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November 14, 2024

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Wisconsin Gas Plant Delayed as Enviros Still Try to Block Project

The timeline for building the Nemadji Trail Energy Center (NTEC) in Wisconsin has been pushed into next year as clean energy groups continue to challenge the need for the planned gas-fired plant.

Minnesota Power, Dairyland Power Cooperative and Basin Electric Power Cooperative filed an update with the Public Service Commission of Wisconsin to report that onsite relocation work on the $700 million plant in Superior, Wis., won’t begin until April. Work was originally slated to begin in the third quarter of this year (9698-CE-100).

The utility and cooperatives now say the 625-MW NTEC won’t reach commercial operation until 2028 — not March 2027, as anticipated in the last update in July.

Dairyland said the holdup is a result of permitting, litigation and supply chain delays. In an email to RTO Insider, Dairyland spokesperson Katie Thomson said delays could drive up the cost of the project and risk grid reliability.

NTEC still needs a wetland permit from the U.S. Army Corps of Engineers and a stormwater permit from the Wisconsin Department of Natural Resources.

The slowdown comes as the Sierra Club and Clean Wisconsin continue to argue that the plant is harmful and unnecessary.

The two environmental groups this year asked the Wisconsin PSC to reopen the docket and rescind its 2020 approval of the plant. They also appealed a 2022 decision on their lawsuit alleging that the PSC failed to consider the full environmental impact of the plant (2020CV000585).

Last year, Dane County Circuit Judge Jacob Frost upheld the regulators’ approval of NTEC and said the PSC followed the law when issuing a certificate of public convenience and necessity, though he acknowledged the “massive impacts a major project of this nature holds for the state.”

In its 2020 decision, the Wisconsin PSC concluded that renewable energy combined with battery storage was “not yet capable of replacing a plant of this size.”

But the two groups argue that the planned construction of 489 MW in battery projects in Wisconsin will be complete a few years before NTEC is slated to begin running and is enough to negate the need for the plant.

They also continue to insist that the utility and cooperatives didn’t sufficiently analyze alternatives before settling on the gas plant. The groups maintain the cooperatives should instead pursue some of the $9.7 billion in federal funding available through the Inflation Reduction Act to help rural electric cooperatives transition from fossil fuels to renewable generation.

The groups say customers will be paying to recover the costs for NTEC at least into the 2050s, past the end date of most net-zero carbon pledges.

This year, Clean Wisconsin attorney Brett Korte said the PSC has a chance to reconsider the plant “to protect ratepayers and the environment by recognizing that the energy landscape has fundamentally changed since 2020.”

“This plant was always a bad investment, but it would be incredibly unwise to leave so much money on the table and stubbornly stick with fossil fuels that are going to harm communities and the environment in Wisconsin. The new federal funding really is a game changer, and Wisconsin should do everything it can to capitalize on the opportunities it presents,” Korte said.

Superior Mayor Jim Paine has changed his tune on the plant, saying it’s no longer needed. In a July letter commenting on a revised supplemental environmental assessment by the Department of Agriculture’s Rural Utilities Services, Paine said his “change of heart, mind and spirit” boils down to Dairyland’s acquisition of the 503-MW RockGen Energy Center gas plant in 2021, the ramp-up of renewable energy and energy storage, and a belief that the NTEC site is ill-suited for industrial development.

Construction will require the developers to fill in about 20 acres of wetlands on the banks of the Nemadji River. It would also be located near indigenous mass burial grounds.

Nemadji Trail Energy Center project map | Minnesota Power, Dairyland Power Cooperative and Basin Electric Power Cooperative

The Sierra Club said NTEC would be located “at the top of a steep slope with a historically high risk of erosion, potentially causing stormwater runoff.” The group pointed out that the utilities estimate they will have to pump almost three million gallons of water daily to operate the plant, close to the total daily water usage of the City of Superior itself.

Four of the Superior City Council’s 10 members — Nicholas Ledin, Jenny Van Sickle, Garner Moffat and Ruth Ludwig — also submitted letters of opposition. The council passed a resolution in favor of the plant in 2019.

Dairyland Says Plant is Crucial

Dairyland insists the plant is necessary to fill lulls in renewable energy output, delivering a bridge to a zero-carbon future. It also said the plant could be retrofitted to operate on up to 30% hydrogen.

“Today, there are not commercially available, utility-scale long-term battery storage technologies on the market to meet current and anticipated energy requirements,” Thomson said. “Currently, battery storage simply does not have the ability to replace the 24/7 power generated by power plants. A battery supplies energy measured in hours between charges, whereas a power plant supplies reliable energy for days, weeks or even months when wind and solar are unable to meet the demand for electricity.”

However, Thomson added that Dairyland is “enthusiastic” about batteries and other forms of energy storage and noted the co-op is exploring pumped hydro storage in abandoned mines and was recently awarded a battery storage grant from the Department of Energy.

She said NTEC’s ramping capability will help support Dairyland’s planned portfolio of 12 new wind and solar projects totaling 1.7 GW that could be funded under the IRA’s Empowering Rural America program, the same $9.7 billion program the Sierra Club and Clean Wisconsin urged the cooperatives to pursue.

Thomson said NTEC will dependably supply power at “60% less carbon, 100% less mercury and 97% less other emissions than coal.”

Clean Wisconsin has said rather than reducing emissions, the plant will annually release 3 million tons of carbon pollution into the environment.

The plant would operate as a merchant generator selling power in MISO markets. The RTO last year commented in support of the plant to the Rural Utilities Service, saying it would welcome new gas-fired capacity to bolster resource adequacy in its footprint. (See MISO Executives Spotlight Fleet Evolution Planning, Risks.)

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Groups Say Partially Approved LG&E-KU Plan Signals Fleet Transition

Community groups are hailing the Kentucky Public Service Commission’s decision this month to reject a proposed gas plant from Louisville Gas & Electric and Kentucky Utilities (LG&E-KU) while greenlighting multiple planned solar installations and coal plant retirements. 

The Kentucky PSC’s order authorized LG&E-KU to build only one of two 640-MW natural gas plants that it proposed in its $2.1 billion integrated resource plan and allowed the retirements of the coal-fired Mill Creek Units 1 and 2 and three smaller gas-fired units (2022-00402). 

The coal retirements total about 600 MW, while the gas unit retirements will subtract about 47 MW from LG&E-KU’s portfolio. They will take place from 2024 to 2027. 

