Page 1082 – RTO Insider

June 30, 2020

NEPOOL Participants Comm. Briefs: June 23-24, 2020

ISO-NE External Market Monitor David Patton delivered highlights from his 2019 assessment of the RTO, comparing its markets with others in the Eastern Interconnection and making several recommendations.

Patton, president of Potomac Economics, related concerns about the current Forward Capacity Market and plugged the benefits of a prompt capacity in the context of improving coordinated transaction scheduling with NYISO.

“We think the pros of a prompt capacity market outweigh the cons,” Patton told the New England Power Pool Participants Committee on June 23. “In other words, we tend to think prompt capacity markets perform better than forward capacity markets, and the large demand forecast errors that have occurred In New England highlights one of the many concerns of a forward capacity market.”

[Note: Although NEPOOL rules prohibit quoting speakers at meetings, those quoted in this article approved their remarks afterward to clarify their presentations.]

However, he did not recommend eliminating the FCM because the benefits of doing so do not clearly outweigh the market disruptions it would cause. But he did recommend that ISO-NE replace the descending clock auction with a sealed-bid auction to improve competition in the Forward Capacity Auction.

Patton also recommended improving the minimum offer price rule by: eliminating performance payment eligibility for units subject to the MOPR; capping the minimum offer price at the net cost of new entry; and exempting competitive private investment from the MOPR.

A comparison of net revenue across various regional electricity markets showed that a well functioning wholesale market helps establish transparent and efficient price signals, which in turn influence the locations and technologies of new projects, according to the EMM’s report.

In New England, net revenues have been close to the levelized new entry costs for combustion turbines, but this will not continue in the future as capacity prices fall over the next few years, the report said. With tax credits and renewable entry credits, the markets are providing more than sufficient revenues for wind resources. Wholesale market revenues will continue to play a key role in motivating entry of flexible units that help integrate policy resources and prompt the retirement of inflexible units.

The EMM also recommended the RTO modify allocation of “economic” net commitment period compensation (NCPC) charges — the payment made to market participants that don’t recover their effective offer costs — to align it with cost causation, and pursue improvements to the price forecasting that is the basis for CTS with NYISO.

An uplift rate of $2 to $3/MWh over the past three years generates millions of dollars in day-ahead NCPC payments, but “the shocking number is the number of hours, almost half the hours of the year, when commitments are being made to supply spinning reserves,” Patton said.

“This signifies that both our prices and our compensation in the day-ahead is not very efficient when it comes to the types of units that are supplying the spinning reserve product,” he said. “It also tends to undermine the energy price because, to the extent that costs are being incurred to meet the spinning reserve requirements, those costs should be reflected in energy prices.” However, Patton indicated that the RTO’s Energy Security Improvements (ESI) initiative will address these concerns.

When asked about how recent reductions in load forecasts should be factored into the capacity market requirements, Patton said that “the general principle is that you should do everything you can to make your installed capacity reserves forecasts as accurate as possible, recognizing that there are Tariff requirements and tradeoffs where the ISO has to publish what the requirements are in advance of the auction so that people can … offer into the auction.”

Further recommendations are to modify the performance payment rate to rise with the reserve shortage level and not implement the remaining planned increase in the payment rate; and consider modifying the capacity compensation of energy-limited resources to be consistent with their reliability value.

The Monitor also recommended that the RTO require the use of the lowest-cost fuel or configuration for multiunit generators when they are committed for local reliability.

BPS Reliability Perspectives for 2050

NERC CEO Jim Robb gave the PC a look at various bulk power system reliability perspectives at midcentury, with key issues being the timing of technology development and deployment (especially batteries), the pace of deep electrification and the regulatory treatment of natural gas.

“The one challenge our industry has is that we’re enormously reactive,” Robb said. “We are great at responding to an event and figuring out what went wrong and changing it, but we are not great at heading events off before they happen, because it’s hard to motivate people to make hard choices when they don’t feel them very present.”

Bruce Ho of the Natural Resources Defense Council referred to the need for increasing system flexibility in which load follows generation — rather than just generation following load — as the country gradually moves to a fully decarbonized grid that relies on variable energy resources like wind and solar.

“I’m curious what you see as the role in the other direction, with more dynamic loads that follow supply,” Ho said, citing the importance of demand response. “What role do you see on the demand side, and do you have any thoughts on how markets and reliability standards might need to adapt to incorporate and compensate that dynamic load?”

“We need to rethink so many things, because I actually have a bias of thinking of the electric system serving load,” Robb said. “And you’re right; as Mark Lauby says — who’s our chief engineer and the smartest technical guy I know on this stuff — that concept is increasingly flawed.”

Planners need to expand their thinking about the grid beyond a linear relationship between the bulk power system, the distribution system and end users, he said. It would be wrong to describe them as being “integrated,” Robb said.

“Really, they’re all interdependent,” he said. “When I talk about the new models, the new operating paradigms, I think those issues need to be brought in as much as anything else. Demand response can play a really important role, but will it be there on the fourth day of the heat wave? I have a little bit of a [former PJM CEO] Terry Boston view of the world in that I like iron in the ground, because I know I can do something with it.”

Robb cited cybersecurity as a constant issue and said he does not like the term “Internet of Things,” preferring to think of it as the “Internet of Threats.”

Investing in the Future

Scott Kushner, managing director of Boston-based John Hancock Infrastructure Investments, discussed how he and his team decide where to invest in the electric power industry and how changing public policy affects such decisions.

Of the firm’s $30 billion in assets under management, approximately 30% is invested in private equity investments, while the remaining 70% is in investment-grade, long-term, fixed-income debt products, Kushner said.

“We lend to utilities; we’ve lent to projects, power plants of all technologies, all fuel sources; but certainly lately renewables has become a very big piece of what we’re looking at on both the debt and equity side,” Kushner said. “One of the main drivers of that, if you look at what an insurance company likes to invest in, is the lower-risk stuff, the stuff with longer-term contracts.”

On lowering the cost of capital, James Daly, vice president of energy supply at Eversource Energy, asked whether Kushner preferred programs with more revenue certainty or those dependent on merchant revenues.

“It certainly helps from an institutional investor standpoint,” Kushner said. “I would say that SREC 1 and SREC 2 [solar renewable energy credits] in Massachusetts worked really well, but certainly when we’re looking at the cost of capital for the SMART [Solar Massachusetts Renewable Target] program, which has the longer-term feed-in tariff like contracts, the cost of capital has come down even lower.”

Whether because of highly structured state programs or just the evolution of time and more investors starting to get comfortable in the clean energy space, “certainly the longer the contract, the more certainty in it, there’s no denying that will lower the cost of capital,” Kushner said.

“It seems that the capacity market in New England, with the seven-year lock rate available for new resources, is able to provide sufficient revenue certainty and risk reduction to make financing terms attractive for gas generation, but it doesn’t have the comparable impact for financing of renewable generation because those resources get the majority of their revenue from the energy market, which has no similar long-term certainty,” said Abigail Krich, president of Boreas Renewables.

“While state solicitations for long-term contracts and programs like SMART are filling in that gap to provide comparable revenue certainty to renewable resources, if the wholesale market were modified to be able to supply a similar level of revenue certainty to renewable resources, would those long-term contracts and policy commitments for renewables still be needed in order to be able to finance them?” Krich said.

