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The growth of distributed energy resources (DERs) is decentralizing energy production and management. The century-old model of centralized electricity production, transmitted in one direction for many miles at high voltage is changing. Onsite generation, battery storage, demand response, electric vehicles and energy efficiency have all contributed to this reshaping of the electric utility landscape. Joint Action Agencies, Associations and even individual electric utilities need to address the reality of DER growth so that they can benefit from its advantages and reduce the potential for negative impacts to their organizations and customers.

While the penetration of DERs has been steadily increasing due to declining costs of these resources, their growth over the next decade is expected to be exponential. Here’s why. Material and installation costs are declining while efficiency of DERs is increasing due to technological advancements. Electric utility customers are demanding greener and cost-effective energy options as they electrify. And there is regulatory support encouraging the integration of DERs such as the Federal Energy Regulatory Commission’s (FERC) Order Number 2222. The primary objective of this mandate, better known as FERC 2222, is to better enable participation by DERs in electricity markets run by regional grid operators. FERC’s directive, coupled with State and Federal mandates and policies, along with corporate goals around decarbonization are all expected to contribute to a future of high DER penetration in various jurisdictions around the country.

The question Public Power entities should be asking is not if their jurisdictions will see a high DER penetration, but how they can enable higher DER penetration to their advantage? This requires a paradigm shift at the distribution grid, where presently the utility is only managing a passive network - buying power from the Bulk level and distributing it to consumers, to a more active network – with two-way power flows from prosumers (producers + consumers), enabling cost-effective deep electrification.

An answer to the question of how to enable higher DER penetration lies in creating the right incentives that would encourage more such resources to be connected. And this is where the Distribution System Operator (DSO) model enters the picture. While many variants of the model may exist, from a thirty-thousand-foot view, in a DSO model, either a Joint Action Agency, Association, or the distribution utility takes on the role of a market facilitator. That market facilitator manages a distribution-level electricity market, much in the same way an Independent System Operator (ISO) manages a bulk-level electricity market. But the model can be customized based on local regulations and requirements.

Essentially the DSO framework allows the right incentives to be created for compensating DERs such that their true value to both the local and bulk grid can be correctly captured. For example, if unprecedented load growth on a particular feeder or station within a utility’s territory is requiring the utility to consider costly infrastructure upgrades, can the utility instead procure generation or load reduction from local resources on that feeder or station to defer or avoid the infrastructure upgrade? While a one-off situation like this might be handled by the existing framework through setting up some form of a demand response program, as the need for these infrastructure upgrades increases, the requirement to optimize the resources on the distribution grid, i.e. DERs, would increase. That would be the role of the DSO. The DSO model can provide significant advantages for all stakeholders. The DSO model extracts maximum value from DERs, provides grid flexibility, and takes a customer-centric approach to power supply decisions.

DSO Advantages for Public Power

The DSO model provides definite advantages to public power. First, it provides improved asset utilization and diversifies the local energy portfolio. It gives individual utilities the opportunity to work with customers who have on-site generation in new and exciting ways. By acting now, Public Power can set the standards for DSOs, with Public Power providing innovation and leadership in this important area.

The success of implementing the DSO model will require overcoming an array of challenges. As with most disruptive advances, existing regulations and market barriers could hinder implementation. Infrastructure upgrades will be necessary. Organizational changes and access to adequate resources will be critical to success. And finally, the support of customers and other stakeholders will be keys in making this transition a reality.

Joint Action Agencies, Associations and local public power utilities should begin now to develop DER and DSO strategies. Begin now to ask these questions: What is the regulatory and policy framework in which we operate today? Based on past experience with NERC standards, it will take time to develop DSO standards. Are our members/customers ready for increased DER penetration? Who are the key stakeholders, partners, and collaborators in this transition? And finally, does our organization have a roadmap for transitioning to the DSO model? 

Thought Leaders Weigh In

Recently, Hometown Connections Partners and Affiliates formed work groups to discuss the many aspects of the DER/DSO transition. The groups covered customer and employee engagement, smart grid technology requirements, operational flexibility and grid resiliency, cyber and physical security requirements, and DER grid integration.

