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California Community Choice Aggregators Form Financing Authority

August 9, 2021

by Paul Ciampoli
APPA News Director
August 9, 2021

Four California community choice aggregators (CCAs) have jointly formed the California Community Choice Financing Authority (CCCFA), a joint powers agency that was created with the goal of reducing the cost of power purchases through a pre-payment structure.

Central Coast Community Energy, East Bay Community Energy, Marin Clean Energy and Silicon Valley Clean Energy are the founding members of CCCFA. CCCFA membership is open to CCAs in California that are interested in utilizing the joint powers agency for prepayment transactions.

Member agencies will be able to save 10% or more on power purchase agreements entered into under this structure, the four CCAs said.

The prepayments will allow CCAs to reduce customer costs, retain the green attributes of the renewable energy contract, and increase funding available for local programs, according to the CCAs.

Formation of CCCFA assists the member CCAs by undertaking the financing or refinancing of energy prepayments with tax-advantaged bonds. The prepay structure enables publicly owned utilities, including CCAs, to effectively leverage the difference between tax-exempt and taxable debt rates to fund the reduction in the cost of power purchases, they noted.

Prepayment transactions have been used in the United States for the last 30 years primarily for natural gas transactions. Over 90 municipal prepayment transactions totaling over $50 billion have been completed in the US, with over 95% of them for natural gas.

Prepayment transactions are codified in U.S. tax law and Congress enacted legislation specifically allowing for such transactions as part of the National Energy Policy Act of 2005. CCCFA will take advantage of this structure to increase the amount, and reduce the cost, of clean energy on the California grid, combating climate change and fulfilling customers’ needs for non-polluting resources, the CCAs said.

Energy prepayment transaction agreements undertaken by CCCFA must be approved by the Board of Directors of the member CCA proposing the prepayment. Then the CCCFA Board will have the opportunity to fully consider the benefits, obligations, and risks of each prepayment transaction prior to approving any bond issuance. CCCFA is governed by a Board of Directors consisting of one director representing each founding CCA.

The creation of CCCFA follows the formation of California Community Power earlier this year as a way to help CCAs across the state reduce costs.

Additional information about CCCFA is available here.

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

APPA, NRECA Urge FERC Not To Revoke Demand Response Opt-Out Mechanism

August 3, 2021

by Paul Ciampoli
APPA News Director
August 3, 2021

The Federal Energy Regulatory Commission (FERC) should not revoke a demand response opt-out mechanism because such a move would intensify concerns of state and local regulators that the Commission does not sufficiently accommodate their policy decisions, the American Public Power Association (APPA) and the National Rural Electric Cooperative Association (APPA) said in response to a notice of inquiry (NOI) issued by FERC earlier this year.

In their July 23, 2021, comments, APPA and NRECA urged the Commission not to rescind its regulations that require a regional transmission organization (RTO) or independent system operator (ISO) not to accept bids from an aggregator of retail customers (ARC) that aggregates the demand response of the customers of utilities that distributed more than four million megawatt-hours (MWh) in the previous fiscal year, in instances where the relevant retail regulatory authority (RERRA) prohibits such customers’ demand response to be bid into organized markets by an ARC (Docket No. RM21-14).  RERRAs include public power regulators.

APPA and NRECA said that the regulation, referred to as the Demand Response Opt-Out, remains valid and necessary for all of the reasons that it was initially adopted. “Moreover, elimination of the Demand Response Opt-Out at this time will likely cause adverse consequences and impose undue burdens on individual states and other RERRAs, as well as exacerbate the concerns of state and local regulators that the Commission does not sufficiently accommodate their policy decisions,” the trade groups argued.

 Therefore, the Demand Response Opt-Out should continue to apply as adopted in FERC’s Order No. 719, issued in 2008.  APPA and NRECA also argued that the Demand Response Opt-Out should apply to demand response resources included in “heterogenous” aggregations, i.e., distributed energy resource (DER) aggregations that are made up of different types of resources including demand response.

FERC Issued Order No. 2222-A, NOI in March

At its monthly open meeting in March 2021, FERC issued an order (Order No. 2222-A) that responded to requests for rehearing and clarification of FERC Order No. 2222, which addresses the participation of DER aggregations in markets administered by RTOs and ISOs. FERC approved Order 2222 in September 2020. Among the important features of Order No. 2222, FERC provided an “opt-in” mechanism for small distribution utilities — including most public power utilities.   This opt-in mechanism is not at issue in the NOI on the Demand Response Opt-Out.

