Fuel hedging can be a legitimate risk management tool for regulated utilities. That point does not need to be overstated or relitigated every time hedge plans are reviewed. Fuel prices can be volatile. Ratepayers can be exposed to sudden changes in natural gas, coal, and purchased power costs. Utilities have a reasonable interest in reducing the risk that a single market event creates a sudden and significant bill impact.

But accepting the general case for hedging does not answer the more important design question: how far forward should a regulated utility begin hedging ratepayer exposure?

That question deserves more scrutiny than it often receives. A short-term hedge plan and a three- to five-year hedge plan may use similar instruments and similar governance language, but they do not create the same risk profile. The longer the hedge horizon, the more the utility is hedging uncertain operational forecasts rather than known fuel needs. That difference matters.

A common long-dated hedge plan works through a layered approach. The utility begins placing small hedges several years before the delivery period, then adds additional tranches as that period gets closer. At first glance, this can look conservative. It avoids putting all of the exposure into the market on one day. It spreads transactions across time. It creates the appearance of discipline. In that sense, it can resemble the logic of dollar cost averaging.

But that comparison only goes so far. A household investor buying an index fund every month is building a long-term asset position. A regulated utility entering fuel hedges is fixing prices against an expected operational exposure on behalf of captive customers. Those are not the same thing. The utility is not simply buying more of an asset over time. It is making financial commitments based on forecasts of future load, dispatch, generation availability, fuel burn, market purchases, transportation costs, and portfolio needs.

That is where long-dated hedge plans create additional risk.

One of the most important problems is the tendency to confuse longer-dated hedging with stronger risk management. A five-year hedge plan may sound more comprehensive than a one- or two-year plan. It may look more disciplined because it begins earlier and follows a pre-established schedule. But earlier action is not automatically better action. Risk management is not measured by how far into the future a utility transacts. It is measured by whether the utility is reducing the right risk, at the right cost, with the right information.

The most important risk is exposure forecast risk. Fuel exposure is not a fixed quantity that exists independently of the utility’s operating plan. It is the result of a forecast. A natural gas plant may have substantial fuel exposure under one dispatch scenario and much less under another. A utility may expect to buy energy from the market under one set of assumptions and rely more heavily on owned generation, PPAs, storage, or demand-side resources under another. Over a three- to five-year horizon, those assumptions can change materially.

Load forecasts change. Weather-normal assumptions change. Resource plans change. Unit retirements move forward or backward. Renewable additions, storage projects, transmission constraints, environmental rules, and market prices all affect future operations. A hedge placed years in advance may have been reasonable when entered, but the exposure it was meant to manage may not exist in the same form when the delivery period arrives.

That creates operational mismatch risk. The issue is not that a hedge should dictate operations. Utilities still need to dispatch economically and maintain reliability. The problem is that the hedge can outlive the operational assumptions that justified it. A utility can end up financially hedged for fuel burn that no longer occurs, or for market purchases that are later reduced by changes in the resource portfolio. The hedge plan may have reduced one risk, but only by creating another.

Long-dated plans also create path dependency. A utility can say that it updates its forecast each quarter, and that may be true. But reforecasting does not erase the hedge book already created. Once several years of layered transactions have accumulated, new information does not start from a blank slate. The utility has to manage the forecast change around existing positions. That means the longer the plan has been running, the less flexible it may become.

There are also important liquidity, collateral, and credit risks. These risks vary by instrument, but they become more significant as the hedge remains outstanding for longer periods of time. The more time a hedge is in place, the more time the market has to move away from the transaction price. Those price movements are what drive collateral requirements, margin calls, and credit exposure between counterparties. A long-dated hedge can therefore create a very real cash-management problem well before the delivery period begins.

If the market moves against the utility’s hedge position, the utility may be required to post collateral or transfer margin to another party. That money is still part of the economics of the hedge program, but while it is posted, it cannot be used for other purposes. In a volatile market, the amount can become substantial. A utility could have tens of millions of dollars sitting with a counterparty because of long-dated hedge positions that will not settle for years. That is not just an accounting issue. It is a liquidity, credit, and ratepayer-risk issue.

None of this means long-dated hedging should be prohibited. It means duration should be treated as a major policy choice, not a minor implementation detail. A five-year hedge plan should require more justification than a one-year plan because it creates a different set of risks. Regulators should ask why the specific horizon is needed, how reliable the exposure forecast is at each tenor, what happens if operations change, how positions can be rebalanced, what collateral stress tests show, and whether the same customer objective could be achieved with shorter-dated hedges, options, storage, index contracts, or more flexible procurement.

The prudence of a hedge plan should not be judged only by whether hedging is an accepted risk management practice. Duration matters. A program designed to reduce fuel-price volatility can quietly transfer forecast risk, liquidity risk, credit risk, collateral risk, and operational mismatch risk to ratepayers. If utilities want to begin hedging three to five years in advance, they should be required to show that the added stability is worth those added risks.