A clearly defined problem should be the starting point. A corridor with repeated storm-related outages might warrant consideration for different reasons than one serving customers for whom an interruption carries unusually severe consequences. A corridor exposed to wildfire risk might warrant consideration because of the dire potential consequences of an ignition. Establishing those distinctions helps the utility determine where undergrounding deserves closer evaluation and what the proposed conversion would need to accomplish.

Corridor screening should consider both exposure to hazards and the consequences of failure. Historical outage patterns can help identify persistent trouble spots, while an assessment of future risks might reveal vulnerabilities that past performance does not fully capture. The resulting priorities should reflect the utility’s objectives, with a documented rationale for advancing particular segments. At this stage, a brief comparison with other mitigation approaches can help establish whether undergrounding merits further investigation.

Success should be defined before design begins. If the objective is to reduce recurring interruptions, the utility needs a baseline against which to measure improvement. If the concern is prolonged restoration or disruption to critical customers, outage frequency alone may not capture the intended value. Measures should reflect the problem that prompted consideration of the project and provide a basis for evaluating its eventual performance.

This screening process establishes an initial set of candidate corridors whose expected benefits justify further analysis. As corridor-specific costs and delivery constraints become clearer, the utility can revisit those priorities and direct investment toward projects that continue to support its objectives. 

Once a corridor merits closer evaluation, the utility needs to establish whether its expected benefits justify the cost of conversion. That assessment depends on a comparable estimate of the available approaches and a clear explanation of how the investment supports the utility’s objectives. Broad assumptions about the cost of undergrounding provide limited guidance for an individual project.

The Power Delivery Intelligence Initiative (PDi2) “Utility Undergrounding Life-Cycle Cost Guide” reports an upfront underground construction cost differential of approximately two to three times comparable overhead construction for strategic programs designed around life-cycle cost and defined resilience and reliability targets. That finding challenges traditional assumptions of a much larger differential — as much as 10 to 15 times — but it still should not become a default estimating factor. Local construction conditions and the extent of the conversion can substantially change the comparison.

A useful estimate distinguishes electrical equipment costs from the civil work and service transitions needed to put the system into operation. In a developed corridor, excavation and roadway restoration may account for substantial uncertainty. Relocating other utilities or maintaining temporary service can add costs that a simple comparison of overhead and underground equipment would miss. Making these assumptions visible helps leaders understand both the realistic, expected investment and the range of possible outcomes.

The benefit assessment requires similar discipline. Potential reductions in restoration and vegetation management costs should be evaluated alongside the operating and replacement costs of the underground system over a consistent study period. Reliability and public-safety benefits also need a stated basis, with a distinction between savings the utility expects to realize and broader benefits to customers or the community. Sensitivity analysis can show whether the investment would remain justifiable if construction costs rise or projected savings are lower than anticipated.

The approval and funding approach should reflect the utility’s governance and the purpose of the project. The applicable approval criteria should inform corridor screening from the outset, because different requirements can produce different investment priorities. A commission, governing board or other approving authority needs to understand why the selected corridors warrant investment and how costs would be allocated.

The business case should also establish which utility and community benefits that authority will recognize in its evaluation. In situations where the most direct benefits are localized but costs would be shared more broadly, the rationale for that allocation deserves explicit attention. A credible investment case connects the proposed spending to measurable objectives while making its assumptions and uncertainties clear. 

The expected benefits for a corridor might justify further investigation while substantial questions remain about how underground conversion would proceed. Before approving a project for detailed design, utility leaders need enough engineering and field investigation to understand the constraints that could change its scope, cost or schedule. The objective is to identify those constraints early enough to inform the investment decision.

Electrical feasibility is part of that assessment. The proposed system must accommodate expected load growth within the space available for cables and structures. Underground conditions affect how effectively cables dissipate heat, which can influence the configuration and capacity of the installation. A preliminary design should establish a credible route and electrical concept, including how the converted segments would connect with existing protection and switching. Discovering a major constraint later could undermine the estimate used to justify the project.

Field investigation should address the subsurface conditions most likely to affect construction. Existing records may provide an incomplete picture of buried utilities or abandoned infrastructure. Targeted investigation, including subsurface utility engineering (SUE) where appropriate and with defined requirements for the quality of utility-location information, can help narrow that uncertainty. Groundwater or contaminated soil could introduce additional complications, while roadway restrictions and easement requirements could limit when and where crews can work. Permitting requirements and review timelines should also be reflected in the delivery plan. The extent of investigation should reflect the potential consequences of an unexpected condition.

