WAPA, U.S. Bureau of Reclamation tapped hydro to help response to Calif. energy emergency
August 26, 2020
by Paul Ciampoli
APPA News Director
August 26, 2020
The Western Area Power Administration and the U.S. Bureau of Reclamation joined forces between Aug. 14 and 19 to generate and transmit roughly 5,400 megawatt-hours in response to California’s energy emergency, the two federal agencies reported on Aug. 25.
The two federal agencies are responsible for generating, marketing and transmitting hydropower from federally owned hydroelectric dams to preference customers. In an emergency situation, the hydropower can be called upon to limit outages and stabilize the grid.
Reclamation generated the power using its fleet of federal hydroelectric dams in the West, including, among others, 18 dams in the Central Valley Project in northern California; Glen Canyon Dam in Page, Arizona; Hoover Dam on the border of Arizona and Nevada; Morrow Point Dam in western Colorado; Davis Dam in Arizona; and Parker Dam in California.
WAPA then transmitted the energy via its high-voltage transmission system into the California Independent System Operator’s service territory, while continuing to reliably serve WAPA’s customer loads.
WAPA’s Sierra Nevada region provided more than 3,300 MWh, while the Colorado River Storage Project provided nearly 1,900 MWh and Desert Southwest provided more than 200 MWh.
In some cases, WAPA was able to offset this generation and continue to meet its customers’ demand by increasing hydropower output from other dams to provide power to local areas.
The agencies noted that hydroelectric dams are crucial sources of reserve energy in case of system emergencies. The large reservoirs, such as Lake Mead and Lake Powell, function as enormous batteries and can quickly dispatch a large amount of electricity on the grid.
WAPA and Reclamation have plans in place with a number of utilities to provide emergency power from federal hydroelectric powerplants.
CAISO implemented rotating outages
On Friday, Aug. 14, CAISO declared a Stage 3 electrical emergency that lasted a little over two hours, with rotating outages throughout the state for about the first hour. A second Stage 3 emergency was declared Saturday night for twenty minutes.
California Gov. Gavin Newsom on Monday, Aug. 17, signed an emergency proclamation to free up energy capacity.
In announcing the emergency proclamation, Newsom also said he had sent a letter to CAISO, the California Public Utilities Commission, and the California Energy Commission demanding an investigation into “the service disruptions that occurred over the weekend and the energy agencies’ failure to predict and mitigate them.”
Calling the blackouts “unacceptable and unbefitting of the nation’s largest and most innovative state,” Newsom said the agencies failed to anticipate the event and to take necessary actions to ensure reliable power supplies.
Newsom also applauded the efforts of state officials who worked to bring more energy resources online, including generation from “sources like the Los Angeles Department of Water and Power, the California State Water Project and investor-owned utilities.”
Calif. grid operator initiates rotating power outages with extreme heat, high power demand
August 17, 2020
by Paul Ciampoli
APPA News Director
August 17, 2020
Against the backdrop of scorching temperatures and a spike in demand for power, California’s grid operator on Aug. 14 and Aug. 15 initiated rotating power outages throughout the state.
The California Independent System Operator (CAISO) on Aug. 14 declared a Stage 3 electrical emergency due to high heat and increased electricity demand. The emergency initiated rotating outages throughout the state.
A Stage 3 emergency is declared when demand outpaces available supply. “Rotating power interruptions have been initiated to maintain stability of the electric grid,” CAISO said.
The Stage 3 emergency declaration was called after extreme heat drove up electricity demand across California, causing the ISO to dip into its operating reserves for supply to cover demand.
The grid operator went into Stage 3 Emergency at 6:36 p.m. PDT. By 7:51 p.m., the grid had stabilized, and utilities began restoring 1,000 megawatts of electricity that had been taken out of service.
CAISO terminated its Stage 3 Emergency declaration at 8:54 p.m. on Aug. 14.
“The power crisis was caused in part by coronavirus restrictions, which have closed movie theaters, malls and other locations where people would typically gather to beat the heat. Concerns about outbreaks have kept many inside their homes with the air conditioning on,” the Los Angeles Times reported on Aug. 15.