The commission also denied approval of the companies’ requested retirement of KU’s coal-fired Ghent Unit 2 and Brown Unit 3, totaling almost 900 MW. It said the retirements should be deferred until it’s clearer what new environmental regulations will be enforced. 

The new gas plant will be located at LG&E’s Mill Creek station. The PSC disallowed LG&E-KU’s proposal for a second new natural gas plant at KU’s E.W. Brown station. 

The PSC also allowed all six of LG&E-KU’s proposed solar facilities at a combined 877 MW, a 125-MW battery storage plant and the utilities’ 2024-2030 demand-side management plan that includes more than a dozen new energy efficiency programs. 

The storage project will be Kentucky’s largest utility-scale battery. The commission said the solar facilities will offer “significant savings” to customers and noted the critical role battery storage can play in the resource transition. 

Intervenors in the case — Mountain Association, Metropolitan Housing Coalition, Kentucky Solar Energy Society and Kentuckians for the Commonwealth — say that the PSC’s ruling is a landmark decision that advances clean energy in a state whose legislature earlier this year enacted a law requiring the commission to review planned fossil-fueled power plant retirements using a presumption that they should remain in operation (SB4). 

In a joint press release, the groups said they were disappointed with the approval of a new natural gas plant and the decision to keep two aging coal plants online. However, they said the order “offers major advances for clean energy in Kentucky and indicates that the PSC is weighing the risks of new and existing fossil fuel plants pose to ratepayers.” 

“LGE-KU must not ignore this opportunity to ramp up efficiency programs, solar energy and battery storage to make any additional gas plants unnecessary,” they said. 

“The denial of a $650 million, 40-year commitment to a risky natural gas plant is a major victory for ratepayers,” said Catherine Clement of Kentuckians for the Commonwealth. “And the closure of those old Mill Creek coal units will mean better air quality for the people of Louisville and the surrounding region.” 

Josh Bills of the Mountain Association said LG&E-KU realizes that the plants are too costly to continue to operate because they require “massive investments to bring them into compliance with air and water quality regulations.” He said the Kentucky PSC’s order establishes a course for future coal plant retirements and “importantly” acknowledges that energy efficiency programs and distributed resources can reduce demand enough that the output from the Ghent and Brown units might not need to be replaced with an expensive new gas plant. 

Chris Woolery, representing the Mountain Association, agreed that successful energy efficiency programs could shave enough demand to offset the need for a major power plant. 

Tony Curtis of the Metropolitan Housing Coalition said his organization is looking forward to assisting LG&E-KU on implementing the new energy efficiency offerings, especially for those who “struggle to pay their bills each month and can really benefit from home energy improvements.” 

After the PSC’s order, PPL — the parent of LG&E-KU — said in a U.S. Securities and Exchange Commission filing that the utilities’ planned capital investments in new and existing facilities in Kentucky are “materially consistent” with the utilities’ original $2.1 billion plan. 

John Crockett, president of LG&E-KU, said the utilities are “pleased” that the PSC approved many aspects of the original plan. 

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Climate Resilience Takes Center Stage at NARUC

LA QUINTA, Calif. — California PUC President Alice Reynolds set the tone for the theme of climate resilience at the National Association of Regulatory Utility Commissioners Annual Meeting with a story about the history of the Salton Sea.

In her opening remarks at the conference Nov. 13, Reynolds explained how the sea — a highly saline body of water in the Southern California desert about an hour from the conference location — was created by an extreme weather event in 1905 when Colorado River floodwater breached an irrigation canal and spilled into the Salton Sink.

The landlocked body of water is now considered a key domestic mining location of a critical mineral needed to manufacture batteries for the energy transition: lithium.

“There’s so much history related to the Salton Sea before this event and after, but I wanted to raise it as an early lesson in resiliency and also an event that created opportunity,” Reynolds said. The Salton “provides the potential for sustainable extraction of lithium and for geothermal generation, both of which are needed for our clean energy transition.” (See ‘Lithium Valley’ Could Accelerate California EV Sector Growth.)

In the future, Reynolds said, inevitable climate-caused extreme weather events could present an opportunity to develop new technologies — like using lithium from the Salton Sea to power electric vehicles — to better adapt to climate change.

Funding for Climate Mitigation

On the heels of Reynolds’ speech, many discussions at the conference centered on the crucial role the energy sector will play in building the infrastructure needed for climate mitigation and resilience.

David Crane, undersecretary of infrastructure at the Department of Energy, discussed DOE’s role in addressing climate change.

“We want to transition the country to a clean energy economy while being true to the historic mission of the electricity industry, in particular to deliver safe, affordable and reliable power,” Crane said during a panel.

The panel’s moderator, Commissioner Ann Rendahl of the Washington Utilities and Transportation Commission, asked what DOE planned to do with the historic funding it received from the country’s Infrastructure Investment and Jobs Act and the Inflation Reduction Act. According to Crane, the agency was given $96 billion for financial assistance equity grants, and its Loan Program Office has around $400 billion in loan capacity.

DOE plans to use $10 billion for the Home Energy Rebate Program, which funds home energy efficiency and electrification projects. In August, DOE also announced up to $300 million for the Transmission Siting and Economic Development grant program, which helps fund transmission projects, grid modernization and wildfire mitigation.

The agency plans to announce an additional $20 billion in funding in the next few months, with the hopes of allocating it by the end of 2024, Crane said.

Tools for Resilience

Industry officials and regulators emphasized the need to look beyond mitigation toward creating a system of resilience that can support the country in the event of a climate disaster.

“Today, I think resilience is coming much more into the forefront,” said Katie Jereza, vice president of corporate affairs at the Electric Power Research Institute (EPRI). “Because we’re going to be more reliant on electricity, resilience is going to be of much more value in the future.”

Commissioner Tammy Cordova of the Nevada Public Utilities Commission echoed those concerns, saying that for utilities to deliver the level of reliability demanded, they need to be resilient in the face of climate change.

During a panel moderated by Cordova, Curt Stokes, senior attorney with the Environmental Defense Fund, highlighted the need to understand risk.

“What we advocate for is, as the electrical utility is planning and understanding how it serves its customers and as we work with individual communities and parts of the communities, understand what risks they’re facing and the role of the electrical utility grid in making sure that those communities are resilient,” Stokes said.

Morgan Scott, director of Climate READi at EPRI, discussed a tool designed to increase the power sector’s collective approach to managing climate risk.

