- Email: [email protected]
Summary of findings on electric power financing and cost recovery
Resources
and Energy
SUMMARY
7 (1985)
153-160.
North-Holland
OF FINDINGS ON ELECTRIC POWER AND COST RECOVERY
FINANCING
Richard E. SCHULER Cornell
University,
Ithaca,
NY
14853,
George A. HAZELRIGG, National
Science
Foundation,
Washington,
USA
Jr. DC 20550,
USA
Although the intention of the articles in this issue was to emphasize the long-run generic implications of alternative cash-flow recovery schemes, it is interesting how frequently the perceived inequities of recent regulatory experience regarding ad hoc, pragmatic rate base adjustments intruded into the discussion. Thus, while the papers and their commentaries were intended to be forward-ranging and theoretical, and to abstract from the immediate phase-in problems, this summary reverses that ordering and begins by examining constraints to alternative cash-flow recovery schemes, both when implemented to phase-in capacity of unanticipated large expense and as a generic matter. Next, the question of what risk premium, if any, would be imposed by financial markets if the intertemporal cash-flow pattern were to be altered is addressed together with the potential behavioral consequences for electric utilities. These two issues must be discussed together if social pluses and minuses are to be assessed. Finally, the various perceptions of incentive, institutional, and technological consequences of these changes are drawn together and examined once again in light of the overall objective of regulating a natural monopoly, if indeed the generation of electricity is one, to mirror a competitive market. Much of the legal discussion in the papers has focused on the ex-post equities of altering cash-flow recovery patterns after the completion of plants the construction of which was begun under a different set of guidelines. It was generally felt that, without some finding of imprudence, phase-in procedures would be accepted, without some constitutional test, only if the ultimate recovery of cost was deemed to be reasonably certain. In contrast, there seem to be few legal constraints to implementing alternative cash-flow recovery schemes on a prospective, generic basis, if predicated on an adequate record. So,‘the chief legal constraints pertain to the ad hoc phaseins of past mistakes; much flexibility is possible in altering future long-term rate-setting procedures. 0165-0572/85/$3.30
0
1985, Elsevier
Science
Publishers
B.V. (North-Holland)
154
R.E. Schuler
and G.A. Hazelrigg,
Jr., Summary
By comparison, the operation of financial constraints appears to be just the reverse. Although the market behaves with the memory of an elephant with respect to bad news, it is quite likely to accept ad hoc regulatory solutions that modify the rate effects of generation plants with large cost overruns as a clearly preferable alternative to a rate-payer revolution However, on a generic basis, Hyman’s spot-check of several investor groups elicited a uniformly pessimistic response: prospective financing would be difficult and the cost of capital might rise greatly. Such a response seems to suggest a large risk premium associated with future-weighted cash flow patterns. And while, as Myers correctly emphasizes, the only source of a risk premium is the greater exposure to after-the-fact changes in regulatory procedure, not the delayed cash recovery time pattern itself, there still exists what economists call the partial- versus general-equilibrium question. Certainly, if one utility or state were to implement tail-end-weighted cash recovery schemes, investors might flock to those jurisdictions that retained conventional procedures. But suppose all jurisdictions converted at once? While some investors might move to municipal or unregulated corporate securities, Gravelle’s ten percent of total investment in the United States is a lot of investment flow to rearrange at once, particularly if many of the alternatives are equally speculative. Nevertheless, if a risk premium were to arise, Gravelle illustrates how investment in the industry might be altered over time. Of course several of the authors, and in particular Myers, argue forcefully that there may be no risk premium associated with the implementation of an economic depreciation scheme, if the alternative is a ‘thirty percent rate shock. Under which circumstance is the uncertainty regarding the behavior of regulators and politicians greater? Several authors do suggest that the fear of a moral hazard associated with deferred cash flow recovery schemes should be much smaller if it is instituted under a well-prescribed formula, like economic depreciation, as compared to ad-hoc phase-ins. Here the table seems to tilt back again toward a preference for prospective, generic implementation. What the papers seem to reduce to then is the question of estimating the magnitude of the risk premium. The flip-side of this question is: what is the implicit subsidy that regulators are perceived to be providing to current utility investors through front-end-loaded cash recovery techniques? Clearly, few non-regulated industries guarantee that type of recovery pattern, and, in terms of objective measures of business risk, like capital intensity or variability in detrended sales, utilities currently have higher levels of risk than many unregulated businesses. So, shouldn’t utilities have higher costs of capital than unregulated industries, were it not for some implicit guarantee inherent in traditional rate-making procedures? This raises the further question of whether or not the inherent risks of
