Page 981 – RTO Insider

February 14, 2021

Grid Operators Face Historic Arctic Blast

Extreme winter weather has placed much of the country’s heartland in a deep freeze, from Minnesota to Texas, and left grid operators scrambling to meet anticipated record winter demand.

MISO, SPP and ERCOT all declared conservative operations and issued other advisories in advance of the storms, which hit Sunday night and are expected to last through much of the week. SPP was the first to declare an energy emergency alert (EEA), issuing a Level 1 alert on Sunday to be effective at 5 a.m. CT Monday.

All three grid operators are expecting record winter peaks in at least a portion of their footprints, with consumers shut in by snow, ice and sub-freezing temperatures.

Wind turbines have been shut down, and gas prices on the region’s spot market have surged to as high as $600/MMBtu, driven by curtailed production and increased heating demand.

Grid Operators Arctic Blast — Extreme winter weather has led to outages throughout the Great Plains. | *Xcel Energy*

ERCOT, expecting to set a new all-time winter peak this week in the face of the state’s lowest temperatures since the 1980s, asked consumers on Sunday to reduce their usage or face the possibility of emergency measures. Among the options in its toolbox are rotating outages, last used during scarcity conditions in early February 2011. (See ERCOT Bracing for Winter Storm, Record Demand.)

Demand was 64.7 GW for the interval ending at 3 p.m., close to the all-time peak of 65.9 GW set in January 2018.

“We are experiencing record-breaking electric demand due to the extreme cold temperatures that have gripped Texas,” ERCOT CEO Bill Magness said in a statement. “At the same time, we are dealing with higher-than-normal generation outages due to frozen wind turbines and limited natural gas supplies available to generating units. We are asking Texans to take some simple, safe steps to lower their energy use during this time.”

The Texas grid operator stressed that rotating outages, the third level of an EEA, are only a “last resort” in maintaining reliability. Declaring an EEA, permitted when operating reserves drop below 2.3 GW or system frequency cannot be maintained above certain levels and durations, allows it to take advantage of additional resources that are only available during scarcity conditions.

Generators have benefited from the tight conditions, with wholesale prices spending much of Saturday and Sunday above four figures. Prices peaked at $9,368.86/MWh Saturday in San Antonio’s CPS Energy load zone during the interval ending at 9:15 a.m.

The National Weather Service has sent out winter storm warnings or watches for much of Texas, and Gov. Greg Abbott issued a disaster declaration for every county in the state. Abbott said during a Saturday press conference that snow could probably cover a “larger swath of land to a higher degree than ever before in Texas history.”

“This period will go down in Texas weather history as one of the most extreme events to ever impact the state,” predicted Chris Coleman, ERCOT’s senior meteorologist. “That’s even more amazing when considering the 1980s’ coldest periods occurred in December with a low sun angle, compared to the extreme cold now with spring soon approaching.”

Coleman said there is “still room for even colder changes,” and he expected near-blizzard temperatures Sunday in windswept West Texas. A second storm “appears increasingly stronger,” he said, and should arrive mid-week.

Forecasts for Amarillo, Abilene and Midland call for temperatures as low as -11 degrees Fahrenheit on Monday. Dallas and Austin are expected to see single-digit temperatures Monday and Tuesday.

State officials are encouraging residents to stay off the roadways to avoid accidents like the 133-car pileup that killed six people on an icy overpass last week in Fort Worth.

SPP Issues EEA1 for Monday

SPP said it issued the EEA1 because it “foresees or is experiencing conditions where all available resources are scheduled to meet firm load obligations and that we may be unable to sustain its required contingency reserves.”

The RTO said its analysis of current forecast data indicates that conditions may continue to tighten over the next several days because of persistent, widespread and extreme cold.

“We have recommended that load-serving utilities throughout our region take conservation measures to mitigate the risk of more widespread and longer-lasting outages,” the company said in a statement.

Expecting the abnormal weather conditions — including temperatures near zero Monday in its Little Rock, Ark., hometown — SPP issued a cold-weather alert early last week. The grid operator later added a resource alert and then a call for conservative operations on Feb. 9.

COO Lanny Nickell warned the RTO’s Regional State Committee on Friday that more extreme measures may be needed.

“It’s not a transmission system issue; it’s a resource adequacy issue,” he said. “Some resources we rely on aren’t showing up.”

Nickell said SPP lost about 5 GW of forecasted wind generation on Feb. 7, with fog causing wind turbines to ice up. With load expected to pick up over the weekend into the week and gas supplies tightening, staff have been coordinating with gas companies and neighboring RTOs to ensure demand can be met.

“We’re ensuring we have all resources available,” Nickell said. “It’s all about keeping the lights on.”

‘Particularly Harsh’ in MISO South

MISO on Saturday declared conservative operations for Sunday through Tuesday for its entire footprint, saying it was expecting “extremely cold temperatures and generator fuel supply risks.” The declaration asks that market participants halt transmission and generation maintenance.

Within hours, the RTO singled out its South region — which spans Arkansas, Louisiana, portions of Mississippi and part of East Texas — for a maximum generation capacity advisory effective Monday at 9 a.m. ET and until “further notice.” MISO’s capacity advisories ask members to prepare for possible use of load-modifying resources and report any natural gas restrictions.

“The impact of winter weather is widespread across MISO’s footprint but is particularly harsh in the South region,” the RTO said Sunday. “MISO is working closely with its members to maintain system reliability amid the extreme conditions.”

MISO said the arctic blast could have the South approaching its all-time demand peak of 32.1 GW set in mid-January 2018. That year, bitter cold set in motion a two-day emergency declaration, a breach of the RTO’s subregional transfer limit, near-load shedding, and subsequent FERC and NERC inquiries. (See FERC Orders Cold Weather Reliability Standard.)

“The current load forecasts in the South Region are … making this a very difficult situation,” said Renuka Chatterjee, system operations executive director. “We are in constant contact with our members and our partner ISO/RTOs to ensure the reliability of the bulk electric system.”

On Sunday, MISO said its market functions were performing “as designed” despite the frigid weather and heavy demand. Spokesperson Brandon Morris said the RTO stood “prepared to take additional actions if generation or transmission sufficiency changes.”

“Keeping the lights on requires a high level of coordination and collaboration with our members and the communities they serve,” MISO South Executive Director Daryl Brown said. “Although we are experiencing unusual weather in the South, we are working together to meet that challenge.”

February 14, 2021

As EVs Have Their Moment, Regulators Get to Work

The media spotlight in 2021 on electric vehicles has been intense thanks to multibillion-dollar investment announcements from General Motors and Ford, and President Joe Biden’s plan to convert the federal fleet to EVs. However, state utility regulators say unlocking the technology’s potential is going to take some work.

