Page 590 – RTO Insider

October 8, 2021June 14, 2023

NYPSC: Utilities Ready for Winter; Electric and Gas Prices Increasing

New York regulators on Thursday heard that the state’s utilities are confident they will have sufficient electric and natural gas capacity to power customers through this coming winter, though customer bills will likely increase 13 to 20% from last winter (21-M-0243).

Tammy Mitchell, NYDPS | NYDPS

“These increased supply prices are not unique to New York state, but are in fact being experienced nationally and globally as the economy begins to recover and demand for natural gas increases after a pandemic-low level,” Tammy Mitchell — director of the Department of Public Service’s Office of Electric, Gas and Water — told the Public Service Commission.

U.S. natural gas prices have more than doubled since this time last year and are at a level not seen since 2014, she said. In Europe and Asia, wholesale prices are more than five times what they were a year ago.

NYPSC Chair Rory Christian | NYDPS

“With many New Yorkers already suffering from arrears, falling behind and being in the unfortunate position of having to choose between paying for heat or feeding their families, I want to … encourage New Yorkers in need to take advantage of several federal, utility and community-based programs available throughout the state that provide support,” newly appointed PSC Chair Rory Christian said.

The price issues seem to be downplayed, Commissioner Diane Burman said. She said she was concerned that there’s going to be “a major sticker shock” if the current price trends hold.

Burman also pointed to natural gas storage and pipeline constraints and referred to the gas hook-up moratoriums of recent years: “What does it mean in terms of interruptible customers remaining on oil? What does that mean in terms of possible lost economic development opportunities if people come and they need access to gas and they can’t get it?” (See Online Protesters Reject NY Gas Supply Plans.)

NYPSC Commissioner Diane X. Burman | NYDPS

With the advent of efforts to reduce greenhouse gas emissions in New York, the role of energy efficiency, demand response and electrification of heating will grow in importance, and staff will continue to brief the PSC on the transition of the natural gas industry, Mitchell said.

“There also is an interdependency between the electric and gas systems, as well as a high correlation between electricity supply prices and natural gas prices, since gas generators are typically the marginal units,” Mitchell said. “This interdependency was highlighted during the 2013-2014 polar vortex that resulted in all-time high winter peak demand on the electric system at the same time that cold weather impacted the operation of some generating facilities.”

Grid Prepared for Winter

DPS staff concluded that the grid is prepared to reliably meet the state’s upcoming winter electric demands, staffer Richard Quimby said.

NYISO expects to have 35,744 MW in net capacity resources available during the winter to serve forecasted peak load of 24,025 MW, including operating reserves, Quimby said. A winter protocol is in place to facilitate communication between state agencies and NYISO in circumstances where fuel supply for generation facilities may be at risk.

As part of the DPS’ winter assessment, staff reached out to major generation facilities owners in southeast New York who own about 12,000 MW of dual-fuel generation capability, he said.

“We found that these owners are continuing to implement lessons learned from past winter experiences, including having increased pre-winter on-site fuel reserves, having firm contracts with fuel oil suppliers, conducting more aggressive replenishment plans, and having more proactive pre-winter maintenance and facility preparations,” Quimby said.

DPS staff also met with NYISO and discussed its procedures and protocols for the winter period.

In recent years NYISO has instituted various changes to help ensure electrical reliability during periods of tight natural gas supply, including closely monitoring generator fuel levels and replenishment. In addition, NYISO has improved communications with interstate pipelines, local gas distribution companies and neighboring RTOs during periods of tight electric operating conditions, Quimby said.

Hurricane Ida Update

Kevin Wisely, NYDPS | NYDPSKevin Wisely, director of the Office of Resilience and Emergency Preparedness, gave the PSC an update on lessons learned from Hurricane Ida, which affected approximately 90,000 electric customers and caused a peak of 52,000 outages in New York during the early morning hours of Sept. 2. (See Experts Call for Tx Reinforcements, Microgrids in Gulf System After Ida.)

“The intense and severe nature of the rainfall caused numerous flooding issues throughout Westchester County and in the New York City area,” Wisely said.

Westchester’s flooding also caused issues with telecommunications equipment. “Verizon was able to quickly reroute incoming local 911 calls to predesignated backup sites so that no calls were lost,” he said. “Overall, the utilities responded, repaired and restored customers as quickly and safely as possible.”

Utilities must consider additional resilience improvements to system design, including such projects as substation location considerations for areas prone to flooding beyond that of just the coastal, river and creek impacts incurred during storms such as Superstorm Sandy and tropical storms Lee and Irene, Wisely said.

“Storm events such as Ida highlight the fact that municipal stormwater drainage systems and infrastructure must be enhanced also to handle larger volumes of rainfall over shorter periods of time,” he said. “With those types of storms in mind, utilities must continually reassess infrastructure vulnerabilities across the entirety of their service territories, determine appropriate resiliency projects to mitigate potential weather risks and make their infrastructure more adaptable to weather extremes.”

