Open-access tariffs hold the key to capturing the gains promised by electric restructuring.
In a restructured electric industry, unbundling the cost of the wires from power generation may well prove more important than dealing with stranded costs. In fact, stranded costs eventually will take care of themselves, whether by direct recovery, indirect recovery or no recovery. Without proper unbundling, however, a restructured industry could force competitors to pay inflated access fees to the distribution utility.
The matter has drawn a lot of attention. For example, the National Association of Regulatory Utility Commissioners has commissioned a study of using performance-based ratemaking for the functionally separated activities of transmission and distribution. Indeed, most restructuring legislation pays at least lip service to PBR. Nevertheless, more traditional regulation (based on a rate of return) generally provides the benchmark from which other, more progressive methods are developed. Thus, public utility commissions will likely face two key tasks in setting open-access fees: 1) identifying and separating the costs of the wires from generation; and 2) allocating the wires costs among distribution customers.
Separating wires and generation costs implies another key step: unbundling the return and capital structure assigned to wires. What was formerly an implicit return assigned to the wires business must now become part of the formula for determining the open-access fee. Here, the wires business should carry a much lower risk than generation, both today and in the future. Thus, the rate of return required for capital invested in wires should be much lower than it has been overall for the traditional, vertically integrated, investor-owned utility.
The impact of this change is substantial. We estimate that the correct return on equity for the wires-only part of electricity supply runs some 2 percentage points less than the old, traditional equity return rate for the integrated enterprise. Given an average equity return of 12 percent, this difference means that the return portion of an open-access fee based on cost of service is nearly 20 percent lower than the old, allowed rate of return. And then there is the question of capital structure - the proper allocation of debt leverage and income tax deductions to the wires portion of the business. Certainly, most observers see the wires utility evolving as more highly leveraged than the competitive generation business.
All told, we have found that the method of allocating risk, capital structure and returns among electric sectors could produce a $3 swing (10-15 percent) in a typical monthly residential wires charge. This swing could eat up more than 10 percent of the projected competitive savings for residential customers served by an average electric utility.
Nevertheless, regulators must tread carefully. Set access fees too high, and potential gains from restructuring may be forfeited. But with rates set too low, be prepared to sacrifice service quality and reliability. Resolving the proper rate of return and capital structure in deregulation could preserve a large share of the competitive savings for residential customers.
Playing the Cost Game
Electric utilities no doubt recognize that their financial interest lies in shifting as many rate-base items as possible to the wires side, away from generation. Competition will impose its own set of prices for electric generation. Only the wires charge will remain rate regulated, with its own rate base determined by accounting allocations, inviting debate among utilities, regulators and others.
Indeed, it is left to the PUCs and perhaps the antitrust authorities to play the role of Solomon. We estimate, for example, that possibly as much as 70 percent of the costs labeled customer accounts expenses are charges that should not be included in the open-access fee, such as uncollectible accounts. Similarly, some customer service expenses fund activities associated with selling electricity, not operating the wires.
Moreover, if utilities should succeed in hiding generation assets within the wires rate base, regulators will end up setting rates that grant a double recovery of the generation investment.%n1%n
In 1995, for example, South Carolina Electric & Gas convinced the South Carolina Public Service Commission to allow it to move $257 million in accumulated depreciation out of transmission and distribution and into generation. That shift would have caused the rate base in generation to go down and the rate base in wires to go up above its true economic cost, because a greater portion of the return is attributable to the wires.
The company openly admitted that this move was a good way to get ready for competition, and the state commission concurred.%n2%n A South Carolina district court also agreed: "The Commission finds ... that the reserve shift is a prudent means to prepare for uncertainties about future competition in the electric industry."
However, the Federal Energy Regulatory Commission was not so inclined. It is not likely that antitrust authorities will support such a move either. In a competitive generation marketplace, open-access fees charged by a fully integrated utility can be attacked as an illegal tie on antitrust grounds, as the court held in the 1994 Cajun Electric case.%n3%n
Unbundling the Rate of Return
In the past, regulators allowed a combined rate of return on more-risky generation and less-risky wires. They should now divide this combined rate of return into separate generation and wires components, reflecting the relative risk of each enterprise. With accurate rate bases for each, an appropriate rate of return can be applied to wires to determine the revenues required to support that part of electricity service. An important principle emerges at this stage:
The appropriate rate of return for the wires part of the business should be much lower than the overall return that has been appropriate in the past.
