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September 7, 2022December 13, 2023

ERO Supports FERC Weather Assessment Proposal

With the 2022 hurricane season in progress and the winter months approaching, NERC and the regional entities signaled their support last week for FERC’s proposal requiring transmission providers to outline plans for assessing the vulnerability of their systems to extreme weather and mitigate any identified risks (RM22-16, AD21-13).

FERC introduced its proposal in June as one of two Notices of Proposed Rulemaking inspired by a technical conference the commission held last year on the impact of climate change and severe weather on the electric grid. (See FERC Approves Extreme Weather Assessment NOPRs.) Commission staff introducing the measure said it was intended to fill a gap in bulk power system awareness, created by the fact that conducting extreme weather vulnerability assessments is currently voluntary and not all BPS stakeholders do so.

The proposal would require transmission providers to submit a one-time assessment to FERC detailing how they:

establish the scope of their vulnerability assessments;
develop inputs;
identify vulnerabilities and determine exposure to extreme weather hazards;
estimate the cost of weather impacts; and
develop mitigation measures to address extreme weather risks.

The NOPR does not apply to utilities that already conduct their own assessments, and transmission providers that do not will only be required to do so once.

Assessments Offer Reliability Benefits

In their joint response filed last week in support of the NOPR, NERC and the REs reminded the commission that “extreme weather events, particularly extreme heat and cold conditions, have threatened the reliability of the electric grid multiple times over the past decade.” Moreover, the ERO noted that the grid is becoming “more vulnerable to the effects of extreme weather” as it transitions to weather-dependent sources of generation.

In addition to considering FERC’s own obligations under the Federal Power Act — as noted in the NOPR — NERC and the REs also suggested that the commission take the ERO’s needs into account in its final rulemaking, particularly in light of the potential benefits to NERC’s reliability standard projects and other reliability-related efforts.

“The ERO Enterprise … agrees that the proposed informational filings would increase transparency into current or planned entity planning practices and facilitate enhanced information sharing and coordination, the benefits of which may extend into enhanced system reliability,” the filing said. The authors requested that any information from utilities’ informational filings that the commission deems too sensitive to be released publicly be shared with the ERO on a confidential basis to help its mission of ensuring BPS reliability.

Industry Feedback More Nuanced

Feedback from other stakeholders was generally supportive, though the responses also contained further suggestions for refinements to the NOPR. For example, Xcel Energy questioned whether FERC’s proposed definition of extreme weather vulnerability assessments is needlessly specific and may rule out many potentially useful reviews.

“The current definition … may omit a significant number of evaluations that, while not couched in the language used in the definition, address specific aspects of the impacts of extreme weather on system operations,” Xcel said, noting that many utilities conduct “myriad types of studies” on current conditions and performance challenges and that, depending on a utility’s circumstances, these could touch on severe heat and cold conditions as a matter of course.

“Without clarifying what this means, exactly, the commission is likely to end up [with] a truncated view of the efforts undertaken to ensure the system can withstand an array of extreme weather events,” Xcel continued, asking that FERC be “very prescriptive in identifying the types of studies it is interested in [in order to] protect entities from inadvertently failing to report or under reporting and, conversely, avoid unnecessarily expanding the record with studies of little or no interest to the commission.”

The Edison Electric Institute also registered some misgivings about the commission’s proposal, despite expressing support for the idea of one-time extreme weather assessments. EEI praised FERC for not requiring assessments from entities that already do so, and for not mandating any changes to how utilities perform their assessments. It urged the commission’s final rulemaking to maintain the NOPR’s recognition that different stakeholders face a range of challenges, and to give utilities a high degree of flexibility in how they follow the requirements.

EEI’s doubts about the NOPR centered on the commission’s plans for the information in the one-time reports, noting that while FERC said the reports “will enhance the commission’s understanding” about transmission providers’ risk assessment, the proposal “does not detail how [FERC] plans to utilize the information included in the reports to accomplish these ends.” The institute said the reports “should serve as an informational tool” and “as the basis for further information sharing and coordination” among transmission providers.

Finally, EEI said FERC should allow utilities more time to prepare their reports than the 90 days following the publication of a final rule, as the NOPR proposed. The institute said in light of the time needed to gather the required information and to vet it for public release, FERC should allow at least 120 days for utilities to respond. Further, EEI said that FERC should not seek public comment on the informational reports as planned in the NOPR. The group called this idea “a departure from precedent” that would punish entities for complying.

“Informational reporting, including the one-time report proposed in the NOPR, is inappropriate for public comment because it threatens to turn good-faith and impartial information sharing into a de facto adversarial proceeding in which entities are compelled to defend themselves,” EEI said. “For this reason, the Commission should not move forward with its proposal to require a post-report public comment period.”

September 7, 2022

Growing Pains Continue for Maryland Community Solar Pilot

Maryland’s community solar pilot program continues to face challenges as it seeks to scale up.

