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San Diego City Council Approves Contract to Study Public Power

October 7, 2022

by Paul Ciampoli
APPA News Director
October 7, 2022

The San Diego City Council on October 3 approved a contract for a consulting firm to examine the feasibility of the California city transitioning to a public power utility.

The contract approved by the San Diego City Council is with NewGen Strategies & Solutions LLC.

According to a City Council Staff Report related to the contract, NewGen will provide feasibility study reports to the Mayor’s Office and City Council on the process, costs, risks, and opportunities that would be associated with transitioning from the current electric and/or gas franchise agreements with investor-owned San Diego Gas & Electric to a public power entity.

The report notes that In conjunction with the award of the gas and electric franchises to San Diego Gas & Electric in July 2021, a corollary action was identified to investigate the feasibility for an alternative to the provision of electric and gas services from an investor-owned utility through some form of municipalization and establishment of a public power entity.

The Energy Division of the San Diego Sustainability and Mobility Department was identified by San Diego’s Chief Operating Officer as the most appropriate staff to develop such a study with the support of consultants with significant technical expertise in all areas and aspects of such a process.

A request for proposals for a Public Power Feasibility Study was issued on Feb. 9, 2022 and closed on April 1, 2022.

The American Public Power Association offers a number of resources related to municipalization on its website.

Frank McRae Named as General Manager of the Southwest Public Power Agency

October 6, 2022

by Paul Ciampoli
APPA News Director
October 6, 2022

Frank McRae was recently named as general manager of Arizona’s Southwest Public Power Agency (SPPA). His official start date was September 19, 2022. 

SPPA is a joint action agency established under Arizona state law, comprising publicly owned, not-for-profit irrigation and electrical districts, municipal electric utilities, and tribal utilities.

McRae will be working together with K.R. Saline principal Dennis Delany on SPPA matters to establish and execute SPPA goals and objectives.

McRae will assist with managing, analyzing, and evaluating the effectiveness of all operations for SPPA. In addition, he will be responsible for projects, interpretations, and implementations of the Board of Directors’ policies.

He will also develop and maintain effective organizational structure and personnel by providing leadership, direction, and guidance of SPPA.

He will also represent SPPA to the membership, regulatory agencies, government, and other electric industry organizations, plus financial, trade and community organizations. 

McRae has forty years of professional experience in the energy utilities industry. Most recently, he was the Director for the City of Mesa’s Energy Resources Department.

Outages Post-Hurricane Ian Down to Less Than 500,000 in Florida

October 5, 2022

by Paul Ciampoli
APPA News Director
October 5, 2022

 

There were approximately 394,000 customer outages in Florida as a result of Hurricane Ian as of the afternoon of October 4, down from a peak of 2.7 million customers without power, the Department of Energy reported.

Ian made its initial landfall near Port Charlotte, Fla., as a category 4 hurricane on September 28.

Outages in Florida were down 85% from the peak on September 29, DOE said.

Restoration efforts continue across Florida. Electric industry representatives report that at the peak, more than 44,000 workers from 33 states and the District of Columbia were supporting power restorations.

Overall, Florida utilities report that Ian mainly impacted the distribution system, with no significant damage reported to transmission assets.

DOE said portions of the electric distribution system will need to be rebuilt in some of the hardest hit areas of Florida.

Meanwhile, in South Carolina, Santee Cooper on Oct. 3 reported that it restored 70,000 customers within 54 hours after Hurricane Ian directly hit its service territory, making landfall at Winyah Bay in Georgetown County Friday. All customers who lost power because of Hurricane Ian were restored by 8:02 p.m. Sunday. 

Santee Cooper is the state-owned public power utility in South Carolina.

Crews worked around the clock to restore all residential and commercial customers, with the help of 34 contract line crews and 12 tree crews from across the southeast. Amongst the restoration, these crews replaced 20 power poles and 32 transformers. 

Hurricane Ian also knocked 12 transmission lines out of service, affecting power delivery to six electric cooperatives and other Santee Cooper retail customers.

