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70 Public Power Utilities Earn Smart Energy Provider Designation

October 26, 2021

by Paul Ciampoli
APPA News Director
October 26, 2021

Seventy public power utilities have earned a Smart Energy Provider (SEP) designation from the American Public Power Association. The designations were presented on October 26 during APPA’s Customer Connections Conference in Scottsdale, Ariz.

SEP designees are recognized for demonstrating commitment to and proficiency in energy efficiency, distributed generation, and environmental initiatives that support a goal of providing low-cost, quality, safe, and reliable electric service.

In total, 97 public power utilities nation-wide hold the Smart Energy Provider designation.

The SEP designation, which lasts for two years (December 1, 2021 to November 30, 2023) recognizes public power utilities for demonstrating leading practices in four key disciplines: smart energy program structure; energy efficiency and distributed energy programs; environmental and sustainability initiatives; and the customer experience. This is the third year APPA has offered the SEP designation.

In an episode of the Public Power Now podcast, Liz Jambor, manager of data analytics and business intelligence at Austin Energy in Texas, discussed the SEP Program and her work as chair of the SEP review panel. To listen to the December 2020 episode, click here.

The full list of SEP designees is available here.

Kansas Municipal Utilities Completes Another Successful Distribution Overhead Workshop

October 26, 2021

by APPA News
October 26, 2021

Kansas Municipal Utilities (KMU) earlier this month completed another successful Electric Distribution Overhead Workshop, which offers training sessions on overhead installation, construction, maintenance requirements and techniques and provides attendees with the opportunity to practice these job tasks in a simulated energized environment.

Brian Meek, KMU’s Director of Training and Safety, noted that the 36-acre KMU training field contains an example of almost every situation encountered in the real world.

Trainees work in crews that are assembled from multiple different utilities. “The multi-utility crew composition forces trainees to hone their communication skills and adapt to the different work practices that are performed by different municipalities,” he said. The workshop is designed to offer training for all experience levels of lineworkers, from apprentice to crew leader. The workshop is taught primarily by journey lineman from across Kansas.

This year’s workshop kicked off with a simulated mutual aid event, Meek noted. Prior to trainee arrival, the field was prepped to simulate a tornado touchdown. Poles were cut down or pushed over, crossarms were broken, lines were cut, and insulators were damaged.

When the trainees arrived, they were given a class on mutual aid response followed by a briefing of the potential damage in the field. After the briefing, the trainees formed their work crews with their instructors and had to access and repair the damage within 3 hours. This exercise also required multi-crew coordination to ensure that everyone could accomplish their tasks safely.

Throughout the workshop, apprentices in the KMU Lineworker apprenticeship program complete required program skill evaluations and participate in hurt man rescue exercises, Meek said.

Meanwhile, Meek detailed how the 2021 KMU Electric Distribution Overhead Workshop that wrapped up on October 1 was a success.

“During our workshops we ensure that safety is the top priority,” he said. “The number one success for the workshop is that no one was injured during their training,” Meek noted.

“Building on that success, a large number of apprentices were able to perform activities that they have never completed before. By completing these tasks in a real-world situation but with the absence of the electrical hazard, the trainees can make mistakes without deadly consequences.”

This practice time improves their skills to ensure the work can be completed safely when they return to their municipalities, Meek said.

“Lastly, networking is one of the most commonly overlooked benefits of the workshop. Trainees leave the facility with the contact information for other lineman in neighboring utilities. The relationships they build during the workshop spill over into their regular work lives. When they have questions or need help, they call their classmates for help. Most workshop attendees say that the networks they build during the classes provide invaluable benefits.” 

Meek noted that this year marked the 10th year for the workshop. “When the workshop began there was no training center and no poles, just an open field. As time went on and the amount of poles and simulated circuits grew, we were able to get more complex in our offerings,” he said.

“Two years ago, we modified the workshop significantly. In the first eight years, trainees would spend a set amount of time at a ‘training station’ learning one aspect. They would then rotate stations after a set amount of time. The workshop was modified to create work crews and allow the crews to work an actual job from start to finish during the week.”

