Page 986 – RTO Insider

February 7, 2021

Net Metering Successors Need ‘Holistic Approach’

Four trends have emerged from the evolution of net energy metering (NEM) rate design taking place across the U.S., an industry expert told state utility commissioners and their staff last week.

The successors to original utility tariffs for distributed energy resources (DER) are focusing on avoided utility costs, value provided to the grid, cost shifting between customers and energy demand, Matthew McDonnell, managing director at Strategen Consulting, told state regulators Thursday during the National Association of Regulatory Utility Commissioners’ Winter Policy Summit.

Reforming the way utilities compensate behind-the-meter generators for the power they add to the grid “is a process, not a singular event,” McDonnell said.

“As technology costs continue to decline and as DER further proliferate, states will need to embrace a comprehensive and holistic approach to DER that will need to be reflected in tariff designs,” he said.

net metering rate design — At the NARUC Winter Policy Forum, attendees heard about the need for a “comprehensive and holistic approach” to programs that compensate behind-the-meter generators, like the rooftop solar system pictured here. | *SunPower*

Top among the trends in tariff overhauls is a focus on export compensation rates.

McDonnell said the widely used net billing approach that compensated energy by retail rate is moving to a calculation based on what utilities avoid spending by not building generation equal to what a customer’s DER provides.

In addition, how tariffs handle the calculation between what customer systems export and import is changing.

“With netting intervals, while they can vary from annual to instantaneous, we are seeing a trend towards greater granularity in order to better reflect the value provided to the grid on a time-differentiated basis,” McDonnell said.

NEM customer bills will also see more base charges in the future.

“With cost shifting a concern, many states have embraced non-bypassable charges as a way to ensure that public benefit programs and services remain adequately and equitably funded,” he said.

Some new NEM iterations, McDonnell added, are transitioning customers to billing based on when they consume electricity.

“We are beginning to see a trend whereby DER customers are increasingly asked to take service under an underlying [time-of-use] consumption tariff, with a goal of incenting more supportive grid behavior through better delivery of price signals to customers,” McDonnell said.

Integrative DER

According to McDonnell, DER tariff design will need to evolve to integrate DER as an operational resource that can provide core grid services. To achieve that goal, he said, regulators should ensure that non-wires solutions are accounted for and DER are integrated into power system planning for customers to fully realize cost savings.

Further consideration, McDonnell added, must be given to the possibility for DER participation in wholesale markets, as envisioned in FERC Order 2222.

“These activities will need to be harmonized at the distribution system level, and DER tariffs may need to enhance flexibility and ensure that there is no double counting of grid service provision,” he said.

In addition, state utility regulators have a complicated set of factors to work with in designing power portfolios that will meet clean energy targets.

Cost-effective resource portfolios must preserve customer choice and integrate DER as a core operational resource, while also acknowledging greenhouse gas reductions from customer-sited generation, McDonnell said.

The changes to states’ DER programs will also be underscored by a call to make them equitable and inclusive.

“DER policies … need to open opportunities for [low- to moderate-income] customers to participate,” he said.

State Hot Spots

How state regulators are approaching the evolving NEM landscape varies widely, but a few state examples demonstrate the leading edge of DER rate design, according to McDonnell.

While some states are just starting to address changes to their original NEM tariffs, California is headed into its third iteration.

California in 2017 implemented NEM 2.0 to succeed its original NEM program. Under NEM 2.0, there is no program cap and existing customers were grandfathered for 20 years. While the customers’ export compensation is still at the retail rate, NEM customers have to take service under a time-of-use rate, McDonnell said.

Proceedings for NEM 3.0 have begun, with new program design proposals due in mid-March.

McDonnell said that some of the principles guiding the new NEM tariff design include “the need to ensure equal compensation for the same generation, equal collection of unavoidable and non-bypassable charges from both participants and non-participants and the requirement that participants pay a fair share for the grid services they use.”

Regulators updated New York state’s NEM tariff in 2017 with a value of distributed energy resources (VDER) approach that McDonnell said offers more efficient price signals for mass market customers.

“Export compensation is determined by the DER value stack, stacking the wholesale price of electricity with other grid benefits of DER, including avoided emissions, cost savings to other customers and avoided capital investments,” he said.