At the meeting, FERC also issued the notice of inquiry on the potential impacts of eliminating the ability of states to choose whether demand response resources should participate in RTO/ISO wholesale markets.

FERC asked whether the circumstances relevant to this demand response opt-out have changed since the opt-out was established in Order Nos. 719 and 719-A, and what are the potential benefits or burdens of removing it.

The NOI sought comment on the following three general areas:

In Order No. 2222-A, FERC also found that demand response resources included in heterogenous aggregations would not be subject to the Demand Response Opt-Out.  FERC later retreated from this finding, saying it would consider the comments in the NOI proceeding before deciding the issue. 

As a number of parties pointed out in response to Order No. 2222-A, failing to apply the opt-out any time demand response resources are included in an aggregation with even one other type of DER would effectively negate the Demand Response Opt-Out and result in adverse consequences, NRECA and APPA told FERC in their NOI comments.

APPA, NRECA Warn of Adverse Consequences

In their comments, APPA and NRECA said that revoking the Demand Response Opt-Out will lead to the adverse consequences that Order No. 719 sought to avoid.

The trade groups said that the rationales for the Demand Response Opt-Out remain applicable today and should continue to be recognized by the Commission.

In Order No. 719, the Commission adopted the Demand Response Opt-Out in order to avoid interference with successful retail demand response programs, APPA and NRECA pointed out.

“The removal of the Demand Response Opt-Out at this time would likely threaten or upend existing demand response programs, in violation of the Commission’s assurance in Order No. 719 that its intent ‘was not to interfere with the operation of successful demand response programs,’” they went on to say.

“Notably, in the years since Order No. 719 was adopted, there has been growth in retail demand response programs, and participation in those programs,” APPA and NRECA said.

According to the Commission’s annual Assessments of Demand Response and Advanced Metering, retail demand response programs and/or customer enrollment in retail demand response programs has increased in the years since Order No. 719 was issued.

“These programs stand to be adversely impacted if the Commission removes the Demand Response Opt-Out at this time. This is a particular concern if demand response ARCs can ‘cherry-pick’ the loads or customers that will best advance their aggregation goals, such as industrial customers. Successful retail programs that are providing benefits to all end-use customers might be relegated to residual programs, with larger loads opting for the wholesale demand response programs through an ARC. Such an outcome would be an unjustified departure from the Commission’s stated intent not to interfere with successful demand response programs,” the trade groups told FERC.

APPA and NRECA said that these existing programs should be accommodated and respected in the Commission’s policies.

Impact On RERRAs

APPA and NRECA said that FERC’s rationale for the Demand Response Opt-Out, to avoid placing an undue burden upon state and local regulatory entities, also remains a valid concern. “The removal of the Demand Response Opt-Out at this time would reintroduce the concerns over displacing state and local authority and imposing undue burdens on retail regulators. With demand response as the most prevalent form of distributed energy resource, managing the impact of demand response aggregators could impose a significant burden on state and local regulatory authorities, after the Commission expressly stated it would not do so.”

If the Demand Response Opt-Out is abandoned now, the burden will be placed on state and local authorities and other RERRAs to take affirmative action to address the myriad regulatory issues that may be raised by ARCs, the groups said.

FERC has previously determined that RERRAs should have the authority if they so choose, to decide whether existing retail aggregation programs provide benefits and whether retail customer participation in wholesale demand response programs, individually or through an ARC, would adversely affect those programs and, if so, whether and how to permit such participation. “APPA and NRECA submit that there are no changed circumstances that justify depriving state and local regulators of this authority by eliminating the Demand Response Opt-Out.”

Costs For End-Use Consumers

APPA and NRECA said that as they “have often reminded the Commission, the focus in all of these efforts must remain reasonable costs to end-use consumers.”

FERC determined in Order No. 719 that RERRAs are in the best position to make determinations whether retail versus wholesale demand response programs are effective, and the role aggregation should play.

“APPA and NRECA submit that the RERRAs remain in that position. The fact that the Commission has in the interim determined in other instances not to abide by this policy of cooperative federalism does not render it inapplicable or not useful in ensuring just and reasonable rates for end-use customers.”

The Commission “should not yet again seize from RERRAs their authority to balance new technologies, maintain grid reliability, and protect consumers from unaffordable costs, particularly since the Commission specifically preserved that authority with the Demand Response Opt-Out.”