There’s a place for both gas-fired generation and renewables in the market, Kushner said.

“If the market were to shift from these longer-term contracts to something like the capacity market for fossil fuels, which gives these projects price certainty for maybe five to seven years, the projects absolutely will get financed,” Kushner said. “It just depends on who’s going to actually finance them and what the ultimate cost of capital is.”

Problem Trio

Rutgers University professor Frank Felder, who teaches electricity policy and market structures, presented a thesis posing three types of problems that market operators and public officials must address: political economy, economic/regulatory and engineering.

“They are really three subsets of the same problem,” said Felder, director of the Rutgers Energy Institute and the school’s Center for Energy, Economic and Environmental Policy.

Deep decarbonization is a political economy problem because it concerns jobs, costs and economic policy, which interact with the economic and regulatory problem, he said.

“Whether an entity is regulated, or in a market environment, or in an integrated utility environment, there are economic and regulatory incentives that shape the decision-making, and in particular with long-term loan capital assets, you have a variety of problems, such as asymmetric information,” Felder said.

For example, an offshore wind developer knows more about the cost structure of a power purchase agreement than the regulator signing off on the deal, he said.

Engineering comprises both optimization and system-control problems, Felder said.

Political, economic and reliability difficulties are likely to arise unless these three types of problems are addressed in an integrated and consistent manner, he said.

“Massachusetts is really committed to trying to find a market-based solution to integrate clean energy,” said Matthew Nelson, chair of the state’s Department of Public Utilities. “We know that’s not going to be easy.

“Massachusetts has been very supportive of carbon pricing, so we’ve supported the Regional Greenhouse Gas Initiative. We have initiatives [that encompass more than] energy, like our state-specific Clean Energy Standard, and the Transportation Climate Initiative, but we’re not so interested in a FERC-jurisdictional carbon pricing — that concerns us,” Nelson said.

Massachusetts wants to ensure that a carbon price brings clean resources online and that it works with existing state policies, he said. Meanwhile, “other states in New England are in very different places on this one as well.”

“Where we’re all aligned, at least on carbon, is we don’t have any interest in a federal-based carbon price that would prevent states from achieving their individual goals,” Nelson said. “How is the price set? How is it priced accurately? Those are big, fundamental questions that bother individuals.” (See Study: $25 Carbon Price Needed to Meet Goals.)

Speaking to RTO Insider after the meeting, Nelson said, “Specifically here, what I think is important is who is setting the price and that process, because obviously that’s a big decision and will influence the outcome. I feel that’s a question we need to answer before states would be supportive.”

Some states don’t have clean energy targets and don’t think that increasing the price of carbon is actually what they want to achieve, he said.

“At this time, I just don’t think that a new carbon price adder outside of RGGI is politically feasible for all six states,” Nelson said. “But we’re not scared to talk about the data, what that data achieves, where the price is set. I think we have to have the conversation around what the numbers are and what we’re paying through different processes, to understand the different policy decisions we’re making.

“We have aggressive clean energy targets in Massachusetts,” he said. “I know that we’re going to need more clean energy to come online, and most of the need will be met through load growth through some of our policies around decarbonization of transportation, of buildings. And continued out-of-market contracts still have some inherent drawbacks, especially in the long-term scale we’re talking about.”

June 30, 2020

GOP Continues Opposition to Pa. RGGI Plans

Pennsylvania Republican senators said last week that Gov. Tom Wolf’s plan to join the Regional Greenhouse Gas Initiative will accelerate the closure of the state’s coal-fired generating plants, dealing another economic blow on top of the coronavirus pandemic.

The Senate Environmental Resources and Energy Committee heard from 11 speakers, including a Critics: Pa. RGGI Hearing Stacked with Detractors.)

Committee Chairman Gene Yaw (R) said joining RGGI will exacerbate the disruption Pennsylvania’s energy sector has suffered during the pandemic. “There are many questions that remain with regard to the governor’s executive order instructing the Pennsylvania Department of Environmental Protection [DEP] to participate in RGGI,” Yaw said.

Yaw and Committee Vice Chairman Joe Pittman (R) led a group of legislators that signed a letter in April asking Wolf to rescind his executive order out of “respect for the oversight process,” noting the committee had to cancel four public hearings on the issue because of the pandemic.

During the hearing, Pittman grilled DEP Secretary Patrick McDonnell, saying that three coal-fired plants in his district — Conemaugh Generating Station, Homer City Generating Station and Keystone Generating Station — will likely be shut down if the state joins RGGI, causing thousands of job losses.

“I’m not naive to the market conditions,” Pittman said. “I recognize the challenges that exist already. But my goodness, allow the market to work. And if you really want us to adjust as communities, then show us the examples of what you’re going to do to rectify the damage being done to our communities.”

McDonnell said people are “going to be standing outside shuttered plants” within the next 10 years regardless of whether Pennsylvania joins RGGI because of the direction of the energy market. He said utility-scale solar generation is becoming the cheapest resource available within the PJM market and that coal generation is quickly disappearing.

“The reality is the market is driving these decisions,” McDonnell said. “The market is driving decisions around moving to renewable energy, clean energy and energy efficiency.”

Minority Chairman Steven Santarsiero (D) said he “wholeheartedly” supported Wolf’s plan, saying RGGI will allow the state to meet its carbon emission goals and provide economic benefits to residents.

“This is an important change in Pennsylvania policy, and as a consequence, it does require thorough public input and thorough input to this committee as we move forward,” Santarsiero said.

First Climate Goals for Pennsylvania

Reducing CO2 emissions is a top priority for the Wolf administration. In 2019, according to the DEP, only 5% of Pennsylvania’s 231,245 GWh of electricity production were from renewables. Nuclear contributed 36%, natural gas 42% and coal 17%.

In January 2019, Wolf signed an executive order setting Pennsylvania’s first statewide climate goals: reducing greenhouse gas emissions by 26% by 2025 and by 80% by 2050 compared to 2005 levels.

GOP Pa RGGI — Generation portfolio mix estimates if Pennsylvania and Virginia join the Regional Greenhouse Gas Initiative | *PJM*

Wolf followed with a second executive order instructing the DEP to begin the regulatory process to join RGGI. On June 22, citing the pandemic, Wolf provided the department with a six-week extension to deliver a proposed rulemaking to the Pennsylvania Environmental Quality Board, extending the previous July 31 deadline to Sept. 15.

Wolf said RGGI states have reduced power-sector CO2 pollution by 45% since 2005 while returning $2.31 billion in lifetime energy bill savings to more than 161,000 households and 6,000 businesses that participated in programs funded by RGGI proceeds through its first six years of existence.

Hayley Book, senior adviser on energy and climate for the DEP, said Pennsylvania’s RGGI implementation date of Jan. 1, 2022, remains in place. Book said the department plans to hold stakeholder and public meetings on RGGI throughout the summer.

RGGI, which includes New York and the six New England states, currently has three PJM states: Delaware, Maryland and New Jersey. Virginia also is planning to join RGGI under the Clean Economy Act that passed its legislature in February and goes into effect Jan. 1. (See PJM Panel Weighs Impact of Pa., Va. Joining RGGI.)

