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By Benoit Laclau
Global Energy & Infrastructure Leader
Blog
4 min
4th November 2026
For utility leadership teams, the question is shifting. The question is no longer only how much capital can be deployed. It is how confidently that investment can be converted into assets in service, at the expected cost and on the promised timeline.
That makes delivery certainty a strategic and financial issue, not just a project-management challenge. The test has two sides: what a loss of delivery certainty costs, and who is now checking whether approved capital delivers.
Delivery certainty is about more than projects running late. When a capital project slips, the most visible consequence is usually the schedule. But schedule delay is only one part of the value at stake.
“When a capital project slips, the most visible consequence is usually the schedule. But schedule delay is only one part of the value at stake.”
First, recovery and earnings timing. When assets enter service later than planned, recovery and returns move with them. At an annual allowed return of approximately 9%, a one-month average delay on $1 billion of annual capital spending shifts the timing of roughly $7.5 million of return. Allowance for funds used during construction (AFUDC), or construction work in progress (CWIP) in rate base where permitted, can soften the timing. Neither removes the delivery risk, the project costs or the delay in customer benefits.
Second, the direct costs associated with delay. Additional labor, contractor, project-management and overhead costs accumulate as schedules extend.
Third, cost growth beyond the delay itself. Scope and design changes, weak estimates, rework, procurement changes, unclear utility/EPC hand-offs and misaligned contracts can all increase the eventual cost of delivering an asset.
The potential value at stake can be significant. In one recent transmission and distribution (T&D) review, Newton identified potential annual benefits equivalent to 5–10% of capex from faster recovery and lower delay-related labor and overhead. A separate potential opportunity of 10–20% came from reducing cost growth beyond delay. These are findings from a single review rather than an industry benchmark, but they show where the value can sit.
Those three buckets focus on the capital program itself; they are not the full measure of the impact on a network business. Delays can propagate across the capital portfolio and into wider operations. A delayed substation upgrade can hold up a new connection, preventing connection work from proceeding as planned and creating a clash with a scheduled outage window, potentially during peak demand. Crews and suppliers must be rebooked, maintenance competes for the same capacity, and assets awaiting replacement may need to remain in service longer. Aligning these dependencies is critical: otherwise, teams are continually managing clashes that undermine capital efficiency, long-term asset health and the ability to connect new load quickly.
The cost of delivery uncertainty does not begin or end with the completion date.
Two financial tests can show whether delivery certainty is slipping. How many months of T&D spending does CWIP represent, how is that changing, and can the trend be explained by the investment ramp and normal project cycle? And are replacement and resilience programs absorbing the crews, engineering capacity and outage windows needed to connect new load?
“In one recent transmission and distribution (T&D) review, Newton identified potential annual benefits equivalent to 5–10% of capex from faster recovery and lower delay-related labor and overhead.”
At the same time, utilities are being asked to demonstrate the value of that investment to stakeholders with different priorities.
Large-load customers, including data centers, are seeking faster and more certain connections. Residential and small-business customers expect reliability and resilience, but also affordability and confidence that they are protected from costs created by new load. Investors expect approved capital to translate into assets, earnings and sustainable growth.
These priorities are not necessarily in conflict. Properly structured large-load arrangements can require customers to fund dedicated facilities and contribute appropriately to shared upgrades. The test is whether connection speed is achieved without transferring undue cost or risk to existing customers, and whether the wider system benefits are demonstrated.
Regulators assess investment through reliability, resilience, affordability and customer protection. Approval gets capital into the plan, but it does not end the regulatory test. Utilities must continue to demonstrate prudent spending, effective cost control and customer benefits.
Recent regulatory activity illustrates the point.
In Maryland, in March 2026, the Commission reduced Pepco’s reconciliation request from $30.6 million to $13.36 million. In October 2026, it found that project-plan changes had reduced the value of advance review and called for clearer explanations of project and budget changes, cost controls and customer benefits.
In Pennsylvania, the Commission approved around $275 million in additional annual distribution revenue for PPL Electric Utilities in June 2026, against the company’s request for $356.3 million, alongside requirements for reporting on approved reliability programs, spending, completed work and measurable outcomes.
These examples don’t point to opposition to investment. They illustrate something more fundamental: capital approval is the beginning of the accountability story, not the end of it.
As capital programs expand, utilities need to be able to demonstrate not only why investment is required, but how effectively it is being converted into tangible outcomes.
Why cost growth is now a regulatory question
Put the two sides together and the risk changes shape. Delay affects the timing of recovery and customer benefits and can also add direct project costs. Cost growth and material changes to approved work create a further risk because they are receiving closer regulatory scrutiny and raise questions about prudence, cost control and whether the promised customer benefits will be delivered.
That is also where our T&D review found the larger opportunity. The parts of capital delivery that are hardest to see on a schedule are becoming the parts that matter most in front of a regulator.
What does greater delivery certainty look like in practice?
Standardize where it creates value. A defined set of transformer specifications or substation designs, for example, can enable reusable engineering, simpler procurement, common training and fewer inventory variants. Standardization can also reduce unnecessary design variation and simplify future operations and maintenance. Projects can then be sequenced by readiness.
Improve the quality of the baseline. Stronger estimates and clearer scopes give leaders a more reliable view of cost, schedule and risk before execution begins. They also make deviations easier to identify and address.
Create clear accountability across interfaces. Utilities increasingly rely on complex ecosystems of engineering firms, EPCs, suppliers and other partners. Clearer ownership, better hand-offs and aligned commercial arrangements can reduce the gaps through which time and value are lost.
Identify risk earlier. Better data and forecasting can allow leaders to see emerging constraints before they become expensive delivery problems. Technology and AI can help where they improve estimates, identify patterns across the portfolio or expose schedule and cost risk sooner.
These fixes must work across the portfolio, not project by project. Improve one stage of delivery in isolation and the constraint simply moves somewhere else.
At Newton, we build portfolio delivery models that combine actual performance data with project dependencies, resource availability and outage windows. These help leaders understand how constraints in one part of the portfolio may affect delivery elsewhere, forecast likely schedule and cost impacts, and test mitigation before problems become more expensive.
For the delayed substation, that could mean testing whether earlier engineering support, a different construction sequence or additional supplier capacity would protect the connection date without displacing essential maintenance. The simulations also help identify where the next dollar should be spent to improve delivery certainty in the most sensitive areas of the capital portfolio. Relieving a critical bottleneck can unlock progress across several dependent projects, multiplying the impact of an intervention rather than simply improving one project in isolation.
From approved capital to delivered outcomes
With capital programs at unprecedented scale, small improvements in delivery certainty create significant financial and customer value.
That requires utilities to look beyond whether projects are “on time and on budget.”
How reliably does capital move from approval to execution? Where is capacity constrained? How quickly does investment translate into assets in service? Where is avoidable cost entering the system? And are those assets delivering the outcomes that justified the investment in the first place?
Those questions point to a broader measure of success: how reliably each approved dollar becomes an asset in service that delivers what it promised.
As demand grows and affordability remains under pressure, the utilities that can turn capital into operating assets more predictably will be better positioned to satisfy customers, regulators and investors alike.
The challenge is no longer simply to deploy more capital. It is to deliver on a commitment to customers, regulators and investors: approved capital, converted into assets in service and customer value.
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