Investor-owned Pacific Gas & Electric (PG&E) on Aug. 16 said that the COVID-19 pandemic “has made the heat-outage forecast more uncertain due to shifts in electric loads because more people are staying home all day.”
Investor-owned utilities
PG&E on Aug. 14 reported that it was directed by CAISO to turn off power to approximately 200,000 to 250,000 customers at a time in rotating power outages. PG&E noted that rotating outages are not Public Safety Power Shutoffs, which are conducted during specific high fire threat conditions.
The utility subsequently said that Power has been restored to essentially all of the approximately 220,000 impacted customers.
Meanwhile, CAISO also directed SDG&E to initiate rotating outages throughout its service territory in San Diego and southern Orange counties.
“A total of about 58,700 customers were impacted in SDG&E’s territory by service interruptions. All impacted customers had their power restored as of 8:03 p.m. – about an hour and 20 minutes after the rotating outages began,” the Times of San Diego reported.
Approximately 132,000 of Southern California Edison’s five million customers lost power Friday night for about an hour, the Los Angeles Times reported, citing spokesman Robert Villegas. All of those customers had their power restored by 8 p.m., he told the newspaper.
LADWP
The Los Angeles Department of Water and Power (LADWP) on Aug. 13 said that in addition to asking residential customers to save energy, LADWP was also implementing a Demand Response event with its commercial customers in response to a CAISO Flex Alert. The alert asked all power customers to save energy from 3:00 p.m. to 10:00 p.m. on Friday, August 14.
LADWP’s Demand Response is an incentive-based, voluntary program designed for businesses that helps reduce their utility bills during periods of peak power demand and helps to ensure the continued reliability of power service for Los Angeles.
LADWP said in an Aug. 15 tweet that the rolling blackouts implemented by CAISO on Aug. 14 did not affect residents of Los Angeles.
The public power utility noted that it owns its plants and transmission lines and had enough supply to meet demand and required reserves.
LADWP, “which has never had to implement rolling blackouts due to excess demand, was able to sell 225 megawatts to California ISO between 5 and 9 p.m., spokesman Joe Ramallo said,” the Los Angeles Times reported.
On Aug. 16, LADWP said that while it has adequate supply to meet its customer demand and emergency reserves “at this time, we join CAISO in urging customers to conserve energy to help the state grid and reduce the strain on neighborhood distribution systems. Extreme heat conditions, including very high nighttime temps that provide little relief to strained equipment, can cause equipment to fail, leading to power outages.”
LADWP also said on Aug. 16 that its crews had been working around the clock to restore small localized power outages caused by extreme heat and electricity demand. “Crews are working as quickly and safely as possible, and will work around the clock responding to outages.” As of 5 p.m., approximately 4,800 customers out of 1.5 million total were without power.
SMUD
The Sacramento Municipal Utility District (SMUD) on Aug. 16 said it was asking customers to limit their use of electricity during this week’s high temperatures, which are expected to continue into next weekend.
“With the heavy use of air conditioners, customers are using electricity at record levels, requiring the use of all SMUD power sources. With help from customers, SMUD expects to be able to avoid any power shortfalls,” it said in a news release.
SMUD noted it is a member of the Balancing Authority of Northern California (BANC), an independent balancing authority within the western electricity power grid. As a member of BANC, SMUD is not required to participate in rotating outages ordered by the California Independent System Operator (CAISO).
SMUD said it continues to support the statewide electricity grid in the event of a true electrical emergency.
During the heatwave, SMUD is all hands on deck with extra personnel available to restore power outages as safely and quickly as possible, it said.
CAISO requested power outages on evening of Aug. 15
CAISO declared a Stage 3 Electrical Emergency at 6:28 p.m. on Saturday, Aug. 15, due to increased electricity demand, the unexpected loss of a 470-MW power plant the and loss of nearly 1,000 MW of wind power.