This format incorporates all of the aspects that were taught in the stations, but in a more real-world and comprehensive setting, Meek noted. “Last year we added the mutual aid component discussed earlier. All of these evolutions have occurred based on the input of the trainees and the instructors. I believe this is why the workshop continues to grow. This year we had a record number of participants (59) and were at capacity for the number of instructors we had.”

The Electric Distribution Overhead Workshop takes place at KMU’s Training Center in McPherson, Kansas.

“We have a large number of training events at our facility each year,” Meek noted. “In addition to the Overhead Workshop we offer an Underground Electric Distribution Workshop, Transformer Connections Workshop, Power Plant Operator Workshop, Watt-Hour Metering School, Substation Workshop, T&D Switching Workshop, multiple Leadership Seminars, a CDL workshop, multiple Utility Locate Certification Workshops, Gas Pipeline Operator Workshop, multiple Mobile Crane Certification Workshops, and a variety of water and wastewater classes.”

In 2022, “we will be expanding our workshop offerings to include heavy equipment workshops,” he said.

In addition to the workshops, “we also host our lineworker apprenticeship training program. This program has grown to over 70 apprentices.”

Colin Hansen, who is currently Executive Director of Kansas Municipal Utilities (KMU), is the chair of the American Public Power Association’s Board of Directors.

It was recently announced that Hansen will be joining Kansas Power Pool (KPP) effective Feb. 1, 2022 as KPP’s new CEO and General Manager. 

FERC Rejects Bid To Require TVA To Provide Open Access Transmission Service

October 25, 2021

by Paul Ciampoli
APPA News Director
October 25, 2021

The Federal Energy Regulatory Commission (FERC) on Oct. 21 denied a request by local power companies (LPCs) that the Commission require the Tennessee Valley Authority (TVA) to provide open access transmission service to the LPCs pursuant to section 211A of the Federal Power Act (FPA).

In January 2021, Tennessee-based Athens Utilities Board, Gibson Electric Membership Corporation, Joe Wheeler Electric Membership Corporation and Volunteer Energy Cooperative filed a request seeking a Commission order requiring TVA to provide transmission service under section 211A of the FPA and interconnection service under section 210 of the FPA (Docket Nos. EL21-40-000, TX21-1-000).

In late August 2021, Joe Wheeler Electric Membership Corporation filed a notice seeking to withdraw its participation in the petition and indicating that it had reached an agreement on a new power supply arrangement with TVA. It is therefore no longer a petitioner in the proceeding.

The LPCs currently purchase their full power supply and delivery requirements from TVA under bundled full requirements power supply contracts.

They said in their petition that they were seeking unbundled transmission service from TVA, which they said is the only transmission provider that can feasibly serve them, in accordance with the Commission’s longstanding open access principles.

In response, TVA argued that that the Commission lacks statutory authority under section 211A of the FPA to grant the request of the LPCs. TVA said that while section 211A authorizes the Commission to require government-owned utilities to provide the type of service the LPCs sought, TVA asserted that FERC’s authority to require TVA to provide transmission service under section 211A is limited by another provision of the FPA – section 212(j).

TVA further argued that section 211A gives the Commission discretionary authority to oversee the rates and non-rate terms and conditions for transmission service that is already being provided, but not to order new wheeling service.

TVA also said that the interpretation of section 211A by the LPCs would destroy TVA’s ability to meet its broad statutory mandate to support the physical, economic, and social welfare of the TVA region and balance its varied missions to achieve that mandate.

Moreover, TVA argued that the Commission’s exercise of its authority under section 211A is discretionary, extremely rare, and must advance the public interest. TVA therefore asserted that there is no basis for exercising any such authority in the LPC proceeding.

In considering the public interest, TVA asserted that, due to a statutory “Fence,” stranded costs resulting from the loss of LPC load could not be mitigated and would shift to remaining LPCs.

The TVA Fence refers to the non-physical boundary that the U.S. Congress placed around TVA’s service territory in 1959.

FERC Order

In an order approved at its Oct. 21 open meeting, FERC noted that Section 211A of the FPA provides that “the Commission may, by rule or order, require an unregulated transmitting utility to provide transmission services.” Thus, FERC’s authority under section 211A is discretionary.