Infrastructure Bill Excludes Provisions Encouraging Sale Of Public Utilities

August 3, 2021

by Paul Ciampoli
APPA News Director
August 3, 2021

The Infrastructure Investment and Jobs Act includes a number of provisions of importance to public power utilities including in areas related to cybersecurity and electric vehicle infrastructure. At the same time, it does not incorporate provisions encouraging the sale of public utilities and other revenue generating assets as a way to fund additional infrastructure investments.

The Senate on Aug. 1 began debate on the legislative text, called the Infrastructure Investment and Jobs Act, of an infrastructure framework negotiated over the last several weeks between 22 Democratic and Republican senators.

An initial draft of the senators’ Bipartisan Infrastructure Framework had listed so-called asset recycling as an area of agreement, and opposition to this proposal was a top priority for the American Public Power Association (APPA). Joy Ditto, President and CEO of APPA, on July 14 wrote to President Joseph Biden in opposition to using infrastructure funding legislation to encourage the privatization of public facilities.

The text of the agreement does not incorporate provisions encouraging the sale of public utilities and other revenue generating assets as a way to fund additional infrastructure investments.

Details On Infrastructure Investment and Jobs Act

A section of the bill establishes a grant program at the Department of Transportation to provide grants to eligible entities, including public power, for the deployment of electric, hydrogen, propane, or natural gas vehicle infrastructure along designated Alternative Fuel Corridors. Entities are required to contract with a private entity for the acquisition and installation of fueling infrastructure and may use a portion of grant funds to pay a private entity to operate and maintain the infrastructure for up to five years and/or to enter into a cost-sharing agreement with the private entity.

Fifty percent of the overall funding is set aside for “Community Grants” for which public power would also be eligible. These grants do not require, but allow for, partnerships with private entities and can be used to deploy fueling infrastructure in public locations, including parking facilities, public buildings, public schools, and parks. This section is based on the Clean Corridors Act, which APPA supports.

Another section of the legislation would require the Secretary of Energy, in consultation with state regulatory authorities, industry, the Electric Reliability Organization, and other relevant federal agencies, to carry out a program to promote and advance the physical security and cybersecurity of electric utilities, with priority provided to utilities with fewer resources. This section of the bill also requires a report to Congress on improving the cybersecurity of electricity distribution systems.

APPA is supportive of this provision. It is modeled upon an existing, successful public-private partnership funded by DOE’s Office of Cybersecurity, Energy Security, and Emergency Response Cybersecurity for Energy Delivery Systems program between the department and APPA to bring greater resources, training, and tools for cyber and physical security to small- and medium-sized electric utilities.

The bill would also authorize $500 million for the period of fiscal years 2022 through 2026 for a state energy program for state, local, and Tribal governments to support transmission and distribution planning, including feasibility studies of line routes and alternatives, preparation of necessary project designs and permits, and outreach to affected stakeholders.

The legislation would also increase the borrowing authority made available to the Bonneville Power Administration under the Federal Columbia River Transmission System Act by an additional $10 billion.

In addition, the bill calls for the establishment of a new Treasury account for the purposes of making expenditures to increase bilateral transfers of renewable electric generation between the United States and Canada — $100 million is authorized to be appropriated to carry out the relevant subsection of the bill, which is specified as non-reimbursable.

The bill also directs a study of the potential hydroelectric power value to the Pacific Northwest of increasing the coordination of the operations of hydroelectric and water storage facilities on American and Canadian rivers.

Also, the bill would appropriate $500 million to the Western Area Power Administration for the purchase of power and transmission services.

California Grid Operator Issues Call For Power Conservation

July 28, 2021

by Paul Ciampoli
APPA News Director
July 28, 2021

The California Independent System Operator (CAISO) issued a call for voluntary electricity conservation, for Wednesday, July 28, due to predicted high energy demand and tight supplies across the West.

With higher-than-normal temperatures in the forecast for parts of interior Northern California, the power grid operator on July 27 said it was predicting an increase in electricity demand, primarily from air conditioning use.

CAISO issued the statewide Flex Alert for 4 p.m. to 9 p.m.

A Flex Alert is issued by CAISO when the electricity grid is under stress because of generation or transmission outages, or from persistent hot temperatures.

“Consumers are urged to conserve electricity, especially during the late afternoon and early evening, when the grid is most stressed due to higher demand and solar energy production falling,” the grid operator said. “Consumers are also asked to turn off unnecessary lights, delay using major appliances until after 9 p.m., and set air conditioner thermostats to 78 degrees or higher, if health permits.”