Currently, VDER applies to non-residential DER customers, with the original NEM tariff extended for residential customers until 2022.

Michigan utility regulators in 2018 adopted a distributed generation program to replace its original net metering program. Of note in the new program, McDonnell said, is an “inflow-outflow” tariff mechanism.

Under the new tariff, DER customers pay for electricity delivered by the utility (inflow) under a regular cost of service-based retail rate, and the electricity they generate behind the meter but do not use (outflow) receives a credit. In the order adopting the new tariff design, Public Service Commission staff said inflow-outflow “accommodates a wide array of potential future rate designs, such as those including demand charges, dynamic pricing and dynamic credits.” It can also “form the basis for future load-control and demand-response programs that target distributed generation customers.”

February 5, 2021

Heard at NASEO: Make Net-zero Grid a Priority

State policymakers and corporate renewable energy buyers need to focus on making electricity grids entirely dependent on clean energy sources as the next step in achieving national climate goals, according to Roger Ballentine, a former chairman of the White House Climate Change Task Force.

“We need a net-zero grid before we can have a net-zero economy,” Ballentine, president of Green Strategies, said Wednesday during a panel at the National Association of State Energy Officials’ 2021 Energy Policy Outlook Conference online.

Deficits in renewable energy availability are still filled by oil and gas, Ballentine said, and that forces policymakers and clean energy advocates who were historically against nuclear energy to consider small modular reactors.

“Whatever you take off [the grid], you have to replace,” Ballentine said. With President Biden eyeing net-zero emissions by 2050, nuclear power is a temporary option until more renewable resources are built, he said.

NASEO Net zero — A former chairman of the White House Climate Change Task Force said power grids need to be entirely dependent on zero-emission resources to achieve U.S. climate goals. | *DOE*

Washington state will rely on hydroelectric and nuclear resources to comply with the Clean Energy Transformation Act, which commits the state to zero-emission electricity by 2045, said Michael Furze, assistant director of the energy division of the Washington State Department of Commerce. “It was a surprise to me to watch that progressive legislative process because it is a divisive issue among environmental justice communities that are active in the energy policy space,” he said.

But Ballentine said that for large renewable energy buyers like Google that are committed to using entirely clean energy, nuclear energy is an option to achieve that goal.

Vulnerable Communities

In the run-up to net zero, state policymakers need to ensure that the benefits of clean energy are equally distributed to communities that have been disproportionately vulnerable to the effects of pollution and climate change, Ballentine said.

Secure data collection from electric grids will guide policymakers in understanding where those communities are and what solutions are available, he said.

Patrick Woodcock, commissioner of the Massachusetts Department of Energy Resources, told RTO Insider that collecting information about energy use is in the pipeline to help the state target communities that could benefit from the renewable energy programs available but that are not participating.

But a siloed government approach will not be enough.

“It does take a federal-state partnership to create a clean energy agenda,” Woodcock said.

February 5, 2021

Weather Drove Fall Load Decline, SPP Monitor Finds

SPP’s average hourly load was off 7% last fall from the previous two years, the RTO’s Marketing Monitoring Unit said in its latest quarterly State of the Market report.

The Monitor attributed half the drop-off to cooler weather in September and warmer weather in November. The fall report covers September through November.

Average monthly profit from virtual transactions was just over $6.6 million in the fall, up from nearly $4.9 million the year before. Profits from virtual transactions were at their highest since the Integrated Marketplace began operations in 2014.

SPP Load — SPP’s average hourly load this past fall was down 7% from the year before. | *SPP*

Virtual transactions scheduled in the day-ahead market are settled in the real-time market. Virtual demand bids are profitable when the real-time energy price is higher than the day-ahead price; virtual supply offers are profitable when the day-ahead energy price is higher than the real-time price.

The report’s special issues section reviewed the potential benefits a new coordinated transaction scheduling (CTS) process could provide SPP and MISO through improved economic transactions on their seam. CTS is a real-time only process in which both RTOs forecast the future price at their interchange locations. Participants place price-sensitive interchange offers that clear when the offered price is within the price spread of the RTOs’ forecasted prices.

The Monitor conducted the CTS study at the request of SPP’s Regional State Committee and the Organization of MISO States. It is one of several suggestions regulators have made to improve the RTOs’ cross-border operations. (See MISO, SPP Regulators Call for Pancaking Fix, Smaller Projects.)