IOUs in the state were directed to initiate rotating outages.
The load was ordered back online 20 minutes later at 6:48 p.m., as wind resources increased.
CAISO issues flex alert
On Sunday, Aug. 16, CAISO issued a statewide flex alert, a call for voluntary electricity conservation, through Wednesday, Aug. 19. The Flex Alerts are in effect from 3 p.m. to 10 p.m. each day.
“A persistent, record-breaking heat wave in California and the western states is causing a strain on supplies, and consumers should be prepared for likely rolling outages during the late afternoons and early evenings through Wednesday. There is not a sufficient amount of energy to meet the high amounts of demand during the heatwave,” the grid operator said.
“However, consumers can actively help by shifting energy use to morning and nighttime hours and conserving as much energy as possible during the late afternoon and evening hours,” CAISO said. “Consumer conservation can help lower demand and avoid further actions including outages, and lessen the duration of an outage.”
Consumers were urged to lower energy use during the most critical time of the day, 3 p.m. to 10 p.m., when temperatures remain high and solar production is falling due to the sun setting.
Extended periods of heat also can cause generator equipment failures that can lead to more serious unplanned losses of power, the grid operator noted.
Lightning strike to Alameda Municipal Power substation knocks out power to customers
Meanwhile, Alameda Municipal Power reported on Aug. 16 that lightning struck one of its substations causing a power outage to 10,000 customers.
Alameda Municipal Power subsequently reported that it had restored power to all but 50 customers on Aug. 16.
CAISO president and CEO offers thoughts on grid reliability, extension of day-ahead market
August 13, 2020
by Paul Ciampoli
APPA News Director
August 13, 2020
Steve Berberich, who will soon retire as president and CEO of the California Independent System Operator, recently offered his thoughts on what he sees as the greatest challenges to grid reliability in the next ten years, CAISO’s stakeholder and governance process and the extension of the day-ahead market into CAISO’s Western Energy Imbalance Market (EIM).
Berberich, who made his remarks in a July 29 interview with the American Public Power Association’s Public Power Daily newsletter, has served 14 years with the CAISO, the last nine as CEO.
On Aug. 6, CAISO announced the appointment of Elliot Mainzer as its new president and CEO. Mainzer, who has served as administrator and CEO of the Bonneville Power Administration for the past seven years, will succeed the retiring Berberich on September 30.
Challenges to grid reliability
In the interview, Berberich was asked to detail what he sees as the greatest challenges to grid reliability in the next 10 years and what steps CAISO should take to address those challenges.
“I think by far the biggest challenge is moving from a thermal-based fleet to a renewable-based fleet,” he said. “I think that’ll be the biggest challenge — to make sure that you can get essential grid resources or services if you will from the renewable fleet, which we’ve shown that you can.”
But this means marrying up “the regulatory, contractual, dispatchability all across because mostly the renewable contracts” reward the producer “on how much they can pump out, not whether they can hold back and provide voltage support or reactive power or ancillary services of all kinds, things like that. But it is technically possible to do that.” Energy storage is “going to play a critically important role,” he added.
“But I think we just have to do that very thoughtfully to make sure we maintain reliability. If you have any reliability issues, that’s going to be a major issue with this transition.”
As for CAISO’s role, “we have to be very clear about what the grid needs to respond to the load profiles and things like that.” But CAISO’s markets “have to adapt to compensate more for services and less from an energy perspective. I think energy’s going to continue to play a big role in the markets, but I do think critical services are going to become a more predominant part of the market mix.”
CAISO’s stakeholder and governance process
Meanhwhile, Berberich was asked to detail how well he thinks the stakeholder and governance process in CAISO is working and whether he sees any benefits to this process as compared to other RTOs.
“We have a unique governance model and it’s become more unique with the energy imbalance market. No other ISO has an appointed board and I’m obviously on record as saying I think a regional grid is really, really important for integrating high levels of renewables. I think you necessarily have to have a regional board of some type.”
He said that “I’m just a big advocate of a regional grid, so you’ve got to have a regional, representative board.”