Climate READi has three main components.

The first is understanding the type of data that exists to characterize climate hazards to a power station.

The second outlines how to use the data to assess risk to assets and inform design criteria for new assets that will be needed. As part of the effort, EPRI is building a climate asset matrix that lists every asset on the power system and each weather variable it could be exposed to.

The third component brings this information to a system level, looking at what assets need to be prioritized in the event of an extreme weather event.

Forty-two electric sector companies and over 80 stakeholder organizations in the U.S., Canada, the U.K. and France have joined Climate READi.

Andy Bochman, senior grid strategist with Idaho National Laboratory, spoke about the Climate Resilience Maturity Model, which considers the well-being of different infrastructure assets and ranks cities in terms of vulnerability and readiness. The model, which is promoted by the Environmental Defense Fund, can be used by energy regulators to hold utilities accountable to their obligation to provide safe, reliable and affordable service by managing climate related risks and building resilient systems.

Energy officials asserted that the tools they’ve developed are important steps in the right direction, but that more needs to be done.

“We spend a lot of time talking about mitigation, and we should, but with emissions rising every year, we’re not really getting much performance bang for all the noise and expenditure buck,” Bochman said. “We are building wind, solar and storage, EVs are coming — I have one, I have solar panels — but that’s not changing the amount of emissions that are going out globally appreciably, so we need much more attention on resilience and adaptation than it’s getting right now.”

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New Jersey to Adopt Advanced Clean Cars II Rule

New Jersey Gov. Phil Murphy (D) said Nov. 21 that the state has adopted the Advanced Clean Cars II rule effective Dec. 18, sparking relief from supporters who pushed for it to be ready for the 2027 model year and disquiet from business groups who say it will make vehicles more expensive. 

Murphy said the move to adopt the rule, which was first crafted and adopted by the California Air Resources Board, would put the state on a “road toward better air quality and cleaner choices for new car buyers while combating the worsening climate crisis.” 

A prepublication copy of the rule will be posted in early December to the Department of Environmental Protection’s Rules and Regulations webpage. 

New Jersey is the ninth state to adopt the rule, which will require all new light-duty vehicles sold in the state to be zero emission by 2035. Combined, the state adoptions mean that by the end of 2035, 28.5% of the sales of new light vehicles in the U.S. would have to be zero-emission vehicles (ZEVs), according to a tracking list put together by the Sierra Club. 

The rule requires manufacturers to make ZEVs a steadily increasing portion of their car sales, starting with 35% for model year 2026, increasing to 68% in 2030 and reaching 100% in 2035. It defines ZEVs as battery-electric, hydrogen fuel cell or plug-in hybrid. The rule also includes increasingly stringent low-emission vehicle standards aimed at reducing tailpipe emissions of gasoline-powered cars and heavier passenger trucks. 

Urban Benefits

Murphy announced his decision in a release containing quotes supporting the move from several environmental and pro-EV groups and the mayors of four urban communities in the state — Newark, Plainfield, Passaic and Trenton — who said rule would help combat emissions from the heavy traffic in the state. 

“As the largest automobile transportation hub and energy generation center in the state, Newark has much to gain through this rule,” Mayor Ras Baraka said. The rule will mean “greater investment into ZEVs, more jobs for city residents and more availability of these vehicles for motorists.” 

Transportation is the largest source of emissions in the state, generating about 37% of the emissions, and supporters of ACC II contend that the state needs tough requirements to accelerate the uptake of EVs and dramatically curb emissions. They say that more moderate programs such as offering incentives won’t stimulate enough purchases and don’t provide the certainty of the state’s commitment that the ACC II rule does. 

“By accelerating the growth of the EV market, ACC II will spur continued investment and innovation in the transition to a clean energy transportation sector,” said Richard Lawton, executive director of the NJ Sustainable Business Council. 

Price Hikes

The New Jersey Business and Industry Association (NJBIA), which led a campaign against the rule, called it an “unworkable mandate,” adopted over the opposition of more than 100 business and labor groups and thousands of people. (See NJ Businesses Demand Halt to EV Sales Promotion Rules.) 

Ray Cantor, a lobbyist for the NJBIA, said the state does not have the charging infrastructure to support a sudden, massive uptake of EVs. He added that because EVs are still much more expensive than gas vehicles, the sudden surge in sales requirements would result in consumers looking for lower-priced used vehicles, pushing the price up. 

“At the end of the day, the DEP did not heed any of those concerns, nor did it offer any solutions to them,” he said. “This ban of the sale of new gas-powered cars, in such an expedited time, does not take costs or feasibility into account. It does not take the lack of local and highway infrastructure into account. It does not take grid capacity into account. It ignores consumer choice. It doesn’t take New Jersey residents into account, especially low- and moderate-income families. And it doesn’t take the lack of actual environmental benefit into account.” 

Incentive Program Closure

State officials say New Jersey has more than 123,000 electric vehicles on the road, representing 12% of new vehicle sales. Since just last December, sales of EVs have surged 50%, according to the state. 

But that is a tiny portion of the estimated 6 million light-duty vehicles registered in the state. 

The New Jersey Coalition of Automotive Retailers says that to increase EV sales volumes, the sector needs to bring the vehicle price down and make more charging stations available, which would help consumers overcome range anxiety. 

To combat those concerns, state agencies have created a variety of programs to provide vehicle subsidies that bring the cost of an EV closer to that of a gas vehicle and help pay for the installation of charging infrastructure. The Board of Public Utilities said Nov. 20 that it is closing the fourth year of its Charge Up New Jersey program because the funds had been exhausted. The program had awarded $30 million since it opened on July 12, the BPU said. 

The Charge Up New Jersey program, which offers subsidies of up to $4,000 for the purchase of an EV, has awarded $120 million over four years and funded the purchase of 35,000 vehicles. 

The agency said it expects the fifth year of the program to open in July 2024. 

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Wash. Cap-and-trade Opponents Advance Repeal Petition to Sec. of State

KENT, Wash. — Opponents of Washington’s fledgling cap-and-trade program, which the state refers to as cap-and-invest, have delivered 418,399 signatures to the secretary of state’s office in a push to repeal the program.

The petition needs 324,516 valid signatures by Dec. 29 to advance to the Legislature. If lawmakers take no action on the petition, it will go to a November 2024 referendum.