October 8, 2021November 8, 2023

California PUC Opens Investigation of Utility Safety

The California Public Utilities Commission launched a proceeding Thursday to evaluate and improve the safety cultures of electric and gas utilities, with the aim of preventing the state’s utility infrastructure from causing disasters like those of the last 11 years.

The new order instituting rulemaking (OIR) is significantly broader than prior safety culture investigations because it covers all gas and electric utilities under CPUC jurisdiction. Previous efforts focused on Pacific Gas and Electric after the San Bruno pipeline explosion of 2010 and Southern California Gas following the massive leak at its Aliso Canyon natural gas storage facility in 2015.

At least a half-dozen catastrophic wildfires blamed on electrical equipment since 2015 have made the safety practices at PG&E, Southern California Edison and other utilities a paramount concern. The November 2018 Camp Fire, for instance, killed 84 people and leveled the town of Paradise. State fire investigators determined the cause was PG&E’s failure to replace a century-old “C” hook on one of its transmission lines.

PG&E is now under investigation for starting this year’s Dixie Fire, the second largest wildland blaze in state history. The California Department of Forestry and Fire Protection seized PG&E equipment hit by a falling fir tree, and the federal judge overseeing PG&E’s probation in the San Bruno case has questioned the utility’s safety practices regarding shutting down power lines that show signs of trouble. (See PG&E Denies New Manslaughter Charges.)

“Safety culture is an organization’s values, principles, beliefs and norms shared by individuals within the organization, manifested through their planning behaviors and actions,” CPUC President Marybel Batjer said before Thursday’s unanimous vote. “It shows how members of an organization work toward safe operations on a daily basis and how that translates into safety outcomes.”

The new OIR is intended to fulfill recent legislative directives, the CPUC said.

Senate Bill 901 and Assembly Bill 1054 were passed in 2018 and 2019 to help investor-owned utilities cover billions of dollars in wildfire costs under California’s strict liability rules while also requiring the utilities to submit to wildfire prevention and safety culture evaluations by the CPUC. (See Calif. Lawmakers Rush to Pass Utility Wildfire Aid and California Wildfire Bill Goes to Governor.)

“Safety culture assessments of electrical corporations are required as part of [AB 1054 and SB 901],” the proposed decision on the OIR said. “AB 1054 directs the commission’s Wildfire Safety Division, now the Office of Energy Infrastructure Safety (OEIS), to conduct annual safety culture assessments of each electrical corporation, the first of which will be published in fall 2021. The AB 1054 assessments are specific to wildfire safety efforts and include a workforce survey, organizational self-assessment, supporting documentation, and interviews.”

“SB 901 directs the commission to establish a safety culture assessment for each electrical corporation, conducted by an independent third-party evaluator,” it said. “SB 901 requires that the commission set a schedule for each assessment, including updates to the assessment, at least every five years, and prohibit the electrical corporations from seeking reimbursement for the costs of the safety culture assessments from ratepayers.”

The CPUC will use the new proceeding to implement the bills, especially SB 901, Batjer said.

“This OIR will help us fulfill [our] mission by requiring utilities to proactively prioritize safety to better serve the public,” she said.

The proposed decision includes a preliminary scope of safety culture audits, but details remain to be worked out with stakeholder input. Parties have 45 days from Thursday to submit their written comments.

October 8, 2021

Conn. DEEP Releases Final Version of Integrated Resource Plan

Connecticut can follow multiple pathways to achieve a carbon-free electric supply by 2040, according to the final version of the state’s integrated resource plan, the biennial look at future electric needs and the strategy to meet them.

Officials from the Department of Energy and Environmental Protection (DEEP) held a virtual press conference Thursday to discuss the latest IRP, Connecticut’s first assessment of pathways to a zero-carbon electric sector, as directed by Gov. Ned Lamont through a 2019 executive order.

Among the key findings was that storage and demand management will play a vital role “in ensuring reliability of the grid and minimizing wasted generation.” DEEP Commissioner Katie Dykes said companies are working hard to enhance long-duration storage technology, and she applauded the U.S. Department of Energy’s “Long Duration Storage Energy Earthshot” that establishes a target to reduce the cost of grid-scale energy storage by 90% for systems that deliver 10 or more hours of output within the decade.

“That’s all good news for people who care about achieving both reliability and a decarbonized grid,” Dykes said.

DEEP is also seeking stakeholder and market input on storage procurement. The Connecticut General Assembly this spring passed legislation that targets 1 GW of energy storage deployment by the end of 2030 and gives DEEP procurement authority. The department can also issue requests for proposals for transmission and distribution grid-connected energy storage, which would factor toward deployment targets. (See Connecticut General Assembly Passes Energy Storage Bill.)