In her testimony June 23, Gladys Brown Dutrieuille, chairwoman of the Public Utility Commission, said about 24% of the electricity produced in Pennsylvania is exported out of the state. Dutrieuille said the cost of RGGI compliance for exported electricity will be paid by electric customers in the states where that electricity is ultimately used.

PJM Testimony

PJM stakeholder opinions regarding RGGI and carbon pricing have been mixed, with many members encouraging the RTO to take a more active role in facilitating carbon pricing as states decide to join the environmental collective. (See Stakeholders Urge PJM Action on Carbon Pricing.)

In a letter sent to the PJM Board of Managers on Friday, 29 companies and renewable industry groups called for the RTO to continue its efforts to consider the integration of carbon pricing in its markets.

“With continued and heightened focus by states in the PJM market on reducing carbon emissions from power generation, PJM should continue to work with stakeholders to explore the relative roles that its competitive wholesale markets and state policies should play in shaping the quantity and composition of resources needed to meet such carbon emission reduction goals while cost-effectively meeting future reliability and operational needs,” they said.

Stephen Bennett, PJM manager of regulatory and legislative affairs, took a neutral stance on carbon pricing in his presentation during last week’s committee hearing, but he said, “A price on carbon emissions generally integrates well with PJM’s current markets.”

PJM’s Carbon Pricing Senior Task Force has received briefings from RTO staff on its modeling of carbon pricing scenarios and ways to address emissions “leakage” occurring when certain states choose to apply a carbon price and others do not. One of the strongest conclusions drawn from PJM’s modeling to date, Bennett said, is that the mix of states included in the carbon pricing region are a “driving factor in determining the overall impact that carbon pricing has on net PJM carbon emissions and electricity prices.”

Bennett also reiterated PJM’s stance that it does not propose to establish a carbon price and does not take advocacy positions on state legislation.

“PJM recognizes and respects Pennsylvania’s prerogative to determine its policies regarding environmental protection and emissions management,” Bennett said. “PJM also recognizes that state policy plays a significant role in determining the assets and fuel mix used to meet the state’s resource adequacy needs. Rather than advocate, PJM seeks to be a neutral party and provider of factual information on the planning and operation of the bulk electric power system, the operation and evolution of the wholesale power markets that help ensure reliability at the lowest reasonable cost, and the value PJM provides as an RTO.”

Chairman Yaw asked Bennett whether PJM will purchase generation from outside of the state if Pennsylvania’s generation capability is reduced because of RGGI.

Bennett said one of the biggest benefits of PJM is its geographic diversity, with a market spanning 13 states and D.C.

“If there is a generator or a generation source that has very high cost of prices, they’re likely to be displaced either in state or out of state by resources that have a lower cost,” Bennett said. “And that’s how across the footprint we’re able to provide that power at the lowest reasonable cost.”

Leakage Concern

Sen. Scott Martin (R) cited PJM’s opportunity statement on carbon pricing, which said that “without addressing leakage, rising emissions can eliminate the environmental benefits that carbon pricing policies are intended to produce.” He asked if environmental benefits touted by the DEP would be offset by other fossil fuel generation units in non-RGGI PJM states, as the department’s draft CO2 trading program regulation contains no provisions to address leakage.

Bennett said he couldn’t “categorically” say that any emissions or environmental benefits would be offset, citing the complexity of the modeling PJM has conducted.

“Depending on the cost of carbon and things of that nature, you do have differing outcomes as far as the impact of leakage on the overall net price and emission intensity outcomes,” Bennett said. “Leakage is certainly something that can have that impact.”

Republican Legislation

The Senate hearing was not meant to be a consideration of Vice Chairman Pittman’s Senate Bill 950 or its companion House Bill 2025 sponsored by state Rep. Jim Struzzi (R), which require RGGI to be “vetted through the legislature,” though both were mentioned during testimony.

Tom Schuster, clean energy program director for the Sierra Club in Pennsylvania, said SB 950 would prevent Pennsylvania from regulating electric sector carbon pollution and revoke the DEP’s existing authority under the Air Pollution Control Act to regulate greenhouse gas emissions in any sector.

Shawn Steffee, executive board trustee and business agent for Boilermakers Local Lodge 154, said he has joined with community, business and labor leaders in the Power PA Jobs Alliance to support both the Senate and House bills. Steffee said Pennsylvania coal-fired power plants and older gas plants will lose their ability to compete with similar units in West Virginia and Ohio, two states that are not examining joining RGGI.

“Our plants will abruptly close, and new power generation growth will happen in West Virginia and Ohio, costing us thousands of good paying, blue collar jobs,” Steffee said.

June 30, 2020

Bulk Tx, 115-kV Upgrades Needed for NY 70×30 Goal

NYISO will need to expand its bulk transmission and some low-voltage lines to meet New York’s 2030 climate goals, according to the latest Congestion Assessment and Resource Integration Study (CARIS).

Jason Frasier, the ISO’s new manager of economic planning, presented the study to the Business Issues Committee on Wednesday, which recommended it be approved by the Management Committee.

New York transmission upgrades — 2019 CARIS study groupings | *NYISO*

Business as Usual

The report, the first phase of the ISO’s two-phase economic planning process, contains a “business as usual” base case that includes only incremental resource changes based on known planned projects with a high degree of certainty. It simulated hourly grid operations from 2019 through 2028, based on the 2019-2028 Comprehensive Reliability Plan, which includes the Western New York and AC Transmission Public Policy Transmission Projects scheduled to enter service on June 1, 2022, and Dec. 31, 2023, respectively.

The model simulated how investments in transmission, generation, demand response and energy efficiency would impact congestion in the three most congested transmission corridors: Central East, Central East-Knickerbocker and Volney-Scriba.

As in past studies, the base case found “limited opportunities for transmission buildout based solely on production-cost reductions” reflecting the current “generation-rich” system, the ISO said.

“The solutions … offered a measure of congestion relief and production costs savings but did not result in projects with benefit/cost ratios in excess of 1.0. Following the energization of the AC Transmission projects, the congestion is substantially reduced and shifts to the Central East-Knickerbocker corridor.”

The study does not attempt to project changes in energy consumption caused by the COVID-19 pandemic. “The study provides in-depth analysis of long-term system usage trends and of system congestion and curtailment patterns over the next decade that are likely to persist notwithstanding the lower energy forecasts for 2020 and 2021 that the NYISO produced for the 2020 Gold Book,” the ISO said.

‘70×30’ Scenario

CARIS’ primary focus, however, is on the “70×30” scenario, reflecting the 2019 Climate Leadership and Community Protection Act (CLCPA) requirement that 70% of the state’s end-use energy be generated by renewable energy systems by 2030.

The scenario, which modeled two hypothetical buildouts of renewable energy facilities, identified transmission-constrained pockets that could prevent renewable production from being fully deliverable to customers. Unlike the base case, it did not include a benefit-cost analysis.

The CLCPA included technology-based targets for distributed solar (6,000 MW by 2025), storage (3,000 MW by 2030) and offshore wind (9,000 MW by 2035), with a goal of making the electric sector emissions free by 2040.

The system model for the scenario added about 110 sites of land-based wind, offshore wind and utility-scale solar, along with additional behind-the-meter solar across the system.

Sufficient renewables were added to the system to equal 70% of state energy consumption, taking into account the “spillage” of generation when renewable production exceeds load within the New York Control Area — power that could either be exported or would have to be curtailed.

