Federal Energy Regulators Schedule PJM Interconnection Capacity Market Forum for June

April 21, 2023

by Paul Ciampoli
APPA News Director
April 21, 2023

The Federal Energy Regulatory Commission on April 19 said it will convene a Commissioner-led forum to examine PJM Interconnection’s capacity market on June 15, 2023.

The forum will include three panels to solicit perspectives on the current state of the PJM capacity market, potential improvements, and related proposals to address resource adequacy. 

The first panel, an overview panel, will explore whether the PJM capacity market is achieving its objectives of ensuring resource adequacy at just and reasonable rates.

The second panel, a technical panel, will discuss potential market design reforms that may be needed to ensure PJM’s capacity market is achieving its objectives. 

The third panel, a roundtable with state representatives (including state Commissioners), will discuss their views and respond to the first and second panels’ discussions.

Additional detail on these topics and panels will be shared in subsequent notices.

FERC’s notice also invited individuals interested in participating as panelists to submit self-nominations by 5:00 p.m. Eastern Time on April 28, 2023 in accordance with instructions in the notice.

New England Again Sets Record for Low Demand on Regional Power System

April 13, 2023

by Paul Ciampoli
APPA News Director
April 13, 2023

For the second time in as many years, New England has seen record low demand for grid electricity. Preliminary data shows that demand for grid electricity hit a low of approximately 6,814 megawatts between 2 and 3 p.m. on April 9, nearly 750 MW less than the previous record of 7,580 MW set on May 1, 2022, ISO New England reported.

Sunny skies, mild temperatures, and a Sunday holiday were key factors in the new record, the grid operator said.

Sundays typically see lower electricity demand than other days of the week, and the Easter holiday has historically led to even lower consumer demand, ISO-NE said.

On April 9, temperatures were mild across New England, further lowering overall demand for electricity in the region. Production from behind-the-meter solar resources was estimated to be more than 4,500 MW throughout much of the afternoon, tempering demand on the bulk power grid.

The record low demand is just one example of the continued impact of rooftop solar installations in New England.

The region set a record in 2022 for so-called “duck curve” days, during which demand from the bulk power system is at its lowest in the afternoon hours and not overnight, and is on pace to surpass that mark in 2023.

ERCOT Winter Peaks More Erratic, Partly Spurred by Electrification, Study Finds

April 13, 2023

by Peter Maloney
APPA News
April 13, 2023

Peak winter electric demand growth in the Electric Reliability Council of Texas has become more erratic, signaling potential concerns for system planners, according to a new study.

While summer peak demand growth has been generally stable and approximately linear with time, winter peak demand growth has been less consistent, the researchers from the Walker Department of Mechanical Engineering at the University of Texas at Austin found in the paper, Perspectives on peak demand: How is ERCOT peak electric load evolving in the context of changing weather and heating electrification?, published in The Electricity Journal.

The more erratic nature of winter peak demand likely reflects the wide variance of winter temperatures during peak demand days compared with the fairly constant summer temperatures during peak days, the researchers said. The erratic nature of winter peak demand is also likely caused by the fact that electrical heating equipment becomes increasingly inefficient at lower temperatures, they added.

In addition, historical winter peak demand has been growing more quickly than summer peak demand, which is likely the result of increases in electrical efficiency of cooling and increases in electricity consumption that result from the rising penetration of electrical heating equipment replacing gas furnaces, the study found.

The study used historical Electric Reliability Council of Texas demand data from 1997 to 2021 along with weather data for the days in which peak demand occurred and from a future climate scenario.

“Future peak demand scenarios indicate that winter peak demand will remain more erratic and will sporadically surpass summer peak demand between 2025 and 2050,” the researchers wrote, adding “resource planners in ERCOT should place less certainty on winter peak demand projections and an increased level of winter preparedness on both the supply and demand sectors appears warranted for resource planners.”

