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.
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 the net present value of this revenue loss, and the combined federal-state income tax rate.
We compared the two sets of market electricity prices for each of the nine NERC regions with the values of industrial electricity price for each of the 160 major IOUs in our database. If the utility's price exceeded the market price, we computed the annual revenue loss and assumed that the loss (in real dollars) would persist for 10 years. We computed the net present value of this annual loss over the 10-year period using a real discount rate of 8 percent. This discount rate is equivalent to a return on equity of 11 to 12 percent and an annual inflation rate of 3 to 4 percent. Finally, we reduced the total loss by 35 percent to account for the amount that taxpayers would contribute through federal and state income taxes.
Who Stands to Lose?
Among individual utilities, industrial prices in 1993 ranged from less than 2 cents per kilowatt-hour (›/Kwh) to over 10›/Kwh. Across the nine NERC regions, CCCT prices ranged from 3.6›/Kwh in ECAR to 4.6›/Kwh in MAAC. And the capacity-adjusted price ranged from 2.4›/Kwh in ERCOT, MAAC, NPCC, and WSCC (where capacity margins are all above 20 percent) to
3.6›/Kwh in MAIN and SERC (where capacity margins are only about 16 percent). Because of these large price differences, both across individual utilities and across regions, a substantial amount of revenue could be "lost" for utilities that charge prices above the regional market price.
Consider, first, the industrial sector alone. As the assumed market price of power declines from the CCCT price to the capacity-adjusted price, the amount of SC increases (see Table 1), ranging from 19 to 38 percent of the equity held by all the major U.S. IOUs. To use what we consider a reasonable example, imagine that industrial customers can obtain electricity at the capacity-adjusted price. Overall, 77 percent of IOU industrial sales would be affected, leading to an annual revenue loss of $15.8 billion. The net present value of the associated after-tax earnings loss is $68.8 billion, which represents 38 percent of IOU equity.
If all retail customers (residential, commercial, and industrial) are able to obtain electricity at market prices, the amounts of SC are even larger, ranging from 54 to 115 percent of utility equity (see Table 1). However, it is unrealistic to match a large demand with a very low price (or vice versa). Thus, competition that allows only the industrial class to access competitive generation markets will yield low market prices, but if industry restructuring allows all retail customers to obtain market-priced power, that price will be higher.
For the industrial-only/capacity-adjusted price case (colored bars in Figure 2), losses are highest in MAAC (54 percent of IOU equity would be stranded with these assumptions) and lowest in SERC (16 percent). Altogether, 153 of the 160 IOUs examined face some SC in this case. Of these, 17 have SC that exceed 100 percent of their equity; another 120 have SC between 10 and 100 percent of equity. Twenty utilities have potential losses of $1 billion or more. These utilities are concentrated in a few states (em including California, Pennsylvania, Texas, New York, and Ohio, in declining order of importance. Lost revenues exceed 50 percent of utility equity in 13 states.
For the all-retail/combined-cycle price case (black bars in Figure 2), the total amount of SC is larger than for the industrial-only/ capacity-adjusted price case considered above (54 vs. 38 percent of equity). By far, the largest losses occur in NPCC (149 percent of equity). Losses are less than 10 percent in ERCOT and MAPP. Altogether, 100 utilities face some SC in this case. Of these, 36 have SC that exceed 100 percent of their equity; another 53 have SC between 10 and 100 percent of equity. Twenty-five utilities have potential losses of $1 billion or more. These utilities are concentrated in a few states (em including New York, California, New Jersey, Massachusetts, Ohio, and Pennsylvania, in declining order of importance. Lost revenues exceed 50 percent of utility equity in 16 states.
In both cases, the potential SC losses are especially severe in California, New York, Ohio, and Pennsylvania. Relative to the amount of utility equity, losses could be largest in several New England states (Maine, Massachusetts, New Hampshire, and Rhode Island).
As noted earlier, the amount of SC depends strongly on the assumptions made. The key assumptions are the market price of electricity and the fraction of retail load lost. Figure 3 shows the importance of these factors. At any market price, the loss to utility shareholders is 2.5 to 3 times as great when all retail loads are at risk than when only industrial loads are at risk. Raising the assumed market price of electricity by 1›/Kwh decreases the equity loss by 25 percentage points for all retail customers, and by 10 percentage points for the industrial class only. Lowering the market price by 1›/Kwh increases the equity loss by 33 and 14 percentage points, respectively. For the all-retail case, the change in SC is about $60 billion for every 1›/Kwh change in the market price of electricity.
Another key assumption that affects results is the number of years over which the utility loses this revenue. If the revenue loss would occur for only five years (rather than the 10 years assumed in Figure 3), equity loss would be cut by 40 percent. On the other hand, if the revenue loss were to occur for 15 years, then equity
loss would increase by almost
Finally, we varied the discount rate. Decreasing the real discount rate from 8 to 5 percent increases the amount of SC by 15 percent; increasing the discount rate to 11 percent cuts the amount of SC by 12 percent. These results show that the discount rate has less effect on results than does the number of years that lost revenues occur. Both factors are less important than the market price and the fraction of retail load able to obtain market-priced electricity.
What's Your Risk?
We developed a rudimentary method to estimate the amount of SC that each large IOU might face. Our best estimates of potential SC range from 38 to 54 percent of equity. Roughly speaking, every 1›/Kwh change in the market price of electricity causes up to a $60-billion change in the amount of SC nationwide. The states with the biggest potential dollar loss include California, New York, Ohio, and Pennsylvania. The states with the biggest potential percentage loss include Maine, Massachusetts, New Hampshire, and Rhode Island.
Our analyses point to four major conclusions:
s Reported estimates of SC depend strongly on the assumptions made in deriving those numbers. Treat skeptically estimates that are not well documented.
s The most important assumptions are the fraction of a utility's retail load that can obtain electricity supplies in a competitive market and the price of electricity in that competitive market. In addition, the number of years during which the utility suffers this revenue loss is important in determining results. Of course, these three sets of assumptions are related to each other.
s The appropriate measure of SC is the net, not the gross, estimate. The net estimate adjusts for utility assets that have a market value above book value.
s SC estimates should reflect the effects of federal and state income taxes, which will reduce the amounts that utility shareholders and customers will ultimately have to absorb.
The amounts of SC computed here are large both in absolute terms and relative to utility shareholder equity. Developing reasonable and equitable ways to quantify, mitigate, and allocate these costs will likely be a critical precondition to restructuring the U.S. electricity industry. t
Eric Hirst and Lester Baxter are researchers at Oak Ridge National Laboratory. They specialize in electric-utility policy issues, including resource planning, demand-side management programs, and industry restructuring. Hirst holds a PhD in mechanical engineering from Stanford University, and Baxter holds a PhD in Public and Urban Policy from the University of Pennsylvania.
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