Speaking at the National Association of Regulatory Utility Commissioners’ (NARUC) Winter Policy Summit, regulators said that the media has hyped EVs before and that the public has qualms about the technology’s cost and reliability, which need to be addressed. Bob Gordon, a member of the New Jersey Board of Public Utilities, outlined the industry’s daunting challenges in a panel discussion Feb. 9.

“State utility regulators are wrestling with some very tough issues, such as are public incentives needed to advance electrification, and if so, how should it be done, and who should pay for it?” Gordon said. “Should the incentives be designed to promote vehicle sales or the development of charging infrastructure? What are the respective roles of utilities and private investors? How should we address equity concerns? And what is the appropriate role of the federal government as opposed to the states?”

Patchwork of 50 Laws

EV industry challenges include a confusing and often contradictory patchwork of state laws that govern automakers.

For instance, more than a dozen states accept California’s emissions standards, which are stricter than the EPA’s because the Golden State’s air pollution is the worst in the country. California and Massachusetts recently announced bans on new gasoline-powered vehicle sales beginning in 2035. New Jersey has set a goal of eliminating internal combustion vehicles by 2035, though it has stopped short of a formal prohibition.

“A patchwork certainly makes things much more difficult,” said Dan Bowerson, director of environment and energy at the Alliance for Automotive Innovation. “We’ve seen a lot of areas where mandates don’t necessarily make markets.”

Tesla and Uber recently joined forces with smaller rivals including Rivian and Lucid Motors to form a trade group, the Zero Emission Transportation Association, which is targeting 2030 for 100% of new car sales to be electric.

The 2030 goal is “something we think from a raw materials perspective, a consumer perspective and a technology perspective is achievable,” said Tesla Senior Global Policy Director Rohan Patel.

Automakers Seek to Make the Leap

Automakers currently make about 40 EV models. In five years, they will offer 130 EVs, making up 1% of all vehicles on the road, according to Bowerson. Dismissed by automakers for years, EVs are now seen as vital in fighting climate change.

Electric Vehicles — Maryland PSC Chair Jason Stanek | © *RTO Insider*

Even so, the technology remains a tough sell to many consumers.

“So, that leaves traditional auto manufacturers, such as Ford and G.M., trying to figure out how to make this leap before the government mandates electric vehicles [or] they have their lunch eaten by companies like Tesla,” Chairman Jason Stanek of the Maryland Public Service Commission said.

Utilities have an integral role in promoting EVs.

For instance, Baltimore Gas and Electric provides calculators on its website to enable consumers to compare the costs of fueling a conventional vehicle to powering an EV. It also provides information on the environmental benefits of EVs and offers special electric rates to EV owners.

“Often when a customer purchases an electric vehicle, they’re looking to their utility for information on when it’s best to charge and are there any special rates available to them,” said Kristy Fleischmann Groncki, manager of strategic programs at BGE. “They ask questions about how to have a charging station [installed].”

Charging Network Challenges

Still, more work is needed to establish a charging network that is extensive enough to combat “range anxiety,” the fear that an EV will run out of power. Royal Dutch Shell’s plan to up its global EV charging network from 60,000 chargers to 500,000 by 2025 reflects the goal of making vehicle charging as convenient as filling up at the gas station.

The industry is also facing legal issues, such as the decades-old federal law that prevents thousands of rest stops on federal highways from offering charging for EVs.

Tesla is developing a charging network though it loses money on the service, Patel said.

“I don’t know of a good business case for charging infrastructure, period, let alone, charging infrastructure in places that have low utilization,” he said. “We’re investing a ton of money into those charging stations because we know that that’s the way to drive vehicle sales growth.”

February 14, 2021

Tx Planning Must Be ‘Highly Coordinated,’ Regulator Says

New complexities in the energy sector mean transmission planners must be “highly coordinated and intentional,” California Energy Commission member Andrew McCallister said Thursday.

“We are in and increasingly going towards a distributed energy future, and that’s why having the distribution system level integrated from the customer … to the wholesale generation system … is so key for planning going forward,” McAllister said during a press conference at the National Association of Regulatory Utility Commissioners’ virtual Winter Policy Summit.

McAllister, who is co-vice chair of the NARUC-National Association of State Energy Officials Task Force on Comprehensive Electricity Planning, joined other task force leaders in releasing a suite of new planning resources.

Those resources, which include Roadmaps for Comprehensive Electricity Planning, a Blueprint for State Action and an online library, are designed to help state agencies, companies and stakeholders unify their transmission planning processes. Fifteen states participated in developing the resources during the two-year task force.

transmission planning resources — Planning for transmission infrastructure, like Duke Energy’s Happy-Jack line seen here, is getting a boost from new resources released by the NARUC-NASEO Task Force on Comprehensive Electricity Planning. | *Duke Energy*

McAllister said that integrated approaches to transmission planning that bring together regulators and state energy officials are key to informing grid-related investment decisions.

“Distribution system planning requires access to more and different data and an expanding array of analytical tools,” McAllister said. “The task force has generated terrific intelligence and insight along those lines.”

Some of the states in the task force have committed to applying the new strategies.

California, Colorado, Hawaii, Michigan, Minnesota, North Carolina, Rhode Island and Virginia intend to explore opportunities to align electricity planning processes to meet priorities, such as decarbonization, through docketed proceedings.

Arkansas, California, Hawaii, Minnesota, Puerto Rico and Rhode Island have agreed to make data, such as voltage studies and hosting capacity analyses, available to improve distribution planning. Hawaii, Maryland, Minnesota and North Carolina also committed to holding technical conferences and briefings on the results of the task force to support states’ efforts to reform planning processes.

McAllister said that states also will have access to technical assistance from the U.S. Department of Energy and the National Laboratories.

February 14, 2021

BOEM Hears Public Support for South Fork OSW

Fishermen, environmentalists, labor unions and local residents broadly support the 132-MW South Fork Wind Project being built for the Long Island Power Authority by a joint venture between Ørsted and Eversource Energy.

“We’re anxious to see the South Fork project go forward,” said Roger Clayman, the executive director of the Long Island Federation of Labor, which represents 250,000 workers.

Clayman made his comments Thursday at the second of three hearings being held by the Bureau of Ocean Energy Management. The agency will hold its final virtual public meeting Tuesday and accept comments submitted or postmarked no later than Feb. 22 before completing its final environmental impact statement.

