Abstract
We revisit Stigler and Friedland’s (J Law Econ 5:1–16, 1962) seminal paper by examining how competitive generation affects prices, sustainability, and reliability in the electricity industry. Exploiting state and year variation in the introduction of regional transmission organizations (RTOs) that facilitate open access to transmission, we first show that wholesale market deregulation significantly increases the prevalence of independent power producers (IPPs). Using RTO membership as an instrument, we find that IPP entry fails to cut electricity prices paid by consumers. This non-result is also robust to using initial electricity tariffs as an instrument for changes in IPP in a long-difference specification. We provide suggestive evidence that the absence of consumer gain can be attributed to efficiency loss due to mandated divestiture of generation assets or simply higher upstream transaction costs. But, increased prevalence of IPPs is associated with more solar and hydropower, although the use of non-fossil fuel as a whole remains unchanged because less nuclear power is used. More IPPs, however, is also associated with less reliable electricity supply. A review of the origins of electricity deregulation suggests that this tradeoff between environmental sustainability and energy security is not likely to have been the major determinant of the deregulation. Rather than a pro-consumer deregulation, the regulatory change is perhaps more appropriately interpreted as a regulatory capture that benefits IPP entrants and existing energy marketers.
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22 May 2020
The published version of this article contained a mistake. The name of the second author was printed incorrectly. The correct name is Kwok Ping Tsang.
Notes
See Mulligan and Tsui (2016) for a theoretical discussion on how price regulation affects quality choice in a competitive environment.
In an interesting recent study, Boylan (2016) found that storms disrupt electricity consumption in areas served by municipal utilities but do not disrupt those served by IOUs. Some of our results are complementary to his in the sense that, instead of comparing public versus private ownership of utilities, we examine whether the entry of IPPs in deregulated states affects the number and duration of outages.
Joskow (2001) and Borenstein et al. (1999) use the California experience to illustrate that deregulation in the wholesale market is challenging and might not bring the prices down to competitive level. McRae and Wolak (2009) and Domah and Pollitt (2001) show that privatisation in the England Wales’ electricity market could lead to higher cost in the beginning due to higher institutional costs caused by the creation of new buiness and markets.
Kasermand and Mayo (1991) was among the first that empirically estimate the economies of vertical integration in the electricity market. Since then, various studies have estimated the economies of vertical economies can range from 6 to 20% in the U.S. and European markets. See Arocena et al. (2012), Gugler et al. (2017), and Meyer (2012).
Right before the California electricity crisis, for instance, Joskow (2000) wrote “[c]ompetitive entry of new unregulated generating facilities owned by developers that assume construction and operating cost risks and that have incentives to use the lowest-cost technologies is likely to be one of the most important long-term benefits of competitive electricity markets.” Even long after the crisis, this view is still shared by the FERC, which claimed “[e]ffective wholesale competition protects consumers by providing more supply options, encouraging new entry and innovation, spurring deployment of new technologies, promoting demand response and energy efficiency, improving operating performance, exerting downward pressure on costs, and shifting risk away from consumers” (Federal Energy Regulatory Commission, 2008).
A problem is further complicated by the fact that even under the regulated regime, there was variation in the specific regulatory approaches of different states. The widely-used dummy-variable approach, in which regulation is measured by a dummy variable indicating whether a state is “regulated” or “unregulated,” has also been criticized because both regulation and deregulation are often lengthy and incremental processes (e.g., Joskow and Rose 1989). When the “regulated” dummy variable is subject to severe measurement error, standard estimation method is likely to produce biased results.
Measurement error is much less of an issue with IPP prevalence. Our panel dataset enables us to take advantage of within-state variation in IPP prevalence, because the share of generation from IPPs was essentially zero in most of the states at the beginning of our sample period. For instance, at the national level, the share of generation from IPPs has increased from a trivial amount in the early 1990s to almost 40% today. Today, the share is as low as less than 1% as in South Carolina, and it can also be as high as more than half as in California.
Moreover, efficiency improvement among the infra-marginal plants may have little impact on prices, which are determined by the marginal plants.
Our non-results are broadly consistent with the earlier literature that examines the direct price effects of deregulation (Kwoka 2008). The earlier literature concluded that there is little reliable evidence that electricity prices become lower as a result of deregulation. More recently, by focusing on states that have not restructured their electricity markets, Kury (2013) showed that there is no robust relationship between the formation of ISO/RTO and electricity prices. In terms of retail competition, Su (2015) found that introducing retail choice does not lower electricity prices across the board or over time.