Nonetheless, with the delegation of responsibilities to the energy imbalance market governing body, and with potential expanded delegation for a day-ahead market, “I think that you can achieve what you need to achieve and I’m confident that we can find a way to balance representation on the governing body board with what the region requires to have a fully functioning real-time and day-ahead market.”
With respect to the stakeholder process, “I have some major philosophical thoughts on this in as much as I think that there is a major evolution of stakeholders over time and I think that has accelerated and when you set up a standing stakeholder committee I think you necessarily create stakeholders that are sort of more important than others and I think we have to be very cautious of that,” he said.
With respect to public power, “it’s easy for the IOUs to overpower the munis because of the resources that they bring to bear and I think it’s a good example of you’ve got to make sure you protect and allow participation of all the stakeholders.”
Some of the ISOs “have standing stakeholder committees and they basically decide on something before it ever comes to the board. I’m not in favor of that because I think it segregates stakeholders and I think that’s unfair to certain stakeholders,” Berberich said.
“The other thing I think about and the analogy I use is the United Nations Security Council. You have the five permanent members on there and it’s really, really hard to get another one on there” and you have that same problem with a stakeholder committee once it’s established.
“Who would have thought the wind association would want to be part of the stakeholder community ten years ago or storage five years ago, or microgrids for that matter? And I think that’s all evolving and changing and I wouldn’t want to be in a place where they were on the outside looking in,” Berberich said.
“I think we have an open, participatory stakeholder process, so my perspective is I wouldn’t change what we’re doing in favor of what some of the eastern ISOs are doing.”
Western EIM and extension of the day-ahead ahead market into the EIM
CAISO in late July reported that the Western EIM surpassed $1 billion in economic benefits.
The Western EIM allows participants to buy and sell power close to the time electricity is consumed and gives system operators real-time visibility across neighboring grids.
Berberich was asked whether he sees any challenges for the future of the Western EIM and if he views the extension of the day-ahead market into the EIM as necessary for its continued success.
“The day-ahead market has vastly more energy traded in it than the real time market so it should have comparably higher value and billions of dollars — and potentially a billion every year — that you could unlock and I think we owe that to the energy customers across the west.”
He also thinks it will help integrate renewables and trade energy.
“We have about 50 percent more curtailment this year than we had last year and you would think that you could just export that negatively priced or very low-priced energy. You have people that…do the resource commitment day ahead and unless you have a coordinated day-ahead market, people can’t take it because they’ve already committed resources. So I think that will be really important from a benefit perspective but also from a renewable integration perspective.”
He added, “there’s a lot of people in the west that seem to like this model better than a full RTO where they turn over transmission control and things like that, so I’m comfortable with the direction we’re headed.”
What are the obstacles? There are “some critical market design things that need to be taken care of. As an example, you’ll have to do some sort of transmission compensation. You’ve got to do some sort of resource adequacy methodology and things like that. Those are going to be hard to do, but I don’t think they’re insurmountable and they’re already handled as part of our bucket one, if you will, of design features for the day-ahead market.”
He is “confident that we can solve the governance issues, which is going to mean some expanded responsibility for the governing body, but also the market design things and once you’ve done that you’ve added a whole lot of value.”
Berberich added, “I also know that, to the extent we can leverage our platform, it’s a hell of a lot cheaper than standing up a new RTO.”
Transmission
Turning to the topic of transmission, Berberich was asked whether he sees a need for new transmission in the state and, if so, what the greatest driver of that need is.
There is a lot of transfer capability that already exists, he said. Moreover, there will be transfer capability that will be freed up “as you retire coal plants and other thermal facilities and I think it’s critically important that we locate new resources,” such as renewables and battery storage – “using those same transmission corridors and in that way I think we can limit the build that we may have to do,” Berberich said.
“I think we’ll have to do some build, particularly to bring renewables to market and to share them, but I think you can limit it if the policymakers are thoughtful about where they put renewables and where they’re procured,” Berberich said in the interview.