The Monitor will host a webinar to discuss the report on Monday.

February 5, 2021

States Working out the Details of Getting to 100%

As an increasing number of states commit to 100% clean energy standards, policymakers and regulators across the country are being faced with working out the details of how to reach those goals in the next 10, 20 or 30 years.

“Big targets are not enough,” said Virginia Sen. Jennifer McClellan (D), one of the sponsors of the Virginia Clean Economy Act, which has put the state on the road to 100% by 2050. “Which is why I and my fellow lawmakers are committed to making sure we have the right permitting process, tax treatments and regulations for energy storage.”

States Clean Energy — Virginia Sen. Jennifer McClellan | *Jennifer McClellan*

McClellan’s call to action opened a wide-ranging discussion on state policy during the second day of the Energy Storage Association’s annual Policy Forum on Thursday. Leaders from Arizona, Colorado, Michigan and New Jersey spoke about their top priorities for 2021, ranging from developing new rate structures for distributed energy resources to balancing their states’ response to COVID-19 with moving forward on clean energy goals.

Capturing the full value storage brings to the grid is challenging, said Dan Scripps, chair of the Michigan Public Service Commission, because “it offers a host of resilience and ancillary benefits, but those benefits are widely dispersed. Our regulatory proceedings often remain siloed; so, a comprehensive approach is needed.”

As a first step, Scripps said the MPSC is setting a high bar on integrated resource planning for the state’s utilities to “fully consider all available resources, and we’ve been pretty direct in our orders in terms of what we expect in terms of storage.”

In Colorado, Sen. Chris Hansen (D) said his first priority for this year’s session will be legislation that would grant energy storage equipment an exemption from property taxes, similar to the exemption for other renewable energy equipment. The state is targeting 100% clean energy by 2050, and the tax exemption would “spur rapid investment in storage,” he said. “It’s a big opportunity, and we need it.”

Arizona recently adopted a new tariff aimed at compensating a range of distributed energy resources for the different services they can bring to the grid, Corporation Commission Chairwoman Lea Márquez Peterson said.

“The focus here is really on third-party aggregators, not the utility company,” Márquez Peterson said. “It’s technology-agnostic, so the focus in not on a specific device being used, but rather on the characteristics of the device and the value each brings. So, it really does promote a free-market approach to the deployment of distributed assets.”

New Jersey has also set aggressive goals for renewables and energy storage, said Joseph Fiordaliso, president of the state’s Board of Public Utilities — including 2,000 MW of energy storage by 2030 and 7,500 MW of offshore wind by 2035. But responding to the COVID-19 pandemic has meant balancing priorities, he said.

“We are focused on the clean energy sectors that will bring immediate economic benefits to the state during the crisis, economic benefits through a new, innovative economy,” Fiordaliso said.

The BPU has also recently established an Office of Clean Energy Equity “to ensure that every citizen in the state of New Jersey has the opportunity to participate in the clean energy revolution.”

Bipartisan Blueprint

Enacting and implementing such a broad range of new policies will likely require broad bipartisan support. McClellan laid out the blueprint she and other stakeholders developed to pass major energy legislation in Virginia in a matter of months.

The first piece was bringing together an alliance of environmental groups, business leaders and public health experts, she said. “Everyone had slightly different goals, but we managed to get around a table and work out a game plan from the beginning,” she said.

The bill was also technology-agnostic, with no “silver bullets, but a collection of standards and investments that chart a path to 100%,” McClellan said.

And finally, to build bipartisan support, she said, “We focused every day on the economic aspects of our bill. We stood for job growth and a cleaner Virginia.”

February 5, 2021

FERC Orders Hearing on MISO Pact for Midwest-South Tx

MISO’s seemingly simple plan to extend payment arrangements for market participants that use the Midwest-to-South transmission path is destined for settlement proceedings.

While FERC in late January accepted the plan to extend the existing rate structure through Jan. 31, 2022, it also established hearing and settlement procedures, saying that the arrangement could be unjust or unreasonable (ER21-530).

FERC cited Alliant Energy’s and MidAmerican Energy’s complaints that market participants in an Iowa local resource zone bore a disproportionate one-third of rate schedule costs in 2020. The companies raised the issue in stakeholder meetings leading up to MISO’s filing. (See MISO Prolongs Terms on Midwest-South Tx Limit.)

