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APPA President and CEO Joy Ditto announces reorganization

September 18, 2020

by Tobias Sellier
APPA News
September 18, 2020

After months of analysis and assessment, APPA President & CEO Joy Ditto has announced the following changes, effective October 1, with a goal of better prioritizing and aligning APPA’s activities to serve its members:

 Additional promotions will be announced before the end of the year, and will take effect on January 1, 2021, per APPA’s regular annual process.

APPA’s mutual aid network delivers smooth response to Hurricane Sally

September 18, 2020

by Paul Ciampoli
APPA News Director
September 18, 2020

The rapid activation of the American Public Power Association’s mutual aid network to Hurricane Sally, which made landfall near Gulf Shores, Ala., as a Category 2 hurricane, created a smooth path for equipment and crews to be deployed in an effective manner, said Jon Hand, Executive Direct of Electric Cities of Alabama, on Sept. 18.

“We were able at a moment’s notice to activate APPA’s mutual aid network,” he noted in an interview, adding that APPA’s Mutual Aid Working Group is a “great resource for member utilities.”

Hand is a mutual aid coordinator for Region IV of APPA’s Mutual Aid Network. Region IV covers Alabama, Florida, Georgia, Kentucky, Mississippi, North Carolina, South Carolina and Tennessee.

He said that it was “quite an easy process once we called for the network to be activated” to get equipment and crews right away.

Hand praised APPA President and CEO Joy Ditto’s leadership during the hurricane. In particular, he cited Ditto’s “reaching out to our utilities directly” and offering APPA as a resource to make sure that any resources needed from the federal government were provided.  

“That was very reassuring and much appreciated,” Hand said.

And APPA’s mutual aid team, which includes Sam Rozenberg, APPA’s Engineering Services Security Director, and Giacomo Wray, APPA Engineering Services Specialist, “were extremely helpful,” he said.

Crews from Louisiana and Florida were traveling to Alabama during the storm to make sure that they arrived in a timely manner, as did crews from Alabama public power utility Dothan Utilities, Hand noted.

He reported that in the wake of Sally, Alabama public power utility Riviera Utilities initially faced around 46,000 outages, but that number had been brought down to approximately 36,000 outages as of 6:00 a.m. on Sept. 18.

Another Alabama public power utility, Fairhope Utilities, was 100 percent out after Sally hit the Alabama coast. On the evening of Sept. 17, a transmission line for the city was fixed, Hand noted.

At around 9:10 the morning of Sept. 18, the City of Fairhope’s Thomas Hospital was re-energized. “Crews are now working to get first-responders up and running. There is still extensive damage throughout our system, but we are working as safely as possible to get everyone up and running,” the city noted on its Facebook page.

The City of Robertsdale, Ala., also initially was faced with 100 percent power outages, but as of mid-day on Sept. 18, the city had reduced outages to around 2,500.

Riviera Utilities, Fairhope Utilities and Robertsdale are Alabama coastal utilities.

Further inland, other Alabama public power cities have been making good progress in terms of bringing the lights back on to customers. The Cities of Evergreen and Andalusia were expected to complete power restoration efforts on Saturday, Sept. 19.

Meanwhile, power restoration efforts for the City of Tuskegee, Ala., were completed on Sept. 18.

Hand noted that at one point, Alabama had 52,000 systemwide public power outages.

Public power utilities deploy crews to help with restoration efforts

Public power utilities from Florida, Louisiana and Alabama deployed crews to assist with restoration efforts.

Those utilities include:

The following Alabama public power utilities also deployed crews for restoration work:

Hand noted that other public power utility crews remain on standby.

As with other recent responses to storms and hurricanes, public power utility crews working on restoration efforts for Hurricane Sally have been taking precautions to minimize potential exposure to COVID-19.

Hand noted that “We’re encouraging all employees and mutual aid crew members to practice social distancing. We’re going the extra mile to make sure that the meals are packaged separately.”

Standing Rock Sioux Tribe launches crowdfunding effort for 235-MW wind farm

September 17, 2020

by Peter Maloney
APPA News
September 17, 2020

SAGE Development Authority has launched a crowdfunding initiative for the next phase of its 235-megawatt (MW) Anpetu Wi wind farm.