“You can do it really, really badly and build a whole lot of transmission or I think you can do it really smart and limit the transmission that has to be built,” he went on to say.
“A lot of people kind of get to the, well, if you move to microgrids and other things will you need new transmission? I don’t know that we’ll need new [transmission] for that, but I do think we’ll have to continue to use the existing transmission system even as you move to a more distributed system.”
He also addressed the question of what steps the grid operator has taken to mitigate rising transmission costs while ensuring that needed infrastructure investments are taking place.
“We have been very, very loud about talking to the public utility commission and other policymakers – not just here in California but throughout the region – that it’s critical that you re-use what you have so you don’t have to force a bunch of new build and I think that’s the best thing we can do,” Berberich said.
“We need to do what we can to re-use what we have” when it comes to transmission “because there’s going to be more pressure” to do things like undergrounding power lines, “which is going to be just hugely expensive.”
Berberich to remain with CAISO into October
Berberich will remain with CAISO into October to ensure a smooth leadership transition to Mainzer.
Mainzer has “demonstrated success leading a large, complex power and transmission organization will serve CAISO, our customers and stakeholders well,” the CAISO Board of Governors said in a statement. “We are happy to have a leader so knowledgeable about integrating renewables and passionate about building on CAISO’s organizational strengths and momentum toward low-carbon electricity.”
In his current position, Mainzer is responsible for managing the non-profit federal agency that markets 23,000 megawatts of carbon-free power and operates much of the high-voltage power grid across the Pacific Northwest, including major interconnections with California.
“I am grateful to have the opportunity to lead the creative and innovative team at CAISO and to enable California to reliably and safely achieve its ambitious clean energy and climate goals,” said Mainzer. “I also look forward to working closely with our colleagues across the West to build on the success of the Western Energy Imbalance Market and further strengthen regional coordination and technology innovation.”
Mainzer brings “exceptional leadership experience, wide-ranging contacts and inclusive strategic thinking to the CEO position,” the Western EIM Governing Body said in a statement. “We look forward to working with Elliot as we continue to enhance and expand the financial, environmental and reliability benefits of the WEIM.”
Silicon Valley Clean Energy Receives Moody’s Investment-Grade Credit Rating
July 17, 2020
by Paul Ciampoli
APPA News Director
Posted July 17, 2020
Moody’s Investor Service on July 15 assigned a first time Baa2 issuer rating to Silicon Valley Clean Energy (SVCE), a California community choice aggregator.
Moody’s issuer rating is an independent assessment of SVCE’s financial strength over the long term and acknowledges the agency’s economic stability. SVCE is the third CCA to receive an investment-grade credit rating.
“SV Clean Energy is pleased to have received the Baa2 rating from Moody’s as we continue to enhance financial strength in our customers’ interest,” said Howard Miller, SVCE Board Chair and City of Saratoga Mayor. “With this credit rating, the agency will be even more equipped to continue investing in cost-effective, new renewable energy projects to provide our customers and communities with affordable, clean energy.”
The Baa2 rating recognizes SVCE’s stability within the California CCA business model and the strong socio-economic conditions of the SVCE service area, despite the negative impacts of the COVID-19 pandemic.
Additional value consideration was given to SVCE’s ability to maintain rate competitiveness relative to PG&E since 2017 by offering rate discounts between 1-6% to PG&E’s rates, while growing its cash position to $120 million.
The benefits of a Baa2 rating include access to new energy supply contracts, greater negotiation resulting in lower energy rates, and further transparency for SVCE customers on the agency’s financial standings, SVCE noted.
Moody’s in May 2108 issued the first ever credit rating for a CCA, a Baa2 rating and stable outlook for California-based CCA Marin Clean Energy.
In May 2019, Moody’s assigned a first-time Baa2 issuer rating to Peninsula Clean Energy, a California CCA.
The American Public Power Association has initiated a new category of membership for community choice aggregation programs.
