Summary
Public service commissions could create meaningful value for ratepayers served by utilities outside ISO/RTO markets by requiring after-the-fact testimony on how those utilities used, or declined to use, external market resources, month-ahead forward purchases, and related transmission reservations in the period leading up to delivery.
Utilities that operate outside organized markets often still have access to nearby ISO/RTO markets. However, they may have limited incentive to make the effort required to secure lower-cost market energy when it is available ahead of delivery. This is especially true when market access requires a separate transmission decision.
Key Issue: Market Structure
Utility managers can reasonably point to a mismatch between how market energy is priced and how transmission must be reserved. ISO/RTO day-ahead or forward energy prices may be lower than a utility’s expected production cost, but the utility must also secure transmission to deliver that energy to load. In some cases, firm point-to-point transmission must be reserved ahead of time and paid for as a monthly block of capacity. As a result, a utility evaluating market purchases one day at a time may conclude that no individual day justifies buying a full month of transmission.
That reluctance to rely on a central market may be rational for purely opportunistic hourly spot purchases or sales due to the commitment of purchasing a month of firm point to point transmission. But the market structure does offer opportunities for utilities to improve their portfolio-level decisions.
If transmission must be purchased in monthly blocks, then the utility should evaluate market purchases in the same way: as month-ahead block transactions. The relevant question is not whether a single day-ahead purchase is cheaper than self-supply after paying for a full month of transmission. The relevant question is whether month-ahead forward market energy, plus firm transmission, losses, congestion, and ancillary services, is cheaper than the utility’s forecasted avoidable production cost over the same delivery period.
A 100 MW purchase that looks uneconomic for a few isolated hours may become economic if paired with a monthly 100 MW firm transmission reservation and used across many hours. The fixed transmission cost is then spread over a larger volume of delivered energy. If the all-in delivered market cost is $25/MWh and the utility’s forecasted avoidable production cost is $30/MWh for the relevant hours, the purchase can reduce total production cost. The correct comparison is not market price versus average embedded cost of service. It is all-in delivered market cost versus the fuel, variable operations and maintenance, emissions, startup, and other production costs the utility can actually avoid by purchasing external energy.
Utility Practices
In practice, utilities may not consistently perform this analysis, although their internal processes on this topic are often not public. Instead markets are typically only considered for longer term RFP decisions or on real-time or day-ahead opportunities.
But the transmission structure itself may be signaling that the utility should be evaluating month-ahead block power purchases, short-term bilateral contracts, or other near-term forward products rather than relying only on spot-market opportunities.
A commission requirement could make this decision-making visible without requiring extensive public disclosure of sensitive commercial data. Each month, alongside the data provided to the public service commission for fuel adjustment clause review, the utility could file testimony showing its forecasted production cost, relevant month-ahead forward market pricing, estimated transmission costs, and an explanation of whether it considered fixed-price power and transmission from the market. The filing would not need to prove that the utility selected the cheapest possible strategy in hindsight. Instead, it would need to show whether the utility made a disciplined, good-faith, portfolio-level evaluation of external market alternatives before delivery.
The value of this approach is cultural as much as financial. Non-RTO utilities remain skeptical of nearby organized markets, and the complexity of ISO/RTO participation can sometimes reinforce a preference for relying on owned generation – especially when integrating decisions into a monthly resource planning decision cycle. If that preference is justified, then utilities should be able to demonstrate to regulators, with a limited amount of supporting data, that their expected generation costs were below what the market could reasonably provide on a delivered basis.
This process would also help commissions distinguish legitimate reliability caution from institutional inertia. Over time, it could improve maintenance timing, reduce avoidable production costs, increase transparency, and lower customer costs without requiring full RTO membership or centralized dispatch. Connecting this reporting to the fuel adjustment clause process would also give regulators a practical and timely mechanism for reviewing whether utilities are reasonably evaluating alternatives to self-supply.
It is difficult to see how this requirement would impose excessive costs if designed properly. The requested analysis would focus on the month-ahead procurement window and would rely on information utilities should already be reviewing as part of fuel planning, risk management, and purchased-power evaluation. The requirement would not force utilities to enter long-dated hedges or multi-month speculative positions. If a utility considered or executed a month-ahead market purchase, any associated margin, credit, or collateral implications could be summarized at a high level without requiring public disclosure of commercially sensitive details.
Ultimately, utilities should not be able to avoid organized-market alternatives simply because those alternatives require additional analysis. The fuel adjustment clause process is already a practical venue for reviewing fuel and purchased-power costs. Public service commissions could use that process to require disciplined evaluation of nearby market opportunities, while preserving utility discretion over reliability, operational risk, and final procurement decisions.