CAISO in a July 28 system conditions bulletin said that several conditions were impacting the grid.

“While the temperature forecast is slightly above normal for parts of California, and demand is projected to be moderately high, there are weather and demand uncertainties, which affects our forecasting data,” it said.

“We are also monitoring several wildfires in and outside of California that could threaten generation and transmission, limiting energy supplies. And there is always the possibility of equipment failure and forced outages on the system,” CAISO said.

“All of these conditions taken alone would normally have minor impacts to the grid, but as the power grid operator, the ISO must plan for unexpected events, such as wildfires or forced line or plant outages, that could whittle into energy supplies and affect grid reliability. To keep the grid stable, the ISO is asking Californians to reduce electricity use from 4 to 9 p.m. today, the critical time of need on the system, when solar production is ramping down and electricity demand can remain high. If everyone makes some small adjustments, the extra supplies can act as a shock absorber in case of unexpected events today,” the July 28 system conditions bulletin said.

“The ISO is not anticipating any rotating power outages at this time. We believe consumer conservation will be key to getting through the most critical period this evening.”

The ISO said it would decide if another Flex Alert is needed for Thursday, July 29, following the close of the market on the afternoon of July 28 and a review of updated weather forecasting.

Earlier this month, a rapidly growing wildfire in Oregon – the Bootleg Wildfire – that threatened transmission lines used to import energy to California and extreme heat throughout California pressured California’s electric grid, prompting CAISO to extend a statewide Flex Alert.

San Francisco Asks CPUC To Determine Value Of PG&E’s Local Electric Assets

July 28, 2021

by Paul Ciampoli
APPA News Director
July 28, 2021

The City and County of San Francisco on July 27 submitted a petition with the California Public Utilities Commission (CPUC) seeking a formal determination of the value of investor-owned Pacific Gas & Electric’s local electric infrastructure, the next step in San Francisco’s efforts to acquire the utility’s city-based electric facilities and complete the city’s transition to public power. 

“Owning the grid would allow San Francisco to provide clean, reliable and affordable electricity throughout the City while also taking meaningful climate action, like reaching its set target of using 100% renewable electricity by 2025,” the Office of San Francisco Mayor London Breed noted in a news release.

The move comes after the city made a $2.5 billion offer in 2019 to purchase PG&E’s local electric assets. San Francisco resubmitted its offer when PG&E emerged from bankruptcy in 2020. PG&E rejected both San Francisco purchase offers.

“San Francisco is ready to transition to full public power, and today we are asking the CPUC to determine a fair price that will allow us to move forward with the acquisition of our local power grid,” said Breed in a statement. “It’s been clear for a long time that full public power is the right choice for our city and our residents, and we know we can do this job more safely, more reliably, and more cost effectively than PG&E. It’s time for everyone in the city to have access to clean, reliable, affordable public power.”

“Generally, electric service provided by publicly-owned utilities is more affordable than service from investor-owned utilities,” the petition noted. “This is due to factors such as the absence of large executive bonuses, shareholders, and taxes.”

Transitioning to public power has public support. A 2019 poll found that nearly 70% of San Franciscans support switching to public power.

In the valuation petition filed by City Attorney Dennis Herrera, the city asks the CPUC to determine the just compensation to be paid for PG&E’s electricity distribution assets that serve San Francisco. State law gives the CPUC the authority to set definitive valuations for utility assets. San Francisco’s petition also proposes a process for the Commission to assess the value of PG&E’s electric facilities.

Breed’s office noted that San Francisco has demonstrated its effectiveness as a local power provider for more than 100 years, delivering hydropower from Hetch Hetchy Power to customers like the San Francisco International Airport, the San Francisco Zoo, and Zuckerberg San Francisco General Hospital. The San Francisco Public Utilities Commission’s (SFPUC) CleanPowerSF program also purchases renewable power for over 370,000 homes and businesses. Collectively, the two programs provide more than 70% of the electricity consumed in San Francisco.

San Francisco has also set a goal of shifting to 100% renewable electricity by 2025 and 100% renewable energy by 2040, a target that will be easier to achieve if San Francisco had local control of its power grid.

San Francisco would use bonds secured by future revenues from electricity generation to acquire PG&E’s infrastructure, so no funds for existing city services, like affordable housing, libraries or addressing homelessness, would be affected.

