FERC Commissioner Allison Clements told the ISO-NE Consumer Liaison Group on Wednesday that the country’s energy sector is facing a “system challenge” from a rapidly changing resource mix that requires intelligent transmission planning and investment as part of the energy transition.
Any system problem needs a system solution, said Clements, who is focusing on ensuring that the commission and states work together “to embrace the full portfolio of solutions to unprecedented and formidable challenges.”
Clements said there is a “once-in-a-generation opportunity” to invest in new transmission that can contribute to cost-effective and reliable facilitation of a changing resource mix. When asked about the uncertainty surrounding the New England Clean Energy Connect (NECEC) transmission line, which would supply hydropower from Hydro-Québec to the New England grid through a 20-year supply agreement with Massachusetts utilities, Clements called it a “clear example” of the challenges related to siting new transmission.
On a subsequent panel, Michael Giaimo, Northeast regional director for American Petroleum Institute, said policymakers should not be so quick to retire existing fossil fuel infrastructure.
“My parents taught me that if you leave a job, make sure you have another job,” Giaimo said. “So, the analogy here is if you want to ensure a reliable power system at a minimum, you shouldn’t retire infrastructure until you are certain.”
Given New England’s policies intended to stimulate solar, wind and electrification, Giaimo said the region needs to have resources in times when renewables aren’t available and to account for the increase in nightly load for electric vehicle charging and residential heating. Additionally, he said, it’s essential to consider that existing gas infrastructure can help facilitate low-carbon fuels, like green hydrogen, in the future.
Dale Bryk, director of state and regional policies at the Harvard Environmental and Energy Law Program, said the region “can’t say ‘no’ to things when we don’t have a plan.”
“But we also can’t use the absence of a plan as a weapon to prevent ever changing anything,” Bryk said. “We have to stop digging the hole and stop investments in fossil fuel infrastructure that we know we have to abandon and build the solutions in a timely way so that we do have a just, equitable and orderly transition.”
“This transition is happening,” Clements said. “It’s not the commission’s job to plan it. It’s the commission’s job to facilitate it and protect customers and contribute to the assurance and reliability while it’s happening. That’s exciting. It’s like we’re the underlying nuts and bolts that are allowing the implementation to take place.”
FERC last week authorized Entergy Louisiana and Entergy New Orleans to assume more than $15 billion in debt and securities to help recover losses incurred from Hurricane Ida’s destruction (ES22-7, ES22-8).
The orders allow Entergy Louisiana to issue up to $13 billion in long-term debt, $450 million in short-term debt and $300 million in preferred securities. Entergy New Orleans can issue up to $1.24 billion in long-term debt, $150 million in short-term debt and $40 million in preferred securities.
FERC said the long-term interest rate cannot exceed 6.775% and the short-term interest cannot exceed 4.5%.
Additionally, the Entergy subsidiaries can also issue $170 million and $25 million in letters of credit to post collateral and secure their participation in MISO’s markets.
Entergy said the late August hurricane inflicted anywhere from $2-$2.4 billion worth of damage to its Louisiana utility arm and $120-$130 million in damages to its New Orleans affiliate. The repair costs caused the utilities to surpass their debt ceilings ahead of their mid-July 2022 conclusion.
Entergy affiliates usually simultaneously file requests with FERC to issue debt, making the out-of-cycle requests unusual.
The new debt authorizations went into effect Dec. 1 and end Oct. 13, 2023.
Entergy reported damage to approximately 500 transmission structures, more than 225 substations, more than 210 transmission lines and nearly 6,000 transformers. Repairs to 30,500 distribution poles and nearly 36,500 spans of distribution wire were also necessary, the company said.
The staggering restoration costs led two commissioners to issue a warning of the increased financial damage related to climate change that ratepayers will bear.
FERC Chair Richard Glick and Commissioner Allison Clements wrote a separate concurrence urging their fellow commissioners to consider transmission investment as a means to hedge increasingly steep repair estimates.
Glick and Clements said while they agreed with Entergy’s need to issue debt and securities, they were writing “to underscore that this is another clear example of the deep costs of climate change and extreme weather, which will ultimately be borne by customers.”
The two pointed out that according to Entergy, the costs inflicted by Hurricane Ida were more than the combined costs of Hurricanes Katrina, Ike, Delta and Zeta.
“Hurricane Ida is just one of 18 climate-related disaster events with losses exceeding $1 billion that has affected the United States this year,” Glick and Clements wrote. “We expect that restoration costs following climate-induced extreme weather events will continue to grow, and for that reason, the commission should consider how prudent investments in transmission system planning can ultimately save customers money.”
