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Electricity powers the modern economy, and the electricity supply chain is notoriously complex. Power plants must develop stable relationships for fuel procurement, as their long-run profitability hinges on securing a cheap, reliable fuel supply. Electric utilities may also lack the incentive to provide a reliable power supply to all potential customers, which could hamper economic productivity. The physical properties of electricity transmission create inherent challenges in providing power to all regions of the grid, while simultaneously incentivizing economically efficient production decisions. In this dissertation, I study three potential market failures in electricity supply: (i) market power in U.S. coal transportation; (ii) under-electrification of India’s rural poor; and (iii) short-run allocative inefficiencies in Indian electricity dispatch. In each case, my findings are of substantial economic importance due the scale of the electric power industry, which is essential to virtually all economic activity. Climate change only raises the stakes, and alleviating electricity market failures has the potential to increase carbon dioxide emissions and further harm the planet.In the first chapter, I investigate how market power in the transportation of coal might impact U.S. climate policies. Economists have widely endorsed pricing CO2 emissions to internalize climate change-related externalities. Doing so would significantly affect coal, which is the most carbon-intensive major energy source. However, U.S. coal markets exhibit an additional distortion, as the railroads that transport coal to power plants can exert market power. This upstream distortion can mute the price signal of a corrective tax, due to changes in markups or incomplete tax pass-through. I provide the first empirical estimates of how coal-by-rail markups respond to changes in coal demand. I find that rail carriers reduce coal markups when downstream power plant demand changes, due to a decrease i

Electricity powers the modern economy, and the electricity supply chain is notoriously complex. Power plants must develop stable relationships for fuel procurement, as their long-run profitability hinges on securing a cheap, reliable fuel supply. Electric utilities may also lack the incentive to provide a reliable power supply to all potential customers, which could hamper economic productivity. The physical properties of electricity transmission create inherent challenges in providing power to all regions of the grid, while simultaneously incentivizing economically efficient production decisions. In this dissertation, I study three potential market failures in electricity supply: (i) market power in U.S. coal transportation; (ii) under-electrification of India’s rural poor; and (iii) short-run allocative inefficiencies in Indian electricity dispatch. In each case, my findings are of substantial economic importance due the scale of the electric power industry, which is essential to virtually all economic activity. Climate change only raises the stakes, and alleviating electricity market failures has the potential to increase carbon dioxide emissions and further harm the planet.In the first chapter, I investigate how market power in the transportation of coal might impact U.S. climate policies. Economists have widely endorsed pricing CO2 emissions to internalize climate change-related externalities. Doing so would significantly affect coal, which is the most carbon-intensive major energy source. However, U.S. coal markets exhibit an additional distortion, as the railroads that transport coal to power plants can exert market power. This upstream distortion can mute the price signal of a corrective tax, due to changes in markups or incomplete tax pass-through. I provide the first empirical estimates of how coal-by-rail markups respond to changes in coal demand. I find that rail carriers reduce coal markups when downstream power plant demand changes, due to a decrease i

We study dispersion in the prices an airline charges to different passengers on the same route. This variation in fares is substantial: the expected absolute difference in fares between two passengers on a route is 36 percent of the airline's average ticket price. The pattern of observed price dispersion cannot easily be explained by cost differences alone. Dispersion increases on routes with more competition or lower flight density, consistent with discrimination based on customers' willingness to switch to alternative airlines or flights. We argue that the data support models of price discrimination in monopolistically competitive markets.

California is faced with an unprecedented budget crisis. The state is also committed to significant reductions in greenhouse gases that cause climate change. Meanwhile, the price of gasoline is plunging as the world economic slowdown cuts oil demand. At the intersection of these three situations lies an opportunity. In this policy paper, I analyze the effects of a transportation fuel surcharge that moves inversely to the price of oil. Such a surcharge could stabilize gasoline prices at levels that a few months ago would have been celebrated by consumers and still significantly reduce California’s budget deficit. It would also slow the return of gas-guzzling vehicles that will otherwise result if oil prices remain at current levels.

Dramatic increases in the price of crude oil during the last half of 2007 have ratcheted up attention on energy policy, but cost is only one of the three oil challenges that confront the U.S. This short essay discusses the recent increases in oil prices and attempts to clarify how the challenge from high oil costs interacts with, but is distinct from, the geopolitical and climate change challenges that oil use also creates. Central to addressing these challenges successfully is recognizing that policy responses need to be evaluated in the context of the worldwide oil market.

The high cost of power from solar photovoltaic (PV) panels has been a major deterrent to the technology’s market penetration. Proponents have argued, however, that typical analyses overlook many of the benefits of solar PV. Some of those benefits are in the realm of environmental and security externalities, but others occur within the electricity markets. In this paper, I attempt to do a more complete market valuation of solar PV. I incorporate the fact that power from solar PV panels is generated disproportionately at times when electricity is most valuable due to high demand and increased line losses. I find that the degree to which the timing of solar PV production enhances its value depends very much on the extent to which wholesale prices peak with demand, which in turn depends on the proportion of reserve capacity held in the system. In a typical US system with substantial excess capacity, I find that the favorable timing of solar PV production increases its value by 0%-20%, but if the system were run with more reliance on price-responsive demand and peaking prices, the premium value of solar PV would be in the 30%-50% range. Solar PV is also argued to have enhanced value within an electrical grid, because the power is produced at the location of the end-user and therefore can reduce the costs of transmission and distribution investments. My analysis, however, suggests that actual installation of solar PV systems in California has not significantly reduced the cost of transmission and distribution infrastructure, and is unlikely to do so in other regions. I then bring together these adjustments to the valuation of solar PV power with calculations of its cost to analyze the market value of solar PV. The market benefits of installing the current solar PV technology, even after adjusting for its timing and transmission advantages, are calculated to be much smaller than the costs. The difference is so large that including current plausible estimates of the value o

