Measuring Market Inefficiencies in California's Restructured Wholesale Electricity Market

TL;DR: In this paper, the authors present a method for decomposing wholesale electricity payments into production costs, inframarginal competitive rents, and payments resulting from the exercise of market power, and find significant departures from competitive pricing, particularly during the high-demand summer months.

Abstract: 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.

Summary

2539 Channing Way, # 5180 Berkeley, California 94720-5180

• Www.ucei.org Measuring Market Ine±ciencies in California's Restructured Wholesale Electricity Market Severin Borenstein¤, James Bushnell¤¤ and Frank Wolak¤¤¤ June 2002 Abstract.
• He is currently a member of the California Independent System Operator's Market Surveillance Committee, of which Wolak is the Chair.
• The authors also address the question of the e±ciency impacts of market power in this market.
• The authors ¯nd that, due to rising input costs, even a perfectly competitive California electric- ity market would have seen wholesale electricity expenditures triple between the summers of 1998 and 2000.1 Market power, however, also played a very signi¯cant role.
• The authors present the results of the analysis in section V.

II. Market Power Analysis in the Electricity Industry

• During most of the 1990s, regulatory evaluation of short-run horizontal market power in electricity focused on concentration measures, such as the Her¯ndahl-Hirschman index (HHI).
• Unfortunately, such measures are a poor indicator of the potential for, or existence of, market power in the electricity industry, because the industry is characterized by highly variable price-inelastic demand, signi¯cant short-run capacity constraints, and extremely costly storage.
• It is less informative about the speci¯c manifestations of market power, but is e®ective for estimating its scope and severity, as well as identifying how departures from competitive outcomes vary over time.
• Furthermore, the authors ¯nd that over substantial periods of time, 3 See Puller (2001) for an analysis of this issue.
• This is because the stranded cost component paid by all consumers was calculated in a way that moved inversely to the energy price: the higher the energy price, the lower the CTC payment for that hour.

III. The California Electricity Market

• Through December 2000, the two primary market institutions in California were the Power Exchange (PX) and the Independent System Operator (ISO).
• The PX markets were e®ectively ¯nancial, rather than physical; ¯rms could change their day-ahead PX positions by purchasing or selling electricity in the ISO's real time electricity spot market.
• A production unit committed to provide reserve capacity during an hour would therefore earn a capacity payment for being available and, if called upon in real time, would earn the imbalance energy price for actually providing energy.
• \Regulation reserve", the most short-term reserve, is treated di®erently.
• Regulation reserve units are directly controlled by the ISO and adjusted second-by-second in order to allow the ISO to continuously balance supply and demand, and to avoid overloading 10 Unlike the PX, the ISO continued to function in approximately its original role through the 2000-2001 electricity crisis.

A. Market Structure of California Generation

• The California electricity generation market at ¯rst glance appears relatively uncon- centrated.
• The former dominant ¯rms, Paci¯c Gas & Electric (PG&E) and Southern California Edison (SCE) divested the bulk of their fossil-fuel generation capacity in the ¯rst half of 1998 and most of the remainder in early 1999.
• Most of the capacity still owned by these utilities after the divestitures were covered by regulatory side agreements, which prescribed the price the seller was credited for production from these plants independent of the PX or ISO market prices.
• The market structure during 2000 was largely unchanged from that of 1999.
• The seemingly dominant position of PG&E is o®set to a large extent by its other regulatory agreements.

B. Analyzing Market Power in California's Electricity Market

• Critical to studying market power in California is an understanding of the economic interactions between the multiple electricity markets in the state.
• If the ISO's real-time imbalance energy price was consistently higher than the PX day-ahead price, then sellers would reduce the amount of power they sell in the PX and sell more in the ISO imbalance energy market.
• Nonetheless, because sellers could move between markets as well, ultimately the buyers had no ability to exercise monopsony power, because they could not reduce their hourly demand for energy.
• In the case of the California market, the relevant consideration is that the provision of ancillary services in most cases does not preclude the provision of energy in the real-time market.
• Even if this were not the case, however, their analysis would fully account for the opportunity cost of exports, because under the California market structure ¯rms from other states had the option to purchase power through markets run by the PX and ISO.