MISO has commissioned a study meant to demonstrate that long-range transmission projects built in the Midwest won’t deliver benefits to the South.
The grid operator has tapped The Brattle Group to test its hypothesis that benefits from long-range projects built in either MISO Midwest or MISO South won’t cross its subregional transmission constraint. Brattle is using hypothetical and past projects from MISO’s 2011 Multi-Value Project portfolio to study a systemwide benefit spread.
The RTO plans to include the results in its FERC filing for a separate-but-equal postage stamp cost allocation that splits the system into MISO Midwest and MISO South for cost-recovery purposes. MISO hopes that the allocation will be temporary, and it plans to explore other long-range design options in 2022.
Speaking during a Dec. 3 Regional Expansion Criteria and Benefits Working Group, MISO’s Jeremiah Doner said staff will share the study report with stakeholders when it’s completed.
Some stakeholders asked whether MISO was deliberately creating a seam within its own borders with the first allocation design.
East Texas Electric Cooperative representative Paul Kelly said that some stakeholders already have performed analysis that show high-voltage, long-range transmission can deliver benefits systemwide despite the subregional transfer limit between the Midwest and South.
Stakeholders asked whether MISO would allow retroactive cost recovery in MISO South if Midwestern project benefits are shown to help the South and whether staff will again test for benefit flows once they finally recommend specific projects.
Currently, MISO won’t estimate how much the first group of recommended projects could cost. It has said its first transmission planning scenario shows a need for upwards of $30 billion worth of projects, but those are expected over multiple years.
“I just can’t help but ask … is there a plan in place if that scenario actually does show significant benefits to the South?” said Sam Gomberg of the Union of Concerned Scientists.
MISO’s Aubrey Johnson said if study results show noteworthy benefits flowing to the South, staff would reopen cost-allocation discussions for the first Midwestern projects to emerge from the long-range transmission plan.
Johnson was asked whether MISO would then be unmoored on a singular cost-allocation design and propose allocation that could vary project-to-project or cycle-to-cycle. He said staff will not alter cost-allocation decisions once made but will use what it learns on benefits flowing Midwest to South to inform future allocation designs.
With the Brattle analysis, MISO once again delayed a FERC filing date for cost allocation, pushing it back from mid-December to mid-January. (See MISO Schedules Cost-allocation FERC Filing.)
The RTO’s long-range transmission plan has evolved meeting-to-meeting, with postponements and temporary reductions in scale announced near-monthly.
The grid operator first told stakeholders it would advance an initial subset of projects based on its most conservative 20-year transmission planning scenario with December’s approval of the 2021 MISO Transmission Expansion Plan. It then said it needed until March. Planners now say they won’t have project proposals ready for a board vote until late spring. (See MISO Postpones 1st Cycle of Long-range Projects.)
MISO is not tackling Southern projects until sometime in 2023, leaving MISO South transmission needs out of the study’s first cycle. Louisiana and Mississippi regulators have threatened to leave the grid operator if the first round of long-range projects’ cost allocation extends to their utilities’ ratepayers.
Stakeholders Tee Up 2022 Allocation Design Debate
Looking ahead to next year’s debates on long-range cost allocation, MISO South members and regulators resubmitted for consideration their allocation proposal first presented in the summer.
The plan prescribes costs be directly assigned to project beneficiaries from either increased reliability, economic gains, or attained policy goals. It would have only states with decarbonization goals splitting project costs that further their clean energy aims. (See Tensions Boil over MISO South Attitudes on Long-range Transmission Planning.)
Clean Grid Alliance’s Natalie McIntire said state goals that split transmission project costs are similar to MISO’s current participant-funded project type, where market participants can construct a project so long as it doesn’t harm the system. She said elements of the South proposal already are available as options in the MISO tariff.
Some stakeholders said the South proposal wouldn’t pass at FERC because it proposes different allocation types for a single project class.
MISO’s Environmental Sector countered the South proposal with a design that asks the RTO to incorporate all benefit metrics it has deemed acceptable, including improved public health from less pollutants. The sector also asked for a two-step cost assignment, with some costs assigned to the parties receiving quantifiable, economic benefits and the remainder spread evenly across a subregion to recognize the broad reliability benefits that high-voltage lines deliver but are difficult to calculate.