As of mid-June, subscriber organizations had applied for authorization to build 711.5 MW of solar generation. But five years into the seven-year pilot, the state has brought only 43 projects totaling 59 MW of capacity online, one-tenth of the 600 MW allowed.

The Maryland Public Service Commission (PSC) summarized the pilot’s status in a recent report to the state legislature, saying community solar has potential and deserves more resources despite its slow growth.

The problems are not unique to Maryland. About 40 states operated community solar programs as of the end of 2021, led by Florida at 1,636 MW, with all but nine states totaling less than 100 MW. In New Jersey, just 17 of 150 approved projects have been installed, with a combined capacity of 35.6 MW, or about 15% of the total capacity awarded. (See NJ Celebrates Completion of First Phase 2 Community Solar Project.)

What accounts for the anemic actual capacity despite the intense interest?

“The pilot has attracted significant development interest and continues to grow in the number of projects and capacity, but the commission acknowledges that local solar policies and permitting processes have impacted [community solar] development,” PSC Communications Director Tori Leonard said. “Siting projects can be challenging due to local policies and a lack of additional financial mechanisms to build projects on preferred sites such as brownfields and rooftops.”

Subscriber organizations surveyed by the PSC said they were hampered by local zoning, supply chain problems, staffing issues related to the COVID-19 pandemic and challenges related to utility interconnections.

“While community solar has experienced strong growth in recent years, including in Maryland where installations have tripled since the start of 2020, land use obstacles remain the greatest barrier to further community solar deployment,” Scott Elias, director of Mid-Atlantic state affairs for the Solar Energy Industries Association, told NetZero Insider.

“There is well-organized opposition to solar development on agricultural land at the county level, which means the ability to site solar projects varies widely from jurisdiction to jurisdiction,” he explained. “Siting of ground-based projects is a significant limitation to program implementation, and the added cost and limited incentives for sites on parking lots, brownfields and commercial rooftops for community solar have limited their utilization.”

Potential Unfulfilled

About 97% percent of the energy in Maryland’s pilot has been subscribed to residential subscribers who have seen discounts of five to 10% below retail rates.

In addition to rate savings, the pilot projects could contribute to the renewable energy portfolio standard (RPS) capacity required for photovoltaic solar. Maryland currently has about 1,550 MW of solar, about a quarter of the 6,200 MW needed to meet its RPS requirements in 2030.

The PSC said community solar also can provide system benefits by deferring distribution capacity investments. “However, in order to realize these benefits, there must be some certainty that a DER [distributed energy resource] will be available and producing energy at the interconnected circuit’s peak in order for its capacity to be used in distribution planning,” it said.

The PSC said the muted response had made it difficult to draw conclusions on community solar’s costs and benefits.
“The limited number of operating projects hampers the ability to draw conclusions in areas such as energy market impacts, transmission benefits, impacts to the price of locational marginal pricing energy, and impacts to the standard offer service,” it said.

Projects in Operation

Among the companies trying to make the pilot a success is Summit Ridge Energy, which is developing 90 MWdc in Maryland, enough to power 12,500 homes and businesses. The company says it is the largest owner-operator of community solar assets in the U.S.

Denver-based TurningPoint Energy says it is the leading greenfield developer in the Maryland pilot and will have 40 MWdc of projects in operation in the state by the end of 2023.

On April 30, Summit Ridge and Cedar Ridge Community Church held a ribbon-cutting ceremony to celebrate the completion of a 2.5-MWdc community solar project in Montgomery County. The church signed a 25-year lease on eight acres of its 30-acre property with TurningPoint. At least 30% of the electricity generated by the project must go to low-and-moderate income (LMI) households, Franny Yuhas, director of development for the Mid-Atlantic region at TurningPoint, said in an interview.

On April 21, WeSolar and the University of Maryland Medical System announced a partnership to develop a solar farm in Baltimore City to provide power to the hospital’s facilities and city residents. Michael Schwartzberg, a spokesperson for UMMS, said in an email that the location for the project is yet to be determined.

“Our company’s mission is about equity,” WeSolar CEO Kristal Hansley said in a statement. “Our main goal is to reduce the bills of low-to-moderate-income customers by at least 25%.” WeSolar touts itself as “the nation’s first community solar provider headed by a Black woman CEO,” and says it helped with more than 100 MW in customer acquisition contracts in the Northeast.

The partnership calls for UMMS to pay $10,000 monthly for up to 18 months to help with construction of the solar farm, which is projected to generate 8 MW. UMMS has committed to purchasing up to half of the output. Once the farm is operating, UMMS employees who earn less than $67,000 will be able to buy solar energy for their residences from the BG&E grid at a discount of up to 25%.

Program Extended

Maryland’s community solar program started in 2017. It was originally supposed to run for three years, but in 2019 that was extended to seven years, and it is now set to run until 2024. (See Maryland PSC Seeks to Expand State’s Community Solar Pilot.)

