Page 1042 – RTO Insider

September 22, 2020October 21, 2025

Counterflow: No Carb California

Steve HuntGood news! California may not know what caused the rolling blackouts last month, but it does know that 25 years from now, a zero-carbon grid would be totally reliable.

Good news! California may not know what caused the rolling blackouts last month, but it does know that 25 years from now, a zero-carbon grid would be totally reliable.

That’s the verdict of California Energy Commission Chairman David Hochschild and other commissioners at a joint agency workshop on state law SB 100, which requires a zero-carbon grid by 2045, early this month. (See Study: Calif. Must Build Renewables at Record Rate.)

The core scenario presented at the workshop calls for a staggering amount of new solar (109 GW), new wind (30 GW) and new batteries (50 GW). For context, this would be a 528% increase from existing solar, 488% in wind and 5,417% in batteries.[efn_note]Existing solar and wind resource data from the Energy Information Administration’s Electric Power Monthly, Table 6.2.B. Existing battery resource is existing and planned by end of 2020. https://www.utilitydive.com/news/largest-battery-resource-connects-caiso-system/581540/.[/efn_note] All this results in a projected annual resource cost of $66 billion and a generation rate cost component of 16 cents/kWh — about double the current one.

We’ll get into the weeds below, but there were some red flags right at the outset. First is that the study’s modeling was adapted from the California Public Utilities Commission’s 2019 integrated resource planning model, which is the same model that said the chance of rolling blackouts last month was 1 in 500.

Second, CEC staff said that the study was “not explicitly testing the reliability of the portfolios.”

Third, this gathering of multiple agencies unintentionally confirmed the elephant in the room: no unity of command for planning and reliability. As long as that continues, so will the blackouts and the finger pointing.

With those warm fuzzies out of the way, let’s roll into the weeds.

Peak Day Resource Adequacy

With general load growth and high electrification (electric vehicles, building electrification, etc.), the study projects peak-day demand in 2045 of 87 GW and adds a planning reserve margin of 15% for a resource adequacy requirement of 100 GW (slide 11).[efn_note]The workshop slides are here, https://efiling.energy.ca.gov/getdocument.aspx?tn=234549.[/efn_note]

How is that covered? Slide 17 from the workshop shows how. Please focus on the middle column showing “SB 100 Core,” which is the principal scenario, supposed to reflect compliance with SB 100.

Starting from the top of the stack, first is “Variable Renewable ELCC,” which looks to be about 20 GW. But existing and new solar of 130 GW at an effective load-carrying capability (ELCC) of 2%, as shown on the slide, would be about 3 GW, and existing and new wind of 36 GW at an ELCC of 19% would be about 7 GW, for a total solar and wind ELCC of 10 GW. Not 20 GW. Problem.[efn_note]It is possible that the reported ELCCs on slide 17 are marginal values rather than cumulative, in which case this concern may be misplaced.[/efn_note]

Next in the stack is “Long Duration Storage”[efn_note]”Long duration storage” is a bit of a misnomer as it appears to refer to hydro pumped storage of 12 hours duration.[/efn_note] of roughly 7 GW, and then four-hour batteries of about 30 GW. Batteries are problematic for reasons I’ve discussed before.[efn_note]It is possible that the reported ELCCs on slide 17 are marginal values rather than cumulative, in which case this concern may be misplaced.[/efn_note] If you don’t believe me, check out the concerns of CAISO here. (By the way, this CAISO document from last year foretold last month’s crisis pretty well.)[efn_note]http://www.caiso.com/Documents/Jul22-2019-Comments-PotentialReliabilityIssues-R16-02-007.pdf (pages 12-14).[/efn_note]

Next is “Zero Carbon Firm” of roughly 12 GW. This is a catch-all for a variety of possible resources, most of which were excluded from the study as impractical and/or uneconomic and don’t show up in any material way in the chart of capacity additions (slide 15). It seems to be basically green hydrogen fuel cells.

California renewables — As of 2019, there is 80 GW of in-state capacity in California. | *California Energy Commission*

Those won’t come cheap. This unproven technology involves additional “off-grid” solar and wind generation converted to hydrogen by electrolyzer,[efn_note]The Inputs & Assumptions document refers to “assuming off-grid California wind or solar to power the electrolyzer…” https://efiling.energy.ca.gov/getdocument.aspx?tn=234532 (page 41, fn. 20).[/efn_note] compression and storage of the hydrogen, transportation of the hydrogen and conversion of the hydrogen back to electricity via fuel cells. The study presents a projected hydrogen fuel cost of $37.68/MMBtu, 825% more than natural gas, which also doesn’t appear to include the cost of the fuel cell itself and perhaps not fuel cell efficiency loss.[efn_note]Inputs & Assumptions document (pages 84 and 43).[/efn_note] By the way, the soup-to-nuts efficiency is 30%, which makes green hydrogen fuel cells a good way to turn a lot of renewable generation into not so much usable a resource.[efn_note]https://www.greentechmedia.com/amp/article/the-reality-behind-green-hydrogens-soaring-hype. By the way, a good critique of the hype around dirt-cheap future hydrogen is here, https://theicct.org/sites/default/files/publications/final_icct2020_assessment_of%20_hydrogen_production_costs%20v2.pdf.[/efn_note]

Next is about 5 GW of “Import Capacity.” We know how that goes when the West is hot. California has only 2,230 GW of dedicated import resources (Palo Verde and Hoover).[efn_note]Inputs & Assumptions document (page 91).[/efn_note]

Finally, the stack shows about 28 GW of “Fossil Firm,” which was explained at the workshop to essentially be the existing gas fleet. It also was stated at the workshop that carbon sequestration was excluded from the study.[efn_note]”Candidate Resources … • Removed Natural Gas w/ CCS due to insufficient cost data” (slide 7).[/efn_note] So this gas can’t be a zero-carbon resource.

Here’s how I add it up from what’s tangible. Solar and wind ELCC capacity value of 10 GW, long-duration storage of 7 GW, dedicated import resources of 2 GW and if you optimistically add batteries of 30 GW, you get to a zero-carbon resource adequacy value of 49 GW. And then there is the non-zero-carbon gas of 28 GW, which isn’t supposed to be there.

Good luck on that peak day when you need 100 GW.