R.E. Schuler
and G.A. Hazelrigg,
Jr., Summary
155
electric utility operations are more easily diversified at less cost by spreading them in part across all customers, as appears to happen under current regulation where the customer implicitly bears some of the risk premium, or whether that risk should be borne by investors, in which case customers will bear the risk premium explicitly through higher rates of return, if in fact that risk premium exists.’ This theoretical argument about minimizing the cost of risk-spreading could be carried one level higher by proposing widespread regional consortia of utilities arranging for the construction of each and every plant. But Berlin’s description of the litigious consequences of divided responsibility and the double-edged assignment of blame in a recent case regarding the cancelled Pilgrim Plant in New England should be sufficient to diminish the ardor for this type of agglomeration in the near term. The important question, then, that seems to arise from this discussion of assignment of risk is not which allocation leads to the lowest short-run financial costs, but rather which provides the proper planning incentives and therefore the lowest long-run cost of utility service. In fact, any regulation or change in regulatory method will alter to some extent the incentives and motivation of those who are regulated. This was emphasized in Czamanski et al. (1981). Thus, the overriding benefits and costs of reversing traditional intertemporal cash recovery patterns may flow, not just from a change in perceived financial risk and cost, but from the impact those regulatory changes may have in turn on the utilities’ construction plans for the future. As an example, will economic depreciation mean larger or smaller plants? While some variant of economic depreciation, used as a phase-in mechanism, may provide a politically feasible way of completing large nuclear facilities already under construction, most of the authors like Per1 and Peck agree that future facilities are likely to be smaller anyway. Would they be even smaller under a regime of future-weighted cash flows as compared to the existing patterns? A positive answer seems to rest on two hypotheses. First, the propensity of regulators to change a rule increases directly with the elapsed time since its adoption (the dim memory hypothesis) and with surprises. Second, smaller plants can be built more rapidly at costs closer to those originally projected than can large units. If true, the first hypothesis exposes facilities with future-weighted recovery schemes to a greater average likelihood of diminished total cash flow than do front-end-loaded schemes, but this effect can be mitigated in part by building smaller plants, so the chance of triggering the regulator’s attention through cost overruns (second hypothesis) is reduced. ‘In a recent paper, Leonard and Zeckhauser (1983) argue that most competitive markets are large enough to diversify all foreseeable risks except large-scale war, so scale economies in spreading risk are not acceptable arguments for government provision of insurance. A similar argument can be made against regulatory spreading of business risk across utility customers.
156
R.E. Schuler
and G.A. Hazelrigg,
Jr., Summary
Thus, a movement toward delayed cash-flow recovery patterns does seem to re-assign a larger portion of planning and construction risk directly onto the party performing those functions - the utility - which strikes us as a sensible outcome. If that coincidence in turn results in smaller plants, then that too may be sensible. So, under such a revised regulatory framework, any future government initiative to deploy new large-scale electricity supply technologies may require an accompanying explicit government subsidy. Osborne observes that few, if any, utilities are likely to undertake the construction of large nuclear plants in the future without some assurance of CWIP in rate base. In fact, the generic implementation of a system of economic depreciation or trended rate base should result in rapidly increasing cash flows, attributed to the previous plant, just as construction gets heavily underway on the new one; the only problem that may arise is in financing the very first plant to be built after a system of reversed cash-flow patterns is implemented. So, if in the long run, economic depreciation leads to intertemporal cash-flow patterns not unlike those arising from CWIP, why not advocate the less drastic regulatory change of the universal inclusion of CWIP in rate base? The difference, as pointed out by Perl, is the causal link between cost incursion and rate relief. Under traditional rate-making or some form of economic depreciation, the utility’s cash inflow during the construction of a new unit is not governed by the actual costs of constructing that unit. Here a special form of regulatory lag provides an incentive to complete the plant expeditiously so that rate relief can begin. By comparison, allowing 100 percent of CWIP in rate base acts like any other automatic adjustment clause; it provides periodic cash flow for costs actually incurred, which certainly eases the utility’s financial planning problems, but also reduces or postpones the penalties for improper cost control or planning. Again, the choice of a preferred regulatory policy hinges on its incentive implications. One final, horrendous potential inefficiency