“We’re eager to hear from market participants or stakeholders about how such a storage procurement should be conducted in order to enhance the opportunities for long-duration storage,” Dykes said.

“Timely” enhancements to energy and ancillary services markets would also allow storage resources “to compete and be valued in the wholesale markets,” Dykes added.

Increased investment in long-duration storage also yields environmental justice benefits, Dykes said. Use of batteries would allow Connecticut to transition away from fossil fuel units that are used to maintain reliability but also comprise the “heaviest contributors” of emissions in environmental justice communities.

“We’re especially motivated with this storage procurement, as well as the focus on other types of investments around demand response and transmission,” Dykes said. “That can help to ensure we can scale up the investment of resources that can maintain reliability with the least emissions possible, [which is] critical for us to achieve our decarbonization goals and our commitments to advancing environmental justice.”

Continued Push for ISO-NE

The IRP continues Connecticut’s call for changes in market design and transmission planning by ISO-NE. Dykes said the RTO has made progress on the New England states’ concerns around transmission planning. It has also worked to eliminate the minimum offer price rule (MOPR) with input from NEPOOL stakeholders.

“We believe that wholesale market reforms are greatly needed much beyond just eliminating the MOPR,” Dykes said. “We need to ensure that the wholesale markets that we’re relying upon have reforms to energy and ancillary services markets that will help to ensure that carbon-free resources that are needed to maintain reliability are being procured as much as possible and valued in the wholesale markets that Connecticut chose to rely on more than two decades ago. We believe that’s really where the focus needs to be on if we’re going to find some compatibility between our state public policies and the design of wholesale markets.”

While governance is not explicitly spelled out in the IRP, “at first blush,” Dykes said, “incremental changes” by ISO-NE signal that the RTO wants to engage more with the states. Those changes include annual open Board of Directors meetings focused on wholesale electricity markets and system planning, a process potentially linked to the biennial Regional System Plan public forum.

Dykes said governance concerns also relate to ensuring broader accessibility to and transparency in ISO-NE’s processes for “all stakeholders and affected ratepayers in the region.”

“These incremental steps reflect the progress New England states have made in elevating the need for governance reforms, as a critical issue in our region,” Dykes said. “I’m convinced that we will not succeed in achieving better transmission planning and investment, or market designs that are more compatible with state public policies and consumer needs, unless we make transformative changes to the governance structures and transparency of ISO-NE.”

October 7, 2021November 13, 2023

Welch: Democrats Face Hard Choices on Cuts to Biden’s Budget

The webinar on Tuesday was ostensibly about energy efficiency jobs, but the discussion with Rep. Peter Welch (D-Vt.) inevitably drifted to the current battle over the bipartisan infrastructure bill and the Democrats’ $3.5 trillion budget reconciliation bill now unfolding in Congress.

Welch reported he was one of about 10 lawmakers on a Zoom call with President Joe Biden and Vice President Kamala Harris on Monday, and “he and she were both very realistic. He’s committed to everything in his $3.5 trillion program. But the reality is Sen. [Joe] Manchin thinks that is too expensive, and Sen. [Kyrsten] Sinema thinks that, too,” Welch said. “And we’ve got 48 votes in the Senate without them, so we’ve got to come to some resolution.

“There was a realistic discussion about the urgency of Democrats making the painful choices that we have to,” he said, although no specific programs that might be trimmed were mentioned. “This bill is largely paid for, but on climate initiatives, where the clock is ticking, we’re going to do everything we can as soon as we can, no matter what.”

Welch’s remarks came as Biden and progressives in the House of Representatives were trying to find a compromise figure, as reported in the Washington Post, with Biden suggesting $1.9 trillion to $2.2 trillion and the progressives countering with $2.5 trillion to $2.9 trillion.

Welch was optimistic that energy efficiency measures he has sponsored would survive the hard decision-making to come. One, the bipartisan Hope for Homes Act, would provide incentives for homeowners to make energy-efficient upgrades to their homes, while the Federal Buildings Clean Jobs Act, sponsored with Rep. John Sarbanes (D-Md.), would fund energy-efficient retrofits of government buildings, he said.

“Energy efficiency does three things,” Welch said. “One, it saves money; if you reduce the use of whatever fuel it is, you’re saving money. No. 2, it increases local jobs. … In each of our congressional districts where there are energy efficiency initiatives, it results in good jobs for good people. And third, it reduces carbon emissions.

“What is so tremendous about so many of the energy efficiency initiatives is that they have to be done at a micro level,” he said. “They have to be done in your home; they have to be done in the homes of black and brown citizens. And the more we have folks in the neighborhood participating in the program, the more we have local workers getting the benefits of the buildout, the more successful the program is going to be.”