Sustainable FERC Project attorney Lauren Azar said the Environmental Sector’s proposal clamps down on free ridership. She said her sector would also like to see benefits assumed over a 40-year horizon, noting most transmission remains energized for about 60 years, making projects undervalued when their benefits are initially measured.
MISO has said its system will not be able to function reliably in a future with a changing resource mix without new, large transmission projects (See MISO Analyses Show Reliability Woes Without Transmission Builds.) Currently, more than 95% of its members have carbon-emissions reduction goals.
Both MISO South regulators and Entergy representatives have questioned the amount of renewable penetration the RTO forecasts in future planning scenarios. They have suggested states with clean-energy goals pay a larger share of transmission construction costs.
The grid operator said it may need more than a dozen 345-kV additions, a handful of 500 kV and 765 kV lines, and even a massive footprint-wide network of DC lines as part of its the long-range planning package. (See MISO Reveals Contentious Long-range Tx Project Map.)
Based on MISO’s annual MTEPs, the footprint could see more than 5,000 miles in new transmission lines come online over the next decade. Only about 200 miles of the new lines will be rated at 345-kV and greater.
MISO has not approved any large economic transmission projects since it changed their cost allocation in 2020. (See MISO Cost Allocation Plan Wins OK on 3rd Round.) The RTO had framed the new allocation as key to getting more Market Efficiency Projects approved.
ISO-NE stakeholders Thursday approved tariff changes that incorporate a new transmission planning process focused beyond the RTO’s current 10-year planning horizon.
The revisions, which the NEPOOL Participants Committee passed unanimously with one abstention, are part of a multiphase effort. The initial phase establishes the rules to enable the New England States Committee on Electricity (NESCOE) to request that the RTO perform longer-term, scenario-based transmission planning studies on a routine basis.
The present processes do not support state-requested transmission analysis based on state-developed scenarios, inputs and assumptions. The new approach includes the development of high-level transmission concepts and cost estimates, if requested, to meet the state-identified requirements.
The second phase, to begin in early 2022, will address the rules to enable NESCOE to consider potential options for addressing the identified issues and cost allocation for associated transmission improvements.
2021-2022 Winter Outlook
ISO-NE COO Vamsi Chadalavada presented the region’s 2021-2022 winter outlook during his monthly report, with the 50/50 and 90/10 winter peak demand forecasts both lower than last winter’s.
The 50/50 forecast of 19,710 MW is 456 MW (2.3%) lower, while the 90/10 forecast of 20,349 MW is 2.2% lower (457 MW). Chadalavada said that if this winter is similar to the last, the RTO anticipates reliable power system operation without the need for emergency procedures. It is assuming no significant generation or transmission outages and limited fuel replenishment in this profile.
Energy Market Value Falls
Chadalavada added that ISO-NE’s energy market value for last month (through Nov. 22) was $375 million, down $185 million from October but up $130 million from last November.
Natural gas prices were 6.1% higher than in October, while gas prices and LMPs were up 154% and 112%, respectively, over the same period last year. Average day-ahead cleared physical energy during the peak hours as a percentage of the forecasted load was 98.6% during November, down from 99% during October, with the minimum value for the month of 93.9% posted Nov. 22.
Daily uplift, or net commitment period compensation (NCPC) payments, in November totaled $2.5 million, down $1 million from October, though $600,000 higher from November 2020. NCPC payments were 0.7% of the energy market value.
Two projects totaling 213 MW were added to the interconnection queue since Chadalavada’s last update. They consist of one battery project and one solar project, and each has in-service dates of 2024. In total, 300 generation projects are currently being tracked by the RTO, totaling approximately 31,947 MW.
2022 Budget
The PC unanimously approved — with abstentions — a 2022 budget of $6,587,000 for NEPOOL, up more than $350,000 from 2021’s spending plan. However, NEPOOL expects to spend $5,974,600 by the end of this year, $246,000 less than the 2021 approved budget.
The decrease mostly comes from declining committee meeting expenses amid the COVID-19 pandemic, as all gatherings were virtual events until October. Budget increases for 2022 include an increase in committee meeting expenses to $725,000, up from an approved figure of $510,000 in 2021 and 10 times the current forecast of $75,000.
Cavanaugh Re-elected Chair
PC Chair David Cavanaugh, vice president of regulatory and market affairs for Energy New England, was re-elected for 2022. Vice chairs were also re-elected include Tina Belew of the Massachusetts Attorney General’s Office; Frank Ettori, Vermont Electric Power Co.; and Michelle Gardner, NextEra Energy. Sarah Bresolin of ENGIE North America and Aleks Mitreski of Brookfield Renewable Energy Group were also elected vice chairs.