The study’s findings might foreshadow “future resiliency challenges that other regions will face as electric heating equipment is deployed in place of boilers or furnaces for decarbonization purposes,” the researchers wrote.

Virtual Power Purchase Agreements Draw Increasing Interest from Corporations

April 13, 2023

by Paul Ciampoli
APPA News Director
April 13, 2023

Virtual power purchase agreements are drawing increased interest from U.S. corporations looking to grow their renewable energy portfolios.

With a virtual PPA contract, the corporate buyer does not own and is not responsible for the physical electrons generated by the project, energy group RMI notes.

In a report released in February examining global renewable energy purchase trends, BloombergNEF said that private companies and public institutions signed contracts to secure a record 36.7 gigawatts of renewable power to power their operations in 2022, up 18% from 2021.

“In the U.S., companies embraced the virtual PPA model under which a clean power project sells directly into the wholesale market to capture the spot price, rather than literally delivering its electrons directly to the customer,” the report said. “Such contracts are comparatively easy for buyers to sign and allow them to hedge against power price spikes,” BloombergNEF said.

The primary advantage of a virtual PPA lies in its flexibility, the American Cities Climate Challenge notes on its website. The American Cities Climate Challenge, sponsored by Bloomberg Philanthropies, was formed with an investment of $70 million “to enhance the work already being done by mayors across the U.S. and to support cities in the fight against climate change,” it says.

The flexibility offered by virtual PPAs “has made them the favored large-scale renewable energy procurement mechanism for large companies in the U.S.”

McDonald’s, Other Corporations Enter Virtual PPAs

McDonald’s has been a major player among corporations entering into virtual PPAs.

In late 2019, McDonald’s announced the signing of two long-term, large-scale virtual power purchase agreements under which McDonald’s agreed to buy renewable energy generated by Aviator Wind West, a wind power project located in Coke County, Texas and a solar project located in Texas.

More recently, McDonald’s entered into a number of virtual PPAs in 2022.

In September of that year, EDF Renewables North America announced a 15-year virtual PPA with McDonald’s tied to a solar project in Texas that is scheduled to come online in 2024.

In December 2022, McDonald’s and all five members of the restaurant chain’s North American Logistics Council signed agreements with Enel North America to purchase renewable energy and the associated renewable energy certificates from Enel Green Power’s Blue Jay solar project in Grimes County, Texas.

The virtual PPAs are for 189 MW from Enel’s Blue Jay solar project, which is expected to be fully operational in 2023.

In February, EDF Renewables North America announced the execution of a 20-year virtual power purchase agreement with Thermo Fisher Scientific. The virtual PPA covers the full output of the 200-MW Millers Branch Solar Project, which is located in Texas and slated for commercial operation in December 2025.

Another corporation embracing virtual PPAs is Campbell Soup. In November of last year, Campbell Soup and Enel North America announced a 12-year virtual renewable PPA.

Through the agreement Campbell will purchase the electricity and the associated renewable energy credits from a 115-MW share of Enel’s Seven Cowboy wind project in Oklahoma.

Meanwhile, earlier this month, Duke Energy Sustainable Solutions reported that the 250-MW Pisgah Ridge Solar project in Navarro County, Texas, came online.

Charles River Laboratories International has a virtual power purchase agreement for 102 MW of the project over the next 15 years. Midwest retailer Meijer signed a separate 15-year virtual PPA agreement for 83 MW of solar energy generated by the Pisgah Ridge Solar project. One other company has a third 15-year virtual PPA agreement. Together, the three agreements account for more than 90% of the facility’s output.

All three virtual PPAs associated with the site will settle on an as-generated basis tied to the project’s real-time energy output.

Why Texas?

“Several factors have made Texas an attractive market for renewable energy development and virtual PPAs,” Greg Rizzo, Head of PPA and Renewable Energy Solutions at Enel North America, told Public Power Current.

Strong solar and wind resources, land availability, transmission investments “and straightforward permitting have enabled Texas to produce more renewable electricity – and associated RECs – than any other state. Texas’ deregulated, wholesale market with spot power prices has facilitated a robust market for VPPAs,” he said.