“It addresses some major concerns on Long Island, first of all climate change; we’re very sensitive as an island to what the impacts will be,” Clayman said. “Secondly, it brings the South Fork what they voted for, which is wind power; and third is job creation on a very large scale.”

The agency in January released a draft environmental impact statement (DEIS) on the proposed wind farm, finding mostly negligible to moderate adverse impacts from the project, as well as some generally minor beneficial impacts. (See BOEM Sees Moderate Impacts from South Fork OSW Project.)

Fish Facts

Ørsted and Eversource are proposing to build up to 15 wind turbines, with a capacity of 6 to 12 MW per turbine, located approximately 30 nautical miles east of Montauk Point.

BOEM Offshore Wind — A crew transfer vessel services the Block Island Wind Farm off Rhode Island. Fishermen at the BOEM hearing on the South Fork Wind Farm noted that fishing around the Block Island facility is just as good as before its construction. | *BOEM*

“The fish I catch today as a charter captain are vastly different in type and abundance due to climate change impacts, so the fishing industry needs renewable energy to help them stem the tide,” said Dave Monti, board member of the American Saltwater Guides Association and vice chair of the Rhode Island Marine Fisheries Council.

The developers have acknowledged the importance of private recreational fishing, but private angling is not covered in the DEIS, he said.

“It’s not the developers’ job to report who is fishing in a wind farm area and what they catch, but it is rather the job of [National Oceanic and Atmospheric Administration] and BOEM to make sure that recreational fishing is covered in surveys,” Monti said. “Recreational anglers are supportive of offshore wind as long as the wind farms are developed responsibly, with research before, during and after construction.”

Europe shows greater fish abundance inside its wind farms, and at the Block Island Wind Farm off Rhode Island, recreational fishing “is good, perhaps even a bit better than before the wind farm, even though fishing pressure in the area has increased,” Monti said.

Rich Hittinger of the Rhode Island Saltwater Anglers Association expressed concern that sound waves from pounding the 31-foot diameter piles into the seabed would damage fin fish within a nearly 6.5-nautical-mile radius.

“I’m just wondering if this is actually true, and if so, I’d like to know what is the anticipated radius of expected fin fish mortality,” Hittinger said. “I’m sure it would be much smaller, but I’d like to know what that is.”

Matt Gove from Surfrider Foundation, a national ocean advocacy group, said that his group hasn’t seen anything in the DEIS to keep it from supporting the project, but that “we’re really hoping to see some leadership from BOEM here on monitoring. … If we don’t have a standardized monitoring to have standardized data across all these projects, we’ll have no idea if any impacts are happening that we can’t see.”

Extension Cords

The preferred landfall site for the facility’s interconnection line is a parking lot at the southern end of Beach Lane in Wainscott, Long Island.

Mike Mahoney of Wainscott, who opposes the project, said that Beach Lane is busy and narrow, while the alternative landing site, Heather Hills, is wider and probably safer. (NOTE: An earlier version of this article stated incorrectly that Mahoney supports the project.)

Site specifics aside, Mahoney said, “The cost for the electricity for ratepayers in Suffolk County will be five times higher than any other location in the state of New York, and that concerns me greatly, especially when the adjacent wind farm, Sunrise, is being paid for by all the ratepayers in the state. … I know that that’s the agreement that LIPA and our state has signed, but I hope that you have input and can go back and suggest that they really look at that.”

David Posnett, a retired medical doctor in East Hampton who works with Win with Wind, an independent advocacy group on the South Fork, said he had a comment for all those who are worried about the “nefarious cable” running under the seabed and coming ashore.

The 660-MW Neptune Cable has been feeding power into Long Island from New Jersey without incident since 2007, and LIPA imports power from New England on the 330-MW Cross Sound Cable. Power also comes in on two older cables owned jointly by the New York Power Authority and Consolidated Edison, the 600-MW Y49 cable and the 400-MW Y50 cable, which also run under the sound to Long Island, he said.

“We already have giant extension cords running to Long Island,” Posnett said, adding that their construction had not harmed local shellfish.

But Mahoney questioned the need to run separate export cables from adjoining wind farms being built by the same developer.

“The developer said they couldn’t because the turbines are producing DC for the South Fork and AC for Sunrise,” Mahoney said. “Wouldn’t it be OK to go back to Ørsted and Eversource and say, ‘Put AC turbines up there instead of DC and just run the one cable and have less environmental impact to our ocean bottom and our sea creatures and mammals?’”

Joe Martens, director of the New York Offshore Wind Alliance, said that although relatively modest in size compared to other projects in BOEM’s queue, the South Fork project is important because electricity demand on the South Fork is growing faster than anywhere else on Long Island.

Adrienne Esposito, executive director of Citizens Campaign for the Environment, a statewide group with 140,000 members, agreed with Martens.

“Although this wind farm won’t cause a fossil fuel plant to close, it prevents another one from being built,” Esposito said.

February 14, 2021

MISO Fostering Alternatives to MTEP Projects

MISO is seeking ways to modify its annual transmission plan and make it easier for stakeholders to suggest alternatives to transmission owners’ project proposals.

During a Planning Subcommittee meeting Feb. 9, the RTO tested a draft plan that would increase the amount of time stakeholders have to assess projects and draw up alternatives during the annual Transmission Expansion Plan (MTEP).

Expansion Planning Senior Manager Thompson Adu said stakeholders have complained that MISO only allows a few weeks in the MTEP planning cycle to “review models, evaluate mitigations and propose alternatives” to submitted projects.

The RTO currently accepts both MTEP project proposals and alternatives on Sept. 15. It is proposing to move the alternative projects’ deadline to May 31 of the following year, giving stakeholders an extra eight and a half months to develop alternative solutions. Staff would then analyze the alternative proposals June through September.

However, multiple stakeholders said that unless MISO standardizes the project information that TOs release, the expanded timeline won’t help. They said TOs don’t post the same datasets on projects, making it difficult to assess proposals and draw up alternatives.

“What we’re looking at here is not just a timeline issue, but also an information issue,” Alliant Energy’s Mitch Myhre said.

Adu said the proposal was only a “conversation starter” and that MISO is accepting more ideas to encourage more meaningful transmission alternatives.

The grid operator has reported it’s overseeing 1,255 active MTEP projects totaling $13.6 billion. Of those, 118 projects, worth $2.3 billion, are under construction. Eleven projects were withdrawn during 2020’s final quarter.

Since the first MTEP package in 2003, approximately $26.5 billion worth of approved transmission projects have gone into service, according to MISO.