IV. Measuring Market Power in California's Electricity Market

• The fundamental measure of market power is the margin between price and the marginal cost of the highest cost unit necessary to meet demand.
• As discussed above, if no ¯rm were exercising market power, then all units with marginal cost below the market price would be operating.
• When a ¯rm with market power reduces output from its plants or, equivalently, raises its o®er price for its output, its production is usually replaced by other, more expensive generation that may be owned by non-strategic ¯rms.
• In estimating a price-cost margin in this paper, the authors therefore must estimate what the system marginal cost of serving a given level of demand would be if all ¯rms were behaving as price takers.
• In the following subsections the authors describe the assumptions and data used for generating estimates of the system marginal cost of supplying electrical energy in California.

A. Market Clearing Prices and Quantities

• As described above, the California electricity market in fact consists of several parallel and overlapping markets.
• This argument clearly relies on very ine±cient markets, because the state was almost never a net exporter.
• It has been argued that the day-ahead PX price should be expected to systematically overstate the marginal cost of energy supply because sellers in the day-ahead market would include a premium in their o®er prices to account for the opportunity of earning ancillary services revenues, which require that the units not be committed to sell power in a forward market.
• Over their sample period, the PX average price was not signi¯cantly greater than the ISO average price (see Borenstein, Bushnell, Knittel, and Wolfram, 2001).
• Therefore, the authors consider the real-time energy demand in each hour to be the quantity that must be supplied, and capacity selected for reserve services to be part of the capacity that can meet that demand and, as such, to be part of their aggregate marginal cost curve.

B. Marginal Cost of Fossil-fuel Generating Units

• To estimate the marginal cost of production for an e±cient market, the authors divide pro- duction into three economic categories: reservoir, must-take, and fossil-fuel generation.
• Generation unit forced (as opposed to scheduled) outages have traditionally been treated as random, independent events that, at any given moment, may occur according to a probability speci¯ed by that unit's forced outage factor.
• 27 Figure 2 illustrates a hypothetical marginal cost curve of the instate generation, ex- cluding must-take and reservoir energy resources.
• If such a capacity constraint were binding at the observed California market clearing price, then the marginal production cost of imports would most likely be below this market clearing price and, thus, a perfectly competitive price within California would yield only weakly lower imports.
• In the event that the net of proposed import and export schedules does exceed transmission capacity on some intertie, the ISO initiates a process of congestion relief by adjusting schedules according to their adjustment bids.

D. Hydroelectric and Geothermal Generation

• Reservoir generation units (i.e., hydro and geothermal units) present a di®erent chal- lenge because the concern is not over a change in aggregate output relative to observed levels but rather a reallocation over time of the limited energy that is available to them.
• To realign the import supply curve implied by the adjustment bids with the observed import-price pair for each hour, the authors calculate the change in imports in each hour as ¢qimp(p) = qimp(p)¡qimp, where is market price during the hour under consideration.
• For the purpose of calculating the impact of market power on total production cost, it is easy to see that this is a conservative assumption, one that will produce downward biased estimates on the e±ciency e®ects of market power.
• Of concern is the possibility that the observed hydro schedule (which may include a response by hydro ¯rms to the exercise of market power by others) { when combined with a counter-factual perfectly competitive production of fossil-fuel resources { could produce a lower marginal cost estimate on average than the optimal hydro schedule.
• To examine this possibility, the authors estimated a kernel regression of their estimated marginal cost (i.e., competitive price) on system demand in order to detect whether in aggregate there are systematic deviations from a monotonically increasing relationship between demand and their estimate of system marginal cost.

E. Calculating Cost Increase Relative to Competitive Outcome

• Utilizing the assumptions outlined in the previous sections, the authors estimated the perfectly competitive market price in the California energy markets for each hour of market operation from June 1998 through October 2000.
• For this reason, their estimate of a unit's marginal cost may be slightly higher than the cost level at which it is capable of operating in a market environment.
• Therefore the authors include negative price-cost di®erences in order to prevent truncating the e®ect of data uncertainty on their cost-estimates.
• Because the authors don't account for the RMR units, their estimates could still indicate that a fossil-fuel unit is marginal and its cost is the system marginal cost, so their estimated system marginal cost would be above the actual PX price due to unaccounted-for RMR calls.

