Progress By Design: Enabling DER Integration with the Capabilities Progression Model

As pressures on America’s electric grid continue to intensify, the need for smart, creative solutions that extend to bridge the gap between energy demands and potential generation shortfalls becomes ever more apparent. With population growth that is twice the national average, continued economic development needs, the increased energy demand from data centers, and consistently more intense weather patterns that drive up power usage, the Tennessee Valley is becoming a living laboratory for testing many of these solutions.

From the use of existing demand reduction techniques like voltage regulation to executing big ideas like the planned ethane-burning Whitehorn Creek Generation Plant being built by Holston Electric Cooperative (see page 18), local power companies (LPCs) across the Valley are leading the way in identifying and exploring cutting-edge ideas and new technologies that may hold the key for building and sustaining a more resilient and efficient electric grid. And with new options under TVA’s flexibility model, new battery storage technologies, plus an increasing number of controllable devices among the Internet of Things (IoT), opportunities continue to emerge for LPCs to utilize a variety of distributed energy resources (DERs) to help manage their system load and offset peak demand. In fact, incorporating DERs has been identified as critical to meeting the energy needs of the Valley and is one of the three core workstreams inside the Valley Vision initiative. During TVPPA’s Annual Conference in May, TVA Chief Commercial and Customer Officer Jeremy Fisher discussed the work of the Valley Vision DER work stream group and, in particular, highlighted their identification of battery storage technologies as a key element demanding greater focus. “It’s not for everybody, but on many of your systems, it does introduce potential financial benefit and increasing reliability and resilience, particularly when you’ve got those [kinds] of more rural radial feeds,” Fisher said.

Enabling DER Integration

Of course, integrating any type of DER into a distribution system requires careful thought, planning and the right system capabilities to effectively monitor, manage or optimize systems in real time.

To ensure LPCs have a framework for effectively executing DER projects, TVA recently introduced the Capabilities Progression Model (CPM): a strategic framework developed to guide LPCs in identifying and maturing the capabilities necessary to operate the grid of the future. Designed collaboratively with LPCs, the CPM ensures that utilities across the region have an identified pathway to modernize operations, optimize infrastructure and ultimately contribute to a more resilient and efficient energy system.

According to Jason Krupp, TVA Senior Consultant, “The CPM outlines 18 capabilities grouped into four stages of progression: enabling, planning and assessing, value generating and enhancing. At the heart of the CPM is the recognition that foundational, or enabling, capabilities are essential prerequisites for more advanced grid functions.”

Enabling capabilities form the foundational building blocks for more advanced grid functions. These capabilities include telecommunications and grid situational awareness and are the prerequisites for more complex capabilities like grid optimization and DER incorporation and optimization. They help unlock more advanced capabilities, leading to added benefits and value for the utility and its enduse customers. These enabling capabilities are especially critical for supporting and leveraging DERs, such as solar and battery energy storage systems, electric vehicles (EVs) and demand response programs. Without these foundational elements, LPCs cannot effectively monitor, manage or optimize systems in real time, which is critical for leveraging the full potential of DERs.

The next step in TVA’s CPM is planning and assessing capabilities that help a utility better understand and plan its system. For example, system modeling improves the ability to adapt to extreme weather events, understand options for alternatives and enable locational elements of DER and load.

Value generating capabilities enable a utility to better optimize and control their system to provide better service to the end-use customers as well as support the bulk electric system. Enhancing capabilities provide the opportunity for LPCs to extract more value out of the existing operational systems and capabilities across the enterprise.

As LPCs build enabling capabilities, achieving capabilities in the following three stages will become easier. For example, grid situational awareness is an enabling capability and refers to LPCs’ ability to monitor and report on their distribution system in real time. Grid optimization, a value generating capability, uses the information uncovered and sourced through grid situational awareness to optimize the performance and efficiency of the grid. To accomplish grid optimization, LPCs must first have achieved some level of grid situational awareness.

The CPM also introduces two key benchmarks: the Valley Standard (VS) level, which sets the minimum recommended threshold for each capability, and the Valley Transformational Level (VTL), which details activities and objectives that optimize a capability, enabling stakeholders to benefit more from the value it offers. Achieving the VS is a critical first step for all LPCs regardless of size, geography or financial constraints. It ensures a consistent baseline across the region, enabling coordinated progress and shared benefits.

Getting Started

The CPM provides structured pathways for LPCs to modernize operations and support the integration of DERs, and it supports LPCs of all sizes:

Small LPCs

Small LPCs, especially those serving rural or low-density areas, face unique challenges such as limited budgets, aging infrastructure and fewer technical staff. For these utilities, foundational capabilities like telecommunications and grid situational awareness are critical enablers. These allow even the smallest LPCs to monitor their systems in real time, respond to outages efficiently and begin integrating DERs like rooftop solar or community storage.

Medium-Sized LPCs

Typically, these LPCs straddle the line between rural and urban service areas, requiring a flexible approach to capability development. For example, system modeling and other planning and assessing capabilities help medium LPCs adapt to extreme weather, optimize DER placement and manage load growth. Achieving the VTL in key areas like grid optimization or customer experience management enables these LPCs to deliver more value to their communities while supporting regional grid stability.

Larger LPCs

Larger LPCs are often at the forefront of grid modernization and DER integration due to customer interests and grid constraints. With more resources and complex infrastructure, they are well-positioned to lead the way in achieving VTL across multiple capabilities. However, even these utilities must ensure that foundational capabilities are in place to support advanced functions like real-time grid control, DER orchestration and customer-facing energy tools. The CPM encourages large LPCs to serve as regional anchors — demonstrating best practices, piloting new technologies and sharing insights that benefit smaller peers. Their progress is essential to achieving Valley-wide transformation, as their scale can drive significant improvements in grid resiliency, efficiency and flexibility.

