations Renuka Chatterjee said. “The accelerated change in conditions led us to our last resort in order to maintain grid reliability, and we are in direct communication with our members to support their restoration efforts in the affected areas.”
MISO said it consulted with members before the load-shed to identify “the worst-case scenarios to limit the effects of temporary power supply interruptions to those areas that will provide the most relief.” The grid operator said their plan was informed by weather forecasts, predicted demand and worst-case reliability risks. Load-shedding is the last-ditch effort in a MISO maximum emergency event.
“This was truly a coordinated effort with all of our members to avoid a potentially larger grid outage,” MISO South Executive Director Daryl Brown said.
Entergy agreed in a press release that the outages were carried out to “prevent a more extensive, prolonged power outage that could severely affect the reliability of the power grid.” It said its demand had hit an all-time high and that outages could continue throughout the day.
“We apologize for the inconvenience these outages may cause, but we have an unusual situation right now driven by extreme weather conditions. We are working to respond and restore power as soon as it is safely possible,” Entergy Vice President of Customer Service Stuart Barrett said. “While our crews worked to prepare for this storm, a loss of generation combined with the peak load has caused a strain on the system. As a result, we are short of the power needed to meet our customers’ demands across southeast Texas.”
Pricing at MISO’s Texas hub flirted with $1,000/MWh at 10 a.m. ET.
Southern Renewable Energy Association Executive Director Simon Mahan took to Twitter on Sunday to criticize the $37 to $39/MWh real-time pricing across MISO South the morning before the emergency, when temperatures near MISO’s Little Rock, Ark., offices were around 18 degrees Fahrenheit. By 9 p.m., pricing in MISO’s Texas territory hit about $284/MWh, though other parts of MISO South hovered around $45/MWh.
It’s unclear how MISO will price load lost to the winter storm, as it is currently investigating how to better price force majeure events. Stakeholders have told the RTO that it made inappropriate after-the-fact price corrections to the $3,500/MWh value of lost load during and after Hurricane Laura. (See MISO to Outline New Pricing Plan for Hurricanes.)
SPP’s 1st Rolling Blackouts in History
SPP was spared from a load-shedding event until just after noon, when it said regionwide demand had exceeded available generation across its 14-state Eastern Interconnection footprint and its available reserve energy had been “exhausted.”
It is the first time SPP has ever resorted to rolling blackouts.
“In our history as a grid operator, this is an unprecedented event and marks the first time SPP has ever had to call for controlled interruptions of service,” COO Lanny Nickell said. “It’s a last resort that we understand puts a burden on our member utilities and the customers they serve, but it’s a step we’re consciously taking to prevent circumstances from getting worse, which could result in uncontrolled outages of even greater magnitude.”
SPP said it had to interrupt service given the decline in imports from its neighbors. It said it has directed its members’ transmission system operators to reduce electricity demand by an amount needed to prevent further uncontrolled outages.
Speaking in a Monday afternoon press conference, senior Vice President of Governmental Affairs Mike Ross said SPP planned for the weather and projected a new winter peak a week in advance. Ross said he was “pleased” to announce that the RTO only had to direct rolling blackouts for a little under an hour until about 2 p.m. CT.
“It doesn’t mean we’ll stay there,” he warned of SPP’s ability to serve load, citing record-high demand and record-low temperatures. “We’ve been coordinating power since 1941; this is the first time in the history of SPP that we’ve found ourselves in this position.”
SPP said that overall, it was just 641 MW shy of its load obligations.
“I don’t want to trivialize any load shedding,” Nickell said. “It’s unprecedented for us. It’s unprecedented for a lot of the country. … Thankfully it didn’t turn out as bad as we expected, and we’re not out of the woods yet.”
Nickell said SPP members already have plans in place to strategically withdraw load when necessary. “We could very well be in and out of this situation until Thursday,” he added. That proved to be the case, as just this morning, SPP was forced to declare another EEA.
The executives said talk about more stringent reserve requirements will be imminent.
“There’s no doubt there will be a lot of policy discussions forthcoming,” Nickell said.
SPP has canceled several stakeholder meetings over the next few days.
“FERC is closely monitoring the extreme weather conditions occurring in much of the country and the impact they are having on electric reliability,” Chairman Richard Glick said in a press release issued Monday afternoon. “The commission is in contact with ERCOT, SPP and MISO, as the regions served by these grid operators have been particularly hard hit by record cold and wintry precipitation. Safeguarding the reliability of the bulk power system is paramount, and I have directed FERC staff to coordinate closely with the RTOs/ISOs, utilities, NERC and regional reliability entities to do what we can to help.
“In the days ahead, we will be examining the root causes of these reliability events, but, for now, the focus must remain on restoring power as quickly as possible and keeping people safe during this incredibly challenging situation.”
ERCOT staff’s work on summer reserve margins has drawn the attention of NERC executives, CEO Bill Magness told the Board of Directors last week.
“We’ve been talking to NERC about how they want to see a summer assessment identified,” Magness said during the Feb. 9 meeting. “[NERC executives] are looking at whether they want to have people try different ways to measure reserve margins, as we are doing.”
The Texas grid operator’s planning reserve margin for this summer is 15.5%, thanks to large amounts of utility-scale solar resources. That figure, which comes out of the December capacity, demand and reserves (CDR) report, is almost 2 percentage points lower than the May 2020 CDR report, which indicated a planning reserve margin of 17.28%. (See Solar Power Boosts ERCOT’s Reserve Margins.)
Magness attributed much of the decrease to planned project delays in solar development.
“Utility-scale solar can move much faster and be built much faster than conventional units. They’re able to be much more nimble and make decisions later in the planning cycle,” he explained.
The key in ERCOT’s energy-only market is net load, a measure of demand minus expected generation from intermittent resources, Magness said. The grid operator’s Supply Analysis Working Group (SAWG) has begun to study net-load-capacity risks to the CDR. That includes improving CDR methodologies for wind and solar capacity that more closely aligns with their reliability contributions and developing a capacity-contribution methodology for battery energy storage systems.