“In this case, we decline to issue a rule or order requiring TVA to offer unbundled transmission service to petitioners or to outside power suppliers to serve load within the TVA Fence under section 211A, and thus we deny the petition,” FERC said.

FERC clarified that, contrary to claims that unregulated transmitting utilities must “abide by” section 211A, there are no established requirements under section 211A that an unregulated transmitting utility must meet, so there can be no “violation” of section 211A by an unregulated transmitting utility.

The Commission’s jurisdiction under section 211A(b)(1) is not invoked automatically upon action by an unregulated transmitting utility, it said.

Rather the Commission “has the discretion to choose to exercise, or as relevant here to instead choose to not exercise, this authority.”

FERC Chairman Richard Glick issued a separate statement concurring in the decision, as did Commissioners Mark Christie and James Danly.  Commissioner Allison Clements dissented from the order.

FERC Commissioners Weigh In On Southeast Energy Exchange Market Vote

October 25, 2021

by Paul Ciampoli
APPA News Director
October 25, 2021

Commissioners at the Federal Energy Regulatory Commission (FERC) recently weighed in with their views on a proposed agreement for a Southeast automated, intra-hour energy exchange. The agreement recently took effect as a result of a deadlock on the Commission.

In an Oct. 13 notice, FERC noted that pursuant to section 205 of the Federal Power Act (FPA), in the absence of Commission action on or before Oct. 11, 2021, the proposed Southeast Energy Exchange Market (SEEM) agreement became effective by operation of law.

The Commission did not act on the proposed SEEM agreement “and concurrences thereto because the Commissioners are divided two against two as to the lawfulness of the change,” the notice said.   Under a provision added to the FPA in 2018, each Commissioner must provide a statement explaining the Commissioner’s views on any filing that goes into effect as a result of such a deadlock. 

Chairman Glick

“Expanding regional electricity markets is one of the single most important steps that the Commission can take to save customers money, enhance reliability, and integrate intermittent resources most efficiently,” said FERC Chairman Richard Glick. He believes regional transmission organizations (RTOs) and independent system operators (ISOs) “are, by far, the best way to achieve these benefits.”

“From my perspective, utilities and other stakeholders in this region should be working to establish an RTO/ISO in the Southeast for the benefit of consumers and to promote grid reliability.  But that is not the proposal presented to us in this docket,” he said in an Oct. 20 statement.

Glick said he believes that much of the SEEM proposal arguably satisfies the standard for FERC approval under Section 205 of the FPA.  “However, I voted no in large part because the filing parties’ proposal to apply the Mobile-Sierra public interest presumption to the Southeast EEM Agreement violates well-established Commission precedent.  When Mobile-Sierra applies, the Commission must presume that the relevant agreement meets the statutory just-and-reasonable standard, so the agreement can only be changed if it seriously harms the ‘public interest,’ a significantly higher evidentiary hurdle,” he wrote.

“Considering the history of entrenched resistance to organized markets in the Southeast, the Southeast EEM represents at least a positive step forward,” Glick said. “Currently, several large incumbent utilities serve most of the consumers in the Southeast as bundled retail customers. Delivering power across multiple balancing authority areas in the region requires multiple transmission reservations and payment of pancaked transmission rates. A centralized and competitive wholesale market in the Southeast, or at least something closer to that model, is a step in the right direction.” 

 But finding a proposal just and reasonable and not unduly discriminatory or preferential under Section 205 of the FPA requires that it be more than just a step in the right direction, he said.  The filing parties initially proposed to apply Mobile-Sierra to the entire SEEM agreement and later narrowed that to a smaller subset of “enumerated provisions.” 

“I cannot support this part of the proposal because I believe that application of the Mobile-Sierra presumption here violates Commission precedent. Under that well-settled precedent, the Mobile-Sierra presumption applies to a contract ‘only if the contract has certain characteristics that justify the presumption,’” Glick said.

He argued that the SEEM agreement fails this test. Applying the Mobile-Sierra public interest presumption to at least the enumerated provisions of the SEEM agreement departs from FERC’s precedent without justification, he said. 

