Silviase/jgov_v1.4_full_ann huggingface dataset:
### B. Retail Rate Structures

Table 3 shows average prices per kWh for residential customers and for all customers sampled over five year intervals from 1930 to 1990 and the average rate of change of prices between the sample intervals. This table shows the striking long term decline in electricity prices, reflecting the productivity growth characterizing the industry up until the 1965-1970 time period. The rate of decline was greater for residential rates than for all customers, because, in part, residential prices started at much higher levels. The gap between residential and non-residential rates in the early 1900s is consistent with profit-maximizing behavior, which would have required low prices to induce industrial consumers to switch to electric power. Prior to World War II, average residential rates were about twice the average rate for all customers (which of course includes residential customers). The price increases, starting in the 1970-1975 period, were distributed less to residential customers than to other customer classes. When real electricity rates peaked around 1985, the average residential rate was less than 10% above the system average.

Table 3. Average Electricity Prices: 1930-1990

Year	Residential Rate (¢/kWh)	Residential Rate (1982¢/kWh)	Average Annual % Change	All Customers Rate (¢/kWh)	All Customers Rate (1982¢/kWh)	Average Annual % Change
1930	6.0	38.6	2.7	17.2
1935	5.0	37.3	-0.7	2.4	18.4	+1.4
1940	3.8	27.8	-5.8	2.0	14.9	-4.1
1945	3.5	18.1	-8.2	1.7	9.2	-9.2
1950	2.9	11.4	-8.9	1.7	7.2	-4.9
1955	2.7	9.3	-4.1	1.7	5.8	-4.0
1960	2.5	7.6	-3.9	1.6	5.2	-2.3
1965	2.3	6.4	-3.2	1.6	4.8	-1.6
1970	2.1	4.9	-5.2	1.6	3.9	-4.1
1975	3.2	5.4	+1.9	2.7	4.9	+4.7
1980	5.1	6.0	+2.0	4.5	5.4	+2.2
1985	7.4	6.7	+2.2	6.5	6.1	+2.2
1990	7.8	5.9	-2.5	6.6	5.1	-3.5

Although the rate making process is supposed to produce prices that are not discriminatory and are based on costs, there are clearly exceptions to these principles. Some states have explicit subsidy policies aimed usually at low-income residential customers, sometimes at all
residential customers. More often, subsidies are implicit. Agricultural customers frequently pay low prices that are difficult to justify on a cost basis. Economic development arguments are sometimes used to rationalize low prices to specific industries, or to specific geographic regions. Table 4 below summarizes average electricity costs for 1992 by customer type for the four main ownership structures.

Table 4

Average Revenue ( $ ¢ $ per kWh) by Class of Ownership and by Sector, 1992

Residential	Commercial	Industrial	Average
Investor-Owned	8.6	7.8	5.0	7.1
Publicly-Owned	6.6	6.6	4.8	6.0
Co-operative	7.7	7.4	4.7	7.0
Federal	5.8	6.1	2.7	2.6
Average	8.2	7.7	4.8	6.8

This table shows the different rate policies and average costs of the investor-owned segment, the publicly-owned segment, co-operatives and the federal government. Because government-owned utilities pay no taxes and have no equity capital, their rates should be lower than investor-owned firms. There are also significant operating subsidies from the federal sector to the municipal and co-operative segments. As Table 1 indicated, federal power sales to ultimate customers are small. Most federal sales are preferential allocations of hydroelectric generation at very low cost. This explains why the average rate for federal power is lower than all rates to end-use customer classes. Despite these price differences, studies of the relative efficiency of government versus investor-owned electric utilities have detected no significant differences (Atkinson and Halvorsen, 1986).

Table 4 also indicates a tendency toward price discrimination against commercial customers. For both publicly-owned and federal rates these customers pay the highest prices. For investor-owned and co-operative firms residential rates are somewhat higher than commercial. The differentials, however, are too small to be based entirely on cost. The typically higher voltages and higher load density of commercial as opposed to residential customers would suggest bigger price spreads. In all likelihood, the commercial customers rates are more determined by their relative bargaining weakness compared to the political power of residential customers. Industrial customers wield economic power because they can shift production to regions with lower costs and, in some cases, they can generate their own power requirements.

