Economics of Energy Distribution

Economics of Energy Distribution

A conference on "Economics of Energy Distribution" took place in Cambridge on March 7-8. Research Associates James B. Bushnell of University of California at Davis, Ryan Kellogg of University of Chicago, and Erin T. Mansur of Dartmouth College organized the meeting, sponsored by the Alfred P. Sloan Foundation. These researchers' papers were presented and discussed:

Nicholas Ryan, Yale University and NBER, and Anant Sudarshan, University of Chicago

The Efficiency of Rationing: Agricultural Power Subsidies, Power Supply and Groundwater Depletion in Rajasthan

Energy subsidies are popular around the world despite being inefficient on their face. Rationing energy may increase efficiency in the second-best regime given these subsidies. Ryan and Sudarshan study the rationing of electricity for farmers in Rajasthan, India, where power is a lifeline that farmers use to pump up groundwater for irrigation. Power rationing binds on farmers, both on the intensive margin (hours of supply are limited to six per day) and on the extensive margin (many farmers are not allowed on the grid). The rationing policy and groundwater extraction costs together act as a shadow price on groundwater. The researchers use this equivalence to estimate the efficiency of the rationed power supply. Preliminary estimates suggest that efficient rationing may be even stricter than observed.

Frank A. Wolak, Stanford University and NBER

The Evidence from California on the Economic Impact of Inefficient Distribution Network Pricing (NBER Working Paper No. 25087)

Charging full requirements customers for distribution network services using the traditional cents per kilowatt hour (KWh) approach creates economic incentives for consumers to invest in distributed generation technologies, such as rooftop solar photovoltaics, despite the fact that marginal cost of grid-supplied electricity is lower. Wolak first assesses the economic efficiency properties of this approach to transmission and distribution network pricing and whether current approach distribution network pricing implies that full-requirement customers cross-subsidize distributed solar customers. Using data on quarterly residential distribution network prices from California's three largest investor-owned utilities he finds that larger amounts of distributed solar capacity and more geographically concentrated solar capacity predict higher distribution network prices and average distribution network costs. Moreover, this result continues to hold even after controlling for average distribution network costs for the utility. Using these econometric model estimates, Wolak finds that 2/3 of the increase in residential distribution network costs for each of the three utilities between 2003 and 2016 can attributed to the growth distributed solar capacity. He also investigates the legal obligation that distributed solar generation customers have to pay for sunk costs of investments in the transmission and distribution networks. Wolak closes with a description of an alternative approach to distribution network pricing that is likely to increase the economic signals for efficient electricity consumption and the incentive for cost effective installation of distributed solar generation capacity. A straightforward approach to implementing this mechanism for regions where residential customers have interval meters. Suggestions for how to implement mechanism in regions with mechanical meters is also discussed.

Bobby Harris, Justin Kirkpatrick, and Steven E. Sexton, Duke University, and Nicholas Muller, Carnegie Mellon University and NBER

Heterogeneous Environmental and Grid Benefits from Rooftop Solar and the Costs of Inefficient Siting Decisions (NBER Working Paper No. 25241)

The environmental benefits of solar electricity generating capacity vary across the U.S. according to solar irradiance, weather, conventional generation fleets, grid characteristics, and population. Though the 1.1 million distributed solar generation systems installed in the U.S are incentivized by local, state and federal programs, virtually none of these varies subsidies according to expected environmental benefits which have not previously been estimated. Sexton, Kirkpatrick, Harris, and Muller therefore, develop a systematic and theoretically consistent measure of the spatially-differentiated environmental benefits of solar capacity across the U.S. These benefits, equal to $6,200 over the lifetime of a typical 4 kilowatt capacity system, are related to the federal and state subsidies that subsidize the typical system in excess of these benefits by $5,400. Yet, in 25% of zip codes, rooftop solar is under-subsidized by as much as $6,200. The magnitude of foregone environmental benefits due to suboptimal siting of solar capacity are estimated at as much as $1.2 billion annually.