The workshop did present a true zero-carbon scenario in which more green hydrogen fuel cells essentially replace the gas fleet (slide 33, comparing year 2045 columns). Assuming that, by my math, California would need about 50 GW total of this very expensive, unproven resource.

Piece of cake.

Multiday/Monthly/Seasonal Resource Adequacy

The study does not consider multiday, monthly or seasonal resource adequacy. But such consideration is critical in a system that relies on limited-duration storage resources like batteries.

Why? Because batteries depend on the availability of excess generation over consumption on a given day to recharge batteries depleted the day before. Fossil fuels, in contrast, are effectively 24/7 energy storage, and not dependent upon other resources to recharge. Big difference.

The problem can manifest over varying time periods: whenever there isn’t enough excess generation to recharge batteries before they’re needed again. That could be because of cloud cover for a week that greatly reduces solar generation that would otherwise recharge the batteries, or fires producing smoke and ash that reduce radiance and cover solar panels. Maybe an extended lull in winds greatly reduces wind generation for a week or two.

Beyond this sort of day/week volatility, there is predictable monthly and seasonal variation. This chart from EIA data shows monthly solar generation in California in 2019.[efn_note]At EIA’s Electricity Data Browser here, https://www.eia.gov/electricity/data/browser/, choose the “Net generation” data set, then filter for California and all solar generation, and select the time period and monthly output on a time series basis.[/efn_note] You can see that the high months are more than twice the low months.

In contrast, this chart shows that California’s monthly electric consumption (unlike some other regions with, for example, heavy summer air conditioning load) is fairly steady throughout the year.[efn_note]At the Electricity Data Browser, choose the “Retail sales of electricity” data set, then filter for California and all sectors, and select a time period and monthly output on a time series basis.[/efn_note]

So the problem is with a month like December, with relatively low solar generation and yet average consumption. I crunched study inputs and EIA data to find that California consumption in December would be about 46,250 GWh.[efn_note]The study projects California annual generation in 2045 of 500,000 GWh (slide 16), which I grossed up for transmission and distribution losses of 7.24% (Inputs & Assumptions, page 7) to get annual consumption of 539,000 GWh. Then, to get December’s share of that, I divided December 2019 consumption by total 2019 consumption from EIA’s Electric Power Monthly for December 2019, Tables 5.4.A and 5.4.B. Applying the share percentage of 8.58% to annual gives December 2045 consumption of 46,250 GWh.[/efn_note] When I add up California’s existing renewable generation that month (including imported hydro and Palo Verde nuclear), I get 8,760 GWh.[efn_note]Existing California renewable generation for December 2019 comes from Electric Power Monthly for December 2019, Tables 1.10.A, 1.14.A, 1.15.A, 11.16.A and 1.17.A. Imported hydro and nuclear estimated from the Inputs & Assumptions document, pages 22 and 29.[/efn_note] Then I apply December capacity factors for wind and solar to the new wind and solar resources and get 18,000 GWh.[efn_note]California renewable capacity factors for December 2019 calculated from Electric Power Monthly for December 2019, Tables 1.14.A, 1.17.A and 6.2.B. I used the study’s capacity factor for offshore wind of 52%. The capacity factors are applied to the new renewable resources listed at the beginning of the column.[/efn_note] So, total existing and new renewable generation is 26,760 GWh.[efn_note]Please note that batteries and other storage such as 12-hour pumped storage can’t help a monthly deficiency. They can’t recharge without depleting the supply needed for load.[/efn_note] There is a 19,490-GWh deficiency, i.e., blackouts.

Now, we could assume that the existing gas fleet is still around, despite being a non-zero-carbon resource. I reckon 28 GW of gas running at a 94% capacity factor could cover the deficiency — if levels of consumption and other generation cooperated perfectly. But that doesn’t do much for a zero-carbon future.

As with the peak-day analysis, to achieve true zero carbon, the study presents a scenario that assumes green hydrogen fuel cells replace gas generation. The study projects a green hydrogen fuel cell cost of $126/MWh in 2045 (slide 28), making the cost of covering the December deficiency around $2.5 billion.

And that’s just one month, on top of the massive costs of new solar, wind and battery resources.

What’s the Takeaway?

A zero-carbon, reliable, affordable future remains an enormous challenge. We should be realistic and not sugarcoat this.

Nor should we throw staggering amounts of solar, wind, batteries and fuel cells at the problem and hope for the best. We need to think about all the options, especially on the consumption side of the equation. Efficiency (e.g., LED lighting, which has reduced carbon emissions twice as much as rooftop solar[efn_note]http://www.energy-counsel.com/docs/LED-Kills-the-Edison-Star-2017-01-24%20RTO-Insider-Individual-Column.pdf.[/efn_note]), demand response, load shifting (hot water heating) and time-of-use rates are a few examples.

And on the resource side, let’s not make big mistakes, such as subsidizing rooftop solar that costs four times as much as grid-scale solar.[efn_note]Grid-scale solar is about $40/MWh levelized cost of energy while rooftop solar is about $155/MWh. https://www.lazard.com/media/451086/lazards-levelized-cost-of-energy-version-130-vf.pdf (page 2, using the midpoint for grid solar and averaging the midpoints for both rooftop solar types). California could more than cover the (staggering) costs of 70 GW of new grid solar simply by not subsidizing rooftop solar.[/efn_note] And is it too late to save Diablo Canyon like I urged four years ago?[efn_note]http://www.energy-counsel.com/docs/Helter-Skelter-September-Fortnightly.pdf.[/efn_note] Remember when those insisting on closure said an estimated cost of $69 to $72/MWh made it too expensive to keep?[efn_note]https://www.nrdc.org/experts/peter-miller/diablo-canyon-legislation-signed-law-governor-brown.[/efn_note]

Now even that inflated cost looks like a bargain compared to $126/MWh for green hydrogen fuel cells.

September 22, 2020

ELCC Method Endorsed by PJM Stakeholders

PJM members on Thursday endorsed a revised joint stakeholder proposal to use the effective load-carrying capability (ELCC) method to calculate the capacity value of limited-duration, intermittent and combination (limited-duration plus intermittent) resources.

The Markets and Reliability Committee and Members Committee approved the ELCC over the objections of Independent Market Monitor Joe Bowring and others, who said the proposal, which could have a profound effect on the capacity market, was flawed.