Anpetu Wi means “breaking of the new day” in the Lakota language.

The wind farm is sited on the Standing Rock Reservation, between Porcupine and Fort Yates, N.D., home to the Lakota and Dakota people of the Standing Rock Sioux Tribe (SRST). The crowdfunding initiative, https://anpetuwi.com/, aims to raise $1.5 million.

The SAGE Development Authority is the first public power authority owned by a single Native nation in the United States.

SAGE has already submitted an application for interconnection to the Southwest Power Pool and has raised nearly $2 million from nine different philanthropic foundations for pre-development work to set up SAGE.

“We are proud to achieve another milestone in our quest to create a model for self-determination and economic development not only for our people but for all Native communities,” Joseph McNeil Jr., general manager of SAGE, said in a statement.

The total cost of the wind project is estimated at $325 million, and the debt-to-equity is targeted at 70% debt, 30% equity. The remaining sponsor equity is being raised through a combination of grants, some additional crowdfunding and contributions from the sponsor when they are selected, spokesman Ludovic Leroy said. SAGE, as a not-for-profit, cannot use the tax credits the wind farm will generate, so the credits will be monetized as part of the project financing.

SAGE is working with LIATI Capital, Connexus Capital, and Hometown Connections. LIATI is overall head of the project’s advisory team. Hometown Connections is handling institution building and identification and implementation of best practices in governance, strategic planning and implementation. Connexus works on the crowdfunding initiatives, including data driven digital marketing and audience targeting.

“Developing renewable energy resources—for export as well as local consumption—will foster badly needed economic development on the Reservation and provide employment and skills training,” Fawn Wasin Zi, chairman of SAGE, said in a statement.

SAGE expects Anpetu Wi to be a revenue source for the Standing Rock Sioux Tribe and will help provide essential needs such as schools, roads, health care, and housing development.

The Standing Rock Reservation has a poverty rate of 40% and an unemployment rate of 70%.

FERC issues final rule allowing DERs to participate in wholesale power markets

September 17, 2020

by Paul Ciampoli
APPA News Director
September 17, 2020

The Federal Energy Regulatory Commission on Sept. 17 approved a final rule that allows for distributed energy resource (DER) aggregators to compete in regional organized wholesale electric markets.

The action took place at the Commission’s monthly open meeting, which was held virtually due to the ongoing COVID-19 pandemic.

The final rule, Order No. 2222, enables DERs to participate alongside traditional resources in the regional organized wholesale markets through aggregations, opening U.S. organized wholesale markets to new sources of energy and grid services, FERC said in a fact sheet (Docket No. RM18-9-000).

The rule allows several sources of distributed electricity to aggregate in order to satisfy minimum size and performance requirements that each may not be able to meet individually.

Order 2222 “is a landmark, foundational rule that paves the way for the grid of tomorrow,” said FERC Chairman Neil Chatterjee.

Chatterjee noted that some studies have projected that the U.S. will see 65 gigawatts of DER capacity come online over the next four years, while others have projected upwards of 380 GW by 2025.

“While these estimates and analytical frameworks vary, there is no doubt that investments in these advanced technologies will only accelerate in the years to come, continuing the seismic shifts we’re seeing in our energy landscape,” he said.

Background

In November 2016, FERC issued a notice of proposed rulemaking (NOPR) that proposed to require RTOs and ISOs to revise their wholesale power tariffs to remove barriers to RTO-run wholesale market participation by energy storage resources such as large battery systems.

The NOPR also proposed to require RTOs and ISOs to allow aggregators of distributed energy resources to participate directly in the organized wholesale electric markets, and similarly remove barriers to DER aggregator participation.

In February 2018, FERC voted to remove barriers to the participation of electric storage resources in the capacity, energy and ancillary services markets operated by RTOs and ISOs.

At the same time, the commission said it would convene a technical conference that would be used to gather additional information to help determine what action to take on DER aggregation reforms proposed in the NOPR issued in late 2016, as well as discuss other technical considerations for the bulk power system related to DERs.