Robbie Tugwell of Power Secure led the DER Integration discussions. His group debated the technical and operational challenges of integrating DER’s and explored possible solutions and best practices for effective integration. His group determined that a high level of transparency and clear communication pathways will be crucial in the successful integration of DERs into a DSO model. They stressed the need for flexibility of utility assets as well as clear decision matrices and protocols.

Loreto Sarracini of Acumen and his group explored the regulatory and economic implications of DER integration. This team expressed concern that the growth of DER may lead to a more complex regulatory environment. For example, the possibility of North American Electric Reliability Corporation (NERC) reliability standards being introduced for the distribution grid, which would likely lead to additional burden on utilities, especially smaller-sized utilities. While there might be many economic benefits of incorporating DERs, utilities will have to study the impact of adopting new technologies, hiring, training and retaining personnel as well as maintaining business continuity. 

AMP’s Branndon Kelly led a discussion of the smart grid technology requirements for an effective DER/DSO implementation. They stressed the importance of grid automation in preparation for the DSO model. Joint Action Agencies (JAA), Associations and their members will need to assess their distribution networks both from a hardware and software perspective. Software for modeling day ahead demand and production such as that provided by Amperon, will be a key ingredient for success. In addition, Jillian Jurczyk of Utility Financial Solutions stressed that rate design must be addressed to ensure the correct financial incentives for DSO participants and utility customers.

The DSO model represents a significant shift in how the electric grid will be sequenced. Employees and customers alike will be affected. Brittany DeArmon of Brillion led a discussion on how utilities and JAA’s can engage, prepare and educate these stakeholders. Bob Welsh of LeverageHR pointed out that workforce and customer education increase the utility’s opportunity to participate successfully in the DER/DSO transition. Tools for informing and educating are currently available, and utilities should act now to begin to build trust through more frequent and more transparent communication.

While a higher number of smaller-sized resources spread out across the grid offer the advantages of decentralization, they will substantially increase the cyber and physical attack surface, i.e. there will be a larger number of assets that threat actors can disrupt, many of which might not be in direct control of the utility itself. Doug Westlund of Acumen said that no single cybersecurity system will address all the risks. However, utilities who follow the regulatory guidelines for cyber security and physical security, and who are committed to planning and implementing protocols will be less likely to fall victim to outside attacks. 

Finally, Randy Parole from Stem, presided over a group that explored the strategies for enhancing grid operational flexibility and resilience through the use of DER’s. They looked at energy storage, flexible load management and grid modernization. This group suggested that the first step would be to look at the existing interconnection agreements to determine if they are future-proofed or need to be updated. From there, financial incentives for existing customers with on-site DERs should be developed. 

Next Steps

What are the next steps for Public Power entities looking to prepare for the future of DERs and DSOs? Nimish Bhatnagar, Director of Energy Solutions at Acumen, suggests the first step is to conduct a DER readiness assessment. JAAs and their members should review the regulatory and policy landscape. They should review load, generation and DER forecasts and perform a technology assessment and gap analysis. This assessment should be performed now regardless of the organization’s current view of how and how soon the DER/DSO transition will transpire within their service territory.

Next, develop a DSO transition roadmap. Build a business case, enlist stakeholder engagement and assess internal capabilities. Again, have the roadmap and other due diligence completed in advance. Having clear and actionable steps in place ahead of the transition will help ensure that Public Power utilities are in the driver’s seat and able to chalk their own path before one is drawn out for them!

A complete presentation on the DER/DSO transition is available on the Hometown Connections YouTube Channel. Access it here: https://www.youtube.com/@4PublicPower

Hometown Connections would like to recognize the following Hometown Connections Affiliates and Partners for contributing to this review of DER/DSO: Acumen, AMEA, AMP, Amperon, Brillion, ElectriCities of NC, FMEA, KTI, LeverageHR, Marsh, MPUA, NMPP Energy, NCPA, Power Secure, SpryPoint, Stem, TEA, TMEPA and Utility Financial Solutions.