The cooperatives impacted were Berkeley Electric Cooperative, Santee Electric Cooperative, Marlboro Electric Cooperative, and Lynches River Electric Cooperative, Horry Electric Cooperative and Mid-Carolina Electric Cooperative.

Santee Cooper had 10 external transmission line and tree crews, plus four helicopters and crews, helping its internal team.

All transmission delivery points were reenergized by Friday night, just hours after Ian left the Santee Cooper footprint.

Biden Administration has Now Approved EV Deployment Plans for All 50 States

October 4, 2022

by Paul Ciampoli
APPA News Director
October 4, 2022

The Biden Administration has now approved electric vehicle (EV) infrastructure deployment plans for all 50 States, the District of Columbia and Puerto Rico ahead of schedule under the National Electric Vehicle Infrastructure (NEVI) Formula Program, established and funded by Biden’s Bipartisan Infrastructure Law.

With this approval, all states now have access to all Fiscal Year (FY) 2022 and FY23 NEVI formula funding, totaling more than $1.5 billion to help build EV chargers covering approximately 75,000 miles of highway across the country.

The NEVI formula funding under the Bipartisan Infrastructure Law makes $5 billion available over five years.

Thanks to flexibility provided by the Bipartisan Infrastructure Law, State Departments of Transportation (DOTs) were able to leverage technical assistance available through the Joint Office of Energy and Transportation and begin staffing and activities directly related to the development of their plans prior to approval, the Department of Energy noted.

Now that EV charging plans from all 50 States, the District of Columbia and Puerto Rico have been approved, each state, territory, or district can be reimbursed for those costs and now have a wide range of options to use their NEVI formula funding for projects directly related to the charging of a vehicle, including:

All approved plans are available on the FHWA web site and funding tables for the full five years of the NEVI formula program can be viewed here. 

 Additional funding sources include: 

FHWA is also working on related efforts to establish ground rules for how formula NEVI funds can be spent.

FHWA published a Notice of Proposed Rulemaking (NPRM) on proposed minimum standards and requirements for projects funded under the NEVI Formula Program and plans to finalize that rulemaking expeditiously now that the comment period has closed. 

FHWA also proposed a Buy America waiver that will allow a short ramp up period for the domestic manufacturing of EV charging; the comment period for the waiver proposal is open through September 30, 2022. Additionally, FHWA has posted updated Frequently Asked Questions on its website. 

The Federal Highway Administration and the Joint Office of Energy and Transportation will continue to provide direct technical assistance and support to states as they begin plan implementation, as well as throughout the lifetime of the NEVI formula program.

Report Finds Solar with Storage Can Provide Reliable Residential Backup Power

October 4, 2022

by Peter Maloney
APPA News
October 4, 2022

Behind-the-meter solar-plus-energy storage systems (PVESS) can generally provide at least minimum levels of backup power during power interruptions, according to a new report by Lawrence Berkeley National Laboratory (LBNL).

The report, Evaluating the Capabilities of Behind-the-Meter Solar-plus-Storage for Providing Backup Power during Long-Duration Power Interruptions, found that backup performance of PVESS can vary depending on a variety of circumstances.

The best performance observed in the report, which included both simulations and historical analysis of how PVESS would have performed during a sample of actual historical events, was for residential buildings. If heating and cooling loads are excluded from those residences, a small PVESS with 10 kilowatt hours (kWh) of storage, the lower end of sizes currently in the market, can fully meet basic backup power needs over a three-day outage in virtually all U.S. counties and in any month of the year, the report found.

If critical loads include heating and cooling, a 10-kWh PVESS would meet 86 percent of critical load on average across all counties and months, while a 30-kWh PVESS, the upper end of sizes currently in the market, would meet 96 percent of critical load.

The report’s authors noted, however, that the results showed considerable performance within individual regions, based on variations in building stock. Performance declines for higher-usage homes but, more significantly, performance is affected by heating technology, building infiltration or “leakiness,” air-conditioner efficiency, and temperature set-points.