Utility regulators frequently attempt to use tariff structures to pursue both distributional and efficiency goals. Efficiency necessitates setting prices as close to marginal costs as possible while still allowing the firm to cover its costs. The common distributional goal is to protect low-income customers from high prices. Perhaps nowhere is the conflict between these goals greater than in the use of increasing-block residential utility pricing, in which the marginal price to the customer increases as the customer’s usage rises. Since the 2000-01 California electricity crisis, the state has adopted some of the most steeply increasing-block tariffs in electric utility history, but the distributional and efficiency effects have not been analyzed in detail. Using a novel approach for matching customer bill data with census data on area income distributions, I derive estimates of the income redistribution effected by the increasing-block tariffs used by California regulated electric utilities. I find that the rate structure does redistribute income to lower-income groups, but that the effect is fairly modest, particularly compared to a means-tested program also in use. While the distributional impact of these tariffs do not seem to be large, the efficiency costs may not be great either. Examining the distribution of customer demand quantities, I find preliminary evidence that customers do not respond to the increasing marginal prices they face.

Utility regulators frequently attempt to use tariff structures to pursue both distributional and efficiency goals. Efficiency necessitates setting prices as close to marginal costs as possible while still allowing the firm to cover its costs. The common distributional goal is to protect low-income customers from high prices. Perhaps nowhere is the conflict between these goals greater than in the use of increasing-block residential utility pricing, in which the marginal price to the customer increases as the customer’s usage rises. Since the 2000-01 California electricity crisis, the state has adopted some of the most steeply increasing-block tariffs in electric utility history, but the distributional and efficiency effects have not been analyzed in detail. Using a novel approach for matching customer bill data with census data on area income distributions, I derive estimates of the income redistribution effected by the increasing-block tariffs used by California regulated electric utilities. I find that the rate structure does redistribute income to lower-income groups, but that the effect is fairly modest, particularly compared to a means-tested program also in use. While the distributional impact of these tariffs do not seem to be large, the efficiency costs may not be great either. Examining the distribution of customer demand quantities, I find preliminary evidence that customers do not respond to the increasing marginal prices they face.

Dramatic increases in the price of crude oil during the last half of 2007 have ratcheted up attention on energy policy, but cost is only one of the three oil challenges that confront the U.S. This short essay discusses the recent increases in oil prices and attempts to clarify how the challenge from high oil costs interacts with, but is distinct from, the geopolitical and climate change challenges that oil use also creates. Central to addressing these challenges successfully is recognizing that policy responses need to be evaluated in the context of the worldwide oil market.

California is faced with an unprecedented budget crisis. The state is also committed to significant reductions in greenhouse gases that cause climate change. Meanwhile, the price of gasoline is plunging as the world economic slowdown cuts oil demand. At the intersection of these three situations lies an opportunity. In this policy paper, I analyze the effects of a transportation fuel surcharge that moves inversely to the price of oil. Such a surcharge could stabilize gasoline prices at levels that a few months ago would have been celebrated by consumers and still significantly reduce California’s budget deficit. It would also slow the return of gas-guzzling vehicles that will otherwise result if oil prices remain at current levels.

The high cost of power from solar photovoltaic (PV) panels has been a major deterrent to the technology's market penetration. Proponents have argued, however, that typical analyses overlook many of the benefits of solar PV. Some of those benefits are in the realm of environmental and security externalities, but others occur within the electricity markets. In this paper, I attempt to do a more complete market valuation of solar PV. I incorporate the fact that power from solar PV panels is generated disproportionately at times when electricity is most valuable due to high demand and increased line losses. I find that the degree to which the timing of solar PV production enhances its value depends very much on the extent to which wholesale prices peak with demand, which in turn depends on the proportion of reserve capacity held in the system. In a typical US system with substantial excess capacity, I find that the favorable timing of solar PV production increases its value by 0%-20%, but if the system were run with more reliance on price-responsive demand and peaking prices, the premium value of solar PV would be in the 30%-50% range. Solar PV is also argued to have enhanced value within an electrical grid, because the power is produced at the location of the end-user and therefore can reduce the costs of transmission and distribution investments. My analysis, however, suggests that actual installation of solar PV systems in California has not significantly reduced the cost of transmission and distribution infrastructure, and is unlikely to do so in other regions. I then bring together these adjustments to the valuation of solar PV power with calculations of its cost to analyze the market value of solar PV. The market benefits of installing the current solar PV technology, even after adjusting for its timing and transmission advantages, are calculated to be much smaller than the costs. The difference is so large that including current plausible estimates of the value o