“We’re going to give the voters a chance to vote it down,” Brian Heywood, a King County hedge fund manager leading the effort, said at a Nov. 21 press conference in Kent in front of a U-Haul trailer containing boxes of signatures. Heywood is providing more than 80% of the petition drive’s budget, according to the website of Let’s Go Washington, an organization Heywood has bankrolled to back the repeal effort and other initiatives.

Administered by the state’s Department of Ecology, Washington’s cap-and-invest program went into effect at the start of this year, requiring carbon-emitting entities to participate in auctions to bid on allowances that permit them to pollute. Opponents blame the program for the state’s high gasoline prices, saying oil companies are passing on their compliance costs at the gas pump. (See Cap-and-trade Driving up Washington Gasoline Prices, Critics Say.)

Smokestack emissions from Washington’s five oil refineries are exempt from the program, while the gasoline they produce is not.

‘Dead on Arrival’

The petition “will be dead on arrival,” state Sen. Joe Nguyen (D), chairman of the Senate’s Environment, Energy and Technology Committee, told NetZero Insider. The initiative will have to go through his committee before getting a wider hearing in the Senate.

Heywood said public ballot measures supporting a cap-and-trade program were defeated before the Legislature passed the cap-and-invest program in 2021. “The Legislature said ‘F U’ to the voters and [it] is saying ‘F U’ again,” Heywood said in response to the fact that a Democratic-controlled Legislature would be hostile to the petition.

Nguyen said the petitioners are unaware of the cap-and-invest program’s benefits. Also, he said, the 2021 law is the result of compromises reached among environmentalists, advocates for disadvantaged communities and the business community, including some in the oil industry. Nguyen also contended the petition’s backers are climate change deniers.

“Of course, climate change exists. Of course, humans cause climate change. I’m just not a member of the mother-breathing Church of Gaia,” Heywood said. He later added: “This money is going to the political friends and allies of the governor. To be honest, this is a money grab.”

In an email to NetZero Insider, Gov. Jay Inslee spokesperson Mike Faulk said: “As for the false claim about how auction revenue is spent, if he can’t back it up, then it’s not even worth printing. We’ve been more than happy to share with folks where the funds are going.”

The cap-and-invest program is on track to raise almost $2 billion in 2023. So far, $300 million has been appropriated to 188 projects. These include intermingling solar projects with farmlands, adding climate change to urban growth planning, climate change projects for the state’s tribes, capturing methane from landfills, installing solar panels on nonpublic buildings, dealing with child asthma in the SeaTac area, building infrastructure for electric vehicles, building a hybrid fuel/electric ferry, and overhauling ferry docks and terminals to handle electric ferries.

Faulk said 43% of cap-and-invest revenue is earmarked for poor and overburdened communities, with an additional 7% going to the state’s tribes.

The cap-and-invest petition is part of a Let’s Go Washington package of six petitions. Heywood said the organization is close to collecting 400,000 signatures for them. A standard rule of thumb in collecting initiative signatures is to gather far more than needed because the secretary of state’s office will throw some out because they are not valid.

Other petitions include calling for repealing a new capital gains tax on people earning at least $250,000 in capital gains. Another wants to forbid any state or local income tax in Washington, which has neither. No state income tax has been proposed for a long time.

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Solar Developers Sing Mid-Atlantic Interconnection Blues

BALTIMORE, Md. ― Some solar companies in the Mid-Atlantic have stopped looking for sites for utility-scale installations in the region due to the current backlog of renewable energy projects in PJM’s interconnection queue, according to Steve Swern, senior director for generator interconnection at Sol Systems, a Washington, D.C.-based developer. 

The RTO is not expected to clear that backlog and start reviewing new applications possibly until 2026, Swern said Nov. 16 during a panel discussion on interconnection at the Solar Focus conference hosted by the Chesapeake Solar and Storage Association (CHESSA). “So how do I tell a corporate off-taker that, sure, we can site a project for you to deliver renewable energy in PJM. Is a [commercial operation date] by 2030 OK?” 

A regional trade association, CHESSA’s members primarily are solar and storage developers in D.C., Maryland and Virginia — all in PJM’s 13-state service territory. When looking to site solar projects in the PJM footprint, Swern said, multiple strategies are considered, including bypassing the queue by approaching utilities to connect to their distribution grids.

The company intends to move ahead with projects it already has in the PJM queue but “is approaching utilities — transmission utilities, distribution utilities — to really push the envelope of how big can we build, what clients can we connect to, without involving the scrutiny, the oversight and the jurisdiction from the RTO,” Swern said. 

Getting more solar on the grid is a critical issue in D.C., Maryland and Virginia, each of which has set ambitious targets for running their respective electric systems on 100% clean power ― by 2032 in D.C., 2035 in Maryland and 2050 for Virginia. 

But reaching those goals likely will mean being able to import clean power from PJM. The nation’s capital, for example, has minimal generation within its 68 square miles, seven of which are water. PJM has warned Maryland of potential rolling blackouts if one of the state’s remaining coal plants, the 1,238-MW Brandon Shores generating station, is taken offline in 2025, as currently planned. 

According to figures from PJM, its power mix is still more than 60% fossil fuels. On the carbon-free side, in 2022, nuclear accounted for about one-third of the RTO’s generation fuel mix, but wind and solar together stood at 4.9%. At the same time, solar, wind and storage make up almost all of the over 300 GW of projects in PJM’s interconnection queue, as reported by the Lawrence Berkeley Laboratory.  

The grid operator is working on a Regional Transmission Expansion Plan aimed at adding the capacity needed for new renewables or other power that will replace retiring coal plants.

Like Swern, James Mirabile, the principal engineer for interconnection at Baltimore Gas and Electric (BGE), said getting renewables interconnected on distribution systems is an easier lift. In 2022, BGE had 91 projects totaling 139 MW in its interconnection queue, 35 MW of which went online that year. This year, to date, the queue has 87 projects totaling 165 MW and has interconnected 27 GW, he said. 

For BGE and other Maryland utilities, the process for getting those projects online is “very highly regulated,” Mirabile said, and the state’s Public Service Commission has set up an interconnection working group charged with updating the rules.  

The most recent update will go into effect Jan. 1, 2024, when all renewable projects will be required to use smart inverters with settings “that include a volt-var curve instead of a fixed power factor,” said Mirabile, who is a member of the working group. Such updated settings provide a flexible way for inverters to react dynamically to variations in voltage on the system, which can occur as more renewables come online, Mirabile said in an email to RTO Insider.  