Staff developed a probabilistic risk assessment model for last summer using ERCOT’s seasonal assessment of resource adequacy as a starting point. The model determines the probability of energy emergency alert events for each hour on peak load days (hours ending 1 to 8 p.m.). Staff and the SAWG will determine the model’s next steps when it is used to support a new requirement to provide resource adequacy risk metrics for the NERC 2021 summer reliability assessment.
“There’s a lot of work to assess the quality of the various reporting mechanisms that assess changes on the grid,” Magness said.
Two additional metrics are ERCOT’s market equilibrium reserve margin (MERM) and the economically optimal reserve margin (EORM), both of which the grid operator reports every two years to the Texas Public Utility Commission. The reserve margin studies analyze scarcity conditions for every hour of the year through 2024, while the CDR measures available resources and demand in the current year’s peak hour.
Astrapé Consulting recently filed a report that indicates a MERM of 12.25% in 2024, up from 10.25% in its 2018 study, and an EORM of 11%.
ERCOT Finishes 2020 with $27.6M Loss
Magness reviewed the 2020 budget and the preliminary 2021 financials during his president’s report, saying ERCOT expects another negative variance this year on top of 2020’s.
According to the final unaudited numbers for 2020, ERCOT took a $27.6 million loss last year, with interest income $15.7 million below budget and a $10.5 million shortfall in the system administrative fee, due mostly to the economic downturn. Interconnection revenues also were under budget, by $900,000. Expenditures were $2.3 million over budget.
ERCOT budgeted an interest rate of more than 2%, which fell to zero under the weight of the COVID-19 pandemic. It projected a 2.25% interest rate this year, which it expects will result in a $19.9 million loss. Overall, the grid operator expects to come in $23.9 million short of its 2021 budget.
The interest rate “seemed like it was low at the time,” Magness said.
Stakeholders will get their first look at the 2022-2023 budget during the April board meeting. Magness reminded those on the phone that ERCOT won’t be asking for a change in its administrative fee, which has remained at 55.5 cents/MWh since 2019.
Magness said 95% of staff continue to work remotely and have had “good luck with health.” ERCOT has requested 210 “essential worker vaccines” for some staff from the Texas Department of State Health Services but has yet to hear back. In the meantime, Magness said it is working with public and private entities to get essential workers vaccinated as soon as possible.
ERCOT will wait until mid-March to next assess when to return staff to the workplace. Any decision will be dependent on the vaccinations’ progress and case counts.
When staff do return to the office, it won’t be long before they move into a new facility. Magness said construction will be complete by year-end on a new, single-story building near its current headquarters. ERCOT will be the only tenant and will have more meeting space than it currently does.
“We’re excited about what we’re going to be able to offer, not only for ourselves, but for the board and stakeholders,” Magness said. “I do hope we have some meetings in the old Met Center.”
ERCOT Projects ‘Just Keep Swimming’
Mandy Bauld, senior director of ERCOT’s Project Management Office (PMO), said her group completed 29 projects during 2020 despite most of the staff working from home with limited personal interaction. The PMO typically runs about 40 active projects each year, worth $60 million, but ran 80 unique projects last year.
“It reminds me of the quote from ‘Finding Nemo,’ which is kind of corny: ‘Just keep swimming,’” Bauld said. “Amid the organization’s shift to working fully remote in March, the organization continues to meet project objectives.”
Topping the PMO’s objectives for 2021 is the Passport Program, which combines the implementation of real-time co-optimization, energy storage resources, and distributed energy resources with ERCOT’s energy management system upgrade. (See “Passport Program Picking up RTC, Energy Storage Work,” ERCOT Technical Advisory Committee Briefs: Jan. 27, 2021.)
The Passport Program faces a 2024 implementation deadline.
She told directors and stakeholders that the first item on her plate is “building connections with all of you,” in addition to ERCOT staff and the PUC.
“Second, I want to prioritize the successful implementation of the key initiatives in the Passport Program,” Talberg said. “So much work went into this last year … I feel fortunate ERCOT is in such a position of strength. This is truly a world-class grid operator, recognized around the world for that.”
Talberg thanked her predecessor, nine-year chairman Craven Crowell, for his mentorship and said she was “drinking by the firehose” as she gets up to speed on ERCOT’s issues.
“I’m fortunate to learn from the founding fathers and mothers of ERCOT,” she said.
Talberg is joined on the board by fellow rookies Raymond Hepper, who retired from ISO-NE as its general counsel, and Just Energy’s Vanessa Anesetti-Parra, who replaces Ned Ross in representing the independent retail electric provider segment.
The directors also confirmed South Texas Electric Cooperative’s Clif Lange as the Technical Advisory Committee’s chair and Just Energy’s Eric Blakey as the vice chair.
Board Approves 17 Protocol Changes
The board unanimously approved 17 revision requests, all but one of which appeared on the consent agenda. Directors unanimously passed the lone Nodal Protocol revision request (NPRR994) that received an opposing vote at the TAC.
The NPRR clarifies which transmission improvement projects associated with the interconnecting new generation resources should be classified as “neutral” projects, including new substations, and delineates which interconnection facilities are considered before ERCOT performs an economic analysis.
The consent agenda included 11 other NPRRs, three revisions to the Planning Guide (PGRRs), and single changes to the Resource Registration Glossary (RRGRR) and the Settlement Metering Operating Guide (SMOGRR):
NPRR1024: authorizes staff to consider significance in determining whether to perform a price correction for the day-ahead or real-time markets, introducing metrics for determining when to perform a price correction or request the board’s approval.
NPRR1034: creates a new protocol section (Frequency-Based Limits on DC Tie Imports or Exports) that enables ERCOT to establish import or export limits on DC ties and avoid the risk of unacceptable frequency deviation during an unexpected loss of one or more DC ties during the import/export. Staff will be able to curtail DC tie schedules on a last-in-first-out basis.
NPRR1040: establishes compliance metrics for ancillary service supply responsibility.
NPRR1044: requires generation resources and ESRs to develop and implement subsynchronous resonance mitigation plans to address vulnerabilities in the event of six or fewer concurrent transmission outages, an increase from the current threshold of four or fewer.