that Berlin suggests will emerge under existing regulation, and that should be avoided at all costs, is that of undertaking continuous costly studies to justify continued construction of projects solely to withstand potential imprudence charges. In fact, much of the debate on altering cash-flow patterns reduces to issues of accountability and trust, both on the part of utility and of regulator. Myers emphasizes that the risk premium issue is really a problem economists define as a moral hazard. This is the risk that regulators will change the rules of the game if the outcome is not to their liking, and in particular with a futureweighted pattern of cash-flow recoveries, the regulator has a greater opportunity to second-guess the utility. So, in a way, perhaps this entire discussion should be focused on ways of insuring that regulatory bodies adhere to whatever cash-flow recovery system they promulgate. One complicating factor raised briefly by Hunt and Stevenson is that a
R.E. Schuler
and G.A. Hazelrigg,
Jr., Summary
157
large percentage of current rate-shock is attributable to required normalization of Federal Income Tax effects for rate-making purposes. The elimination of that requirement is one ready mechanism that would allow state regulators considerable discretion in determining future cash-flow recovery patterns. What was not discussed was how Congress might respond to widespread state regulatory moves toward reversed cash-flow recovery patterns by making countering changes in the tax code. Hyman’s suspicion that this topic is about a problem that is past may be well-founded with respect to large nuclear plants, but as illustrated in the introduction, many moderately-sized utilities with low rates of load growth face the prospect of substantial and frequent price oscillations in the future under conventional rate-making treatment, merely as a result of replacing existing facilities. That sort of price oscillation is not likely to engender public confidence in utilities or their regulators, and it only heightens our concern over the final issue raised by Kahn: Will the system be able to build new plants when and as they are needed? We contend that this is not a problem that will go away, even when all nuclear plants currently under construction are disposed of, or with a moderation in construction cost inflation rates. Nevertheless, if the purpose of regulation is to mirror a market, then the market does not provide investors in large scale projects with a single incontrovertible intertemporal pattern of cash-flow recovery. Many high technology or consumer, fashion-oriented investments exhibit large initial cash flows that rapidly deteriorate as other competitors enter the market. Other investors, such as real estate developers building commercial properties on speculation, expect some negative cash flow, even in the early years of operation, but they anticipate that booming demand will force prices continuously upward over time. In other capital-intensive industries, such as steel and chemicals, producers may wait until market prices are high enough to insure a reasonable return on new investments before they undertake a capacity expansion. Of course, there are two big differences between all of these businesses and an electric utility. First is the absence of an obligation to provide service. Second, competitive market forces set the price; it is not predetermined (at least in terms of computational methodology) by some regulatory body. In fact, this entire discussion is about alternative computational schemes for setting prices and the certainty with which they will be adhered to by regulators over the life of the project. The most secure method from the utility’s perspective is for the regulators to set a full schedule of future prices in concrete through an iron-clad contract before project construction begins. But this degree of certainty is not available even under current regulatory practice, since allowed rates of return can be varied, within limits, from one rate case to another. A second approach is to tie the cash-flow pattern to some external index, such as the
158
R.E. Schuler
and G.A. Hazelrigg,
Jr., Summary
GNP utility cost deflator,’ that cannot be manipulated by individual utilities or state regulatory bodies. This procedure is similar to the one available to small hydro-electric projects and cogenerators, the future cash flow of which, under the Public Utility Regulatory Policy Act of 1978 (PURPA), is tied to the purchasing utility’s avoided costs. The third and least- certain (most subject to moral hazard) method is a cash-flow recovery tied merely to a computational methodology, the components of which may vary from year to year. Most proposals for economic depreciation or trended rate base cashflow calculations follow some combination of the latter two procedures, but both are subject to some degree of post-implementation manipulation by regulatory parties. For further guidance, let us consult the determination of bounds to cashflow patterns in an unregulated competitive market. There, the maximum cash flow to any company is based on a cost, not necessarily their own, but that of the lowest cost alternative. If firm A raises its price above the marginal unit cost of firm B, the latter producer can always cut the former down to size by stealing its customers. So too, one way of setting the level of cash flow to any utility for its generation, as suggested by Hunt, is to grant it the marginal cost of production