The single biggest impediment to backup performance is the presence of electric space heating, which is currently mostly electric resistance, and is most prevalent in the Southeast and the Pacific Northwest, the report said.

The authors also noted that backup performance for homes with electric heat or high cooling loads is quite sensitive to weather variability. For example, in counties with high penetration of electric heat, between 53 percent and 96 percent of critical load is served during winter months, depending on which specific day the outage begins. A similar but less dramatic was observed for homes with high cooling loads, the authors added.

In terms of duration, the report found that backup performance is fairly insensitive to outages lasting longer than one day. In general, backup performance declines as outage duration increases, though the effect is relatively modest, given the ability of solar panels to recharge batteries each day, the authors said.

For a PVESS with 30-kWh of storage and critical loads that include heating and cooling, backup performance drops from a population-weighted average of 100 percent of critical load served for a one-day outage to 92 percent for a 10-day outage, the report found.

In seven of the 10 historical outage events analyzed, the majority of homes would have been able to maintain critical loads with heating and cooling, using a PVESS with 30 kWh of storage, the report said. However, the authors noted that there was considerable variability among the five hurricane events analyzed, which was driven by differences in solar insolation levels.

The lowest performing event was Hurricane Florence, where almost no solar generation occurred over the first three days of the roughly eight-day outage due to cloud cover. For the two winter storms analyzed, all critical load was served in the median case, but a sizeable fraction of customers—those with electric heating—saw much lower performance, the report said.

The major constraint to backup performance for commercial buildings were roof area constraints on solar system sizing, the report said. “Providing full-building backup for a multi-day outage would require significantly larger systems than what is typically observed in the market today, for systems installed primarily for other purposes,” the authors said.

LBNL said the report is the first in a series it plans to do in collaboration with the National Renewable Energy Laboratory on the use of PVESS for backup power. The report’s authors plan to host a webinar summarizing key findings of the new report on Oct. 6.

DOE Begins Accepting Applications for $7 Billion in Funding for Hydrogen Hubs

October 4, 2022

by Peter Maloney
APPA News
October 4, 2022

The Department of Energy (DOE) recently opened the application process for a $7 billion program to create regional clean hydrogen hubs (H2Hubs) across the country.

As part of a larger $8 billion hydrogen hub program funded through the Bipartisan Infrastructure Law, the DOE said the H2Hubs will be a driver in helping communities across the country benefit from clean energy investments, good-paying jobs, and improved energy security while supporting the Biden administration’s goal of achieving a net-zero carbon economy by 2050.

For the initial funding opportunity launch, the DOE aims to select six to 10 hubs for a combined total of up to $7 billion in federal funding.

Hydrogen is a versatile fuel that can be produced from clean, diverse, and domestic energy resources, including wind, solar, and nuclear energy, or by using methane while capturing resulting carbon to reduce emissions, the DOE said. Hydrogen’s characteristics also make an option to decarbonize energy-intensive heavy industry and support heavy-duty transportation, the agency added.

Concept papers for H2Hubs proposals are due by Nov. 7 with full applications due by April 7. Additional funding opportunities may follow to accelerate and expand the network of clean hydrogen projects, the DOE said.

The DOE has also released a draft of the National Clean Hydrogen Strategy and Roadmap for public feedback. A final version of the strategy and roadmap is scheduled to be released in the coming months with an updated version at least every three years.

In February, the DOE released requests for information to inform the implementation and design of the Bipartisan Infrastructure Law’s hydrogen programs, which includes $8 billion for Regional Clean Hydrogen Hubs, $1 billion for a Clean Hydrogen Electrolysis Program, and $500 million for Clean Hydrogen Manufacturing and Recycling Initiatives to support equipment manufacturing and strong domestic supply chains.

APPA Says Record Shows Support for Joint Transmission Ownership Opportunities for LSEs

October 3, 2022

by Paul Ciampoli
APPA News Director
October 3, 2022

The record of a pending Federal Energy Regulatory Commission (FERC) proceeding offers specific support for the Commission to find that promoting joint transmission ownership opportunities for load-serving entities (LSEs) is likely to provide the benefits the Commission projects, the American Public Power Association (APPA) said in reply comments filed at FERC.