NPRR1048: changes certain required system adequacy reports to being aggregated by forecast zone instead of by load zone. Forecast zones have the same boundaries as the 2003 congestion management zones: North, South, West and Houston.
NPRR1049: removes the requirement to obtain board approval to add, delete or change a DC tie load zone and also removes the 48-month waiting period before such actions can go into effect.
NPRR1050: changes the summer projected commercial operations date deadline to July 1 from the start of the summer peak load season, June 1.
NPRR1051: removes the administrative price floor of -$251/MWh from all day-ahead settlement point prices.
NPRR1052: ensures that energy storage systems registered as settlement-only generators will continue to have their injections and withdrawals settled at load zone pricing until nodal pricing for injections and withdrawals is approved and implemented.
NPRR1053: establishes an exemption from ancillary service supply compliance requirements for any qualified scheduling entity (QSE) representing an ESR whose ability to charge is restricted during a Level 3 energy emergency alert event. The change also clarifies that the compliance exemption does not impact the QSE’s financial responsibility because of the AS insufficiency.
NPRR1054: removes all references to the Oklaunion Exemption from the protocols and adjusts the affected sections’ remaining language accordingly. The coal-fired Oklaunion plant was retired in October.
PGRR085: requires resource entities, interconnecting entities (IEs) and TOs to provide reports benchmarking the power system computer-aided design (PSCAD) model against actual hardware testing. Also requires them to provide parameter verification documentation confirming that model settings match those implemented in the field.
PGRR086: clarifies that resource entities and IEs must provide dynamic model data and model-quality tests to complete a full interconnection study application.
PGRR087: clarifies that remedial action schemes should not be relied upon to resolve planning criteria violations.
RRGRR027: clarifies that resource entities and IEs must provide dynamic model data and model-quality tests to complete a full interconnection study application. PSCAD models should be required before the applicable quarterly stability assessment deadline.
SMOGRR024: makes modifications to accommodate telemetered auxiliary load, allowing sites to comply with NPRR1020.
Washington Gov. Jay Inslee is known nationally as the 2020 Democratic primary candidate almost totally focused on climate change as an existential threat to the world.
During debates and on the campaign trail during his five-month candidacy, Inslee consistently returned to that theme, sometimes even when asked about other topics.
“We are the first generation to feel the sting of climate change and the last generation that can do something about it,” he said in a 2019 video announcing his campaign.
That message could not save Inslee’s candidacy, although President Biden embraced many of Inslee’s stances in early 2020 — far beyond former President Donald Trump, who had denied the existence of climate change.
In an interview with RTO Insider, Inslee said he did not have any major epiphany leading to his intense focus on climate change. He described his interest gradually growing since he was a child. His father was a biology teacher and basketball coach in Seattle. His mother was a sales clerk. He remembers clearing brush and planting trees with his parents around Mount Rainier. As a teen, he would visit a family beach cabin and help Tulalip tribal fishermen haul in nets filled with salmon.
Like his interest in environmental issues, Inslee’s entry into politics was gradual. He was recruited as a successful state legislative candidate in Eastern Washington at the age of 37. He represented that same conservative Washington district in Congress for one term before being unseated. He moved to a more liberal district along Puget Sound where he served seven terms as its congressman.
In 2002, Inslee wrote a column for the now-defunct Seattle Post-Intelligencer arguing that the U.S. needs to tackle global warming and a green economy on the scale of NASA’s Apollo moonshot program. Five years later, he and a collaborator expanded on those thoughts in a book called “Apollo’s Fire.”
‘Unromantic Things’
Inslee has just begun his third term as Washington’s governor. He has been pursuing a climate change-oriented agenda for the past eight years but has clashed with a Republican majority in the state Senate. Meanwhile, Inslee always had a slight Democratic majority in the House of Representatives, a coalition that had to walk a tightrope between urban liberals who embrace most measures to combat climate change and more environmentally cautious suburban and rural Democrats who live in more politically purple districts.
Higher temperatures in the state have harmed its shellfish; rendered inland salmon habitats more inhospitable, affecting Puget Sound orcas; altered snow melts in the Cascade Range, which has complicated irrigation in Eastern Washington; and made forests drier and more susceptible to fires. And increasing temperatures have affected the state’s wine industry, whose grapes grow best within narrow ranges of temperatures. Health officials have also linked carbon emissions in the air to increased asthma and other lung problems.
Starting in 2018, Democrats began winning several previously Republican suburban seats. Today, Democrats hold a 57-41 majority in the House and a 28-21 majority in the Senate — giving Inslee his best chance to pursue his often stalled climate change agenda.
This session, Inslee’s agenda is to:
cut carbon emissions from gasoline and diesel fuel sold to Washington motor vehicles by 10% below 2017 levels by 2028 and by 20% by 2035.
push electrification of vehicles and ferries. Bills are in play to accomplish these goals, including encouraging an eventual switchover from gas to electric vehicles. (See Wash. EV Bills Spark Concern About Buildout.)
put caps on industrial carbon emissions and encourage investments in green projects, a complicated undertaking for the past few years. The bill tackling the topic this session is currently being rewritten. (See Cap-and-trade Bill Emerges in Wash. Senate.)
create an Environmental Justice and Equity Advisory Panel to advise him and the legislature on how to allocate money from the proposed cap-and-invest program to communities burdened with pollution troubles.
require new commercial buildings to use carbon-free space and water heating by 2030 and start decarbonizing all existing buildings by 2050. A bill is in play to begin those efforts.
Inslee has not given detailed thought yet to which measures he should tackle in the second half of his term. “We’ve been focused just on this session so far,” he said.
However, he said many of these future efforts will be “unromantic things,” such as making buildings more energy-efficient, boosting public transportation, building charging stations, developing bike trails and tweaking water spillage over dams to prevent killing young salmon by increasing the nitrogen levels in their tissue.
“We need to reduce the per-capita use of electricity. … Most houses and buildings are not designed for a carbon-free world,” Inslee said.