from the next least costly facility interconnected to the system. As pointed out by Kubitz, this is nothing more than an application of the same avoided cost standard to regulated utilities that is currently applied to small unregulated power producers under PURPA in most jurisdictions. Thus, the establishment of this cash-flow criterion would treat regulated and non-regulated utilities identically. It would avoid substantial rate shock if, plants experienced tremendous construction cost overruns, but it would also be perfectly symmetrical. by yielding substantial profits to those utilities that could build and operate facilities for less than currently available alternatives. And while those utilities that could build plants economically would stand to earn substantial profits in the short run, in the long run consumers would also benefit since those new, lower cost plants would set the avoided cost standard for other plants in subsequent years. Such a procedure would enhance economic efficiency because, although many jurisdictions have implemented marginal cost pricing for marginal consumption in order to achieve efficient usage of electricity by consumers, less attention has been focused on establishing an overall cash-flow signal to utilities (the revenue requirement) that will guarantee a matching long-run supply side efficiency. Thus, in partial answer to Kahn’s pricing efficiency question regarding the need for economic depreciation, in the extreme it may impose cash-flow constraints on some utilities that will in turn rationalize their construction plans. Furthermore, the establishment of an avoided cost‘See Baumol’s
previous
proposal
along
these lines.
R.E. Schuler
and G.A. Hazelrigg,
Jr., Summary
159
based cash-flow standard should accomplish that objective, so long as new capacity can be constructed and operated at a lower real cost than the alternatives. When that is not the case, however, and additional capacity is required to meet peak demands, a more traditional prior specification of cash-flow patterns, presumably tied to an external price index, may be necessary. We say ‘may’, because if secondary markets for capacity become as widely available as current markets for economy power, an effort currently being encouraged by the Federal Energy Regulatory Commission, then in the future, cash flows could be assigned to new increments of capacity, needed solely for reliability purposes, on the basis of an avoided cost standard too. What remains is the nagging question of moral hazard. What if the utilities are too successful in completing low-cost capacity under the previously described avoided cost guidelines? Will subsequent commissions be tempted to siphon profits away from successful companies and Welch on their bargain? Under regulation, all things are possible, but note that the cash-flow setting/pricing procedure just described for new generation is designed to mirror closely what would transpire in a competitive market. In fact, with no further scale economies in generation and in those regions of the country with integrated power pools, a competitive market among alternative generators may be entirely feasible. And by cutting the umbilical cord with the regulators totally, the question of moral hazard to the financial community disappears; they now face only the risk of competitive markets. Only if this process is so successful as to encourage the discovery of future substantial additional scale economies in generation might there be some desire to reestablish traditional price regulation. But that is a happy risk for which it may be well worth loosening the current grip of regulation. While this concluding discussion has strayed from the original topic of economic depreciation, as suggested by Seidel, the digression follows as a logical extension of the theoretical analysis of alternative cash-flow recovery patterns and their incentive consequences. But if the conceptual arguments evolve smoothly, the practical consequences are appreciably different. Economic depreciation, like traditional utility rate-making, begins with actual project costs and uses these ultimately to set the prices; only the formulas differ. By comparison, avoided cost pricing or deregulation sets the price first, and the price then determines which projects ‘the company will start at what anticipated costs. Thus, while economic depreciation is intended to mirror a deregulated market, the sequence of causation is reversed, and only the price-comes-first ordering provides market-like incentives for costeffective planning and construction, provided realistic prices are set. And so the dilemma of efficient regulation comes full circle. How should regulators compute realistic prices in periods of rapid inflation? By using economic forms of depreciation. The only way to break this conceptual cycle is, where feasible, to de-regulate bulk power markets.
160
R.E. Schuler
and G.A. Hazelrigg,
Jr.,
Summary
References Baumol, William J., 1983, Productivity, incentive clauses and rate adjustment for inflation, Public Utilities Fortnightly 110, no. 2, 11-18. Czamanski, Daniel Z., J. Stephen Henderson, Curtis J. Odle and Vivian Witkand, 1981, Regulation as a system of incentives (National Regulatory Research Institute, Columbus, OH). Leonard, Herman B. and Richard J. Zeckhauser, 1983, Public insurance provision and nonmarket failures, Paper presented at the Annual Meetings of the American Economic Association, San Francisco, CA.
and Energy
SUMMARY
7 (1985)
153-160.