V. Results

• The authors computed the expected perfectly competitive price each hour for the months of June 1998 through October 2000 using the algorithm described above.
• For each hour, the authors can calculate an arc elasticity implied by the adjustment bids for the import response from the change between the competitive and actual price and the resulting change in imports.
• To re°ect this fact, let P̂ tpx denote the observed PX price for hour t and E(P̂ t px) the expectation of this magnitude with respect to the joint distribution of generating unit outages.
• Electricity demand is low in these months and supply is relatively large due to the resurgence in hydro production from winter rains.
• 31 The authors results also indicate that, given the supply and demand conditions during that period, the performance of the market was not dramatically di®erent in 2000 from that in 1998 and 1999.

VI. Deadweight Loss and Rent Division

• Even without a market power analysis, it is clear that the extraordinary prices that began in the summer of 2000 created large transfers of wealth.
• Some of the rents due to market power became pro¯ts of electricity producers or marketers, but some were dissipated in production e±ciency losses: e±ciency losses resulting from the operation of higher-cost production units when a ¯rm with lowercost production exercises market power and restricts output.

A. Deadweight Loss

• The authors begin by estimating the loss in economic e±ciency due to the imperfections in the market.
• By assuming that import bids re°ect the marginal cost of the supplier, the authors assume that increased production from these imports due to market power exercised by ¯rms within California creates an increase in total production cost.
• The two components of deadweight loss are illustrated in Figure 2.
• In Figure 5, the authors illustrate the relationship between their estimated instate productive ine±ciency and aggregate demand faced by California fossil-fuel plants using a kernel density regression.
• Given their ¯ndings in the previous section, it is not surprising that the authors observe low levels of production ine±ciency at low levels of system demand, when there are low levels of market power.

B. Rent Division

• With the calculation of deadweight loss due to productive ine±ciency, the authors are now in a position to parse the total wholesale market payments into costs, competitive rents, and rents due to the exercise of market power.
• 42 Together, these areas { Comp: Rents and Comp: Total Cost { account for all wholesale market payments under perfect competition.
• With market power, the quantity qr is produced by instate generation units and the quantity qtot ¡ qr is imported.
• Rents 2 and Import Loss are the additional variable production costs of the imported power under the assumption that imports are bid competitively, also known as The areas labeled Comp.
• E±cient production costs more than tripled between these periods and with the marginal unit having higher costs, competitive rents for lower cost units quadrupled.

VI. Conclusions

• Restructuring of electricity industries has been predicated on the belief that workably competitive wholesale electricity markets can be attained.
• The authors have attempted here to reliably estimate the degree to which California's wholesale electricity market has deviated from the competitive ideal.
• These estimates should serve as a reminder that the problem of producer market power that was addressed in a purely regulatory framework for most of the 20th century has not completely disappeared with the recent restructuring.
• The authors have not attempted to assess the pro¯tability of any generation ¯rms selling in California, because such pro¯ts are not necessarily an indication of market power, just as the absence of pro¯ts is not an indicator of competitive behavior.
• This is separable from the important debate over what index levels indicate a need for some form of market intervention.

Figures

Figure 5: Efficiency Losses

Figure 1: California Fossil Plant MC Curves (September)

Figure 6: Calculation of Division of Rents

Table 3: Production Costs and Rent Distribution (Millions $) June - October

Figure 2: Import Adjustments and Efficiency Losses

Table 1b: California ISO Generation Companies (MW) July 1999 - Online Capacity

Table 1b: California ISO Generation Companies (MW) July 1999 - Online Capacity

Figure 3: Kernel Regressions of Lerner Index August 7 - September 30

Table 2: Actual Price and Estimated Marginal Cost

Figure 4: Cumulative Distribution Functions of Demand Met by Instate Fossil-Fuel Generation August 7 - September 30

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UC Berkeley
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Title
Measuring Market Inefficiencies in California's Restructured Wholesale Electricity Market
Permalink
https://escholarship.org/uc/item/2159m46p
Authors
Borenstein, Severin
Bushnell, Jim
Wolak, Frank A.
Publication Date
2002-06-01
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University of California