At the technical conference, the Commission heard from a wide range of power industry participants, including Paul Zummo, the Association’s director of policy research and analysis and Christopher Norton, director of market regulatory affairs at American Municipal Power.

APPA stressed need for local decision-making in DER aggregation

In response to a Commission notice inviting comments following the technical conference on DER aggregation issues, APPA said that FERC should defer to retail regulatory authorities on whether or not DERs should participate in wholesale aggregation programs and put aside the idea that successful DER participation in the wholesale markets would be best achieved by dictating a uniform approach for RTO and ISO DER aggregation programs.

Specifically, APPA supported a opt-out/opt-in framework for retail regulatory authorities similar to existing regulations for aggregated demand response bids in RTO and ISO markets. Under that framework, large utilities would be given the option to opt-out of DER aggregation and small utilities would need to opt-in. APPA also stated that if Commission declines to adopt such a mechanism, it should, at a minimum, adopt an opt-in mechanism for small distribution utilities.

Final rule builds off recent court ruling on Order No. 841

FERC said that Order No. 2222 builds off a recent ruling from the U.S. Court of Appeals for the District of Columbia Circuit on Order No. 841 in which the court affirmed the Commission’s exclusive jurisdiction over the regional wholesale power markets and the criteria for participation in those markets.

In July, the appeals court issued an opinion that denied an appeal filed by the American Public Power Association and several other parties that challenged certain aspects of Order Nos. 841 and 841-A, which established rules for the participation of electric storage resources in RTO and ISO markets. 

Retail regulatory authorities and small utilities

The rule does not allow retail regulatory authorities to broadly prohibit DERs from participating in the regional markets. However, it does allow retail regulators to continue prohibitions against distributed energy aggregators bidding the demand response of retail customers into the regional markets.

The rule also establishes a small utility opt-in. Specifically, it prohibits grid operators from accepting bids from the aggregation of customers of small utilities whose electric output was four million megawatt-hours or less in the preceding fiscal year, unless the relevant retail regulatory authority for a small utility allows such participation.

“Several commenters raised concerns that costs borne by small utilities and their customer bases may outweigh the benefits of DER aggregation participation in RTO/ISO markets and that small distribution utilities may not have the resources needed to coordinate with aggregators and RTOs and ISOs,” a FERC staff member noted during the meeting.

The rule said that state and local authorities remain responsible for the interconnection of individual DERs for the purpose of participating in wholesale markets through a DER aggregation.

Grid operators must revise tariffs

As a result of the final rule, ISOs and RTOs must revise their tariffs to establish DERs as a category of market participant.

These tariffs will allow the aggregators to register their resources under one or more participation models that accommodate(s) the physical and operational characteristics of those resources, FERC said. Each tariff must set a size requirement for resource aggregations that do not exceed 100 kW.

The tariffs also must address technical considerations such as:

The rule also directs the grid operators to allow DERs that participate in one or more retail programs to participate in its wholesale markets and to provide multiple wholesale services, but to include any appropriate, narrowly designed restrictions necessary to avoid double counting.

Final rule takes effect 90 days after publication in Federal Register

Order No. 2222 takes effect 90 days after publication in the Federal Register.

Grid operators must make compliance filings to FERC within 270 days of the effective date and each compliance filing must propose an implementation plan appropriately tailored for its region and must outline how the final rule will be implemented in a timely manner.

Commissioner James Danly offered a dissent to the final rule.

“I dissent because, regardless of the benefits promised by DERs, the Commission goes too far in declaring the extent of its own jurisdiction and because the Commission should not encourage resource development by fiat,” wrote Danly.

The Federal Power Act delineates the respective roles of the Commission and the states, assigning powers in accordance with each sovereigns’ core interests, he said.

“The federal government is tasked with ensuring just and reasonable wholesale rates, prohibiting state action that would either encumber interstate commerce or harm other states. The states retain authority over the most local of concerns: choice of generation, siting of transmission lines, and the entirety of retail sales and distribution. Each sovereign has a sphere of authority, and in each sphere, the relevant sovereign’s powers are supreme,” wrote Danly.