Why this conclusion? The generation portion of the electricity industry has traditionally proved more volatile than the distribution side. The true cost of capital, therefore, is lower for wires when it is functionally separated from generation activities by the host utility.
Also, the cost of capital for wires should be lower because, for example, less volatility in wires revenues and expenses lessens the chances of bankruptcy. The fixed nature of wires lowers the potential for improper management. This reduced risk makes debt finance more appropriate since less monitoring of management activities is needed.%n4%n Also, regulators must recognize the tax advantages of debt over equity when calculating the income tax liabilities associated with the wires business.
Of the five bankruptcies that have occurred in the electric utility industry since the Great Depression, only one was not directly related to investments in generation assets. The singular exception was Tucson Electric, and even there, generation assets created the biggest problem of all electricity assets in resolving the financial distress. Never has transmission or distribution added to a utility's financial difficulties.
Moreover, the overwhelming majority of price disparities in the U.S. appear attributable to differences in the embedded cost of generation. Generation capital has historically come in much larger lumps than wires, making unexpected changes in demand more problematic and vicious.
Debt, Equity and Beta
To assess the proper rate of return for unbundled wires services, we start from the possibly heroic assumption that the return and capital structure allowed in the past was fair and equitable. The allowed return is termed the weighted average cost of capital.
In basic financial economics, the weighted average cost of capital is the return to each component of the capital structure (debt, preferred stock, common stock) multiplied by its share in the capital structure.%n5%n The WACC is composed of three factors: the debt-equity ratio, the equity beta and the debt rate.%n6%n By evaluating these three factors separately for generation and for wires, the right rate of return for the unbundled wires assets will emerge. The first step is to forecast the equity component.
The equity return to a common stock is based on the way the price fluctuates compared with other stocks in the market. A simple way to do this is to use the capital asset pricing model. CAPM says that equity return depends on beta. Beta is a measure of the statistical relation between the stock price movements of one firm and the movement in the overall market; it is a financial statistic reported by financial services such as the Value Line Investment Survey. The CAPM equation says that equity return is equal to the risk-free rate of return plus beta times the overall risk premium to equity assets.
In mid-summer, the risk-free rate was 6.6 percent.%n7%n The risk premium on common equities historically has been 7 percent. So, the expected return to the market portfolio of common stocks is 13.6 percent. Using CAPM, a firm with a beta of 1 is predicted to make an equity return of 13.6 percent for the coming year. A firm with a beta of 2 is expected to make 20.6 percent.
The historical equity beta for utilities has been around 0.7. This beta gives an expected equity return to electricity stocks of 11.5 percent.%n8%n In other words, the financial market has acted over the long term as if it expected public utility commissions to allow an equity return of 11.5 percent in bundled, rate-regulated electric utilities. Indeed, this expectation is approximately correct based on the equity returns allowed by various commissions as reported in the FERC Form 1 filings of electric utilities nationwide.
The next problem is to unbundle the equity rate of return allowed in the past into its generation versus wires components. We can unbundle the equity rate of return by assigning different betas to generation and to wires to mimic the financial market. For instance, since wires are much less risky than generation, we assume a beta in wires of 0.4, and a beta in generation of 0.9, which is still less than the overall market. This split unbundles the risk of generation and wires.%n9%n
The capital base of a fully integrated electric utility (the rate base in the regulated enterprise) is split between generation and wires approximately 60-40. Thus, a generation beta of 0.9 and wires beta of 0.4 gives the historical average beta for the integrated enterprise of 0.7. Assuming a generation beta of 0.9 and a wires beta of 0.4, the proper equity return to generation is 12.9 percent and 9.4 percent for wires. That is, we expect that the equity return to generation assets will be approximately 12.9 percent in the financial market and that regulatory commissions should set the allowed rate of return to wires at approximately 9.4 percent. Note, however, that most of these numbers must be confirmed through additional research.
Optimizing the Capital Structure
The determination of the utility's capital structure and the assignment of an approved debt-equity ratio will play a significant role in unbundling the cost of capital and allocating a true cost of service to the wires business. About half the value of electric utilities is debt.%n10%n How much of this debt should be implicitly assigned to generation and how much to wires?