Installation methods should be evaluated as part of this work. Open-cut construction may be practical along some portions of a corridor, while trenchless methods may help navigate major crossings or reduce surface disruption elsewhere. Existing duct could represent another viable option where its condition and capacity permit reuse. Those choices carry different requirements for access, thermal performance and restoration. Trenchless construction, including methods such as horizontal directional drilling (HDD), jack-and-bore or microtunneling, comes with its own risks, including the potential for drilling-fluid releases or failed installations. The selected approach should reflect conditions along each segment and account for how crews would respond if the installation could not be completed as planned.

Conversion planning also requires a workable transition from the existing system. Utilities must maintain service to customers as the construction advances, and electrical cutover may depend on relocating communications assets or other attachments before poles can be retired. Early coordination with joint-use owners and affected customers can clarify responsibilities and expose dependencies that could impact the schedule. Temporary-service arrangements and outage windows belong in the preliminary delivery plan.

These investigations will leave some uncertainty unresolved. Leaders should receive a cost and schedule range that reflects what is known, supported by contingency tied to identified risks. Each major authorization should identify the evidence required to advance and who has authority to approve that decision. It should also establish responsibility for managing the remaining uncertainty and what findings would trigger reconsideration of the project. That gives the utility a basis for advancing detailed design while retaining the ability to respond if conditions change. 

Undergrounding changes both a circuit’s exposure to hazards and the work required to maintain service. Reducing weather-related faults can improve reliability, but the value of that improvement depends in part on how the utility responds when a failure does occur. The operating model should be developed alongside the investment case so projected benefits reflect the capabilities and resources needed to achieve them.

An underground fault can take longer to locate, access and repair than an overhead fault. Fewer interruptions could still deliver a substantial reduction in total outage time, but frequency and duration need to be evaluated in relation to each other. The System Average Interruption Frequency Index (SAIFI) measures the average number of sustained interruptions per customer, while the System Average Interruption Duration Index (SAIDI) measures average total interruption time per customer over the reporting period. Undergrounding could improve both measures if fewer interruptions more than offset longer restoration times.

In one PDi2 composite case study of mid-Atlantic utilities programs, converted areas showed 99% improvement in both SAIFI and SAIDI; because the result was program- and geography-specific, it should not be treated as a universal performance factor. Results reported by other utilities can inform expectations; local system configuration and restoration capabilities will shape what a particular conversion delivers.

The proposed design should support the utility’s restoration objectives. Sectionalizing and switching arrangements affect how much service can be restored while a damaged segment remains out of operation. Fault-location equipment and trained crews help determine how quickly repairs can begin, while access to spare components and excavation support can influence how long they take. These capabilities carry costs that belong in the operating assumptions used to evaluate the project.

Asset management also changes when equipment moves underground. A buried system offers less visible evidence of deterioration, and its performance depends on cables, joints and terminations working together over time. Modern cables could have service lives exceeding 100 years, according to a 2021 T&D World article that also cited an approximately 50-year average life for wood poles. These component-level figures can inform life-cycle planning but do not establish the service life of an entire underground system. Condition assessment and eventual replacement still require planning and funding.

The same article also reports a review of public data for five investor-owned utilities in which overhead distribution maintenance costs per mile were three to seven times those for underground distribution. This illustrates potential savings, although local cost assumptions should reflect the utility’s own system and maintenance practices.

Before claiming operating savings, the utility should establish who will own the asset information and how inspection findings and failure records will inform maintenance decisions. It should also determine whether existing personnel and equipment can support the expanded underground system or whether additional capabilities will be needed. That preparation connects the proposed conversion to the organization that will operate it throughout its life. 

A strategic undergrounding program begins with a clear purpose and advances as evidence supports further investment. Corridor priorities should remain open to revision as investigation clarifies construction costs and operating requirements. At each major commitment, leaders need to understand whether the expected value remains credible and what unresolved risks they are accepting.

After energization, the utility should compare actual delivery and operating performance with the approved case, returning to the measures established during corridor screening. That review should account for schedule performance and maintenance demand as well as cost and reliability outcomes. The findings should inform future corridor priorities and estimating assumptions, including contingency.

Using actual results to refine subsequent decisions turns individual conversions into a more informed capital program. The framework’s lasting value comes from connecting each investment decision to a defined need, a workable delivery and operating approach, and results the utility can measure.