Imelda Wang, Matthias Fripp, and Michael J. Roberts, University of Hawaii

Variable Pricing and the Cost of Renewable Energy (NBER Working Paper No. 24712)

Although technological progress has lowered the cost of solar and wind to make renewable energy competitive with fossil fuels on a levelized-cost basis, supply of these resources is highly variable and inelastic, which contrasts with elastic, stable and controllable supply from traditional power plants. As a result, the cost of flat retail pricing in comparison to dynamic, marginal-cost retail pricing, long advocated by economists, will grow. At the same time, computer technology opens up new opportunities for flexible demand and energy storage, opportunities that cannot be fully exploited without dynamic retail pricing and open access to the grid. Implementing efficient dynamic-pricing systems could be institutionally costly, so it is important to evaluate the potential gains. Wang, Fripp, and Roberts develop a novel model of power supply and demand to examine how much variable pricing can reduce the cost of a 100 percent renewable power system in Hawaii. The model is novel in the way it integrates investment in generation and storage capacity with real-time operation of the system, including an account of reserves, a demand system with different interhour elasticities for different uses, and substitution between power and other goods and services. The model, an extension of Switch (Fripp 2012), is open source and fully adaptable to other settings. Earlier versions of the model (lacking demand-side integration) have been implemented for California, the Western United States, and other areas. Consistent with earlier studies, the researchers find that dynamic pricing of power provides little social benefit in fossil-fuel systems, only 2.6 to 4.6 percent of baseline annual expenditure depending on cost and interhour substitutability. But dynamic pricing leads to a much greater social benefit of 8.5 to 23.4 percent in 100 percent renewable system with otherwise similar assumptions. The other key finding is that high penetration renewable systems, including 100 percent renewable, are remarkably affordable. Indeed, the welfare maximizing (unconstrained) generation portfolio under the utility's projected 2045 costs and pessimistic interhour demand flexibility uses 79 percent renewable energy and improves welfare by 34.6 percent of baseline expenditure. With dynamic pricing, even a 100 percent renewable system is welfare improving over a fossil system, excluding gains from reduced pollution externalities. If overall demand for electricity is more elastic than the researchers' baseline (0.1), renewable energy is even cheaper and variable pricing considerably more valuable.

Catherine Hausman, University of Michigan and NBER, and Lucija Muehlenbachs, University of Calgary

Price Regulation and Environmental Externalities: Evidence from Methane Leaks (NBER Working Paper No. 22261)

Hausman and Muehlenbachs estimate expenditures by U.S. natural gas distribution firms to reduce natural gas leaks. Reducing leaks averts commodity losses (valued at around $5/Mcf), but also climate damages ($27/Mcf) because the primary component of natural gas is methane, a potent greenhouse gas. In addition to this private/social wedge, incentives to abate are weakened by this industry's status as a regulated natural monopoly: current price regulations allow many distribution firms to pass the cost of any leaked gas on to their customers. The researchers' estimates imply that too little is spent repairing leaks, they estimate expenditures substantially below $5/Mcf, i.e. less than the commodity value of the leaked gas. In contrast, expenditures on accelerated pipeline replacement are in general higher than the combination of gas costs and climate benefits (they estimate expenditures ranging from $48/Mcf to $211/Mcf). The researchers conclude by relating these findings to regulatory-induced incentives in the industry.

Severin Borenstein, University of California at Berkeley and NBER, and James B. Bushnell

Do Two Electricity Pricing Wrongs Make a Right? Cost Recovery, Externalities, and Efficiency (NBER Working Paper No. 24756)

Advocates of market mechanisms for addressing greenhouse gases and other pollutants typically argue that it is a necessary step in pricing polluting goods at their social marginal cost (SMC). Electricity prices, however, deviate from social marginal cost for many reasons, some of which cause prices to be too low-such as pollution externalities-and others cause prices to be too high-such as recovery of fixed costs. Furthermore, because electricity is not storable, marginal cost can fluctuate widely within even a day, while nearly all residential retail prices are static over weeks or months. Borenstein and Bushnell study the relationship between residential electricity prices and social marginal cost, both on average and over time. They find that while the difference between the standard residential electricity rate and the utility's average (over hours) social marginal cost is relatively small on average in the US, there is large regional variation, with price well above average SMC in some areas and price well below average SMC in other areas. Furthermore, the researchers find that for most utilities the largest source of difference between price and SMC is the failure of price to reflect variation in SMC over time. In a standard demand framework, total deadweight loss over a time period is proportional to the sum of squared differences between a constant price and SMC, which can be decomposed into the component due to price deviating from average SMC and the component due to the variation in SMC. The researchers' estimates imply that if demand elasticity were the same in response to hourly price variation as to changes in average price, then the sales-weighted average share of deadweight loss attributable to the failure to adopt time-varying pricing is 62%, with the remainder attributable to the gap between price and average SMC. These deadweight loss shares, however, vary dramatically across utilities and regions, and are sensitive to demand elasticity assumptions.