For instance, England and Wales have become more competitive since the late 1990s, which have increased efficiency and have conveyed more benefits to consumers (Newbery 2006). In many developing countries, electricity reform appear to have increased operating efficiency and expanded access to urban customers (Jamasb et al. 2005). In the U.S. market, Borenstein (2002) argues that restructuring in electricity market is challeging. “The difficulties in outcomes so far, however, should not be interpreted as a failure of restructuring, but as part of the lurching process toward an electric power industry that is still likely to serve customers better than the approaches of the past.” Hogan (2002) notes that “[t]he benefits of reform may be substantial, but they require careful attention to market design.” Joskow (2008) and Brennan et al. (2002), in reviewing the historical experience, concludes that even though incompletely or incorrectly implemented reform can carry risk of significant potential costs, electricity sector reforms still have significant potential benefits.
Unlike a decentralized market where buyers and sellers can simply rely on bilateral agreement, in centralized electricity wholesale market there is a demand for energy marketers. For example, Enron is such an energy marketer that benefited from the emergence of centralized electricity wholesale market.
The regulatory experience of local phone service is perhaps also consistent with this interpretation of the capture theory of regulation. See Sect. 6 for more details.
The basic principles of Order No. 888 are simple: “transmission owners must provide access to third parties to use their transmission networks at cost-based maximum prices and non-discriminatory terms and conditions, make their best efforts to increase transmission capacity in response to requests by third parties willing to pay for the associated costs, and shall behave effectively as if they are not vertically integrated when they use their transmission systems to support wholesale market power transactions” (Joskow 2000a, b). Order No. 889, on the other hand, specifies information availability rules and various behavioral rules designed to guard against discriminatory practices by the transmission owner.
While some states mandated divestitures, others adopted stranded-cost recovery mechanisms that provided financial incentives to encourage utilities to sell their generating plants. There were also state reform programs that encouraged utilities to transfer their generating plants to unregulated affiliate companies. According to Wolfram (2005), “[b]y the end of 2001, 305 plants accounting for over 156,000 MWs, or nearly 20% of US generating capacity had been transferred from utilities to merchant generators.”
During the same period of time, some states began to develop retail competition. Moreover, there was an increase in the number of mergers among traditional electric utilities and among electric utilities and gas pipeline companies. According to Order 888, however, “[a]mong the many issues that are important to competitive bulk power markets are: independent system operators (ISOs); regional transmission groups; generation market power; utility merger policy; and the development of innovative transmission pricing alternatives, such as flow-based, distance-sensitive transmission pricing methodologies that reflect incremental costs. In particular, we believe that ISOs have great potential to assist us and the industry to help provide regional efficiencies, to facilitate economically efficient pricing, and, especially in the context of power pools, to remedy undue discrimination and mitigate market power.” (pp. 51–52).
Order 2000 proposed four minimum characteristics (independence, scope and regional configuration, operational authority, and short-term reliability) and eight minimum functions of an RTO (tariff administration and design, congestion management, parallel path flow, ancillary services, OASIS and total transmission capability and available transmission capability, market monitoring, planning and expansion, and interregional coordination).
To date, the majority of the power grids are still owned by IOUs. The number of transmission owners also varies across RTOs. Moreover, each of them has its own governance structure. For instance, while some have all independent members as board of directors, some also have stakeholders in their board. Some, not all, also have committees with representatives from IOUs, IPPs, state and federal agencies, public consumer advocates, environmental advocates, etc.
FERC defines scope requirement as: “Order No. 1000 requires public utility transmission providers to improve transmission planning processes and allocate costs for new transmission facilities to beneficiaries of those facilities. It also requires public utility transmission providers to align transmission planning and cost allocation. These changes will remove barriers to development of transmission facilities.” See the details at https://www.ferc.gov/media/news-releases/2013/2013-1/02-21-13-E-1.asp. Over time, some ISOs have evolved into RTOs or organizations similar to RTOs.
In other states that allow wholesale competition but are not part of any ISO/RTO (e.g., states in the Northwest and Southeast), their approach to competition is to base trades exclusively on bilateral sales negotiated between suppliers.
We note that deregulation at the retail level can also be relevant to our analysis. By early 2001, 22 states and the District of Columbia had adopted retail competition legislation. These states tended to view the separation of power generation ownership from power transmission and distribution ownership as a prerequisite for retail competition. Among them, California, Connecticut, Maine, New Hampshire, and Rhode Island passed laws requiring IOUs to divest their power plants. Other states encouraged divestiture to arrive at a quantifiable level. In our analysis, we provide robustness checks to examine if deregulated states with and without retail choice have different market performances.
States that suspended their plans of retail market restructuring were Arizona, Arkansas, California, Nevada, New Mexico, Virginia, Wyoming.