Meanwhile, the RTO has developed its cost-estimation guide for 2021 MTEP economic projects. Substation engineer Alex Monn said the fourth iteration of the annual guide includes both upfront project costs and costs over time. He said that as new technologies are sized up as project alternatives, MISO should provide maintenance cost predictions. He said energy storage projects generally have larger costs over the first 20 years versus traditional wires projects.

MISO will collect stakeholder opinions on its cost-estimation guide through April.

February 14, 2021January 21, 2024

Bipartisan Agreement on Minnesota Climate Bills Unlikely

Minnesota has fallen far short of emission reductions established in 2007 by Republican Gov. Tim Pawlenty, but the chance for bipartisan agreement on a course correction appears slim, according to legislative leaders on both sides of the aisle.

Considered historic at the time, the bipartisan “Next Generation Energy Act” requires the state to cut overall greenhouse emissions by 30% by 2025 and 80% by 2050. But emissions have declined by just 8% from 2005 levels, the Minnesota Pollution Control Agency reported last month.

While the report applauded the state government’s move to more electric vehicles and the energy industry’s move away from coal-fired power plants in favor of carbon-free wind and solar, MPCA officials also said the state has made little progress in the areas of transportation and agriculture.

On Jan. 21, Gov. Tim Walz announced a four-part plan by the Democratic-Farmer-Labor party to accelerate the state’s efforts, including a requirement that the state’s electric utilities use only carbon-free resources by 2040.

It would also require that utilities prioritize energy efficiency and clean energy resources over fossil fuels when proposing to add new generation, allowing new fossil fuel resources only if necessary for reliability and affordability. Walz would also raise energy efficiency standards and set a state goal of cutting greenhouse gas emissions from existing buildings in half by 2035. “The time to fight climate change is now,” Walz said.

But State Senate Majority Leader Paul Gazelka (R) said his current session priorities are substantially scaled back because of the coronavirus pandemic and an anticipated $1.3 billion budget shortfall.

“We knew that we were going to be in trouble [financially] this year,” Gazelka said in a January capitol report regarding session priorities. “And we’re not going to [balance the budget] by raising taxes.

He added that with limited floor action because of COVID protocols, he’s encouraged legislators in both the Senate and the House to “think about doing less.” His priorities this session focus on three key items: the budget, redistricting and dealing with pandemic issues.

“We’ve got to get our businesses open,” Gazelka said. “The rest can wait until next year.”

Despite the prospects of a divided legislature, DFL leaders have already pitched proposals with the hope that the Republican-controlled Senate might consider renewed goals for cutting emissions.

“This is an issue of our times, and it’s urgent that we deal with it,” Senate Minority Leader Susan Kent (DFL) said. While she said the state has made some headway on reducing emissions, transportation remains the number one concern, and a faster move to electric vehicles is a key to addressing it.

But Republicans prefer to stick with the targets set in the 2007 bill. The GOP’s relationship with Walz has been heading south for several months. The two sides have argued often and publicly about the governor’s use of emergency powers because of the pandemic. There have been several legislative attempts to curtail Walz’s emergency powers, but they have all been stopped by the DFL-controlled House of Representatives.

Gazelka said his party believes it is long past time to allow the Senate and the House to address the state’s economic issues, and that decisions “should not be given to one person for over a year.”

Republicans have also criticized the state’s vaccination rollout as being confusing and slow, and there has been a growing rural-urban split over how to fund economic recovery efforts for businesses impacted and destroyed in Minneapolis during the days following the death of George Floyd on May 25.

Despite a slim Senate margin, Republicans believe they have somewhat of a mandate judging from the November elections which saw their party gain five seats in the House, primarily in rural Minnesota. While the DFL still holds a 70-64 edge in the House, Republicans hold a 34-31-2 advantage in the Senate.

Two former DFL members, Rep. David Tomassoni (I) and former House Majority Leader, Rep. Tom Bakk (I), have left the party and plan to caucus with Republicans.

A bill sponsored by Rep. Jamie Long (DFL) that would set benchmarks for meeting Walz’s 2040 goal was the first clean energy measure to get a hearing in the new legislative session. And on Jan. 29, Long’s Capital Investment Committee held a joint hearing on Long’s bill with the Climate and Energy Committee chaired by fellow Minneapolis Rep. Fue Lee (DFL).

“As one of the fastest warming states in the nation, Minnesota needs strong, resilient infrastructure to withstand the impacts of climate change,” Long said in a press release. “Investing in sustainable infrastructure will create new jobs and help our communities adapt and thrive as the climate continues changing.”

Sen. Nick Frentz (DFL), who is sponsoring Long’s proposal in the Senate, isn’t quite as optimistic at winning support for the measure in the GOP-controlled upper house.

Sen. Dave Senjem (R), chair of the Energy and Utilities Finance and Policy Committee, plans to reintroduce the “Clean Energy First” proposal he authored in 2020. The bill would direct the Minnesota Public Utilities Commission to prioritize use of sources such as nuclear, solar, wind, hydropower, carbon sequestration and municipal solid waste in utility requests for additional generation. The PUC would be required to determine if the energy is adequately reliable and affordable for ratepayers.

The state’s two largest utilities, Xcel Energy and Allete’s Duluth-based Minnesota Power, have pledged to produce energy without carbon emissions by 2050, focusing on wind and solar options. Minnesota Power also plans to eliminate coal-powered generation by 2035.

In December, Minnesota Power announced it had become the first state utility to provide 50% renewable energy in its system, which serves 145,000 residential and commercial customers across northern Minnesota. Land O’ Lakes, through its sustainability affiliate Truterra, launched a carbon exchange program Feb. 4 to pay Minnesota farmers for increasing carbon storage in the soil. Companies that want to reduce their GHG emissions could buy credits to help offset the impact of climate change, according to Land O’ Lakes, a farmer-owned cooperative.

Microsoft became the program’s first customer, announcing it will pay $20/ton for carbon sequestered in the soil by sustainable farming practices.

February 14, 2021

MISO TOs’ Self-funding Option Tested Again

Two FERC commissioners still have heartburn over a 2018 commission order reinstating MISO transmission owners’ rights to self-fund network upgrades.

Chairman Richard Glick and Commissioner Allison Clements expressed their concerns in a Feb. 8 order following MISO’s submittal of an unexecuted facilities service agreement (FSA) between itself, interconnection customer Walleye Wind and transmission owner Northern States Power Co. While FERC approved the unexecuted FSA for a 111-MW Minnesota wind farm, it opened old wounds over the appropriateness of TOs’ unilateral right to self-fund network upgrades (ER21-615).

Walleye Wind, a NextEra Energy Resources subsidiary, said it refused to execute the FSA and requested MISO file an unexecuted document because of “continued legal uncertainty regarding” TOs’ right to provide initial funding for the network upgrade that would accommodate the project.