The program could receive a boost from Maryland’s Climate Solutions Now Act of 2022, which provides tax exemptions for community solar projects. New projects are exempt from paying county or municipal property tax as long as they provide at least 50% of their electrical output to LMI customers at rates that are at least 20% lower than the rates charged by the local electric utility company, and are located on a rooftop, parking facility canopy or brownfield, said Susan Casey, a spokesperson for the Maryland Department of the Environment.

The PSC says that when the pilot ends, there should be “a full benefit-cost analysis … in a similar manner to other state programs, such as EmPOWER Maryland,” the state’s energy efficiency program. When the General Assembly is considering future legislation, the commission says, it should seek to maximize LMI consumers’ participation and benefits; coordinate potential projects with electric utilities; and pair projects with energy storage. Better coordination with utilities and the addition of storage could “increase both grid and market benefits,” the report says.

The PSC also says the legislature should investigate local planning and development requirements and seek more funding to lower ratepayers’ costs and locate projects in preferred locations like brownfields and rooftops.

The PSC submitted the report July 1 to the Senate Finance Committee and the House Economic Matters Committee, with public comments due by Aug. 22. The commission will now consider further steps, Leonard said. Linda Forsyth, chief of staff to Senate Finance Committee Chair Delores Kelley (D), said that the committee “won’t be holding any hearings or briefings regarding this issue in 2022.” With Kelley retiring at the end of her term in January 2023, further action will happen only after the Senate president replaces her, Forsyth said. C.T. Wilson, chair of the House Economic Matters Committee, did not respond to a request for comment.

September 7, 2022June 14, 2023

Texas Gov. Abbott Touts ERCOT’s Fall Resource Adequacy

ERCOT quietly dropped its latest seasonal assessment of resource adequacy on Tuesday, saying it has sufficient installed generating capacity to meet peak demand under normal system conditions this fall.

Had it not been for a press release from Gov. Greg Abbott’s office, the report might have gone unnoticed for days.

Abbott, a Republican who is seeking a third term, has been hammered by his Democratic opponent, Beto O’Rourke, over the ERCOT grid’s near collapse during the February 2021 winter storm and the slow pace of the market reforms.

With Abbott providing a heavy hand, the grid operator’s public communications have shriveled since the storm. ERCOT has not posted a public notice about the seasonal assessment (SARA) since May 2021. The media updates that accompanied the SARA were discontinued after the storm, although ERCOT’s interim CEO and its top regulator have twice appeared for short Q&A sessions.

But Abbott was quick to issue a release Tuesday and tweet an image of himself sitting at the same table with outgoing interim ERCOT CEO Brad Jones, incoming CEO Pablo Vegas, Public Utility Commission Chair Peter Lake and several others. Vegas will replace Jones on Oct. 1. (See ERCOT Names NiSource’s Vegas as New CEO.)

“Met with ERCOT and PUC to discuss the strong position of Texas’ electric grid heading into the fall season,” Abbott posted. “Our grid is stronger and more reliable because of bipartisan reforms we passed and began implementing last year.”

In the release linked from the tweet, Abbott said the state is continuing to monitor the grid’s reliability. It notes he discussed the grid operator’s updated planned outage scheduling process that “ensures Texas’ generational fleet has the necessary time to conduct maintenance operations.”

The shoulder season’s traditional maintenance period couldn’t come soon enough for thermal generators that have been running full bore this summer as part of ERCOT’s conservative operations posture. The grid operator has regularly kept more than 3 GW of operating reserves on the sidelines and dispatched older peaking units as reliability unit commitments.

Scott Bruns, Enverus | Enverus

Scott Bruns, director of markets for energy analytics firm Enverus, likened the situation to having a classic car in the garage.

“These units are typically older units that are not typically run or only run during the summertime when you need to support the system. And this summer, we ran these units much longer than previous years,” Bruns said during a webinar Wednesday on ERCOT’s summer performance. “I like to think of it as like your classic Camaro that you have for cruising. It runs well, but it has a limited number of miles left on that odometer and every time that you drive it, it’s more maintenance or repairs, and it just becomes more expensive.”

And not only expensive for the generation operators, but risky for the ERCOT system.

“So now, what we’re doing is we’re asking these Camaros to spend all the time in the driveway sitting there and idling, when you know that this is just increasing the risk on the system,” Bruns said. “We’re moving to this new future where more intermittent renewables are pulling onto the system and we’re asking all of these classic cars that are sitting out along the system to provide more of these baseload reliability services. And eventually, we’re going to have some issues.”

ERCOT staff does not appear to think that will be a problem. The fall SARA, covering October and November, indicates the system will have over 93 GW of resource capacity available during peak demand hours, more than enough to meet a projected high of 64.9 GW.

The grid operator expects to have 2.6 GW operational battery storage resources. However, they are not currently included in ERCOT’s capacity contribution for fall because they are not expected to provide sustained capacity for meeting system peak loads.