“However, this environment may be jeopardized by pending legislation in the Texas Legislature, which would undermine the state’s nation-leading renewables sector by increasing regulation and costs,” Rizzo said.

Fixed-Priced Virtual PPA

In February, Ever.green announced that it was partnering with Watershed, a climate platform, to launch the first fixed-price virtual PPA.

The long-term commitments of Watershed customers including Samsara, Stripe, and TaskUs will help build a new solar plant in Laredo, Texas.

The new fixed-price virtual PPA developed by Ever.green and Watershed allows companies to fix their long-term costs. This eliminates exposure to the volatile pricing inherent to a traditional virtual PPA, while still increasing a project’s likelihood of full financing by lowering the project’s overall financial risk, Ever.green said in a blog.

 Ever.green helps companies fund new solar projects through long-term contracts for Renewable Energy Certificates and a marketplace for transferable clean energy tax credits.

Pro-Public Power Group Raises Concerns About Michigan City Pursuing Virtual PPAs

Meanwhile, Ann Arbor for Public Power, a group formed to support the creation of a public power utility in Ann Arbor, Mich., recently came out in opposition to the city’s possible pursuit of virtual PPAs.

Virtual PPAs appear in the Ann Arbor Office of Sustainability and Innovation’s draft budget for the Community Climate Action Millage.

Ann Arbor for Public Power endorsed this millage and supports other initiatives in this draft budget, but does not support the funding of virtual PPAs. Virtual PPAs “are financial arrangements which are easy to frame as effective tools of decarbonization, but are complex, making them difficult to understand, and prone to pitfalls that undermine their effectiveness,” the group said, adding that it believes the costs of virtual PPAs outweigh the benefits.

Ann Arbor for Public Power said that while virtual PPAs may allow for the construction of new wind or solar, they will not reduce carbon emissions unless they replace fossil fuel generation.

“If there’s not enough demand for the energy where it’s built, building it at all actually increases carbon emissions,” the group said. It said that pursuing a virtual PPA “also means the financial and legal firms which will facilitate the deal charge the city a fee that could otherwise be more effectively used for decarbonization.”

The group said the money OSI is considering allocating to virtual PPAs “should instead be used for programs that make direct, local change to reduce carbon emissions, such as building local solar and energy efficiency programs.”

New APPA Reports Outlines Public Power Strategies for Cryptocurrency, Cannabis Operations

April 13, 2023

by Paul Ciampoli
APPA News Director
April 13, 2023

A new report issued by the American Public Power Association details strategies that public power utilities can utilize in response to cryptocurrency mining operations and cannabis grow facilities.

APPA enlisted Utility Financial Solutions to develop the report, “Managing New Electric Loads in a Changing Industry: A Look at Cryptocurrency Mining and Cannabis Grow Facilities.”

“An increasing number of public power utilities have received inquiries from cryptocurrency miners or cannabis grow facilities on the cost to provide electricity,” the report noted. “In addition to the increased demand, electric load from such facilities raise considerations for utilities, including legal questions, customer stability, and community perception.”

Cryptocurrency mining operations and cannabis grow facilities are being built throughout the U.S. Cryptocurrency miners often seek to locate in communities where electricity prices are relatively low because of the high amount of electricity they use. Due to limited building needs, miners can locate almost anywhere, the report said.

“Cryptocurrency operations often have a consistent usage pattern and may have flexibility in their operations to shift usage if needed. Cannabis grow facilities locate in states where cannabis has been legalized for medical or recreational use and have load patterns similar to commercial or general service customers,” according to the report.

Before a cryptocurrency miner or cannabis grow facility chooses a location, it will often inquire about the cost for electric service. Most utilities, including public power utilities, have procedures in place to provide guidance when speaking with a prospective customer. The utility typically assesses its ability to provide the service, estimates the connection costs, and determines what rate structures are available, the report said.