### C. Investment Behavior

Mismatches between supply and demand were particularly severe during the 1970s and
1980s as the size of generating units grew and construction lead time lengthened. At first, the issue was potential capacity deficiencies. During the 1970s, the requirements for environmental review of power plant construction became much greater than they had been previously. Repeated changes in safety requirements, particularly following the accident at Three Mile Island in 1979, lengthened construction and added to its cost. The oil price shock of 1973-74 made the economics of coal and nuclear power projects more attractive, but the contemporaneous rate increases also reduced demand growth. By the late 1970s, short-run marginal costs were high, reserve margins were low, and the backlog of large-scale construction projects was substantial.

This process reversed in the 1980s. Oil prices began a gradual decline. A severe economic recession reduced demand growth. Utilities began to cancel plans for capacity expansion. In the 1972-1974 period utilities ordered 107 nuclear plants. Between 1975 and 1978, 38 were canceled and another 48 were canceled in the 1979-1982 period (EIA, 1983). Despite these efforts to adjust supply, there was substantial excess capacity during the mid-1980s. The cost disallowances described briefly in Section III were based in part upon excess capacity considerations.

Table 5 shows the growth in capacity and demand for the period 1966-1990, and their consequences for reserve margin. Reserve margin is used as the best single summary statistic measuring the adequacy of capacity relative to demand. A conventional industry rule of thumb for reserve margin (measured as the percentage of capacity above peak demand) is 20%. This is often related to some probabilistic measure of outage risk, but the appropriate outage risk level is usually specified by convention, rather than by economic criteria. The Table 5 data are at the aggregate national level. The non-coincident peak means just the sum of the highest demands, regardless of when during the year it occurred. As such, these data conceal regional variations, and probably understate effective reserves, due to potential capacity sharing when peak loads occur at different times. Table 5 clearly shows the excess capacity period from 1975-1990.

Table 5. Aggregate Capacity and Peak Demand Growth and Reserve Margins

Period	Capacity Growth Rate (%)	Demand Growth (%)	Average Reserve Margin (%)
1966-1970	6.4	6.2	18.5
1971-1975	6.2	4.0	24.6
1976-1980	2.7	3.3	33.2
1981-1985	1.6	1.4	36.2
1986-1990	1.1	3.1	29.2

Table 6 gives aggregate data on the capital expenditures of the investor-owned segment from 1973-1990. The tremendous inertia of the commitment to nuclear power is indicated by
comparing this data with Table 5. At the very time when price induced declines in demand were increasing excess capacity, the capital budget of the industry was escalating substantially.

The Table 6 data are also interesting in the more recent period. The rapid decline in generation sector investment explains most of the decline in total construction. The only offsetting effect is an increase in distribution system investment, which increases by 40% from 1983 to 1990. These data suggest that while the vertically integrated firms are losing control of the generation segment (see Part 3), they are relatively free to shift investment attention to the distribution segment, which is free from competitive pressures. There is no incentive to increase transmission investment because it would inevitably end up strengthening the competitive position of independent generators seeking wider markets.

Table 6. Construction Expenses of Investor-Owned Utilities

(Billions of 1982 dollars)

Year	Total Construction	Generation	Transmission	Distribution
1973	31.0	17.4	3.9	7.3
1974	31.8	18.7	3.9	6.7
1975	27.3	17.0	3.0	5.2
1976	29.2	19.1	2.9	4.7
1977	32.2	21.8	2.6	5.1
1978	33.8	22.7	2.4	5.5
1979	34.7	23.7	2.7	5.6
1980	33.0	22.4	2.7	5.3
1981	32.7	22.3	2.4	4.9
1982	35.3	25.3	2.2	4.8
1983	37.3	24.0	2.2	4.8
1984	31.0	22.2	2.0	5.5
1985	28.0	19.3	1.6	6.0
1986	25.7	16.3	1.5	6.3
1987	21.7	12.3	1.8	6.3
1988	18.0	8.2	1.6	6.8
1989	18.3	7.8	2.0	6.9
1990	17.0	6.6	1.8	6.8
Table 7. Number of Investor-Owned Firms