North-Holland
OF FINDINGS ON ELECTRIC POWER AND COST RECOVERY
FINANCING
Richard E. SCHULER Cornell
University,
Ithaca,
NY
14853,
George A. HAZELRIGG, National
Science
Foundation,
Washington,
USA
Jr. DC 20550,
USA
Although the intention of the articles in this issue was to emphasize the long-run generic implications of alternative cash-flow recovery schemes, it is interesting how frequently the perceived inequities of recent regulatory experience regarding ad hoc, pragmatic rate base adjustments intruded into the discussion. Thus, while the papers and their commentaries were intended to be forward-ranging and theoretical, and to abstract from the immediate phase-in problems, this summary reverses that ordering and begins by examining constraints to alternative cash-flow recovery schemes, both when implemented to phase-in capacity of unanticipated large expense and as a generic matter. Next, the question of what risk premium, if any, would be imposed by financial markets if the intertemporal cash-flow pattern were to be altered is addressed together with the potential behavioral consequences for electric utilities. These two issues must be discussed together if social pluses and minuses are to be assessed. Finally, the various perceptions of incentive, institutional, and technological consequences of these changes are drawn together and examined once again in light of the overall objective of regulating a natural monopoly, if indeed the generation of electricity is one, to mirror a competitive market. Much of the legal discussion in the papers has focused on the ex-post equities of altering cash-flow recovery patterns after the completion of plants the construction of which was begun under a different set of guidelines. It was generally felt that, without some finding of imprudence, phase-in procedures would be accepted, without some constitutional test, only if the ultimate recovery of cost was deemed to be reasonably certain. In contrast, there seem to be few legal constraints to implementing alternative cash-flow recovery schemes on a prospective, generic basis, if predicated on an adequate record. So,‘the chief legal constraints pertain to the ad hoc phaseins of past mistakes; much flexibility is possible in altering future long-term rate-setting procedures. 0165-0572/85/$3.30
0
1985, Elsevier
Science
Publishers
B.V. (North-Holland)
154
R.E. Schuler
and G.A. Hazelrigg,
Jr., Summary
By comparison, the operation of financial constraints appears to be just the reverse. Although the market behaves with the memory of an elephant with respect to bad news, it is quite likely to accept ad hoc regulatory solutions that modify the rate effects of generation plants with large cost overruns as a clearly preferable alternative to a rate-payer revolution However, on a generic basis, Hyman’s spot-check of several investor groups elicited a uniformly pessimistic response: prospective financing would be difficult and the cost of capital might rise greatly. Such a response seems to suggest a large risk premium associated with future-weighted cash flow patterns. And while, as Myers correctly emphasizes, the only source of a risk premium is the greater exposure to after-the-fact changes in regulatory procedure, not the delayed cash recovery time pattern itself, there still exists what economists call the partial- versus general-equilibrium question. Certainly, if one utility or state were to implement tail-end-weighted cash recovery schemes, investors might flock to those jurisdictions that retained conventional procedures. But suppose all jurisdictions converted at once? While some investors might move to municipal or unregulated corporate securities, Gravelle’s ten percent of total investment in the United States is a lot of investment flow to rearrange at once, particularly if many of the alternatives are equally speculative. Nevertheless, if a risk premium were to arise, Gravelle illustrates how investment in the industry might be altered over time. Of course several of the authors, and in particular Myers, argue forcefully that there may be no risk premium associated with the implementation of an economic depreciation scheme, if the alternative is a ‘thirty percent rate shock. Under which circumstance is the uncertainty regarding the behavior of regulators and politicians greater? Several authors do suggest that the fear of a moral hazard associated with deferred cash flow recovery schemes should be much smaller if it is instituted under a well-prescribed formula, like economic depreciation, as compared to ad-hoc phase-ins. Here the table seems to tilt back again toward a preference for prospective, generic implementation. What the papers seem to reduce to then is the question of estimating the magnitude of the risk premium. The flip-side of this question is: what is the implicit subsidy that regulators are perceived to be providing to current utility investors through front-end-loaded cash recovery techniques? Clearly, few non-regulated industries guarantee that type of recovery pattern, and, in terms of objective measures of business risk, like capital intensity or variability in detrended sales, utilities currently have higher levels of risk than many unregulated businesses. So, shouldn’t utilities have higher costs of capital than unregulated industries, were it not for some implicit guarantee inherent in traditional rate-making procedures? This raises the further question of whether or not the inherent risks of
R.E. Schuler
and G.A. Hazelrigg,
Jr., Summary
155