“We must always tread cautiously when determining whether a presumption that an agreement satisfies the statutory ‘just and reasonable’ standard is applicable,” wrote Glick. 

Had the Commission been able to reach agreement on the Mobile-Sierra issue, “I believe that our existing statutory protections against undue discrimination would have been sufficient to address protestors’ concerns about the Southeast EEM and to protect consumers and market participants in the region.  Applying the Mobile-Sierra presumption in these circumstances will make it more difficult for third parties or even the Commission to mount legitimate challenges in the future to the justness and reasonableness of the Southeast EEM.  Put simply, there is no need (and no basis) to apply the Mobile-Sierra presumption here — and there is considerable risk to the public in doing so.” 

Aside from his disagreement on the Mobile-Sierra issue, Glick was willing to support the SEEM proposal, as modified by the filing parties’ June 7 and August 11 responses to Commission deficiency letters, because he believes the modified proposal otherwise meets the “just and reasonable” standard of section 205 of the FPA.

Glick said the stated benefits of this platform, “though unverified, appear to be meaningful: The filing parties project over $100 million per year in market-wide savings by 2037 assuming higher renewable and energy storage penetration across the region, or $40 million per year relative to the current bilateral market under a more conservative estimate.”   

For customers to realize such benefits, however, “market outcomes must be the product of genuine competition, not market manipulation. For this reason, I share the concern of many that the Southeast EEM Agreement may present opportunities for the participants to engage in manipulation.”

He noted that the SEEM parties made commitments, in their responses to deficiency letters, to provide additional transparency safeguards.

“While the original filings, not those subsequent responses, go into effect by operation of law, I urge the parties to stand by their additional commitments on transparency,” wrote Glick.

“Beyond what the parties have offered, the Commission has the tools — and stands ready — to investigate any potential fraudulent or manipulative conduct and take any corrective action as needed, including imposing civil penalties. As I have often stated, guarding against market manipulation remains one of the core obligations vested in this agency by Congress. I intend for the Commission to continue to remain vigilant on this front.”

Commissioner Clements

“To be very clear, my lack of support for the instant proposal is not because I would prefer a different market structure or that I fail to appreciate the parameters of the legal inquiry that Section 205 prescribes,” said Commissioner Allison Clements.

“I am cognizant of Section 205’s requirements that we not let perfect be the enemy of the good and that we can only review the proposal in front of us. But legal insufficiency must foreclose Commission approval.  In my view, the Southeast EEM, as proposed, contains infirmities that compel the Commission to find that the Filing Parties have not satisfied their legal burden,” she wrote in a statement.

She voiced concern that the SEEM may expose participants to unjust and unreasonable rates and said she agreed with Glick’s conclusion that applying the Mobile-Sierra standard to the generally applicable SEEM Agreement provisions, even the “enumerated provisions” identified in the response to the first deficiency letter from FERC, would violate Commission precedent.

By failing to reject the SEEM as proposed, FERC “compromises its fundamental principles of transparency, oversight and fair and open market access,” Clements said. “Failing to apply these principles to this market is dangerous not only because of the discriminatory and unjust rate impacts it may impart in the region, but because it may inhibit the Commission’s ability to ensure that other organized markets, existing or forthcoming, are just and reasonable and not unduly discriminatory.”

She argued that failing to reject the proposal “is likely to invite future attacks on the Commission’s fundamental market design safeguards in existing and future markets across the country.”

Commissioner Christie

Commissioner Mark Christie said that the SEEM proposal meets the standard for approval under section 205 of the FPA.

“The opposition to this proposal stems from one core issue:  the goal of many interest groups to force the Southeastern states into a Regional Transmission Organization (RTO) or at least into a halfway-house to an RTO now, with full submission later,” Christie asserted.

Christie said he would have voted to accept the SEEM proposal as a package. The filings “unquestionably meet the statutory criteria for acceptance under section 205 and should have been approved by majority vote of this Commission,” wrote Christie in his statement. He said he would have voted to approve the SEEM proposal as a package within the deadline of August 6, 2021 created by a May 4 FERC deficiency letter.