BGE and four other utilities have submitted the smart inverter settings they will require for projects to the PSC, which approved the proposed settings on Nov. 21.  

The working group also has sent recommendations to the commission to reform cost allocation for distribution system upgrades, Mirabile said. Traditionally, when a project requires a distribution system upgrade for interconnection, the project developer carries the full cost. 

The working group is proposing a model where the project developer is allocated part of the cost, with the remainder “spread across future interconnecting customers,” he said. If approved, the proposed update would be “a major change in the way we price jobs.” 

The Aggregation Work-around

The backed-up interconnection queues at PJM and other RTOs and ISOs across the country are rooted in the wave of renewable projects seeking interconnection on systems that were “set up in such a way to not handle a large influx,” Swern said.  

Approved in July, FERC’s Order 2023 (RM22-14) is aimed at pushing grid operators toward some basic structural changes, such as doing cluster studies of projects seeking interconnection rather than on a case-by-case basis and attempting to weed out speculative projects by upping financial requirements for developers. (See FERC Updates Interconnection Queue Process with Order 2023.) 

But implementation of the order is on hold as FERC considers multiple requests for a rehearing on the rule. 

FERC previously approved reforms PJM had proposed to its interconnection process, similar to Order 2023 — cluster studies and stricter financial requirements — which the RTO rolled out in July. According to Susan Buehler, PJM’s chief communications officer, 40,000 MW of projects have been approved but not yet built.

Bahaa Seireg, senior director of energy storage at the American Clean Power (ACP) Association, said utility-scale energy storage projects are caught in the same slow interconnection queues. While an increasing number of states, including Maryland, have set targets for adding energy storage projects to the grid, Seireg said, it can take five years to work through transmission-level interconnection processes at an RTO or ISO.  

In May, Gov. Wes Moore (D) signed a law setting a goal for the state to have 3,000 MW of storage online by the end of 2033.  

Seireg sees a possible workaround for the interconnection problem in aggregation that breaks down the traditional divide between distribution and transmission. “Now, you can actually interconnect [solar and storage] to the distribution grid and aggregate resources … add them to distribution substations, aggregate them and bid them into the wholesale market,” he said. 

“That allows for some temporary reprieve from PJM,” he said.  

Sol Systems sees another “prime opportunity” for getting projects interconnected quickly at municipal utilities and electric cooperatives. These smaller, nonprofit utilities often are unregulated and “have a lot of flexibility in the decisions they make, in the projects they move forward and how costs are allocated,” Swern said. 

He also pointed to grid-enhancing technologies — such as advanced conductors and dynamic line ratings — as another option for maximizing the capacity of existing lines. “These are very low-cost solutions that help give grid operators higher granularity to thermal capacity of wires in a very specific location, [which] allows projects to operate … at full bore without being curtailed,” he said. 

The Information Gap

But the panelists all see major gaps in the information developers need to site and design projects that can get interconnected as quickly as possible.  

“Where we see a major stumbling block for interconnection is the quality of data, the existence of the data and the ability to use that to make informed decisions,” Swern said. In some cases, just figuring out where transformers are located means sending out trucks to map an area, he said. 

Some utilities now have online “hosting capacity” maps, showing what lines in their service territories have excess capacity, but Swern said, not all maps are created equal. “Some of them just give you a color-coded map; some of them actually allow you to click on the feeder itself and see what’s the ability to connect [distributed energy resources]; some you can get a load profile … for the past two years,” he said. 

At BGE, the best way for a developer to check out the available capacity of distribution lines at a site is to contact Mirabile directly, and he will do a pre-application analysis, he said. It’s reliable but not self-service, he admitted. 

Swern sees a more fundamental obstacle to interconnection in the misalignment of “spheres of control … or jurisdiction.” Federal, state, county and local governments all “have specific targets, mandates, goals for deploying renewables or retiring fossil assets … and there isn’t a good way to align all of those different things.” 

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New Jersey Launches OSW Infrastructure Solicitation

New Jersey’s Board of Public Utilities launched a new solicitation for offshore wind coastal infrastructure Nov. 17 as the heads of the BPU and the Economic Development Authority reaffirmed the state’s commitment to developing OSW projects in the wake of Ørsted’s abandonment of its two projects.

The BPU board, with a 4-0 vote, opened a solicitation for proposals to build a link between future wind projects developed off the Jersey Shore and the onshore substation infrastructure backed at the conclusion of a State Agreement Approach (SAA) solicitation on Oct. 26, 2022. (See NJ BPU OKs $1.07B OSW Transmission Expansion.)

The BPU vote opened the new infrastructure solicitation with a submission deadline of April 3, 2024. The agency set out a schedule in which favored proposals would be picked in the third quarter of 2024, with an expected project in-service date of January 2029.

Brushing off Ørsted’s withdrawal, BPU President Christine Guhl-Sadovy said at the meeting the agency is “looking forward” to the third solicitation for offshore wind developments and said it had been “our most competitive yet.”

“Offshore wind is, and continues to be, the economic development opportunity of a generation and remains a key tool in climate change mitigation,” she said. “We remain excited about the prospect for a future generation and transmission solicitations.”

Protecting Ratepayers

Gov. Phil Murphy (D) has set a state wind capacity target of 11 GW by 2040, of which the BPU so far has awarded 3,758 MW. The BPU approved its first OSW project, Ørsted’s 1,100-MW Ocean Wind 1, in the first solicitation in 2019, and two other projects — the 1,148-MW Ocean Wind 2 project and the 1,510-MW Atlantic Shores project — in the second solicitation, in 2021.

The Atlantic Shores project continues to move ahead. But Ørsted stunned New Jersey officials on Nov. 1 by cancelling its two Ocean Wind projects, saying that cost increases had made the projects untenable. (See Ørsted Cancels Ocean Wind, Suspends Skipjack.)

In the state’s third solicitation, the BPU initially required developers submitting bids to include plans for the construction of infrastructure — known as pre-build infrastructure or PBI — that could tie several projects to the on-land infrastructure. But the board on Oct. 25 split off the offshore infrastructure requirement, saying that such a plan would impose an “unreasonable burden” on ratepayers, and that separating the two elements would create greater competition for the infrastructure projects. (See NJ Revamps Third Solicitation OSW Connection Plans.)

Jim Ferris, deputy director of the BPU’s division of clean energy, told the board Nov. 17 that the agency’s initial strategy of bundling the project and PBI elements together would have meant the developers would be awarded incentives for the entire package in offshore wind Renewable Energy Certificates.