In May 2007, a Los Angeles Times newspaper article reported that the California Solar Initiative (CSI), commonly called the "million solar roofs" program, was being hobbled by a requirement that recipients of the solar PV subsidies go on time-of-use (TOU) rates. TOU rates charge higher prices for electricity at peak demand times (primarily weekday summer afternoons in California) and lower prices at off-peak times than the more common flat-rate tariff, which imposes the same price for a kilowatt-hour (kWh) of electricity at all times. The LA Times story reported that orders for solar installations had dropped 78% since January 1, 2007 when the TOU-mandate went into effect for solar-rebate recipients. By June, California regulators had eliminated the TOU mandate. I examine data from a sample of 274 medium- to high-use residential customers of Pacific Gas & Electric (PG&E) and Southern California Edison (SCE) to see if the TOU mandate makes the solar rebate program less attractive financially. Among PG&E customers, I find that the vast majority would be better off on TOU than on a flat rate tariff. For SCE customers, however, the effect of a switch to TOU is complicated by the fact that SCE's flat rates are tiered (ie, increasing marginal electricity price with greater total level of monthly consumption), but its TOU rates are not. Thus, even though solar PV production is greatest during TOU peak periods, many customers' value from the system is maximized on a flat-rate tariff. I then examine the overall economics of installing a solar PV system for these customers. The financial return to solar PV depends very much on how retail rates will change over the 20-30 year life of the panels, a very difficult path to predict. If inflation-adjusted rates were to remain at current levels, however, I find that a solar PV installation might generate a positive financial return for up to half of PG&E's medium- and high-consumption residential customers, but not f

One of the most critical concerns that customers have voiced in the debate over real-time retail electricity pricing is that they would be exposed to risk from fluctuations in their electricity cost. The concern seems to be that a customer could find itself consuming a large quantity of power on the day that prices skyrocket and thus receive a monthly bill far larger than it had budgeted for. I analyze the magnitude of this risk, using demand data from 1142 large industrial customers, and then ask how much of this risk can be eliminated through various straightforward financial instruments. I find that very simple hedging strategies can eliminate more than 80% of the bill volatility that would otherwise occur. Far from being complex, mystifying financial instruments that only a Wall Street analyst could love, these are simple forward power purchase contracts, and are already offered to retail customers by a number of fully-regulated utilities that operate real-time pricing programs. I then show that a slightly more sophisticated application of these forward power purchases can significantly enhance their effect on reducing bill volatility.

Regulators and firms often use incentive schemes to attract skillful agents and to induce them to put forth effort in pursuit of the principals’ goals. Incentive schemes that reward skill and effort, however, may also punish agents for adverse outcomes beyond their control. As a result, such schemes may induce inefficient behavior, as agents try to avoid actions that might make it easier to directly associate a bad outcome with their decisions. In this paper, we study how such caution on the part of individual agents may lead to inefficient market outcomes, focusing on the context of natural gas procurement by regulated public utilities. We posit that a regulated natural gas distribution company may, due to regulatory incentives, engage in excessively cautious behavior by foregoing surplus-increasing gas trades that could be seen ex post as having caused supply curtailments to its customers. We derive testable implications of such behavior and show that the theory is supported empirically in ways that cannot be explained by conventional price risk aversion or other explanations. Furthermore, we demonstrate that the reduction in efficient trade caused by the regulatory mechanism is most severe during periods of relatively high demand and low supply, when the benefits of trade would be greatest.

Adoption of real-time electricity pricing — retail prices that vary hourly to reflect changing wholesale prices — removes existing cross-subsidies to those customers that consume disproportionately more when wholesale prices are highest. If their losses are substantial, these customers are likely to oppose RTP initiatives unless there is a supplemental program to offset their loss. Using data on a sample of 1142 large industrial and commercial customers in northern California, I show that RTP adoption would result in significant transfers compared to a flat-rate tariff. When compared to the time-of-use rates (simple peak/offpeak tariffs) that these customers already face, however, the transfers drop by 29%; even under the more extreme price volatility scenario that I examine, 90% of customers would see changes of between a 4% bill reduction and an 8% bill increase. Though customer price responsiveness reduces the loss incurred by those with high-cost demand profiles, I also demonstrate that this offsetting effect is unlikely to be large enough for most customers with costly demand patterns to completely offset their lost cross-subsidy. The analysis suggests that adoption of real-time pricing may be difficult without a supplemental program that compensates the customers who are made worse off by the change. I examine possible “two-part RTP” programs, which allow customers to purchase a baseline quantity at regulated TOU rates, and show they can be used to greatly reduce the transfers associated with adoption of RTP.

Regulators and firms often use incentive schemes to attract skillful agents and to induce them to put forth effort in pursuit of the principals’ goals. Incentive schemes that reward skill and effort, however, may also punish agents for adverse outcomes beyond their control. As a result, such schemes may induce inefficient behavior, as agents try to avoid actions that might make it easier to directly associate a bad outcome with their decisions. In this paper, we study how such caution on the part of individual agents may lead to inefficient market outcomes, focusing on the context of natural gas procurement by regulated public utilities. We posit that a regulated natural gas distribution company may, due to regulatory incentives, engage in excessively cautious behavior by foregoing surplus increasing gas trades that could be seen ex post as having caused supply curtailments to its customers. We derive testable implications of such behavior and show that the theory is supported empirically in ways that cannot be explained by conventional price risk aversion or other explanations. Furthermore, we demonstrate that the reduction in efficient trade caused by the regulatory mechanism is most severe during periods of relatively high demand and low supply, when the benefits of trade would be greatest.