State	1938	1948	1958	1968
California	8	7	5	3
Illinois	16	16	9	8
Massachusetts	43	36	25	16
New Jersey	5	7	6	5
New York	22	19	14	8
Ohio	15	13	11	8
Pennsylvania	22	21	18	12
National Total	412	321	265	236

### B. Productivity Stagnation and Its Consequences

The U.S. regulatory system functioned smoothly during the post-WWII period as long as productivity increases continued. When these stagnated and began to reverse themselves in the 1970s and early 1980s, the system came under strain. Joskow (1987) is a good summary of these effects. The regulatory response to these conditions was a variety of experiments. We give a brief overview of these experiments, some of which will be examined in more detail below.

The locus of productivity problems in electricity was in new generating capacity. Initially the problem had its origin in the increased stringency of environmental regulation. The Clean Air Act and the requirements of the National Environmental Policy Act raised the cost of new power plants by requiring extensive review of the impact of new facilities and imposing mitigation costs. Increasingly stringent environmental regulation also affected nuclear power. Following the Three Mile Island accident of 1979, increased safety regulation required considerable extra work on a large number of plants under construction. The high interest rates during this period, slow growth, and management inefficiency also had negative impacts on construction costs. When plants entered commercial operation in the early 1980s, their nominal dollar costs were frequently 5 to 10 times higher than original estimates.

Standard regulatory practice in the U.S. defers including new plant costs in rates until commercial operation. Then, the costs are placed into “rate base” and become part of the total cost of service to be recovered in rates. A crucial step in this process is the determination that the costs were prudently incurred and that the projects are “used and useful.” The large costs of nuclear power projects focused more attention on these questions than they had previously received. State commissions refused to accept all costs. Disallowances in the range of 10-40% became frequent during the 1983-1987 period. The total disallowance has been estimated at $10 billion (ORNL, 1987, 1989). Sometimes the rationale for disallowance was “imprudence;” sometimes it was
excess capacity. In the latter case, the utility would eventually recover some of the costs as demand increased.

The disallowance experience (which was not confined to nuclear plants) created strong incentive effects. Utilities that were punished financially had a disincentive for investment. Regulators, disappointed with the performance of firms, developed a more activist stance regarding alternative resource strategies. A number of state jurisdictions implemented performance incentive schemes for baseload power plants. Joskow and Schmalensee (1986) found that these were the dominant type of incentive mechanism adopted in the U.S. electricity industry. The productivity of capital intensive baseload power plants depends considerably on their level of output. Through a system of rewards and penalties, regulators hoped to induce good performance and lower overall cost. The effect of these incentives is doubtful. Berg and Jeong (1991) studied these programs. They find that a measure of cost inefficiency is a good predictor of the agency's decision to adopt incentive mechanisms. Unfortunately, they find that firm efficiency does not improve due to these mechanisms. Presumably such results, if correct, occur because the incentive is limited to only part of the firms' behavior and not all of it.

### C. The Political Economy of Deregulation

The first steps toward deregulation in the U.S., the passage of the PURPA legislation and its implementation, were taken as a response to the problems of the nuclear power industry. Vigorous growth of the private power industry created constituencies that lobbied for the expansion of this sector at the expense of the investor-owned firms. This process eventually contributed to the passage of the Energy Policy Act of 1992 (discussed at greater length in Part 3), which substantially expanded the rights of these producers.

These transformations were constrained to occur with no major disruption to existing stakeholders. Asset write-downs were limited, bankruptcies few. The contrast with drastic government intervention in other countries, however, is remarkable. Nationalization as a remedy of last resort is virtually absent from political discussion of the problems and solutions proposed for the electricity sector. The highly fragmented industry structure makes any kind of nationalization a formidable political and administrative task. It also limits the ability to achieve rapid, large-scale privatization.