In the valuation request, San Francisco said that PG&E’s “ongoing problems with providing safe and reliable gas and electric service throughout its service territory are well-known.” The city noted that the CPUC has acknowledged that PG&E’s recent history of safety performance “has ranged from dismal to abysmal.”

While San Francisco has not experienced the devastation associated with catastrophic wildfires and other disasters caused by PG&E, “over the years PG&E’s difficulty in maintaining a safe and reliable system has caused multiple incidents resulting in injuries and property damage within the city,” the petition said.

“PG&E customers in San Francisco, like PG&E’s other customers, have also paid substantial costs resulting from PG&E’s physical and financial disasters, including two bankruptcies in as many decades,” the city said.

The city also said that while San Francisco’s acquisition of PG&E assets in San Francisco would benefit the city and its residents, such an acquisition would not materially burden PG&E’s remaining ratepayers and could potentially benefit them as well.

The petition pointed out that San Francisco is a small part of PG&E’s large service territory and PG&E’s revenues per San Francisco customer are smaller than its revenues per PG&E customer outside the city. “The size of PG&E’s remaining service territory would be reduced along with its service obligations. This alone could benefit remaining ratepayers as PG&E would no longer have any expenses or service obligations related to the upkeep — and future capital needs — of the assets purchased by San Francisco.”

Acquisition of PG&E’s property serving San Francisco will provide numerous benefits, the petition said, including enabling the city to provide affordable, safe, and reliable service, and take meaningful environmental and climate action; and improve its programs to ensure workforce development and equity.

“Electric service provided by the city would also be more transparent and accountable to customers,” the city said, noting that bi-weekly meetings of the SFPUC are open to the public.

In addition, rate setting decisions are governed by the city’s charter, which requires independent review, and are subject to rejection by the Board of Supervisors. And SFPUC Commissioners are appointed by the mayor, subject to approval by the Board. “Ultimately, the mayor and board are directly accountable to the voters.”

The petition said that the city developed the two formal offers to PG&E to purchase the assets the city would need to serve San Francisco customers with the advice of experts using standard methods of asset valuation.

“In its responses, PG&E claimed that the city’s offer price was far below the value of the assets. The city seeks to fix the value of the targeted assets using the Commission’s unique expertise under authority granted to the Commission by state law. The city hopes that establishing a definitive value will facilitate negotiation of an acquisition transaction with PG&E.”

Ditto Outlines Opposition To Using Legislation To Encourage Public Facility Privatization

July 20, 2021

by Paul Ciampoli
APPA News Director
July 20, 2021

American Public Power Association (APPA) President and CEO Joy Ditto on July 14 wrote to President Joseph Biden in opposition to using infrastructure funding legislation to encourage the privatization of public facilities.

“In general, privatizing public projects reduces local control, increases costs by providing a higher rate of return for investors, and, contrary to the perception, does nothing to increase project funding, which ultimately comes from residents of the community,” wrote Ditto in the letter. “As a result, while communities should consider all alternatives when assessing their infrastructure, the federal government should not tip the scales of those decisions by favoring privatization,” she said.

Ditto highlighted her concern over “the troubling bipartisan, bicameral interest in the federal government paying states, counties, and cities to sell their roads, bridges, and utilities to raise short-term cash for other infrastructure repairs. This so-called ‘asset recycling’ arguably failed in Australia – just four out of 16 Australian states and territories participated, and the program ended with unspent funding – and has failed to take off elsewhere.”

Ditto said in the letter that a comprehensive review of objective, data-based analyses “shows that up-front costs of privatized projects tend to be higher for several reasons, including higher transaction costs and higher financing costs. These analyses also find that real value of privatization is the extent to which the seller can shift risks onto the buyer, and that shifting those risks — which can reduce later profits — can be quite difficult to do.”

Lackluster results “may be driving declining public interest in privatization of infrastructure globally,” she wrote. Ditto pointed out that since 2006, the number and dollar value of new privatized projects has fallen by more than 70 percent in Europe, according to the European Investment Bank. Outside Europe, the number and dollar value of privatization projects in 2019 were roughly half what they were in 2012, according to the World Bank.

“Conversely, private investment in U.S. infrastructure made through the purchase of tax-exempt municipal bonds has rebounded since 2011: more than $2 trillion in new investments in the last decade and $300 billion in 2020 alone. Most municipal bonds are held by retail investors, such as retirees, union workers, and average American workers with 401k plans, who receive a rate of return commensurate with the relatively low risk.”