Respect for the states’ role in the federal system and under the FPA “would counsel against even modest, non-essential declarations of our authority, if done at the states’ expense. Why, when issuing a directive to the RTOs and ISOs (undoubtedly Commission-jurisdictional entities), must we also declare that ‘retail regulatory authorit[ies] cannot broadly prohibit the participation in RTO/ISO markets of all distributed energy resources or of all distributed energy resource aggregators’? Perhaps the states should not or cannot prohibit such participation.”

But it is not “for us to make sweeping declarations regarding the States’ jurisdiction over distributed generation,” Danly argued.

Rather, he argued that the Commission’s jurisdiction over wholesale rates “would ideally be vindicated, were it to collide with a state prohibition, through a challenge to a specific enactment or regulation by making arguments ‘armed with principles of federal preemption and the Supremacy Clause.’”

Apart from FERC’s “injudicious jurisdictional declarations, today’s order stands as an imprudent exercise of the Commission’s power. Why promulgate a rule at all? Reluctance to govern by fiat is counseled particularly in a case like this in which the generation resources the majority seeks to promote, by their very nature, inevitably will affect the distribution system, responsibility for which is assigned, with no ambiguity, to the states.”

FERC should allow the RTOs and ISOs “(or the states or the utilities) to develop their own DER programs in the first instance. If the promises of DERs are what they purport to be, the markets will encourage their development. And if those programs result in wholesale sales in interstate commerce, then the question of the Commission’s jurisdiction will be ripe. Commission directives are unnecessary to encourage the development of economically-viable resources.”

Danly said he has “greater faith in the power of market forces and in the discernment of the utilities and the states.”

APPA joins DOE program to help utilities expand community solar

September 16, 2020

by Peter Maloney
APPA News
September 16, 2020

The American Public Power Association has joined the National Community Solar Partnership (NCSP), a program sponsored by the Department of Energy that aims to expand access to affordable community solar to every American household by 2025.

Nearly 50% of households and businesses are not able to host rooftop solar systems, according to a report by the National Renewable Energy Laboratory.

Partners in the program, first announced last September, have access to peer networks and technical assistance resources that can be used to set goals and work toward overcoming barriers to expanding community solar projects.

The National Community Solar Partnership program’s three goals are to make community solar accessible to every U.S. household, ensure community solar is affordable for every U.S. household, and to enable communities to realize supplementary benefits and other value streams from community solar installations.

More specifically, partners in the NCSP program have access to an online community platform that includes virtual person-to-person meeting and webinars that allow them to communicate with DOE experts and each other. Program partners also have access to the technical resources of the DOE and its network of national laboratories.

Program partners also can participate in collaborative groups to address barriers to establishing community solar projects. The program’s Municipal Utility Collaborative, for instance, seeks to demonstrate replicable models for solar energy deployment that offer low or no fee subscriptions and result in energy savings for customers.

“Through the program, the DOE provides technical assistance for utilities to come together and solve community solar challenges. APPA will work with the DOE to help produce guides and webinars for people who want community solar,” Alex Hofmann, vice president of engineering services at APPA, said.

Despite early successes – dating back to 2011, public power utilities were among the first utilities to develop community solar projects – but barriers have limited the spread of that success. NCSP’s Municipal Utility Collaborative aims to address those barriers, including conflicts that can arise between community solar programs and existing rate structures, finding appropriate locations for community solar projects, streamlining procurement processes, and creating project financing structures that accommodate the fact that public power utilities are not eligible for tax incentives often used to fund renewable energy projects.

To reach its aims, the Municipal Utility Collaborative is focused on identifying and implementing best practices and lesson learned regarding community solar program design, including pre-qualification of income status, and working with third-party sponsors.

The collaborative also focuses on developing sustainable customer financing options, such as on-bill financing, monthly subscription products, subsidy options for low income residents, and finding models that can integrate community solar with other utility programs, such as demand response, energy efficiency, and rate assistance programs for low income customers.

The Association’s kick-off meeting for the NCSP program is scheduled for next week with meetings for more technical aspects of the program slated for November.

“Community solar is a great way for utilities to provide access to solar energy for people in the community that wouldn’t normally have the option” Hofmann said. In most cases, it is more cost effective for a utility to build a community solar project than for an individual to install rooftop solar, if they own a roof top to put solar on, that is, he added.