Wildfires pose severe societal, economic, and personal challenges—especially when sparked by electric utility infrastructure. Fortunately, these types of fires are preventable. EGM’s Meta-Alert® Solution empowers utilities with advanced line-sensor technology and real-time analytics to detect potential ignition sources early. By enabling rapid response and enhancing situational awareness across the grid, Meta-Alert® reduces wildfire risk, protects critical infrastructure, and helps safeguard communities.

Read the full white paper here.

3-phase transformers serve essential customers such as hospitals, factories, agriculture and data centers and are often the most expensive asset in the distribution system. They are part of the invisible grid, often below grade or in vaults. 

Read the full white paper here.

A large investor-owned utility in the Southeast operates more than 80,000 miles of overhead distribution lines and serves approximately 9 million customers across a fast-growing service territory. Sustained demand growth—driven by new residential development, electrification, and economic expansion—has required the utility to add new circuits across an already dense distribution network.

Maintaining reliability at this scale is not optional. Every operational decision carries systemwide impact.

Challenge
As the utility added more circuits to meet growing demand, fault activity began to increase across the network. Protective devices were doing their job—reclosers operated correctly and cleared faults—but the utility faced a new operational reality:

Faults were occurring more frequently as network density increased
Many faults were momentary, but still required investigation
Crews were being dispatched without clear insight into root cause
Reliability metrics, including SAIDI, began to feel pressure
The problem was not protection failure. It was lack of visibility into fault behavior as the system grew more complex.

Without understanding why faults were happening—or whether they were isolated or systemic—the utility was forced into a reactive posture that increased O&M costs and operational risk.

Solution
To close this gap, the utility deployed Electrical Grid Monitoring (EGM) line sensors in combination with reclosers, creating a more observable and intelligent distribution network.

As new neighborhoods were commissioned, the utility standardized the deployment of:

Reclosers for protection and isolation
EGM line sensors placed strategically along feeders and laterals
EGM analytics software to turn raw fault data into operational insight
EGM’s platform provided detailed, real-time visibility into each fault event, capturing:

Fault magnitude
Direction
Phase involvement
Event patterns across circuits
This intelligence allowed engineering and operations teams to move beyond fault clearing and into root cause analysis at scale—something that was previously impossible across such a large network.

With EGM in place, the utility fundamentally changed how it responded to fault activity:
Cleared faults no longer automatically triggered truck rolls
Crews were dispatched based on data, not uncertainty
Engineering teams identified recurring fault patterns tied to load growth and circuit expansion
Maintenance practices evolved from routine investigation to targeted intervention
Instead of reacting to individual events, the utility gained system-level awareness of how growth was affecting reliability.

Results
The operational improvements delivered clear, defensible outcomes within the first year:

Up to 25% reduction in truck rolls, driven by fewer unnecessary investigations
7.5 SAIDI minutes saved across the system in a single year
$3.7 million in O&M savings, with no compromise to safety or protection
Improved reliability performance as new load and circuits continued to come online
These results were achieved while the utility continued to grow, proving that reliability and expansion do not have to be tradeoffs.

Benefits
For large IOUs, the challenge is no longer whether faults can be cleared—it is whether the grid can be understood as it operates under increasing load and complexity.

EGM helps utilities answer critical questions:
Are faults isolated events or early indicators of stress?
Where is growth changing fault behavior?
Which events require action—and which do not?
By delivering practical, real-time grid intelligence, EGM enables utilities to operate with confidence as their networks evolve.

Conclusion
By adding situational awareness where it mattered most—downstream of protective devices—the utility transformed how it understood and responded to fault activity. What was once a reactive investigation process became a data-driven operating model grounded in real-time insight.

This deployment demonstrates how targeted grid visibility can deliver meaningful reliability improvements at scale, without requiring an overhaul of existing infrastructure. As distribution systems continue to grow in size and complexity, visibility is no longer optional—it is foundational to sustaining performance.

Bring Visibility to Your Distribution Network
Learn how Electrical Grid Monitoring helps utilities turn fault data into actionable insight—supporting reliability as systems grow and evolve.

