Many of the challenges facing DER are not caused by intent alone, but rather by issues with accountability, operational standards and the readiness of industry infrastructure of large-scale integration.
A familiar critique appears in every conversation about distributed energy resources (DER): utilities are too beholden to rate basing to support DERs. The statement is easy to repeat and easy to believe, especially for developers and customers who experience slow interconnection timelines, vague requirements, and repeated studies. Many of the challenges facing DER are not caused by intent alone, but rather by issues with accountability, operational standards, and the readiness of industry infrastructure for large-scale integration.
Both sides of the argument have legitimate evidence.
From the outside, utility behavior can look like opposition. Projects face long queue times, inconsistent requirements, and iterative study processes that extend timelines. Critics also point to the structure of utility regulation. Cost recovery is clearer for capital investments than for ongoing operational work, reinforcing the critique that utilities favor infrastructure over third-party DER. If the system pays more reliably for physical infrastructure than for performance outcomes, the critique follows: utilities will tend to favor the former, consciously, or not.
Utilities, however, point to a different set of facts. They are accountable for safety and reliability in real time, including storms and extreme conditions. DERs can support the grid but only when they are observable, forecastable, and manageable where appropriate. Many people view DER through a bulk power lens, assuming DER availability can defer traditional capacity investment. That framing is directionally right, but it skips the planning question utilities must resolve: what share of DER is dependable capability versus variable contribution during peak conditions and grid events, and whether that performance is visible and enforceable.
When it is not, DER gets discounted in planning models, which limits its role as a true alternative.
In many jurisdictions, DER deployments have grown faster than the underlying standards, telemetry, cybersecurity pathways, and enforcement mechanisms needed to treat DER as dependable system capability. In that environment, conservative assumptions are not just cultural inertia, they can be a rational response to responsibility. Grid operators cannot be asked to rely on resources they cannot verify.
The debate stalls when it frames the issue as binary: utilities either support DERs or oppose them. In practice, the industry’s challenge is structural. DER integration is an operating model change, not a technology procurement It touches interconnection, planning assumptions, distribution operations, IT and OT architecture, cybersecurity, workforce training, and program performance. If any link in that chain is missing, the visible outcome is the same: delay, disagreement, and
frustration.
A straightforward way to examine the debate is to walk through the logic on both sides:
- Incentives
The critique is that capital investment is the primary path to cost recovery and earnings, while third party DER can defer traditional upgrades and shift value outside the utility.
The utility view is that rate-based investment is not simply a preference, it is the mechanism that finances infrastructure required for universal service and reliability. Even in a high DER future, distribution upgrades, protection modernization, communications, and operational systems are needed. DER does not eliminate infrastructure investment. It changes where, when, and how investment must occur.
- Interconnection
The critique is that lengthy and inconsistent processes function as soft denial. The utility view is that interconnection volume and complexity have outpaced staffing, tooling, and standardized procedures, and that feeder models and study methods were not built for the current pace. Both can be true: the outcome feels like obstruction even when root causes include under resourcing, outdated tools, and fragmented governance.
- Risk
The critique is that utilities lean on worst case scenarios to justify broad constraints instead of targeted mitigations and clear standards. The utility view is that protection coordination, voltage behavior, backfeed, and operational risk are real, and utilities are accountable when failures occur. The synthesis is that risk is real, but it must be differentiated. Scale requires separating systemic constraints from localized constraints and then building standards and mitigation that enable safe, faster adoption.
- Planning
The critique is that DER can provide peak reduction, resilience, and non-wires alternatives, but utilities avoid treating DER as planning grade. Utilities consider DER a planning resource only if its performance can be specified, measured, enforced, and backed by reliable telemetry and high quality data. The practical truth is that DER value is not automatic. It must be operationalized.
Utilities consider DER a planning resource only if its performance can be specified, measured, enforced, and backed by reliable telemetry and high-quality data.
This leads to the central conclusion: the core problem is not that utilities “like rate base” or “hate DER.” The core problem is that the regulatory model, the technical operating framework, and the organizational execution engine are not consistently aligned to make DER a dependable system capability.
DER at scale requires three conditions to be true at the same time.
First, accountability must be explicit. Who is responsible for performance during events. Who carries operational risk when dispatch commitments are not met or when telemetry fails.
Second, the operating framework must exist: Interconnection screens and standards, inverter behavior expectations, telemetry tiers, data exchange rules, cybersecurity pathways, and operating procedures.
Third, the utility must have execution capacity. People, sustained funding, training, tooling, program governance, and an integrated roadmap must be in place to deliver the end state.
When these conditions are missing, a predictable loop emerges. Utilities say they cannot rely on DER because it is not observable. DER providers say utilities are not building the systems that would enable observability and control. Regulators ask for speed and scale, but utilities struggle to justify sustained operating budgets, hire specialized talent, and coordinate cross function delivery.
The path forward is straightforward if entities with decision authority choose to enable it.
First, fund the enabling backbone as critical infrastructure. DER integration depends on distribution visibility, communication, model management, operations tools, and data governance.
Then, pay for outcomes not just assets. If policy makers want faster DER integration, they can reward measurable outcomes such as interconnection cycle time reduction, verified hosting capacity improvements, DER visibility coverage, event performance, and reliability maintained while DER penetration grows.
Three, standardize the rules of the road. Clear, consistent technical requirements reduce bespoke negotiation and uncertainty led by those that operate the grid and are the ones held currently accountable. Standardization lowers costs for developers and utilities while reducing repeated studies and shifting expectations.
Next, define planning grade DER capability. Move beyond nameplate ratings to verified performance. Define requirements, measure them, and enforce them so planners can count DER with confidence and ensure funding and resources are available to support such efforts with partnership agreements with all end use hardware and software loops.
Lastly, assign single point account ability inside utilities. DER enablement spans planning, interconnection, operations, IT and OT, cybersecurity, and regulatory. Without a single accountable owner and a shared roadmap, organization silos will continue to slow delivery.
Execution still requires confronting internal obstacles. Workforce limitations in distribution engineering, protection expertise, OT integration, and cybersecurity are real. Hiring pipelines are slow, compensation is competitive, and training takes time. Budgets can be misaligned, with much of DER enablement landing as operating expense while many regulatory and internal processes are better suited to capital programs.
The debate about whether utilities support DERs is unlikely to disappear. But it becomes more productive when it shifts from motives to mechanisms. DER will scale when the industry aligns incentives, accountability, standards, and execution capacity. Without that alignment, the conversation will continue to cycle between critique and defense while practical integration advances too slowly for the moment.
Even in a high DER future, distribution upgrades, protection modernisation, communications, and operational systems are needed.
Dr. Elizabeth Cook, PhD, holding dual roles as the Vice President of Technical Strategy at the Association of Edison Illuminating Companies (AEIC) and as a consultant in grid modernization. At AEIC, she drives initiatives in electric energy innovation and operational excellence, working closely with technical committees, member companies, and directing projects at AEIC’s Center for Operational Excellence. Elizabeth is at the forefront of grid modernization efforts. Her expertise, honed through her experience as Director of Advanced Grid Systems at Duquesne Light Company, is pivotal in advancing digital transformation in utilities. She is also an adjunct professor, published author, mindset coach, and a mother of six. She holds a doctorate in electrical and computer engineering from the University of Pittsburgh.
This article was originally published in the June 2026 issue of the Grid Modernization and Flexibility magazine.
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