Staff reviewed the proposals and found they represented an unreasonable burden for New Jersey’s ratepayers, he said, and that separating the two has not affected the projects already submitted for the third solicitation.

Servicing Multiple Projects

Four bidders submitted plans for the third solicitation, which could add OSW capacity of between 1.2 GW and 4 GW, and perhaps more, according to the guidance document for the solicitation. (See NJ Opens Third OSW Solicitation Seeking 4 GW+.)

The solicitation, which the BPU released as an attachment to its order, seeks proposals for “all cable vaults, duct banks and related facilities for four (4) separate qualified projects, enabling qualified project developers to install their cables into the prebuild by pulling them through the completed prebuild infrastructure facilities.”

Unlike the first infrastructure solicitation, held under the SAA agreement, the BPU will conduct the new infrastructure solicitation solely with BPU staff rather than in partnership with PJM, but will get “support from PJM, as requested by staff,” according to the order. The solicitation adds that it is open to companies that are prequalified through “PJM’s planning process to be a Designated Entity.”

Optimism for the Future

The state’s commitment to offshore wind includes extensive investment in creating infrastructure to support the development of a supply chain and logistics services that can support the projects, including the development of the New Jersey Wind Port on the Delaware River.

Much of that work has been funded by the EDA, where Chairman Terence “Terry” O’Toole — speaking at the agency’s monthly meeting Nov. 16 — called Ørsted’s decision “very disappointing and frustrating news.” He said that “despite the setback, there continue to be massive opportunities for New Jersey in this new sector and making investments in infrastructure and the manufacturing capacity support.”

Tim Sullivan, EDA’s CEO, said the agency has “continued optimism” about the sector, in part because “there is so much private capital being invested in the US wind industry, there’s so many private sector interests.”

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PJM MRC/MC Briefs: Nov. 15, 2023

Markets and Reliability Committee

Vote to Close Clean Attribute Group Fails

VALLEY FORGE, Pa. — The Markets and Reliability Committee voted against sunsetting the Clean Attribute Procurement Senior Task Force (CAPSTF), instead putting the group on track to be on hiatus as a state-led working group continues discussions outside the PJM stakeholder process. (See “Stakeholders Mixed on Sunsetting Clean Attribute Procurement STF,” PJM MRC Briefs: Oct. 25, 2023.) 

Task force facilitator Scott Baker said PJM dropped its recommendation to sunset the CAPSTF given ongoing discussions the states are having with FERC staff to explore whether a forward clean energy market (FCEM) would fall under state or federal jurisdiction.  

If the issue is determined to fall under the commission’s purview, it would return to the PJM stakeholder process to determine what form it would take and how it would operate. After Baker said PJM would not pursue sunsetting the task force, Paul Sotkiewicz, president of E-cubed Policy Associates representing JPower USA, motioned to sunset, receiving 34% support. 

The FCEM design would allow clean energy attributes to be purchased and traded by states and entities with sustainability targets and provide a centralized platform for existing renewable energy credit (REC) sales. PJM currently administers a registry of RECs through the subsidiary PJM EIS (Environmental Information Services), but it does not facilitate the trading of credits. 

Constellation’s Juliet Anderson said that if a Forward Energy Attribute Market design was determined to be FERC-jurisdictional, it could be returned to PJM stakeholders for consideration most efficiently through the existing charter of the senior task force. 

Calpine’s David “Scarp” Scarpignato said PJM task forces are meant to address specific topics over a specific period of time and the work envisioned for the CAPSTF has been complete. He argued that a new stakeholder group with a scope or charter more specific to any future needs would be better than leaving the task force open in case it can be restarted. 

Endorsement of Multi-schedule Modeling Solution Deferred

Stakeholders opted to defer voting on two proposals to narrow the number of market seller offers entered into the market clearing engine (MCE) in order to allow multi-schedule modeling capability to be added to the engine without causing processing times to increase beyond the day-ahead market’s 2.5-hour clearing window. The introduction of multi-schedule modeling is part of a larger overhaul of the engine under PJM’s Next Generation Markets initiative. (See “Multiple Proposals Considered for Incorporation of Multi-schedule Modeling,” PJM MRC Briefs: Oct. 25, 2023) 

PJM Associate General Counsel Chen Lu recommended delaying the vote to the December meeting in the hope that an anticipated FERC order on parameter-limited offers and real-time values would provide more clarity on how the proposals would be viewed by the commission. However, the docket was pulled off the agenda for the Nov. 16 open meeting (EL21-78). 

Both proposals would allow the day-ahead market to adopt the formula currently used in the real-time market to select one schedule from a resource to be modeled by the MCE. The main motion, sponsored by PJM in the Market Implementation Committee, would consider all offers with the aim of producing a schedule with the lowest total dispatch cost. 

The alternate motion, jointly sponsored by GT Power and PJM, would use the same formula, but would mitigate resources that fail the three-pivotal-supplier test to their cost-based offers, disregarding any price-based offers. During emergency conditions, the proposal also would limit capacity resources to their price-based parameter-limited offers. 

GT Power’s Tom Hyzinski said the joint proposal would alleviate the potential “crossing curves” issue in PJM’s design, in which the RTO would consider offers only at their economic minimum (EcoMin) value even if that offer would be more expensive at higher outputs. Highlighting the topic during the Oct. 25 MRC meeting, Deputy Market Monitor Catherine Tyler gave an example of a resource where the price-based offer is cheapest at its 100-MW EcoMin but  jumps to the $1,000/MWh offer cap when the resource is dispatched above 120 MW. In such a case, she said the cost-based offer should be selected even if it’s more expensive at EcoMin. 

Tyler said both PJM proposals could run into an issue in which dual-fuel generators may be selected to run on a schedule using a fuel that is not economical for a portion of the day. The Market Monitor/GT Power Group joint proposal is identical to the PJM/GT Power Group proposal except that the Monitor proposal allows generators to select the fuel they want to use while the PJM proposal has PJM choose the fuel. 

Scarpignato said the proposals would go beyond fixing an issue identified by the Energy Management System vendor and would sacrifice some of the current flexibility in the day-ahead market. PJM’s Keyur Patel responded that the status quo has the most optimal schedule selection process and there would be trade-offs to meet the technical requirements of adding multi-schedule modeling capability to the MCE. 