electric utility operations are more easily diversified at less cost by spreading them in part across all customers, as appears to happen under current regulation where the customer implicitly bears some of the risk premium, or whether that risk should be borne by investors, in which case customers will bear the risk premium explicitly through higher rates of return, if in fact that risk premium exists.’ This theoretical argument about minimizing the cost of risk-spreading could be carried one level higher by proposing widespread regional consortia of utilities arranging for the construction of each and every plant. But Berlin’s description of the litigious consequences of divided responsibility and the double-edged assignment of blame in a recent case regarding the cancelled Pilgrim Plant in New England should be sufficient to diminish the ardor for this type of agglomeration in the near term. The important question, then, that seems to arise from this discussion of assignment of risk is not which allocation leads to the lowest short-run financial costs, but rather which provides the proper planning incentives and therefore the lowest long-run cost of utility service. In fact, any regulation or change in regulatory method will alter to some extent the incentives and motivation of those who are regulated. This was emphasized in Czamanski et al. (1981). Thus, the overriding benefits and costs of reversing traditional intertemporal cash recovery patterns may flow, not just from a change in perceived financial risk and cost, but from the impact those regulatory changes may have in turn on the utilities’ construction plans for the future. As an example, will economic depreciation mean larger or smaller plants? While some variant of economic depreciation, used as a phase-in mechanism, may provide a politically feasible way of completing large nuclear facilities already under construction, most of the authors like Per1 and Peck agree that future facilities are likely to be smaller anyway. Would they be even smaller under a regime of future-weighted cash flows as compared to the existing patterns? A positive answer seems to rest on two hypotheses. First, the propensity of regulators to change a rule increases directly with the elapsed time since its adoption (the dim memory hypothesis) and with surprises. Second, smaller plants can be built more rapidly at costs closer to those originally projected than can large units. If true, the first hypothesis exposes facilities with future-weighted recovery schemes to a greater average likelihood of diminished total cash flow than do front-end-loaded schemes, but this effect can be mitigated in part by building smaller plants, so the chance of triggering the regulator’s attention through cost overruns (second hypothesis) is reduced. ‘In a recent paper, Leonard and Zeckhauser (1983) argue that most competitive markets are large enough to diversify all foreseeable risks except large-scale war, so scale economies in spreading risk are not acceptable arguments for government provision of insurance. A similar argument can be made against regulatory spreading of business risk across utility customers.
156
R.E. Schuler
and G.A. Hazelrigg,
Jr., Summary
Thus, a movement toward delayed cash-flow recovery patterns does seem to re-assign a larger portion of planning and construction risk directly onto the party performing those functions - the utility - which strikes us as a sensible outcome. If that coincidence in turn results in smaller plants, then that too may be sensible. So, under such a revised regulatory framework, any future government initiative to deploy new large-scale electricity supply technologies may require an accompanying explicit government subsidy. Osborne observes that few, if any, utilities are likely to undertake the construction of large nuclear plants in the future without some assurance of CWIP in rate base. In fact, the generic implementation of a system of economic depreciation or trended rate base should result in rapidly increasing cash flows, attributed to the previous plant, just as construction gets heavily underway on the new one; the only problem that may arise is in financing the very first plant to be built after a system of reversed cash-flow patterns is implemented. So, if in the long run, economic depreciation leads to intertemporal cash-flow patterns not unlike those arising from CWIP, why not advocate the less drastic regulatory change of the universal inclusion of CWIP in rate base? The difference, as pointed out by Perl, is the causal link between cost incursion and rate relief. Under traditional rate-making or some form of economic depreciation, the utility’s cash inflow during the construction of a new unit is not governed by the actual costs of constructing that unit. Here a special form of regulatory lag provides an incentive to complete the plant expeditiously so that rate relief can begin. By comparison, allowing 100 percent of CWIP in rate base acts like any other automatic adjustment clause; it provides periodic cash flow for costs actually incurred, which certainly eases the utility’s financial planning problems, but also reduces or postpones the penalties for improper cost control or planning. Again, the choice of a preferred regulatory policy hinges on its incentive implications. One final, horrendous potential inefficiency that Berlin suggests will emerge under existing regulation, and that should be avoided at all costs, is that of undertaking continuous costly studies to justify continued construction of projects solely to withstand potential imprudence charges. In fact, much of the debate on altering cash-flow patterns reduces to issues of accountability and trust, both on the part of utility and of regulator. Myers emphasizes that the risk premium issue is really a problem economists define as a moral hazard. This is the risk that regulators will change the rules of the game if the outcome is not to their liking, and in particular with a futureweighted pattern of cash-flow recoveries, the regulator has a greater opportunity to second-guess the utility. So, in a way, perhaps this entire discussion should be focused on ways of insuring that regulatory bodies adhere to whatever cash-flow recovery system they promulgate. One complicating factor raised briefly by Hunt and Stevenson is that a
R.E. Schuler
and G.A. Hazelrigg,
Jr., Summary
157