Public power utilities that were already participating in the Municipal Utility Collaborative include Austin Energy, BrightRidge, City of Colton Electric Utility, Seattle City Light, Snohomish County Public Utility District, and the Town of Marblehead Municipal Light Department.

PJM market monitor protests market-based filings submitted to FERC

September 16, 2020

by Paul Ciampoli
APPA News Director
September 16, 2020

Monitoring Analytics, the Independent Market Monitor (IMM), recently filed identical protests in at least thirteen market-based rate (MBR) triennial filings at the Federal Energy Regulatory Commission.

Sellers of energy, ancillary services and/or capacity at market-based rates must submit indicative screens to assess whether they have horizontal market power. Certain sellers are required to submit updated screens and other information every three years in these triennial filings.

Last July, FERC issued Order No. 861, which eliminated the requirement for MBR sellers to submit horizontal market power screens for regional transmission organization or independent system operator administered energy, capacity, and ancillary services markets that are subject to FERC-approved market monitoring and mitigation. 

APPA in joint comments with the National Rural Electric Cooperative Association and the American Antitrust Institute, opposed this change to FERC’s regulations. 

Order No. 861 preserves the requirement for MBR sellers to submit horizontal market power screens in RTOs and ISOs without capacity markets — currently the California Independent System Operator and Southwest Power Pool — unless the MBR seller will limit its MBR sales to energy and ancillary services.

In its protests, Monitoring Analytics is not seeking market power screens, but instead argues more fundamentally that “current PJM market rules for market power mitigation are insufficient to support such authorizations.”

The IMM requests that “unless and until the deficiencies in PJM’s market power mitigation rules are corrected, the Commission should authorize participation in the PJM capacity market at market based rates only on the condition that market sellers offer their resources in the PJM Capacity Market at or below the competitive capacity offer,” which is “equal to the Avoidable Cost Rate adjusted for expected Capacity Performance penalties and bonuses.”

Monitoring Analytics also asks the Commission to condition participation in the PJM energy market at market-based rates on market sellers offering their units “at or below the defined cost-based offer” and submitting “operating parameters that are at least as flexible as the defined unit specific parameter limits in the PJM energy market.”

According to the protest, “the Market Monitor has provided ample evidence that the PJM Capacity Market is not competitive due to inadequate market power mitigation” and “of the inadequacies of PJM energy market power mitigation in its State of the Market Reports.”

With respect to the capacity market, the protest references Monitoring Analytics’ complaint from last year arguing that the current default capacity market seller offer cap is excessive and therefore prevents effective mitigation of market power.

APPA, American Municipal Power and the Public Power Association of New Jersey all filed comments in support of that complaint.

Monitoring Analytics said that in the energy market, some sellers that fail the structural market power test, the Three Pivotal Supplier test, are able to set prices with a substantial markup over their cost-based offer, and some “are able to operate, set prices, and collect uplift payments with operating parameters that are less flexible than their defined parameter limits.”

With respect to the submission of screens, the protest said that without adequate market power mitigation, passing indicative market power screens does not provide customers protection from the effects of market power on prices. “Accordingly, it would serve no useful purpose for the Commission to request indicative screen information.”

In each protest, Monitoring Analytics recommended institution of a Federal Power Act section 206 proceeding to investigate whether the existing RTO/ISO mitigation continues to be just and reasonable.

Calif. CCA group asks governor to take steps to improve grid reliability

September 15, 2020

by Peter Maloney
APPA News
September 15, 2020

The California Community Choice Association (CalCCA) has sent a letter to Gov. Gavin Newsom, asking him to take immediate action to improve the reliability of the state’s electric system.

California is dealing with record-breaking heat, as well as a record setting level of wildfires, which threaten the stability of the state’s power grid.

Earlier this month, the California grid operator called on customers to reduce power consumption during recent heat waves to avoid more drastic rolling outages. In August, the grid operator initiated rolling power outages in response to record heat.