Privatizing public facilities “will not get the private sector ‘off the bench.’ Often, privatized project financing comes from investors purchasing private activity bonds instead of municipal bonds. And, insofar as overseas investors or private equity firms are providing a new pool of financing, they are replacing traditional investors, but demanding a much higher rate of return,” Ditto said.

“Likewise, one governor recently defended a privatized express lane project saying it will ‘cost the state nothing.’ But, of course the ‘state’ itself never pays for anything, people do through income taxes, sales taxes, and user fees. Privatizing a public facility doesn’t change that, except perhaps to increase the costs paid as I discussed above.”

Ditto said she takes it “as good news that it appears that in discussing asset recycling, policymakers are not discussing the sale of federal assets, such as the Power Marketing Administrations (PMAs) and the Tennessee Valley Authority (TVA).”

The costs to run the PMAs and TVA are paid by customers and not the federal government and none of the costs are borne by taxpayers. “Furthermore, there is no factual evidence that selling the transmission assets of the PMAs would result in a more efficient allocation of resources. Rather, it is much more likely that any sale of these assets to private entities would result in attempts by the new owners to charge substantially increased transmission rates to PMA customers for the same service they have historically received,” Ditto wrote.

Granholm Details How Public Power Can Work With The Department of Energy In Key Areas

July 15, 2021

by Paul Ciampoli
APPA News Director
July 15, 2021

Secretary of Energy Jennifer Granholm on July 14 detailed how the Department of Energy (DOE) and the public power community can work together in a number of areas including research, development and deployment (RD&D) programs, as well as the country’s clean energy transition.

Granholm made her remarks in a Q&A with Colin Hansen, chair of the American Public Power Association Board of Directors, at APPA’s National Conference Virtual Event.

Given the Biden Administration’s push for the power sector to get 100 percent of its electricity from zero-emitting resources, Hansen asked Granholm to detail what DOE plans to do to specifically help public power utilities in this clean energy transition “that will importantly ensure that electricity remains both affordable and reliable.”

“We totally want to partner,” Granholm said.

She noted that in October, DOE will begin a five-year, one-and-a -half-million dollar agreement with APPA “so we can work together on practical strategies to make the grid cleaner and more resilient and more reliable and affordable.”

Granholm also noted the partnership that many APPA members have with DOE’s power marketing administrations “to provide that affordable and reliable power.”

She said that as part of DOE’s new initiative to reduce the cost of grid-scale, long duration energy storage by 90% within the decade, “we’re going to work with stakeholders, including public power utilities, to make sure that the new long duration storage solutions can meet” the needs of public power utilities in an affordable way.

Turning to a different topic, Hansen noted that at the end of last year, the Energy Act of 2020 was signed into law, authorizing billions of dollars in RD&D programs over the next decade. APPA supported the legislation, particularly because DOE RD&D programs would be open to public power.

Hansen asked Granholm to discuss how public power utilities can participate in, and benefit from, RD&D efforts at DOE, particularly smaller public power utilities.

The Secretary of Energy said that DOE has already mobilized $1.5 billion for clean energy deployment and RD&D “just this year in this administration.”

Granholm said that “a lot of this work is happening at the labs and through our efforts with states and utilities including on grid modernization and energy efficiency. We’re also supporting demonstration projects – emerging zero carbon technologies like carbon capture and advanced nuclear.”

She said that passing President Biden’s Build Back Better agenda overall through Congress “would give us so many more resources for all of this work for partnerships with utilities large and small. We want to share the resources, the funding, the innovation, the insights with you to work together to test and deploy these solutions” that public power is looking for.

Meanwhile, Hansen noted that in September 2020, DOE’s Office of Cybersecurity, Energy Security and Emergency Response awarded APPA a grant of $6 million over a three-year period to develop and deploy cyber and cyber-physical threat solutions for public power utilities.

“Through this cooperative agreement, we’re going to continue to work with APPA to develop and to deploy these cyber solutions for public power utilities,” Granholm said.

Hansen, executive director of Kansas Municipal Utilities (KMU) in McPherson, Kansas, was installed as chair of APPA’s Board of Directors during APPA’s National Conference in Orlando, Florida, on June 23.