Balancing Act
A common criticism of measures dealing with climate change is that they kill jobs. Washington is the home to five oil refineries. Inslee has been a big booster of creating renewable energy jobs. So far, the state has not looked at how renewable energy jobs might rise, while oil and natural gas jobs might shrink in Washington. “We have not done an algorithmic assessment on that,” Inslee said.
He added that renewable energy jobs are growing at a faster pace than average jobs.
The International Renewable Energy Agency last year reported that the renewable energy sector employed about 756,000 people in the U.S. in 2019. Another 2.38 million people hold jobs relating to energy, according to a joint report from the National Association of State Energy Officials and the Energy Futures Initiative. At the same time, slightly more than 1 million Americans are employed in the oil, gas and coal industries.
Meanwhile, the U.S. Bureau of Statistics recently noted that wind turbine technicians are the fastest growing occupation in the nation, increasing by 61% from 2019 to 2020. Solar panel installers are the third-fastest growing occupation, increasing 51% in that same period. A U.K. Energy Research Centre report said that it will take two to five renewable energy jobs to produce the same power created by one fossil fuel worker.
“We know the fossil fuel industry is going to decline,” Inslee said.
Washington is the home to numerous hydroelectric dams and one nuclear reactor — both carbon-free power sources.
However, reactors nationwide have had trouble competing financially with natural gas as a source of electricity, leading to several being closed. And Puget Sound liberals have strong anti-nuclear sentiments.
In addition, the state’s relationship with its dams is complex. Though these resources provide cheap electricity and irrigation water for crops, they decimate inland Northwest runs of young salmon migrating to the Pacific Ocean. For at least 30 years, Northwest interests have clashed over whether the four Snake River dams between Lewiston, Idaho, and Pasco, Wash., should be removed.
On Feb. 6, Rep. Mike Simpson (R) proposed legislation that would remove the four dams and require the power, barging and irrigation benefits be replaced. This is the first Republican proposal to remove the four dams.
Consequently, removing dams will affect the bigger decarbonization picture in the Northwest and will provide a complicated balancing act for Washington’s leaders.
“We don’t want to wall off any potential energy source,” Inslee said.
PJM delayed an endorsement vote on an issue charge regarding the allocation of capacity transfer rights (CTRs) for a month after stakeholders raised questions over the initiative’s scope and potential impact.
Kevin Zemanek, director of system operations for Buckeye Power, reviewed the problem statement and issue charge by the Ohio-based company during last week’s Market Implementation Committee meeting, saying current rules are exposing his cooperative to price separation.
Under the Reliability Pricing Model (RPM), CTRs return to load-serving entities (LSEs) capacity market congestion revenues that occur when there is a difference between capacity prices paid by load and market revenue received by cleared capacity resources. CTRs permit LSEs with load inside a constrained locational delivery area (LDA) to receive a credit for the import of capacity from a lower-priced region.
Zemanek said PJM does not have a way to allocate CTRs to an LSE that corresponds to the network load identified in its network integration transmission service agreement. Instead, PJM allocates CTRs pro-rata to each LSE serving load in the LDA or zone based on the LSE’s share of the zonal unforced capacity obligation.
Although an LSE may have resources that are deliverable to load inside the constrained LDA, current rules do not allocate an equivalent number of megawatts, Zemanek said.
Buckeye Power has been harmed because the existing RPM rules disregard the “historic structure” of Buckeye and Ohio TO’s, Zemanek said, leading to “millions of dollars” in excess charges.
He added that Buckeye seeks to explore market rule changes that would account for resources within PJM’s footprint that existed prior to the implementation of RPM.
“We’re asking the committee to consider a rule change that would account for historic resources internal to PJM’s footprint and have the deliverability to designated load,” Zemanek said.
He said he anticipates two months of education followed by discussions on potential rule changes.
Paul Sotkiewicz of E-Cubed Policy Associates said he’s inclined to support the problem statement to start the discussion, but one of his concerns would be adding to the key work activities on how incremental capacity transfer rights (ICTRs) would be impacted by any changes.
Zemanek said Buckeye didn’t intend to have ICTRs impacted by the issue charge and was not looking to impact any existing contractual rights.
Sotkiewicz asked if Buckeye would be open to a friendly amendment to look at the potential impact to ICTRs, but Zemanek said he wasn’t sure if the issue charge needs to be changed.
Sotkiewicz said he doesn’t see a way to address CTRs without also addressing ICTRs.
“Some of us have felt like we’ve gotten burned on issue charges where we think topics are in scope and then we’re being told they’re out of scope,” Sotkiewicz said.
Jeff Bastian, PJM senior consultant in market operations, said the CTRs that Buckeye is considering allocating are those remaining after ICTR megawatts are determined. Bastian said there would be no impact on the ICTR calculation from the issue charge.
One stakeholder questioned language in the issue charge, saying it seemed to find a way to allocate CTRs to entities like Buckeye while leaving other issues “undisturbed.” He said he’s not sure there’s a way to allocate the CTRs without disturbing the existing system.
Independent Market Monitor Joe Bowring said the Monitor is “skeptical” about introducing a contract path as the basis for the rights to CTRs.
Lisa Morelli of PJM suggested deferring the endorsement vote until the March MIC meeting to allow for refinements to the issue charge and problem statement from the stakeholder feedback about what is in scope and out of scope.
Capital Recovery Factors Discussion
Bastian provided a second first read of the problem statement and issue charge to regularly update the value of capital recovery factors (CRFs) based on current federal tax rates. CRFs are a component of the net avoidable cost rate (ACR) of a resource, which determines a resource’s market seller offer cap or minimum offer price rule (MOPR) floor price, depending on which is applicable.
Proposed table in Attachment DD of the tariff of CRF values for resources to calculate the market seller offer cap or the MOPR floor offer price | PJM
The Monitor notified PJM in a letter Dec. 4 that the CRF values, which were set in 2007, do not reflect the 2017 reduction in federal corporate tax rates.
The RTO has proposed to address the CRF issue as part of a quick fix process in which the MIC would simultaneously approve the issue charge and the proposed tariff revisions at the March 10 meeting.