Court Denies Appeal of FERC Orders On Energy Storage Participation In Markets
July 11, 2020
by Paul Ciampoli
APPA News Director
Posted July 11, 2020
The U.S. Court of Appeals for the District of Columbia Circuit on July 10 issued an opinion that denied an appeal filed by the American Public Power Association and several other parties that challenged certain aspects of Federal Energy Regulatory Commission Order Nos. 841 and 841-A, which established rules for the participation of electric storage resources (ESRs) in regional transmission organization (RTO) and independent system operator (ISO) markets.
In 2019, APPA, the Edison Electric Institute (EEI), the National Rural Electric Cooperative Association (NRECA) and American Municipal Power (AMP) challenged FERC’s conclusion that state and local regulators may not “broadly prohibit” ESRs located on a distribution system or behind a retail meter — what the court refers to as “local ESRs” — from participating directly in wholesale markets.
While the Federal Power Act (FPA) gives FERC jurisdiction over wholesale sales, the FPA leaves regulation of distribution facilities to state and local regulators.
APPA and the others primarily argued that FERC exceeded its jurisdiction in Order Nos. 841 and 841-A by concluding that state and local regulators could not exercise their jurisdiction over distribution facilities to prohibit local ESRs from participating in RTO/ISO markets.
APPA and the other groups also asserted that FERC acted arbitrarily and capriciously by not applying to ESRs the same “opt-in/opt-out” framework that FERC adopted for demand response in Order Nos. 719 and 719-A, under which a relevant electric retail regulatory authority can restrict aggregated retail customer participation in wholesale demand response programs.
The National Association of Regulatory Utility Commissioners (NARUC) filed an appeal raising similar issues, which was consolidated with the appeal made by APPA, EEI, NRECA and AMP.
Court addresses jurisdictional issues
As framed by the court, the primary question in dispute was whether Order No. 841 unlawfully regulates matters left to the states. On this issue, the court concludes that, in allowing local ESRs to access wholesale markets, FERC is not directly regulating distribution facilities. The fact that local ESRs will use the distribution system “is the type of permissible effect of direct regulation of federal wholesale sales that the FPA allows,” the court said.
The court turned aside arguments that authority over distribution facilities allows state and local regulators “to close their facilities to local ESRs seeking to transport electric energy to the wholesale markets,” citing principles of federal preemption under the Supremacy Clause of the U.S. Constitution.
The court said that the argument that a local ESR does not participate in the federal wholesale market — and therefore cannot fall within FERC’s authority — until after it navigates through state-regulated facilities falls short.
Any state effort that aims directly at “destroying” FERC’s jurisdiction by necessarily dealing with matters which directly affect the ability of the Commission to regulate comprehensively and effectively over that which it has exclusive jurisdiction invalidly invades the federal agency’s exclusive domain, the court said.
While agreeing that state and local regulators cannot broadly prohibit wholesale market participation by local ESRs, the court points out that, under Order No. 841, states retain their authority to prohibit local ESRs from participating in the interstate and intrastate markets simultaneously, “meaning states can force local ESRs to choose which market they wish to participate in.”
The court also emphasized that state and local regulators retain authority to impose restrictions on local ESR participation in wholesale markets, short of broadly prohibiting such participation, even if such requirements hinder FERC’s efforts to facilitate wholesale market participation by local ESRs.
Thus, for example, states retain their authority to impose safety and reliability requirements without interference from FERC, the court said.
The court also noted that states “will be free to challenge” Order Nos. 841 and 841-A as applied to their own state regulations or imposed conditions.
The court also responded to the argument made by APPA, EEI, NRECA and AMP that allowing state and local regulators to broadly prohibit local ESR participation would be preferable to the inevitable litigation over which state restrictions on local ESRs are permissible and which are not.
The court said that “Petitioners are likely correct that litigation will follow as states try to navigate this line, but such is the nature of facial challenges.”
The court also rejected the argument that FERC acted arbitrarily and capriciously by not applying to local ESRs the “opt-in/opt-out” framework that FERC applies to demand response resources. The court said that FERC’s decision to treat local ESRs different from demand resources was “neither unexplained nor unsupported.”