LPCs Leading the Way

Currently, 107 LPCs have signed flexibility agreements with TVA and 34 generation projects have been approved. Meanwhile, a growing number of LPCs are exploring load management projects ranging from dispatchable voltage regulation and controllable hot water heaters to battery storage technologies and the integration of a variety of other DERs with huge potential for supporting load reduction needs.

Gibson Electric Membership Corporation Explores Innovative Approach

Gibson Electric, with a service area covering parts of northwest Tennessee and southwest Kentucky, serves a rural area that includes a large agricultural base. Rising temperatures and changing rainfall patterns, leading to more frequent and intense droughts, have led to a sharp nationwide increase in the need for irrigation. This, in turn, has increased electricity demand. In 2023, on-farm irrigation in the United States consumed 26.2 TWh of electricity. “Over the last decade, we have had more than 200 irrigation systems built in our service area. These run during summer peak periods, and we’ve seen a direct correlation between the irrigation systems and our peak demands in the summer months,” said Barry Smith, Gibson VP of Engineering and Operations.

To help reduce the impact of those irrigation systems on their peak demand, Gibson Electric is exploring a demand response program centered on optimizing the demand created by irrigation pumps/wells.

The project, currently in its beta phase, came out of a teamwide effort to find new ways to reduce wholesale power costs and help co-op members reduce their retail power costs. To enroll members in the project, Gibson representatives are making direct contact with their members with irrigation systems. “We are also working with vendors that supply irrigation systems to get them on board so they can help us explain the value of the program to our common customers,” according to Smith.

Peak demand for irrigation systems is during late summer afternoons. Demand response, according to VP of Technical Services Charles Phillips, will be “utility directed and partially automated.”

“We will use historical AMI data to perform data analysis and forecasting then utilize our fiber-to-premises network to execute the demand response,” he added.

Smith and Phillips believe there are additional benefits of participation that can further incentivize their members to participate in the program beyond any retail savings. Although the Gibson Electric project is loosely based on projects executed by cooperatives in the Midwest that are using demand response for irrigation, Phillips said, “What makes our project unique is we are trying to utilize our fiber-to-the-premises network to provide additional incentives for participation in the program. We are testing monitoring equipment on the irrigation systems to help members reduce the risk of theft. Providing that additional monitoring capability and protecting members’ assets [provide] economic value.”

He went on to say, “We think it’s going to reduce peak demand and improve our operational efficiency. By reducing the peak, we reduce the losses.”

Blue Ridge Mountain Electric Membership Corp. Joins Consortium with Volunteer Energy Cooperative, North Georgia Electric Membership Cooperative to Explore Battery Storage

Blue Ridge Mountain EMC, along with VEC and NGEMC, was tapped as part of a grant initiative by the Appalachian Regional Commission (ARC) that will help rural electric utilities and energy supply companies deploy smart grid technologies to better serve their communities and address challenges such as the rolling blackouts that have impacted consumers across the country during times of peak energy usage. The ARC is an economic development partnership between the federal government and 13 states across Appalachia.

Daniel Frizzell, BRMEMC Director of Engineering, said, “Volunteer Electric Cooperative initiated this partnership and invited us and North Georgia EMC to be a part of the multistate grant application. We are representing the state of North Carolina.”

The overarching goal of the project, according to Frizzell, is to study the impacts of DERs on distribution systems. Tennessee Technological University is also participating in the consortium, modeling data using a dedicated computer platform called HILLTOP, created by Tennessee Tech and Massachusetts Institute of Technology (MIT). Experiments will be performed with new technologies in a real-time simulated environment so that electric utilities can provide cost-effective testing and solutions prior to the implementation.

The battery storage project won’t be BRMEMC’s first venture into integrating DERs. “Our board had asked our general manager to look at opportunities for alternative generation and encouraged us to take advantage of our flexibility option, and we’ve utilized some previous grant funding to implement a 1 MW solar project on our campus.”

ARC is particularly interested in non-lithium battery storage solutions and wants to encourage demand for battery manufacturing in Appalachia because many new battery technologies use materials that are abundant in the Appalachian region, including iron and ethane.

Under the requirements of the grant, BRMEMC must find and test a suitable alternative battery storage technology. Frizzell and his team have a list of around 30 vendors they are researching to find the best fit. Blue Ridge plans to use a battery storage array for load shaving, charging the batteries during non-peak hours and then bringing them online during peaks. “Our goal is to have approximately 2 to 3 megawatts of storage. We are working to find a technology that will give us the best bang for our buck,” Frizzell said.

He also noted that BRMEMC has been an early adopter of many of the technologies necessary to successfully integrate DERs. “About 20 years ago, the state of North Carolina gave tax credits to encourage more solar generation, and that required us to make sure we had the right technology in place. The substation where we plan to site the battery array has SCADA relays in place. With SCADA and high-speed fiber throughout our system, we should have no issues calling up the battery storage when it’s needed.”

He added, “The whole goal for us is providing rate stability for our members. We already execute voltage reduction to help offset peaks and reduce costs; battery storage will just be another tool that allows us to help offset wholesale power costs and protect our members.”

A Team Effort

Efforts like those being explored by Gibson EMC and Blue Ridge Mountain EMC demonstrate that innovation and strategic planning can transform challenges into opportunities. Such initiatives represent more than individual effort — they are part of a larger commitment to building a resilient, efficient and sustainable energy future. With TVA’s CPM providing the roadmap and LPCs across the Valley embracing both foundational improvements and cutting-edge technologies, the region is not just adapting to the grid of the future, it’s actively creating it. The success of these early adopters will help pave the way for broader implementation across the Valley, ensuring that communities of all sizes can benefit from enhanced reliability, reduced costs and greater energy security in the years ahead.