Home Retrofits and Climate Goals

The problem with energy-efficient jobs, however, is that they are hard to count, said Philip Jordan, vice president of BW Research, which conducts an annual energy efficiency job survey for E2 and E4TheFuture, both clean energy advocacy groups that focus on economic and job growth.

“The Bureau of Labor Statistics doesn’t track energy efficiency as a standalone [category] because much of the work is done across other industry sectors,” Jordan said during the Tuesday webinar, rolling out the results of this year’s survey. “So, these are electricians and plumbing and HVAC and engineers and architects and assemblers.”

Based on interviews with more than 30,000 businesses across the country, the 2021 survey report counted 2.1 million Americans working in energy efficiency, accounting for more jobs than any other sector of the energy industry. The industry took a hit during the first stages of the Covid-19 pandemic, but it has been slowly rebounding, according to the report.

Retrofitting all 111 million U.S. residential units — homes and apartments — built before 2000 could create more than 1 million full-time jobs for 10 years, while saving Americans an estimated $66 billion per year on utility bills, the report says.

Efficiency may also be critical for the U.S. and individual states to meet carbon-reduction goals. The American Council for an Energy Efficient Economy (ACEEE) has estimated that robust energy efficiency measures could get the U.S. halfway to its 2050 climate goals, yet few states have specific energy-efficiency targets. A recent report from the ACEEE found that out of 17 states with 100% clean energy standards, only two — Virginia and Washington State — have specific energy-efficiency goals.

Similarly, while 24 states and Washington, D.C. have set carbon reduction goals, only New York and D.C. have set targets for decreases in energy consumption. Adoption of such targets could reduce the cost of meeting clean energy standards by managing demand on the grid, accelerate building and transportation electrification and “advance equitable decarbonization strategies” to ensure all consumers benefit from the clean energy transition, the ACEEE report says.

October 7, 2021December 13, 2023

Grid Operators Seek Policy Role, Reliability `Safety Valve’

Grid operators and planners need “a seat at the policymaking table” and a reliability “safety valve” to ensure efficient and reliable integration of renewables, the Eastern Interconnection Planning Collaborative said in a white paper Wednesday.

The EIPC was formed in 2009 under an agreement by 19 planning coordinators from the Eastern and Central U.S. — including MISO, SPP, PJM, ISO-NE and NYISO — with funding from the Department of Energy.

Its new report, titled “Planning the Grid for a Renewable Future,” contains no new data but makes three main recommendations for adapting the Eastern Interconnection to the increase in inverter-based renewables:

Enhance policy coordination across the “three-legged stool” of planning, cost allocation and siting: “Enhancing planning alone will do little to manifest the significant transmission needed to achieve a high-renewable future unless policymakers also deal with the issues of who pays for the new transmission … and challenges in siting new transmission, including issues of property rights, land use, and environmental and social justice.”
Establish a system of monitoring and course correction as events unfold: Regulators, industry and stakeholders should have the “opportunity to both monitor and correct course in a timely fashion if a particular [policy] path is leading to unnecessarily higher costs, limited choice for customers or negative reliability impacts.”
Enhance collaboration: To “ensure that public policy and the physics of the power system work harmoniously together,” EIPC says policymakers considering renewable portfolio standards, carbon dioxide standards, or other energy-related goals should invite system planners and operators to provide input “as to the full-range of planning and operational challenges, costs and trade-offs associated with the proposed set of standards. Understanding the full range of implications can be extremely challenging, which sometimes more high-level analyses used in the legislative process can overlook.”

The paper acknowledged the issues it raised “should not surprise industry leaders.”

But it said that because of the size and diversity of the Eastern Interconnection, “the insights among the planning coordinators through this effort provide a robust view on the lessons learned in planning the transmission grid to support high-renewable systems.”

The report says the growth of wind and solar resources is shifting resource adequacy risks beyond peak load periods, necessitating “more detailed modeling and integrated resource planning.” It also said additional transmission is needed to integrate renewables and meet increased demands for electrification of the transportation and industrial sectors.

To respond, there should be “a seat at the policymaking table for power system operators and planners to articulate the system reliability needs and how they are changing, so that public policy has built-in processes to account for these needs,” EIPC said. “… Grid operators and planners need to be more engaged in the discussions.”

The report said planners need more sophisticated modeling because of the growth of rooftop solar, backup generators, home chargers for electric vehicles, the conversion of gas and oil heating to heat pumps and whole-building battery backups. “As with operations, system planners must have adequate visibility into the locations and level of penetration of distributed energy resources so that the impact on the bulk system can be accurately modeled and controlled.”

In addition to transmission upgrades, integrating renewables may require “non-traditional assessments,” such as electromagnetic transient (EMT) studies to determine the impact of interruptions caused by lightning and system faults.