The Sept. 20 reply comments were made in a FERC proceeding related to regional transmission planning and cost allocation (Docket No. RM21-17-000).

In a Notice of Proposed Rulemaking (NOPR), FERC outlined significant changes to its transmission planning rules, including a proposal to promote joint ownership of transmission lines through the use of a conditional right of first refusal (ROFR) to build jointly owned lines.  In comments filed in response to the NOPR, APPA urged FERC to adopt a more narrowly tailored version of the proposed conditional ROFR focused on promoting joint ownership opportunities for public power utilities and other LSEs.

The proposed reforms outlined by FERC in the NOPR are intended to remedy deficiencies in the Commission’s existing regional transmission planning and cost allocation requirements to ensure that Commission-jurisdictional rates remain just and reasonable and not unduly discriminatory or preferential.

“Focusing the conditional ROFR on joint ownership opportunities for LSEs would not be unduly discriminatory,” APPA said in its reply comments.

APPA’s proposal for a conditional ROFR that is focused on LSE joint ownership is consistent with the specific statutory requirement in Federal Power Act section 217(b)(4) that the Commission exercise its authority in a manner that facilitates the planning and expansion of transmission facilities to meet the reasonable needs of LSEs to satisfy the service obligations of LSEs, the trade group went on to say in the reply comments.

APPA said it recognizes that many commenters have expressed concern that any ROFR for incumbent transmission providers, even a conditional one, would be a retreat from competition.

“APPA acknowledges that transmission competition may be a mechanism to control rising transmission costs, which is a significant concern for APPA members and other transmission customers. The premise of APPA’s joint ownership proposal is that it would make it more likely that the benefits envisioned by the Commission would actually be realized,” APPA said.

Those benefits include helping to increase opportunities for investment in the transmission system and promoting market entry and greater diversity of participation and perspectives in transmission ownership, APPA told FERC.

“These goals are pro-competitive and APPA’s proposed narrow ROFR would provide an option to achieve them.”

Moreover, APPA underscored the fact that its proposal for a narrowly tailored conditional federal ROFR would not be mandatory. “APPA does not support proposals or comments in favor of a mandatory ROFR, conditional or otherwise.”

APPA also said it does not agree with comments that if the Commission decides to reinstate some form of ROFR, it should do so on a nationwide basis or permit the states to make determinations regarding competitive processes.

Instead, APPA’s proposal allows that in those areas where regional transmission planning stakeholders believe that transmission competition is beneficial, they could opt not to implement a conditional ROFR approach.

If the Commission declines to adopt a conditional ROFR in any final rule in this proceeding, APPA urged it to promote public power joint transmission ownership through other methods.

There is a substantial record “in this docket demonstrating the benefits that joint ownership opportunities for public power and electric cooperative LSEs are likely to produce.” 

The Commission should pursue policies to promote these benefits even if it decides not to adopt the conditional ROFR, APPA said.

“The Commission could, for example, seek to promote joint ownership through the transmission planning process by specifying that joint ownership of transmission facilities is a positive factor in evaluating transmission solutions in regional transmission planning processes, including competitive solicitations,” APPA said.

SPP RTO Expansion Into Western Interconnection Details Projected Savings

October 3, 2022

by Paul Ciampoli
APPA News Director
October 3, 2022

Expanding the Southwest Power Pool (SPP) Regional Transmission Organization into the Western Interconnection could produce a net total of $55 million to $73 million per year in savings depending on hydrologic conditions, according to a new study commissioned by prospective SPP RTO participants in the Western Interconnection.

The Brattle study evaluated adjusted production cost savings and reported potential market benefits for expanded SPP RTO participation. The study estimates adjusted production cost savings of $71 million per year under average hydrology conditions. The savings increase to $89 million per year under severe drought conditions.

There are also potential operational and reliability benefits provided by RTO participation that are not quantified in the adjusted production cost study.

