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Snohomish County PUD launches study of EV driving and charging patterns

September 21, 2020

by Paul Ciampoli
APPA News Director
September 21, 2020

Washington State’s Snohomish County PUD is teaming up with FleetCarma on a two-year study of driving and charging patterns and other data related to electric vehicles.

The study was launched earlier this month, with eligible drivers starting to register for the study on Sept. 9, Snohomish County PUD noted. The study hit its limit of 100 participants later that week. There is currently a waiting list for customers.

Suzanne Frew, PUD Senior Project Manager Strategy and Emerging Technology, noted that “We have over 6,000 EV owners in our service territory and many are ‘enthusiasts’ who want to share their data to support the growth of electric vehicles. We had many interested prior to the rollout but with any program, you never know the customer response. On Sept. 9, we launched the program and sent out an email promoting the new program to our EV Customer Community, which has approximately 1,000 customers. In about a week, we were up to 112 participants in the study, so we have 12 customers currently on the waiting list. It was good to see the response and level of customer interest.”

With respect to what motivated the PUD to do this study, Frew said there were two main drivers/goals for the program.

The first was to learn more about the PUD’s customers who regularly drive electric vehicles — both their driving and charging habits. “Our service territory is a mix of rural and suburban areas, and many of our customers have long commutes throughout the Puget Sound region. We want to find out where and when our EV owners are driving and charging their vehicles,” she noted.

FleetCarma will provide information on charging duration and load plus trip data that the PUD can use to inform rate schedules, grid impacts, charging infrastructure needs and potential customer programs.

“The second goal was to find out if we could change their charging behavior to lower the impact on our grid. The first year of the program establishes a baseline and the second year provides incentives to those customers who charge off peak. Our goal is to encourage all of our EV drivers to charge off peak to increase the benefit to all of our ratepayers,” said Frew.

To be eligible, drivers must be a Snohomish PUD customer, live year-round in the PUD’s service territory and own or lease an EV or plug-in EV through fall 2022.

Study participants will install a small device in their vehicle that collects and transmits vehicle information via a cellular connection, Snohomish County PUD said in a news release.

Data collected will be shared with participants through a personalized portal and will be used by FleetCarma, a Toronto, Canada-based company that collects driving and charging data to help utilities better understand EVs, and the PUD to better understand EVs and charging impacts to the grid. Customer data will not be sold to outside parties or used for marketing purposes, the PUD said.

Based on meeting certain qualifications, participating customers can receive up to $185 over the two years of the study. Payments are based on installing the device and providing vehicle driving and charging data and off-peak charging in both years of the study.

FleetCarma’s installed device will collect information about charging session duration, energy consumption and location. GPS charging location coordinates will be used to determine how much charging is occurring within the PUD’s service territory and trip duration, energy consumption and distance traveled.

Addressing the question of why SnoPUD decided to partner with FleetCarma on the study, Frew said that FleetCarma offered a turn-key solution and unique features that other vendors did not. “We also established a good working relationship where we explained our needs and jointly worked toward the best solution. They have continued to evolve their product which is a key to success for emerging technology.”

LES partnering with FleetCarma

Public power utility Lincoln Electric System (LES) is partnering with FleetCarma on a similar project to study charging and driving habits of customers in the Lincoln, Neb., area over a 2-year period.

LES was previously awarded a $46,075 grant from the American Public Power Association’s Demonstration of Energy & Efficiency Developments program to help support the project.

In July, APPA hosted a webinar about the project. Additional details about the webinar are available here

FERC issues NOI on threats from equipment sourced from foreign adversaries

September 21, 2020

by Peter Maloney
APPA News
September 21, 2020

The Federal Energy Regulatory Commission (FERC) is seeking comments on the potential risks to the bulk electric system posed by equipment and services produced or provided by entities identified as risks to national security.

The Notice of Inquiry (NOI), docket # RM20-19-000, also seeks comments on whether or not the current Critical Infrastructure Protection (CIP) reliability standards adequately mitigate the identified risks and on what possible actions the commission could consider taking to address the risks. The NOI is also seeking comment on the extent to which equipment and services provided by such entities are used in the operation of the bulk electric system.

Since October 2018 when FERC issued Order 850, which approved the existing CIP reliability standards on supply chain risk management, there have been significant developments in the form of Executive Orders, legislation, as well as federal agency actions that raise concerns over the potential risks posed by the use of equipment and services provided by certain entities identified as risks to national security, the NOI says.