The Monitor said the tables should have been updated in 2018 and must be changed before the next capacity market auction, for the 2022/23 delivery year, takes place in May. The RTO said it was concerned that seeking an earlier effective date would further delay the auction, which was originally scheduled for 2019. (See PJM Sets BRA for May 2021.)
The RTO said it agrees with the Monitor that offers including the avoidable project investment rate in net ACR values are unlikely to impact the May auction results.
PJM proposed that after the upcoming auction, the table of CRF values be posted on the PJM website no later than 150 days before the beginning of the offer period of each auction. The values would reflect federal income tax laws in effect for the relevant delivery year at the time of the determination.
Bastian said PJM revised its initial proposal to reflect feedback at the January MIC meeting, when stakeholders requested more transparency in the key input assumptions. (See “Challenge on CRF Quick Fix,” PJM MIC Briefs: Jan. 12, 2021.)
Sotkiewicz thanked PJM for listening to the stakeholder feedback and said the changes reflected much of the discussions. He said the only potential concern he had was making the formulas used to calculate the CRFs accessible on PJM’s website rather than stated as a “generic financial model.”
Erik Heinle of the D.C. Office of the People’s Counsel said PJM was able to come up with a “reasonable solution” that addresses concerns of not falling behind in tax laws and constantly trying to catch up with changes.
Aaron Baizman, senior engineer for PJM, reviewed the solution package matrix for the long-term five-minute dispatch and pricing issue worked on in the MIC special session meetings and said an endorsement vote on the PJM/IMM package would be delayed until the March MIC meeting.
Baizman said PJM wants to take a “measured approach” for the implementation of the long-term evaluation of five-minute dispatch and pricing, especially with the number of changes affecting dispatch.
Stakeholders approved the short-term proposal to resolve five-minute dispatch and pricing at the July MRC meeting. The RTO had said it expects to continue evaluating long-term solutions late into this year, with a quantitative analysis of the pros and cons of different approaches. (See PJM Stakeholders OK 5-Minute Dispatch Proposal.)
Baizman said highlights of the long-term package include real-time security-constrained economic dispatch utilizing previous generator dispatch instructions to create guidelines. PJM dispatchers will also be provided flexibility for exceptions for case approval caused by unanticipated conditions or application issues.
A first read of the proposed tariff language was also moved to the March 24 Markets and Reliability Committee meeting. Baizman said PJM and the Monitor are still reviewing the tariff changes, and a review of the draft tariff language will be held at the five-minute dispatch and pricing special session on Wednesday.
Baizman said the current long-term timeline calls for software development until April, testing of the software from May to June, parallel operations and evaluation from July to September and a pilot evaluation and implementation by Nov. 1.
Stakeholders last week endorsed PJM’s packages of proposals for mitigating and avoiding designating projects as critical infrastructure under NERC reliability standards after more than a year of work on the issues.
The Planning Committee endorsed the avoidance package, including associated manual language, with 77% support at its meeting last week. In a separate vote, the package won 61% support over maintaining the status quo.
The committee also endorsed PJM’s mitigation package with 61% support and 60% preferring it over the status quo.
Dave Souder of PJM thanked members for their work on the proposals and for the endorsements. He said PJM will take at least a month to finalize Operating Agreement language to be included with the mitigation portion, with a first read at the Markets and Reliability Committee’s meeting March 24.
“We’re not done yet, but we’re on the right path,” Souder said.
Mike Herman of PJM presented the proposals to the committee. The changes to Manual 14B include the addition of a new subsection describing the process related to maintaining reliability and added “avoidance” to the list of transmission planning activities.
PJM also added text to Manual 14F detailing the process by which it may modify a proposal submitted through the competitive planning process. Herman said PJM removed the term “resilience” from all the manual language edits in favor of the term “critical substation planning analysis” in response to stakeholder feedback at the January PC meeting. (See “CIP-014 Update,” PJM PC Briefs: Jan. 11, 2021.)
Other changes included new text detailing the process by which PJM may modify a proposal submitted through the competitive planning process and includes examples of proposal modifications that would and would not be deemed “limited in scope.”
Paul Sotkiewicz of E-Cubed Policy Associates pointed out that the term “resilience” was still included in at least one section in Manual 14F and should be corrected by PJM before endorsement.
“I think consistency is really important in the language, especially when it comes to the transmission planning between the different manuals,” Sotkiewicz said.
PJM’s Aaron Berner said it appeared the existence of the “resilience” terms in the manual language was an oversight and would be corrected.
The RTO will hold a special PC meeting on Feb. 19 to go over the proposed OA language for the mitigation portion of the package. Herman said the major language change was the addition of a definition for substation contingency resilience planning criteria: “analyses performed to ensure system resilience based on a study of select substation contingencies, which are based upon TPL-001-4 Extreme Contingency Analysis. The analysis evaluates the loss of load and potential cascade events which may result from power flow analysis. Due to the sensitive nature of the analysis, identified substations and results require confidentiality consistent with established processes and good utility practice.”
Flow chart for “Substation Contingency Resilience Planning” within mitigation efforts for the PJM proposal on future CIP-014 facilities | PJM
Robert Taylor of Exelon said he appreciated the work that went into the packages and that it was “a long road to get here.”
“I personally believe we’ve landed in a good place that balances a lot of competing interests in how to address this,” Taylor said.
Capacity Interconnection Rights
Jonathan Kern of PJM provided a first read of the problem statement and issue charge to address the capacity interconnection rights (CIRs) of variable resources.
Kern said the recent adoption of effective load-carrying capability (ELCC) highlighted the need to investigate the topic. Stakeholders endorsed a revised joint stakeholder proposal at the September MRC and Members Committee meetings to use the ELCC method to calculate the capacity value of limited-duration, intermittent and combination (limited-duration plus intermittent) resources. (See ELCC Method Endorsed by PJM Stakeholders.)
ELCC, which is already used by MISO, NYISO and CAISO, evaluates reliability in each hour of a simulated year and compares a resource mix with limited resources against one with unlimited resources.
Kern said CIRs for new wind and solar resources are administratively set for several years at the average expected outputs for the summer period unless developers can supply weather data to support higher outputs. CIRs for new limited-duration resources such as storage are administratively set based on the amount of energy that can be supplied over a 10-hour period, he said.