 “This study, including the specific impacts across WAPA customers, will help inform our next steps and potential future as we adapt to the changing climate and generation mix. We greatly appreciate the effort dedicated to this study from Brattle and other study participants,” said Western Area Power Administration Administrator and CEO Tracey LeBeau. “As always, we are committed to collaborating with our customers and stakeholders as we assess this opportunity. Any decision to move forward with final negotiations for SPP RTO membership will be consistent with our statutory requirements and involve the appropriate public processes.”

Prospective SPP RTO participants included in the study are Basin Electric Power Cooperative, Colorado Springs Utilities, Deseret Power Electric Cooperative, Tri-State Generation and Transmission Association and the Municipal Energy Agency of Nebraska along with the WAPA Upper Great Plains region, Rocky Mountain region and Colorado River Storage Project.

Each of these entities is currently participating in the SPP Western Energy Imbalance Service and receives Reliability Coordinator services from SPP. Tri-State, WAPA UGP region, Basin Electric and MEAN are already members of SPP in the Eastern Interconnection.

Although not included in the study, Platte River Power Authority announced in August its intention to join the SPP RTO.

As potential benefits, the SPP RTO expansion could increase the portfolio of tools available to support reliability in the Western Interconnection. This includes consolidated balancing authority operations, coordinated resource adequacy and a fully integrated wholesale market that would optimize real-time, day-ahead and ancillary services.

Additionally, the established SPP RTO transmission processes could improve transmission planning and development needed to support growing electricity demand and addition of more generation resources, including renewables.

“We’re pleased that the study reinforces the promise of an organized power market and our partnership with the Southwest Power Pool,” said Colorado Springs Utilities CEO Aram Benyamin. “For our customers, the benefits are clear – millions of dollars in annual savings by having access to regional energy producers and the reliable and cost-effective integration of additional carbon-free energy resources into our system.”

This study builds on previous evaluations of the benefits of SPP RTO expansion into the Western Interconnection, including a 2020 study commissioned by SPP. The new 2022 study uses updated modeling assumptions about the participant footprint, generation portfolios, natural gas prices and projected hydrology conditions.

The study is not a decision by participants to join the SPP RTO. Each of the participating organizations will continue their internal review and approval processes to determine if they will proceed to the next steps for SPP RTO membership. The 2022 Brattle study results, along with other factors, will help inform those processes.

President Biden Signs Spending Bill that Includes $1 Billion in LIHEAP Funding

October 3, 2022

by Paul Ciampoli
APPA News Director
October 3, 2022

President Biden on Sept. 30 signed a stop-gap spending bill that includes $1 billion in additional funding for the Low Income Home Energy Assistance Program (LIHEAP).

Half of the funds will be distributed using the old formula, which tends to benefit heating states, while the other half will be distributed using a new formula, which provides greater benefit to cooling states relative to the old formula.

In addition, LIHEAP is expected to receive roughly $4 billion in regular appropriations for fiscal year 2023 when permanent spending bills are approved.

The American Public Power Association strongly supports LIHEAP and the funding increase including the bill, which stems in large part because of rising energy prices.

The spending bill will keep the federal government operating through December 16 to allow time for Congress to pass permanent annual spending bills for the fiscal year which begins on October 1.

The Senate passed the measure on Sept.29, with the House passing it on Sept. 30.

Nominations for APPA’s Policy Makers Council Now Being Accepted

October 1, 2022

by Paul Ciampoli
APPA News Director
October 1, 2022

Nominations for the American Public Power Association’s Policy Makers Council (PMC) are being accepted through November 18.

Leaders of public power utilities can nominate members, who are either elected or appointed officials, on the governing authorities of public power distribution utilities, including mayors, city council members, and elected or appointed board members.

The PMC meets twice a year in Washington, D.C. during the APPA Legislative Rally in February and at a separate PMC-only meeting in July to participate in meetings with elected representatives and congressional staff to advance APPA’s legislative and regulatory agendas. 

To nominate a member of a utility’s governing body to the PMC or learn more about the process, contact Steve Medved, APPA’s Government Relations Manager, at: smedved@publicpower.org.