To study the impact of one potential renewable resource mix that could meet the 70×30 goal, the model included about 15,000 MW of utility-scale solar, 7,500 MW of behind-the-meter solar, 8,700 MW of land-based wind and 6,000 MW of offshore wind in addition to existing hydro generation. ISO staff also included a sensitivity analysis assuming the policy target of 3,000 MW of energy storage.

The study used a new screening tool to identify five “renewable generation pockets” where insufficient bulk and local transmission network (115-kV and some 230-kV lines) capacity could prevent renewables from being delivered to consumers statewide. The study concluded that about 11% of total potential renewable energy production of 128 TWh/year would be curtailed without transmission improvements.

The North Country pocket saw the highest curtailment by percentage, the highest curtailed energy by gigawatt-hours and the most frequent congested hours. Offshore wind also would be constrained in New York City (Zone J) and Long Island (Zone K) because of constraints on the land-based grid.

The increase in intermittent renewable generation meant lower production from the state’s fossil fuel generators compared to the base case.

“In many cases, however, the reduced output is accompanied by an increased number of generator starts, indicating the need for dispatchable and flexible operating capabilities in the future. Fossil fleet operation can also be highly dependent on transmission constraints,” the report said. “In particular, comparison of operations in the relaxed and constrained cases makes apparent that simple cycle combustion turbines may run more and start more often due to transmission constraints.”

The conclusion: “Additional transmission expansion, at both bulk and local levels, will be necessary to efficiently deliver renewable power to New York consumers.”

The report also found that energy storage could decrease congestion and help to increase the use of the renewable generation, particularly solar generation, when “dispatched effectively.”

“The targeted analysis showed that energy storage likely cannot by itself completely resolve the transmission limitations in the pockets analyzed.”

MMU Review

Pallas LeeVanSchaick of Potomac Economics presented the Marketing Monitoring Unit’s review of the report, saying the transmission constraints identified in the 70×30 hourly resource modifiers (HRM) scenario “also substantially affects investment incentives” for intermittent renewable generation and battery storage. Under HRM, renewable resources are modeled to allow their outputs to change on an hourly basis.

Wholesale market incentives will encourage developers to locate assets where the transmission system is not already saturated with a particular renewable technology, the MMU said.

While renewable generation and battery storage projects may rely on revenues from sources outside the wholesale market, “the wholesale markets are as important as ever in channeling investment,” LeeVanSchaick said.

Many renewable generators seek to reduce market risk by signing long-term (20- to 25-year) contracts for “index” renewable energy credits, which pay a price per megawatt-hour equal to a fixed strike price minus the index price for a nearby pricing hub. A generator with a strike price of $65/MWh located near a trading hub that averaged $30/MWh over a month would receive $35/MWh for its RECs for that month.

But index RECs don’t eliminate all risks in the 2030 scenario, the MMU said.

The MMU cited the “technology discount” — the difference between the simple average zonal LBMP in the day-ahead market and the generation-weighted average zonal LBMP in the real-time market by technology. This affects technologies that tend to produce electricity at times when zonal LBMPs are below the day-ahead average.

Generators also face a “nodal discount” — the generation-weighted average differential between the zonal locational-based marginal prices and the nodal LBMP for a particular technology and location. This reflects reduced revenue when local transmission constraints further discount the energy revenue to a particular technology and location.

Neither of the discounts are much of a factor in 2020, LeeVanSchaick said. “But you see those tend to grow over time as [intermittent renewable] penetration increases.”

In the 70×30 scenario, the MMU found technology discounts of 27 to 87% of average zonal LBMPs for solar generation in Zones A to G, with solar in Zone K facing a potential 14% revenue reduction. Land-based wind would face a 2 to 21% discount in Zones A to E, with a 6 to 13% discount for offshore wind in Zones J and K.

Nodal impacts could range, from a 79% discount to a 29% premium for solar. Land-based wind could see between a 56% discount to an 8% premium, with offshore wind ranging between a 68% discount to 23% premium.

The MMU emphasized that the 70×30 scenario does not constitute a prediction of the resource mix in 2030, and its analysis is not a prediction of future market outcomes. It said the scenario does provide useful information about market incentives as the state works toward the 70×30 goal.

“If additional entry into saturated areas is motivated by raising index REC prices in the future, it will result in large financial risks to renewable generation developers that invest sooner (i.e., before the area has become saturated with a particular intermittent generation technology),” the MMU said. “Thus, a stable and predictable policy regarding index REC price levels may facilitate progress towards the state’s goals.”

It also said the high renewable penetration in the 2030 scenario would result in “strong incentives” for entry by unsubsidized battery storage developers.

“This market response would moderate energy prices and reduce market risks for renewable generation investors. Hence, a competitive wholesale market for energy, ancillary services and capacity will ultimately facilitate state policy objectives.”

Next Steps

CARIS Phase 1 will be brought to a vote at the July 1 Management Committee meeting and is expected to be considered by the NYISO Board of Directors at its July meeting.

The ISO said it will build on the CARIS results in the upcoming 2020 Reliability Needs Assessment and the Climate Change Impact and Resilience Study.

After CARIS Phase 1 is approved by the board, NYISO will begin Phase 2 of the economic planning process, in which developers will be invited to propose projects to alleviate the identified congestion.

The ISO will evaluate proposals to determine their impact on congestion and whether the projected economic benefits make the project eligible for cost recovery under the ISO’s rules.

“While the eligibility criterion is production cost savings, zonal LBMP load savings (net of transmission congestion contract revenues and bilateral contracts) is the metric used in Phase 2 for the identification of beneficiary savings and the determinant used for cost allocation to beneficiaries for a transmission project,” the ISO said.

June 30, 2020

PJM Revises Consultant Scope for ARR/FTR Review

PJM has revised its proposed review of its auction revenue rights (ARRs) and financial transmission rights markets as stakeholders decide whether to put their work on the issue on hiatus until a report is completed.

At Friday’s ARR/FTR Market Task Force meeting, PJM’s Dave Anders presented the revised draft scope of work to be done by an external consultant in its review of the ARR-FTR construct, a project recommended in last year’s independent consultant report on the GreenHat Energy default.

PJM ARR FTR — Dave Anders, PJM | © *RTO Insider*

Anders said PJM received “significant feedback” after last month’s task force meeting and decided to take a “higher-level view” to ask broader structural questions than the RTO had originally proposed.

While the overarching question of whether load is receiving optimal value from the ARR/FTR markets remains the same, Anders said, the revised questions seek to avoid conflicts between load-serving entities and financial traders over what is to be examined. (See PJM ARR/FTR Review Could Pit LSEs vs. Financial Traders.)

“This thinks about the big-picture questions first and then gets down to the more granular considerations,” Anders said.

The new work scope requests that the consultant examine ARRs and FTRs both separately and as a system working together and make recommendations for potential improvements. The questions include a look at the reason the markets were created; whether they are producing the desired outcome; and whether there are alternatives to achieving the desired results.

Anders said the request for hiring the consultant should be posted by the end of this week. He said the RTO hopes to have the consultant start work by the end of July and to have a report done by October.