The recent rolling blackouts, “reveal an urgent need to reform the existing resource adequacy rules administered by the California Public Utilities Commission (CPUC) and the CAISO [California Independent System Operator], and focus the CPUC’s integrated resource planning process more rigorously on supply reliability,” Beth Vaughan, executive director of CalCCA, said in the letter.

CalCCA represents 20 Community Choice Aggregators (CCAs) that provide energy to customers in more than 170 California cities and counties. Collectively, CCAs serve about 25% of CAISO’s load.

In the letter, the CalCCA also recommends the governor appoint an Independent Review Panel to consider the results of a root-cause investigation of the conditions that led CAISO to initiate rotating outages on Aug. 14 and 15.

While root causes identified may point to solutions needed to mitigate the risk of repeating similar events, even without certainty regarding root causes, California should begin to take steps to increase reliability through action in the regulatory, legislative, and federal arenas, Vaughan argued.

In the letter, the CalCCA recommended several near-term actions to improve the reliability of California’s grid. Specifically, CalCCA says the CPUC should continue to ensure adequate supplies will be in place for summer 2021 requirements and beyond through the procurement track of the IRP process and review its import restrictions in the context of the recent emergency events.

The CPUC should also use the IRP process to refine needs for the 2024-2026 timeframe. CalCCA supported the CPUC’s 3,300-megawatt (MW) procurement order in 2019 and recommends analysis to identify any incremental near-term procurements beyond the current 3,300 MW order.

CalCCA also recommends using the IRP process in the coming months to “better refine” technical needs, such as capacity, energy, and evening ramp resources, and to establish a fair process to allocate those resources to load serving entities for procurement action.

And the CalCCA recommended that the CPUC should develop a deeper understanding of import resource availability and institutional barriers to securing firm import resources and provide incentives and regulations for behind-the-meter infrastructure to act as supply-side energy and capacity resources.

On the legislative front, CalCCA recommends the state’s legislature should enact AB 3014, which would establish a Central Reliability Authority responsible for planning and coordinating the state’s resource adequacy with CAISO and, where necessary, procuring backstop supply.

CalCCA said it supports the expansion of the federal Investment Tax Credit (ITC) to standalone energy storage resources and the removal of charging restrictions currently limiting the flexibility of battery energy storage to support the state’s ramping and peak needs.

Community choice aggregators have already signed long-term power purchase agreements for an aggregate total of 5,000 MW of new solar, wind, geothermal and energy storage projects and have expanded the use of time-of-use pricing regimes that can help relieve stress on the grid, Vaughan noted, adding that CCAs “are prepared to do more and are committed to working with the Joint Agencies and the investor-owned utilities (IOUs) to support reliable energy service and ensure sufficient in-state renewable integration supply.”

The American Public Power Association has initiated a new category of membership for community choice aggregation programs.

NYISO’s proposed modifications to capacity market rules are rejected by FERC

September 11, 2020

by Paul Ciampoli
APPA News Director
September 11, 2020

The Federal Energy Regulatory Commission on Sept. 4 issued an order rejecting changes proposed by the New York ISO (NYISO) to the buyer-side mitigation rules in its capacity market.

FERC’s decision drew a stinging rebuke from FERC Commissioner Richard Glick, who argued in a dissent that the order is “just the latest in the Commission’s ever-growing compendium of attempts to block the effects of state resource decisionmaking.”

The NYISO’s proposal, which the grid operator said received full stakeholder and market monitor support, would revise the process by which the NYISO determines exemptions from buyer-side mitigation when capacity prices are forecast to exceed certain thresholds following the entry of the new resource, which is referred to as the “Part A” exemption (Docket No. ER20-1718-001).

These provisions are intended to allow for the possibility that a new resource may be entering service at a time of tight capacity, and therefore would not need to have its offer price mitigated.

The NYISO said that the modifications were designed to better reflect the expected expansion of renewable resources and storage resulting from state laws and regulations.

The proposed tariff changes would increase the likelihood that such “Public Policy” resources would qualify for the Part A exemption, primarily by changing the order of preference for the exemption from resources with the lowest project cost to Public Policy resources, among other modifications.