Regulators and firms often use incentive schemes to attract skillful agents and to induce them to put forth effort in pursuit of the principals’ goals. Incentive schemes that reward skill and effort, however, may also punish agents for adverse outcomes beyond their control. As a result, such schemes may induce inefficient behavior, as agents try to avoid actions that might make it easier to directly associate a bad outcome with their decisions. In this paper, we study how such caution on the part of individual agents may lead to inefficient market outcomes, focusing on the context of natural gas procurement by regulated public utilities. We posit that a regulated natural gas distribution company may, due to regulatory incentives, engage in excessively cautious behavior by foregoing surplus-increasing gas trades that could be seen ex post as having caused supply curtailments to its customers. We derive testable implications of such behavior and show that the theory is supported empirically in ways that cannot be explained by conventional price risk aversion or other explanations. Furthermore, we demonstrate that the reduction in efficient trade caused by the regulatory mechanism is most severe during periods of relatively high demand and low supply, when the benefits of trade would be greatest.

In May 2007, a Los Angeles Times newspaper article reported that the California Solar Initiative (CSI), commonly called the "million solar roofs" program, was being hobbled by a requirement that recipients of the solar PV subsidies go on time-of-use (TOU) rates. TOU rates charge higher prices for electricity at peak demand times (primarily weekday summer afternoons in California) and lower prices at off-peak times than the more common flat-rate tariff, which imposes the same price for a kilowatt-hour (kWh) of electricity at all times. The LA Times story reported that orders for solar installations had dropped 78% since January 1, 2007 when the TOU-mandate went into effect for solar-rebate recipients. By June, California regulators had eliminated the TOU mandate. I examine data from a sample of 274 medium- to high-use residential customers of Pacific Gas & Electric (PG&E) and Southern California Edison (SCE) to see if the TOU mandate makes the solar rebate program less attractive financially. Among PG&E customers, I find that the vast majority would be better off on TOU than on a flat rate tariff. For SCE customers, however, the effect of a switch to TOU is complicated by the fact that SCE's flat rates are tiered (ie, increasing marginal electricity price with greater total level of monthly consumption), but its TOU rates are not. Thus, even though solar PV production is greatest during TOU peak periods, many customers' value from the system is maximized on a flat-rate tariff. I then examine the overall economics of installing a solar PV system for these customers. The financial return to solar PV depends very much on how retail rates will change over the 20-30 year life of the panels, a very difficult path to predict. If inflation-adjusted rates were to remain at current levels, however, I find that a solar PV installation might generate a positive financial return for up to half of PG&E's medium- and high-consumption residential customers, but not f

Adoption of real-time electricity pricing — retail prices that vary hourly to reflect changing wholesale prices — removes existing cross-subsidies to those customers that consume disproportionately more when wholesale prices are highest. If their losses are substantial, these customers are likely to oppose RTP initiatives unless there is a supplemental program to offset their loss. Using data on a sample of 1142 large industrial and commercial customers in northern California, I show that RTP adoption would result in significant transfers compared to a flat-rate tariff. When compared to the time-of-use rates (simple peak/offpeak tariffs) that these customers already face, however, the transfers drop by 29%; even under the more extreme price volatility scenario that I examine, 90% of customers would see changes of between a 4% bill reduction and an 8% bill increase. Though customer price responsiveness reduces the loss incurred by those with high-cost demand profiles, I also demonstrate that this offsetting effect is unlikely to be large enough for most customers with costly demand patterns to completely offset their lost cross-subsidy. The analysis suggests that adoption of real-time pricing may be difficult without a supplemental program that compensates the customers who are made worse off by the change. I examine possible “two-part RTP” programs, which allow customers to purchase a baseline quantity at regulated TOU rates, and show they can be used to greatly reduce the transfers associated with adoption of RTP.

One of the most critical concerns that customers have voiced in the debate over real-time retail electricity pricing is that they would be exposed to risk from fluctuations in their electricity cost. The concern seems to be that a customer could find itself consuming a large quantity of power on the day that prices skyrocket and thus receive a monthly bill far larger than it had budgeted for. I analyze the magnitude of this risk, using demand data from 1142 large industrial customers, and then ask how much of this risk can be eliminated through various straightforward financial instruments. I find that very simple hedging strategies can eliminate more than 80% of the bill volatility that would otherwise occur. Far from being complex, mystifying financial instruments that only a Wall Street analyst could love, these are simple forward power purchase contracts, and are already offered to retail customers by a number of fully-regulated utilities that operate real-time pricing programs. I then show that a slightly more sophisticated application of these forward power purchases can significantly enhance their effect on reducing bill volatility.

Regulators and firms often use incentive schemes to attract skillful agents and to induce them to put forth effort in pursuit of the principals’ goals. Incentive schemes that reward skill and effort, however, may also punish agents for adverse outcomes beyond their control. As a result, such schemes may induce inefficient behavior, as agents try to avoid actions that might make it easier to directly associate a bad outcome with their decisions. In this paper, we study how such caution on the part of individual agents may lead to inefficient market outcomes, focusing on the context of natural gas procurement by regulated public utilities. We posit that a regulated natural gas distribution company may, due to regulatory incentives, engage in excessively cautious behavior by foregoing surplus increasing gas trades that could be seen ex post as having caused supply curtailments to its customers. We derive testable implications of such behavior and show that the theory is supported empirically in ways that cannot be explained by conventional price risk aversion or other explanations. Furthermore, we demonstrate that the reduction in efficient trade caused by the regulatory mechanism is most severe during periods of relatively high demand and low supply, when the benefits of trade would be greatest.