The joint stakeholder proposal, Package D, received a sector-weighted vote of 3.98 (79.6%) from the MRC after a friendly amendment clarifying issues was added at the meeting. In a first-round vote at the MRC, the proposal without the friendly amendment received a sector-weighted vote of 2.56 (51.2%), failing to meet the two-thirds threshold for endorsement.

The Members Committee approved Package D with the friendly amendment later Thursday by a sector-weighted vote of 4.05 (81%).

PJM — Betty Watson, Modern Energy | © *RTO Insider*

ELCC, which is already used by MISO, NYISO and CAISO, evaluates reliability in each hour of a simulated year and compares a resource mix with limited resources against one with unlimited resources. A resource that contributes a significant level of capacity during high-risk hours will have a higher capacity value than a resource that delivers the same capacity only during low-risk hours.

Betty Watson, senior director of policy and market design at Modern Energy, one of the sponsors of Package D, praised the work done by PJM and stakeholders since April when the issue was brought to the Capacity Capability Senior Task Force (CCSTF).

“The package approved by stakeholders today represents an important step forward for the participation of energy storage and intermittent renewables in PJM,” Watson said. “Just as important, the package represents the result of meaningful stakeholder cooperation and finding common ground.”

ELCC Background

Melissa Pilong of PJM provided an update of the work completed at the CCSTF. In October 2019, FERC opened a paper hearing under Federal Power Act Section 206 on the capacity capability of energy storage resources in PJM. Pilong said ELCC, which was already under consideration for solar and wind resources in the RTO, could serve as an alternative to the 10-hour minimum run time requirement for storage that was rejected by FERC last October.

FERC partially approved PJM’s Order 841 compliance filing but set a paper hearing to determine whether its 10-hour minimum for storage seeking capacity obligations was unjust and unreasonable. (See FERC Partially OKs PJM, SPP Order 841 Filings.)

Pilong said that by January, PJM began soliciting feedback from stakeholders on proposed alternatives to the 10-hour requirement. PJM then submitted a motion to hold the FERC hearing in abeyance to pursue an ELCC construct with stakeholders. The commission ultimately granted PJM’s abeyance motion, setting a deadline of Oct. 30 for a response from the RTO.

The MRC approved an issue charge in March to consider using ELCC to set the capacity value of limited-duration resources such as battery storage. The issue was then sent to be worked on by the newly created CCSTF. (See PJM MRC Moves Forward on Storage, Hybrids.)

Proposed Packages

Andrew Levitt, PJM’s senior business solution architect, presented Package A, the main motion endorsed by the CCSTF, receiving 64% support in a nonbinding vote in the subcommittee.

Levitt said the PJM package had several key characteristics, including specifying the ELCC methodology for simulated dispatch of energy storage resources, hydroelectric resources with storage and other limited-duration resources. It also provided for an annual reassessment of derate factors, performance factors and accredited unforced capacity (UCAP) values for all applicable resources.

Levitt said the package was designed to accommodate a diversity of resource classes, including new technology like four-hour energy storage resources and hybrids.

Package A ultimately failed at the MRC, receiving a sector-weighted vote of 1.29 (25.8%).

Watson reviewed Package D at the MRC, which was the alternative solution endorsed by the CCSTF with 57% support in a nonbinding poll. Watson said the joint stakeholder transition package was formulated to find a balance between accurate and stable market signals, stakeholder preferences, the various business models of asset owners and existing and future resources.

Watson said the package was a “true negotiated outcome” and not the design of any one stakeholder. It built upon the foundation of Package A and went even further, Watson said, adding in a transition package that provides values for the class average ELCC percentages. The transition package will be evaluated in the 2026 quadrennial review, Watson said, in which PJM will “evaluate its efficacy and appropriateness and make recommendations as to whether some or all components of this package should be reconsidered through a stakeholder process.”

The friendly amendment added to Package D was developed after further discussions with stakeholders, Watson said, with an agreement to further evaluate the operations of limited-duration resources following FERC approval of the ELCC-related filing that includes a four-hour limited-duration class. PJM will also initiate a stakeholder process to further evaluate the coordination of the operation of limited-duration capacity resources with system needs and to consider rules to ensure that their operational behavior is “appropriately aligned with the resource adequacy construct and system reliability by examining issues including, but not limited to, bidding, operations, emergency procedures and energy market offer requirements.”

Also in the friendly amendment is a “clarification of intent of transition” with language recommended to the PJM Board of Managers to include in the cover letter for the proposal’s filing with FERC, stating, “Nothing in the joint stakeholder package is intended to preclude any potential changes to the structure and market design of PJM’s Reliability Pricing Model or create the expectation that the current market design will remain intact.”

“This package is not at all where the joint stakeholders started but really represents the evolution that we’ve all arrived at after months of dedicated work,” Watson said.

Besides the packages, stakeholders also voted to endorse corresponding Reliability Assurance Agreement (RAA) revisions.

Stakeholder Opinions

Monitor Bowring gave a presentation on his firm’s interpretation of the ELCC, saying it was “premature” for stakeholders to rush toward a solution on the issue. Bowring said the solutions in the packages could have significant impacts on the PJM capacity market for decades because of issues like a locked-in floor value based on a 10-year forecast of ELCC values.

Bowring said a 10-year ELCC forecast will be based on unknown inputs, including thermal and intermittent capacity levels, which would prevent a mechanism for understanding the ELCC forecast error. He said the ELCC should reflect the capacity resource mix and can only be accurately determined when incorporated into PJM’s market clearing engines.

“We just want to emphasize that the ELCC approach represents a really significant change to the capacity market,” Bowring said. “We don’t think there’s any reason to rush.”

Calpine’s David “Scarp” Scarpignato said FERC put PJM in a position where it’s difficult to meet deadlines while still adequately addressing the issues surrounding ELCC. Scarp said he hoped there would be more time to formulate a more clearly defined solution to the issue and wanted to see more data from PJM to make a more comprehensive decision.

“We weren’t given adequate time as stakeholders to truly give this justice,” Scarp said. “I imagine we’re going to have to rework some of this in the future.”

Tom Rutigliano of the Natural Resources Defense Council said both proposed packages were a “major improvement” in how PJM handles non-traditional resources and represented a “big step forward” in how the RTO handles resource adequacy in a “rapidly changing grid.”