large percentage of current rate-shock is attributable to required normalization of Federal Income Tax effects for rate-making purposes. The elimination of that requirement is one ready mechanism that would allow state regulators considerable discretion in determining future cash-flow recovery patterns. What was not discussed was how Congress might respond to widespread state regulatory moves toward reversed cash-flow recovery patterns by making countering changes in the tax code. Hyman’s suspicion that this topic is about a problem that is past may be well-founded with respect to large nuclear plants, but as illustrated in the introduction, many moderately-sized utilities with low rates of load growth face the prospect of substantial and frequent price oscillations in the future under conventional rate-making treatment, merely as a result of replacing existing facilities. That sort of price oscillation is not likely to engender public confidence in utilities or their regulators, and it only heightens our concern over the final issue raised by Kahn: Will the system be able to build new plants when and as they are needed? We contend that this is not a problem that will go away, even when all nuclear plants currently under construction are disposed of, or with a moderation in construction cost inflation rates. Nevertheless, if the purpose of regulation is to mirror a market, then the market does not provide investors in large scale projects with a single incontrovertible intertemporal pattern of cash-flow recovery. Many high technology or consumer, fashion-oriented investments exhibit large initial cash flows that rapidly deteriorate as other competitors enter the market. Other investors, such as real estate developers building commercial properties on speculation, expect some negative cash flow, even in the early years of operation, but they anticipate that booming demand will force prices continuously upward over time. In other capital-intensive industries, such as steel and chemicals, producers may wait until market prices are high enough to insure a reasonable return on new investments before they undertake a capacity expansion. Of course, there are two big differences between all of these businesses and an electric utility. First is the absence of an obligation to provide service. Second, competitive market forces set the price; it is not predetermined (at least in terms of computational methodology) by some regulatory body. In fact, this entire discussion is about alternative computational schemes for setting prices and the certainty with which they will be adhered to by regulators over the life of the project. The most secure method from the utility’s perspective is for the regulators to set a full schedule of future prices in concrete through an iron-clad contract before project construction begins. But this degree of certainty is not available even under current regulatory practice, since allowed rates of return can be varied, within limits, from one rate case to another. A second approach is to tie the cash-flow pattern to some external index, such as the
158
R.E. Schuler
and G.A. Hazelrigg,
Jr., Summary
GNP utility cost deflator,’ that cannot be manipulated by individual utilities or state regulatory bodies. This procedure is similar to the one available to small hydro-electric projects and cogenerators, the future cash flow of which, under the Public Utility Regulatory Policy Act of 1978 (PURPA), is tied to the purchasing utility’s avoided costs. The third and least- certain (most subject to moral hazard) method is a cash-flow recovery tied merely to a computational methodology, the components of which may vary from year to year. Most proposals for economic depreciation or trended rate base cashflow calculations follow some combination of the latter two procedures, but both are subject to some degree of post-implementation manipulation by regulatory parties. For further guidance, let us consult the determination of bounds to cashflow patterns in an unregulated competitive market. There, the maximum cash flow to any company is based on a cost, not necessarily their own, but that of the lowest cost alternative. If firm A raises its price above the marginal unit cost of firm B, the latter producer can always cut the former down to size by stealing its customers. So too, one way of setting the level of cash flow to any utility for its generation, as suggested by Hunt, is to grant it the marginal cost of production from the next least costly facility interconnected to the system. As pointed out by Kubitz, this is nothing more than an application of the same avoided cost standard to regulated utilities that is currently applied to small unregulated power producers under PURPA in most jurisdictions. Thus, the establishment of this cash-flow criterion would treat regulated and non-regulated utilities identically. It would avoid substantial rate shock if, plants experienced tremendous construction cost overruns, but it would also be perfectly symmetrical. by yielding substantial profits to those utilities that could build and operate facilities for less than currently available alternatives. And while those utilities that could build plants economically would stand to earn substantial profits in the short run, in the long run consumers would also benefit since those new, lower cost plants would set the avoided cost standard for other plants in subsequent years. Such a procedure would enhance economic efficiency because, although many jurisdictions have implemented marginal cost pricing for marginal consumption in order to achieve efficient usage of electricity by consumers, less attention has been focused on establishing an overall cash-flow signal to utilities (the revenue requirement) that will guarantee a matching long-run supply side efficiency. Thus, in partial answer to Kahn’s pricing efficiency question regarding the need for economic depreciation, in the extreme it may impose cash-flow constraints on some utilities that will in turn rationalize their construction plans. Furthermore, the establishment of an avoided cost‘See Baumol’s
previous
proposal
along
these lines.