The report includes six risk scenarios that reflect alternative assumptions for peak demand, unplanned thermal outages and renewable output. One of the three elevated risk scenarios (low renewable output) and the most severe extreme risk scenario (high peak load, high unplanned thermal outages, extreme low wind output) would result in rotating outages.

September 7, 2022

Clean Energy Groups Don’t Buy ISO-NE’s Gas Reliance

Environmental and clean energy advocates are pushing New England to get off the gas.

In a new white paper and at a press briefing, several regional and national environmental groups challenged the approach taken by grid operator ISO-NE as industry stakeholders head into a high-profile policy forum in Vermont this week.

The groups, which include the Sierra Club, Conservation Law Foundation, Acadia Center and others, say that New England needs to quickly pivot to clean energy, and avoid throwing “good money after bad” by investing more in fossil fuel infrastructure.

The document lays out several clean grid reliability solutions that can be pushed to the front in the short term, including expanding residential demand programs, ramping up commercial and industrial demand response, and boosting energy efficiency.

And it calls on the region to, in the long term, better utilize the existing fleet of renewables, deploy “stacked” battery storage, and make “smart expansions” to the region’s transmission system.

Amid increasingly frequent warnings about the reliability of the region’s grid in winter, New England has clean options, the groups conclude.

“New England’s leaders, with the support of federal agencies like FERC, should be accelerating efforts to deploy alternatives to gas generation that take advantage of the region’s abundant clean energy resources,” the white paper says.

The policy paper was a response to a recent statement put out by ISO-NE, in which the grid operator took a different view.

In its “problem statement” ahead of the FERC forum in Vermont, ISO-NE emphasized that even though the region is moving toward a decarbonized grid in the long-run, natural gas remains a vital generating fuel in the near term. (See ISO-NE: Reliability Still Depends on Mass. LNG Import Terminal)

“Without adequate gas, the region may not be able to meet the demand for home heating and electricity — and, when reliability suffers, the clean energy transition suffers,” the grid operator wrote.

Though all involved agree that New England is moving toward weaning itself off gas in the long run, the grid operator’s message rankled some of its most frequent critics in the environmental and clean energy sectors, who blame ISO-NE for the region’s current reliability travails.

“For years we’ve been presented by the ISO with programs and policies that did not solve any of the perceived winter reliability challenges,” said Phelps Turner, senior attorney at the Conservation Law Foundation, at a press briefing Tuesday.

“It’s our view that if we had spent that time working on the clean energy transition, rather than constant annual fear-mongering, we would be in a much better spot today,” Turner said.

It’s a recurring message from environmental advocates, who feel that ISO-NE has moved far too slowly in following the directives of the New England states to shift to clean energy.

In that vein, the problem statement followed a familiar pattern, said Melissa Birchard, director of clean energy and grid transition at the Acadia Center: It led with identifying clean energy for the region’s long-term needs but then switched to a focus on fossil fuels in the short-term.

“We need to get off this merry-go-round,” Birchard said. “We can’t keep going through this every year and having these incredible costs that consumers are experiencing.”

Managing expectations for Thursday

The all-day forum scheduled by FERC for Thursday in Burlington, Vt., isn’t expected to produce consensus.

“They’re going to be discussing challenges and not solutions. What are the problems and how do we fix them?” said Mireille Bejjani, an organizer on the Fix the Grid campaign.

But getting a wide variety of speakers and guests in the same room could be a start to more productive conversations about how to move forward, said Caitlin Marquis, director of Advanced Energy Economy.

“We want to see a clear and transparent discussion about what the reliability risks are that we’re facing, specifically,” Marquis said. “What is the time frame of those risks? What are the grid’s needs that we need to be defining?”

In the natural gas sector, there are different hopes for the meeting.

A group of associations representing gas and oil generators and pipeline owners called on New England to build more pipelines and tweak market rules to give generators more certainty.

“We hope this forum will provide an avenue to discuss market design improvements and to develop sufficient natural gas infrastructure for power customers in addition to the manufacturers, businesses, and households that rely on natural gas to power their everyday needs,” the groups said in a statement.

September 7, 2022June 14, 2023

PJM Planning Committee Briefs: Sept. 6, 2022

Planning Committee Reviews Capital Budget

The Planning Committee reviewed a $45 million capital budget proposal during its Tuesday meeting, a potential $3 million increase over current funding.

Nearly half of the suggested budget goes toward current applications and systems reliability, with $22 million allocated toward items such as dispatch tool enhancements, data analytics and cybersecurity. Spending on facilities and technology infrastructure would also increase to $12 million.

Less spending is being requested for application replacements and retrofits, which would reduce by a fifth down to $8 million, while new products and services as well as interregional coordination would remain static.

The spending plan will be reviewed by the Market Implementation Committee and Operating Committee this week and will be considered by the Finance Committee on Sept. 22 and 28. The Finance Committee will draft a recommendation letter to the PJM Board of Managers, which will consider approving the budget on Oct. 4.