Carl Johnson of the PJM Public Power Coalition said most stakeholder criticisms of the packages were “valid” and presented a difficult issue for members to solve as PJM makes its filing with FERC next month. Johnson said the packages provided little detail as to how resources would be represented in the ELCC model and how they would actually have to behave in real-world scenarios for the model to work.

“Above all, it’s certainly in my members’ interest that we do not send another mess to FERC or that we at least limit the mess,” Johnson said.

September 20, 2020

NYPSC Accepts CLCPA Environmental Review

The New York Public Service Commission on Thursday approved an environmental impact statement on the additional renewable resources needed under the Climate Leadership and Community Protection Act (CLCPA) that concludes that the increase “could result in direct benefits in the form of reduction in [greenhouse gas] emissions, additional economic development, workforce employment, the avoidance of adverse health outcomes, and improved transmission and distribution network” (15-E-0302).

“This is just one step, but it is essential in moving ahead on the ambitious and necessary renewable energy targets called for in the CLCPA,” PSC Chair John B. Rhodes said.

The CLCPA requires that 70% of electricity come from renewable resources by 2030 and that electricity generation be 100% carbon-free by 2040. Its clean energy targets include deploying at least 9 GW of offshore wind energy by 2035, doubling distributed solar generation to 6 GW by 2025, deploying 3 GW of energy storage by 2030 and raising energy efficiency savings to 185 trillion BTU by 2025.

The supplemental generic environmental impact statement (SGEIS) for the new law, as required by the State Environmental Quality Review Act (SEQRA), updated the state’s 2018 SGEIS by including:

the impact of additional utility-scale solar projects on grassland birds;
additional hydropower upgrades and low-impact run-of-river projects;
development of additional offshore wind; and
development of 3,000 MW of distributed solar on land use, visual resources and birds.

The PSC’s resolution of acceptance built on a white paper published in June by it and the New York State Energy Research and Development Authority (NYSERDA), which recommended updating the state’s Clean Energy Standard with the CLCPA targets and proposed a feasibility study for Great Lakes wind development. (See NYPSC Approves $700 Million for EV Chargers.)

NYPSC CLCPA review — Potential sites for utility-scale solar PV categorized by size | *NYSERDA*

Commissioner Diane Burman voted “no” without prejudice, as she did in June on the draft SGEIS. Although she said she would normally vote in favor of such a procedural matter, she could not accept the SGEIS as complete because the comments from stakeholders such as Sierra Club and National Fuel Gas “are really worth taking the time as a group to review and go through.”

Commissioner Tracey Edwards voted in favor but noted that an SGEIS can be submitted anytime “if there is any change in circumstances. … We should be following the [SEQRA] documents, as it’s important for us to check environmental circumstances along the way. The lead agency has a requirement to do that.”

Commissioner John Howard said that “while this is a roadmap, the real nitty-gritty questions will come in implementation.” He asked that the PSC pay close attention to “environmental justice issues, to make sure that rural communities get treated equitably.”

The assessment noted that it does “not substitute for project-specific environmental reviews, which may result in the identification of site-specific impacts.”

DLM Incentives Extension

The commission also modified the dynamic load management (DLM) implementation plans for the six major electric utilities in New York to include solicitations for two new products (18-E-0130).

The commission’s action follows from its 2018 energy storage order, which directed Central Hudson Gas and Electric, Consolidated Edison, New York State Electric and Gas, Niagara Mohawk, Orange and Rockland Utilities and Rochester Gas & Electric to supplement their existing one-year DLM programs by holding competitive procurements for resources for at least three years. The commission said it expects that energy storage rates for PSEG Long Island, which operates the grid for the Long Island Power Authority, will be consistent with its guidelines.

The commission said the existing DLM programs — commercial system relief program, a day-ahead peak-shaving program; distribution load relief program, an intraday reliability program; and direct load control program, a peak-shaving and reliability program for residential and small commercial non-demand customers — “resulted in a bias towards short-term, low-capital investment solutions” because of their yearly performance structure.

“The [2018] energy storage order explained that securing compensation over a multiyear period is expected to stimulate more participation and investment in the programs,” the commission said.

The commission ordered the utilities to issue solicitations by November to procure DLM resources beginning next summer:

A day-ahead peak-shaving program requiring load relief for a four-hour period with at least 21 hours advance notice (called “Term-DLM”)
A reliability and peak-shaving program to provide load relief for four hours at any time except for specified off-peak charging hours, with at least 10 minutes advance notice (called “Auto-DLM”)

Term-DLM will be available throughout each utility’s service territory, while Auto-DLM will be limited to certain areas of their territories.

Although the order did not explicitly require the utilities to issue annual solicitations for new Term-DLM and Auto-DLM resources, it said “we hereby establish the expectation that such solicitations will become a regular part of DLM program operations.”

“Sometimes our work is technical, and at the same time it’s a big deal, and this is one of those cases,” Chairman Rhodes said. “This will unlock storage and other flexibility resources into use cases that are good for the system and, critically, are also good for customers.”

New York now has approximately 93 MW of advanced energy storage capacity deployed with 841 MW in the pipeline, in addition to 1,400 MW of traditional pumped hydro storage, toward meeting its goal of 1,500 MW deployed by 2025, the PSC said.

The PSC’s 2018 storage order, which doubled New York’s storage goal to 3,000 MW by 2030, said that the targeted deployment of storage “will result in reductions in system peak load demand during critical periods, increases in the overall efficiency and resiliency of the electric grid, and displacement of fossil fuel-based generation.” (See NYPSC Expands Storage, Energy Efficiency Programs.)

Commissioner Burman dissented in part because she said the commission should have reconsidered its position on energy storage, as so much has changed since the 2018 order.

“We started numerous technical conferences; a market design and integration group was set up; NYSERDA filed many different filings; and there was a [Department of Public Service] end-use storage deployment program report; and there were notices issued for comment; … and the list goes on,” Burman said.

September 20, 2020February 12, 2025

Dykes Calls out ISO-NE, FERC on Carbon Pricing

Connecticut Department of Energy and Environmental Protection Commissioner Katie Dykes took aim at both ISO-NE and FERC in a panel discussion on carbon pricing in wholesale electricity markets at Thursday’s Consumer Liaison Group video meeting.