As with other commodities, electricity is often traded on both forward and spot markets. This was initially true in the restructured California electricity industry from 1998 to 2000. Though the power traded in the forward and spot markets was for delivery at the same times and locations, prices often differed in significant and predictable ways. We consider several explanations for this apparent inefficiency, concluding that uncertainty about regulatory penalties for trading in the spot market caused most firms to avoid trading on inter-market price differences. The few firms that did carry out these trades did not find it profit-maximizing to eliminate the price differences. Skyrocketing prices in the summer of 2000, however, changed the major buyers’ (utilities’) incentives and increased the price differentials between the markets.

JEL CODES: D21, G3, L2, L72KEYWORDS: profit function, free cash flow, gold mining, x-efficiency, rent seeking, fatABSTRACT: Conventional economic theory assumes that firms always minimize costs given the output they produce. News articles and interviews with executives, however, indicate that firms from time to time engage in cost-cutting exercises. One popular belief is that firms cut costs when they are in economic distress, and grow fat when they are relatively wealthy. We explore this hypothesis by studying how the stock market valuations of gold mining companies vary with gold prices. The value of a cost-minimizing, profit-maximizing firm is convex in the price of a competitively supplied input or output, but we find that the stock values of many gold mining companies are concave in the price of gold. We show that this is consistent with fat accumulation when a firm grows wealthy. We then address a number of potential alternative explanations and discuss where fat in these companies might reside.

As with other commodities, electricity is often traded on both forward and spot markets. This was initially true in the restructured California electricity industry from 1998 to 2000. Though the power traded in the forward and spot markets was for delivery at the same times and locations, prices often differed in significant and predictable ways. We consider several explanations for this apparent inefficiency, concluding that uncertainty about regulatory penalties for trading in the spot market caused most firms to avoid trading on inter-market price differences. The few firms that did carry out these trades did not find it profit-maximizing to eliminate the price differences. Skyrocketing prices in the summer of 2000, however, changed the major buyers’ (utilities’) incentives and increased the price differentials between the markets.

JEL CODES: D21, G3, L2, L72KEYWORDS: profit function, free cash flow, gold mining, x-efficiency, rent seeking, fatABSTRACT: Conventional economic theory assumes that firms always minimize costs given the output they produce. News articles and interviews with executives, however, indicate that firms from time to time engage in cost-cutting exercises. One popular belief is that firms cut costs when they are in economic distress, and grow fat when they are relatively wealthy. We explore this hypothesis by studying how the stock market valuations of gold mining companies vary with gold prices. The value of a cost-minimizing, profit-maximizing firm is convex in the price of a competitively supplied input or output, but we find that the stock values of many gold mining companies are concave in the price of gold. We show that this is consistent with fat accumulation when a firm grows wealthy. We then address a number of potential alternative explanations and discuss where fat in these companies might reside.

Adoption of real-time electricity pricing -- retail prices that vary hourly to reflect changing wholesale prices -- removes existing cross-subsidies to those customers that consume disproportionately more when wholesale prices are highest. If their losses are substantial, these customers are likely to oppose RTP initiatives unless there is a supplemental program to offset their loss. Using data on a random sample of 636 industrial and commercial customers in southern California, I show that RTP adoption would result in significant transfers compared to a flat-rate tariff. When compared to the time-of-use rates (simple peak/offpeak tariffs) that these customers already face, however, the transfers drop by nearly half; even under the more extreme price volatility scenario that I examine, 90% of customers would see changes of between a 9% bill reduction and a 14% bill increase. Though customer price responsiveness reduces the loss incurred by those with high-cost demand profiles, I also demonstrate that this offsetting effect is unlikely to be large enough for most customers with costly demand patterns to completely offset their lost cross-subsidy. The analysis suggests that adoption of real-time pricing may be difficult without a supplemental program that compensates the customers who are made worse off by the change. I discuss how "two-part RTP" programs, which allow customers to purchase a baseline quantity at regulated TOU rates, can reduce the transfers associated with adoption of RTP.

We explore issues relating to the vertical structure of ownership and control in gasoline distribution and retailing. Some have argued that refiner control of the retail sector has increased California gasoline prices, prompting proposals for legislation to restrict refiner participation in gasoline retailing. We study the arguments for and against government intervention in gasoline distribution and retailing, and describe the conditions under which such intervention could be justified. In theory, vertical controls in the gasoline industry can produce both positive and negative effects. Many vertical controls can increase efficiency, both operations and in the transactions between refiners and retail outlet. Some controls, however, could also influence the structure or incentives of refiners in a way that increases their market power (reduces competition) and could therefore prove costly to consumers. In general, the positive aspects of vertical controls impact the pricing and operations of retail outlets, and are passed through to consumers in the form of lower retail mark-ups over wholesale prices. The negative consequences primarily impact wholesale prices through the influence of vertical structure on the incentives of refiners to reduce competition at the wholesale level. We conclude that in order to make a case that public intervention could be justified as a basis for reducing consumer prices, one must establish both that intervention could indirectly reduce the wholesale margins of refiners and that these wholesale benefits are not offset by increased costs and market power at the retail level.