FERC last week said a MISO transmission owner cannot duck refunds stemming from the commission’s recent decision to implement a 10.02% return on equity (ROE) for the grid operator’s other TOs.
In a Dec. 1 order accepting the TOs’ compliance filing for MISO’s new ROE, the commission said Mississippi’s Cooperative Energy cannot evade its refund obligation by shortening its refund period (ER17-215).
MISO’s ROE has been a carousel of numbers for years. FERC in 2020 enacted a 10.02% ROE for transmission rates effective September 2016, superseding the 9.88% and 10.32% ROEs approved in 2019 and 2016, respectively. Those figures were intended at different times to replace the 12.38% ROE established in 2002, which FERC deemed excessive years ago. (See FERC Stands by 10.02% ROE.)
The TOs’ compliance filings in question date back to 2016, reflecting the 10.32% ROE. FERC accepted them and ordered them updated to the TO’s current ROE of 10.02%, including incentives not to exceed 12.62%.
But the docket’s bigger point of contention came from Cooperative Energy, which argued that it shouldn’t have to provide refunds for the full refund period FERC prescribed.
FERC ultimately ordered TOs to refund customers for the 12.38% ROE from Nov. 13, 2013-Feb. 11, 2015, and Sept. 28, 2016-Dec. 23, 2020. (See MISO, TOs: More Time Needed for ROE Refunds.)
Cooperative Energy argued that it wasn’t obligated to issue refunds until mid-2015. That’s the date it began receiving a 50-basis point adder for its participation in MISO, despite it having been a non-public utility TO in MISO and using the MISO ROE since December 2013.
Other MISO TOs bristled at Cooperative’s interpretation of refund periods, leading them to register a limited protest of their own compliance filing.
FERC pointed out that Cooperative’s RTO adder was conditioned on its agreement to provide ROE refunds should the commission lower the rate. FERC said the TO should use its 2013 entrance into MISO as its effective refund date.
The commission found Cooperative’s arguments that forcing more refunds would amount to retroactive ratemaking to be baseless.
NYISO on Thursday updated stakeholders on several market changes in the works to accommodate thousands of megawatts of state-solicited renewable resources coming online in New York over the next decade.
The measures range from carbon pricing and buyer-side mitigation to distributed energy resource participation models, including for storage, hybrid and co-located resources, all part of the ISO’s Grid in Transition initiative announced two years ago, NYISO Principal Economist Nicole Bouchez told the Installed Capacity/Market Issues Working Group.
The ISO also posted the final version of its 2022 Master Plan for managing the changes in the energy, ancillary services and capacity markets.
The state’s Climate Leadership and Community Protection Act (CLCPA) and other statutes set ambitious clean energy targets staggered every five years from 2025 to midcentury, with strict emissions limits that regulators recently cited in denying air quality permits to two gas-fired generator proposals in the Hudson Valley and New York City. (See NY Regulators Deny Astoria, Danskammer Gas Projects’ Air Permits.)
“This path of Grid in Transition is focused on market enhancements under three different areas, the first one being aligning competitive markets in New York with the state’s clean energy objectives,” Bouchez said. “The second one is valuing reserves for resource flexibility, and the third one is improving capacity market valuation.”
NYISO retained The Brattle Group to forecast future resource mixes and help inform planning for reliability and market design over the next two decades, with the final report presented in June 2020. (See ‘Astonishing’ Buildout Needed for Clean NY Grid.)
Stakeholders expressed concerns about how fast the ISO is able to incorporate new events and regulations into its capacity processes. For example, the gas-fired projects were turned down, but state agencies have approved two separate projects totaling 2,550 MW to bring solar, wind and hydropower south to the city, as well as offshore wind projects totaling 4,300 MW. (See Two Transmission Projects Selected to Bring Low-carbon Power to NYC.)
In addition to the projects proposed, the ISO also presented an update on leading indicator metrics, with the most recent data provided in September, Bouchez said.
Supporting Studies
In looking at what changes to the markets are needed to face a growth in intermittent resource penetration, the ISO relied on several studies it has conducted over the past few years, including the following:
Aside from work on buyer-side mitigation tests and capacity accreditation, the ISO deployed a software-defined wide area network (SD-WAN). Separately, the NYISO is developing a billing and settlement system and billing simulator code. The remaining code for the DER participation model will be developed in 2022, with deployment also scheduled for next year.