Real-Time Grid Assessment Is Adequate But Could Be Improved: FERC-NERC Report

July 13, 2021

by Peter Maloney
APPA News
July 13, 2021

Operators of the bulk power system are prepared to manage  assessment of real-time grid operating conditions, but they should develop alternative procedures in the event of data loss failures lasting more than two hours, according to a report issued last week by the staff of the Federal Energy Regulatory Commission (FERC) and the North American Electric Reliability Corporation (NERC) and its regional entities.

Real-time assessment requirements in NERC standards mandate that transmission operators and reliability coordinators perform an assessment at least once every 30 minutes to ensure prevention of instability, uncontrolled separation, or cascading outages that could adversely impact the reliability of the interconnection.  The report detailed these requirements and provided further recommendations for real-time assessments of grid operating conditions.

NERC developed the existing standard requirements in the wake of the 2011 Southwest blackout report to ensure that real‐time tools are adequate, operational, and used frequently enough to provide system operators with the situational awareness needed to identify and plan for contingencies and to reliably operate their systems.

Among the primary causes of the 2003 Northeast blackout was the failure to assess and understand the real-time risks to the grid. The current real-time assessment requirements are a direct result of that finding, NERC says.

The real-time assessment review was not a compliance activity. It included on-site discussions with representatives of nine participating reliability coordinators and transmission operators. The purpose of the review was to work with subject matter expert participants and technology leaders in a collegial environment. The underlying intent, according to the report, was that understanding operational challenges enhances regulatory oversight.

Among other findings, the report found that as the penetration of renewable generation and inverter-based resources increases, transmission system operators should be prepared to augment existing tools to facilitate reliable operation planning that includes renewable forecasting.

Among other recommendations, the report said reliability coordinators and transmission operators should:

The review team also found that all participants have processes for identifying problems with quality of individual real-time data points and have procedures for correcting the errors.

However, only a few of the participants have developed metrics to trend aggregate real-time data errors with thresholds identifying when errors are reaching levels that would impair the quality of the real-time assessment, the report found.

California Grid Pressured By Heat Wave, Oregon Wildfire That Threatens Transmission Lines

July 12, 2021

by Paul Ciampoli
APPA News Director
July 12, 2021

A rapidly growing wildfire in Southern Oregon that threatened transmission lines used to import energy to California, along with continued extreme heat throughout California, put new stresses on the electric grid, the California Independent System Operator (CAISO) reported over the weekend.

CAISO on Saturday, July 10, extended a statewide Flex Alert for a second consecutive day and strongly encouraged consumers to conserve as much electricity as possible from 4 p.m. to 9 p.m. to help keep the grid stable.

Conditions on the electric grid were already a challenge Friday, July 9, when much of California was experiencing triple-digit temperatures, some generating capacity was not available and a Flex Alert was called for the late afternoon and evening, the grid operator noted.

ISO data show demand for electricity did start to drop once Friday’s Flex Alert was in effect and consumer conservation began to take hold. But conditions deteriorated quickly as the Bootleg Fire continued to grow and posed an imminent threat to transmission lines leading into the California Oregon Intertie (COI).

The COI is not only used to import electricity from the Pacific Northwest to the electric grid managed by the ISO, it also imports power into other grid balancing authorities and the state of Nevada, the grid operator noted.

“The fire has been a wildcard for grid operators since it began Tuesday in rural Klamath County reportedly from a lightning strike. The wind-driven blaze, which has forced evacuations and is not projected to be contained for another two weeks, had burned a little less than 40,000 acres by Friday, nearly doubling in size from the day before,” CAISO said.

By Saturday morning, it had nearly doubled in size again and burned more than 76,000 acres.

On Friday afternoon, the ISO issued a formal grid warning, which gives the grid operator authority to initiative emergency demand response programs that compensate electricity customers for conserving. That warning was canceled at 10 p.m. Friday, about the time demand for electricity is typically low.

On Sunday, July 11, CAISO said that with electric transmission lines from Oregon still unreliable due to the Bootleg Fire and continued high temperatures across the West resulting in increased demand for electricity, it was issuing a statewide Flex Alert for Monday, July 12 to help stabilize the state’s electric grid and deal with uncertainty created by the extraordinary conditions. Consumers were also strongly encouraged to continue to conserve as much electricity as possible between 4 p.m. and 9 p.m.

In addition, the ISO issued a Restricted Maintenance Operations for Monday that requires generators to postpone any planned outages for routine equipment maintenance, ensuring that all available resources can be dispatched to the grid.