Sharon Midgley, Exelon’s director of wholesale market development, said PJM’s work scope changes were “excellent” and “raised the level of conversation” instead of assuming any outcomes. She asked if PJM will have the consultant look at the technical platforms running the ARR-FTR markets to ensure the technology is up to date and able to be expanded or changed if needed. “I would hate for us to go through the process and not be able to implement certain things because we don’t have the systems to support it,” she said.

Jim Davis, Dominion Energy | © *RTO Insider*

Anders said the consultant may not be able to scrutinize the IT platforms because PJM is searching for someone who understands “the economics” of the market and not necessarily the technology running the programs.

Jim Davis of Dominion Energy said the consultant questions represent what his company had in mind when discussions about the markets were being proposed. Davis said the consultant should spend “sufficient time” considering market design changes to optimize the value or lower the risk to load.

“The scope of work is well defined yet flexible as well,” Davis said.

PJM vs. IMM

After Anders presented the updated scope of work, he discussed potential pathways forward for the task force while the consultant completes its review. Anders said stakeholders have expressed varying opinions, ranging from putting the group into hiatus to looking at some limited-scope items over the next few months.

PJM’s recommendation is to put the task force on hiatus until the consultant completes its work, Anders said, because the broad range of work to be completed may result in changes to aspects of the market construct. He said continuing work on anything that could contradict the consultant’s report would not be a good use of stakeholder time.

“PJM and stakeholders don’t want to give the impression that they’re driving towards some solution at the same time the consultant is doing a broad review,” Anders said.

Howard Haas, chief economist for Monitoring Analytics, PJM’s Independent Market Monitor, said he appreciated the work that went into formulating the work scope but disagreed with the hiatus recommendation. He said conducting a third-party review of the markets was only one aspect of the recommendation that came from the GreenHat report and that it asked PJM, the Monitor and stakeholders to do a “holistic review” of the entire ARR-FTR process.

Slowing down the pace of the task force’s work makes sense during the consultant’s review, Haas said, but the amount of information stakeholders need to cover requires continuous effort. Haas suggested continuing discussions and a presentation of methodologies, analysis and data needed to facilitate a discussion of any needed changes to the current ARR/FTR market.

“There’s a lot of work that has to be done with or without the consultant’s report,” Haas said.

Anders said the Market Implementation Committee will vote July 8 on whether to put the task force on hiatus or continue work. The MIC will vote after receiving the results of a nonbinding poll of task force members on the same question.

Stakeholder Opinions

Davis said he agreed with Haas’ recommendation to continue the task force work at a slower pace. He also suggested that the consultant provide interim updates to the group as it conducts its review to have a better understanding of the issues being examined.

Susan Bruce of the PJM Industrial Customer Coalition said she was “of two minds” when thinking about how the task force should proceed. She said that although she understands PJM’s interest in allowing the consultant to do its work without outside influence, she is open to continuing conversations on market dynamics to avoid losing the sense of momentum that has built during task force discussions since January.

“This is a complicated nut, and I think there are a lot of issues here to discuss,” Bruce said.

Several stakeholders expressed support for a hiatus. Jim Benchek of FirstEnergy said he is concerned that the continuing mixture of data production and presentations by PJM and the Monitor at task force meetings could influence the content of the independent report.

Gary Greiner, director of market policy for Public Service Enterprise Group, said stakeholders need to recognize that the GreenHat report indicated PJM’s markets are not fundamentally broken and did not constitute a “house on fire” situation that needed immediate attention. He said taking more time and being thoughtful in deliberations would be beneficial for stakeholders and at the same time allow the consultant to do its work unimpeded.

“If the consultant comes back and we dismiss everything they’ve done out of hand, then we’ve done a pretty poor job on our part,” Greiner said.

June 30, 2020

NE Utilities Lay out Strategies for Net-zero Emissions

Representatives of three of the dominant utilities in New England on Wednesday briefed Northeast Energy and Commerce Association members about their companies’ aggressive decarbonization efforts, suggesting that many other utilities will need to step up their games to reach net-zero emissions by 2050 — the year by which climate experts say the world must stop emitting carbon entirely or find some way to remove it from the atmosphere to prevent catastrophic environmental changes.

Officials from Avangrid, National Grid and Eversource Energy spent most of their presentations triumphantly pointing to the progress they have made toward their decarbonization goals. The strategies laid out by the officials ran the familiar gamut: aggressive investment in renewable resources, upgrading the transmission system to make it more efficient and co-locating new renewables with storage.

Driven by legislation passed by states in their service territories, the utilities are indeed well on their way to reaching their targets — for now. National Grid last year, for example, upped its goal from an 80% reduction by 2050 from 1990 levels to net-zero emissions by then. Its also increased its interim goals, having already achieved its previously 70%-by-2030 target this year; it’s now targeting 80% by 2030.

New England net-zero — Having achieved its 70% emissions-reduction goal 10 years earlier than its original target, National Grid last year upped its goals. | *National Grid*

Avangrid’s generation mix is made up almost entirely of wind energy, with 7.4 GW of onshore resources in operation, and another 9.6 GW in development, both on- and offshore. It expects to be carbon-neutral by the end of 2035 — the year its last remaining fossil fuel plant, the Klamath Cogeneration Project in Oregon, will reach the end of its useful life.

But the speakers cautioned that these strategies will get utilities only so far in reaching net-zero emissions by 2050. Nascent technology such as long-duration energy storage, carbon capture and sequestration, and renewable natural gas will be needed not just to offset emissions but to balance the intermittency of renewable resources, they said.

“High penetrations of renewables are going to need some truly flexible power plants to balance them … which means, for many utilities, natural gas,” said Javier Ceña, Avangrid’s executive director of sustainability. “So the electric sector might need to rely on carbon capture or carbon-free fuels, like green natural gas or green hydrogen, to reach carbon neutrality by 2050.”

Clockwise from top left: Javier Ceña, Avangrid; Catherine Finneran, Eversource; Michele Leone, National Grid; and VHB Senior Environmental and Sustainability Planner Donny Goris-Kolb, who moderated the discussion. | *NECA*

He pointed to Avangrid parent company Iberdrola’s demonstration project in Puertollano, Spain, that will use a combination of solar and electric storage to produce hydrogen.

National Grid is also in the early stages of developing a program to counter emissions. “As much as our primary focus is to reduce our emissions, we do believe that we will have to do some offsetting in 2050,” said Michele Leone, director of sustainability and environment. “So right now we’re looking to develop a program … looking at local partnerships, looking at co-benefits of various offsetting options.”

Eversource has perhaps one of the most aggressive targets in the U.S.: carbon neutrality by 2030. Its strategy is to first reduce its own greenhouse gas emissions “to the maximum extent possible,” according to Catherine Finneran, vice president of sustainability and environmental affairs. “And then … we’ll offset those emissions, whether through the purchase of offsets or the development of initiatives that produce the offsets.”

Both National Grid and Eversource said they’re also focusing on reducing leakages of methane from their natural gas pipelines and of sulfur hexafluoride (SF6) — an extremely potent greenhouse gas rarely mentioned compared to carbon dioxide and methane — which is used in switchgear as an insulator.

SF6 “might look like a small amount of our footprint, but it is a very big focus for us,” Finneran said. The company is working with its suppliers to phase in SF6-free equipment over the next five years. The challenge, however, is that such equipment is only available for lower-voltage equipment, “and we really need it also at higher voltages as well,” she said.