Solar PV panels generate electricity only during daylight hours and generate more electricity when the sun is shining more intensely. As a result, in summer-peaking electricity systems, such as California and most of the U.S., power from PVs is produced disproportionately at times when the value of electricity is high. Thus, a valuation of solar PV electricity production that uses only the average wholesale cost of electricity will tend to undervalue the power. Yet, that is what happens by default in many installations because solar PVs are generally located at the end-user's premises and those end-users are often billed on a flat per kilowatt-hour rate that does not reflect time-varying valuation. As a result, the benefits to many owners of solar PV in reduced electricity bills do not reflect the true time-varying valuation of the power the panels produce. I use solar PV production information in conjunction with wholesale price data and simulations to estimate the actual wholesale value of power from solar PVs and the degree of bias that occurs from using a constant price to value electricity generated by solar PVs. I find that in the California locations I analyze, the most credible long-run valuation of solar PV power is 29%-48% greater than results from valuation at a flat-rate tariff, depending on the location of the PV panels. If the end user is billed on a time-of-use tariff (a simple peak/off-peak price system), however, I find that the misvaluation of wholesale power from solar PVs is approximately zero.

Between 1995 and 2004, I find that airline prices fell more than 20% adjusted for inflation. I also show that premia at hub airports declined and that there is now substantially less disparity between the cheaper and more expensive airports than there was a decade ago. Still, I find that prices remain quite high at a few dominated airports.

Retail real-time pricing (RTP) of electricity -- retail pricing that changes hourly to reflect the changing supply/demand balance -- is very appealing to economists because it "sends the right price signals." Economic efficiency gains from RTP, however, are often confused with the short-term wealth transfers from producers to consumers that RTP can create. Abstracting from transfers, I focus on the long-run efficiency gains from adopting RTP in a competitive electricity market. Using simple simulations with realistic parameters, I demonstrate that the magnitude of efficiency gains from RTP is likely to be significant even if demand shows very little elasticity. I also show that "time-of-use" pricing, a simple peak and off-peak pricing system, is likely to capture a very small share of the efficiency gains that RTP offers.

Adoption of real-time electricity pricing -- retail prices that vary hourly to reflect changing wholesale prices -- removes existing cross-subsidies to those customers that consume disproportionately more when wholesale prices are highest. If their losses are substantial, these customers are likely to oppose RTP initiatives unless there is a supplemental program to offset their loss. Using data on a random sample of 636 industrial and commercial customers in southern California, I show that RTP adoption would result in significant transfers compared to a flat-rate tariff. When compared to the time-of-use rates (simple peak/offpeak tariffs) that these customers already face, however, the transfers drop by nearly half; even under the more extreme price volatility scenario that I examine, 90% of customers would see changes of between a 9% bill reduction and a 14% bill increase. Though customer price responsiveness reduces the loss incurred by those with high-cost demand profiles, I also demonstrate that this offsetting effect is unlikely to be large enough for most customers with costly demand patterns to completely offset their lost cross-subsidy. The analysis suggests that adoption of real-time pricing may be difficult without a supplemental program that compensates the customers who are made worse off by the change. I discuss how "two-part RTP" programs, which allow customers to purchase a baseline quantity at regulated TOU rates, can reduce the transfers associated with adoption of RTP.

We explore issues relating to the vertical structure of ownership and control in gasoline distribution and retailing. Some have argued that refiner control of the retail sector has increased California gasoline prices, prompting proposals for legislation to restrict refiner participation in gasoline retailing. We study the arguments for and against government intervention in gasoline distribution and retailing, and describe the conditions under which such intervention could be justified. In theory, vertical controls in the gasoline industry can produce both positive and negative effects. Many vertical controls can increase efficiency, both operations and in the transactions between refiners and retail outlet. Some controls, however, could also influence the structure or incentives of refiners in a way that increases their market power (reduces competition) and could therefore prove costly to consumers. In general, the positive aspects of vertical controls impact the pricing and operations of retail outlets, and are passed through to consumers in the form of lower retail mark-ups over wholesale prices. The negative consequences primarily impact wholesale prices through the influence of vertical structure on the incentives of refiners to reduce competition at the wholesale level. We conclude that in order to make a case that public intervention could be justified as a basis for reducing consumer prices, one must establish both that intervention could indirectly reduce the wholesale margins of refiners and that these wholesale benefits are not offset by increased costs and market power at the retail level.

Solar PV panels generate electricity only during daylight hours and generate more electricity when the sun is shining more intensely. As a result, in summer-peaking electricity systems, such as California and most of the U.S., power from PVs is produced disproportionately at times when the value of electricity is high. Thus, a valuation of solar PV electricity production that uses only the average wholesale cost of electricity will tend to undervalue the power. Yet, that is what happens by default in many installations because solar PVs are generally located at the end-user's premises and those end-users are often billed on a flat per kilowatt-hour rate that does not reflect time-varying valuation. As a result, the benefits to many owners of solar PV in reduced electricity bills do not reflect the true time-varying valuation of the power the panels produce. I use solar PV production information in conjunction with wholesale price data and simulations to estimate the actual wholesale value of power from solar PVs and the degree of bias that occurs from using a constant price to value electricity generated by solar PVs. I find that in the California locations I analyze, the most credible long-run valuation of solar PV power is 29%-48% greater than results from valuation at a flat-rate tariff, depending on the location of the PV panels. If the end user is billed on a time-of-use tariff (a simple peak/off-peak price system), however, I find that the misvaluation of wholesale power from solar PVs is approximately zero.