CIRs are not included in ELCC calculations or in determining accredited unforced capacity (UCAP). Kern said sizing the grid for CIRs based on outputs below maximum summer values may result in curtailments because of insufficient transmission, and resource adequacy performance and accredited UCAP may be overstated unless CIRs are considered.
Kern said PJM’s goal is to hold a series of monthly discussions with the PC and to develop and propose changes to the applicable manuals and governing documents by the end of the year. He said PJM will hold educational sessions and discuss and develop proposals from April to October and ideally present a proposal to the MRC in November.
Gary Greiner, director of market policy for Public Service Enterprise Group, said PJM’s presentation seemed “a little bit off” from what he expected to be discussed and that it’s not good to have stakeholder discussions “start on second base.” Greiner said there needed to be more foundational education pieces on the CIR issue, focusing on CIRs and what their rights and purposes are in traditional and intermittent resources, not diving into specifics from the beginning.
Greiner said the only point he’s comfortable with in the key work activities and scope on the issue charge is education on the status quo policies for CIRs.
Kern said PJM’s intention is to give a “good foundation” on the status quo policies of CIRs during the educational sessions.
Sharon Midgley of Exelon said she had additional questions on the issue charge. She pointed to subject areas deemed to be out of scope in the issue, including provisions for unlimited resources.
Midgley said Exelon realizes the CIR effort is to look at variable resources, but it wants to make sure there is “equity” in the rules between variable and unlimited resources. She asked PJM to strike the unlimited resources subject area from the out-of-scope section.
Kern said PJM wants to achieve the objectives in the allotted time, so a topic like unlimited resource CIRs would be considered out of scope. He said there may be other issues identified during the discussion that warrant a separate problem statement and issue charge.
“In the end, we want to find an equitable solution that works for all resources,” Kern said.
Midgley said she doesn’t want to have to bring forward another problem statement and issue charge “to fix something that might be inequitable” that emerges from the process. She said she would rather change the current problem statement and issue charge to leave the opportunity to examine unlimited resources if it’s needed.
Sotkiewicz said he agreed with the concerns raised by Greiner and Midgley. He said there are already issues he anticipates that will be brought up in the way CIRs and dispatch are done that will create inequitable outcomes among different resources.
He said there are too many issues that are “left to the imagination” that need to be spelled out more clearly in the problem statement and issue charge and that too many of the issues are “open ended.”
“I think the issue charge as it stands today is not ready for prime time,” Sotkiewicz said.
PJM encouraged stakeholders to provide redline language before the next PC meeting to address concerns in the problem statement and issue charge.
TO/TOP Matrix v15
Stakeholders unanimously endorsed a draft version 15 of the TO/TOP Matrix to be provided to the Transmission Owners Agreement-Administrative Committee (TOA-AC). Mark Kuras, chairman of the Transmission Owners/Transmission Operator (TO/TOP) Matrix Subcommittee, presented the proposed changes.
The matrix is an index between the PJM manuals and governing documents and NERC reliability standards that are applicable to the RTO as the TOP. It includes a column of “tasks” required by PJM under the documents. Kuras said version 15 of the matrix adds references for reliability standards, including TOP-001-5.
The endorsed changes will head back to the TOA-AC for final approval at its April 22 meeting.
Transmission Expansion Advisory Committee
Technological Pilot Project
Map of PEPCO region where Exelon is examining the installation of an experimental coated conductor | Exelon
Exelon is looking to test an experimental coating for overhead conductors to improve capacity. Koushy Nareshkumar of Exelon presented a need for supplemental projects in the Potomac Electric Power Co. (PEPCO) region.
Nareshkumar said Exelon is testing the “innovative technology” of E3X Technology, a coated conductor, to increase circuit rating. Conductors with the coating have shown to have increased emissivity and lower absorptivity. The technology allows for operation with a cooler conductor at higher ampacity, the maximum current a conductor can carry continuously without exceeding its temperature rating.
Erik Heinle of the D.C. Office of the People’s Counsel asked if Exelon’s project was being introduced through a state initiative or if it was just looking to test the technology. He also asked if the technology had been used anywhere else by Exelon.
Nareshkumar said Exelon was taking the initiative to test the technology themselves and that it was the first time E3X was being utilized. She said Exelon is still in the process of determining what line will be used for the project, but it will be on one of its 230-kV lines in PEPCO.
PJM is looking to improve the deployment of synchronized reserves during a spin event, but some stakeholders are questioning whether the timing of the issue is appropriate given major changes in the reserve market next year.
Mike Zhang, PJM senior engineer of markets coordination, provided a first read of a problem statement and issue charge during last week’s Operating Committee meeting.
Synchronized reserve events are emergency procedures triggered by PJM to maintain grid reliability in accordance with NERC’s Resource and Demand Balancing (BAL) standards. Such procedures are caused by a variety of conditions, including loss of generation by multiple units going offline at the same time or a sudden influx of load.
Zhang said real-time security-constrained economic dispatch (RT SCED) cases are generally not used by PJM during an emergency event, which can lead to problems like unpredictable levels of unit response and a mixture of over- and under-response across various units.
Zhang said PJM dispatchers have been seeing a pattern of a slow initial recovery period followed by extended over response after the emergency event is over. Because tools like RT SCED are not utilized during an event, Zhang said, pricing and dispatch signals are still from a pre-event RT SCED case and often conflict with all-call instructions because the signals don’t go away immediately.
PJM control room | PJM
PJM is looking for controlled deployment of synchronized reserves throughout emergency events by utilizing tools like RT SCED to have consistent pricing and dispatch signals. The goal is to also ensure BAL compliance during recovery and a reliable transition in and out of emergency events.
Key work activities include review and education on existing actions and expectations for synchronized reserve events, and analysis of metrics and data on previous emergency events. PJM also wants to develop solutions and timelines for the overall synchronized reserve deployment process, including the deployment method, the expectations of resources and the evaluation of performance.
The existing performance penalty structure is not in scope for the issue, Zhang said, as PJM views it is adequate.