CSEM WP 102
Measuring Market Inefficiencies in California’s
Restructured Wholesale Electricity Market
Severin Borenstein, James Bushnell and Frank Wolak
June 2002
This paper is part of the Center for the Study of Energy Markets (CSEM) Working Paper
Series. CSEM is a program of the University of California Energy Institute, a multi-
campus research unit of the University of California located on the Berkeley campus.
2539 Channing Way, # 5180
Berkeley, California 94720-5180
www.ucei.org

Measuring Market Ine±ciencies in California's
Restructured Wholesale Electricity Market
Severin Borenstein
¤
, James Bushnell
¤¤
and Frank Wolak
¤¤¤
June 2002
Abstract
We present a method for decomposing wholesale electricit y 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 d emand and increased production costs caused by market power and other market
ine±ciencies. Using data from June 1998 to October 2000 in California, we ¯nd signi¯cant
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 ¯nd 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.
For helpful discussions and comment s, we thank Carl Blumstein, Roger Bohn, Peter Cram-
ton, David Genesove, Rob Gramlich, Paul Josk ow, Ed Kahn, Alvin Klevorick, Christopher
Knittel, Patrick McGuire, Catherine Wolfram, an anonymous referee, and participants in
numerous seminars. Jun Ishii, Matt Lewis, Erin Mansur, Steve Puller, Celeste Saravia and
Marshall Yan provided excellent research assistance.
¤
Haas School of Business, University of California, Berkeley, CA 94720-1900, University
of California Energy Institute, and NBER. email: borenste@haas.berkeley.edu.
¤¤
University of California Energy Institute, 2539 Channing Way, Berkeley, CA 94720-5180.
email: jimb@ieor.berkeley.edu.
¤¤¤
Department of Economics, Stanford University, Stanford, CA 94305-6072, and NBER.
email: wolak@zia.stanford.edu.
Borenstein is a member of the Governing Board of the California Power Exchange. Bushnell
was a member of the Power Exchange's Market Monitoring Committee during 1999-2000.
He is currently a member of the California Independent System Operator's Market Surveil-
lance Committee, of which Wolak is the Chair. The views expressed in this paper do not
necessarily re°ect those o f any organization or committee.

I. Introduction
In the spring of 2000, the momentum behind a dramatic restructuring of the electric-
ity industry appeared to be irresistible. There were four regions of the U.S. with inde-
pendent system operators running spot mark ets for wholesale electricity{California, PJM
(maj or parts of Pen nsylvania, New Jersey, Maryland, Delaware, Virginia and the District
of Columbia), New England, and New York. Several other states were undertaking ini-
tiatives to restructure their electricity sector along similar lines. Beginning in summer
2000, however, soaring wholesale electricity prices in California made international news
and threatened the ¯nancial stabilit y of the state. The disruptions in California slowed,
and threatened to reverse, the movement towards restructured electricity mark ets in the
U.S. and elsewhere.
In the aftermath of California's electricity crisis, policy makers debated the correct
lessons to take from the state's restructuring as well as the proper regulatory response
to the crisis. Many of the answers to the questions being debated depend upon a proper
diagnosis of the problems that disrupted California's power sector during this period.
Were soaring power costs the result of market \ fundamentals" such as rising fuel prices,
en vironmental cost, and a scarcity of generating capacity? Or were power suppliers able
to exercise signi¯cant market power? In this paper we estimate the extent to which each
of these factors - input costs, scarcity, and market power - in°uenced market outcomes
in the California power market from 1998 through 2000. We analyze input and output
prices, generator variable costs, and actual production quantities to measure the degree to
whic h California wholesale electricity prices exceeded competitive levels. We also address
the question of the e±ciency impacts of market po wer in this market.
While market power has been studied and estimated in many industries, there has been
little attention paid to intertemporal variation in the ability to exercise market power. For
industries in which the good is storable, such intertemporal variation is necessarily small
b ecause inventories greatly reduce intertemporal supply variation, and possibly, demand
variation. In markets for non-storable goods, including electricit y and most services, this
is not possible. The problem is exacerbated in electricity because demand is very inelastic
in the short run and supply becomes very inelastic as production approaches the system
1