June 29, 2020

Companies Debate When to Bring Back Staff

The world changed for American Electric Power’s Scott Smith in early March when the coronavirus pandemic forced Ohio Gov. Mike DeWine to partially shut down Columbus’ annual professional bodybuilding event.

“The Arnold,” as it’s called locally, is no ordinary strongman competition. Named after Arnold Schwarzenegger, the Arnold Sports Festival annually attracts more than 20,000 competitors from more than 80 countries to Ohio’s capital.

“It was a watershed moment for us,” Smith, AEP’s senior vice president of transmission field service, said last week during an online Gulf Coast Power Association panel discussion.

“It’s the largest convention in Ohio, other than [Ohio State University football],” he added.

AEP leadership quickly dusted off a plan it had developed after the H1N1 pandemic in 2009 and by mid-March had sent much of its corporate staff home. Now, AEP’s executives are wondering whether they’ll even have some staff return to the office.

“We originally thought we would come back to work the same as before, but it’s not business as usual,” Smith said during the discussion Thursday. “There’s going to be the new normal. We’re in the beginning stages of figuring out that and the protocols around it.”

ERCOT companies COVID-19 — Scott Smith, AEP | *GCPA*

Smith was joined on GCPA’s panel, “The Future of Work in the Age of Pandemics,” by ERCOT CEO Bill Magness, who said he has the same thoughts. The Texas grid operator also sent its corporate staff home in mid-March. Their stay-at-home orders have since been extended through September.

“We ended up with about 95% of our people working off-site, and there they remain,” Magness said.

ERCOT and AEP have since been using federal guidelines and social-distancing and hygiene practices to determine how best to safely bring back employees. Today’s open-office concepts mean companies will have to rely on shields for workspaces and faces if staff are going to return to their workspaces.

“We’re not going to be able to keep 6-foot distancing for everyone in their cube,” Smith said, noting he sits in an office that is 80% open space.

“We’re thinking hard about this,” Magness said. “Is it better to maintain the performance of the people on your team by keeping them where they are in a remote environment, or bring them back to the way we used to be? From a business perspective, what’s going to help the business the most? What helps the most is productive employees.

“If we only have a somewhat limited number of people in the footprint, we may not be able to bring people back to sit where they use to sit. We may have A Team/B Team arrangements. We’re learning a lot about what the future is going to look like. It’s been fascinating.”

A recent Upwork survey of hiring managers revealed that more than half the nation’s workforce is working remotely. Managers are planning for almost 22% of their workforces to be entirely remote in five years and for the expected growth rate of full-time remote work during that time to more than double, from 30% to 65%.

It may seem counterintuitive, but the survey also found 32% of managers say remote work has increased productivity. That’s because of a lack of commute, less nonessential meetings and fewer distractions than in the office, according to the survey.

“We’ve learned that we have a lot of employees who can get their work done remotely. We’ve traditionally never thought that way,” Smith said. “We’ve found the production of a lot of folks is up because they can get things done at home. Their days may extend to 6:30, 7:30 at night because of all the phone calls and time differentials. It’s actually very interesting. There are going to be a few persons who have to be at work, but we’re questioning who does really need to come back in the office.”

“Part of what’s challenging is people want to get back to work,” Magness said. “We’ve never stopped working, but people want to get back to their environments. Those environments are not what [they were].”

Staying the Path

In contrast, protecting employees in the field or control rooms is much easier. Smith said AEP’s work crews complete health self-assessments each day on an app. If an employee answers positively to one of the questions, their supervisor gets an email that indicates the employee needs to stay home.

“That’s our first line of defense: the employee staying home,” he said. “We’re asking employees, as best they can, to separate themselves with their vehicles. If there are three or four of them working on an issue, we may have three or four trucks at the jobsite, just to maintain social distancing.”

Austin-based ERCOT has isolated controllers in its two operations centers in nearby Taylor and Bastrop. When a 12-hour shift ends in Taylor, the next shift begins in Bastrop while the Taylor ops center is sanitized.

Smith said the remote work environment has revealed a need for different ways of communicating. Zoom and Microsoft Teams can only go so far in bringing together staff from disparate locations and instilling a sense of camaraderie.

“It’s very hard to replicate face-to-face time with electronic tools,” he said. “One of the things we find, like staff meetings on the web, is someone makes a joke, but no one hears anyone laugh. Everyone’s on mute. That kills camaraderie right there.”

“That’s right! That’s a terrible thing,” Magness responded.

Turning serious, Magness said the current environment has left him pleased with staff’s ability to get their work done in a difficult setting.

“From ERCOT’s perspective, we’re really gratified with the way people have stepped up,” he said. “We have to remember this is unusual. This is odd. People will have different reactions to this. We need to constantly think about who we were when we started this, who do we want to be, and how do we stay on that path until this is over.”

June 28, 2020

New Yorkers Plug New Tx Need for Clean Future

Renewable energy experts and grid planners joined government officials Thursday to discuss how to address New York’s outdated transmission system, which can’t move enough clean energy from upstate generation sources to key load centers in and around New York City.

New York transmission — Anne Reynolds, ACE NY | *ACE NY*

“New York will be bringing more and more renewable energy online,” said Alliance for Clean Energy New York (ACE NY) Executive Director Anne Reynolds, who opened the meeting. “This is good news — wind and solar are pollution-free, and 22,000 New Yorkers already work in the renewable electricity industry. But for New York to actually achieve its renewable electricity goals, we need to update the grid, parts of which were built more than half a century ago.”

An estimated 226 people listened in on the virtual town hall co-hosted by the American Council on Renewable Energy and the Solar Energy Industries Association.

ACE NY lobbied the State Legislature for a budget bill that passed in April, the Accelerated Renewables Growth and Community Benefit Act, which aligns state law, bureaucratic practices and policies — including property tax laws — with the clean energy goals outlined in last July’s landmark Climate Leadership and Community Protection Act (CLCPA) (A8429). (See NY Renewable Supporters Push for New Siting Agency.)

The bill directed the Public Service Commission to authorize a study, which it did in May, to identify distribution upgrades, local transmission upgrades and bulk transmission investments needed to meet the state’s clean energy goals (20-E-0197). (See NYPSC Launches Grid Study, Extends Solar Funding.)

“I agree with the premise that we are going to need more transmission if we’re going to meet the goals of the CLCPA, the most aggressive set of climate standards in the entire nation,” said Sen. Kevin Parker, chair of the Senate Energy and Telecommunications Committee.

“Now the hard work has begun, which is how do we actually meet the goals. I very much believe that transmission is going to be really critical in that, and organizations like ACE NY are going to be leading the charge,” Parker said. “This also is happening in a time at which … our economy has been way slowed down, and if we look at where we’re going to produce full-time jobs at a living wage with benefits, the clean energy economy is the next best place to do that.”

However, reduced state revenues stemming from the slowdown means “we have to produce more green using less green,” Parker said.

Additional Buildout

Two things are at the heart of the new climate law, said Ali Zaidi, Gov. Andrew Cuomo’s deputy secretary for energy and environment: “One is dramatic transformation of the grid to 100% clean, and the second is an expansion of that grid to reach more and more sectors of the economy.”