Without the extension, the rate schedule was set to expire this month. The schedule lays out the cost allocation for market participants that use the subregional transfer limit beyond the 1,000-MW contract path linking MISO Midwest and MISO South.

Currently, MISO’s payments to SPP and other parties for flows across the transfer limit are recovered from market participants through a combination of load-ratio calculations and flow-based beneficiary allocations.

MISO Midwest-South — MISO Midwest and South | *MISO*

The load-based share has declined every year since 2016, while the flow-based portion has increased. From Feb. 1, 2016, to Jan. 31, 2017, the allocation was 45% load-based and 55% flow-based. From Feb. 1, 2020, to Jan. 31, 2021, the mix was 10% load-based and 90% flow-based.

Alliant said MISO “ignored stakeholders’ requests to share production cost modeling information necessary to determine why the share of costs allocated to Local Resource Zone 3 [in Iowa] continues to increase while the identified benefits (and thus costs allocated) to other zones remain zero.” The utility said either MISO’s production cost modeling or the allocation itself is “distorting the identification of the real economic beneficiaries.”

Alliant and MidAmerican said an extension of the rate schedule could affect MISO’s annual transmission planning because the grid operator performs a benefit analysis of potential projects that stand to reduce dependence on the Midwest-to-South transfer and thus reduce settlement payments to SPP and other parties. If MISO’s current cost allocation process identifies market participants in Zone 3 as being particularly helped by a transmission project that could offer an alternative to the transfer, Zone 3 could unfairly foot the bill on the project, Alliant and MidAmerican argued.

MISO doesn’t have any transmission projects lined up to secure more transfer capability between its subregions. (See “No Midwest-South Tx Solution this Year,” Price Tag Rising for MTEP 20.)

During a Market Subcommittee teleconference Thursday, MISO senior adviser Jack Dannis said the settlement process will begin soon.

In the meantime, Dannis said the RTO will use the extension to discuss a new settlement agreement and cost allocation with stakeholders.

“We want to initiate a more permanent cost-allocation mechanism for settlement payments after Feb. 1, 2022,” he said.

Dannis said MISO hopes to file a fresh allocation with FERC by Nov. 1. He said the grid operator will use “a lot of stakeholder feedback and interaction” to inform the rate schedule.

February 5, 2021

NY Public Speaks on Clean Energy Jobs, Costs, Urgency

It might come as little surprise that New Yorkers hold a wide variety of strong opinions about their state’s efforts to decarbonize its energy system and broader economy.

That was evident from a set of advisory panels recently convened by the New York State Climate Action Council (CAC) to gather feedback from the general public about the monumental effort to reduce carbon emissions.

The panels revealed that some residents believe New York officials should focus their greening efforts on employment, creating new clean energy jobs and training people in time for the expected construction boom in solar and wind projects.

New York Clean Energy — The Power Generation Advisory Panel of the New York Climate Action Council met on February 3, 2021. | *NYDPS*

Others think it was shortsighted to start shutting down the Indian Point nuclear plant before building the renewable energy capacity to replace it. Still, others say the state is taking too long to chart its transition to a clean-energy economy, while some stakeholders want energy costs kept down for all, including industrial users.

The various advisory panels and working groups will submit their initial recommendations to the CAC in April. The CAC is working toward fall delivery of a scoping plan for achieving New York’s ambitious energy and climate goals, even as the state inches toward economic recovery from the pandemic.

New York’s Climate Leadership and Community Protection Act (CLCPA) requires the state to consume 70% renewable electricity by 2030, switch to 100% zero-emission electricity by 2040 and reduce greenhouse gas emissions to 85% below 1990 levels by mid-century.

New Jobs Not All New

On Wednesday, the Just Transition Working Group took public comments after reviewing the state’s newly released Clean Energy Industry Report, presented by Philip Jordan, vice president at BW Research Partnership.

Jordan’s firm examined industry hiring challenges before the COVID-19 outbreak, noting that the construction industry “has really roared back to life” in New York.

“Which means we think that we’re in a position very soon to come to pre-pandemic levels of hiring difficulty, which is going to create some challenges in making sure we have enough workforce,” Jordan said.