According to the EIA website, the average price of electricity is calculated by dividing the electric revenue from ultimate consumers by the corresponding sales of electricity. The average price is calculated for all consumers and for each end-use sector. In other words, it represents a weighted average of consumer revenue and sales, and does not equal the per kWh rate that individual consumers is being charged under peak-load pricing that is commonly practiced by electric utilities.
Day 2 RTO offers a fully functioning centralized market for day-ahead and real-time energy, capacity and ancillary services, and market-based congestion management. The major source of heterogeneity among different RTOs comes from these additional market functions.
The regressions with different outcomes variables share similar structure.
We thank a referee for raising this point. We did indeed try to contact the EPA for the relevant data. However, the data would be very difficult to come by, and would merit an entirely new project.
Some earlier studies considered the reduced-form \(Price_{it} = \beta_{r} RTO_{it} + X_{it}^{\prime } \gamma_{r} + \delta_{r,i} + \lambda_{r,t} + \varepsilon_{r,it}\). For instance, Taber et al. (2006) find that wholesale competition (measured by ISO membership) does not reduce retail prices. Lenard and McGonegal (2008) find that wholesale competition (measured by RTO membership) does not reduce wholesale prices. Our two-stage least squares estimate can be interpreted as the ratio of the reduced-form coefficient and the first-stage coefficient (i.e., \(\beta_{0} = \beta_{r} /\beta_{1}\)).
We have also experimented with cross-sectional specifications using early price as instrument for IPP prevalence. None of these specifications suggest IPP prevalence reduces electricity prices.
The results are not sensitive to the choice of sample periods.
To evaluate if this assumption holds as well as we can, we regress the change in tariffs from 1993 to 1995 (before the appearance of the first RTO/ISO) on the initial tariffs in 1990 and the changes in log income and population over the same period. The results are shown in Table 15 in the “Appendix”, and they indeed show that initial tariffs do not predict changes in tariffs in the further future.
None of the effect on other renewable fuel is significant.
We thank one referee for pointing this out.
Note that in the IV estimation reported in Table 8, our first-stage regression has the “wrong” sign because data on reliability are only available after year 2000, when IPP prevalence in the deregulated states was about to decline. However, ISO/RTO membership is still a valid instrument for IPP prevalence because the two variables are significantly correlated.
Januszeski Forbes and Lederman (2009) argue that such vertical economies can explain the better responses to weather emergencies in the airline industry.
All retail choice states (except Oregon) are located in regions where wholesale electricity prices are set through ISOs or RTOs. However, not all states with centralized wholesale markets have retail competition.
A related reason is the presence of search friction in the retail market (Hortaçsu et al. 2015).
According to EIA (2000), “California, Connecticut, Maine, New Hampshire, and Rhode Island are examples of States with laws explicitly requiring utilities to divest their fossil and hydroelectric generation assets and, potentially, any ownership in nuclear power generating assets.”
If instead we exclude California, Connecticut, Maine, New Hampshire, and Rhode Island in our sample, the point estimate is 0.214, with standard error 0.553.
Restricting our sample to the states from PJM and MISO as well as other regulated states, we still obtain a positive point estimate of 0.234, with standard error 0.481. Note also that states in PJM such as Pennsylvania, New Jersey, and Maryland do not require retailers to divest their generating assets.
Notice that this implication implies asymmetric effects of endogenous regulation and deregulation, because prices are expected to go up in the former case.
White (1996) observed that “in no state entertaining electric utility regulatory reforms have regulators offered to withdraw their authority to intervene with the visible hand should market forces fail to perform in a suitably equitable fashion.”
A number of studies have discussed that electricity deregulation had its origins in overinvestment in nuclear. For example, Weare (2003) notes that “In the early 1990s, interest in restructuring the California electricity sector was spurred by the high cost of electricity. In 1995, because of expensive investments in nuclear power and high-priced contracts for QF power, California consumers paid the highest rates in the western continental United States.”
See Becker (1983) for his analysis of interest group competition where deadweight losses are a constraint on inefficient regulation.
We thank one referee for this suggestion.
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We would like to thank Bill Dougan, Nic Tideman, Maggie Wang and seminar participants at Clemson University for helpful comments.
Appendix
Appendix
See Tables 11, 12, 13, 14 and 15.
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Leung, T.C., Ping, K.P. & Tsui, K.K. What can deregulators deregulate? The case of electricity. J Regul Econ 56, 1–32 (2019). https://doi.org/10.1007/s11149-019-09386-9
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DOI: https://doi.org/10.1007/s11149-019-09386-9