The project cost is no longer the main factor determining which resources will be constructed, the grid operator said. The NYISO said that resources that meet public policy needs are likely to be built and become operational, even if they do not have the lowest Net Cost of New Entry because such resources are “favored by new laws and policies that govern siting and operation of these resources. They are thus more likely to have firm off-takers and receive favorable financing terms from private lenders.” 

The NYISO’s proposed change to the Part A exemption to give preference to Public Policy resources would not reduce capacity prices, and only would change which specific resources receive an exemption.

FERC decision

FERC determined that the NYISO proposal is unduly discriminatory because it does not provide sufficient justification for prioritizing the evaluation of Public Policy Resources before non-Public Policy Resources, independent of cost.

“Further, our finding that NYISO’s proposal is unduly discriminatory is dispositive; we need not reach NYISO’s arguments that its proposal would not cause price suppression,” the Commission said.

In contrast to its orders on the PJM MOPR expansion, in which FERC sought to avoid what it terms  “price suppression” from the participation of state-sponsored resources in the capacity market, in the NYISO order FERC focused only on this differential treatment between Public Policy resources and other types of capacity resources.

Commissioner Glick’s dissent

In his dissent, Glick argued that the Commission “has perverted NYISO’s buyer-side market power mitigation rules into a mind-boggling series of unnecessary and unreasoned obstacles aimed at stalling New York’s efforts to transition the state toward its clean energy future. As a result, those rules have become an unprincipled regime that has little to do with buyers or the exercise of market power.”

Responding to the other Commissioners’ reason for rejecting the proposal, Glick said that Public Policy Resources are not similarly situated for the purposes of the Part A Exemption Test “because they are subject to relatively favorable siting regimes and, as a result of their status under New York law, are more likely to secure the customers and financing that help ensure that they get developed successfully.”

He said that given that the purpose of the Part A Exemption Test “is to facilitate the entry of resources when capacity margins are getting tight and additional resources are needed, the likelihood that the exempted resources actually appear is a highly relevant and distinguishing feature that would support differential treatment.”

Glick said that until recently, the Commission “has long asserted an interest in balancing the effects of state policies with measures to address how those policies affect capacity market prices.  While reasonable minds can disagree over how effectively the Commission struck that balance in years gone by, it is hard to argue that today’s order does anything but confirm that the era of respect for state decisionmaking is over.”

And that, in turn, puts regional transmission organizations and independent system operators “in an impossible position, forcing them to juggle the Commission’s ideological antipathy toward state efforts to shape the resource mix with the realities that Congress gave states responsibility over resource decisionmaking and that the physical system will ultimately, and rightfully, reflect those state choices.” 

The NYISO’s filing “sought to strike a balance between those concerns by taking into account the effects of New York law while avoiding any of the ‘price suppression’ concerns on which the Commission has been so focused. And NYISO appeared to have done so admirably,” Glick said. 

The proposal received a super-majority of votes in the stakeholder process and not a single party protested this issue before the Commission, he noted, including any of the generator groups “that have cheered on the Commission’s slew of recent buyer-side mitigation orders. But, of course, the Commission thinks it knows better than NYISO’s stakeholders, better than NYISO’s Market Monitoring Unit, better than the New York State Public Service Commission, and better than the people of New York.” 

In rejecting the NYISO’s proposal, “the Commission makes clear how little it cares about stakeholder compromise or the consequences its actions will have for the practical reality of running an organized wholesale market,” wrote Glick.

This decision comes in the midst of a New York Public Service Commission proceeding, launched last August to consider how to reconcile the NYISO resource adequacy programs with the State’s renewable energy and environmental emission reduction goals.

Power mostly restored to Vinton, La. after public power utility crews pitched in

September 11, 2020

by Paul Ciampoli
APPA News Director
September 11, 2020

Power has been largely restored to Vinton, La., after the city was hit hard by Hurricane Laura last month. Crews from several public power utilities have played a key role in helping to bring power back to the city in an expedited fashion.

Crews from Louisiana public power utility Lafayette Utilities System (LUS), Florida public power utility Gainesville Regional Utilities (GRU) and Alabama public power utilities deployed in late August to assist with restoration efforts after Vinton was hit by Laura.