Reserve Requirement Study Recommends Increasing FPR and IMR

The PC also received a presentation of the 2022 Reserve Requirement Study results, which recommends increasing both the forecast pool requirement (FPR) and installed reserve margin (IRM) compared to the 2021 study results. This year’s study results recommend an IRM of 14.9% for the 2023/24 delivery year, rather than the 14.8% favored in last year’s study for that year, and a FPR of 1.0930 next year, as opposed to 1.0901 recommended in the 2021 study.

The recommended IRM would fall to 14.8% in 2024/25 and continue down to 14.7% for the following two years. The FPR would decline to 1.0926 in 2024/25 and would sit at 1.0918 for the next two years.

2022 forecast pool requirement (FPR) waterfall chart | PJM

The study also proposed winter weekly reserve targets for the upcoming season, recommending 21% maximum monthly available reserves for December, 27% for January and 23% for February. The WWRT was set using RTO-aggregate outage data from the 2007/08 delivery year through last year.

The PC will take another look at the study in October, when it is scheduled to vote on the FPR, IRM and WWRT. From there, the Operating Committee is slated to vote on the WWRT in November, and the FPR and IRM are set to be voted on by the Markets and Reliability Committee and Members Committee in October through November. The PJM Board will consider final approval in December. The study’s assumptions were endorsed by the PC in June, and its load model selection was endorsed in August.

Tx Refunds Could Date Back to 2014

PJM could be required to refund transmission cost allocations dating to 2014 as a result of an appellate court ruling last month that remanded FERC decisions on two North Jersey transmission projects, PJM attorney Pauline Foley told stakeholders.

The D.C. Circuit Court of Appeals said FERC failed to explain why the solution-based distribution-factor analysis (DFAX) method should be used to assign the costs of two North Jersey transmission projects but not for a similar project in Artificial Island, partially supporting appeals by two merchant transmission operators. (See DC Circuit Faults FERC on Cost Allocation of NJ Transmission Projects.)

The case involves $1.3 billion in transmission upgrades authorized by PJM to address short-circuit problems between Public Service Electric and Gas’s Bergen and Linden switching stations and repairs to and around the utility’s Sewaren substation.

If FERC decides not to try to justify its distinction between the projects “we do not have a cost allocation to replace solution based DFAX for the Bergen-Linden and Sewaren projects,” said Foley, who noted the RTO has approved the allocations for the projects in late 2013 and early 2014. “Depending on what FERC determines, refunds could date back as far as 2014,” she said.

Annual Pre-qualification Window Opens for Competitive Planning Process

The annual one-month pre-qualification window for transmission developers seeking to submit projects under the competitive planning process has opened. Applications to qualify as designated entities can be submitted between Sept. 1 through Sept. 30 at ProposalWindow-Prequal@pjm.com.

To remain qualified, participants are required to confirm or update their pre-qualification information at least every three years. The Competitive Planner Tool now contains a new Pre-qualification Submission feature allowing form-based submissions and the ability to attach public or confidential versions of documents.

September 7, 2022

Report Updates NY OSW Cable Routing Study

The New York State Energy Research and Development Authority last week issued an update on the potential challenges to routing transmission cables to the fleet of wind turbines planned off the New York coast.

NYSERDA has been working since August 2021 on the Offshore Wind Cable Corridor Constraints Assessment as part of the state’s drive to achieve a carbon-free power grid.

Five OSW projects totaling 4.5 GW are under development in New York; the state’s Climate Leadership and Community Protection Act mandates that 9 GW of OSW generation be in place by 2035.

The assessment is targeted for completion late this year. It seeks to:

document the environmental, technical and stakeholder constraints of potential undersea and overland cable corridors;
document the opportunities, concerns, impacts and risks of these corridors;
inform future policy actions to maximize benefits associated with the new OSW infrastructure;
minimize conflicts and impacts while following a timeline that reaches the 9-gigawatt goal by the 2035 deadline.

In its progress report submitted Sept. 1 to the New York Public Service Commission, NYSERDA said the Cable Working Group, which is performing the assessment, broke New York’s waters into four separate areas, each with different characteristics and potential constraints on installation, operation and maintenance of OSW cables.

Offshore, specific zones and subzones were identified with similar characteristics and constraints. On land, zone boundaries were drawn to optimize existing rights of way used for electric or gas transmission, elevated roadways and passenger rail lines in the densely constructed region.

In the South Shore Approach Area — the Atlantic Ocean south of Long Island — commercial fishing, including bottom trawling, recreational fishing and existing utilities (pipelines, telecommunications and transmission cables) present the most significant challenges to OSW cables, the assessment has determined.

In the Long Island Sound Approach Area — waters north and east of Long Island, from Block Island Sound to the East River — marine geology, commercial and recreational uses, aquatic resources and cultural concerns are flagged. There is, for example, a strong tidal currant, shallow zones, scour, boulder fields, a hard seabed, slopes greater than 10%, sensitive resources such as cold-water coral, shipwrecks and, in the westernmost end, anchorage areas.