MISO Transmission Owners — | *NextEra Energy*

Walleye said FERC could reverse its decision in the future, placing initial funding responsibility back on interconnection customers.

The company asked FERC to direct MISO to amend the FSA by including a provision for the possible reversal of TOs’ self-funding option. It asked that the FSA state that “changes will be undone if the legal premise for [transmission owner initial funding] is later eliminated.”

FERC declined to amend the FSA to incorporate such language, saying the document correctly reflects the state of MISO’s rules at the time.

Glick concurred with the FSA decision but wrote separately that giving TOs the option to “unilaterally choose whether to self-fund network upgrades constructed on behalf of affiliated and nonaffiliated interconnection customers” could be unfair. He said the commission “failed to meaningfully wrestle with these concerns in its orders allowing transmission owners the unilateral right to choose up-front funding.”

Clements said that while she concurred with the decision, she is worried that FERC didn’t “adequately address the justifiable concern that those rules create an opportunity for generation-owning transmission owners to unduly discriminate” between assets they have an ownership interest in and those they don’t have an interest in.

She said that when interconnection customers have control of initial funding, they can finance at more favorable rates instead of reimbursing TOs for construction and a predetermined rate of return. She also said TOs’ unilateral right to self-fund ignores that the “vast majority of transmission owners do in fact still own generation.”

The commission should conduct a “more searching inquiry” of the issue, she said.

“While this topic has been the subject of litigation before this commission and the courts for several years, I believe we have more work to do,” Clements wrote. “A foundational principle of the commission’s work to open up access to the nation’s transmission grid over the past 25 years has been that when monopoly utilities are permitted to discriminate among affiliated and nonaffiliated customers, competition suffers and customers pay.”

She said that while the reasonableness of MISO interconnection rules was not the item in question, “they may well merit additional scrutiny in the near future.”

MISO in 2018 acted on FERC’s direction and reinstated TOs’ right to self-fund network upgrades necessary for new generation. FERC originally issued a 2015 order barring TOs from electing to provide initial funding for network upgrades, but that decision was remanded by the D.C. Circuit Court of Appeals. (See MISO Gauging Aftershocks of TO Self-fund Order.)

The move was unpopular with some MISO generation developers, who said it could pave the way for discrimination by TOs of some interconnection customers and increase the cost of new generation. But TOs’ ability to self-fund network upgrades survived a challenge last year from the American Wind Energy Association. (See FERC Upholds MISO Self-fund Order, Glick Dissents.)

February 14, 2021

Long-term Tx Plan Edges Out MISO GI Coordination

MISO last week said it bit off more than it could chew by simultaneously mounting a long-term transmission package while trying to merge interconnection upgrades with annual transmission planning.

Staff announced Wednesday during a Planning Advisory Committee (PAC) teleconference that it will table the effort to analyze network upgrades stemming from interconnection requests for economic benefits and possible cost-sharing. They said MISO would wait until the end of the year and see how the long-term transmission plan develops.

“We received feedback from stakeholders last month that it’s probably better to wait until more information of the long-range transmission plan comes at the end of the year,” Senior Manager of Economic Planning Neil Shah said. “Let’s put this issue on hold, and we will continue to monitor the progress of the long-range plan.”

Stakeholders, particularly those belonging to the environmental sector, seemed fine with the breather.

“It did seem like it was appropriate to pause work on this since there are so many moving parts that could affect [it],” Clean Grid Alliance’s Natalie McIntire said. “I don’t want to lose this issue. It may be that it gets addressed somehow with long-range transmission and its allocation.”

Shah agreed that some long-term projects may ease network upgrade costs for interconnecting generators.

Stakeholders have warned MISO that system upgrade costs for interconnection hopefuls have been snowballing in recent years because of scant transmission planning, threatening a clean energy transition. (See “Coordinated Planning Effort Continues,” MISO Planning Advisory Comm. Briefs: Sept. 23, 2020.)

Before hitting pause on the network upgrade analysis, the RTO had proposed to conduct economic evaluations of interconnection upgrades with signed interconnection agreements rated at 230 kV or above and costing at least $50,000/MW. If the upgrades demonstrated the same 1.25:1 benefit-to-cost ratio required of market efficiency projects, they would have been included as economic projects in MISO’s annual Transmission Expansion Plan (MTEP).

The Long View

While interconnection upgrade coordination took a back seat, stakeholders at the PAC were left wondering how often they’ll be apprised of MISO’s long-term transmission planning.

They asked for monthly updates on the progress of MISO’s burgeoning long-term transmission plan, the first in a decade. (See MISO Begins Longterm Tx Modeling.) The February PAC meeting did not have an agenda item on the long-term plan.

Director of Planning Jeff Webb said MISO will begin delivering regular reports to stakeholders when it has “substantive materials.” He said so far, there is little to report.

“We can give updates, but they’ll probably be brief status updates,” Webb said, adding that the RTO plans to hold a discussion on long-term planning at the March PAC.

The grid operator is currently relying on the 20-year futures scenarios developed for MTEP 21.

Todd Hillman, MISO’s senior vice president and chief customer officer, said the RTO is first focusing on Future I, which most closely resembles member utilities’ collective plans. The future assumes an 85% likelihood that utilities meet their current decarbonization plans and full certainty that their stated generation retirements and additions come to pass. The scenario will likely translate into a 60% carbon reduction in MISO from 2005 levels.

“Future I was largely developed in talking with our members and stakeholders,” Hillman said during an informational forum in January.

MISO expects to have preliminary project solutions from its Future I modeling within the next few months. Staff is also beginning long-term modeling for the more aggressive Futures II and III. Webb said he thought that any transmission projects coming out of Future I would most likely be “baseline” and serve as a foundation for other needs found using the second and third futures.

WEC Energy Group’s Chris Plante said he wasn’t sure that MISO was predicting enough storage technology in its futures. He noted utilities are increasingly turning toward storage.

The Natural Resources Defense Council said late last month that the RTO has failed to prepare for a clean-energy future through sufficient transmission planning. The nonprofit said MISO’s recent transmission planning ignored the rapid pivot to clean resources and only anticipated “incremental clean energy development over the coming decade, rather than transformational clean energy development that is anticipated by 2035 and beyond.”

“In 2020, [MISO] ignored the demand for the regional transmission necessary to transition the Midwest into a clean energy hub. This year [it] can and should do better by building regional transmission,” the NRDC’s Toba Pearlman wrote in a blog post. She said the RTO’s inaction intensified its interconnection queue backlog.