He said that “any claim in this record that an RTO would provide ‘more’ benefits than those offered by the Southeast EEM is purely speculative and unpersuasive.” The issue of RTO benefits versus costs and disadvantages, “in terms of both reliability and consumer protection, are complex and multi-faceted.” 

The only proposal before the Commission is the SEEM “and under section 205 the Commission’s analysis is limited to whether this proposal is just and reasonable and not whether some other proposal is more just or more reasonable,” he wrote in his Oct. 20, 2021 statement.

Commissioner Danly

For his part, Commissioner James Danly said that the Commission’s “deficient notice is just one more in a line of improper procedural maneuvers that have unjustifiably delayed the establishment of this market and delayed the issuance of a merits order by half a year.”

Danly said that “in the face of all of the potential benefits that could be realized by the creation of the Southeast EEM, and the fact that there is virtually no downside to its implementation, there is simply no lawful basis upon which to reject this submission.”

While protestors raise concerns with various aspects of the SEEM proposal, “we should have found that the filing parties have satisfied their burden under FPA section 205, and we should have ruled on the proposal before us and not upon protestors’ alternatives.”

He noted that FERC will get a second chance to issue a merits order in response to requests for rehearing. “I sincerely hope that wisdom prevails, and that the Southeast EEM proposal is ultimately accepted,” he said in his statement.

However, should this matter eventually come to the court under FPA section 205(g), “the court should remand it back to FERC for an order in the first instance. Failing that, if the court chooses to issue a decision on the merits, it should deny the petitions for review and remand with instructions that every aspect of the filers’ submission — in all related dockets — be accepted,” Danly said.

Background on SEEM

On Feb. 12, 2021, Southern Company Services, Inc., as agent for Alabama Power Company, filed the SEEM agreement on behalf of itself and the other prospective members of the SEEM. In addition, seven prospective SEEM members on Feb. 12, 2021 submitted certificates of concurrence to the SEEM agreement.

Over the summer, SEEM members offered changes to the proposal that they said would create greater oversight ability for FERC and more transparency for all participants.

Fitch Highlights Fayetteville Public Works Commission’s Strong Financial Performance

October 24, 2021

by Paul Ciampoli
APPA News Director
October 24, 2021

Fitch Ratings has assigned and affirmed an “AA” rating to bonds issued by North Carolina’s Fayetteville Public Works Commission (PWC). The rating reflects PWC’s very strong financial performance characterized by very low leverage, strong operating cash flow and healthy liquidity, Fitch said.

The rating outlook is stable for the public power utility, Fitch said.

Additional planned debt issuances to fund capital expenditures over the next five years will increase leverage for PWC, but Fitch believes revenue contributions from the utility’s multiple business lines, which includes electric, water and wastewater systems, will continue to support ratios consistent with the current rating.

“PWC maintains strong revenue defensibility assessment, which is buoyed by each utility system’s monopolistic revenue source characteristics and autonomous rate setting ability,” Fitch said.

The rating also considers an expectation for lower electric operating costs following the execution of PWC’s renegotiated Power Supply and Coordination Agreement with Duke Energy Progress, LLC in November 2019.

The power supply agreement is expected to save PWC approximately $300 million through the remaining life of the contract which extends to 2042, although PWC has the option to terminate the contract in 2032, and in each year thereafter, if it provides a three-year written notice.

Fitch assigned the “AA” rating to approximately $98.3 million revenue bonds, series 2021, issued by PWC.

In addition, Fitch affirmed the “AA” rating to approximately $266.6 million outstanding series 2014, series 2016 and series 2018 parity revenue bonds issued by PWC.

In addition, Fitch has assessed PWC’s Standalone Credit Profile (SCP) at “aa.” The SCP represents the credit profile of the utility on a stand-alone basis irrespective of its relationship with and the credit quality of the city of Fayetteville, N.C.

OPPD Board Approves Selection of Jeff Bishop As CFO, Vice President Of Finance

October 22, 2021

by Paul Ciampoli
APPA News Director
October 22, 2021

The Omaha Public Power District (OPPD) Board of Directors recently approved the selection of Jeff Bishop to serve as the utility’s chief financial officer (CFO) and vice president of finance.

He brings more than 20 years of experience in energy and consulting and will start Nov. 15.