The ISO expects to implement its hybrid co-located model in mid-December and will work to integrate the rules and software needed to enable large‐scale weather-dependent and energy storage resources to participate as co‐located resources (CSR) behind a single interconnection point. FERC in March accepted the ISO’s rules allowing an energy storage resource to participate in the wholesale markets with wind or solar as a CSR, and NYISO has since been working on the market software. (See FERC Approves NYISO Co-located Storage Model.)
A regulation service project completed in September last year updated requirements, and the ISO will continue to monitor fleet changes and appropriately update statewide regulation procurement requirements in the future.
New Resource Integration
One critical area is related to new resource integration projects, Bouchez said.
She listed three: the DER participation model, the hybrid aggregation model — which is scheduled for a functional requirements specification in 2022 — and internal controllable lines, “obviously something that we need to work through,” she said.
The ISO anticipates starting to review the real-time market structure to start in 2025, “but we’re thinking that it might not be a bad thing to start those discussions [next year] about the existing structure and different ideas for what changes should be considered and why,” Bouchez said.
Reliability Risks
The ISO on Friday released its Comprehensive Reliability Plan (CRP), the culmination of the 2020-2021 Reliability Planning Process. The report concludes that the state’s bulk power system will meet all applicable reliability criteria from 2021 through 2030 for forecasted system demand in normal weather.
The figure shows typical load profiles with typical generation profiles for wind and solar resources; while there may be enough energy overall to meet demand, it will be necessary to shift the generation from the afternoon to the morning and evening hours. | The Brattle Group
But it also “demonstrates that our reliability margins are thinning to concerning levels beginning in 2023,” Zach Smith, vice president of system and resource planning, said in a statement. “We have to move carefully with the Grid in Transition in order to maintain reliability and avoid the kind of problems we’ve seen in other parts of the U.S.”
The CRP recommends monitoring and tracking transmission projects and other risk factors in order to mitigate risks to BPS reliability. In addition, system margins are expected to narrow to such a level that warrants review of current reliability rules and procedures.
NYISO said it will administer its short-term reliability process to address generator deactivation notices and other system changes on a quarterly basis, and continuously evaluate on a forward-looking, five-year basis.
“The potential risks to reliability identified in the analyses may be resolved by new capacity resources coming into service, construction of additional transmission facilities, and/or increased energy efficiency, integration of distributed energy resources, and growth in demand response participation,” NYISO said.
Reversing course, FERC on Thursday ruled that PJM did not have to pay an Illinois wind farm $10 million under a resettlement of incremental capacity transfer rights (ICTRs) to the Commonwealth Edison locational deliverability area (LDA) (EL18-183).
ICTRs — available to interconnection customers that are required to fund a transmission facility — are awarded based on how much the improvement increases the transmission import capability into an LDA. ICTR holders receive revenues if the LDA in question is constrained in subsequent capacity auctions. The rights are good for up to 30 years.
The commission ordered the resettlement in April 2020 in response to a complaint by Radford’s Run Wind Farm, which said PJM unfairly denied ICTRs for funding an upgrade identified in its system impact study (SIS) to mitigate a thermal overload on the 345-kV Loretto-Wilton Center line.
In a subsequent compliance filing, PJM determined that Radford’s Run was entitled to almost $10 million for the 2019/20 delivery year. Crediting the wind farm required offsetting charges to the load-serving entities in the ComEd LDA associated with their corresponding CTR reductions. (See PJM Announces $10M Resettlement in ComEd LDA.)
In Thursday’s order, however, the commission said it now concludes the wind farm wasn’t entitled to ICTRs at the time of the 2016 Base Residual Auction for 2019/20.
Agreeing with challenges by PJM and Exelon’s Commonwealth Edison (NASDAQ:EXC), FERC said its earlier rebilling directive was “incompatible” with the PJM tariff’s definition of ICTRs because the wind farm did not become “obligated to fund” its upgrades until after the 2016 BRA.
The commission said PJM’s tariff is “ambiguous as it does not expressly state when the obligation to fund must occur.”
It concluded that the tariff requires that the resource either execute an interconnection construction service agreement with collateral or reimburse the transmission provider for the costs of the customer-funded upgrades prior to the BRA to qualify for the ICTRs for the associated delivery year.
The 306-MW wind farm in Macon County, Ill., went into service in December 2017. Neither the wind farm’s owner, RWE Renewables Americas, nor its attorney, Bruce Grabow of Locke Lord, responded to requests for comment.