It praised the “proactive” implementation of IEEE 1547, the standard for interconnection and interoperability of DERs, as an example of “good, enhanced consultation.” (See State Regulators Endorse IEEE DER Standard.) “State utility commissions must adopt the new requirements if they are to be effective,” it said.

The lack of standardized performance requirements for inverter-based renewables has caused “significant delays” in the interconnection study queues of system planners, it said. “To address this issue, there must be transparency of the control systems by the designers and vendors, so that they can be validated by the resource owners and system planners to ensure system reliability.”

The report predicts energy markets will face increasing challenges in obtaining reliability services such as generator ramping, voltage support, reactive power, frequency response and system inertia that have historically been supplied by legacy synchronous resources at no cost or through regulated rates. “As resources become more diversified, the reliable and efficient delivery of electricity will require the development of additional market products to properly incentivize those ancillary services the grid needs,” it said. “Additionally, falling marginal energy prices due to the increase in renewable resources has already put pressure on existing resources that rely on energy or capacity revenues to remain operational.”

The group said regulators could consider a “reliability safety valve” in any future legislation to address unintended consequences that could impact grid reliability as new policies are implemented.

“The intent of the ‘timeout’ to address an identified reliability problem isn’t to block progress on the intended policy objective,” it said. “Rather, it is designed to ensure a limited surgical opportunity to address particular reliability issues that may arise either during the regulatory process in developing a final rule or during its implementation.”

Previous EIPC reports have examined gas-electric coordination, transmission planning and system inertia. (See Study: Frequency Response OK in Eastern Interconnection.)

In addition to the RTOs, the EIPC includes Associated Electric Cooperative Inc.; Dominion Energy (NYSE:D); Duke Energy (NYSE:DUK); NextEra’s (NYSE:NEE) Florida Power & Light; PPL’s (NYSE:PPL) Louisville Gas & Electric/Kentucky Utilities; South Carolina Public Service Authority (Santee Cooper); Southern Co. (NYSE:SO); and the Tennessee Valley Authority.

October 7, 2021June 14, 2023

Overheard at 2021 ISO-NE Regional System Plan Forum

ISO-NE hosted a virtual public forum on Wednesday to discuss its draft 2021 Regional System Plan (RSP), which generally uses a 10-year planning horizon to estimate the need for energy resources.

However, several studies are underway looking beyond 10 years to assess reliability with a decarbonized grid. Planning is also necessary for a future grid that is prepared to respond to extreme incidents like calamitous weather or cybersecurity events.

Here is some of what we heard during the forum.

Storage, Cybersecurity Keys for King

U.S. Sen. Angus King (I-Maine) | ISO-NEBefore he was elected to two terms as Maine’s governor, U.S. Sen. Angus King (I-Maine) worked for the development of hydroelectric and biomass projects and energy conservation in New England with two companies, one of which he owned and sold before entering elected politics.

King said the key to decarbonizing the power grid with 80% of electricity coming from renewables by 2030 is long-duration battery storage.

“I think the single biggest step is storage,” King said. “That’s the thing that is most important and allowing us to go to a decarbonized future.”

King said he does not see a limit to wind and solar technology, which is “improving daily; as their efficiency is going up, their cost is going down dramatically.” Instead, the problem is what fills in the gaps.

“Storage is the real Green New Deal,” King said. “If we can deal with that issue and can come up with the technology for grid-scale, long-duration storage, then we are well on our way to a decarbonized future.”

The grid of the decarbonized future also needs protection from bad cybersecurity actors. King said Russia and China were maliciously working to gain access to New England’s power grid as he spoke at the forum.

“I can guarantee you, right now at this very moment, there’s somebody in Moscow or St. Petersburg or Beijing or Shanghai working on how to penetrate ISO-NE; how to plant malware; how to create the opportunity to get in our data systems, to get in our transformers,” King said. “This is the most significant national security challenge that we face right now. The next 9/11 will be cyber.”

King added that RTOs have done well at “being ahead of this problem,” though they “can’t ever stop.”

“This is a constantly evolving threat,” King said.

As co-chair of the Cyberspace Solarium Commission, King said he had spent the last three years establishing a national cybersecurity strategy.

“I can tell you this is a grave threat, and you’re the target,” King said. “We need to establish a new relationship between the federal government and the private sector because 85% of the targets are in the private sector.”

King said that the natural gas pipeline system is “not adequately protected.” Because more than 60% of New England’s electricity comes from natural gas, King said that if something happens to the pipeline system, “we’re offline.”

Panel Discusses Extreme Events

NERC CEO Jim Robb said during a panel discussion on preparing and responding to extreme events that there have been a “cascading series” of weather incidents that have impacted the power grid. However, the “granddaddy of them all” was in Texas last February when a winter storm caused the ERCOT system’s near collapse and long-term outages.