The fast-moving Bootleg Fire tripped off transmission lines on Friday and again Saturday, limiting electricity flow from the Pacific Northwest to California and other states. Power supplies to the California ISO service territory, which covers about 80 percent of the state, have been reduced by as much as 3,500 megawatts because of the fire.

California governor signs order to free up additional energy capacity

California Gov. Gavin Newsom on Saturday, July 10, signed an executive order to free up additional energy capacity.

Building on Newsom’s emergency proclamation on July 9 which suspended certain permitting requirements to enable the use of back-up power generation, the July 10 order allows the emergency use of auxiliary ship engines to relieve pressure on the electric grid.

Public power plays its part to help alleviate stress on grid

Meanwhile, public power utilities in the state have been proactively working to help alleviate stress on the grid by reminding customers of the ways in which they can help.

For example, in a Saturday night tweet, the Los Angeles Department of Water and Power (LADWP) said that “Every bit of energy conservation will help the state power grid right now. A statewide #FlexAlert is in effect until 9 pm tonight. Hold off on the laundry for a bit longer, set AC thermostats to 78 and turn off unnecessary lights and appliances. Thanks LA!”

For its part, SMUD in a tweet said it was asking customers to limit electricity usage in the afternoon of Saturday, July 10, and through the weekend. “The Bootleg Fire in Oregon is impacting critical transmission lines and has reduced imported energy. We’ll use every measure to keep the lights on, but power shortfalls are possible,” SMUD said.

The public power utility said that customers can help by doing the following:

ELCON Asks Congress To study How Wholesale Markets Have Affected Consumer Prices

July 9, 2021

by Peter Maloney
APPA News
July 9, 2021

The Electricity Consumers Resource Council (ELCON), leading a coalition of 11 organizations, on July 8 sent a letter to Congressional leaders calling for an independent study on the impacts on consumers of wholesale electric power markets under the jurisdiction of the Federal Energy Regulatory Commission (FERC).

The letter requests that the Congressional leaders direct the Government Accountability Office (GAO) or other independent oversight organization “to undertake a detailed and objective study of the cost of electricity” and specifically of how FERC policies regarding wholesale power markets impact the cost and reliability of delivered power.

“We need regulators who base their policy decisions on objective data and real-world impacts rather than assumptions by advocates,” the signatories said in the letter.

While FERC commissioned a report on the benefits of wholesale competition in the Entergy region in 2010, that study looked at future prices, not actual historical costs and benefits. “To our knowledge, no one has studied the impacts of RTOs [regional transmission organizations] on customer bills,” the letter said.

“Government studies published more than a decade ago regarding wholesale markets claimed to lack the necessary data—the time is right to revisit these issues with fresh data so we can have an informed debate about the impacts of wholesale markets on consumers,” Travis Fisher, president and CEO of ELCON, said in a statement.

ELCON is a national association of large industrial consumers of electricity. ELCON was joined in the request by other industrial consumer advocates, as well as public policy organizations, including Energy Choice Coalition, Public Citizen, Conservative Energy Network, Industrial Energy Consumers of Pennsylvania, Louisiana Energy Users Group, and R Street Institute.

The letter was addressed to the leaders of the energy committees of both the Senate and the House of Representatives. It was also copied to the chairman and commissioners of FERC.

“At minimum,” the letter’s authors said, the study “should examine how existing RTO market structures have impacted the cost of electricity to retail consumers. We also ask that the study explore the reliability impacts of wholesale market structure and, if resources allow, develop a set of best practices regarding RTO expansion.”

The letter cited a letter by nine former FERC chairmen and commissioners who advocated for an expansion of RTOs.

Saying that the requested study is “long overdue,” the signatories also cited a 2008 study in which the GAO said, “there is no consensus about whether RTO markets provide benefits to consumers or how they have influenced consumer electricity prices.”

With “no guidance from federal regulators, states and regions are independently exploring the impacts of RTOs,” the letter says, citing proceedings under way in North Carolina, South Carolina, Colorado, Nevada, Missouri, and Oregon.

Many of those battles are primarily between incumbent utilities and “a growing chorus of consumers who want more choice, better access to new technologies, or less exposure to the ratepayer risks associated with monopoly utilities,” the signatories said.

The issue is not matter of “historical trivia,” the signatories said, but is “more important than ever” because of three trends: discussions about the voluntary or mandatory expansion of RTOs, state and federal policies driving changes in resource mix that will require large spending increases in transmission infrastructure, and increased electrification to the economy.