PJM spokesman Jeff Shields said the RTO will comply with the order. “We don’t have any further details at this time,” he said.
FERC last week approved WECC-levied penalties totaling $156,000 against Black Hills Power (NYSE:BHP) and Southern California Edison (NYSE:EIX) for violations of NERC reliability standards (NP22-3).
NERC submitted the settlements to FERC on Oct. 28 in a spreadsheet Notice of Penalty. The commission indicated last week it would not review the WECC settlements, along with a separate $300,000 penalty against Ohio Valley Electric Corp. (See OVEC Hit with $300K in NERC Penalties.)
BHP Reports Study Shortfalls
Black Hills’ $46,000 penalty resulted from three violations of TPL-001-4 (Transmission system planning performance requirements) and one each of PRC-005-1 (Transmission and generation protection system maintenance and testing) and PRC-005-6 (Protection system, automatic reclosing, and sudden pressure relaying maintenance). All were self-reported.
The utility’s infringement of TPL-001-4 had to do with the 2017 and 2018 Transmission Coordinating Planning Committee (TCPC) studies, which Black Hills discovered in 2020 had not been completed to requirements R2, R3 and R4 of the standard. Specifically, several aspects of the planning assessment were not finished in 2017 because the employees who were assigned to handle those parts left the company before it was done. The following year’s assessment was completed late as well, though WECC did not state whether this was because of the employees’ departure as well.
WECC assessed the risk level of the violation as minimal and acknowledged that it “did not pose a serious or substantial risk to the reliability of the bulk power system.” However, the regional entity also pointed out that the lack of a complete planning assessment could have limited Black Hills’ ability to “identify weaknesses in its system … implement action plans for identified system deficiencies or make needed system improvements.”
The RE regarded the issues with Black Hills’ planning assessments as systemic, warranting a financial penalty, because of the number of requirements violated and the fact that they spanned several years. The utility’s first mitigating action for the infraction was to complete the missing aspects of the affected assessments, which it did in 2020 while working on the 2019 assessment. It also created a TPL-001-4 process checklist to monitor the project’s progress each year, with backup plans for what to do if the needed information is not available in time.
The PRC-005-1 violation originated with Black Hills’ failure to verify the functioning of battery terminal connection resistance and battery interval or unit-to-unit connection resistance in two battery banks at a 230-kV converter substation. Black Hills reported in 2019 that it had not performed the testing — which is required every 15 months, according to the standard — since the standard became effective in 2007 because contractors performing the testing were unable to access the battery’s posts and straps. Black Hills verified the resistance of the batteries and replaced the bolts that kept contractors from accessing the batteries.
Similarly, the utility’s violation of PRC-005-6 was failure to verify that the communications system at a bulk electric system substation was functional every four calendar months. Black Hills found that its internal BES review committee “did not analyze and recategorize the substation as containing BES elements” after a new substation was interconnected on the BHP system in 2016. The utility completed the required maintenance testing, conducted an extent of condition review that found no other instances of noncompliance, and overhauled its BES review committee.
WECC considered these infractions systemic as well because of the overlapping timelines. The RE noted Black Hills’ internal compliance program but did not consider it a mitigating factor because of its failure to detect or prevent these violations, as well as the violations of TPL-001-4.
Testing Failures Net $110K Penalty for SCE
The $110,000 penalty for SCE originated from a violation of regional reliability standards FAC-501-WECC-2 (Transmission maintenance) and FAC-501-WECC-1, the earlier version replaced by FAC-501-WECC-2 in 2018.
SCE reported both infractions in May 2019. The utility discovered the infringement of FAC-501-WECC-2 first: It realized that three series capacitors and three circuit breakers that were elements of major WECC transfer paths had not been maintained and inspected in January 2019 as the standard required. The second violation was discovered during the investigation of the first, when SCE found that it did not have documentation of the 2016 and 2017 reviews of its transmission maintenance and inspection program (TMIP). The utility was also late in completing the 2018 TMIP review.
WECC found that the root cause of the original violation was failure to track the progress of the inspections, coupled with lack of communication between responsible parties. The second was caused by poorly defined management policy guidance and expectations, specifically the lack of a formal process for initiating the annual review of the TMIP, for documenting its completion or for storing the documents.
SCE mitigated the infractions by completing maintenance and testing for the series capacitors and circuit breakers, updating its monthly workload planning checklist to ensure the TMIP is completed, and documenting the scheduling process project plan. It also documented a process for annual review of the TMIP.