In the New York Harbor Approach Area — the Upper and Lower harbors and the Hudson and East rivers — surface traffic is a major concern, with federally designated navigation channels and anchorage areas, heavy commercial shipping and passenger ferry traffic, narrowing waterways and the presence of pleasure craft.

In the Landfall and Overland Area — New York City and Long Island, and the places on both where undersea cables would make landfall and interconnect with the grid — the potential constraints are many and varied. Most prevalent is topography, as slopes exceeding 15% exist in all 25 zones designated on shore. There are potential environmental justice concerns in 23 of the 25 zones. Federal Highway Administration review and authorization would be required to site transmission lines along FHA-funded highways. Fish and wildlife habitats, public beaches, recreational fishing and eelgrass are other potential constraints.

The preferred approach would be to avoid negative impacts from all the potential constraints identified, but the assessment suggests steps to minimize or mitigate those impacts that cannot be avoided.

The assessment recommends that OSW cable routing incorporate accepted siting principles and industry experience but also notes that bringing 9 GW of power from the sea to land will require innovation in design, operation and maintenance that goes beyond standards set by previous projects and addresses the specific considerations for each site in New York.

NYSERDA issued a request for information Aug. 30, seeking feedback on whether the draft assessment accurately captures the most significant potential constraints and opportunities arising from the initiative. The comment period closes Oct. 14.

September 7, 2022

MISO Officially Opens Markets to Storage Resources

MISO successfully opened its wholesale markets to electric storage resources last week in compliance with FERC Order 841, the grid operator said Tuesday.

Effective Sept. 1, storage resources can participate in the RTO’s energy and operating reserves markets as supply or demand. MISO said the resources have the “operational characteristics that support reliability and resilience as the industry continues to transition the resource fleet.”

“We are excited to see this space grow with increasing member interest and participation, particularly as we continue to adapt to the accelerating resource transition,” Jessica Lucas, executive director of system operations, said in a statement. “With the introduction of electric storage resources to our market portfolio, we will continue to position MISO’s grid and its members as the grid of the future.”

Staff has developed a method that implements new storage-specific offer parameters required by FERC in a way that recognizes their unique physical and operational characteristics. The technology earned MISO its first patent last year from the U.S. Patent and Trademark Office.

The RTO said the participation model’s near-term benefits are “modest due to the small volume of storage resources.”

“However, the new model positions MISO ahead of the increased storage participation anticipated with higher penetration of renewables and distributed energy resources over the next five to 10 years,” it said.

MISO debuted the storage participation on its legacy market platform. It had originally requested that it be given until 2025 to fully incorporate storage on its new market platform. However, FERC ordered the grid operator to build the participation models on both of its market platforms. (See MISO: No Choice but to Double Up on 841 Compliance.)

The RTO said that that integrating storage offers into its markets would be better served under its new market platform and argued that being forced to put together two participation models to meet the deadline would stretch its resources.

CEO John Bear wrote to FERC in May to support a deferral, saying a 2022 launch could delay and “severely” compromise MISO’s “efforts to address growing reliability and resilience concerns and meet members’ carbon-reduction goals.”

The RTO reported over the summer that it was testing its new energy-storage participation software. Its electric storage model uses eight commitment statuses, including injecting, withdrawing or toggling between the two. Resources can also designate themselves as emergency injecting, emergency withdrawing, available, not participating or on outage.

September 7, 2022June 14, 2023

Hochul Insurance Investment Helps Shore Up CLCPA Targets

New York Gov. Kathy Hochul

| Darren McGee, Office of Governor

New York Gov. Kathy Hochul on Sept. 1 announced $6.5 million in funding to support research of innovative insurance policies or products that will promote the adoption of clean technologies.

The Insurance Innovation for Climate-Technology Solutions program will target insurance for residential and commercial renewable energy products that will both develop new business models and enable future climate technology solutions and be funded through the state’s 10-year, $5.3 billion Clean Energy Fund, according to the New York State Energy Research and Development Authority (NYSERDA).

A new program administrator will be awarded up to $1.5 million to create the program by working with insurance management experts to develop, fund and test innovative risk models that better address climate change. The remaining $5 million will be used for competitive grants expected to be announced in 2023.

The program will help overcome barriers to bringing new insurance products to the market in the face of increasingly costly extreme weather events. It is another step by the Hochul administration in support of New York’s 2019 climate and energy legislation, the Climate Leadership and Community Protection Act (CLCPA), the sweeping climate and energy initiative that calls for 70% of the state’s electricity to be generated through renewable sources by 2030 (70×30) and 100% through zero-emission means by 2040.

Many businesses have significantly re-evaluated their risk model projections to factor in the potential costs of coverage associated with climate change, especially the natural disasters that seem to be coming with greater frequency and cost. New York estimates that Hurricane Sandy caused $19 billion in damages and lost economic activity in New York City alone.