“We have a variety of metrics and historical data to draw from, and hopefully we can utilize that to get us started,” Zhang said.
PJM’s proposed approach to the issue calls for convening a task force within the OC to recommend potential changes to resource expectations during events. The estimated work schedule is between six to 12 months after endorsement.
One stakeholder said the timing of the work by the task force may be complicated by PJM’s revised operating reserve demand curve (ORDC), set to go into place by the middle of 2022. The stakeholder said he’s hoping the price signals from the ORDC will change whether the events PJM are worried about will even need to be called. (See FERC Approves PJM Reserve Market Overhaul.)
“I’m not sure that you need to still do all-calls, or at least the need would be different,” he said. “And I don’t see that anywhere in the issue charge.”
Zhang said PJM still believes the effort is beneficial even with the ORDC changes. He said those “hit at different areas” of the synchronized reserve market. This proposal revolves around the deployment of reserves, while the ORDC involves how those reserves are procured and priced, he said.
The stakeholder said he believes PJM’s analysis of the ORDC only impacting procurement and pricing is “strongly incorrect” and that all the issues are intertwined more closely. He said the key work activities should at least include an educational piece on how all-calls would work in an environment of the ORDC coming into play next year.
Adrien Ford of Old Dominion Electric Cooperative said she understood the stakeholder’s concerns and thought having education on the impact of the ORDC was important. Ford said the reserve price formation changes set to go into effect next year are “pretty sweeping,” and education should be included in the issue charge.
“Issue charges are to explore what we need to do and not a foregone conclusion that the change would occur,” Ford said.
Stakeholders will vote on endorsement of the problem statement at the March 11 OC meeting.
Manual 40 Changes Endorsed
Stakeholders unanimously endorsed a minor change to Manual 40 as part of the periodic review.
Michael Hoke of PJM reviewed the update Manual 40: Training and Certification Requirements. In section 3.2.1: Transmission Owner Operators, a reference was added to the annual training requirements referenced in NERC standards. A second reference was added regarding using the PJM Learning Management System to track the annual task training requirement.
Hoke said the change was based on feedback from ReliabilityFirst, which expressed a desire to “see a more explicit connection” between Manual 40 and standard requirements in the matrix for transmission owners.
Resource Tracker Quick Fix
Chris Franks of PJM reviewed a “quick fix” problem statement and issue charge to update language in Manual 14D regarding the Resource Tracker application’s ownership confirmation requirement.
Franks said PJM members are responsible for maintaining complete and accurate records as stipulated in section 11.3.1(a) of the Operating Agreement. The Resource Tracker application was created in 2013 to provide a single-point location for generation owner information, Franks said, and stakeholders endorsed changes in 2018 to move the confirmation period to an annual basis with a four-week duration to enter correct information in the application. (See “Resource Tracker,” PJM Operating Committee Briefs: Nov. 6, 2018.)
The 2020 annual confirmation period opened on Oct. 1 and closed on Nov. 1, Franks said, with a total of 1,503 resources requested to confirm information. Of those resources, 60 did not confirm by Nov. 1. As of Feb. 1, four have yet to confirm information.
Franks said PJM is looking to refresh the user interface of the application to reflect similar tools used by the RTO and to add additional fields to provide contacts associated with the resources.
The proposed manual language includes changing “market participants are requested” to the “generation owner, or designated agent, is required” to confirm the resource ownership by Nov. 1.
The OC will be asked to approve the issue charge and endorse the proposed revisions as part of the “quick fix” process at the March meeting.
Energy officials in New England are concerned that ISO-NE’s transmission planning process cannot adapt to the evolving resource mix, the growing investments in clean energy and the decarbonization of the grid. Without more robust transmission planning, they said, ratepayers in the region likely face higher costs and lower reliability, plus potential curtailment of the renewable resources needed to meet state policy goals and mandates.
Here is some of what we heard during a public online technical forum on Feb. 2, organized by New England states, to discuss reforms to the RTO’s transmission planning process.
Long-term Tx Planning ‘Key’
New Hampshire Public Utility Commissioner Kate Bailey said the region’s clean-energy transition requires “significant new investments” in renewable resources that are unlikely located close to load centers.
Bailey said changes resulting from an expansion of distributed energy resources, energy efficiency, electrification of the transportation and heating sectors and, “retirement of a good portion of the fossil-fired fleet” would likely produce “very different power flows across the grid of the future compared to today’s grid.”
“Two-way flows of power are likely to be much more common than they are today, which will make the transition even more complicated,” Bailey said. “All of this will require substantial additional spending on new transmission lines and upgrades to existing lines to accommodate the new, remotely located clean resources.”
According to Bailey, the region must complete the transition within a relatively short time, and “our goal should be to accomplish the transition at least cost for ratepayers.”
New England states have decarbonization targets of 30 to 45% by 2030 and 80% or net-zero by 2050.
Bailey said that “long-term transmission planning, which factors in the state’s collective requirements, is key.” One way to limit higher costs for ratepayers, she said, is to require competitive solicitation for all transmission construction, not just those projects that address reliability, and she hopes that “changes made to the process will require that.”
Judy Chang, undersecretary of energy for the Massachusetts Executive Office of Energy and Environmental Affairs, said the region could not afford to continue the traditional way of developing transmission by reacting to interconnection requests or conducting reliability upgrades.
ISO-NE, Eversource Weigh in
Robert Ethier, ISO-NE’s vice president of system planning, said the grid is “undergoing as big a change as it’s experienced in the last several decades.”
Ethier said the RTO’s transmission planning process has been driven by addressing reliability needs and the interconnection of new resources. The integration of renewables and storage to meet state public policy initiatives “in a timely and efficient way” will require new planning, approval and funding approaches, he said, along with greater engagement with both states and NEPOOL stakeholders.
Breakdown of the new resource proposals in the ISO-NE interconnection queue | ISO-NE
Bill Quinlan, president of transmission for Eversource Energy, said that an effective long-term transmission planning process is essential — especially when examining the timeline to execute major upgrades — to achieve decarbonization goals.