NRDC reported that 278 storage, hybrid, wind and solar projects were withdrawn at “advanced stages” in the grid operator’s interconnection queue between 2016 and October 2020.

Senior Transmission Planning Engineer Andy Witmeier said the grid operator’s current transmission planning would be inefficient without a long-term package, and without it, “the resource shift contemplated by MISO stakeholders’ goals will be difficult to achieve.”

Speaking during a cost allocation working group teleconference on Thursday, Witmeier pointed to MISO’s newest instantaneous wind peak on Dec. 23, when 20.2 GW of wind generation served almost 27% of system load. He said even more wind power was available that day but was “trapped behind transmission congestion.”

“We have to make sure we enable the delivery of that extra generation,” he said. “With an additional 4,500 MW expected to come online in the next 12 months, it is increasingly important to see how the system is currently handling production of renewable resources and [preparing] for future growth.”

Cost Allocation Decisions Loom

MISO’s cost allocation group will eventually consider a benefit measurement and cost-sharing design for the long-range transmission plan.

Witmeier said the RTO’s current market efficiency project cost allocation won’t likely capture all long-term transmission benefits.

The Organization of MISO States convened a special cost-allocation committee late last year to draw up principles on how staff should approach long-term projects’ cost sharing. The resulting principles are broad, driving home that costs should be portioned out as precisely as possible to beneficiaries and cost-causers. OMS said generation and load — including regions with decarbonization goals — can be considered beneficiaries. It also suggested MISO use subregional allocations and bundle certain transmission projects’ costs when it makes sense.

MISO Executive Director of System Planning Aubrey Johnson acknowledged there’s not much appetite among stakeholders for a footprint-wide postage stamp rate for long-term transmission.

“That camp is very small. There’s not a high likelihood of success,” he said during an OMS meeting in January.

February 14, 2021January 15, 2025

Southeast Seeks FERC OK for Expanded Bilateral Market

Utilities and cooperatives in 11 Southeastern states on Friday proposed using automation and free transmission capacity to expand bilateral trading and allow 15-minute energy transactions.

Led by the Tennessee Valley Authority, Southern Co. and Duke Energy, the Southeast Energy Exchange Market (SEEM) seeks to reduce the “friction” in bilateral trading by using an algorithm to match buyers and sellers and eliminating transmission rate pancaking in the region’s 10 balancing authority areas.

Electric providers purchase cheaper power when they can back down more expensive generation in their own fleets; sellers earn profits to offset their operating costs.

To make a transaction currently “the parties must discover one another, negotiate the terms of the sale, arrange and pay for transmission service across all utilized transmission systems, and schedule the delivery of energy. All of this is done with ‘traditional’ methods of communication, by phone and electronically, thus creating transactional friction,” Southern Company Services said in a FERC filing on SEEM’s behalf (ER21-1111, et al.). “Trades generally occur on an hourly basis as the shortest increment, and most often occur only with entities in the same or directly interconnected balancing authorities.”

The SEEM proposal, which would allow participants to move power over unused transmission capacity at $0/MWh, “will enhance efficiencies and reduce opportunities to exercise market power by allowing more buyers to transact with more sellers over a much bigger region,” SEEM said.

Although the group’s name includes “market,” participants made clear that they do not see the proposal as a prelude to an RTO. “The Southeast EEM is not — and was never intended to be — a top-to-bottom reimagining of the Southeast energy market; rather, it reflects incremental improvement to the existing bilateral market,” the group said.

Among SEEM’s “core principles” are that each electric service provider and state will maintain control of generation and transmission investment decisions and that each transmission provider will remain independent, with its own transmission tariff. There will be no changes to reliability, state jurisdiction or responsibilities for resource adequacy, it said.

SEEM had provided some details of its proposal in an informational filing with the North Carolina Utilities Commission in December. (See Southeast Utilities Announce Regional Energy Market.) Friday’s filings provided many more details on its governance, cost allocation and measures to address potential market power.

Fourteen utilities and cooperatives have signed the SEEM agreement and five others are “contemplating or in the process of seeking” approvals to do so. Members opened 13 dockets detailing the agreement and changes to their transmission tariffs. (Some of the members are not FERC jurisdictional.)

Members and Participants

TVA; Southern’s Alabama Power (ER21-1111, ER21-1125), Georgia Power (ER21-1119) and Mississippi Power (ER21-1125, ER21-1121; and Duke Energy Carolinas (ER21-1116) and Duke Energy Progress (ER21-1115, ER21-1117) represent nearly three-quarters of SEEM’s net energy for load (NEL).

The other initial members are: Associated Electric Cooperative Inc.; Dalton Utilities; Dominion Energy South Carolina (ER21-1112, ER21-1128); Louisville Gas & Electric (ER21-1114, ER21-1118) and Kentucky Utilities (ER21-1120) (LG&E/KU); North Carolina Municipal Power Agency Number 1; PowerSouth Energy Cooperative; and North Carolina Electric Membership Corp.

Those planning to join are Georgia System Operations Corp. (GSOC); Georgia Transmission Corp. (GTC); Municipal Electric Authority of Georgia (MEAG); Oglethorpe Power Corp. (OPC); and South Carolina Public Service Authority (Santee Cooper).

The 19 expected members have 160 GW of summer generating capacity (180 GW winter) in parts of 11 states across the Eastern and Central time zones and serve more than 32 million retail customers.

New members — which must have a load-serving responsibility or serve an entity with that responsibility — will be allowed to join during an enrollment period from July 1 through Sept. 30 annually. Nonmembers that want to submit bids and offers into SEEM will be called participants.

Yes or No Decision for FERC

SEEM asked FERC to allow a comment period of 30 days, rather than the usual 21, and sought an effective date in 90 days — May 13. Members hope to select a vendor to build the system in the first quarter of this year with the buildout complete by the third quarter and trading beginning in the first quarter of 2022.

SEEM said FERC can only opine on whether the rates proposed in the group’s Federal Power Act Section 205 filing are just and reasonable, limiting any changes to “minor deviations.”

But FERC is likely to hear complaints from intervenors who contend SEEM does not go far enough to modernize the region’s electric industry.

When news of SEEM’s efforts became public in July, the Solar Energy Industries Association and the Southern Environmental Law Center said they would push regulators to demand more competition. The Southern Alliance for Clean Energy said SEEM appeared to be an effort to avoid legislative action to create an RTO in the Carolinas. “We remain concerned that SEEM is being constructed as a way for participating utilities to avoid being pushed to form or join a competitive energy market.” (See Southeast Utilities Talking Regional Market.)