One of the state’s most powerful tools in decarbonizing buildings, industry and transportation is to back out existing sources of energy in those sectors and replace them with electrons generated in a clean way, Zaidi said.

“We have hundreds of miles of power lines that are on their way to being built in this state in the very near term, and we need to bird-dog that progress and make sure it is done on time,” Zaidi said. “It’s critical that we build what we already know we need and what is barely far along in the development process … and use data and analysis to inform where we are going to speed up additional buildout.”

As part of its “Grid in Transition” initiative, ‘Astonishing’ Buildout Needed for Clean NY Grid.)

“Most people know that the interconnection points that can efficiently accommodate large renewable generation projects in upstate New York are becoming much harder to find,” said Bart Franey, director of transmission planning, asset management, systems and data for National Grid.

The constraints are partly because of generation and transmission development being largely siloed from each other, he said.

“New flow patterns across the networks are creating a growing issue of curtailments on renewable energy, and generation development continues to outpace that of transmission,” Franey said. “The result is a suboptimal solution for ratepayers.”

National Grid has been exploring this issue for two years and looking for ways to upgrade what are referred to as “byways” in its transmission network, he said.

National Grid Simmons Station site in Humphrey, Cattaraugus County, N.Y., an example of a “byway” in the company’s transmission network | *National Grid*

The company “has focused on creating upgrades that are available to deliver renewable resources to the bulk, or the highways,” Franey said. “These studies assumed light load conditions with an objective of minimizing curtailments, and it resulted in some really exciting opportunities around optimally sizing upgrades using a [renewable energy credit]-based benefit approach.”

When National Grid analyzed its systems and identified projects, they realized that “in some cases, the least-cost byways solution would in fact be a greenfield project, used specifically to deliver renewables,” Franey said. “We refer to them as collector stations, but they would really be a form of integrated resource planning.”

Developer and Local Insights

“In New York alone, we have a pipeline of over 3 GW of solar and storage in various stages of development and have partnered with Shell Energy for the development of offshore wind, and we have a number of solar projects already online,” said Rodica Donaldson, senior director for commercial transmission and analytics at EDF Renewables North America.

“The transmission risk is important to renewables because if we have high curtailment, which has been identified in the latest [Congestion Assessment and Resource Integration Study] by the New York ISO, that means high risk for us because we cannot be delivered as low-cost energy for loads,” Donaldson said.

The high risk of congestion and curtailment also means that the transmission system is reaching capacity, she said.

“We have curtailment; we have depressed LMPs within that pocket; and those are financial costs for us,” Donaldson said. “As a generator, when we look at developing projects, this risk can challenge the ability to secure financing and even can make the project uneconomic. So, for us, a scenario without transmission investment is a high-risk environment.”

Ryan Piche, Lewis County, N.Y. | *ACE NY*

“We are home to 27,000 residents over 1,200 square miles, so when you talk about room for green energy growth, this is where it is: It’s upstate,” said Ryan Piche, manager of Lewis County in the Adirondacks. “No offense to Sen. Parker, but it’s not in Brooklyn.”

Despite having open space, the needs of the local community in Lewis County and elsewhere are very important, he said.

“We know our community better than anyone, and we need to be the ones who are deciding which areas are prime for growth and which areas need to be preserved,” Piche said. “We’re the ones who understand viewshed and habitats. The ‘solar tsunami’ is a fun little phrase, but think about a tsunami — it can overwhelm you. I think it is important that the local governments draw a line in the sand and understand what is going to be acceptable and what is not.”

June 28, 2020

Study Foresees MISO Solar Eclipsing Wind

MISO’s southern and central regions could surpass the RTO’s wind-heavy northern reaches as the biggest producer of renewable energy as solar generation grows in popularity, new study results indicate.

The findings come out of MISO’s ongoing Renewable Integration Impact Assessment (RIIA), which most recently focused on where new resources could be located when renewables rise to 50% of the RTO’s resource mix. It found distributed and utility-scale solar installations would proliferate in Michigan and Indiana and the footprint’s southern states, while the wind buildout that has so far dominated the North planning region winds down.

“Some of the heavy wind that we were seeing in Minnesota, North Dakota and even Iowa, we’re starting to see a shift,” James Okullo, MISO policy studies engineer, told stakeholders during a teleconference Friday.

The RIIA results are based on trends in MISO’s interconnection queue and load ratios in local resource zones. The Southern Alliance for Clean Energy recently predicted the U.S. Southeast could contain 25 GW of solar capacity by 2023.

MISO solar — Possible resource additions at 50% renewables | *MISO*

Okullo said MISO has generally found that grid needs rise sharply beyond a 30% renewable penetration. Previous results of RIIA have concluded that to operate with a 50% renewables mix, MISO must boost reserve requirements and demand-side management, dramatically increase transmission (including HVDC) and add more technology to lines, including synchronous condensers and transformers. (See MISO Renewable Study Shows More Tx, Tech Needed.)

MISO has been undertaking the study since 2017, which used actual peak load levels at the time and a 2022 power flow model to draw conclusions. The RTO has not yet modeled strategic energy storage additions in addition to the growing renewable share, and Okullo said it would have new RIIA results by August projecting how much energy storage might be needed to help ease the transition.

For now, MISO’s study projects an increasing risk to serving load outside of summer as solar generation gains momentum. A large solar fleet staves off the usual early evening daily peak as the sun still shines, compressing risk to a shorter and steeper time period later in the evening, the RTO said.

The Union of Concerned Scientists’ Sam Gomberg last month said that MISO might be biasing the presentation of RIIA results in terms of what the system could not do rather than what it could. After the RTO presented its last RIIA results last November, many stakeholders walked away with the view it couldn’t possibly operate with more than 40% renewable penetration because of complexity, he said.

“I would encourage you to think hard about the takeaways you communicate and the message you deliver,” Gomberg told staff during a Planning Advisory Committee teleconference May 13.

June 28, 2020

MISO Unveils 1st Proposal to Consolidate Tx Planning

MISO last week floated a proposal that would require network upgrades needed by projects in the generator interconnection queue to reach certain voltage and price levels before they could be tested for the economic benefits needed for cost-sharing eligibility.

But renewable proponents argue the plan wouldn’t do much for developers facing costly upgrades.

MISO transmission planning — Neil Shah, MISO | © *RTO Insider*

The proposal is a starting point for MISO’s effort to coordinate and align studies found in network upgrade planning in the interconnection queue and the RTO’s annual Transmission Expansion Plan (MTEP), Senior Manager of Economic Planning Neil Shah told stakeholders during a Planning Advisory Committee teleconference Wednesday. (See Regulators Not Sold on MISO Tx Planning Sync.)

Under the proposal, a generation project’s needed upgrade would need a minimum rating of 230 kV and cost at least $5 million to be eligible for evaluation as a possible market efficiency project (MEP), the same thresholds set out for MEPs in MISO’s proposed cost allocation plan, currently awaiting Local Projects Axed from MISO Cost Allocation Refile.)

MISO is additionally proposing that costs for a network upgrade submitted for economic evaluation can be spread across a group of interconnecting generation projects as long as they are $50,000/MW or higher. However, the projects necessitating the upgrade would need to have already completed the queue and executed a generator interconnection agreement (GIA) before they could be evaluated.

Shah said a GIA execution would help MISO avoid running economic analyses on projects that haven’t completed all interconnection studies.

