The 2026 DER interconnection playbook for LDCs

The way energy is planned, produced, and delivered in the U.S. is changing rapidly. New climate policies and rising demand for affordable energy have driven a recent surge in solar and storage projects of all sizes.

For LDCs, this progress is more of a double-edged sword. These new assets help keep energy cleaner and more affordable while making the grid more resilient in the long term. But safely integrating them into the distribution system puts tremendous pressure on LDCs’ legacy planning and interconnection processes.

Keeping up with this shift requires more than incremental fixes to existing workflows; it calls for a fundamentally more transparent, technology‑enabled way to manage interconnection. For LDCs, there is only one way forward: adopt modern, data‑driven interconnection solutions that can unlock a more affordable, sustainable grid.

From one-way power flows to a distributed grid

The energy chain has historically flowed in one direction: Power plants produce energy, high-capacity networks move it long distances, then LDCs safely step it down, delivering it over neighborhood infrastructure to homes and businesses for end use.

Now that picture is changing.

How DERs upend the equation

As distributed technologies have matured, energy generation no longer has to begin at the power plant. Anyone from utility-scale solar developers to everyday EV owners can generate or store power on their own, through rooftop solar, battery storage, EVs, EV chargers, microturbines, and more. These small-scale, decentralized assets are known as distributed energy resources (DERs).

When those DERs produce more than a site needs, the excess can flow back onto the grid under net metering or similar programs. This widespread DER adoption means LDCs are now the gatekeepers, responsible for millions of small, variable injections at the edges of their systems — all while maintaining safety, reliability, and affordability.

Interconnection for the modern distribution grid

LDCs have always been responsible for deciding how new demand and resources connect to their local networks, but with DERs, it’s is no longer a simple, one‑off approval step. Every decision now has to balance engineering limits, daily operations, and evolving regulatory requirements. Interconnection is now one of the most demanding responsibilities LDCs hold.

The expanding demands of interconnection

Today, interconnection is more complex than ever, exerting far more pressure than these legacy, manual processes were built for.

On the technical side, LDCs must constantly estimate the impact of new DERs, ensuring they don’t push voltages, thermal limits, or fault currents outside of safe ranges on local equipment. This also means updating protection and control schemes to safely accommodate higher-impact DERs, like multi‑MW battery storage systems or large DC fast‑charging sites — a massive undertaking for already stretched engineering teams.

Interconnection also requires updating operating practices, procedures, and playbooks to handle higher DER penetration and more variable flows on distribution feeders. With so many projects moving in parallel, making space for them all can easily complicate grid planning and resource allocation, disrupting daily operations.

And all of this is happening amidst evolving regulatory frameworks. LDCs have to comply with shifting interconnection codes and utility commission rules that define how and when DERs can connect, while also hitting mandated timelines and transparency requirements for processing applications and sharing study results. If they fall short, penalties, audits, and disallowed cost recovery loom.

Despite this increasing complexity, interconnection at most LDCs is still reliant on manual handoffs and siloed data.

Legacy interconnection processes

These outdated, legacy processes many teams depend on were designed for a smaller number of large projects, not today’s volume of requests.

The process usually involves developer drafting interconnection plans with utility engineers via email and spreadsheets. Engineers will pull network data — loads, constraints, protection settings — from disparate systems and interpret it by hand. But without an official channel to route this data to the right planners and protection engineers, requests are processed ad hoc and require expert review at every step.

Lacking standardized, data-driven processes, leaders lose the ability to predict what will get built and when, making long-term planning and resourcing decisions increasingly uncertain. That uncertainty, in turn, contributes to massive interconnection backlogs that tie up capital and capacity for years and erode trust with developers.

As queues swell, regulators ask why timelines are being extended and why safety requirements aren’t being met, while developers eager to bring more affordable energy solutions online grow frustrated by delays.

While these processes often do lead to successful DER integration, they leave very little margin for error and simply can’t scale. Any small break in the interconnection framework or a lapse in following the requirements can result in a real reliability event on the grid.

While DER interconnections have not yet caused any large-scale outages in the U.S., they have been linked to local reliability events, including the 2017–2021 solar PV disturbances on the California ISO (CAISO) system and the 2021 Odessa, Texas disturbance — both of which showed how DERs can unintentionally worsen otherwise manageable grid faults.

Digital, data-driven interconnection is key to successful DER integration

The operational, regulatory, and customer-experience fallout has reached an inflection point: the Department of Energy has issued a national interconnection roadmap with explicit efficiency targets, including cutting median large-project timelines to under 140 days by 2030. What was once voluntary guidance is now a formal expectation for interconnection reform.

And momentum is building fast. According to the U.S. Energy Information Administration, “the U.S. added 53 GW of new electric-generating capacity in 2025” and developers are set to add a record 86 GW in 2026. Solar, storage, and other distributed clean resources are leading the surge, fueled by investor capital and reinforced by new incentives and federal funding. DER growth isn’t hypothetical — it’s accelerating on every front.

Against this backdrop, the message is clear: To meet emerging expectations and remain credible, LDCs must dramatically modernize and standardize their interconnection and transmission planning processes.

Precision software for LDCs

Modernization starts with redesigning how information moves through the organization — getting the right data in front of the right people at the right moment. And doing that reliably at scale requires software that’s designed around how LDCs actually work.

Fortunately, a new generation of software is ready to guide LDCs through this interconnection modernization.

When properly configured, precision software acts as a powerful operational layer that connects to existing data sources, codifies internal workflows and decision logic, and then transforms these inputs into custom-built applications that automate specific interconnection tasks. Here’s what this looks like in practice:

• Streamlined project intake and communications: Developers and utility engineers share a single portal for applications and status, enabling faster, more transparent decision-making and reducing back-and-forth and missed deadlines.
• A single source of truth for hosting capacity: Engineers log into that same portal to access up‑to‑date network models and hosting capacity views, allowing them to quickly evaluate current DER requests, spot tight capacity, and avoid rework on studies.
• Automated project prioritization: Software automatically performs routine screening and feasibility checks, auto‑approving low‑impact requests and routing higher‑impact cases to the right planners and protection engineers with clear queues, SLAs, and priorities — freeing experts to focus where it matters most.

Armed with unified data and standardized workflows, leaders can finally see which projects are moving, where the grid is constrained, and how to adjust. This means projects get delivered faster and within regulatory timelines, while customers have quicker access to lower-cost, reliable clean energy.

The long-term result is a greener, more affordable, and more reliable grid that’s strengthened, not strained by DERs.

Turn interconnection into a strategic advantage with Cogna

We are undoubtedly entering a new, bidirectional era of energy. Cogna is here to help LDCs navigate it by shifting interconnection from reactive, case-by-case engineering toward a more programmatic, data-driven capability.

Our experts work closely with teams to map out existing interconnection workflows, encode their decision logic, and create a new, fully modernized operating model. On top of that model, we layer customized applications that solve specific interconnection challenges. Those applications can be configured around each utility’s priorities, whether that’s managing centralized DER project intake, tracking application status, mapping hosting capacity, or prioritization and routing of studies.

With our guidance, LDCs design systems to effortlessly integrate high volumes of divergent DER requests — without straining grid capacity or stretching internal resources. Even better, our systems get smarter with use, learning from every new project, incident, or exception, helping you adapt to shifts in DER demand and grid complexity.

Industry leaders like Cadent Gas are already leveraging Cogna to gain better data visibility, automate essential functions, and future-proof their grids.

Prepare for the future of energy by booking a demo today.