“We are constantly defining and refining what clean energy is,” said Eliot Cresswell, a policy analyst with the Workforce Development Institute (WDI). “In the olden days these were brand-new jobs with brand-new skills and brand-new titles … but so much of this work can be carried out by people in occupations with skillsets that already exist.”

Amanda Kogut-Rosenau of Nontraditional Employment for Women (NEW) said that women made up 2% of the construction workforce when NEW started in 1978 but now occupy 7% of new hard-hat and “green collar” jobs. Tonya Gayle, executive director of Green City Force (GCF Corps), described how her group trains youth and workers from the inner city to either help them develop new career paths or enhance existing skills.

James Barry of 32BJ SEIU, a labor union representing 125,000 workers across 12 states and D.C., said SEIU started working with the New York State Energy Research and Development Authority (NYSERDA) in 2004 to train “green building supers.”

Marjaneh Issapour, director of the Renewable Energy and Sustainability Center at Farmingdale State College, one of two schools helping run the state’s $20 million offshore wind training program, said she sees many opportunities for policy regarding OSW, whose thousands of jobs are not all new jobs with new skills.

“Pre-apprenticeship models are fantastic to bring people from disadvantaged communities on board, but a study needs to be undertaken to understand how many of the new OSW jobs can go to more experienced workers,” Issapour said.

Compliance Costs

Couch White attorney Michael Mager, who represents Multiple Intervenors, a coalition of about 60 large industrial, commercial and institutional energy customers, said the group’s comment focuses on maintaining existing jobs in New York, including manufacturing jobs.

“Our members support the goals of the CLCPA, and many members have taken and continue to take aggressive actions to reduce greenhouse gases through increased energy efficiency efforts, the purchase of renewable power and attributes, and modified operations that incorporate renewable technologies,” Mager said. “Although fully supportive of CLCPA goals, many members of Multiple Intervenors are concerned about the unknown impacts of CLCPA compliance on the overall cost and reliability of energy supplies in New York state.”

Because of that uncertainty, the coalition would like to ensure that the definition of what is considered an energy-intensive and trade-exposed industry entity should be focused on preventing economic or emissions leakage to the greatest extent possible in order to protect manufacturing jobs, Mager said.

New York Labor Commissioner Roberta Reardon, co-chair of the Just Transition Working Group, said public engagement is “focused on understanding workforce training and development in a new clean energy economy. This is a topic of particular relevance to me and to the work of the New York State Department of Labor.”

Reardon’s co-chair, NYSERDA CEO Doreen Harris, said the working group “will be reserving time at a future meeting to debrief and discuss the feedback we hear today.”

The CLCPA charges the Just Transition Working Group with a number of workforce-related tasks, including to advise the CAC on issues and opportunities for workforce development and training, with a specific focus on disadvantaged communities and underrepresented people such as veterans, women and formerly incarcerated persons, Harris said.

Cool Hand Nuke

The Power Generation Advisory Panel held its public engagement session on Wednesday and will hold additional public comment meetings Feb. 12 and 22.

New York City resident Miles McManus urged the panel to “move a lot faster” with its mission, citing an article in Carbon Brief on the “budget” for how much CO₂ human activity can emit and still allow society to stabilize global warming at 1.5 Celsius above pre-industrial levels.

“With that budget, we’d have to cut emissions globally almost as much as COVID did, but every year, until we hit zero by 2040,” McManus said. “The situation is urgent, and thus, it is irresponsible to take a year to chart the path forward as the [CAC] is doing.”

Richard Berkley, head of the Public Utility Law Project, said he was speaking as a private citizen.

“This transition is probably the hardest pivot in New York’s economy in our entire history,” Berkley said. “The only thing that comes close is the Erie Canal … and the birth of New York City. We’re doing something that we’ve never tried before but is vitally important. There is no Plan B.”

Leonard Rodberg, professor emeritus of urban studies at Queens College, said he wondered why the panel did not discuss the closure of Indian Point, whose last unit is scheduled to go offline April 30. Entergy has agreed to sell the 2,311-MW plant to Holtec International, which will oversee its decommissioning. (See Entergy Celebrates Sale of Final EWC Nuke.)

