Springer Science and Business Media LLC

We examine the impact of state incentive regulation on network modernization, aggregate investment, revenue, cost, profit, and local service rates in the U.S. telecommunications industry between 1986 and 1999. We find evidence of greater network modernization under price cap regulation (PCR), earnings sharing regulation (ESR), and rate case moratoria (RCM) than under rate of return regulation (RORR). Costs are generally lower under RCM. Costs are also lower under ESR and PCR when local competition is sufficiently intense. Some local service rates for business customers are lower under PCR. Revenue, profit, aggregate investment, and residential local service rates do not vary systematically under incentive regulation relative to RORR.

This paper examines the effectiveness of using community-level rewards to subsidize environmental protection. Specifically, we study the Connecticut Clean Energy Communities (CCEC) program that provides mostly symbolic rewards in the form of municipal photovoltaic installations in proportion to the number of households that voluntarily purchase green electricity. We find that the program causes a 22 % increase in the number of households purchasing green electricity in CCEC municipalities. The pattern of results suggests that the CCEC leads to the mobilization of community-based recruitment campaigns that increase signup rates by up to 700 % around the period of initial qualification. We also find that a change in the marginal incentive created by the program has little consequence on signup behavior. The implication for policy is that community-based incentives can be effective, but the size of the subsidy itself appears less important. Finally, simple calculations based on CCEC up-front costs reveal upper-bound, cost-effectiveness measures of $570 per household signup, 6.7 $$\not {c} $$ per kilowatt-hour of annual green-electricity demand, and $113 per ton of annual carbon-dioxide emission reductions.

Over the 30 year history of the Rutgers University CRRI Eastern Conference the regulatory scene has changed dramatically. In 1989 the first Issue of the Journal of Regulatory Economics appeared. This paper builds on Crew and Kleindorfer (J Regul Econ 21(1):5–22, 2002), which reviewed 20 years in the development of regulatory economics. In addition, this aricle outlines the history and assesses the significance of the JRE in the literature of regulatory economics.

Traditional methods of evaluating transmission expansions focus on the social impact of the investments based on the current generation stock which may include firm generation expansion plans. In this paper, we evaluate the social welfare implications of transmission investments based on equilibrium models characterizing the competitive interaction among generation firms whose decisions in generation capacity investments and production are affected by both the transmission investments and the congestion management protocols of the transmission system operator. Our analysis shows that both the magnitude of the welfare gains associated with transmission investments and the location of the best transmission expansions may change when the generation expansion response is taken into consideration. We illustrate our results using a 30-bus network example.

This paper considers a market with an incumbent monopolistic firm and a potential entrant. Production by both firms causes polluting emissions. The government selects a tax per unit of emission to maximize social welfare. The size of the tax rate affects whether or not the potential entrant enters the market. We identify the conditions that create a market structure where the preferences of the government and the incumbent firm coincide. Interestingly, there are cases where both the government and incumbent firm prefer a monopoly. Hence, the government might induce profitable monopolization by using a socially optimal tax policy instrument.

Performance based regulation (“PBR”) directly regulates public utilities’ prices or revenues with the goal to provide greater incentives for achieving efficiencies and other cost savings than cost-of-service (profit) regulation provides. PBR plans typically include a formula capping the allowed prices or revenues with the cap calculated to reflect what we would expect to observe in competitive markets in the long run: prices are set to equal input prices minus productivity “I–X”, where I represents inflation and X represents industry-wide productivity. The PBR formula may also include a consumer stretch factor (“stretch factor”)—sometimes referred to as a consumer productivity dividend. Some regulators view the stretch factor as a one-time component meant to share between the company and customers the immediate expected increase in productivity growth as the regulated firm transitions from cost of service to PBR regulation. Other regulators view it more as a permanent component of PBR meant to incentivize the regulated firm beyond the initial switch to PBR by benchmarking its costs to a comparable group of companies and rewarding (penalizing) it for superior (inferior) cost performance. This paper focuses on economic aspects of utilizing the stretch factor as a permanent feature of PBR, and importantly, on the theoretical underpinnings of utilizing cost benchmarking to determine the stretch factor in a PBR plan. We provide a review of the academic literature on econometric cost benchmarking and assess that literature with respect to the stretch factor. We provide an econometric cost benchmarking analysis, using data on U.S. electricity transmission.

Residential electricity competition is under investigation in a number of U.S. states due to alleged market imperfections including consumer behavior that is supposedly inconsistent with rational, economic decision-making. In this paper, I examine these issues and use a panel data of distribution utilities in Illinois during the period 2011–2017 to estimate demand models for regulated and competitive electricity services. I find that residential electricity consumers in Illinois are acting in a manner consistent with standard consumer behavior theory, with price elasticity of demand estimates that are generally in line with those in the literature, ranging between − 0.40 and − 0.60. Importantly, I find evidence that customers served by competitive suppliers are sensitive to the regulated default service price. Specifically, I find that a 1% decrease in the regulated default service price will lead to approximately 0.5% of customers served by competitive suppliers switching to the regulated default service. These findings call into question some of the underpinnings of policymakers’ critique of residential electricity competition.

This study focuses on the welfare impact of taxes, minimum-quality standards, and/or product labeling. A theoretical framework shows that the combination of a label and a per-unit tax is socially optimal. Alternatively, if the label is unavailable, the theory cannot directly conclude which instrument should be socially preferred. Estimations of willingness-to-pay (WTP) are useful for completing the theoretical analysis and evaluating policies ex ante on case-by-case basis. Using hypothetical WTP for shrimp, we confirm that the combination of a label and a tax is socially optimal. In the absence of a label, simulations show that a minimum-quality standard leads to a higher welfare compared to a tax.

Traditional economic theory provides a conundrum for pricing large, lumpy infrastructure investments: very different short- and long-run pricing prescriptions. Unless the facility is congested, efficient short run prices should only cover operating costs (short-run marginal cost, SMC); any higher price designed to also recover capital costs would risk inefficient under-utilization. However, if the facility becomes crowded, capital costs should be included in the calculation of user-fees since that burgeoning demand is likely to cause the construction of more capacity, and users should be confronted with the cost-consequences of their decisions. Once additional capacity is completed, however, and if because of the large size of the addition the facility is no longer congested, then price should once again fall to SMC. The resulting jagged pattern of prices offers little assurance to investors of capital cost-recovery without a government guarantee, and it may lead to schizophrenic behavior by both customers and potential suppliers. Just because the physical investment is lumpy, should the price pattern also be dichotomous or can a smoother transition be employed? By integrating the use of congestion fees that are based upon the external costs imposed by one user on all others prior to the construction of added capacity, and then by using the same congestion charge to gauge the “willingness-to-pay” for new capacity and to set an “opportunity-cost”-based benchmark for capital cost recovery afterward, a smoother sequence of prices can evolve. The capital cost recovery portion of these prices, whose magnitude is based upon the congestion eliminated, is premised on a long-run, dynamic view of markets and the transitions they can facilitate, and these cost-recovery adders can be combined with “peak-load-pricing” and the “inverse-elasticity” rule, for example, to improve efficiency and fairness over both space and time. The resulting price patterns can provide compatible incentives for all parties, and they complement several existing electricity system planning processes in those regions where congestion rents are already assessed for the use of transmission. The net effect could be similar to a sequential “real-options” analysis of efficient capacity expansion.