“These weather events impact not only generation availability and deliverability but also loads,” Robb said. That is the “triple whammy” of not knowing what loads are being served, not having the infrastructure to deliver it and not knowing whether the generation “is going to show up.”

“There’s going to be a new set of tools needed because I think we’ve tortured the ones we used for our grandfather’s electric systems about as far as they can go into the new world,” Robb said.

Bill Magness, the former CEO of ERCOT who was fired in the wake of the storm, said it led to the largest controlled load shed in U.S. history, but “we did keep the system under control.”

“While we had horrendous impacts on human life, on the economy … we were able to hold on to the system, not go into a blackout and come out of it with the system intact,” Magness said.

A big issue, according to Magness, was the freezing up of generation units.

“It was an extreme weather event, but being prepared for those worst cases is critical,” Magness said. “You can have the fuel, but if you don’t have the ability to run the plant, you’re not going anywhere.”

Henderson Remembered

During opening remarks, ISO-NE Director Vickie VanZandt paid tribute to Mike Henderson, the RTO’s former director of regional planning who died May 22, a little more than a year after his retirement. The meeting was dedicated to Henderson.

Much of Henderson’s tenure at ISO-NE focused on the creation and evolution of the RSP.

“Mike was at the heart of the regional and interregional planning process in New England from the late ’90s until his retirement last year,” VanZandt said. “From the first through RSP 19, Mike’s fingerprints were all over each of these reports.”

The RSP process, according to VanZandt, has been recognized by FERC as an example of how a regional planning process should be performed, which was a testament to Henderson’s passion for the project and his work overall, she said.

October 7, 2021June 14, 2023

Study Suggests Texas LSEs Can Provide Reliability

NRG Energy (NYSE:NRG) and Exelon (NASDAQ:EXC) have funded a white paper that proposes an answer to the ERCOT energy-only market’s reliable electricity supply problems by “leverag[ing] the highly competitive retail market.”

The Load Serving Entity Reliability Obligation would directly address resource adequacy concerns by introducing a formal reliability standard and a mechanism to ensure sufficient resources meet this standard. The paper’s authors say the proposal would preserve the market’s competitive and customer choice elements while ensuring there are enough resources able to perform during reliability events.

Written by consulting firm Energy and Environmental Economics (E3) with the help of R Street Institute senior fellow Beth Garza, ERCOT’s former market monitor, the suggested market design is one of dozens of proposals and recommendations supplied to the Public Utility Commission as it works to address flaws laid bare during the February winter storm in its blueprint for a redesigned market (52373).

Beth Garza, R Street Institute | © RTO Insider LLC
“This discussion was coming whether we wanted to have it or not,” Beth Garza told RTO Insider. “It’s time for an examination of what we want from the ERCOT energy market. As always, it takes a crisis to force that decision.”

“It offers the best pathway I’ve seen on electric reliability in the state of Texas,” tweeted former Montana regulator Travis Kavulla, now NRG’s vice president of regulatory affairs. “We’re at a seminal moment where Texas decides either to have a centralized or [government]-led procurement for reliability — or where the hard work of reliability is done by the decentralized, competitive retail market that’s flourished in the state.”

Under E3’s proposal, the PUC would determine a formal system reliability standard, such as one day in 10 years, and ERCOT would calculate the required seasonal reserve margin to meet the standard.

The grid operator would then accredit each resource’s reliability value for each season. Intermittent resources and others with dispatch limitations would be accredited according to their expected performance during reliability events. ERCOT would then give a three-year forward assessment of whether it has sufficient accredited resources to satisfy the seasonal reserve margin necessary to meet the reliability standard.

That would trigger the PUC’s LSE Reliability Obligation, with each load-serving entity — retail electric providers, cooperatives and municipalities — assigned a seasonal reliability requirement based on its projected firm load during critical system hours. LSEs serving interruptible loads would receive a reduced reliability requirement. Any LSEs unable to reach their seasonal requirement on a year-ahead forward basis would be assessed a penalty that the grid operator could use to procure accredited resources and correct the deficiency.

Resources accredited with a reliability value and obligated as part of an LSE’s portfolio would be required to offer into the energy market during designated reliability events, with penalties assessed for nonperformance.

“We had to offer enough specificity so that people had a working understanding of what this proposal looks like, but to be careful of not being too prescriptive of what’s being defined,” Garza said. “The ERCOT energy-only market does a lot of things really well. What it doesn’t do, and never will, is provide any certainty for installed capacity. It incents and hopes people will react and respond.”

Garza, who was brought in by NRG and Exelon to provide an independent analysis of ERCOT’s market design and to recommend “practical reforms,” said the paper leans on proposals from the Australian and Albertan markets, the only two similar to the Texas grid. Those markets have also been the subject of restructuring discussions and legislation intended to ensure resource adequacy, the report says.