generation capacity. Recognizing the dynamics of market power is likely to be important
in both determining its causes and crafting remedies as part of the evolving public policy
towards electricity restructuring.
Luckily, due to the history of regulation in electricity markets, data exist on the hourly
output of all generating units and transmission power °ows. In addition, information
collected on the technical characteristics of each California generating unit during the
regulated monopoly regime allows very accurate estimation of generating unit-level variable
costs.
We ¯nd that, due to rising input costs, even a perfectly competitive California electric-
ity market would have seen wholesale electricity expenditures triple between the summers
of 1998 and 2000.
1
Market power, however, also played a very signi¯cant role. In summer
1998, 25% of total electricity expenditures could be attributed to market power, a ¯gure
that increased to 50% in summer 2000. The increased percentage margins due to market
power combined with substantial production cost increases for marginal producers to cre-
ate a drastic rise in absolute margins and, thus, pushed the market into a crisis later in
the summer of 2000.
In section II, we discuss the issues raised in estimating market po wer in electricit y
markets and the consequences of market power. We present an overview of California's
electricity market in section III. In section IV, we describe the e stimation technique in
detail in the context of the California market, addressing each component of the market
and outlining the assumptions made in implementing the analysis. We try to take a
conservative approach, interpreting the data in a way that would be likely to understate
the degree of market power exercised. We present the results of the analysis in section
V. In addition to our estimates of premia of actual prices over the competitive levels, we
also attempt to parse changes in competitive revenues between changes in actual costs and
changes that re°ect rents to inframarginal competitive sellers. We conclude in section VI.
1
For the purpose of this analysis, we de¯ne the summer to be June through October of each year.
2

Frequently asked questions

Q1. What are the contributions mentioned in the paper "Measuring market inefficiencies in california's restructured wholesale electricity market" ?

The authors present a method for decomposing wholesale electricity payments into production costs, inframarginal competitive rents, and payments resulting from the exercise of market power. The views expressed in this paper do not necessarily re°ect those of any organization or committee. Using data from June 1998 to October 2000 in California, the authors ̄nd signi ̄cant departures from competitive pricing, particularly during the high-demand summer months. 

Q2. Why is the lack of market power critical to understanding its consequences?

Because the extent of market power varies tremendously on an hourly basis, the absence of very-short-run elasticity is critical to understanding its consequences. 

Q3. Why is the Lerner index set to zero?

Because the Lerner index is not symmetric around zero, negative values of the ratio are set to zero to maintain a reasonable scale for the ¯gure. 

Q4. What is the process of congestion relief?

In the event that the net of proposed import and export schedules does exceed transmission capacity on some intertie, the ISO initiates a process of congestion relief by adjusting schedules according to their adjustment bids. 

Q5. Why does the ISO sometimes not use some types of reserve?

Due to reliability concerns, the ISO occasionally has not utilized some types of reserve (\\spinning" and \\non-spinning") for the provision of imbalance energy even when the units are economic (see Wolak, Nordhaus, and Shapiro (1998)). 

Q6. What percentage of electricity expenditures could be attributed to market power?

In summer1998, 25% of total electricity expenditures could be attributed to market power, a ¯gurethat increased to 50% in summer 2000. 

Q7. What did the ineciencies due to increased imports in power grow?

The ine±ciencies due to increased imports in power did grow substantially during their study, rising from 2% to 8% of total production costs by the summer of 2000. 

Q8. What is the difficult aspect of estimating the cost of meeting total demand in the ISO system?

C. Imports and ExportsOne of the most challenging aspects of estimating the marginal cost of meeting totaldemand in the ISO system is accounting for imports and exports between the ISO and other control areas. 

Q9. What is the debate over whether the restructuring of the electricity industry is correct?

The debate over whether that assumption is correct and what must be done to ensure competition in electricity generation is ongoing. 

Q10. What was the price of the capacity still owned by these utilities after the divestitures?

Most of the capacity still ownedby these utilities after the divestitures were covered by regulatory side agreements, whichprescribed the price the seller was credited for production from these plants independentof the PX or ISO market prices. 

Q11. How do the authors calculate the arc elasticity of the import response?

For each hour, the authors can calculate an arc elasticity implied by the adjustment bids for the import response from the change between the competitive and actual price and the resulting change in imports. 

Q12. Why is it likely that the cost estimates that exceed the PX price occur?

it is most likely that the cost estimates that exceed the PX price occur because there were no fossil-fuel generating units that were economic to run at the time.