Nevada Gov. Steve Sisolak on Thursday announced the membership of a panel that will advise the governor and legislature on potentially bringing the state into an RTO.
Sisolak named Sen. Chris Brooks (D), the bill’s author, as chairman of the task force. Its other 18 members include representatives of utilities, labor, environmental groups, business and government.
The governor’s office expects to add five more task force members in coming weeks.
“This task force will further advance our state’s mission of developing our infrastructure, bolstering our commitment to renewable energy and building out our green energy economy,” Sisolak said in a release.
RTO by 2030
SB 448 includes a requirement for transmission providers to join an RTO by January 2030, unless they can show that they haven’t been able to find a viable RTO or that joining an RTO wouldn’t be in the best interest of the providers or their customers.
The Regional Transmission Coordination Task Force will formulate advice on topics and policies related to regional energy transmission in the West.
Under the provisions of SB 448, the task force will study the potential costs and benefits of forming or joining an RTO, for transmission providers and their customers in Nevada. The task force may bring in an independent third party to help analyze those costs and benefits.
The panel will explore policies to help bring transmission providers in the state into an RTO by 2030, including whether any legislation is needed to allow the providers to join an RTO.
The task force will also look at business the state could attract by having a position in a regional wholesale electricity market. It will look at locations for new transmission facilities that would help achieve the state’s clean energy and economic development goals.
The task force will meet at least twice a year and send a report to the governor and legislature by Nov. 30, 2022, ahead of the state’s 2023 Legislative session.
Cost Savings, Reliability
Western Resource Advocates, which has a representative on the task force, pointed to a market study this year that found Western electricity customers could save more than $2 billion a year if a single market operator managed transmission and coordinated generation planning. Such a move could also support renewable energy development and improve reliability. (See Study Shows RTO Could Save West $2B Yearly by 2030.)
“The state task force’s work on a Western regional transmission organization will help Nevada reap the economic, environmental and reliability benefits of regionalization,” Vijay Satyal, Western Resource Advocates’ regional energy markets manager, said in a release.
Members of the Regional Transmission Coordination Task Force are:
Sen. Chris Brooks (chairman)
David Bobzien, director, Governor’s Office of Energy
Kris Sanchez, deputy director, Governor’s Office of Economic Development
Carolyn Barbash, vice president, transmission development and policy, NV Energy
Carolyn Turner, executive director, Nevada Rural Electric Association
Cameron Dyer, managing senior staff attorney, Western Resource Advocates
Eric Witkoski, executive director, Colorado River Commission of Nevada
Erik Hansen, chief sustainability officer, Wynn Resorts
Jeremy Newman, assistant business manager, IBEW Local Union 396
Leslie Mujica, executive director, IBEW/NECA/LMCC – Las Vegas Power Professionals
Luke Papez, director, project development, LS Power Development
Richard Perkins, president/CEO, The Perkins Co.
Mona Tierney-Lloyd, head, U.S. state public policy and institutional affairs, Enel North America
Samuel Castor, EVP of policy, Switch
John Seeliger, regional energy manager, Nevada Gold Mines
Kostan Lathouris, managing member, Lathouris Law PLLC
From Buffalo to Long Island, New York is trying to reduce transportation-related pollution not only by promoting electric vehicles, but by increasing the availability of public buses and light rail, developing greenways to make bicycling safer and easier.
Betta Broad, NYCP | NYCP
“The regional Transportation and Climate Initiative Program (TCI-P) had some setbacks, but we’re still committed to the program and want people to take action by supporting it and signing our petition to send a message to Gov. [Kathy] Hochul,” Betta Broad, director of New Yorkers for Clean Power (NYCP) and a member of the state’s Climate Action Council, said Wednesday as she hosted a “teach-in” on clean transportation on behalf of NY for TCI.
Connecticut Gov. Ned Lamont, Massachusetts Gov. Charlie Baker and Rhode Island Gov. Dan McKee separately announced last month that their states would back away from the program, which they and D.C. in December 2020 had signed a memorandum of understanding to join. (See Conn. Environmental Advocates Urge Continued Commitment to TCI-P.)
“We hope to see TCI included in the Climate Action Council’s plan that will also be circulating across the state next year, with lots of opportunities for public comment,” Broad said.
EVs vs. Mass Transit?
Meanwhile, passage of the bipartisan infrastructure bill in Washington means many billions of dollars coming to New York for transportation initiatives, she said.
