Why Utilities Are Stalling on Clean Baseload and What That Costs Industrial Buyers

Utility procurement for new generation capacity runs on a cycle that is measured in years, sometimes decades. Environmental impact reviews, rate case proceedings, integrated resource plan updates, regulatory approval, financing, and construction together produce a timeline that is structurally incompatible with the urgency most industrial buyers feel when their energy costs are rising, their carbon commitments are intensifying, and their utility is telling them that new renewable supply will be available in 2031.

The gap is not a conspiracy. It is an institutional alignment problem. Understanding it is useful for industrial buyers who are trying to decide whether to wait for utility-delivered clean baseload or to take a different path.

How Utility Procurement Actually Works

State-regulated investor-owned utilities in the US develop Integrated Resource Plans, typically on 4-year cycles, that project capacity needs and identify how those needs will be met. The IRP process is the planning document. It feeds into a resource solicitation, which is a competitive bid process for new capacity. The bid evaluation takes months to years. The selected projects then go through their own permitting, financing, and construction phases.

A geothermal project bid into a utility RFP in 2025 that wins the solicitation might reach commercial operation in 2030 or 2031 under favorable circumstances. During those five or six years, the industrial buyers in that utility's service territory are still on the existing tariff structure, still managing demand peaks with diesel backup where their baseload supply is inadequate, and still waiting.

The utility has a legitimate reason for this pace. Committing to large capital investments on behalf of ratepayers requires regulatory certainty, established financing structures, and demonstrated technology risk. State utility commissions exist partly to ensure that utilities do not make imprudent capital investments that would be socialized across the rate base. The process is slow because the financial stakes are large and the consequences of getting it wrong are borne by customers who did not make the decision.

Understanding the institutional logic does not make the pace less frustrating for an industrial buyer. It does suggest that waiting for utility-delivered clean baseload is a reasonable choice only if your timeline allows it.

What the Cost of Waiting Actually Looks Like

Let us be concrete about what the delay costs. An industrial manufacturer drawing 8 megawatts continuously, operating in a region with a diesel-backed emergency generation capacity charge of approximately $18 per megawatt-month (a representative figure for demand response program costs in Western US utility territories), and running 2 megawatts of backup diesel for approximately 400 hours per year to cover grid unreliability and demand peak management, is paying something in the range of $180,000 to $350,000 per year in costs that are directly attributable to the absence of reliable clean baseload supply. That is a rough illustrative range, not a precise calculation for any specific site.

Over a 5-year wait, that is $900,000 to $1.75 million in costs that continue to accumulate. If carbon compliance costs are factored in through a state carbon pricing mechanism or a voluntary corporate commitment, the number goes higher.

The carbon cost is the more visible one in current industrial procurement conversations. Several large manufacturers in the Western US have committed to Scope 2 emissions targets that require clean electricity supply on specific timelines. A commitment to reach net zero Scope 2 emissions by 2030 that was made in 2023 does not automatically extend because the utility's clean generation timeline slipped. The industrial buyer is caught between a self-imposed timeline and a utility-paced supply constraint.

Interconnection Queue Dynamics

There is a secondary problem layered on top of the procurement cycle: the interconnection queue. New generation projects, whether utility-owned or independent, must complete an interconnection study process before connecting to the grid. The Federal Energy Regulatory Commission tracks interconnection queues across US ISOs, and the backlogs have grown substantially over the past several years.

As of recent FERC reports, the average time from interconnection application to commercial operation for projects that complete the process is roughly 4 to 5 years. A meaningful fraction of projects in queue are withdrawn before completion. The queue backlog is particularly pronounced for solar and wind projects, but geothermal projects entering the queue face the same process even if the technology is inherently more reliable and simpler to integrate from a grid stability standpoint.

Behind-the-meter industrial generation, including modular geothermal serving an industrial site directly, navigates a different and generally faster permitting process than grid-connected generation. This is one of the structural reasons behind-the-meter makes sense for industrial sites that do not need to sell excess generation into the wholesale market.

What Industrial Buyers Are Actually Doing

Based on conversations we have had with industrial procurement leads in the Western US, the response to utility delays falls into a few patterns. Some buyers are waiting, having concluded that the utility supply option will materialize on a timeline they can manage and that the transition costs in the interim are acceptable. Some buyers have shifted to renewable PPAs with large solar developers, accepting intermittency as a feature of their energy mix and managing the baseload gap with grid purchases and demand response. Some buyers have invested in on-site generation, typically gas-fired cogeneration or combined heat and power, as a bridge technology that reduces utility dependence but does not solve the carbon problem.

A smaller group is actively evaluating distributed geothermal for behind-the-meter baseload. This group tends to have a few characteristics in common: continuous 24/7 operations where intermittent supply creates real process disruption risk, sites in geological zones with accessible formation heat, and planning horizons of 15 to 25 years rather than 5-year capital cycles. These buyers are doing the feasibility work now because they understand that the 18 to 30-month development timeline for modular geothermal means that a decision made in 2025 or 2026 results in operational supply in 2027 or 2028, ahead of the utility timeline in many regions.

The Structural Mismatch and What It Tells You

The utility procurement cycle is not going to change fundamentally. It is governed by state regulatory processes that exist for legitimate reasons and that are not responsive to individual industrial buyer urgency. The question for an industrial buyer is not how to change the system but how to make rational decisions within it.

If your site is in a region with accessible geothermal resources, your load profile is suitable for baseload supply, and your timeline cannot wait 5 to 7 years for utility-delivered clean generation, behind-the-meter geothermal development is worth a serious look. The preliminary assessment step, which is a heat flow and geological feasibility review of your site, takes weeks not months and carries no commitment. It is the right first step before deciding whether to wait for the utility or to take a different path.

We are not suggesting that the utility path is wrong. For many buyers it is the right choice, particularly for sites without suitable geology or with flexible load profiles that can accommodate intermittent supply. The point is that waiting by default, without having assessed the alternatives, is itself a decision with a cost, and that cost is worth understanding before making it.