a regulatory compact for a new era

Michael McGrath, Edison Electric Institute

Rate cases are back. By one estimate, state commissions will hear more than two dozen cases by year’s end. Many states will be revisiting rates that have been frozen for the past six to eight years as part of their transition to competitive retail markets.

As states and electric utilities re–enter the cost–of–service arena, they will need to update rate designs to address the new issues created by the industry’s unbundling and the advent of customer choice. Of particular importance to utilities will be addressing the new challenges involved in procuring energy and serving a customer base in flux. Innovative regulatory policies will be needed to continue to meet the customer’s historic demand for stable prices and reliable service.

The new risks imposed in procuring energy affect all utilities to varying degrees, but particularly those utilities that have sold their generating assets. The distribution–only companies, being dependent on power purchased in the wholesale market, have to decide what to buy, when to buy it and whether to hedge in some way the wholesale prices they are paying.

The risk is that—given the uncertainties in both the electric and gas wholesale markets—the price a utility pays for power today could end up being higher, even much higher, than what that power sells for at any given time in the future. Consequently, it will always be possible–after–the–fact–to second–guess a utility’s energy procurement strategy.

The traditional, vertically–integrated utilities also run risks with procuring energy resources. For them, the growth of wholesale markets has meant that they can buy the power they need rather than generating it themselves or building a plant. And, many have done so, which has opened them up to the same after–the–fact scrutiny that distribution–only companies now face.

Those integrated utilities that built plants tended to build natural gas plants due to the relative economics. But, those economics have changed today. Coal plants are now more competitive, but, because they are more capital intensive and therefore financially riskier to build, there needs to be more regulatory certainty before electric utilities build (or before the investment community will finance).

Several states and utilities have adopted new planning and approval processes to manage utility risk. Many are also considering or are in the process of adopting competitive procurement practices. The Federal Energy Regulatory Commission (FERC) has also called for states to use competitive procurement and is providing guidelines as an antidote to market power concerns.

To address these new challenges in energy procurement, both restructured and traditional electric utilities will be encouraging state regulators to adopt or consider:

“- planning processes that develop a shared understanding (among regulators, customers and others) about the new uncertainties involved in meeting the resource needs of customers—and about reasonable strategies for dealing with such uncertainties.

“- policies that preserve the distinction between risk management and cost minimization. Risk management cannot minimize cost. Risk management, like fire insurance, typically adds cost but can avoid a potential financial crisis.

“- measures that provide assurance that an approved resource strategy will not be subject to a “perfect hindsight” prudence review as to its relative success. Access to the reasonably priced capital required to serve future customer needs is at stake.

“- (to the extent competitive procurement practices are employed to secure supply) non–price factors should be considered with the product requirements or selection process. Such factors may include fuel diversity, supplier diversity, reliability, creditworthiness of the supplier and impacts on utility creditworthiness, contract length, cost and certainty of delivery, economic development, or other factors established by the state. Establishing competitive procurement processes should not limit the flexibility of a state or its utilities to meet customer requirements by all means possible, including building or acquiring generation, transmission, demand response and efficiency.

“- procedures that institutionalize frequent communications between the utility and regulators. Markets are dynamic; things change. It should be expected that adjustments would be needed. Regular communication, through scheduled progress reports for example, can help keep regulators apprised of market trends, and,

“- incentives to give them a stake in superior planning and procurement performance. This benefits consumers and investors as well.

Another risk created by industry restructuring is the obligation for those utilities in competitive retail markets to continue to supply power to any customer who requests it at rates that no longer reflect today’s increasing costs. Although it is called different things in different states—default service, standard offer service, basic generation service, price to beat, provider of last resort—utilities who have this obligation to serve run the risk of buying too much (or too little) energy supply to meet demands of customers who can come and go at will. They can also end up paying more in wholesale markets than they are allowed to recover in retail rates.

The obligation to serve was originally intended to be purely a transitional service—protecting customers while competitive markets were being established—and hence was launched with an expiration date. Since the retail markets generally are not serving small customers, it is very likely this obligation to serve will be extended. Some states already have done so. When it is, utilities will be proposing reforms that look at:

“- customer differentiation. Policies covering service for large customers should be different from policies covering service for small customers. Because market–based suppliers generally are available to serve large customers, it is reasonable to think about removing the regulatory obligation for utilities to serve large commercial and industrial customers entirely.

“- protections for low–income customers. Low–income customers, which tend to be least–served by the market, need the most protection—and policies that promote stable rates. In particular, they need termination policies to remain in force that limit when and how a customer can be shut off.

“- new rate designs. Because rates were designed for fully–regulated markets, they may no longer provide appropriate price signals for consumers. New rate designs must be implemented that reflect both the new market structures, costs and risks.

These new regulatory policies will also help to restore investor confidence in the industry by providing the industry and the investment community with a renewed sense of certainty. The investment community is looking at the philosophies that generally drive the regulatory policies to determine whether or not a company remains a worthwhile investment.

McGrath is executive director of retail energy services with Edison Electric Institute. More information on EEI can be found at www.eei.org.

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