“It’s clear to us that to deliver the clean energy future that we’re all seeking … we need to take a hard look at the long-term planning process,” Quinlan said. And “that planning process needs to begin now. We need to then look for alignment with key policies, whether it’s at the federal level … or the state level. With good involvement by the stakeholders, I think we will be able to deliver that grid of the future that will enable the clean energy future we are all seeking.”
‘The Benefit of Consumers’
Rebecca Tepper, chief of the Energy and Telecommunications Division in the Massachusetts Attorney General’s Office, said she “wanted to remind everyone” that the transmission system “was built for the benefit of consumers, and every penny of it was paid for by consumers, either directly or indirectly.”
“Over the last 10 years, New England ratepayers have spent $11 billion to develop and upgrade our transmission system,” Tepper said.
There are planned transmission upgrades “that will cost billions more,” so she said it is vital that the region makes “the best use of the transmission systems that customers have already paid for.”
“Right now, the overall utilization of our transmission system is actually low,” Tepper said. “Think about your car … you probably only use 10% capacity of your car, but it’s still really valuable when you want to drive it somewhere. …
“More efficient use of transmission lines can help save money by avoiding congestion, but it also can help integrate new kinds of uses like electric vehicles at lower costs,” she said.
Next Steps
Chang requested written comments on the forum’s topics and discussions. Those comments will be accepted through March 1 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.
State officials have scheduled additional technical forums on governance reform (Feb. 25) and environmental justice (TBD).
Nevada lawmakers are planning to introduce an array of clean energy bills during the 2021 legislative session, including a measure that could pave the way for a massive expansion of electric transmission in the state.
Sen. Chris Brooks | Nevada Legislative Counsel Bureau
Sen. Chris Brooks (D) is crafting a bill that he says would incentivize and prioritize new electric transmission in the state, potentially creating about $10 billion worth of investment in clean energy.
“I’m really looking forward to being able to expand the clean energy opportunities in the state of Nevada through transmission investment,” Brooks said during a meeting this month hosted by the Nevada Conservation League. “I think it’s long overdue.”
Brooks told RTO Insider that he’s still working with stakeholders to hammer out details of the bill, which had not yet been introduced. While specifics of the proposal were not yet available, he said the incentives are not likely to be financial. Instead, the bill would provide ways to facilitate new transmission projects.
Transmission won’t be the only focus of Brooks’ omnibus legislation, which the senator informally called his “big energy bill.” Other components will include plans for electric vehicle charging infrastructure and measures that would create rooftop solar energy opportunities for renters and multifamily housing residents.
Another piece of the legislation aims to align electric utilities’ integrated resource planning process with the state’s carbon reduction goals.
“It won’t just be the renewable portfolio standard anymore that is guiding how we invest in clean energy in the state,” Brooks said. “We’re actually going to use the carbon reduction goals of the state to guide clean energy investments.”
| DOE
The Nevada legislature, which meets every other year, convened on Feb. 1 for a session that will run through May 31. Brooks and other lawmakers outlined their clean energy plans during a Nevada Conservation League meeting on Feb. 1, held via Zoom.
Although lawmakers are grappling with the COVID-19 pandemic’s economic impacts, they said they are still determined to make progress toward climate objectives this session. Nevada has set a goal of net-zero greenhouse gas emissions by 2050.
“Even in the midst of a pandemic, even in the midst of a massive economic downturn, we can take advantage of this legislative session to move the ball forward on climate and also create jobs — good-paying jobs — and tax revenues,” Brooks said. “We can achieve all of the goals at the same time.”
‘Classic Car’ Loophole
In addition to Brooks’ energy bill, Assemblyman Howard Watts (D) is planning a bill to reduce vehicle emissions by closing what’s been called the state’s “classic car” loophole.
The state allows cars that are 20 years or older to be registered as classic vehicles, which exempts them from smog checks. Critics point to cars that many people wouldn’t consider a classic — such as a 2000 Honda Accord — which may qualify for the exemption and remain on the roads as gross polluters.
Assemblyman Howard Watts | Nevada Legislative Counsel Bureau
Watts said his bill would not only close the classic car loophole but also increase smog check fees to raise funds for a variety of programs. Those would include assistance to low-income residents to repair their cars to meet emission standards or even to buy a new electric vehicle.
Chispa Nevada, a Las Vegas-based environmental conservation organization, has championed the proposal.
“We like the idea of creating/identifying funds for programs that help low-income customers repair their polluting vehicles or replacing them with cleaner versions like … low- or zero-emission cars,” Program Director Rudy Zamora said. “Oftentimes when we talk about electric vehicles, we forget about our communities — low-income communities, communities of color.”
Natural Gas Under Scrutiny
The Natural Resources Defense Council (NRDC) is also crafting legislation for the 2021 session.
One proposed bill calls for increased scrutiny of investments in natural gas infrastructure.
“As Nevadans use less methane gas in homes and businesses … gas utilities are at risk of wasting ratepayer money on unnecessary construction projects,” said Dylan Sullivan, a senior scientist with the NRDC. Sullivan said Assemblywoman Lesley Cohen (D), had agreed to sponsor the bill.
NRDC’s second piece of proposed legislation would focus on energy efficiency programs. Although NV Energy runs a number of such programs, Sullivan said the utility is not doing enough. The bill would make some energy-savings targets mandatory and increase targets for programs geared toward low-income residents. The bill would also give regulators the option to designate a third party to run the programs.
Two bills are likely to come out of the Legislative Committee on Energy, a panel of six lawmakers that meets between legislative sessions to discuss energy matters. Assemblywoman Daniele Monroe-Moreno (D) chairs the committee, and Brooks is vice chair.
One of the committee’s proposals would amend the Nevada constitution to allow proceeds from gas taxes or vehicle license and registration fees to be used for transit projects. Currently, the use of those funds is restricted to the construction, maintenance, operation and repair of public highways.
The second proposal would establish a working group to develop preliminary plans for a sustainable system of transportation funding. The group would study topics including the needs of bicyclists, pedestrians and transit users, as well as ways to reduce transportation-related GHG emissions.