Dykes said she opposes the RTO’s proposal to add a carbon price on top of the Regional Greenhouse Gas Initiative (RGGI), which sets the cap for carbon emissions across New England.

“Our states in New England, participating in RGGI as we do, have sent multiple letters to ISO New England and to [the New England Power Pool] regarding carbon pricing,” Dykes said. “And essentially, repeatedly we’ve had to go on record, stating that we are not in support of a carbon adder as a supplement or perhaps as a replacement for the RGGI program.”

Dykes, who served as chair of the Connecticut Public Utilities Regulatory Authority from 2015 to 2018 and RGGI board of directors chair from 2014 to 2017, noted that states also contract for grid-scale renewables and back utility-administered investments in energy efficiency.

“Overall, those programs, in compliment with the RGGI program, have contributed to achieving significant reductions in carbon emissions in our state at a relatively low cost to families and businesses,” Dykes said.

RGGI’s strengths are that it is governed by state commissioners, Dykes said, which means program designs align with individual states’ policies, and it provides for reinvestment of proceeds from the sale of allowances.

“Those reinvestments are flowing back into energy efficiency programs, which provide the greatest magnifier of benefits for our customers, not just in terms of further reducing emissions … but also helping to offset individual bills,” she said.

Estimated consumer energy costs that adopt electric vehicles and convert to electric heat pumps | Analysis Group

Asked to comment on Dykes’ remarks, an ISO-NE spokesperson said the RTO “continues to support the states as they work to develop electricity sources that are clean, reliable and cost-effective for the benefit of our region. We’ve recommended carbon pricing as a simple, cost-effective and transparent solution to integrate the state’s policy goals with the wholesale electricity markets. We recognize it as just one of several ideas being discussed among the states and regional stakeholders to deliver a clean energy future for New England.”

Joseph Cavicchi, vice president of Analysis Group, gave the Consumer Liaison Group a presentation on his company’s report on carbon pricing for the New England Power Generators Association (NEPGA). He agreed with Dykes for the “need to be cognizant of the costs that would be incurred by consumers” if carbon pricing pushed up not only electricity prices, but also increased the cost of gasoline, natural gas and oil as well. Cavicchi said progressively increasing the price on carbon emissions can support market-based investment in “clean energy technologies.”

“If you had a carbon price that translated to $25 to $35/short ton in 2025, upwards to $55 to $70/short ton in 2030 and 2035, you’d go a long way toward supporting the kinds of investments that we think are necessary,” Cavicchi said.

‘Tragic’ Disconnect

During the panel’s question-and-answer session, Dykes fielded a question from an attendee who referenced FERC’s Sept. 4 ruling rejecting NYISO’s proposal to make it easier for public policy resources to clear its capacity market. (See FERC Rejects NYISO Bid to Aid Public Policy Resources.)

Dykes said that FERC is challenging the ability of states to rely on competitive markets to achieve decarbonization goals. That is “really the tragedy of this disconnect between the federal policies and in states continuing to address the need to mitigate carbon emissions,” she said.

She also said it concerned her that no state regulators were invited to speak at FERC’s Sept. 30 technical conference on carbon pricing in the wholesale electricity markets. (See FERC Announces Tech Conferences on Carbon, OSW.) ISO-NE CEO Gordon van Welie and Matthew White, chief economist for the RTO, are scheduled to be panelists.

“We look forward to sharing our perspectives,” the RTO spokesperson said of the conference. “The New England states play an important role in evaluating potential solutions, and we fully recognize that any solution for carbon reduction in our region, such as carbon pricing, requires a coordinated effort with state policymakers.”

Boston Climate Action Plan

John Cleveland, executive director of the Boston Green Ribbon Commission, a group of stakeholders working to implement the city’s Climate Action Plan, gave a presentation on the group’s work and the 2019 update of the climate plan, which highlights the steps the city will take over the next five years toward achieving carbon neutrality by 2050.

Cleveland emphasized the need for a “comprehensive and integrated approach,” including reducing energy demand and maximizing energy efficiency; electrification of transportation and heating; and a transition to greenhouse gas-free fuels. “There is no silver bullet,” he said.

As next steps, he urged the RTO to engage stakeholders to reach consensus, “reinvigorate” the Integrating Markets and Public Policy Initiative, invest in the Future of the Grid analysis and develop a decarbonization “pathways” analysis with options including carbon pricing.

ISO-NE Update

Eric Johnson, ISO-NE’s director of external affairs, gave the group an update on activities in the RTO, including the impact of COVID-19 on power demand, the RTO’s proposed 2021 budget and preparations for Forward Capacity Auction 15.

He said the RTO’s latest Electric Generator Air Emissions Report showed carbon dioxide emissions dropped by 31% during the 10-year period of 2009 to 2018. Nitrogen oxide emissions decreased by 43% and sulfur dioxide emissions plunged 94% over the same period, he said.

September 20, 2020

MISO Looks Back on Turbulent Summer

With a challenging summer in the rearview, MISO expects more traditional reliability risks this fall while making blueprints for an industry roiled by change.

MISO’s relatively low 114-GW summer peak in early July and average $21/MWh real-time prices belied a whirlwind season containing two emergency declarations. The peak was lower than both the grid operator’s projection (125 GW) and last summer’s peak (121 GW).

In late summer, MISO directed its first load-shed event after Hurricane Laura ripped through the heel of Louisiana. (See MISO Keeps Advisories in Effect a Week After Laura.)

MISO Executive Director of Market Operations Shawn McFarlane said the RTO began preparations for the hurricane about a week before the storm’s landfall. At the grid operator’s orders on Aug. 27, Entergy shed about 573 MW of load in the West of the Atchafalaya Basin load pocket.

The load-shed orders maintained grid stability and kept MISO South from experiencing cascading outages, McFarlane said during a summer review Sept. 15 before the Board of Directors’ Markets Committee.

MISO estimated that uplift payments totaled $90 million during the event. McFarlane said that is the largest the RTO has ever experienced from a single episode.

It could take until the end of October to restore power to all Louisiana ratepayers, based on Entergy’s restoration estimate, he said. About 80,000 Entergy customers remain without power, down from approximately 700,000 immediately after the storm.

McFarlane also said MISO monitored Hurricane Sally, which was brewing in the Gulf of Mexico before ultimately tracking east of its footprint.