Alex Antonowitsch, an LUS spokesman, noted in a Sept. 10 email that Vinton is 80 percent restored.  The remainder are due to structural or electrical damage that would require the resident to have resolved, he said. 

LUS and GRU installed a 5,000 kV transformer to step down the voltage from investor-owned utility Entergy’s lower 35.5 kV line to feed Vinton. “Entergy’s 138 kV transmission lines are still down so we are waiting for Entergy to rebuild the lines. There is no timeline from Entergy as to when these will be rebuilt,” Antonowitsch said.

Antonowitsch noted that LUS currently has one five-man crew traveling every day to Vinton to assist in any additional work.

Two days after Laura made landfall and after completing restoration work in Lafayette, Greg Labbe’, Electric Operations Manager at LUS, was asked by the mayor of Vinton to oversee the restoration in Vinton.

“The damage was much worse than when we went to help out after Rita,” said Labbe’. “We are committed to see it through to the end.”

Labbe’ is a member of the American Public Power Association’s Mutual Aid Working Group.

Kevin Bihm, General Manager for the Louisiana Energy and Power Authority, noted that there were “so many facets of mutual aid that were displayed in Vinton.” Lafayette and Vinton are both member cities of LEPA.

Bihm cited the “neighbor helping neighbor” story seen through LUS personnel helping Vinton to assess damage to the system and assist city leaders in the coordination effort to restore power, as well as

APPA mutual aid line crews from various states “putting boots on the ground to restore and in some cases rebuild” the distribution system.

In addition, he noted that APPA and LEPA worked with state and federal governments to fast track needed equipment and facilities to get the lights back on as expeditiously as possible.

On a normal day, Vinton’s main substation is fed via a 138 kV transmission line, Bihm pointed out. This 138 kV line was damaged in the storm and Entergy was estimating several weeks for restoration. 

“APPA and LEPA were working on both the federal and state levels to secure a generator for Vinton so that they could power critical infrastructure” in Vinton, he said.

These efforts led to the installation of a temporary transformer that was interconnected to an energized 34.5 kV transmission line near Vinton in order to supply up to 5 MW of the total 8 MW load of Vinton.

Labbe’ and his team led the effort to construct the necessary substation structures for the installation of this transformer, Bihm said.

LADWP employees use emergency training to respond to automobile fire

September 10, 2020

by Paul Ciampoli
APPA News Director
September 10, 2020

Two employees of the Los Angeles Department of Water and Power,Sergio Morelos and Javier Hernandez, this summer utilized their training for emergency situations to quickly extinguish an automobile fire.

The event took place in July in San Francisquito Canyon near LADWP Power Plants 1 and 2.

Morelos and Hernandez noticed a car pulled to the side of the road that was emitting smoke. Morales noticed that the car tire had blown out, causing a small fire.

He recalled his recent training about proper fire extinguisher use, and immediately worked to put out the blaze. The two men then waited with the driver until the Fire Department was on the scene to ensure the situation was safe.

Morelos is a Utility Pre-Craft Trainee and Hernandez is a Maintenance Laborer.

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Above: Hernandez and Morelos put out fire; Below: Javier Hernandez and Sergio Morelos (photos courtesy of LADWP)

“My crew members and I attend daily tailgates, which remind us what to do in case of an emergency,” said Hernandez. “The daily training helps you remain composed and focused when an emergency does occur. The situation was unexpected, but our training prepared us to handle the unexpected.”

“By listening to information given at tailgate and safety meetings, I was prepared mentally for the dangers I may face on the job and on a daily basis,” said Morelos.

“Having had training where we actually use tools such as a fire extinguisher is vital when real life emergency situations happen,” he said.

“In the case of the incident, it was a scary situation, but we remained calm and knew how to assist the driver with the spreading fire because we had been trained on properly using fire extinguishers—PASS (pull the pin, aim the extinguisher, squeeze the trigger and sweep side to side),” Morelos said.

SRP Substation Troubleman helps save the life of a car crash victim

In another example of frontline public power workers quickly responding to dangerous situations in the field, Salt River Project Substation Troubleman John Boyle recently helped to save the life of a car crash victim in Mesa, Ariz.