Sotkiewicz urged PJM to explore whether hardware and software changes could resolve the computational limitations to allow the status quo schedule selection to be retained. 

“We’re sacrificing optimality on solutions because we’re unwilling to make a lot of the investments in hardware, software, parallel processing,” he said. “We’re drifting away from optimality, and we could pour more money into resources on this to get to the right answer.” 

Patel said PJM looks at upgrading its hardware every two to three years, but the benefits of replacing servers are limited as the software is integrated. He said solution times are expected to improve as the software is fine-tuned after being launched. 

New Winterization Requirements Endorsed

The committee endorsed revisions to Manual 14D, which details operational requirements for generators, to require that resources prepare for winter conditions by either developing their own winterization checklist or following the list produced by PJM, which itself was expanded under the proposal. (See “Generation Winterization Requirements Endorsed,” PJM OC Briefs: Nov. 2, 2023.) 

The revised checklist added guidance for combustion turbine intake preparation, drawing from NERC’s Lessons Learned. It prompts generation owners to assess safety hazards posed by snow and ice accumulation on wind and solar facilities, inspect commodities and resources that may be used in severe winter weather, and consider adding a “freeze protection operator” staff member to inspect critical equipment. 

The revisions also included clarifying changes such as replacing definitions with references to corresponding sections of the governing documents, specifying that the critical information and reporting requirements include a need to notify PJM dispatch by phone and several administrative changes. 

PJM Presents Regulation Market Rework

PJM’s Danielle Croop presented the proposal recommended by the Regulation Market Design Senior Task Force (RMDSTF) to redesign the regulation market to have one price signal and two products representing a resource’s ability to adjust its output up or down. The proposal carried 86% support at the RMDSTF during an August vote, with two competing proposals receiving 26% and 6%. 

The new price signal would be easier for market participants to follow and would result in all resources having the same settlement process, Croop said. Resources would be able to participate as being only regulation up (RegUp), regulation down (RegDn) or capable of doing both. The current market design has two price signals: Regulation D for resources that can modulate their output almost instantly and Regulation A for longer deployments. 

The proposal also would shift to a 30-minute clearing and commitment period, down from the hourly intervals used now; less testing required for new and returning regulation resources; a ramp-limited lost opportunity cost (LOC) calculation meant to avoid overestimating LOC; and a performance score based only on the precision of the response, rather than the average of the scoring of its response accuracy, delay and precision. The proposal would add an annual review of the market to consider if the changes the grid is experiencing during the clean energy transition necessitate any adjustment of the regulation requirement. 

Croop said the new scoring method would tend to be stricter, but still accurately capture resources’ performance when called upon. 

The market overhaul implementation would be split into two phases, with the first year introducing all the changes except the RegUp and RegDn products, which would be added in the second year. 

American Electric Power’s Brock Ondayko said the proposal may impact the ability for energy storage to provide regulation service, as those resources typically would be able to provide both RegUp and RegDn but would be able to move in one direction only if they are fully charged or depleted. 

Croop told RTO Insider that there wouldn’t be a change to how batteries participate in the market, and they would be able to remain in the market when fully charged or depleted. However, they may experience a reduction in their performance score if they are not able to follow the price signal. 

Carl Johnson, representing the PJM Public Power Coalition, said he was concerned the task force would work around the edges of an RTO proposal FERC rejected in 2018 and was glad to see an entirely new market design proposal came out of the group’s deliberations. (See FERC Rejects PJM Regulation Plan, Calls Tech Conference.) 

Independent Market Monitor Joe Bowring presented several concerns with the proposal, arguing the bidirectional price signal is not fully developed. He also argued against calculating LOC based on how a resource is dispatched over multiple regulation intervals, preferring it be reset for each half-hour period, and said PJM’s approach would result in significant overpayment of opportunity costs. 

“There is no good reason to approve a market design that has not been developed or tested. In addition, the joint optimization with the energy market would make the energy market less efficient,” Bowring said. 

PJM, Monitor Urge Participants to Complete Account Manager Migration

PJM’s Chidi Ofoegbu said the Dec. 13 deadline for eDART accounts to be migrated to the new Account Manager (AM) software is fast approaching with less than a fifth of users completing the transfer process. Of the 7,933 accounts in eDART across 758 companies, 1,433 have a corresponding account in AM, representing a completion rate of about 18%. (See “Migration of eDART Accounts to New Platform Underway,” PJM PC/TEAC Briefs: Aug. 8, 2023.) 

Once the deadline arrives, active eDART accounts will have their access revoked and users will not be able to access their accounts, rendering them unable to create generation or transmission tickers, respond to data requests or view reports in eDART. 

Bowring said it would be difficult to participate in PJM’s markets and complete required tasks without access to the online tools. 

“Key market functions depend on eDART. If you do not have access to eDART it’s hard to see how you could function in the markets. … The numbers now are frighteningly low given how close the deadline is,” he said. 

Members Committee

3 Revisions to Stakeholder Process Endorsed

The Members Committee endorsed revisions to Manual 34, which outlines the stakeholder process, to change the voting structure at the MRC and MC, clarify the relationship between the higher and lower committees, and set deadlines for adding items to committee agendas. (See “3 Changes to Stakeholder Process Proposed,” PJM MRC Briefs: Oct. 25, 2023.) 

Under language brought by Dayton Light and Power (DLP), the senior standing committees continue to vote on any main motions before considering alternates. Those alternates now would be voted on simultaneously, similar to the lower committees. 

One of the two proposals by Exelon clarifies that the MRC and MC hold final authority on topics considered by task forces and the lower committees, which have the role of setting the order of proposal votes at senior committees. The other revision requires that requests to add items to committee agendas must be made at least seven days in advance and include a summary of any action sought by the committee in order to be considered timely. Committee chairs would retain discretion to consider untimely items should they be time-sensitive or the result of unforeseen disruptions, or non-voting items such as informational reports. 

Several states objected to the two Exelon revisions and abstained from voting on the DLP proposal. Four industrial consumers also abstained on the DLP language. 

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North Carolina Regulators Combine Duke’s IRP with Carbon Plan

The North Carolina Utilities Commission issued an order Monday combining Duke Energy’s integrated resource plan with its carbon plan. 

The regulator approved the firm’s first carbon plan late last year, separately from the IRP process. (See North Carolina Regulators Approve Duke’s 1st Carbon Plan.) 