In particular, Huawei Technologies Company and ZTE Corporation “have been identified as examples of such certain entities because they provide communication systems and other equipment and services that are critical to bulk electric system reliability,” the NOI said.

The NOI says both entities have close ties to the Chinese government at both the ownership and employee level. In addition, under Chinese law, both entities have obligations that permit Chinese government entities, including state intelligence agencies, to demand that private communications sector entities cooperate with governmental requests, including revealing customer information and network traffic information.

And while there are many manufacturers of networking and telecommunications equipment, Huawei and ZTE are “gaining substantial shares of the market globally,” the NOI says, adding that systems are also vulnerable to Huawei and ZTE components embedded in equipment produced by unaffiliated vendors. That raises the probability that electric utilities now use “a significant amount” of telecommunications equipment with embedded components from Huawei and ZTE, the NOI says.

“If these obscured, or potentially unlabeled, components are present in an electric utility’s infrastructure, the same risks may exist as if the hardware had been purchased directly from Huawei, ZTE or one of its subsidiaries,” the NOI says.

The NOI cited Executive Order 13,873, which directs the Secretary of Commerce to identify equipment from a foreign adversary that has the potential for sabotage.

Executive Order 13,920, issued May 1, 2020, declared a national emergency in that foreign adversaries are increasingly creating and exploiting vulnerabilities in the bulk power system, including substations, generating stations and control rooms, and that unrestricted foreign supply of equipment constitutes a threat to national security. The order also created a Task Force on Federal Energy Infrastructure Procurement Policies Related to National Security, chaired by the Secretary of Energy.

In June 2020, the Federal Communications Commission issued orders designated Huawei and ZTE as national security threats to the integrity of communications networks and the communications supply chain.

Comments on the NOI are due 60 days after publication in the Federal Register, and reply comments are due 90 days after publication in the Federal Register.

Joint FERC-NERC report outlines best cyber security practices

September 21, 2020

by Peter Maloney
APPA News
September 21, 2020

Staff of the Federal Energy Regulatory Commission (FERC) and the North American Electricity Reliability Corporation (NERC) have published a report detailing utility best practices for response and recovery from cyber attacks.

The report, Cyber Planning for Response and Recovery Study (CYPRES), was developed based on interviews with subject matter experts from eight electric utilities of varying size and function. The report includes the joint staffs’ observations on the utilities’ defensive capabilities and the effectiveness of their incident response and recovery (IRR) plans.

The report identifies common elements among the incident response and recovery plans, including the definition and scope of a cyber incident, the roles and responsibilities of staff, reporting requirements and guidelines for external communication, as well as procedures to evaluate performance in the wake of an attack.

While acknowledging that there is no single best incident response and recovery plan model, the FERC/NERC team identified best practices that utilities should consider when developing their IRR plans.

Specifically, an effective incident response and recovery plan should:

Among other observations, the report found that well defined roles and responsibilities became clearer to participants after participating in exercises, such as NERC’s Grid Security Exercise (GridEx), to test their response and recovery plans. Many participants in the report said they modified their incident response and recovery plans after completing the GridEx process.

GridEx, which takes place every two years, allows utilities, government partners and other critical infrastructure participants to engage with local and regional first responders, exercise cross-sector impacts, improve unity of effort messages and communication, identify lessons learned and engage senior leadership.

The most recent GridEx occurred in 2019. In 2017, 53 public power entities participated in GridEx, while in 2019, 100 public power entities participated.

Meanwhile, some participants in the report also noted that virtualization is a useful tool. Virtualization uses software to operate as if it were an actual physical device. Virtualizing hardware allows one physical device to house many virtual devices, reducing hardware and real estate costs.

And, because a virtualized device can be easily saved and restored, it can save hours of work when a software glitch occurs. In the same way, if a cyber attack were to require the reinstallation of a new machine, virtualization would make the restoration process less costly and time consuming.

The report concludes that an “effective IRR plans can mitigate the natural advantages that cyber attackers possess.” Because cyber attackers operate covertly, “effective IRR plans should be in place and response teams should be prepared to detect, contain, and, when appropriate, eradicate the cyber threat before it can impact the utility’s operations.”

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.