To reach greater certainty in resource adequacy, Garza said, ERCOT first needs to specify quantities, how they will be measured and who is going to provide the capacity.

“If you need requirements, the best place to put those is on the LSEs,” she said. “We’re acknowledging the competitive retail world here. We will allow those retailers to figure out how to make those obligations in a way that suits the customers’ needs and expectations. That’s what makes this mechanism much more practically attractive than a centrally dispatched market.”

The LSE Reliability Obligation differs from a capacity market in that instead of one entity buying capacity on behalf of everyone else and spreading the costs to them, Garza said, LSEs will “go out and figure out the best way to do that.”

“We would describe [the proposal] as a really good idea,” she said. “It’s not a good idea [that] you can snap your fingers and it’s implemented. Significant processes and mechanisms have to be developed and defined. There are some market power issues that have to be addressed. The PUC has to make those decisions.”

The PUC will review the various recommendations to modify the market and prevent a repeat of February’s near collapse. Several workshops will be held before the final blueprint is released in December.

October 7, 2021November 13, 2023

Massachusetts Legislators Call on DPU to Reconsider Gas Plan

A group of Massachusetts legislators on Monday called on Department of Public Utilities (DPU) Chair Matthew Nelson to revisit the state’s near-term approach to natural gas.

The DPU’s current approach, set out in an October 2020 order, could result in customers paying for stranded assets, including repairs to pipelines, Sen. Cynthia Creem (D) said during a legislative hearing on grid modernization and the future of gas.

“Things are different now,” Creem said, referring to the passage of the state’s comprehensive climate law, signed in March. (See Mass. Governor Signs NextGen Climate Bill.) The legislation authorizes the Secretary of Energy and Environmental Affairs to establish emissions limits for sectors of the state’s economy, including natural gas distribution and service.

“We see problems with natural gas that we didn’t see before,” she said.

The DPU’s order (D.P.U. 20-80) opened a proceeding on the role of natural gas in reaching net-zero emissions by 2050, noting that meeting the goal “may require [local distribution companies] to make significant changes to their planning processes and business models.”

It required LDCs to hire independent consultants to produce reports identifying decarbonization strategies by March 1, 2022.

Nelson said during the hearing that the DPU will use the reports to develop a roadmap to “guide the evolution of the gas distribution industry in alignment with the commonwealth’s climate goals.”

In the meantime, gas utilities in the state are continuing to replace aging pipelines.

But lawmakers are pushing for the DPU to start phasing out natural gas sooner as the state aims to electrify home heating systems to decarbonize buildings. The billions of dollars being spent to replace pipelines could be redirected to energy efficiency or decarbonization programs, Sen. Michael Barrett (D) said during the hearing.

“You could be more proactive at an earlier time, and my hope is you will reconsider that sooner than six months from now,” Creem said during Monday’s session.

Lowering Emissions from Leaking Pipelines

Nelson defended the timeline, saying it is “critical utility companies have a comprehensive plan that is transparent for stakeholders to pick apart.”

The DPU will continue spending money to fix leaking pipelines, Nelson said, noting that although the new climate law makes reducing GHG emissions a primary goal of the DPU, the agency also remains responsible for ensuring safety and reliability.

“The more we can do to reduce emissions, the better,” he said.

A large part of the methane released into the atmosphere is from aging natural gas pipelines. Massachusetts gas companies reported 32,877 leaks in 2018, according to a report from the DPU.

The DPU is also investigating how existing natural gas infrastructure can be used to transport potentially low-carbon alternatives, such as biogas, green hydrogen or geothermal energy.

But these alternatives are not “clean, renewable resources,” depending on how they are produced, Barrett said.

Biogas is typically about two-thirds methane, according to the Environmental Defense Fund.

“Reductions in emissions are happening when replacing existing pipelines with plastic pipes,” Nelson said. As far as their future uses, Nelson said the agency will “see where the research points.”

October 7, 2021December 5, 2023

FERC OKs MISO Hybrid Resource Accreditation Plan

FERC on Tuesday approved MISO’s two-part plan to accredit hybrid resources for participation in capacity auctions.

The commission said MISO’s plan “sufficiently captures the critical characteristics of hybrid resources” (ER21-2620). The ISO considers hybrid resources as renewable generation and energy storage joining the grid at the same interconnection point.

The accreditation will be handled in two parts because MISO currently lacks the operational data it uses to base accreditations on. The grid operator will first rely on the combined value of its existing unforced capacity values for each element of the hybrid resource, up to the resource’s limit of interconnection service. When staff collects enough operational data, the unforced capacity will be determined “based on historical performance, availability and type and volume of interconnection service.”