For regulatory efficiency, the two are going to be rolled into one process, with Duke filing a proposal earlier this year after consulting with the NCUC’s public staff for weeks. 

The utility will have to file a consolidated carbon plan and integrated resource plan (CPIRP) every two years for approval, which will have Duke continuing to meet its obligation to serve load in its territory while making long-term plans for carbon neutrality. State law requires a 70% cut in carbon emissions by 2030 and carbon neutrality by 2050. 

The plans will have to include several different resource portfolios so that a range of demand-side, supply-side, energy storage and other technologies can be fairly evaluated in the process. Those plans are required to either maintain or improve upon the adequacy and reliability of the existing grid. 

The NCUC agreed with the North Carolina Attorney General’s Office that at least one of the plans Duke submits needs to meet the 2030 carbon target. Legislation gave the commission the authority to delay that target, and it needs the planning data to make that decision, it said. 

The CPIRPs will require near-term action plans that identify specific investments in the demand and supply sides, procurements and retirement activities, and upgrades to the transmission system needed to interconnect new resources. The attorney general suggested that Duke be required to identify whether those near-term plans can support the resource portfolios in the CPIRP and, if not, any additional activities that would bring the company on track to meet longer-term carbon goals. The commission agreed. 

The NCUC declined to include transmission planning into the CPIRPs directly, but it agreed with some intervenors that the carbon plans should inform it. Duke will have to discuss how the most recently approved CPIRP was incorporated into its transmission planning process, the regulator said. 

The CPIRP process includes some stakeholder meetings before it is filed with the NCUC and that is meant to produce a report on what was discussed during that time. The NCUC said that the report will have to include a list of which stakeholder ideas Duke decided to adopt in its initial plan, which will give the commission some clarity on how well the early stakeholder discussions are working. 

The Clean Energy Buyers Association asked the NCUC to require Duke to include information on the costs and benefits of participating in the Southeast Energy Exchange Market (SEEM) and whether participating in an RTO, especially PJM (which neighbors Duke’s territory), would be cheaper overall. 

Duke opposed CEBA’s request, saying nothing in the relevant statutes on carbon plans and IRPs discusses wholesale market participation. The utility also said it would join an RTO only if state or federal legislation required that, which is not the case now. 

IRP modeling also is not capable of capturing the 15-minute granularity of SEEM transactions over a long planning period, Duke said. 

The current rules already are enough for Duke to consider wholesale issues, and requiring the kind of study CEBA wants would only add unnecessary costs given the lack of legislation requiring RTO membership. 

Duke filed its initial CPIRP in August, and said it followed the proposal that was pending at the NCUC at the time. The commission deemed that August filing in compliance with the order issued Monday. 

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NYISO to Keep Gas Peakers Online to Solve NYC Reliability Need

NYISO announced Nov. 20 it will keep two natural gas peaker plants in Brooklyn operational beyond their state-mandated retirement to address a generation shortfall in New York City.

The ISO’s Nov. 20 Short-Term Reliability Process Report said the Gowanus 2 & 3 and Narrows 1 & 2 barge-mounted power plants will remain online to help plug a 446-MW reliability deficit.

The deficit was identified in NYISO’s second quarter Short Term Assessment of Reliability, which said the city would be short for up to nine hours on the peak day in 2025 during expected weather conditions, assuming forecasted economic growth and policy-driven increases in demand. (See NYC to Fall 446 MW Short for 2025, NYISO Reports.)

The two facilities, owned by Astoria Generating Co., collectively can generate 564.9 MW and contribute 508 MW toward New York City’s transmission security margin.

The Gowanus facility has been operational since 1971 and compromises 32 simple-cycle combustion turbines, each with a nameplate value of 20 MW. The Narrows facility has been running 32 similar units since 1972, but with a nameplate value of 22 MW.

NYISO’s decision highlights the challenges New York faces in balancing reliability with environmental regulations and increasing energy demands under electrification.

NYISO Chief Operating Officer Emilie Nelson said the ISO is committed to a reliable transition to emissions-free resources and is aware of how fossil fuel plants — a source of ozone-contributing pollutants — affect surrounding communities. “This means running these units only when conditions require, and closing them when no longer necessary for reliability,” she said.

The ISO’s report says Gowanus and Narrows help New York City’s bulk power transmission system during unexpected facility outages or during extreme weather conditions like a heat wave when other power producers may become unavailable.

The units were set to retire May 1, 2025, to comply with the Department of Environmental Conservation’s 2019 Peaker Rule, which imposes nitrogen oxide emissions limits on fossil fuel plants. NYISO reports that 1,027 MW of peakers had ceased or limited their operation as of May 1, 2023, with an additional 590 MW scheduled to go offline by the 2025 deadline, all of them in New York City.

The peaker rule allows plants needed for reliability to remain operational until May 1, 2027, with a potential two-year extension to May 1, 2029.

NYISO anticipates improved generation margins in 2026 with completion of the 339-mile Champlain Hudson Power Express, which will carry up to 1,250 MW of hydropower from Quebec to New York City. If the project is delayed, or if more power plants are retired, or demand exceeds forecasts, the city could experience a reliability shortfall for up to 10 years.

Even with CHPE, “the margin gradually erodes through time thereafter as expected demand for electricity grows,” the ISO said. And it noted that while CHPE will help summer reliability, it is not expected to provide any capacity in the winter. New York’s winter electricity demand is forecast to increase over the next decade.

New York City transmission security margins with designated peakers | NYISO

The decision to keep the Gowanus and Narrows plants operational was a last resort, made after alternative proposals failed to present viable solutions that could address the 446-MW deficiency and be installed before 2025.

Con Edison proposed installing roughly 16 miles of 345-kV underground cables and associated stations. The ISO said the proposal was rejected because the project would not be completed until “well after” the CHPE’s anticipated in-service date.

Orenda, a renewable energy storage supplier, proposed a reliability must-run solution involving small battery storage projects interconnected with Con Ed’s distribution system. However, the ISO deemed this output — a maximum of 27 MW over four hours, or up to 12 MW over the nine-hour duration of the need — insufficient. “The total capability of the Orenda batteries is less than the output of the smallest Gowanus or Narrows peaker,” the ISO noted.

The ISO said it received no market-based proposals to solve the shortfall.

“NYISO is working very closely with the DEC, the Public Service Commission and NYSERDA [the New York State Research and Development Authority] as we address the reliability need in New York City and a reliable transition to renewable resources for the state,” Nelson said.