Order No. 841 was issued in February 2018
Order No. 841, issued in February 2018, adopted rules aimed at removing barriers to the participation of ESRs in wholesale power markets operated by RTOs and ISOs. At the time, several organizations, including APPA, asked FERC to reconsider some aspects of Order No. 841, arguing that FERC was overstepping its jurisdictional authority and encroaching on state and local authority over distribution utilities and networks.
APPA also argued that FERC should have given state and local authorities the ability to opt out of allowing ESRs in their jurisdictions from participating in wholesale markets, as the Commission did for demand response aggregation in Order Nos. 719 and 719-A. FERC largely rejected these arguments in Order No. 841-A, issued in May.
APPA’s Ditto, Patterson, EPB President and CEO David Wade Named To DOE Advisory Committee
July 2, 2020
Joy Ditto, President and CEO of the American Public Power Association, Delia Patterson, Senior Vice President of Advocacy and Communications and General Counsel at APPA, and David Wade, President and CEO of the Electric Power Board of Chattanooga, have been appointed to serve as members of the Department of Energy’s Electricity Advisory Committee (EAC).
Ditto, Patterson and Wade were three of 35 members of the EAC announced by the DOE on July 1. Twenty-two of the 35 appointed members of the EAC are returning members.
Each member of the EAC was appointed by U.S. Secretary of Energy Dan Brouillette for a two-year term.
The group reports to the DOE’s Assistant Secretary for Electricity and meets three times a year to advise DOE on a variety of electricity issues. The members of the EAC are from state governments, regional planning entities, utility companies, cyber security and national security firms, the natural gas sector, equipment manufacturers, construction and architectural companies, non-governmental organizations, and other electricity-related organizations.
During their two-year term, the EAC members will advise DOE on current and future electric grid reliability, resilience, security, sector interdependence, and policy issues. They will periodically review and make recommendations on DOE electric grid-related programs and initiatives, including electricity-related R&D programs and modeling efforts.
Members will also identify emerging issues related to electricity production and delivery and advise on federal coordination with utility industry authorities in the event of supply disruptions and other emergencies.
The thirty-five appointed members of the EAC began their term on July 1, 2020 and are listed alphabetically here.
FERC Commissioner McNamee Says He Intends To Serve For The Foreseeable Future
June 19, 2020
by Paul Ciampoli
APPA News Director
Posted June 19, 2020
Federal Energy Regulatory Commissioner Bernard McNamee on June 18 said that he intends to continue serving as a Commissioner for the foreseeable future.
He made his remarks at FERC’s monthly open meeting.
In January, McNamee announced that he would not seek another term at the Commission but said he would stay longer at the agency if needed. McNamee’s current term expires at the end of this month.
He is permitted to remain a Commissioner until a successor is confirmed or the end of the current Congress.
The U.S. Senate in December 2018 confirmed McNamee to join FERC as a Commissioner. McNamee, a Republican, previously served in several high-level positions at the U.S. Department of Energy, as well as at McGuireWoods LLP and the Texas Public Policy Foundation.
McNamee filled the seat on the Commission vacated by Robert Powelson, a Republican, who left the Commission to become President and CEO of the National Association of Water Companies.
Calif. CCA Group Concerned About Level Playing Field In Wake of Procurement Decision
June 15, 2020
by Paul Ciampoli
APPA News Director
Posted June 15, 2020
The California Community Choice Association (CalCCA), which represents community choice aggregators in the state, on June 11 expressed disappointment in a California Public Utilities Commission decision that designates Pacific Gas & Electric (PG&E) and Southern California Edison (SCE) as central buyers to procure local, multi-year resource adequacy.
In the wake of the CPUC decision, CalCCA said it remains concerned “that the playing field will not be level under such a framework, nor will it be transparent and neutral.”
CalCCA said it continues to support the terms of a settlement agreement that would have established a residual central buyer framework, and put a competitively neutral, independent and creditworthy entity in the role of central buyer.