### Part 2. Competitive Bidding and Independent Power

### I. Introduction

The creation of an unregulated independent power industry in the U.S. began incrementally, and without explicit central policy design, as a result of a number of separate legal, regulatory and economic changes. The major watershed event was the passage of the Public Utilities Regulatory Policies Act (PURPA) of 1978. PURPA created a class of private suppliers, called Qualifying Facilities (QFs) that were exempt from profit regulation and entitled to sell their
Table 8. Prices of Private Power Projects

20-Year Levelized Prices
Fuel Type	Project Name	Contract Capacity (MW)	Capacity $/kW-yr	Energy $/kWh	Total 80% cf $/kWh
Coal	Indiantown Cogen	300	351	0.035	0.085
Chambers (Carneys Point)	184	324	0.042	0.088
Crown Vista	100	523	0.029	0.104
Average	400	0.035	0.092
Gas	Hermiston	409	181	0.020	0.045
Independence	740	43	0.049	0.055
Hopewell Cogen	248	150	0.035	0.056
Richmond Power Ent./SJE Cogen	210	145	0.036	0.057
Doswell	600	171	0.033	0.057
North Las Vegas	45	199	0.030	0.058
Spanaway (Pierce Co., Wa.)	240	0.060
Gordonsville/Turbo Power I and II	100	128	0.045	0.064
Panda	165	160	0.042	0.065
Brooklyn Navy Yard Central	90	254	0.031	0.067
Tiger Bay	217	299	0.028	0.070
Blue Mountain Power	150	338	0.022	0.070
Wallkill	95	269	0.034	0.072
Brooklyn Navy Yard B	40	277	0.036	0.075
Brooklyn Navy Yard A	40	278	0.036	0.076
Linden	594	266	0.041	0.079
Pedricktown	106	234	0.050	0.083
Holtsville	136	251	0.050	0.085
Dartmouth, Mass.	68	405	0.028	0.085
Enron	83	520	0.020	0.094
Average	240	0.035	0.069
Peaker	Hartwell	303	90	0.038	0.051
Commonwealth Atlantic	312	68	0.052	0.061
Average	79	0.045	0.056
Wind	Franklin & Somerset Co. ME	20	0.056*
Table 9. Selected Data on Independent Generation (1992)

Independent Generation (million kWh)	Sales (million kWh)	Independent Share (%)
California	59.3	213.4	27.8
Florida	10.3	147.0	7.0
Louisiana	18.7	65.1	28.7
Massachusetts	7.5	45.0	16.7
New Jersey	12.8	63.1	20.3
New York	14.1	128.5	11.0
Texas	51.6	239.4	21.5
Virginia	7.7	76.5	10.0
U.S. Total	296.0	2763.3	10.7

In 1992, the policy agenda shifted to the legislative arena. The Energy Policy Act created a new class of private producers as part of a change in federal regulation under the Securities Exchange Commission. The transmission access questions were also addressed in this legislation, but in ways that will take time to assess.

### Part 3. Implications of an Open Access Regime

### I. Introduction: The Energy Policy Act

The Energy Policy Act (EPAct) of 1992 has opened the door to significant change in wholesale competition by greatly extending the powers of the Federal Energy Regulatory Commission to mandate transmission access. Prior to this Act, the FERC was prevented from mandating transmission access that interfered with existing competitive relationships. This has now changed. EPAct gives the FERC authority to mandate transmission access if

(1) voluntary negotiations have been conducted by the requesting entity and transmission owner for 60 days;

(2) the order would be in the public interest;

(3) reliability of all utility systems affected by the order would be maintained;

(4) third-party wheeling is not subsidized by utility’s existing customers.

If the FERC has the objective of promoting wholesale transmission access, it appears that
it will now have broad power to do so. The powers do not extend to transmission access at the retail level. There is substantial controversy in the U.S. over the issue of competition for end-use customers. Although some erosion of the franchised monopoly in distribution is likely to occur, for the most part there is a resistance to introducing retail competition on a wide scale, as is scheduled to occur in the British electric power market.