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Contact Information
Andrea Wenz
andrea.wenz@egm.net
403-973-3301

Fort Lauderdale, Florida (February 2, 2026) – Ubicquia, Inc., a leader in intelligent infrastructure solutions for utilities, municipalities and enterprises today announced the launch of AI-driven power monitoring services purpose-built for commercial and industrial (C&I) customers. Powered by Ubicquia’s AI driven UbiVu® analytics platform, the service delivers 24/7 monitoring, real-time visibility, and predictive insights into business-critical power quality issues—without upfront capital or operational disruption. 

Designed for C&I customers of all sizes, the new service helps businesses predict and prevent emergency outages and reduce the operational and financial risks associated with poor power quality. The service is particularly beneficial for commercial and industrial environments where power reliability is mission-critical including commercial and residential buildings, logistics and distribution centers, multi-location retail operations, manufacturing facilities, telecommunications infrastructure, and data- and energy-sensitive operations. 

“You can’t have grid reliability without grid visibility,” said Ian Aaron, Chief Executive Officer at Ubicquia. “We’ve taken the success of our UbiGrid® distribution transformer monitoring and UbiVu analytics platform deployed at scale with major utilities and made it available to commercial and industrial customers, as a service with no upfront capital. With UbiVu enabling the customer and utility to see the same real-time data, we can predict and identify power quality issues before they become failures.”  

A $145 Billion Annual Business Problem 

A study conducted by the Electric Power Research Institute (EPRI) estimates that poor power quality costs U.S. businesses more than $145 billion annually, driven by equipment damage, data loss, operational downtime, and increased energy costs. Without real-time visibility into power quality, businesses struggle to understand root causes, predict failures, or take proactive action to protect critical operations. 

Real-Time Visibility for Proactive Power Quality Management 

Ubicquia addresses these challenges with 24/7 transformer monitoring and AI-driven, real-time power quality analytics that translate electrical anomalies into clear business impact and actionable insights. Ubicquia’s service helps C&I customers prevent: 

• Damage to sensitive and high-value equipment (caused by sudden voltage events)
• Equipment malfunction, overheating, and shortened asset life
• Data loss and operational disruptions
• Unexpected increases in operating and energy costs
• Poor capacity planning due to unseen load growth

Power quality issues affect all buildings, including modern buildings, frequently causing equipment to overheat and waste energy. Ubicquia helps prevent these issues by continuously monitoring more than 24 power-quality parameters—such as voltage disturbances, harmonics, and load changes—and applies AI-driven analytics to detect, predict, and prioritize issues in real time. As part of the service, Ubicquia provides continuous monitoring and resolution coordination, working with both the customer and the local utility to quickly determine responsibility and accelerate responses. 

“Ubicquia’s power quality analysis delivers insights that traditional power quality meters simply can’t,” said Melvin Liwag, Senior Engineer, System Planning and Reliability Engineering, Orlando Utilities Commission. “Shared, real-time visibility allows us to quickly determine whether an issue originates on the utility side or the customer side, coordinate resolution, and help protect equipment, improve reliability, and extend transformer life.”

Simple, Scalable Service Model for C&I Customers 

• Low monthly cost per transformer business model
• No up-front capital  
• No downtime  
• Includes installation  
• Includes real-time data for both the customer and utility*  
• Includes 24/7 monitoring  
• Includes resolution coordination with the customer and utility 
   

* Real-time data can be integrated with existing building management systems and third-party platforms to support Energy Star™ compliance and revenue-grade metering. 

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About Ubicquia 

Ubicquia’s AI platforms make existing critical infrastructure intelligent to reduce energy consumption, increase resiliency, and enhance operational efficiency. Built on grid-scale deployments and billions of data points analyzed daily, Ubicquia’s analytics platforms deliver actionable insights across utilities, municipalities, and now commercial and industrial customers. Ubicquia® solutions—spanning sensors, software, and wireless connectivity—are compatible with hundreds of millions of grid and infrastructure assets worldwide and are deployed in more than 1,000 cities. For more information, visit www.ubicquia.com. 
 