CalCCA and several energy market stakeholders — Calpine Corporation, Independent Energy Producers Association, Middle River Power, NRG Energy, Inc., investor-owned San Diego Gas & Electric Company (SDG&E), Shell Energy North America, and the Western Power Trading Forum — reached the settlement agreement last year.
The parties in August 2019 filed a joint motion for adoption of the settlement agreement with the CPUC.
CalCCA argued that the June 11 CPUC decision:
* Is a significant departure from the current framework for ensuring local reliability;
* Limits the scope of costs that CCAs can control for their customers;
* Will have a significant effect on the resource adequacy (RA) market, moving from a market with many buyers of local RA to one dominated by PG&E and SCE;
* Will blunt incentives for CCAs to invest in “behind the meter” resource solutions, allocating costs to all customers on the same basis, regardless of the unique efforts of their load-serving entities; and
* While characterized as a “local RA” mechanism, it allows the central procurement entity to procure any associated system and flexible RA capacity with mandatory allocation of these rights to LSEs without sufficient time to position their portfolios for annual compliance.
CalCCA said that the settlement agreement would achieve the state’s aims by reducing the need for California ISO backstop procurement, maintaining and enhancing a liquid and robust bilateral capacity market, while also preserving the self-procurement autonomy of load-serving entities including community choice aggregators.
Details on CPUC decision
Under the PUC’s decision, beginning in 2021, PG&E and SCE will serve as the central procurement entities for their respective distribution service areas and begin procuring local resource adequacy for the 2023 compliance year.
The CPUC said its decision adopts a hybrid procurement model that tasks the central procurement entities with the responsibility to procure the entire amount of required local resource adequacy on behalf of all LSEs, while still allowing individual LSEs the opportunity to procure their own local resources.
If an LSE procures its own local resource, it may:
* Sell the capacity to the central procurement entities;
* Utilize the resource for its own system and flexible resource adequacy needs, or
* Voluntarily show the resource to meet its own system and flexible resource adequacy needs and reduce the amount of local resource adequacy the central procurement entities will need to procure for the amount of time the LSE has agreed to show the resource
The CPUC said that it is open to considering a compensation mechanism for local capacity requirement reduction achieved through shown local resources by LSEs.
The decision directed parties to form a working group to develop proposals for a local capacity requirement reduction compensation mechanism and the treatment of existing contracts.
The CPUC said it would address any proposed local capacity requirement reduction compensation mechanisms in a subsequent decision to be issued prior to the central procurement entities’ 2021 procurement (for the 2023 and 2024 compliance years).
SDG&E
With respect to SDG&E’s distribution service area, the decision declined to adopt the central procurement entities framework.
The PUC said it recognizes that the SDG&E service area is uniquely situated in that the local resource adequacy requirements, which must meet a higher reliability threshold than system capacity requirements, exceed the system resource adequacy requirements for most months of the year.
Given that local capacity procured by the central procurement entities would also count towards LSEs’ system resource adequacy requirements, LSEs would have very little procurement autonomy for system resource adequacy requirements if a central buyer were to procure all needed local capacity, the CPUC said.
Decision directs filing of independent evaluator report
In addition to directing the creation of a working group to develop a local capacity requirement reduction compensation mechanism, the decision directs an independent evaluator report to be filed annually with the central procurement entities’ compliance filing, “which will increase transparency into any gas-fired procurement by including the basis for any fossil fuel procurement that exceeds the minimum multi-year requirements,” the CPUC said in a news release.
The independent evaluator report will also assess the neutrality of the procurement process, any market power or aggregate pricing concerns, procurement of preferred resources (e.g., on what basis preferred resources were not selected), and consideration of disadvantaged communities in the procurement process, according to the CPUC.
The decision also directs the CPUC’s Energy Division to prepare a report assessing the effectiveness of the central procurement entities structure by 2025.
The proposal voted on last week by the PUC is available here.
The American Public Power Association has initiated a new category of membership for community choice aggregation programs.