R.E. Schuler
and G.A. Hazelrigg,
Jr., Summary
159
based cash-flow standard should accomplish that objective, so long as new capacity can be constructed and operated at a lower real cost than the alternatives. When that is not the case, however, and additional capacity is required to meet peak demands, a more traditional prior specification of cash-flow patterns, presumably tied to an external price index, may be necessary. We say ‘may’, because if secondary markets for capacity become as widely available as current markets for economy power, an effort currently being encouraged by the Federal Energy Regulatory Commission, then in the future, cash flows could be assigned to new increments of capacity, needed solely for reliability purposes, on the basis of an avoided cost standard too. What remains is the nagging question of moral hazard. What if the utilities are too successful in completing low-cost capacity under the previously described avoided cost guidelines? Will subsequent commissions be tempted to siphon profits away from successful companies and Welch on their bargain? Under regulation, all things are possible, but note that the cash-flow setting/pricing procedure just described for new generation is designed to mirror closely what would transpire in a competitive market. In fact, with no further scale economies in generation and in those regions of the country with integrated power pools, a competitive market among alternative generators may be entirely feasible. And by cutting the umbilical cord with the regulators totally, the question of moral hazard to the financial community disappears; they now face only the risk of competitive markets. Only if this process is so successful as to encourage the discovery of future substantial additional scale economies in generation might there be some desire to reestablish traditional price regulation. But that is a happy risk for which it may be well worth loosening the current grip of regulation. While this concluding discussion has strayed from the original topic of economic depreciation, as suggested by Seidel, the digression follows as a logical extension of the theoretical analysis of alternative cash-flow recovery patterns and their incentive consequences. But if the conceptual arguments evolve smoothly, the practical consequences are appreciably different. Economic depreciation, like traditional utility rate-making, begins with actual project costs and uses these ultimately to set the prices; only the formulas differ. By comparison, avoided cost pricing or deregulation sets the price first, and the price then determines which projects ‘the company will start at what anticipated costs. Thus, while economic depreciation is intended to mirror a deregulated market, the sequence of causation is reversed, and only the price-comes-first ordering provides market-like incentives for costeffective planning and construction, provided realistic prices are set. And so the dilemma of efficient regulation comes full circle. How should regulators compute realistic prices in periods of rapid inflation? By using economic forms of depreciation. The only way to break this conceptual cycle is, where feasible, to de-regulate bulk power markets.
160
R.E. Schuler
and G.A. Hazelrigg,
Jr.,
Summary
References Baumol, William J., 1983, Productivity, incentive clauses and rate adjustment for inflation, Public Utilities Fortnightly 110, no. 2, 11-18. Czamanski, Daniel Z., J. Stephen Henderson, Curtis J. Odle and Vivian Witkand, 1981, Regulation as a system of incentives (National Regulatory Research Institute, Columbus, OH). Leonard, Herman B. and Richard J. Zeckhauser, 1983, Public insurance provision and nonmarket failures, Paper presented at the Annual Meetings of the American Economic Association, San Francisco, CA.