Between 1995 and 2004, I find that airline prices fell more than 20% adjusted for inflation. I also show that premia at hub airports declined and that there is now substantially less disparity between the cheaper and more expensive airports than there was a decade ago. Still, I find that prices remain quite high at a few dominated airports.

Retail real-time pricing (RTP) of electricity -- retail pricing that changes hourly to reflect the changing supply/demand balance -- is very appealing to economists because it "sends the right price signals." Economic efficiency gains from RTP, however, are often confused with the short-term wealth transfers from producers to consumers that RTP can create. Abstracting from transfers, I focus on the long-run efficiency gains from adopting RTP in a competitive electricity market. Using simple simulations with realistic parameters, I demonstrate that the magnitude of efficiency gains from RTP is likely to be significant even if demand shows very little elasticity. I also show that "time-of-use" pricing, a simple peak and off-peak pricing system, is likely to capture a very small share of the efficiency gains that RTP offers.

In recent months, prices for California's special (CaRFG) gasoline have again exceeded U.S. average prices by much more than the difference in production costs. A number of observers have attributed the widening average differential to increasing scarcity of refinery capacity among plants that are equipped to manufacture CaRFG gasoline. While these arguments have generally been sound, the dismissals of market power concerns have not been well supported. We study the potential for firms in the CaRFG wholesale gasoline industry to exercise market power, examining the refining, importation and storage of the fuel. We don't dispute arguments that the elevated prices are consistent with competitive markets, but we illustrate that the data are also consistent with some firms exercising market power. We then discuss methods for, and difficulties in, distinguishing between competitive pricing and market power.

In the three years following the restructuring of the California electricity industry, 1998 to 2000, power trading occurred in both a day-ahead market and a real-time market. Despite the fact that the power traded in these two major markets was for delivery at the same times and locations, prices differed significantly in many months. We consider several explanations for persistent price differences between the markets. We conclude that uncertainty about regulatory penalties for trading in the real-time market caused most firms to eschew arbitrage between the two markets. The few firms that did carry out this (risky) arbitrage did not find it profit-maximizing to eliminate the price differences. Due to California’s electricity restructuring plan, the investor-owned utilities, which were the primary buyers of electricity, had little incentive to respond to the price differences. In the summer of 2000, however, when prices in both markets skyrocketed, we argue that the utilities’ incentives changed in a way that was consistent with one utility’s subsequent attempts to move demand between markets to minimize their purchase costs.

In recent months, prices for California's special (CaRFG) gasoline have again exceeded U.S. average prices by much more than the difference in production costs. A number of observers have attributed the widening average differential to increasing scarcity of refinery capacity among plants that are equipped to manufacture CaRFG gasoline. While these arguments have generally been sound, the dismissals of market power concerns have not been well supported. We study the potential for firms in the CaRFG wholesale gasoline industry to exercise market power, examining the refining, importation and storage of the fuel. We don't dispute arguments that the elevated prices are consistent with competitive markets, but we illustrate that the data are also consistent with some firms exercising market power. We then discuss methods for, and difficulties in, distinguishing between competitive pricing and market power.

In the three years following the restructuring of the California electricity industry, 1998 to 2000, power trading occurred in both a day-ahead market and a real-time market. Despite the fact that the power traded in these two major markets was for delivery at the same times and locations, prices differed significantly in many months. We consider several explanations for persistent price differences between the markets. We conclude that uncertainty about regulatory penalties for trading in the real-time market caused most firms to eschew arbitrage between the two markets. The few firms that did carry out this (risky) arbitrage did not find it profit-maximizing to eliminate the price differences. Due to California’s electricity restructuring plan, the investor-owned utilities, which were the primary buyers of electricity, had little incentive to respond to the price differences. In the summer of 2000, however, when prices in both markets skyrocketed, we argue that the utilities’ incentives changed in a way that was consistent with one utility’s subsequent attempts to move demand between markets to minimize their purchase costs.

The standard economic model of efficient competitive markets relies on the ability of sellers to charge prices that vary as their costs change. Yet, there is no restructured electricity market in which most retail customers can be charged realtime prices (RTP), prices that can change as frequently as wholesale costs. We analyze the impact of having some share of customers on time-invariant pricing in competitive electricity markets. Not only does time-invariant pricing in competitive markets lead to outcomes (prices and investment) that are not first-best, it even fails to achieve the second-best optimum given the constraint of time-invariant pricing. We then show that attempts to correct the level of investment through taxes or subsidies on electricity or capacity are unlikely to succeed, because these interventions create new inefficiencies. In contrast, increasing the share of customers on RTP is likely to improve efficiency, though surprisingly, it does not necessarily reduce capacity investment, and it is likely to harm customers that are already on RTP.

The standard economic model of efficient competitive markets relies on the ability of sellers to charge prices that vary as their costs change. Yet, there is no restructured electricity market in which most retail customers can be charged realtime prices (RTP), prices that can change as frequently as wholesale costs. We analyze the impact of having some share of customers on time-invariant pricing in competitive electricity markets. Not only does time-invariant pricing in competitive markets lead to outcomes (prices and investment) that are not first-best, it even fails to achieve the second-best optimum given the constraint of time-invariant pricing. We then show that attempts to correct the level of investment through taxes or subsidies on electricity or capacity are unlikely to succeed, because these interventions create new inefficiencies. In contrast, increasing the share of customers on RTP is likely to improve efficiency, though surprisingly, it does not necessarily reduce capacity investment, and it is likely to harm customers that are already on RTP.