“The benefit of this process is that it allows MISO and stakeholders an opportunity to compile and list all [generator interconnection] projects for economic evaluation rather that doing it on an ad hoc basis as interconnection projects come in,” Shah said.

He said MISO is aware that the RTO’s Environmental and Other Stakeholder Groups sector is critical of the proposal, arguing that it wouldn’t give interconnection customers certainty on future cost-sharing as they make their way through the definitive planning phase (DPP) of the queue.

Too Late

Sustainable FERC Project attorney Lauren Azar said the economic evaluation would still come too late for “bona fide” developers saddled with large network upgrades that could show regional economic benefits for others.

“This proposal is not going to solve the problem of generators being scared away by large increases, because by the time a generator interconnection agreement is signed, those customers would have already been scared away by large network upgrade costs,” Azar said. “I don’t think this scratches the itch of the problem we have before us.”

“We’re not going to wait until we have signed GIAs in order to get an economic evaluation. … This really doesn’t solve the problems. If folks get to a signed GIA, it’s likely that they can afford those upgrades,” Clean Grid Alliance’s Natalie McIntire argued.

But Shah said he didn’t think an economic evaluation earlier in the DPP would be feasible. Even if MISO were to figure out the timing issue, it likely wouldn’t make a substantial dent in project withdrawals because affected-system studies with neighboring grid operators — which come later in the interconnection process — also reveal high upgrade costs, he said.

Trust Queue Price Signals?

Stakeholders asked how interconnection customers could gain insight into whether their network upgrades could be economically beneficial.

Shah said it would depend on the customers’ access to tools and modeling — or by hiring of consultants, if they do not have tools to perform their own economic analysis.

“The interconnection queue is working as designed. We’ve got too many interconnection projects interconnecting at places where there isn’t enough transmission. It’s sending that signal to either reinforce the grid or go somewhere with less congestion,” WEC Energy Group’s Chris Plante argued.

Indiana Utility Regulatory Commission staffer Dave Johnston agreed, saying requests for proposals or power purchase agreements could benefit from inclusion of grid upgrade costs.

“We need a big transmission overlay if a lot of people in the footprint wanted to procure resources of those areas,” and that’s not happening, Johnston argued.

Azar said that while price signals are appropriate, network upgrades have never been evaluated for economic benefits, even though project developers are being told to build “backbone” transmission projects.

Apex Clean Energy’s Richard Seide said the 2017 MISO West network upgrade costs were so egregious that nearly all were canceled, even those projects with PPAs approved by state commissions. Of the 27 generation projects that entered the February 2017 MISO West queue cycle, all but two dropped out, hindered by expensive but necessary transmission upgrades to accommodate the projects that cost tens to hundreds of millions of dollars per project.

More to Come

Shah stressed that the proposal for making interconnection project network upgrades eligible for economic evaluation was just the first step that MISO is considering to align transmission planning processes. He asked stakeholders to consider whether its next step should be changing its annual MTEP model building timeline in order to get more data from the interconnection queue.

Shah added that MISO’s goal is to align the two processes and not disturb them — or the FERC-approved Tariff language that governs them — as much as possible.

“I hope that we don’t make perfect the enemy of the good,” McIntire said, arguing that generator interconnection planning doesn’t need to perfectly conform to the timeline of a year and pointing out that even MTEP studies begin prior to the plan’s approval year. “We don’t need to get too hung up on making this 365 days.”

June 28, 2020

NEI Emphasizes Cooperation with Renewables

Nuclear Energy Institute CEO Maria Korsnick is always upbeat and optimistic about the future of nuclear energy when she makes her annual State of the Industry address, emphasizing plants’ emissions-free nature, high capacity factors and reliability.

Korsnick’s address this year, conducted online as it has been for the last two years, was no different. (See NEI CEO: FirstEnergy Emergency Request a ‘Bridging Strategy’.) But after the usual quick, bright and positive speech and soft question-and-answer with NEI spokeswoman Monica Trauzzi, NEI on Wednesday hosted a panel discussion featuring Union of Concerned Scientists President Ken Kimmell and Renewable Energy Buyers Alliance (REBA) CEO Miranda Ballentine. Both expressed general support for nuclear’s role in a future, zero-carbon generation mix, though both couched it with contingencies.

NEI renewables — NEI CEO Maria Korsnick | *NEI*

In her opening speech, Korsnick positioned nuclear not as a competitor with renewables but as a partner. Though she noted that nuclear provides more than half of all carbon-free generation in the U.S. (as she did last year), “I want to be absolutely clear: We need to develop every source of carbon-free energy that we can. The world is counting on carbon-free resources to complement one another, not just compete. Our choice isn’t between nuclear power or wind and solar. It’s between a status quo of rising emissions from fossil fuels or a low-carbon future from all available sources, including nuclear.”

As evidenced by its name, REBA members — consisting of large corporations such as Facebook, Google and Walmart — have focused their procurement targets on renewable resources, particularly utility-scale wind and solar. But Ballentine said that “there has been a fairly significant transformation in the mindset of large clean-energy buyers, actually quite recently I would say … from goals of 100% renewable energy, to now companies thinking about 24/7/365 zero-carbon power, where renewable energy is one means to that end.”

REBA members “are beginning to think about other forms of zero-carbon power” besides large wind and solar projects, Ballentine continued. She listed geothermal, landfill gas and hydropower, “which is the one that tends to get left out of the discussions so frequently.”

But she said nuclear presents unique concerns for the organization: “What do we do with the waste, how do we handle proliferation, and how do we handle safety? … To the extent that new nuclear [technology] addresses some of those three core challenges of the existing fleet … I think you’re going to start seeing large consumers of power being more interested in the potential role that new nuclear can play.”

Kimmell emphasized “the herculean challenge” of not only using 100% clean energy but electrifying transportation and building heating. “This is a gigantic challenge that implies a pace of expansion of our electric grid in a way that we’ve never come close to doing in history,” he said.

Ballentine agreed. “I would say that many of the members in REBA … have a sense of urgency around the timeline that even 2050 for the power system is too late because there are so many other parts of our economy that are much harder to decarbonize.”

“To meet a challenge like” avoiding permanent climate change, Kimmell said, “all of us need to be prepared to abandon a tribalistic attachment to particular solutions.”

ClearPath Executive Director Rich Powell, who moderated the panel, echoed those sentiments. “I think that lesson of stopping being against the things we’re not specifically for — and eventually becoming for the things we’re not specifically for — is … just a crucial mental frame to adjust [to] as we respond to a challenge this enormous.” ClearPath, formed in 2014, seeks to “develop and advance conservative policies that accelerate clean energy innovation.”

Kimmell warned, however, that UCS’ support for nuclear power was conditioned on maintaining the Nuclear Regulatory Commission’s strict safety regulations for plants. “And I should say this is an area where it’s hard for us to work cooperatively because we don’t support efforts to relax those standards, and to the extent that those standards do get relaxed, we’re going to need to reconsider that criteria” of support, he said.

He also said any financial support through legislation should be reserved for plants that “meet or exceed the NRC’s highest safety standards.” He pointed to UCS’ 2018 report that recommended policies such as a national carbon tax or clean energy standard that would prevent existing nuclear plants from retiring earlier than their expected useful life.