The grid operator continues to review the Laura event and will hold future stakeholder discussions during the Market Subcommittee’s public session, McFarlane said. Subcommittee Chair Megan Wisersky has proposed a special joint meeting with the Reliability Subcommittee on Oct. 1 to discuss the hurricane’s impact on the grid.

RTO executives also reported that proactive communication with other grid operators was much improved during its other maximum generation event on July 7, when MISO Midwest was seized by a stubborn heat wave.

“It’s good to hear that coordination has improved. That’s what the public expects of us,” Board Chairman Phyllis Currie said.

“This was an exciting quarter. Usually I begin by saying it was an uninteresting quarter,” Independent Market Monitor David Patton said.

Patton said he is concerned about the availability of supply in Michigan’s Lower Peninsula, which racked up high congestion costs this summer. He said three resources in one transmission pricing zone that cleared the annual Planning Resource Auction were unavailable for most of the summer.

“They provided us virtually no value during the summer,” he said.

MISO: Fall Emergency a Possibility

McFarlane said MISO expects near normal load going forward.

“Load levels will more or less be at the level of what we call non-COVID,” McFarlane told the board. “We haven’t totally confirmed this, but our suspicion was air conditioning load was making up for economic impacts” during the summer, he said, explaining that mostly empty offices were still being temperature controlled while widespread work-from-home employees kept their houses comfortable too.

MISO might have to declare an emergency this fall if conditions are right, despite its 152 GW of available capacity paired with a 113-GW forecasted seasonal peak.

“As we say every quarter, if we end up in a high-load, high-outage situation, it may require access of our emergency resources,” McFarlane said.

He said higher outages paired with extreme weather conditions could lead to tightening supply. MISO said it’s preparing to work around more outages than usual this year, as the pandemic lockdowns in spring led to maintenance rescheduling.

“In the spring, 20 GW of outages were deferred,” McFarlane said.

MISO expects to have a little more than 115 GW of total available capacity in September after factoring in outages. If load stays at normal levels — about 112 GW — the grid operator doesn’t foresee a problem. But if high demand pushes load to 119 GW, MISO will have to dip into at least a few gigawatts of its 14.6 GW in load-modifying resources and operating reserves. The supply picture worsens if MISO has only 104.1 GW of capacity, as predicted by its worst-case outage scenario.

The RTO said that as usual, the largest amount of generation outages are slated to occur in October and November. It said the two months contain the highest potential for significant generation outages on monthly peak days.

MISO projects about 94.2 GW of available capacity in October with nearly 90 GW of usual load and a 95.2-GW high load. Increased outages could cull capacity to just 90.6 GW, making emergency measures all but certain in a high-demand scenario.

In November, MISO said available capacity should rise to 97 GW, handling both a typical 90.3 GW load and a 95.7 GW high load. However, if generation doesn’t return as expected, MISO could have just 92.6 GW of capacity on hand during the month, spurring operational challenges.

Changes Ahead

MISO Executive Director Ken McIntyre, a former NERC and ERCOT staffer, is helping the RTO modernize its operations and markets as the electric industry moves toward renewable and more dispersed generation.

“Today, we rely on operator experience and years and years of on-the-job-training. Tomorrow, we will have to rely on advanced monitoring and decision-support tools that predict conditions and provide guidance. Today, more days are the same. Tomorrow, more days will be different. The seasonal and peak demand profiles will become … less obvious and less meaningful for day-to-day operations,” McIntyre said.

He said MISO can launch automated tools using artificial intelligence in control rooms that can “pre-position the grid” for extreme weather or outages.

Vice President of System Planning Jennifer Curran said operations decisions will rely more on artificial intelligence and automated processes in the future.

“Today, we rely on operators with years of experience, and many of them are near retirement,” Curran said during the full board’s Thursday meeting. “There’s not a ready pool of additionally experienced operators to replace them.”

Director Barbara Krumsiek asked how MISO might incorporate “non-traditional forecasting arenas,” such as social forces, to predict energy demand. She pointed out that a coronavirus vaccine’s introduction could rally the economy and cause electricity demand to spike.

McIntyre said MISO might gather society trends by “scraping” data on social media to influence forecasts.

Patton also said MISO should transition to a “more sophisticated, probabilistic forecast” in their control rooms. He said that when faced with tight conditions, MISO tends to overcommit resources. That overcompensation often results in high revenue-sufficiency guarantee payments but low LMPs, he said.

“The tools could be much better to let operators make more surgical decisions,” he said.

September 20, 2020

MISO Readying Intensive Transmission Planning

Two recently announced special transmission planning efforts could have MISO members soon stringing miles of new wires across the footprint.

Stakeholders heard last week that a recently announced long-term transmission plan may result in project approvals as early as late 2021. At the same time, MISO and SPP will partner on an extra study focusing on transmission projects that could bring more of the renewable generation in the RTOs’ interconnection queues online. (See MISO, SPP to Conduct Targeted Transmission Study.)

Jennifer Curran, MISO’s vice president of system planning, said during the Board of Directors’ teleconference Thursday that while member companies’ renewable transition plans are disparate, stakeholder attitudes have shifted in favor of new transmission to support the metamorphosing generation portfolio.

MISO transmission planning — Jennifer Curran, MISO | *MISO*

“I think in our stakeholder community, we’re in quite a different place, even from a year ago,” Curran said. “Not all stakeholders are enthusiastic about new transmission … but we have received a lot of letters, feedback [and] emails from stakeholders saying, ‘Yes, it’s time to get going.’ 2030 is the equivalent of tomorrow when you’re talking about long-term, large-scale transmission projects. The work must begin today.”

MISO in mid-July confirmed it will undertake a series of long-range transmission planning studies under its annual transmission planning cycles. (See MISO Foresees Massive Shift to Renewables by 2040.)

Curran likened long-term planning to considering buying a new car rather than replacing a high-mileage car’s bald tires and fixing an oil leak. Long-term projects will not be approved en masse in a special portfolio, but under different annual MISO Transmission Expansion Plans, she said.

“With the Multi-Value Projects, it took four or five years to decide on projects for board approval. I just don’t think we have that kind of time here to bring projects forward for approval in 2025,” Curran said during the board’s System Planning Committee meeting Sept. 15.