Since generation is the riskier enterprise, it will have a lower implied debt-equity ratio, and of the overall average debt-equity ratio of approximately 1, the implied ratio for wires is greater than 1. A split of the historical average that imputes a debt-equity ratio of 1.6 to wires and 0.6 to generation maintains the assumption that commissions have imposed the correct ratio for the unbundled company in the past. The debt- equity value of 1.6 for wires comes from the debt-equity ratio of certificated air transport that we found in prior research.%n11%n
Average long-term debt rates for public utilities are about 1 point higher than the long-term, risk-free rate. The average interest rate on long-term debt for bundled utilities is around 8 percent. However, for the unbundled generation and wires functions, the appropriate implied rates will diverge. The rate on generation assets will rise, and the rate on the wires will fall due to relative risk levels. Assume the interest rates on debt in the two business segments are 8.5 percent for generation and 7 percent for wires.
When this is put together, we get an implicit weighted average cost of capital of 11.3 percent for generation and 7.9 percent for wires (see Table 1).
Notably, both the allowed equity return and the WACC for wires are considerably lower than they were in the bundled past. Of course, the returns to generation are commensurately higher. It is important to note that for the investor holding a portfolio of the two in the same levels as before (60 percent generation and 40 percent wires), there is no net effect. The average return to their bundled equity holdings will remain at about 11.5 percent.
In the past, where generation was combined with transmission and distribution, the higher overall return was justified because of the relative riskiness of generation. In the open-access regime, generation will be separate from transmission and distribution and its riskiness should also stand separated in the open-access ratemaking process. The effect is substantial. The return on an investment portion of the open-access wires tariff can be overstated by 20 percent or more by incorrectly assessing the appropriate rate of return and assigning the old allowed rate of return.
Income Tax Allocations
The allocation of income tax expenses between the wires and generation business also will play a key role in unbundling the cost of capital. And here, risk and capital structure are again important. Interest on long-term debt is an expense item; dividends paid to equity owners are not. The more leveraged the firm is (value constant), the lower its income taxes. Leverage reduces tax liabilities.
The amount of income tax expense that a utility should properly include in its open-access fees depends on the correct assignment of equity return and leverage to the wires part of the business. Public utility regulators generally cannot force utilities to adopt specific capital structures. They also cannot force firms to minimize that cost of capital by increasing how much debt financing that they employ. However, regulators can set open-access tariffs at a level that reflects the true cost of supplying the wires service. This tariff can be calculated using the appropriate and optimal capital structure and rate of return.
Using the previously determined debt-equity ratio of around 1.6 and a required equity return of around 9.4 percent, income taxes for the wires business can be calculated directly. The important point is that the true, implied income tax liability of the wires business is much smaller than the implied income tax liability on generation. (See Table 1 for the parameters used to calculate the proper taxes on the wires business based on total income taxes paid in the past.)
With the proper capital structure in place, the correct taxes on the wires portion of income is about 23 percent of the historical total. In other words, a utility paying $500 million in income taxes in 1997 as a fully integrated, regulated electricity supplier, would pay less than $115 million for the wires portion of its business as an unbundled supplier of generation and wires services in 1998. The details of this calculation are available from the authors.
Rate Design: Allocating Fees by Customer Class
Once the state commission has determined the revenues required to recover the cost of wires service, the next issue is to allocate these fees across customer classes. Open-access fees should be levied on a per-customer basis rather than on a kilowatt-hour basis. The reason for this is simple: The wires part of the electricity industry is based on capacity and not usage. There is a significant economic loss to electricity consumers if wires charges are levied on a per-kilowatt-hour basis.
Moreover, charging for wires on kilowatt-hour usage is discriminatory. Customers who buy from low-priced providers and use more electric energy will be forced to pay an unfairly larger portion of the transmission and distribution costs.
Open-access fees should be assessed on a per-customer basis within classes of customers and allocated across customer classes based on the true cost of serving each customer class. Generally, costs vary between customer classes based on the voltage at which they take power off the system. The higher the voltage, the lower the wires cost of serving the customer. Line loss factors must also be determined for each customer class, and these also vary based on voltage. Hence, commissions can define customer classes by voltage and assign an allocation factor for wires that fairly spreads the cost across.
An Example: A Residential Access Charge
We have calculated sample open-access tariffs for South Carolina Electric & Gas using their own 1995 rate filing data. We use SCE&G because it is in our home state, and we recently filed a restructuring proposal with the state PSC that analyzes open-access tariffs in South Carolina.
By our estimates, the wires charge paid to SCE&G by an open-access provider should be around $21.42 per month per residential customer if the right rate of return and implied capital structure are used. If, however, the South Carolina commission uses the wrong factors and the historical average rate of return and capital structure are used, then the open-access fee would increase $2.83 per month per residential customer. SCE&G has more than 400,000 residential customers. The size of this potential mistake is around $14 million annually. Nationwide, a $2.83 mistake per residential customer per month is $3.5 billion annually.