“Additionally, for public power, a key consideration is a prospective business’ value to the community. Cryptocurrency miners and cannabis grow facilities may present potential benefits, such as additional employment or increased tax base for the community, but could also create adverse impacts, such as noise, odor, or negative community perception.”

The report said that utilities might consider developing new rates and policies or updating existing rates and policies when adding cryptocurrency mining or cannabis grow facilities to their system to ensure that this new growth does not adversely impact existing customers. “When rates and policies are designed according to the utility’s cost structure, they often result in more efficient use of infrastructure and lower rates for existing customers.”

The paper reviews key aspects of rate tariff development, potential rate offerings, characteristics of cryptocurrency operations and cannabis grow facilities, considerations for managing cryptocurrency mining and cannabis grow facility loads, and utility experiences with these types of customers.

Utilizing a marginal cost recovery approach to rate design, requesting the ability to interrupt service, and putting in place a formal line extension or contribution margin policy are tools for electric utilities to manage cryptocurrency miners, cannabis grow facilities, and other emerging loads, the report said.

“As individual utilities strive for growth, resiliency, and reliability, work at the state and federal levels is being done to better understand the effects of cryptocurrency mining and cannabis grow facilities on the electric grid. Even with new loads and progression toward the ‘grid of the future,’ the goal of utilities remains to maintain reliable and affordable electricity for the communities they serve.”

The following public power utilities contributed to the report: City of Hamilton, Ohio; City of Shasta Lake, Calif.; Denton Municipal Electric, Texas; Electric Cities of Georgia; Stanton County Public Power District, Nebraska. A public power utility in Michigan also contributed but wished to remain anonymous.

Click here for the report.

Western Area Power Administration Desert Southwest Region Joins Western Energy Imbalance Market

April 10, 2023

by Paul Ciampoli
APPA News Director
April 10, 2023

The Western Area Power Administration Desert Southwest region, Texas investor-owned utility El Paso Electric and AVANGRID on April 5 formally began participating in the California Independent System Operator’s Western Energy Imbalance Market.

WEIM now represents nearly 80% of the demand for electricity in the Western interconnection.

Click here for additional details on other WEIM members, which include a number of public power entities.

As the WEIM has continued to grow, CAISO has been moving toward the launch of the Extended Day-Ahead Market, an initiative that was jointly approved in February by the ISO Board of Governors and the WEIM Governing Body.

When it goes live, the EDAM will offer WEIM partners the opportunity to participate in the day-ahead market, where the majority of energy transactions occur and even greater benefits are expected.

APPA Highlights Impact of Treasury Department’s Energy Communities Guidance on Public Power

April 4, 2023

by Paul Ciampoli
APPA News Director
April 4, 2023

The American Public Power Association on April 4 said it appreciates the Treasury Department’s release of guidance on energy communities.

APPA said it continues to review the guidance, but key aspects appear to provide clarity and reliability where needed. In turn, the energy community provision is a key element of the Inflation Reduction Act (IRA) and could provide substantial benefits to public power utilities, which serve customers in every state (except Hawaii), as they transition to clean technologies. 

In addition to extending and expanding a variety of critical energy tax incentives, the IRA created a refundable direct pay mechanism to ensure that all utilities can benefit from these incentives, including bonus credits for projects sited in energy communities.

Without such a mechanism, public power utilities and electric cooperative utilities — which both operate as non-profit, tax-exempt entities — would be effectively blocked from owning tax creditable energy projects.

These utilities collectively serve nearly 30 percent of U.S. customers, so allowing them to benefit from energy tax provisions for projects they own makes these tax incentives more effective, while also ensuring that no communities — including energy communities — are left behind. 

Since the IRA’s enactment, APPA has asked that implementing guidance be clear, simple, and certain. For example, Treasury’s guidance allows a safe harbor for entities which qualify as energy communities when project construction begins. This is a step in the right direction, which APPA appreciates.