### I I. Transmission Pricing

The liberalization of wholesale trade represented by EPA $ ^{st} $ increases the importance of transmission pricing policy. FERC is considering a broad range of options, which we summarize here. The three approaches that we outline represent a different approach to the role of regulation and the structure of inter-firm relations.

### A. Regional Transmission Groups - Reciprocal Voluntary Arrangements

There is a long tradition of reciprocal voluntary transmission arrangements in segments of the U.S. electricity industry. In its most elaborated form, these arrangements underlie the fully integrated power pools that operate principally in the Northeastern region. For a pooling arrangement to work, the members must be able to exchange power freely over the combined network of transmission facilities. Where the pool does central dispatch of the combined generation resources, fully reciprocal use of the combined transmission network occurs.

There are looser pooling arrangements which do not involve central dispatch. In these, some form of reciprocal transmission arrangement is also necessary, but the mutual commitment is less than in the fully integrated case. "Loose" pools commonly operate a kind of brokerage service, where parties post willingness-to-buy and willingness-to-sell offers, but transactions occur through bilateral arrangement. Power pooling institutions in the United States are surveyed in FERC (1981).

The limiting cases of reciprocity are bilateral agreements to exchange transmission services and emergency support involving commitments among many participants in a transmission network. In the latter case, the agreements are only for extraordinary circumstances where reliability is involved. Such arrangements are nearly ubiquitous. Typically the prices charged for emergency support are higher than the prices charged for routine firm and non-firm transmission services.

In principle, reciprocal voluntary arrangements might operate under the Energy Policy Act by offering transmission service within the framework of regional transmission groups (RTGs). These arrangements would be voluntary, although it is likely that they would be constrained by a constitution governing the policies of the group. There is considerable uncertainty about how and under what conditions concerning access to facilities such accommodation might or might not be achieved.

The limiting case, where an RTG developed a costing approach for transmission access that would be based on regional implementation of avoided-cost principles. This would require the
following elements.

## (i) A transmission resource plan (TRP)

The correct cost for transmission access is the incremental cost that a user imposes on a system. This requires an assessment of the impact that a user's demand for access would have on the current cost-minimizing plan for constructing and maintaining adequate transmission capacity to meet the needs of its members. This, in turn, requires the development of a resource plan that is accepted by the RTG members.

## (ii) A cost model for the TRP

The preferred TRP would depend on the needs of the Group members, and on the costs of satisfying those needs. This requires the development of a transmission costing model. Such a model would compute the total present-value cost of building and maintaining a desired transmission configuration. Given the economies of scale and interdependencies of transmission costs, it is unlikely that an algorithm could be devised that would choose the optimal plan for the members' needs. Instead, several scenarios would have to be specified and the RTG would have to narrow the search done to those plans that are most cost-effective. Finding the optimal scenario would be an iterative process. Iteration would be necessary to investigate the cost consequences of different plans. An additional complication is that users' demands for transmission services depend on their costs. Therefore, the optimal resource plan would have to be an iterated process so that demands are consistent with the cost of the resources that are made available.

## (iii) The incremental cost of additional demand for transmission services

If a transmission system has adequate capacity to meet all demand in the foreseeable future, the economic cost of transmission is only the cost of line losses and other operating costs that are directly attributable to a user's demands. If the system does not have adequate capacity, the economic cost of transmission includes the present-value of additional investment that must be incurred in order to provide the service. This is the same principle that governs the determination of avoided generation costs.

To estimate a transmission user's capacity cost, it would be necessary to evaluate the change that the user's demand imposes on the present-value cost of meeting all users' transmission needs. Although the principle is identical to the principle of avoided generation capacity costs, this is a more complicated calculation because the cost is likely to depend on the size and the location of the transmission user's demands. Qualitatively, if T is a vector of all the transmission services that are anticipated in the RTG's optimal resource plan, and if $ t_{ij} $ is transmission demand of an individual user, the capacity cost of the transmission service is

$$ \mathbf{c}(t_{ij})=C(T+t_{ij})-C(T), $$