From 2020 to 2022, MISO expects members to bring more than 25 GW in new generation online. That number pales in comparison to the 756 projects, totaling 113 GW, currently awaiting interconnection in its queue. (See MISO Processing Heftiest Interconnection Queue Ever.)

Curran acknowledged it will be challenging to find that “just-right, Goldilocks” level of long-term project approvals.

MISO and stakeholders will also work on cost-allocation processes next year as more immediate project needs emerge, she said.

The Organization of MISO States last week announced it has formed a special committee to examine and advise MISO on possible cost-allocation methods for long-term transmission projects. The special committee will be helmed by Indiana Utility Regulatory Commissioner Sarah Freeman.

Curran said the regulators’ perspective on cost allocation will be invaluable to MISO.

Teamwork with SPP

In a first, SPP CEO Barbara Sugg joined the MISO board’s virtual meeting on Thursday to discuss the RTOs’ increasingly crowded generation interconnection queues, the catalyst for the new joint study.

“SPP and MISO are such similar organizations dealing with such similar issues. … Our interconnection queue certainly draws the most criticism in SPP, and I’d wager MISO gets its share of criticism too. I think there’s no better time to collaborate and work together,” Sugg said.

“We thought about those queues … and how to make a difference for both of our members,” MISO CEO John Bear said in agreement.

MISO Executive Director of System Planning Aubrey Johnson said the study will likely last a year and is meant to identify project opportunities that wouldn’t be unearthed in the RTOs’ coordinated system plan studies.

Sugg gave MISO staff her “heartfelt thanks” for joining forces with SPP to possibly plan transmission together.

MISO Board Chairman Phyllis Currie said it was refreshing to see the cooperation between the two RTOs.

“I think her presence today says a lot about the level of commitment,” Currie said of Sugg’s address.

“Meeting after meeting, I’ve heard from our stakeholders that we need to do something about our seams issues. I hope this is evidence that we hear you,” Currie told stakeholders. “We can’t solve all seams issues, but I think it’s important we show that we’re listening to concerns.”

Director Baljit Dail said the “fantastic” teamwork between MISO and SPP was difficult to imagine more than a decade ago when he joined the board. “It may have taken a bit of time to get there, but we got there,” he said.

Clean Grid Alliance’s Beth Soholt also commended MISO and SPP for agreeing to the “important undertaking.”

Director Mark Johnson asked that MISO executives update the board on the study’s progress during the March quarterly board meeting.

September 20, 2020

NC Muni Wins Right to Add Storage over Duke Objections

FERC on Thursday granted North Carolina Eastern Municipal Power Agency’s (NCEMPA) request for a declaratory order allowing it to add battery storage to its system under its full-requirements power purchase agreement with Duke Energy Progress (EL20-15).

The commission rejected Duke’s opposition to the request, ruling that the PPA permits NCEMPA to use battery storage technology as either demand-side management or demand response. The commission cited a sentence in the agreement stating that it does not “preclude [NCEMPA] and/or its members from instituting or promoting activities designed, in whole or in part, to manage or reduce the members’ demands and/or loads through demand-side management programs.”

NCEMPA) storage — NCEMPA serves 32 cities and towns with their own municipal electric distribution systems in North Carolina. | *Electricities of North Carolina*

“When used as NCEMPA proposes, battery storage technology is inherently a load-shape-modifying device, designed not to reduce a customer’s overall load, but to shift the incidence of such load, i.e., to manage the customer’s demands,” the commission said. “Similar to other demand-side management activities, such as pre-cooling buildings overnight or midday to avoid withdrawing energy to provide air conditioning during afternoon peak-load conditions, NCEMPA’s proposed use of battery storage technology simply determines when energy is consumed.”

NCEMPA said it intended to use storage to reduce its load when prices are high because of increased system demand.

The commission noted that Order 841 — although not applicable in this case because NCEMPA is not part of an RTO or ISO market — “confirms that battery storage resources are capable of providing demand response service.”

The commission rejected Duke’s “restrictive interpretation” that battery storage is a form of generation, saying that it allows “a withdrawal of energy for later injection back onto the grid.”

Duke’s “argument ignores the fact that NCEMPA still would be purchasing its full energy requirements from Duke. The power used to charge the batteries would come from Duke’s generation, and then that power would be discharged from the batteries to serve NCEMPA’s customers,” FERC said. “The fact that NCEMPA is buying power from Duke at one hour and then using that same power from Duke in another hour does not change the fact that NCEMPA is meeting its full requirements through Duke.”

NCEMPA serves 32 cities and towns with their own municipal electric distribution systems. Between 1981 and 2015, it was the co-owner with Duke of two coal-fired generating units and three nuclear-fueled generating units operated by Duke.

September 20, 2020

FERC: No MISO Rules on Mid-queue Fuel Change Studies

FERC on Thursday said that MISO’s Tariff was silent on the issue of whether a generation project can switch from wind to solar while in the RTO’s interconnection queue (ER19-1823-003).

It also said that there was no requirement in Order 845 that requires grid operators to study projects that opt to change fuel types.

The issue stems from a Leeward Renewable Energy Development wind project currently in the definitive planning phase (DPP) of MISO’s generator interconnection queue. The developer wants to convert the project to using solar energy while also retaining its position in the queue.

Leeward said MISO was disregarding its own Tariff when it refused to perform an analysis to determine whether switching the project would constitute a material modification. Borrowing a phrase from Order 845, Leeward argued that the switch would result in “equal to or better” electrical performance.

Order 845 allows interconnection customers to make certain technological advancements to their generation projects without triggering a material-modification rule. Under the order, a customer can offer evidence that a requested technological change results in “equal to or better” performance. MISO must evaluate such claims and render a decision before projects can proceed.

MISO fuel change — | *Leeward Renewable Energy Development*

Order 845 also dictates that changes between wind and solar technologies should not automatically be treated as non-material modifications because “such changes involve a change in the electrical characteristics of an interconnection request, and the transmission provider would likely need to evaluate the impacts of such changes.”

MISO argued that it should not have to evaluate “mid-DPP fuel change requests” under Order 845 and said its Tariff doesn’t permit fuel type changes to projects after they enter the DPP.

