I've spent years watching solar projects get built. Some pencil out beautifully. Others bleed money in ways that don't show up until years later.

The difference usually comes down to assumptions made long before ground breaks.

Utilities face a particular version of this problem when they plan infrastructure investments. The stakes are higher because the assets last 30-40 years, and the financial structures create incentives that don't always align with what ratepayers need.

How Utility ROE Actually Works

When a utility builds new infrastructure, state regulators allow them to earn a return on that investment. In the US, the average utility ROE (Return on Equity) sits at 10.13%.

Here's where it gets interesting.

Evidence suggests that allowed ROEs have become increasingly generous since the 1990s. They've fallen less than prevailing interest rates and costs of capital. The data clearly shows ROEs are higher than what investors actually require.

This creates a structural incentive. Every dollar a utility puts into transmission rate base costs ratepayers more than $3.50 over the life of that asset, based on conservative assumptions.

You can see the problem. Utilities earn more when they build more, regardless of whether that infrastructure represents the most cost-effective path to meeting energy needs.

Where IRPs Enter The Picture

Integrated Resource Plans determine what gets built. More than 40 states have formal IRP mandates, typically updated every two to four years.

These plans map out electricity system needs and identify the optimal mix of generation and demand-side resources. They inform bidding processes and approval decisions.

Georgia Power's recent example shows the scale. Their 2025 IRP projects approximately 8,500 MW of electrical load growth over six years. That's an increase of roughly 2,600 MW by 2030 compared to their 2023 projections. The Georgia Public Service Commission approved this plan in July 2025.

The assumptions embedded in these plans matter enormously.

Cost Assumptions Drive Everything

The weighted average cost of capital can account for 20-50% of the levelized cost of electricity for utility-scale solar PV projects, according to IEA analysis.

Lower financing costs directly impact energy affordability.

For power generation, the cost of capital for utility-scale solar PV and onshore wind ranges from 3-6% depending on region. Offshore wind runs 4-7%.

But here's what I've learned from designing commercial solar systems: the cost assumptions that matter most aren't always the obvious ones.

The Real Cost Multipliers

Project delays compound in ways that financial models often underestimate.

From January through June 2022, about 20% of planned solar photovoltaic capacity was delayed. By Q3 2024, that figure hit 25% before dropping back to 20%.

Grid interconnection studies take 12-24 months due to transmission capacity constraints and utility coordination requirements. Equipment like transformers and switchgear require 12-18 month lead times that must align with construction schedules.

These delays don't just push timelines. They cascade through financing costs, contract penalties, and opportunity costs that rarely appear in initial ROI calculations.

Permitting: The Overlooked Variable

Soft costs account for about two-thirds of residential system costs. Improving permitting and inspection processes is crucial to reducing these expenses.

A typical PV permit takes 50 days at the median. But the distribution tells the real story. About half of permits take fewer than 27 days or longer than 96 days. That variance creates planning uncertainty.

The good news: median permit durations declined from 68 days in 2012 to 43 days in 2018, showing that process improvements work.

For commercial projects, large systems in jurisdictions requiring PE stamps and fire department reviews take 2-3 weeks. Utility-scale solar and wind facilities average four years from permitting through siting and construction.

I've seen projects where permitting delays erased projected margins. The issue wasn't the permit fee. It was the carrying costs during the delay and the downstream schedule compression that forced expensive workarounds.

Design Quality As Financial Risk Mitigation

Soft costs include labor, permitting, inspections, and design services. These directly impact long-term output and financial returns.

Urban environments present challenges like roof shading, structural constraints, and limited space. Infrastructure limitations, permitting hurdles, and site-specific engineering constraints complicate deployment and reduce system efficiency when you don't address them early.

Here's what I've learned from standing on commercial roofs: the failures that cost the most money happen years after installation.

I remember an Arizona rooftop project where membrane failure from installer traffic patterns took 18 months to settle. A wire management system failed after three years due to thermal cycling. These weren't design oversights. They were second-order effects that required construction experience to anticipate.

The financial models didn't account for these failure modes because they looked compliant on paper.

What This Means For Developers And EPCs

If you're developing commercial or industrial solar projects, the utility investment dynamics create both opportunity and risk.

The opportunity: utilities need to build clean energy infrastructure, and the ROE structure rewards capital deployment. Projects that can demonstrate lower total cost of ownership over the asset life become more attractive.

The risk: cost assumptions that look reasonable in year one can unravel if you haven't accounted for the variables that actually drive long-term performance.

You need to front-load the hard thinking.

Understanding local requirements prevents permit delays and interconnection approval issues. Quality designs enable faster permitting and reduce construction problems. Upfront investment in thorough analysis reduces downstream costs that compound over decades.

This isn't about perfection. It's about identifying the tricky items early, before they become expensive problems during construction or performance failures three years in.

The Electricity Rate Pressure Context

Lawrence Berkeley National Laboratory researchers show that electricity prices have risen nationwide from 2019-2024. The Energy Information Agency reports average retail electricity rates have risen more than 5% since last year.

Failure to invest in infrastructure that connects regions and concentrating investment where utilities can earn returns will continue driving up both system costs and rates.

This creates urgency around getting clean energy projects right the first time. Every revision cycle, every permit delay, every performance shortfall adds cost that ultimately flows to ratepayers.

What Actually Matters

The math behind utility clean energy investments isn't hidden because it's secret. It's hidden because the variables that matter most don't show up in the initial financial models.

ROE structures create incentives to build. IRPs determine what gets built. Cost assumptions determine whether those investments deliver value over their 30-40 year lifespan.

But the assumptions that actually predict long-term performance come from understanding what breaks things.

I've designed enough commercial solar systems to know: the projects that pencil out over decades are the ones where someone thought through the installation realities, the local permitting requirements, the thermal cycling effects, and the maintenance access patterns before the first panel went on the roof.

That's not engineering perfectionism. It's risk mitigation that shows up as ROI.

For developers and EPCs working in this environment, the question isn't whether utilities will invest in clean energy infrastructure. The question is whether your projects will deliver the performance that justifies those investments when regulators review the numbers five years from now.

The difference comes down to which assumptions you're willing to challenge before you break ground.