APPA said it will continue to review the guidance, “but again appreciate the work being done here by the Treasury Department, Internal Revenue Service, and Department of Energy.”

While these are draft proposed regulations, Treasury said that the regulations are effective as of April 4. Treasury did not say when it would formally introduce the proposed regulations but that stakeholders can rely on the proposed regulations until final guidance is published.

Additionally, Treasury is seeking comments regarding possible data sources for determining a community’s fossil fuel tax revenues. Comments should be submitted by May 4, 2023. At this time, Treasury is not seeking comments on other issues covered by the draft regulations.

Treasury has also launched a “mapping tool” to help communities determine whether they qualify as an energy community.

First, the map shows the census tracts and directly adjoining tracts that have had coal mine closures since 1999 or coal-fired electric generating unit retirements since 2009. These census tracts qualify as energy communities.

Second, the map shows the metropolitan statistical areas (MSAs) and non-metropolitan statistical areas (non-MSAs) that have had 0.17% or greater direct employment related to extraction, processing, transport, or storage of coal, oil, or natural gas. Annual employment rates at the county level for 2022 will be released later this month and the map will be updated to show the MSAs and non-MSAs that meet both the 0.17% employment threshold and the unemployment rate requirement.

The map does not indicate which areas might have a qualifying brownfield site, but Treasury believes that guidance alone should be sufficient for a community to make that determination.

Snohomish County PUD, Tacoma Power Execute Funding Agreements Tied to SPP Initiative

March 31, 2023

by Paul Ciampoli
APPA News Director
March 31, 2023

Washington State’s Snohomish County PUD and Tacoma Power recently executed funding agreements to participate in the first phase of development of the Southwest Power Pool’s Markets+ initiative.

“We are excited to have a seat at the table to help shape the design of this new market option,” said Adam Cornelius, Snohomish PUD Principal Utility Analyst, in a statement. “The potential of Markets+ to integrate more renewable energy on to the grid and to do so in a cost-effective manner is aligned with the PUD’s goals and strategy to become 100 percent carbon free while keeping rates affordable.”

Snohomish PUD and Tacoma Power join several other organizations that have agreed to participate in the Markets+ phase one development, including Arizona Public Service, Bonneville Power Administration, Chelan PUD, NV Energy, Powerex, Puget Sound Energy, Salt River Project and Tucson Electric Power.

Participation in phase one does not commit utilities to join Markets+. A decision to participate in the market is expected to follow tariff approval.

Snohomish PUD and Tacoma Power are significant new additions to the Markets+ footprint as they represent BPA’s largest and fourth-largest public utility customers, respectively, and serve a significant portion of Washington state’s population.

When combined with BPA, PSE and Chelan PUD, the additions of Tacoma and Snohomish means that most Washingtonians are served by an electric utility participating in the Markets+ development effort.

“Tacoma Power is happy to join our peer utilities in supporting the development of SPP Markets+,” said Clay Norris, Tacoma Power’s Power Management Officer. “Given the significant impacts of moving to centralized day-ahead markets, we think that it is beneficial for utilities across the west to have multiple options to evaluate.”

SPP is developing Markets+, a regional, day-ahead electricity market in the western United States, with funding and participation from a diverse collection of utilities, interest groups and others.

SPP plans to officially announce a complete list of organizations who will participate in phase-one development of Markets+ on April 3.

SPP announced in March that phase one of Markets+ development will see the establishment of a fully independent governance structure. The group’s work will result in market protocols, tariff and governing documents that SPP will eventually file with the Federal Energy Regulatory Commission for approval in early 2024.

Snohomish County PUD is a public power utility that serves electricity to 365,000 customers and water to 23,000 customers in Snohomish County and Camano Island in Washington state.

Tacoma Power is a division of Tacoma Public Utilities. Publicly owned since 1893, it provides electric service to nearly 179,000 customers in Tacoma, University Place, Fircrest and portions of Fife, Lakewood, Federal Way, Steilacoom, Joint Base Lewis-McChord and incorporated Pierce County, as far south as Roy.