“Closing just one unit of Indian Point last April has cost us annually more clean electricity than is generated by all the solar and wind power in the state today,” Rodberg said. “At your last meeting, NYSERDA presented plans for expanding solar and wind for the next four years; even if those plans are successful, they will have replaced barely one-half of Indian Point’s steady output with intermittent electricity.”

Retired librarian Paul van Linden Tol from Brooklyn said he believes nuclear power will be necessary to fight climate change and ocean acidification in New York, the U.S. and the world.

“The composition of this CAC panel seems to be mainly people with preferences for either renewable or the fossil industry; there’s no nuclear energy representatives,” van Linden Tol said.

Gas Troubles

Pramilla Malick, chair of Protect Orange County, said the 300,000 residents of her county “are frontline victims of a failure of public policy to protect the public’s interest and health by allowing the development of the [678-MW] CPV Valley fracked gas power plant, that was specifically built to replace carbon-free Indian Point.” (See New Builds to Cover Indian Point Closure, NYISO Finds.)

Malick said she found it reassuring the nuclear plant has been operating since 1962 without a major incident, though the agricultural area around the CPV Valley plant has 14 environmental justice communities.

“The only metric that should really matter to your commission is carbon … and methane,” Malick said. “We have documented large amounts of fugitive methane emissions, both at the infrastructure to serve the power plant and at the plant itself.”

Sarah Wilkinson of Brooklyn asked panel chair John B. Rhodes, chairman of the state Public Service Commission, “How can we let National Grid liquefy natural gas and truck it through my community?”

Rhodes said, “It’s an important topic, but that North Brooklyn project is up for a decision before my commission and there are rules that say I can’t comment on it, but I do understand your concerns.”

Irene Weiser from Fossil Free Tompkins [County] in Ithaca said she had concerns about behind-the-meter generation using natural gas, which “becomes a situation of doing an end-run around the CLCPA greenhouse gas emissions goals.”

When state officials permitted the 106-MW Greenidge power plant on Seneca Lake to switch from being a gas and wood-burning power plant to running a data center behind the meter, “this allowed them to skirt a lot of the CLCPA’s greenhouse gas rules … and is a loophole that needs to be closed,” Weiser said.

February 5, 2021

Glick: These 4 FERC Priorities Will Affect Energy Storage

Recently appointed FERC Chair Richard Glick told members of the energy storage industry Wednesday that the technologies they bring to the power sector will play a “big role” in the clean energy transition.

Glick said during the Energy Storage Association Policy Forum that among the priorities he wants FERC to address are four issues that directly affect energy storage expansion in the U.S.:

eliminating more market barriers;
revisiting minimum offer price rules (MOPRs);
increasing long-distance transmission development; and
overhauling interconnection queue processes.

Glick said he wants to expand on the commission’s work to address market barriers for new technologies.

FERC, he said, has addressed some market barriers for energy storage with, for example, Orders 841 and 2222, but there are more opportunities.

Glick said that while the commission’s work to date has focused on organized markets, there also are “big parts of the country that aren’t served by RTOs and ISOs.” He wants to explore some of the challenges those other markets are facing that create barriers for energy storage and clean technologies.

FERC Energy Storage — Avista’s Turner Energy Storage Project in Pullman, Wash. | *UniEnergy Technologies, CC-BY-SA-4.0 via Wikimedia Commons*

The technologies that support climate-related energy mandates also are being limited in mandatory capacity markets, he said, and he believes FERC can change that.

“Over the last several years, the majority of commissioners at FERC have opted for an approach in these capacity markets that essentially disadvantages technologies that have been the subject of state … efforts to subsidize or promote those technologies,” he said.

Energy storage and other clean technologies, he added, have been placed at a disadvantage in favor of older, less efficient generation plants that are “propped up” by MOPRs.

“These programs essentially are limiting the ability of cleaner technologies and subsidized technologies to fit into the markets at the price they want to bid in at,” he said, adding that the rules result in inefficiencies and higher prices for consumers. Capacity markets can’t sustain MOPRs because they create tension over states’ clean energy goals, he said.

Transmission and Interconnection

Glick sees transmission having a broad role in the clean energy transition, saying it’s important to “substantially build out the grid more than we have been doing.”

Long-distance transmission facilities that connect remote clean resources to demand centers must be a priority in that buildout, he said. In order to do that, he added, it will be necessary to “reassess some of the commission’s policies … sooner rather than later.”

