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Stranded commitments (SC), because they are potentially huge, may be a show stopper for increased competition in the U.S. electricity industry. Utility shareholders, industrial customers, and small commercial and residential customers are likely to wage tough battles before state and federal regulatory commissions as they seek to reduce their exposure to these costs. Widely varying estimates of the amounts of SC may be a key element in these battles.

We define SC more broadly than others define stranded costs or investments. Our definition can include four classes of costs:

s Stranded assets, primarily in expensive power plants and excess capacity

s Stranded liabilities, primarily in power-purchase contracts (including those with qualifying facilities) and deferred income taxes

s Regulatory assets (whose value is based on regulatory decisions rather than on market forces), including deferred expenses and DSM-program costs that regulators allow utilities to place on their balance sheets

s Stranded public-policy programs, including tax collection, DSM programs paid for by all customers, and support for energy research and development.

Estimates of SC vary widely. Niagara Mohawk Power Corp. estimates that stranded costs could run as high as $200 billion. At the other end of the spectrum, the American Public Power Association estimates potential losses at $10 to $20 billion. These and other estimates differ because of the assumptions used to calculate SC, differences between gross and net estimates, and the effects of federal and state income taxes.

Testing Assumptions

To explore the effects of different assumptions, we developed a simple method to estimate the amounts of potential SC faced by individual investor-owned utilities (IOUs). The method, described in our report, Estimating Potential Stranded Commitments for U.S. Investor-Owned Electric Utilities, is based on the difference between the industrial electricity price for the utility in question and an estimated market price for the region as a whole. We used the industrial price (rather than the utility's overall retail price) because it closely represents the utility's generation and transmission costs (and excludes most of its distribution and customer-service costs). We tested two proxies for market price: 1) the capital and operating cost of a combined-cycle combustion turbine (CCCT), and 2) a "capacity-adjusted" price that lies between the region's short-term operating cost for existing plants and the cost of a CCCT based on the capacity margin in the region. The market price declines, and the estimates of SC increase, as one goes from the first to the second price.

We used the nine North American Electric Reliability Council (NERC) regions to define the boundaries of competitive electricity markets (see Figure 1). Although electricity flows across these boundaries, they seem like reasonable limits given the coordination and planning that occur within each region.

We assumed that two portions of a utility's retail load would be at risk (em that is, able to obtain electricity supplies from a competitive regional market: 1) industrial customers only, or 2) all retail customers.

Our method also required us to make assumptions as to the number of years during which the price difference will persist, the appropriate discount rate to use in calculating