Colorado City Takes Closer Look at Possible Municipalization

March 27, 2023

by Paul Ciampoli
APPA News Director
March 27, 2023

Cañon City, Colo., is taking a closer look at its electric utility options including the possible formation of a public power utility.

In 2020, city voters rejected a new franchise agreement with investor-owned utility Black Hills Energy, but Cañon City continues to be served by the utility.

The Cañon City Energy Franchise Committee was formed by the City Council after voters turned down the renewal of the franchise agreement with BHE. The committee’s focus has been to examine different business models that could possibly save customers money on their electric bills.

The Energy Franchise Committee recently completed an interim report detailing electric service options for the city.

Included among the options in the report is a public power utility. Not having a current franchise agreement with BHE is the first step for Cañon City to municipalize an electric utility, the report said.

The report said that even though BHE is not a willing seller, the city has the option of Colorado’ s condemnation law through the eminent domain process to create a new municipal electric utility for Cañon City.

The report also noted that public power’s rates, on average, are lower. “Year after year, for more than 50 years, data from the U.S. Department of Energy show that investor-owned utilities and rural electric cooperatives charge more on average for electricity than public power utilities. In 2014, residential customers of investor-owned utilities paid average rates that were 14 percent higher than those paid by customers of public power utilities.”

The report goes on to detail the steps that would be required to form a public power utility in the city. Among other things, the report highlights the need for community education.

It pointed out that the American Public Power Association has stressed the importance of community education throughout the municipalization process. An educational community plan needs to be developed prior to a city election, the report said.

APPA offers a wide range of resources and information related to municipalization. Click here for additional details.

PJM Offers Details on Initial Capacity Market Reform Proposal

March 21, 2023

by Paul Ciampoli
APPA News Director
March 21, 2023

The PJM Interconnection recently presented stakeholders with an early outline of its initial proposal aimed at improving key aspects of the PJM capacity market construct.

At the request of stakeholders, in the March 15 meeting of the Resource Adequacy Senior Task Force, Markets personnel presented a preliminary Problem Statement and Issue Charge framing what they envisioned as key areas to be addressed. They noted that their drafts were based on the PJM Board of Managers Feb. 24 letter that launched the CIFP process and identified key areas to address.

The first stage of the CIFP begins with a presentation of PJM’s formal proposal on March 29. The work of the RASTF and related key work activities will be on hiatus pending completion of the CIFP process, PJM announced.

The PJM proposal focused on the following areas directed by the Board in its Feb. 24 letter:

• Reliability Risk Modeling: Enhancements to how PJM models risk for reliability aim to more accurately reflect the likelihood and severity of extreme weather events. Model improvements enhance how PJM determines procurement targets in future years;
• Capacity Accreditation: Inaccurate accreditation of resources, PJM said, artificially inflates supply, depresses clearing prices and risks premature resource retirement. Marginal accreditation accredits each resource to reflect its expected incremental contribution to system reliability.
• Winter Qualification Requirements: PJM proposed minimum requirements aligned with recommendations by other grid operators. These requirements are also informed by NERC requirements and ongoing study of extreme events, specifically Winter Storm Elliott.
• Performance Assessment Reform: PJM proposed to enhance varying levels of resource testing, assessment and compliance obligations to ensure committed capacity may deliver when needed.
• Market Power Mitigation Rules: This area focuses on reforms to the market seller offer cap in order to ensure needed investments are attracted for reliability. 

The next annual capacity auction, or Base Residual Auction, covers the 2025/2026 Delivery Year and is scheduled for June.

PJM and stakeholders discussed risks and merits of delaying that and other capacity auctions so that any FERC-approved rule changes would be included in subsequent auctions.

Stakeholder feedback taken at the March 15 and previous meetings will help inform the Board’s final decision on a proposed auction schedule that is subject to FERC approval.