MISO will collect from hybrid resource owners their top eight daily peak hours per season’s operating history. It said owners must operate their resources as an integrated whole and under one dispatch. Owners of combined resources that intend to dispatch them individually must register the units as co-located resources, not hybrid resources, MISO said.

FERC said the accreditation “identifies and establishes a reasonable accreditation methodology for a unique resource type with distinct operational characteristics.”

“This framework is consistent with how MISO currently initially determines capacity accreditation for wind and solar resources with insufficient operational data and then subsequently bases capacity accreditation on historical performance, availability, and type and volume of interconnection service,” the commission wrote.

To date, only a handful of hybrid projects have successfully connected to the MISO system from the interconnection queue. MISO said this summer that it has 30 hybrid projects and 2.1 GW worth of capacity wending their way through the queue. Most of the projects marry solar and battery storage, the grid operator said.

The RTO’s queue numbers likely underrepresent the number of hybrids that will eventually materialize in the footprint. Staff has said interconnection customers sometimes request two separate applications for the storage and generation components and others request surplus interconnection capability for storage that’s added later. (See MISO Prepares Hybrid Participation Model for Unknown Numbers.)

In public meetings, some MISO stakeholders have said most solar generation built today either has some storage connected to it or contains later plans for storage additions.

Great Plains Institute (GPI) and Clean Grid Alliance have said the RTO should move more quickly to make its markets friendlier to hybrid resources.

GPI conducted an informal survey among 21 member developers of Clean Grid Alliance, finding that many plan to bring hybrid resources online in MISO over the next three years. The Institute said 90% of survey respondents said they were actively pursuing some kind of hybrid project, with 75% expecting to bring a hybrid resource online within three years.

“…[G]rowing interest indicates that we are likely entering a phase of accelerated deployment,” GPI said.

October 7, 2021December 5, 2023

Palo Verde Hydrogen Demo Gets $20M from DOE

The U.S. Department of Energy will provide $20 million in funding for a demonstration project that will produce green hydrogen using power from the Palo Verde nuclear plant in Arizona.

The project is part of DOE’s “Hydrogen Shot” initiative to reduce the cost of green hydrogen to $1/kg by the end of the decade. Current DOE estimates put the cost for the fuel around $5/kg. (See Hydrogen: ‘Holy Grail’ of Rabbit Hole?)

“Developing and deploying clean hydrogen can be a crucial part of the path to achieving a net-zero-carbon future and combatting climate change,” Deputy Energy Secretary David Turk said Tuesday in a statement announcing the project. “Using nuclear power to create hydrogen energy is an illustration of DOE’s commitment to funding a full range of innovative pathways to create affordable, clean hydrogen, to meet DOE’s Hydrogen Shot goal, and to advance our transition to a carbon-free future.”

The project will produce 6 tons of stored hydrogen capable of generating 200 MWh of electricity or being used to make chemicals and other fuels.

Led by PNW Hydrogen, the project will receive $12 million from DOE’s Hydrogen and Fuel Cell Technologies Office and $8 million from the department’s Office of Nuclear Energy (ONE).

PNW is a subsidiary of Pinnacle West Capital (NYSE:PNW), parent of Arizona Public Service, part owner and operator of the Palo Verde Generating Station. In a quarterly report filed with the Securities and Exchange Commission in August, Pinnacle West explained that ONE’s participation aims to improve the long-term competitiveness of the nuclear power industry through the production of hydrogen.

“The project will provide insights about integrating nuclear energy with hydrogen production technologies and inform future clean hydrogen production deployments at scale,” DOE said Thursday.

With a capacity of 3,990 MW, Palo Verde is the largest nuclear plant in the U.S. Because of its location in the desert 50 miles west of Phoenix, far from any major body of water, the facility relies solely on wastewater to cool its reactors.

“Arizona continues to lead the nation in clean hydrogen energy innovation, and today’s Department of Energy investment will help fuel continued progress,” U.S. Sen. Kyrsten Sinema (D-Ariz.) said. “I am committed to supporting state-of-the-art investments to secure our energy future, including by passing the bipartisan Infrastructure Investment and Jobs Act, which provides $9.5 billion for national clean hydrogen hubs, hydrogen manufacturing and recycling programs, and programs to lower the cost of clean hydrogen.”

PNW’s partners in the project include Idaho National Laboratory, National Energy Technology Laboratory, National Renewable Energy Laboratory, OxEon, Electric Power Research Institute, Arizona State University, University of California Irvine, Siemens, Xcel Energy, Energy Harbor and the Los Angeles Department of Water and Power (LADWP).

LADWP plans to convert its jointly owned 1,900-MW coal-fired Intermountain Power Plant in Delta, Utah, into a natural gas-fired facility that will eventually be equipped to burn green hydrogen to generate electricity. The utility plans to produce and store the hydrogen on site.