State Sen. Neil Breslin, an Albany Democrat who chairs the Senate Insurance Committee, said in a news release that the Innovation for Climate-Technology Solutions program “is critical for economic stability” because it will “enable businesses to better manage risk and prepare for the negative impacts climate change may have on them.”

NYISO Climate Vulnerabilities

NYISO recently assessed the impacts that climate change would have on the resilience and reliability of New York’s power grid.

The study found that climate disruptions could significantly reduce resource output during the winter, replacing fossil fuels would make meeting peak electricity demands more difficult, and better planning would make identified vulnerabilities more manageable.

Specifically, NYISO found that utility-scale battery storage would fill many of the reliability gaps created when carbon-fueled power generation is taken offline, which tracks closely with recent findings from Potomac Economics’ “Outlook” review.

Greater transmission capacity also will be needed to maximize renewable energy access, while dispatchable emission-free resources, such as green hydrogen, will be needed to act as load failsafes when intermittent renewable generators are taken offline because of meteorological disruptions.

Application Process

NYSERDA will competitively select a program administrator and is accepting applications from qualified organizations through Oct. 12. Applicants are asked to demonstrate economic benefits, and their proposals will be evaluated by a scoring committee.

Applicants must show how they can promote the research and development needed to bring new insurance products and services to market, including soliciting new insurance ideas, managing the development and growth of the program, and reducing risk for climate technology services.

September 6, 2022June 14, 2023

NERC Warns of Fuel Shortages Going into Winter

NERC has not yet issued its annual Winter Reliability Assessment, but it is already clear that it is concerned about the electric industry’s readiness to withstand severe and unpredictable weather this winter.

“We’re requesting early adoption of some of our cold weather standards,” said John Moura, director of NERC’s reliability assessment and performance analysis, at the start of the ERO’s annual winter preparation webinar on Thursday.

John Moura, NERC | NERC

Moura said that in 2021 the industry experienced 70 hours of unplanned load shedding because grid operators had no other options.

“This is a trend we have seen over the last couple of years: more times where the system is under duress and has to initiate energy alerts [that] has led to operator-initiated load shed,” he said. “This is kind of a trend that we really need to reverse.”

A NERC analysis of outages from 2013 through 2021 shows that all generation types other than nuclear have experienced an increase in forced outages during cold weather, he said. That includes traditional baseload coal and gas plants, said Moura, adding that gas storage is currently at the low end of the five-year average and coal inventories are lower than they should be at some power plants, making them vulnerable to railroad worker strikes or other events that could reduce resupply.

NERC is urging “cross industry engagement” to ensure gas and coal plants do not experience fuel shortages this winter.

“Even if we were to winterize all our units, and we had perfect reliability, we will still have in some places concerns with the availability of fuel and the reliability either of the pipeline system or other energy delivery systems. I think that that only can be fixed … when we work and plan together,” Moura said.

Mark Olson, NERC | NERC

Mark Olson, manager of reliability assessment at NERC, said the organization will soon release a cold weather alert with recommendations for this winter. He added that “coal stockpiles have been at a historic low level.”

Explaining that the goal of Thursday’s webinar was “to help get the ball moving” before NERC publishes its 2022/23 Winter Reliability Assessment in November, Olson acknowledged that the industry is already preparing for winter.

“I know there’s a lot being done, and so we’re not really initiating action here as much as we’re emphasizing and sharing the insights from the past,” he said, acknowledging that NERC is aware that “generators are taking steps and need to continue those steps to be proactive and prepare for the winter.”

Olson also said that “grid operators need to prepare and do drills for cold weather plans and for things like load shedding so that they can be efficient and minimize disruption as much as possible to end users while preserving the reliability of the overall system.”

David Lemmons, Greybeard Compliance Services | NERC

Two areas of special concern are the MISO footprint and Texas, he said.

In MISO, “our preliminary data indicates there’s about 7 GW of coal generation and 1 GW of nuclear generation that has retired from last winter. And that’s led to a declining reserve margin,” he said, which could become a serious problem in an extremely cold winter.

David Lemmons, an independent analyst and co-founder of Greybeard Compliance Services, stressed the importance of detailed information sharing and close cooperation between generators and grid operators, particularly during extraordinary weather events.

Examples North and South

Webinar participants also heard about extreme weather preparations from Canada’s largest electric utility, Hydro-Quebec, and El Paso Electric. Both utilities experienced severe weather-related service disruptions in the past and had to develop practices and technologies that have enabled them to function in extreme weather.

Anne-Marie Fournier, a regulatory affairs expert and reliability coordinator at Hydro-Quebec, said annual reliability assessments that begin in May have helped the company develop strategies to deal with potential weather catastrophes when demand normally peaks.

“A very important part of preparing for winter and improving the way we prepare is by looking back at how we have performed,” she said.

“We learn a lot from past events, and sometimes we learn the hard way,” she said. “That was the case with the 1998 ice storm that hit south of Quebec. We received more than 3 inches of freezing rain spread over five days. That freezing rain was very heavy and made 24,000 utility poles and 900 steel poles collapse.”