Stakeholder Outreach

The proposal arose out of a year of discussions among the electric providers and other stakeholders, including “governmental entities and non-governmental entities such as environmental groups, trade associations and individual customers,” SEEM said.

“Comments have been overwhelmingly supportive, but a common request was that the members take the Southeast EEM construct further, to have more ambitious aims entailing far greater complexity. … The current proposal is the one that struck a delicate balance among the members, and thereby enables, for the first time, a regionwide market enhancement in the Southeast.”

“This is not the first effort to develop a regional market in the Southeast … but it is the first one to enjoy such broad support from the transmission owners and load-serving entities in the region,” Aaron Melda, TVA’s senior vice president for transmission and power supply, and Lonnie Bellar, chief operating officer of LG&E/KU, said in an affidavit submitted to FERC, referencing the collapse of a four-year effort following Order 2000 in 1999.

The group said it will post trading data on a public website and that it will hold annual meetings “open to all interested parties.”

Any changes to the market rules will be filed at FERC, providing an opportunity for public comments.

No Impact on Reliability

SEEM proposes a new zero-cost, non-firm energy exchange transmission service (NFEETS) provided on an as-available basis after all other uses have been considered. It would be available solely for 15-minute energy exchanges, have the lowest curtailment priority, and unable to be reassigned, sold or redirected.

It could only be provided by a transmission provider whose system — when added to the other participating transmission providers — creates a continuous contract path. Because it would be a non-firm, as-available product, no transmission studies would be required.

“The Southeast EEM will not have any negative impact on reliability, because it will not change any current reliability roles or responsibilities and will rely on unused transmission given the lowest curtailment priority,” the group said, adding that the market will not offer capacity transactions. “The reliability obligations that BAs and transmission providers have today are unchanged under the Southeast EEM.”

Split the Savings

SEEM said it will save customers money by allowing more efficient use of unused transmission capacity over a large footprint, increasing the opportunities for win-win trades. It will use a “split-the-savings” approach with the transaction price at the midpoint between the seller’s offer and the buyer’s bid, with an adjustment for transmission losses.

SEEM will be a “low-risk, high-reward venture,” members said, citing a 20-year benefits analysis by Guidehouse and Charles River Associates that projected a minimum of $40 million in benefits per year (2020$) in a scenario based on recent integrated resource plans and equivalent data.

Under a “carbon constrained” scenario, benefits will increase to more than $100 million annually by 2037, according to the analysis. The scenario was based on participants’ IRP carbon-reduction plans and “reasonable assumptions of what a high-renewable-and-storage, low-carbon future may look like in the Southeast.”

Start-up and ongoing costs are estimated at a total of $3.1 million annually (2020$) levelized over the 2021-2040 period.

SEEM acknowledged that the new free transmission service could result in a “slight decrease” in point-to-point revenues used to offset network service charges but said the revenues at stake are “minimal.”

Its benefits will result from bilateral trades unlikely to occur under current rules, the group said. “The automated system will have a substantial advantage in searching for transmission paths with available transmission to complete beneficial trades, overcoming transaction costs and information barriers. Further, the algorithm will exhaustively seek out all possible beneficial trades across the territory.”

In addition, it “will allow for better integration of diverse generation resources, including rapidly growing renewables, and will reduce renewable curtailments,” Melda and Bellar said in their affidavit.

Because of the lack of sub-hourly market liquidity, transmission providers currently must balance all variation in renewable output across the full hour.

“By creating greater liquidity in sub-hourly wholesale transactions, especially across a broad geographic area encompassing possibly different weather conditions and renewable policies, the Southeast EEM can provide additional opportunities for transmission service providers to either procure additional energy or to dispose of excess energy, rather than having to rely exclusively on increasing or decreasing the output from their own generation resources that provide imbalance service,” they said.

Governance, Cost Allocation

Each of the members would have a seat on a Membership Board, which “will be responsible for all significant decisions,” while a revolving subset of four members would run the Operating Committee, responsible for overseeing the day-to-day operations and working with an independent entity that would administer the system.

The Operating Committee would have two members from the investor-owned utility sector and one each from the cooperative sector and governmental utility sector, reflecting the sectors’ shares of load. To prevent any subset of members from dominating, votes by the Operating Committee would have to be unanimous, with any issues that cannot be resolved taken to the Membership Board. All members would be permitted to “attend, observe and participate” in Operating Committee meetings.

The group plans a hybrid cost allocation formula, with 25% of costs allocated equally among all members and 75% assigned based on NEL.

Market Power

The members said they would contract with an auditor to “review and analyze” market data to ensure that the system is functioning properly, but they have no plans to create a market monitor, contending that SEEM does not create new opportunities to exercise market power.

“Any additional market monitoring functions beyond the auditor’s responsibilities would be superfluous, creating additional administrative costs that are not justified. For these reasons, members are unwilling to fund the costs of a market monitor and believe the traditional means of commission oversight of [market-based rate] transactions will continue to provide adequate opportunities for review and regulatory protection,” SEEM said.

To avoiding potentially anticompetitive price discovery, all reported pricing information would be aggregated and its release delayed until at least the day after the trading day.

The group submitted an affidavit from Susan Pope, a managing director at FTI Consulting, who said no participant could exercise market power in SEEM “unless it already could exercise market power in today’s hourly bilateral market.”

Companies will be able to put constraints into the algorithm to ensure that they continue to obey current mitigation measures, Pope said. “Dominion Energy South Carolina, Duke and LG&E/KU anticipate complying with their mitigation requirements by toggling ‘off’ their home BAAs, thus ensuring that they are not matched with any bidder in their home BAAs and more than meeting the market power mitigation requirement.”

Pope said it would be problematic if a participant could unfairly obtain zero-cost NFEETS or profit from manipulating the average hourly energy exchange prices.

But she said the requirement that all participants have “toggled on” at least three unaffiliated potential counterparties would prevent collusion “to trick the algorithm into moving the schemers to the front of the line for zero-cost transmission.”

“The number of counterparties renders it difficult and risky for parties to coordinate to implement such a scheme, particularly in light of the small benefit to be obtained (i.e., a greater probability of obtaining zero-cost NFEETS),” she said.

TVA ‘Fence’

In crafting the SEEM agreement, members said they were careful to honor the so-called TVA “fence,” which Congress enacted to prevent the federal utility from selling power outside the areas it was selling to as of July 1, 1957.

Among the current SEEM participants, TVA can sell power to only Duke, LG&E/KU and Southern, although it can purchase from any SEEM participant.