Douglas Funke, president of the city’s Citizens for Regional Transit, said investing in more infrastructure to accommodate individual vehicles is not the ideal solution.
“We really have to fix the car problem, and public transit in our opinion is the way to do that,” Funke said.
He noted that Buffalo had a plan for a 42-mile light rail network but only built 6 miles. The city is building another 6, which is encouraging, he said, but it’s still far from the goal.
Changing all vehicles to electric doesn’t work in urban areas like Buffalo or New York City, Funke said, “because you still have the congestion, still have all the parking, all the roads. Every ton of concrete generates a ton of CO2, so if you have to keep building parking lots and roads and repairing them for all the cars, it just creates more pollution.”
Mariah Okrongly, Bedford 2030 | NYCP
In suburban Westchester County, however, EVs make more sense, said Mariah Okrongly, program manager at Bedford 2030, which is working to get local school districts to buy electric school buses.
Her organization expects at least one of the school districts in the next bond proposition to include an electric school bus, but it has been difficult selling the novel concept of using the buses to feed the grid with the vehicle-to-grid technology, Okrongly said.
“So it definitely is a long a long-haul initiative, but worthwhile, and with the new infrastructure bill and all the funds associated with that, there’s going to be a bigger push to move forward with this, so I think it’s a prime time if you’re considering this to begin the process,” Okrongly said.
Another town, Peekskill, is hosting a pilot on-demand, fully electric transit program that links with Westchester’s Bee-Line bus network, said Nina Orville of Sustainable Westchester.
The on-demand fleet also provides the opportunity to build out the charging infrastructure in Peekskill, where most households have either one car or none, Orville said.
“We still need to do work across the state to address tariffs for charging vehicles, which is particularly important for people who live in multifamily housing and have to use charging infrastructure that might be billed different rates than if they had their own charging equipment,” she said.
On-demand EVs “would be swell” in southeast Queens, where most commuters still have to take a bus to a Long Island Rail Road station and then to the New York City Subway to get to work, said Jean Sassine, a member of New York Community for Change.
“We just need more buses, more electric buses because … most of the pollution is coming from cars,” Sassine said. “Queens is built with the idea of that old sprawl mentality, so we’re either driving or waiting for buses.”
Greenways Connect People
Ibrahim Abdul-Matin, Green Squash | NYCP
The Brooklyn-Queens Greenway is part of a larger effort to develop dedicated biking and walking paths throughout New York City, said Ibrahim Abdul-Matin, of consultancy Green Squash, who also serves on the state’s advisory board of the Trust for Public Land.
A lot of people don’t necessarily feel safe or comfortable on the subway or they live far from where they work, Abdul-Matin said. The old purpose of greenways was to infuse residents with trees and wildlife, but now the idea is to reconnect and create a whole different type of transportation infrastructure, he said.
The Trust for Public Land has put together a slate of projects to help conserve and protect natural areas around the country, and almost every initiative had bipartisan support, he said.
Brigitte Griswold, Groundwork Hudson Valley | NYCP
Community volunteers in Yonkers thought they were doing trash pick-up on a series of vacant lots, but then realized the lots were the former route of an abandoned railroad known as the Putnam that used to run from New York City all the way up to Brewster before it was discontinued in the 1940s, said Brigitte Griswold, executive director of Groundwork Hudson Valley.
“A piece of the old railroad was completely forgotten: a 2.2-mile route that was a spur off the main line that ran from New York City to downtown Yonkers,” she said. “And so we got involved with thinking about how we could convert these series of vacant lots into a green bike and walking pathway.”
The Yonkers Greenway wasn’t originally conceived as a green solution, but as an answer to crime and a way to revitalize economic activity in the neighborhoods where businesses were shuttered, she said. When completed within the next two years, the greenway will be a 15-minute bike ride to Manhattan and will also connect with the 242nd St. subway stop in the Bronx.
For over 12 years Sustainable Westchester has been developing the Yonkers Greenway to transform a disused railway into a green corridor to Manhattan. | NYCP
Meanwhile, the Center for Post Carbon Logistics is developing solar-powered boats to carry freight up and down the Hudson River, said Andy Willner, the center’s executive director.
“The schooner Apollonia is a freight sailing vessel that carries Hudson Valley goods to and from New York City,” Willner said. “Primarily their cargo has been grains and malted barley for beer and distilled spirits, but they also had their first interaction with a cross-oceanic sailing vessel.”