The CFO position at Nebraska public power utility OPPD was previously held by Javier Fernandez, who recently became President and CEO of the utility. Fernandez

Bishop comes to OPPD from Washington State, where he was CFO of the Grant County Public Utility District for the past four years. He was responsible for a number of areas, including Finance, Accounting, Treasury, Accounts Payable, Information Technology, Forecasting, Planning & Analysis, and Corporate Services.

Jeff
Jeff Bishop

He previously served as the senior vice president, CFO & treasurer of GridLiance in Irving, Texas. GridLiance, a NextEra Energy company, develops, owns and operates transmission assets with public power utilities.

Before joining GridLiance, Bishop served as chief financial officer of Seattle City Light. His utility experience also includes eight years of service at PacifiCorp Energy in Portland, Ore., where he worked his way up from lead senior financial consultant to managing director of Finance/controller.

Bishop is a licensed certified public accountant and serves on the Large Public Power Council as a member of the Chief Financial Officers Committee.

LES Customers Helped Reduce Peak Summer Demand Through Utility Program

October 22, 2021

by Paul Ciampoli
APPA News Director
October 22, 2021

Participants in a Lincoln Electric System (LES) program this summer helped the Nebraska public power utility reduce peak summer demand by approximately four megawatts. This was accomplished through 15 events that adjusted thermostat temperatures thanks to program participants.

“Four megawatts is the equivalent power demand of eight big-box retail stores,” noted Marc Shkolnick, manager for Energy Services at LES. “By having the ability to reduce peak demand with the help of our customers, LES can cost-effectively delay the need to add another generating source to its portfolio.”

LES launched Peak Rewards in 2018 to work with residential and small commercial customers to better manage the system’s peak demand through internet-connected thermostat adjustments.

Customers with qualifying, internet-connected thermostats controlling their central air conditioning system are eligible to participate. They are rewarded with monetary incentives to enroll and reduce electricity use during periods of high demand.

Incentives come in the form of a one-time $25 Amazon e-gift card for enrolling. There is also a $25 bill credit after the close of each program year.

“During our peak demand season, we assess historical usage trends alongside a 15-day weather forecast every morning to help us decide if calling an event that day is necessary to minimize our monthly peak demand,” said Lee Anderson, supervisor, System Energy Maintenance at LES.

DOE Report Distills Challenges and Opportunities Utilities Face As EVs Proliferate

October 21, 2021

by Peter Maloney
APPA News
October 21, 2021

The Department of Energy (DOE) has released a report on the issues and opportunities facing utilities as electric vehicles become more widespread.

A wave of electrification will put millions of personal and commercial electric vehicles (EVs) on U.S. roads in the coming decade, according to the report, An EV Future: Navigating the Transition, by the DOE’s Office of Electricity’s Advanced Grid Research Division (AGR) and the Office of Energy Efficiency and Renewable Energy’s Vehicle Technologies Office (VTO). That “wave may be more like a tsunami,” the report’s authors said, noting that the “merging the transportation and electricity sectors has the potential to fundamentally transform how customers fuel vehicles and how goods are transported across the country.”

To address the challenges of more widespread electric vehicle use, the AGR and VTO in July 2020 launched the Navigating the Transition initiative, taking the same Voices of Experience approach the DOE has used for other initiatives it has conducted.

To implement the EV initiative, the DOE hosted a series of 33 two-hour virtual meetings covering 15 topics. An industry steering committee provided feedback and input into the scope and topics to ensure alignment with stakeholder needs and interests and to avoid duplication of other efforts.

The steering committee included Bill Boyce, supervisor of electric transportation at the Sacramento Municipal Utility District in California, and Patricia Taylor, senior manager for regulatory policy and business programs at the American Public Power Association.

In addition to participation on the steering committee, the following public power utilities also participated in the initiative as presenters:

The topics participants in the initiative explored and debated fell into three broad areas: planning, operations, and business case. Planning topics included forecasting EV market penetration and adoption rates, as well as considerations regarding the fulfillment service requests and the timing of adding new EV charging infrastructure.

Operations included topics such as how fast charging technologies can affect the electric grid and the impact extreme events could have going forward.