“Given TVA’s central location in the Southeast, if TVA cannot participate in a redesigned market, then others (LG&E/KU and AECI) would not have a contiguous connection to the rest of the market,” Pope noted. “If they cannot connect through TVA, they must connect through one of the neighboring RTOs, thus adding another wheel, and the added transmission expense, to any transaction with a counterparty in the Southeast.”

February 14, 2021November 10, 2023

NYPSC OKs Clean Energy Programs, Local Transmission Planning

The New York Public Service Commission on Thursday approved several programs to speed up the state’s transition to renewable energy.

The measures include money for communities hosting solar or wind resources and those losing old power plants and their tax payments, new regulations on handling utility and customer data related to energy usage, and a mechanism for utilities to bypass rate case proceedings in local transmission planning.

The PSC also granted a certificate of environmental compatibility and public need to New York Transco to build a new, double-circuit 54-mile 345/115-kV transmission line, estimated at $530 million, along the Hudson River from near Albany down to Duchess County (Case No. 19-T-0684). The commission also approved the 20-mile, 345-kV Empire State Line project by NextEra Energy Transmission New York in the western part of the state (Case No. 18-E-0765).

New York state agencies last month released a study that urges faster permitting, planning and approval to build the transmission needed to integrate nearly 40 GW of new renewable energy into the grid over the coming decades. (See NY Grid Study Pushes Meshed OSW Tx, Coordination.)

The commission’s fast pace is being driven by New York’s Climate Leadership and Community Protection Act (CLCPA), which requires the state to consume 70% renewable electricity by 2030, switch to 100% zero-emission power by 2040 and reduce greenhouse gas emissions to 85% below 1990 levels by midcentury.

Utility Leverage

The PSC unanimously approved a “Phase One” local transmission planning mechanism that allows utilities to bypass the usual rate case process and acquire funding approval by petitioning the commission for such authority (Case No. 20-E-0197).

The state’s investor-owned utilities on Nov. 2 jointly filed a report in which they collectively proposed to undertake about $7 billion in transmission and distribution upgrades by 2025 (Phase One) and another $10 billion in projects for the following five years (Phase Two). (See Meshed OSW Tx Grid May Work Best, NY Officials Hear.)

The commission’s order said that relying strictly on rate case cycles to provide for cost recovery of proposed Phase One projects may delay achievement of CLCPA goals.

“However, we expect that this mechanism will be needed only in the short term … and once those [CLCPA] deadlines and requirements are incorporated into the utilities’ capital planning processes and rate plans, the commission does not anticipate a continuing need to rely on petitions for incremental funding of Phase One projects,” it wrote.

“In my eyes, this is a thoughtful and practical item founded on an open and thorough process founded on ample opportunity for input, and in fact ample and helpful uptake on that opportunity,” said PSC Chair John B. Rhodes. “It represents the next milestone to developing out the grid that we know we will need, in today’s case both on the distribution and local transmission side of the grid.”

“This really does mark the change in how transmission planning moves from serving native load, exclusively at lowest cost, to a more environmentally sensitive and environmentally driven system,” Commissioner John Howard said. “Most of the items here on Phase One were going to go forward regardless of the CLCPA, and we do get some tremendous environmental benefits by their construction.”

Most comments on the docket supported approval of the proposed Phase One projects, but the state’s Utility Intervention Unit, the City of New York and LS Power Grid New York filed comments opposing some or all of the projects on the basis that they either go beyond the scope of the PSC’s initial grid study order last May or that the utilities failed to provide adequate details or cost information.

In its comments, Multiple Intervenors, a coalition of about 60 large industrial, commercial and institutional energy customers, asked “that more robust cost-containment measures be applied to CLCPA-driven projects and especially those approved outside of the rate case process.” The group recommended NYISO’s public policy transmission planning process as a framework under which “developers submit highly detailed proposals” to allow the ISO to assess viability and sufficiency.

Relying on Property Taxes

The PSC unanimously approved a program that provides bill credits to residential electric customers in municipalities in which major renewable energy facilities are located, possibly dampening local opposition to such projects (Case No. 20-E-0249).

The type and size of the facility determine the amount of the credit. Any new solar or wind project greater than 25 MW that goes into service after April 2020 will be required to pay the utility serving the affected municipalities an annual fee of $500/MW and $1,000/MW of nameplate capacity, respectively.

Howard was not entirely pleased with the host community benefit program but said he was encouraged by the provisions to assess its effectiveness every two years.

“In the interim I would urge all municipalities that border host communities for large-scale renewable projects engage in the siting process to assure that any affected residences receive compensation under this program,” he said.

Two other energy-related items on the consent agenda had one or two votes in opposition, either from one or both of the Republican members on the five-member commission.

Commissioner Diane X. Burman provided the only dissenting vote on creating an integrated energy data resource that will provide a platform for collecting, integrating, managing and accessing customer and system data from the state’s energy utilities (Case No. 20-M-0082).

“While I think that the proposal for a statewide integrated energy data resource may have some merit, it is something we should not undertake as a commission right now,” Burman said, adding that the arrangement needs more discussion. “Frankly, I think we can and should wait until the new, permanent chair to decide if this is the direction … to have staff deeply invested in.”

Both Burman and Howard voted against authorizing the New York State Energy Research and Development Authority (NYSERDA) to provide approximately $12.5 million each year through 2029 to help local communities offset the loss of property taxes that typically occurs when a large power plant closes (Case No. 20-E-0473).

The plant closing mitigation program will not be backed by imposing incremental funding obligations on ratepayers. Instead, NYSERDA would transfer Regional Greenhouse Gas Initiative (RGGI) funding to Empire State Development for the program, with aid not to exceed $112.5 million in total through 2029.

“I must say I’m very troubled by this item for several reasons, first being the use of RGGI funds to compensate communities for loss of property tax revenues due to power plant closures,” Howard said.

The legislature has the power to compensate the loss of tax revenue in various ways, and the new program “takes off any veil” from RGGI and related fees on emitters or ratepayers being taxes, and in fact fungible, thus able to be used for purposes not foreseen when the environmental programs were created, he said.

“This is a perfect example of our state’s overreliance on property taxes to fund essential local services,” Howard said. “No state taxes energy infrastructure to the extent that we do in New York. … We also need to understand that massive capital investments to meet the carbon reduction goals of the CLCPA will only exacerbate this very flawed system.”

The PSC approved a resolution to petition Gov. Andrew Cuomo to increase the number of commissioners on the board from five to seven, given the increasing workload for commissioners and staff. The session closed with PSC Secretary Michelle Phillips reading a resolution from staff and commissioners thanking Rhodes, whose term ended Feb. 1, for his “faithful service to the residents of New York.”