Working Paper CSEM-105

We present a method for decomposing wholesale electricity payments into production costs, inframarginal competitive rents, and payments resulting from the exercise of market power. The method also parses actual variable costs into the minimum variable costs necessary to meet demand and increased production costs caused by market power and other market inefficiencies. Using data from June 1998 to October 2000 in California, we find significant departures from competitive pricing, particularly during the high-demand summer months. Electricity expenditures in the state's restructured wholesale market rose from $2.04 billion in summer 1999 to $8.98 billion in summer 2000. We find that 21% of this increase was due to increased production costs, 20% was due to increased competitive rents, and the remaining 59% was attributable to increased market power.

In this monograph, we present an overview and analysis of the possible approaches to bringing an active demand side into electricity markets. In section I, we describe the ways in which economic incentives can be introduced on the demand side. We discuss the fundamental economics of establishing these incentives and the economic loss from systems that lack demand-side participation, and we analyze the effect of these incentives on the efficiency and competitiveness of the market. In section II, we move from the fundamentals to specific issues of implementing time-varying prices. We begin by describing illustrative Realtime Pricing and Critical Peak Pricing tariffs that are in use today. We then address the actual development of dynamic retail prices. In section III, we examine the ways in which customers respond to time-varying and dynamic prices. We discuss both the potential responses that are envisioned by those who study optimization of power use and the actual responses that have taken place in pilot and long-term programs. We conclude in section IV by advocating much wider use of dynamic retail pricing, under which prices faced by end-use customers can be adjusted frequently and on short notice to reflect changes in wholesale prices and the supply/demand balance.

The standard economic model of efficient competitive markets relies on the ability of sellers to charge prices that vary as their costs change. Yet, there is no restructured electricity market in which most retail customers can be charged realtime prices (RTP), prices that can change as frequently as wholesale costs. We analyze the impact of having some share of customers on time-invariant pricing in competitive electricity markets. Not only does time-invariant pricing in competitive markets lead to outcomes (prices and investment) that are not first-best, it even fails to achieve the second-best optimum given the constraint of time-invaraint pricing. We then study a number of policy interventions that have been proposed to address the perceived inadequacy of capacity investment. We show that attempts to correct the level of investment through taxes or subsidies on electricity or capacity are unlikely to succeed, because these interventions create new inefficiencies. We demonstrate that the most common proposal, a subsidy to capacity ownership financed by a tax on retail electricity, is particularly problematic. In contrast, an increase in the share of customers on RTP improves efficiency, though it does not necessarily reduce capacity investment. We demonstrate that the analysis is robust to inclusion of a simple form of reserve capacity.

We present a method for decomposing wholesale electricity payments into production costs, inframarginal competitive rents, and payments resulting from the exercise of market power. The method also parses actual variable costs into the minimum variable costs necessary to meet demand and increased production costs caused by market power and other market inefficiencies. Using data from June 1998 to October 2000 in California, we find significant departures from competitive pricing, particularly during the high-demand summer months. Electricity expenditures in the state's restructured wholesale market rose from $2.04 billion in summer 1999 to $8.98 billion in summer 2000. We find that 21% of this increase was due to increased production costs, 20% was due to increased competitive rents, and the remaining 59% was attributable to increased market power.

In this monograph, we present an overview and analysis of the possible approaches to bringing an active demand side into electricity markets. In section I, we describe the ways in which economic incentives can be introduced on the demand side. We discuss the fundamental economics of establishing these incentives and the economic loss from systems that lack demand-side participation, and we analyze the effect of these incentives on the efficiency and competitiveness of the market. In section II, we move from the fundamentals to specific issues of implementing time-varying prices. We begin by describing illustrative Realtime Pricing and Critical Peak Pricing tariffs that are in use today. We then address the actual development of dynamic retail prices. In section III, we examine the ways in which customers respond to time-varying and dynamic prices. We discuss both the potential responses that are envisioned by those who study optimization of power use and the actual responses that have taken place in pilot and long-term programs. We conclude in section IV by advocating much wider use of dynamic retail pricing, under which prices faced by end-use customers can be adjusted frequently and on short notice to reflect changes in wholesale prices and the supply/demand balance.

The standard economic model of efficient competitive markets relies on the ability of sellers to charge prices that vary as their costs change. Yet, there is no restructured electricity market in which most retail customers can be charged realtime prices (RTP), prices that can change as frequently as wholesale costs. We analyze the impact of having some share of customers on time-invariant pricing in competitive electricity markets. Not only does time-invariant pricing in competitive markets lead to outcomes (prices and investment) that are not first-best, it even fails to achieve the second-best optimum given the constraint of time-invaraint pricing. We then study a number of policy interventions that have been proposed to address the perceived inadequacy of capacity investment. We show that attempts to correct the level of investment through taxes or subsidies on electricity or capacity are unlikely to succeed, because these interventions create new inefficiencies. We demonstrate that the most common proposal, a subsidy to capacity ownership financed by a tax on retail electricity, is particularly problematic. In contrast, an increase in the share of customers on RTP improves efficiency, though it does not necessarily reduce capacity investment. We demonstrate that the analysis is robust to inclusion of a simple form of reserve capacity.