Business case topics included ownership models for the EV technologies that will be deployed and the financing of charging infrastructure.

While electric rate reform is an important issue, the design of the DOE initiative touched on existing rate structures but did not explore rate reform alternatives because of the enormity of the topic.

Key Takeaways

Noting that the report is not a roadmap or technical report, the authors did compile several key takeaways based on the 66 hours of stakeholder conversations. Among those takeaways was the recognition that EV loads are mobile and unpredictable and, therefore, processes and regulations may need to evolve to respond to customer requirements. The participants also noted that social justice issues will require special attention as the country moves away from an early adopter phase.

The participants agreed that a robust, visible charging network will be critical as EV penetration rises. Not all drivers will be able to charge at home, the participants noted, and even those who can charge at home will likely want the comfort and security of being able to charge when they need to wherever they are.

The deployment of EV infrastructure will face the added challenge of a shortage of skilled workers, including electricians, meter technicians and contractors that can work with high voltage equipment, the participants said.

The participants also noted that the charging of electric vehicle fleets will be more challenging than charging in residential neighborhoods. Electrifying a fleet of delivery trucks or buses could increase load requirements by double or triple digits, possibly requiring new substations or transmission lines, they said.

Utilities will be a key nexus in the transition to an electrified transportation sector, the participants said. Utilities will likely, in the near term, be required deploy and maintain the backbone infrastructure needed for charging stations. The modernization of the grid is changing the nature of utilities’ relationships with their customers, and electric vehicles will amplify this change, the participants noted in the report.

As electrification continues to move forward, collaboration will be key and stakeholders who have worked together in the past will likely work together differently in the future, the initiative participants noted. They also noted one piece of recurring advice throughout the initiative: embrace the local utility as a partner.

CPS Energy President and CEO Paula Gold-Williams To Depart Utility In Early 2022

October 21, 2021

by Paul Ciampoli
APPA News Director
October 21, 2021

CPS Energy President and CEO Paula Gold-Williams on Oct. 21 informed the public power utility’s Board of Trustees of her plans to leave CPS Energy in early 2022.

Gold-Williams will work cooperatively with the Board of Trustees through this transition, San Antonio, Texas-based CPS Energy said.

The board will form an executive search committee for a new President and CEO and will update the public once that information is finalized.

“We are confident that Ms. Gold-Williams will continue to provide excellent guidance to her employees and the company as we go through this transition period,” said Board Chair Dr. Willis Mackey. “Board members are committed to a thorough search to fill this vital role. We expect to have additional information about next steps in the coming days.”

JEA Launches Program To Shift EV Charging To Off-peak

October 21, 2021

by Peter Maloney
APPA News
October 21, 2021

JEA, the public power utility serving the greater Jacksonville, Florida, area, has launched JEA Drive Electric, an electric vehicle education, marketing, and peak load reduction program.

JEA and its partner, Sagewell, designed the program to encourage electric vehicle adoption and provide incentives to drivers who charge their electric cars during times of lower electric demand.

The marketing program was built around Sagewell’s EV Expert service, a concierge service that educates customers about electric vehicles and connects them with local dealerships and installers of residential EV chargers.

The JEA Drive Electric program will also work with automobile dealers and manufacturers to secure and publish electric vehicle purchase and lease discounts.

Sagewell and JEA are also working to reach a wider group of customers by coordinating with local organizations to reach new communities and lower barriers to electric vehicle ownership.

JEA is seeking to enroll 1,000 drivers in an EV Charging Rebate program, its version of Sagewell’s Bring Your Own Charger (BYOC) load management program. Participants would program their vehicles to charge during off-peak hours, and algorithms developed by Sagewell would confirm off-peak charging compliance from regular household smart meters.

The American Public Power Association awarded the BYOC program its Energy Innovator award in 2018. In 2019, the Wellesley Municipal Light Plant in Massachusetts launched a BYOC program, making it the fifth municipal electric department in Massachusetts to adopt the program.

Communities that have adopted a BYOC program have seen participants shift over 90 percent of their charging to off-peak hours, reducing the need for costly utility upgrades, according to Sagewell.