[Ephrata, WA / Jacksonville, FL – February 18, 2026] – The Energy Authority (TEA) and the Public Utility District No. 2 of Grant County, WA (Grant PUD) announced today that TEA’s Board of Directors and Grant PUD’s Commission have approved Grant PUD’s Membership in TEA, deepening the organizations’ strategic relationship and expanding TEA’s Member footprint to be nationwide.

As a Member of TEA, Grant PUD will have access to TEA’s full suite of services, including energy trading and risk management, portfolio management, advanced analytics, and advisory solutions. 
Grant PUD will become TEA’s seventh Member on April 1, 2026, strengthening TEA’s public power membership base and aligning TEA’s Membership with its national client footprint. Grant PUD joins TEA’s existing Members: American Municipal Power, Inc.; City Utilities of Springfield, Missouri; Grand River Dam Authority; JEA; Nebraska Public Power District; and the South Carolina Public Service Authority (Santee Cooper).

Grant PUD first partnered with TEA in 2025, and the relationship quickly demonstrated the value of TEA’s services and experience. In a short time, Grant PUD saw the additional strategic advantages that Membership brings —deeper alignment, long-term stability, and a direct role in shaping TEA’s future—leading to the decision to join TEA as a Member.

“TEA has proven to be a trusted partner and regional leader as the West undergoes significant market evolution,” said John Mertlich, General Manager & CEO of Grant PUD. “Becoming a Member is a natural next step. It formalizes our long-term alignment and ensures Grant PUD and TEA work together to take advantage of the changing market landscape in the region. Being a Member of TEA also ensures that Grant PUD has a strong voice in TEA’s strategic direction as we work together to manage risk, capture value, and serve our customers with reliability and affordability.”

Grant PUD is well-known for its leadership in regional and national public power initiatives, including its role in the Large Public Power Council (LPPC) and its forward-thinking approach to navigating market transformation in the West.

“TEA is honored to welcome Grant PUD as our newest Member,” said Joanie Teofilo, President & CEO of The Energy Authority. “Grant PUD has long been recognized for its leadership, both in the Pacific Northwest and across the industry. Their decision to become a Member of TEA reflects a shared commitment to public power values, strategic growth, and building long-term strength through collaboration. We are thrilled to welcome Grant PUD as our seventh Member.”

“On behalf of the TEA Board, we are very pleased to welcome Grant PUD to Membership in TEA,” said Jimmy Staton, Chair of TEA’s Board of Directors. “As the nation’s leader in serving public power, it is important that TEA’s Membership reflects the breadth of our nationwide client footprint. Grant PUD is widely recognized as a leader in public power and an important force in the Western energy market landscape. Their perspective will strengthen the TEA Board and enhance our ability to serve public power across the country.”

About Grant County Public Utility District
Grant PUD, a public utility providing power and fiber service for Grant County, Washington, was founded in 1938 by local residents who envisioned affordable electricity for the entire county. Today, Grant PUD realizes that vision with a generation portfolio of more than 2,100 megawatts of clean, renewable, reliable energy, and by delivering power at some of the most affordable rates in the country. To learn more, visit www.grantpud.org.

About The Energy Authority 
TEA provides public power with access to advanced resources and technology for responding competitively in the ever-changing energy markets. As a national energy trading and risk management firm, TEA not only provides public power entities with a strategic perspective on deriving maximum value from their assets but also offers advisory services, advanced analytics, and renewable solutions. Through partnership with TEA, clients benefit from an organization that understands the unique challenges facing community-owned utilities today. TEA is currently partnered with over 70 public power utilities nationwide. To learn more, visit www.teainc.org.

When a utility provides multiple essential services, managing functions such as billing, operations and customer service can be extremely complex, both for employees and customers.

This is Newport Utilities’ story of how they evolved from a siloed approach, where every department was totally independent of one another, to the total integration of all aspects of the business.

Learn how this “small but mighty” staff is benefiting from the efficiencies NISC solutions provide.