Non-transmission alternatives — such as storage as transmission — can help offset the high cost of expanding the grid, Glick said. Interest in storage as transmission has been growing in the power sector, but Glick said the industry needs clarity from FERC on how that service will be handled in the future.

“I think it’s incumbent upon us to create a set of either rules or an outline of what the majority of the commission thinks might qualify as transmission from the storage facility perspective,” he said.

Storage as transmission presents an interesting set of challenges, he added, including, for example, whether a storage facility can compete in energy markets when it is not acting as transmission. Additional clarity is needed to determine who has operational control of a storage facility if it is treated by FERC as transmission.

With respect to needed changes in the transmission sector, Glick said he also wants to address the current challenges with interconnection queues for new resources.

“These projects, which include hybrid projects that are both solar and storage or wind and storage, stay in these interconnection queues forever,” he said.

Once those projects make it through the interconnection queue, they face costs related to network upgrades for interconnection. Those upgrades, Glick said, have benefits that go beyond the interconnecting generator that is being asked to pay for them.

The inefficiencies of that interconnection process, he said, halt the development of a lot of generation and storage projects and allow older, less efficient generation to stay online longer.

February 5, 2021

MISO to Outline New Pricing Plan for Hurricanes

MISO hopes to have a more nuanced pricing plan before the next hurricane contorts transmission towers.

Stakeholders have told the RTO that it was unacceptable for it to make after-the-fact price corrections to the $3,500/MWh value of lost load (VoLL) when Hurricane Laura tore through the grid in late August. (See MISO Questions VOLL Pricing During Abnormal Events.) They said the RTO’s use of VoLL is clunky because it doesn’t consider when load and generation are powerless to respond to real-time price signals during hurricanes and other force majeure events.

“Those prices were not shown in the marketplace for participants to respond to,” MISO Director of Market Design Kevin Vannoy told stakeholders during a Market Subcommittee teleconference on Feb. 4.

Vannoy said MISO will pursue alternative plans for pricing during force majeure events. He added that the grid operator would discuss a direction with stakeholders through April, finalize a plan in May and file with FERC by June 1, when the next hurricane season begins.

“This is urgent given the looming hurricane season,” Vannoy said.

MISO Hurricanes — Restoration crews in the wake of Hurricane Laura | *Entergy*

MISO used VoLL pricing last August in Louisiana’s Lake Charles area, where Hurricane Laura destroyed enough distribution and transmission lines to effectively create a dead zone. Five months after the storm, the RTO’s Independent Market Monitor continues to call for a retroactive pricing change for the dead buses priced at VoLL in Laura’s wake. (See “Laura Pricing in Question,” MISO Monitor Reviews Blustery Fall.)

“Force majeure events render generation and load physically unable to respond through no fault of their own,” staff said in summing up stakeholder sentiment.

Vannoy said to better price anomalies, they should be published in real-time, recognize the reliability value of the energy provided during a transmission emergency, recognize assets that are physically unable to respond, respect operational constraints and “assign the resulting costs exclusively to cost causers/beneficiaries.”

Monitor David Patton asked for a “permanent solution,” not simply a correction for Hurricane Laura.

The RTO is still in nonpublic discussions about settlement disputes stemming from Hurricane Laura. Market participants impacted by the storm had until December to initiate a settlement dispute process.

February 5, 2021

MISO Clarifies LMR Performance Rules

FERC on Wednesday allowed MISO to edit its tariff to clear up performance rules for load-modifying resources (LMRs).

MISO’s ruleset now more clearly states that LMR performance is evaluated on an individual basis, not on the aggregate performance of a market participant’s entire portfolio (ER21-693). Market participants can operate several LMRs across multiple local balancing authorities.

The tariff revisions, which the commission approved without comment, don’t change existing MISO policy. The new language is considered effective July 1.

The RTO said it discovered a need for the clarification following a maximum generation emergency in early 2019, when an extreme cold snap forced MISO’s first LMR use in its North and Central regions. (See Cold Snap Halts DER Talk as MISO Calls Max Gen Event.)

MISO said while market participants were able to supply 93% of the megawatts it requested to manage the emergency, only 21% of the deployed LMRs met the grid operator’s performance measurement and verification throughout the emergency. MISO penalized and even disqualified some LMRs after the event, leading their owners to seek alternative dispute resolution with staff.