Anne-Marie Fournier, Hydro Quebec | NERC

Nearly 1.4 million customers lost power, for up to four weeks in some areas. Montreal was without power for two days, crippling the metro transit system and the water filtration system as well, she said. Then temperatures dropped into a “deep freeze,” she said, leaving most customers without heat because homes and businesses are heated electrically.

The company has since built “anti-cascading” transmission towers to limit the extent of line damage if a tower collapses, built additional lines and installed de-icers on certain lines. Hydro generators are located inside heated buildings with backup auxiliary heating; spillways are heated electrically; and dams are designed to withstand ice formations.

Fournier said the annual spring assessment moves to a load forecast in July and an updated inventory and “formal identification” of all available internal resources in August. Another resource adequacy check, including potential power imports and exports, gets under way in September, as well as the running of several scenarios simulating the coming winter’s projected peak demand.

In October, a planning team validates available interruptible loads and the amount of power available that those customers could provide the company if needed. Final equipment checks and operator training happens in November, she said, before demand begins to surge in early December.

“During the peak period, we have a cross-functional team that meets daily to make sure everything is handled. And this team is constituted of people from the transmission side, the generation side and the distribution side. Our teams of meteorologists and load forecasters are very busy also at wintertime as they sometimes monitor load and weather closely for 24 hours a day, seven days a week,” she said.

Kyle Olson, director of generation and asset management at El Paso Electric, said a major reason the company survived the February 2021 storm is that it did not do well in a major storm 10 years earlier.

That storm knocked out one of the company’s aging power plants, leading to rolling blackouts. The utility turned to Black and Veatch for recommendations on how to improve its performance.

“We invested over $4.5 million in freeze protection upgrades at what were only two local plants at the time. These upgrades included heat tracing insulation and other winterization tools,” he said.

The company also developed hot and cold winterization checklists, procedures and preventative maintenance strategies, and “new design criteria” for construction of new power plants capable of operating at temperatures as low as -10 degrees Fahrenheit and as high as 105 F.

“We also factored in wind and humidity. It tends to be the high wind and the humidity that ends up biting us during the cold events more than just the actual cold temperatures,” Olson added.

In the decade between the two storms, the company replaced its coal generation with gas turbines, the newest of which it plans to run on 30% hydrogen by 2045 through an agreement with turbine maker Mitsubishi Power. The utility is also aiming to build large solar arrays backed up by Mitsubishi gas turbines.

Olson said the company installed freeze-protection equipment for critical controls at its new gas turbines plants. That included the use of “O’Brien Boxes,” protective, often heated, enclosures designed to keep controls, instruments and even tubing warm and operable at low temperatures.

The company has opted to build simple cycle gas turbine plants rather than the more efficient combined cycles, which require water heated by the waste heat of the gas turbines to run secondary steam turbines.

“We are in a desert,” Olson explained, “but also because [simple cycles] perform well during severe winter events,” such as the 2021 storm when temperatures in the region fell to 14 F.

The company’s newest plant has dual-fuel capability, he said, another strategy to make certain the plant can stay online during emergencies.

The company also contracts for more than 600 MW from the Palo Verde nuclear plant in western Arizona. “During the 2021 storm, Palo Verde was essential to meeting our customer loads and avoiding price spiking,” said Olson.

September 6, 2022

4 Arizona Entities Commit to Developing SPP’s Markets+

Four Arizona electricity providers have joined seven Pacific Northwest entities to support the next phase of SPP’s Markets+ development.

SPP announced Tuesday that Arizona Electric Power Cooperative, Arizona Public Service, Salt River Project and Tucson Electric Power said in an Aug. 31 letter that they intended to work with the RTO to build a Western market that includes “both a workable governance framework and a robust market design.”

“This will be an important milestone that will enable us to collectively move forward to the next phase,” the entities said.

Last month, seven entities from the Pacific Northwest offered similar support to SPP, following a commitment from the Bonneville Power Administration. (See SPP’s Markets+ Offering Attracts 6 More Western Entities.)

“Adding the desert southwest region to the development of this market adds more value for all participants, and we very much appreciate the contributions from these entities thus far” SPP CEO Barbara Sugg said in a statement.

The four companies serve more than 20 GW of combined peak demand. The Pacific Northwest group accounts for 50 GW of combined peak demand.

SPP plans to have the Markets+ draft service offerings, based on stakeholder input, available for comment by the end of September; the final service offering is scheduled to be distributed Nov. 18. Participants will make financially binding commitments in the first quarter of 2023, at which point the market protocols and tariff language can be drafted.

Markets+ is a conceptual bundle of services that centralize day-ahead and real-time unit commitment and dispatch, provide hurdle-free transmission service across its footprint and pave the way for the reliable integration of a rapidly growing fleet of renewable generation. It is designed for utilities that aren’t ready to pursue full RTO membership.