But FERC said the Tariff allows Leeward to at least make a case for a fuel change in its generation project. It said Order 845 didn’t change MISO’s pre-existing material-modification provisions in its generator interconnection procedures. While Order 845 doesn’t require the grid operator to study fuel type changes, FERC said MISO also doesn’t have language in its generator interconnection procedures to preclude itself from studying fuel change requests.

“We find that the question of whether these pre-existing Tariff provisions allow an interconnection customer to submit a fuel change request after its project enters the DPP is therefore outside the scope of MISO’s Order No. 845 compliance filing,” FERC said.

The commission added that its decision was without prejudice to MISO making any filings to “further address the permissibility of, and requirements for, fuel change requests.”

September 20, 2020

FERC Upholds MISO Self-fund Order, Glick Dissents

FERC on Thursday left MISO transmission owners’ ability to self-fund network upgrades intact over a protest from the American Wind Energy Association and the dissent of Commissioner Richard Glick (EL15-68-005, et al.).

MISO in August 2018 reinstated TOs’ rights to self-fund network upgrades necessary for new generation. That meant generator interconnection agreements signed between June 24, 2015, and Aug. 31, 2018, could be revised to allow TOs to fund network upgrades and bill interconnection customers. (See MISO Gauging Aftershocks of TO Self-fund Order.)

The change came after the D.C. Circuit Court of Appeals remanded FERC’s 2015 decision barring TOs from electing to provide initial funding for network upgrades.

MISO Self-fund Order — FERC Commissioner Richard Glick | © *RTO Insider*

AWEA argued that the commission’s ultimate decision is “patently discriminatory” because it will allow those who had never applied for the self-fund option to do so and treat different interconnection customers differently. The association pointed out that before mid-2015, only one MISO TO has ever opted to self-fund a network upgrade.

FERC disagreed with the claims of discriminatory treatment.

“The fact that transmission owners may not have elected transmission owner initial funding in GIAs they were a party to prior to the interim period … does not, by itself, support a finding that such transmission owners should be barred from electing transmission owner initial funding on an ongoing basis,” FERC wrote.

AWEA also argued that FERC strayed from its usual mode of “preserving the sanctity of contracts.” It said the commission “has previously only departed from that precedent in extreme circumstances, such as fundamental industry restructuring and reorganization of a bankrupt utility.” The association contended that TOs shouldn’t be allowed to self-fund upgrades under multiparty facilities construction agreements because MISO’s original compliance filing didn’t mention such agreements.

FERC disagreed, noting that prior orders found that MISO’s facilities construction agreements and multiparty facilities construction agreements should be treated like GIAs.

Glick said the commission’s order didn’t “meaningfully” address AWEA’s concerns about the possible discrimination of some interconnection customers.

“Today’s order … doubles down on the unwise decision to permit the reopening of numerous previously negotiated interconnection agreements, despite considerable evidence that allowing transmission owners and affected-system operators to retroactively elect to self-fund the network upgrades associated with those agreements will result in substantial harm to interconnection customers and could lead to project terminations,” he wrote.

AWEA also argued that resource owners may have already started depreciating network upgrade investments in their books. FERC said that since 2015, generation owners have been put on notice that TO self-funding could again become a possibility.

Glick said that FERC stumbled by simply reversing its 2015 decision after the D.C. Circuit’s remand. He pointed out that the commission five years ago found that allowing TOs to unilaterally elect to fund upgrades could deny interconnection customers the “opportunity to finance network upgrades with more favorable rates and terms.”

He also said FERC’s decision to treat GIAs, facilities construction agreements and multiparty facilities construction agreements similarly was done without “any additional analysis or meaningful response to arguments raised by protesters.”

September 20, 2020

MISO Members Urge Dynamic Line Ratings

MISO members last week said the RTO’s footprint could benefit from transmission line ratings that change with the weather and other factors.

Clean Grid Alliance’s Natalie McIntire said static, conservative line ratings might be unnecessarily limiting transmission capacity and the amount of new generation resources that can interconnect to the MISO system.

“There might be transmission limitations that might exist for a small number of hours every year,” she said during a Advisory Committee conference call Wednesday.

McIntire also said it would be helpful if MISO transmission owners offered more information on how they form line ratings and for the RTO to identify the circuits that stand to benefit the most from more flexible ratings.

“As we’re all trying to make the most efficient use of the system, it would be helpful for MISO to tell us which are the lines that have the most potential gap between the static and dynamic ratings,” she said. Dynamic line ratings (DLRs) will ensure that consumers “get the most from their investment,” McIntire said.

DTE Energy’s Nick Griffin said MISO and its TOs should concentrate first on congested flowgates with the largest impact. “It doesn’t have to be broad range right at first,” he said.

MISO Dynamic Line Ratings — | © *RTO Insider*

Other members said MISO should establish a standard method for TOs to report the latest line ratings.

Organization of MISO States Executive Director Marcus Hawkins said transmission ratings in the RTO aren’t formed transparently. He has asked stakeholders to decide how large a role the grid operator should take in managing line ratings.

“MISO really could play a critical role in deciding where these enhanced ratings could be most beneficial and most cost-effective,” Hawkins said last month during an Advisory Committee teleconference.

Independent Market Monitor David Patton has said temperature-adjusted ratings would save the RTO about 10% of its total transmission congestion. He has estimated that MISO stands to save more than $150 million on an annual basis but says TOs remain reluctant to adopt DLRs because it involves investing in equipment and manpower with little return. Entergy already uses ambient-adjusted ratings in MISO South.

“The costs of not utilizing our transmission network is large,” Patton said during MISO’s Market Subcommittee meeting in April.

The Monitor and TOs have been discussing the possibility of DLRs in nonpublic Reliable Operations Working Group meetings.

The TOs said they’re working on their own benefit analysis of DLRs. Some cautioned that while some lines’ ratings could go up, some could also be lowered.

Transmission Owners sector representative Stacie Hebert said changes to facility ratings could result in higher cost recoveries and additional risk to TOs’ equipment.

DLR implementation made a shortlist of improvements that the MISO community was interested in working on in 2020. (See 7 Projects Make MISO 2020 Integrated Roadmap.)

Some stakeholders have said that while it’s true that lines can carry more capacity in below-freezing temperatures, it’s the generation component that’s often lacking in emergency conditions. That is especially true in MISO South, which is less prepared for arctic blasts.