“Ultimately, the information gathered through these disputes highlighted the need for the clarifications to the tariff,” MISO said.

Market participants were confused by the process, the grid operator said, and some were unaware that they needed to update their LMRs’ individual availability in the RTO’s communication system from default summer values to a daily offering.

The revised tariff language states that market participants are responsible for communicating to MISO “when the status or availability of an LMR changes.” When MISO calls up LMRs, scheduling instructions are sent to the owning market participants, not to individual resources.

The RTO also wrote that LMRs that “fail to perform in accordance with its market participant’s response to MISO’s scheduling instructions will be subject to a penalty and will not receive credit for its deployment.”

February 5, 2021

MISO Sets Sights on 4-season Capacity Market

MISO said Wednesday it is close to completing a proposal to create a four-season capacity market after floating a rudimentary plan with stakeholders, who remain skeptical over stricter accreditations.

While the RTO expects to file the plan with FERC by the end of the second quarter, seasonal auctions won’t become a reality until the 2023/24 planning year at the earliest. MISO is currently leaning toward the idea of simultaneously conducting four seasonal auctions with separate zonal clearing requirements.

“MISO’s inclination is to go forward with one auction but monitor it closely and have further discussion about modifying that,” Director of Research and Development Jessica Harrison said during a Resource Adequacy Subcommittee teleconference.

Independent Market Monitor Michael Chiasson said monitoring staff continues to feel “quite strongly” that the design should include a spot auction prior to each season to complement the annual auction.

The RTO said it is “monitoring the pace of changes and evaluating needs for additional spot or true-up auctions.”

As part of the seasonal approach, the grid operator will likely require resources to demonstrate their minimum capacity capabilities. MISO will also likely use a three-year average of historical data to define “resource adequacy hours,” or the system’s tightest hours of the year for reserve margins when resources should make sure to be available. (See MISO Intends to Add Seasonal Capacity Auction.)

MISO Capacity Market — MISO’s Carmel, Ind., headquarters | © *RTO Insider*

“If we’re going to have reduced capacity credits throughout the year, we have to make sure they’re available,” Harrison said.

She added that MISO must still determine how to treat capacity resources that take long-term outages. The RTO’s draft plan stands to reduce capacity accreditation for resources on long-term outages during the predefined tight hours, even if MISO has already approved the planned outages.

Stakeholders seemed most preoccupied with the potential for capacity resources to be penalized through accreditation reduction for planning extended outages during RA hours. Stakeholders said those hours would probably be difficult to predict and avoid when planning generation outages months in advance.

“Why would anyone bother to get permission for outages if they’re going to be penalized by MISO?” Customized Energy Solutions’ Ted Kuhn asked. “There is no benefit to providing this information. You’re basically going forward with an accreditation process that says, ‘I don’t care if you’re approved; you’re going to be penalized anyways.’”

Kuhn said the move might disincentivize resources from providing the data that MISO relies on for system reliability and to define tight margin hours.

“There is room for outages to be planned effectively and avoid these hours,” Harrison countered.

Harrison said the proposal focuses on individual unit behavior instead of socializing the risk across several capacity resources.

“I think we’re moving away from a process that penalizes everyone by focusing on individual units’… ability to meet capacity requirements,” she said.

“It seems incongruous of MISO to say, ‘Sure, you can take an outage, but the risk is on you,’” MidAmerican Energy’s Greg Schaefer said. He said the proposal seems to rely on resources’ “sheer luck” of not scheduling outages during RA hours.

“We all agree to pay a small premium to avoid people getting hammered,” he said, likening resources’ shared risk to a health insurance pool.

Kuhn asked MISO to consider implementing less severe repercussions for resources that aren’t available in light-risk seasons, when the RTO can only identify a few RA hours. Harrison said MISO would consider the idea.

Senior Manager of Resource Adequacy Coordination Lynn Hecker argued the availability-based accreditation proposal that takes the riskiest hours into account is “outage agnostic” by taking a true measure of resources’ availability.

MISO Executive Director of Market Operations Shawn McFarlane said it rewards the “more available portfolios” and reduces the accreditation of “less available portfolios.”