Newport Utilities Case Study PDF
 

Rising demand forecasts are presenting significant challenges for public power utilities. A primary driver is data center interest within local communities.

According to APPA’s October 2025 report, What Public Power Needs to Know about Serving Data Centers, projections for data center capacity growth range from 50 GW (S&P Global Market Intelligence) to 120 GW (Deloitte and Lawrence Berkeley National Laboratory. At any end of that spectrum, it’s an historic amount of demand.

As you think about the issues surrounding meeting this unprecedented demand, new technologies should be a key focus for public power. A good example of this is the recent move by the Utah Municipal Power Agency to deploy 48 MW of new capacity using linear generators in Nephi, Utah.

Linear generators: One new solution worth your attention.

As I strive to keep abreast of evolving industry issues and challenges, I was fortunate about two years ago to learn of Mainspring Energy and the entirely new approach it is taking to meeting local power generation needs. Their demonstrated success, examples of which are below, is impressive.

The company manufactures Linear Generators: power generators that run on any fuel, are fully dispatchable, use no water, and emit near-zero NOx. With their proprietary technology, Mainspring delivers local power that can rapidly add new capacity and deliver reliable, affordable electric power. They began commercial shipments in 2020 and today have hundreds of megawatts in field operations and advanced development. I’ve been so impressed with their solution, in fact, that I’ve joined their Strategic Advisory Board.

A record of success with existing installations.

Most utility managers understandably don’t want to be first when it comes to adopting newer technologies. We all want the reassurance that a product is proven in customer field operations. Fortunately, there are multiple existing installations of linear generators up and running. I’ve visited some myself. Here are two installations I think you’ll find especially relevant.

An irrigation district powering one of the fastest growing cities in the U.S.

Lathrop Irrigation District (LID) is the municipal electric utility serving the River Islands community in Lathrop, CA — one of the fastest growing cities in the U.S. LID needed power to support approximately 4,000 homes and 3 million square feet of commercial space.

Their ideal power solution would help lower electricity costs, quickly dispatch to complement existing rooftop solar, and meet the NOx emissions compliance with the San Joaquin Valley Air Pollution Control District, one of the strictest in the country. What’s more, it had to fit in a limited footprint, scale with long-term community growth, and be deployed and permitted quickly to keep pace with development.

Mainspring’s low-emissions design and factory-built units enabled LID to secure air permits in three months and deploy 2.3 MW generators in seven months.

Commercially operational since February, 2025, LID is now meeting 95% of River Island’s peak demand, has 24/7 control over its electricity supply reducing its exposure to volatile pricing and rising transmission costs, and with Mainspring’s modular design, is well positioned for future capacity expansion.

10MW of new electricity without three years of grid infrastructure buildout.

Facing California’s ambitious zero-emissions truck mandate with properties near the Los Angeles and Long Beach ports, logistics real estate company Prologis needed to deploy EV charging infrastructure for its customer, Maersk, looking to charge a fleet of up to 96 electric drayage trucks.

This would require nearly 10 MW of capacity and take three years of grid infrastructure build-out.

Grid resilience and cost also presented longer-term challenges, as did the need to meet the company’s own ambitious sustainability goals. The new EV charging infrastructure needed to be fast, resilient, cost-effective, and clean.

Prologis reduced that estimated time for new power from nearly 36 months down to 9 months with a power solution consisting of 3 MW of Mainspring Linear Generators and 6 MW / 18 MWh of storage.

Commercially operational since 2024, Prologis has eliminated outage risk with an islanded microgrid, obtained best-in-class total cost of ownership resulting from competitive capital costs and low operating expenses, and has the ability to run biogas and zero-carbon fuels like hydrogen as well as natural gas. It’s the largest EV truck charging station in North America.

An opportunity to learn more through APPA

If this piques your interest, Mainspring will be participating in the APPA Engineering and Operations Conference, March 29 - April 1, 2026 and the annual APPA conference in June. Either would be a good place for public power managers and their staff to learn more about how linear generator technology can help meet the significant demand challenges facing today’s public power utilities.