Besides the $21.42 wires fee paid by a competitive open-access electricity provider to SCE&G, customer costs run $3.36 per month per residential customer. SCE&G and the open-access provider will share these costs, but they will continue to show up on the customer's bill. Finally, given a forecast cost of electric energy of 3¢/kWh and average usage of 1,062 kWh per month, competitive energy costs will be $31.86 per month. So, adding the energy charge to the access fee yields the expected competitive cost of electricity for residential customers in the SCE&G territory at $56.64 per month. This compares with $79.33, the amount that SCE&G requested in its recent rate filing (see Figure 1).
If the South Carolina commission does it right, residential consumers stand to gain $22.69 per month from competition, or $272 per year, based on 1995 consumption.%n12%n If the commission errs in unbundling the rate of return, consumer savings will only be $19.86 per month or $238 per year. A mistake by the commission reduces the potential savings from competition by 12 percent.
Of course, open-access fees will not apply directly to all residential customers. Many customers will choose to remain with the incumbent host utility. Nonetheless, the competitive price will be set at the margin by open-access providers. The fees they are forced to pay the host utility for the wires service will be the baseline from which the competitive price of electricity service is built.
The appropriate capital structure and rate of return questions have implications beyond access fees. If regulators ignore these arguments and allow the historical WACC for the unbundled distribution company, we will see an increase in the stock prices of distribution companies. Stock owners are now gaining the same historical rate of return for a less risky asset. Stock prices of distribution companies will rise if the wrong rate of return is allowed.
The essential debate in electric restructuring will not likely revolve around the stranded costs of generation assets. Instead, the question looming before commissions around the country will be finding the true costs of distribution and transmission activities. Answering this question is independent of the valuation of generation assets, especially if fees are assessed on a per-customer basis.
Michael T. Maloney and Robert E. McCormick are professors of economics at Clemson University, Clemson S.C. Last year they collaborated on an extensive study on electric utility deregulation, prepared for the Citizens for a Sound Economy Foundation: Customer Choice, Consumer Value: Analysis of Retail Competition in America's Electric Industry. Cleve B. Tyler is an economics graduate student at Clemson.
Risk-free rate: 6.6% Risk premium: 7.0%
Debt Equity Interest Rate Beta Return to WACC
Ratio on Debt Equity
Generation 0.6 8.0% 0.9 12.9% 11.1%
Wires 1.6 6.6% 0.4 9.4% 7.7%
1If a certain cost truly is a cost of generation, then in a competitive market for generation the price will allow for its full recovery. Competition ensures that all costs get paid on average and at the margin in the long run. If that cost is allowed to appear on the accounting books as though it were a wires costs, then the integrated utility will effectively recover that cost twice. Such a result is economically inefficient.
2Re South Carolina Elec. & Gas Co., Docket No. 95-100, Order No. 96-15, Jan. 9, 1996, 167 PUR4th 154 (S.C.P.S.C.). See also, "Depreciation Reserve Soaks Up Stranded Investment," PUBLIC UTILITIES FORTNIGHTLY, Feb. 15, 1996, p. 45.
3Cajun Elec. Power Co-op. v. FERC, 28 F.3d 173 (D.C.Cir.1994).
4See Maloney, McCormick, and Mitchell, "Managerial Decision Making and Capital Structure," Journal of Business, 66(2) (April 1993):189-217.
5In a simple problem where there is only debt and equity, the WACC is the long-term debt rate paid by the company times the proportion of long-term debt to total capital in the firm plus equity return times the proportion of equity to the value of the firm.
6The equity beta is a financial economics expression for the coefficient of the relation between the return to a firm and the return to the overall market.
7Based on the 30-year Treasury bond rate as of July 8, 1997.
8That is, beta times the risk premium plus the risk-free rate, or 0.7 times 7 percent plus 6.6 percent equals 11.5 percent. By late July, however, the rate had fallen to about 6.4 percent. For the sake of simplicity, calculations here will assume a rate of 6.6 percent.
9This division, in particular, will be subject to intense scrutiny and debate. The particular numbers do not change our basic argument, but do highlight the need for additional research into this matter.
10According to 1995 FERC Form 1 data, major investor-owned utilities had a capital structure of 47 percent debt, or a D/E ratio of 0.9.
11See Maloney, McCormick, and Mitchell, op. cit., note 4.
12Based on 1995 consumption.
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