Download The PJM Electricity Market

Environmental Regulation in Oligopoly
Markets: A Study of Electricity
Restructuring
Erin T. Mansur
UC Berkeley and UC Energy Institute
March 22, 2002
POWER Conference
Pennsylvania, New Jersey, and Maryland
Electric Utility Emissions
1,500
1,450
1,400
1,350
1,300
1,250
1,200
1994 1995 1996 1997 1998 1999 2000
• NOx down 17% in 1999
NOx Emissions (thousands of tons)
SO2 Emissions (thousands of tons)
• SO2 down 12% in 1999
440
420
400
380
360
340
320
1994 1995
1996 1997 1998
1999 2000
• PJM Electricity Restructuring
– Change Firm Incentives
• Environmental Regulation
– New marginal cost (OTC NOx Tradable Permit Market)
2
Research Questions
• Did restructuring the PJM electricity market
enable firms to exercise market power?
• If so, what are the welfare losses and
environmental consequences?
• What are the policy implications of these
effects?
3
The PJM Electricity Market
• PJM wholesale spot market
– PJM interconnection established in March, 1997
• Required firms to bid “cost-based”
– Rule changes in 1998 - “nodal” market
– April 1999: started “market-based” bids
• Structure of market
– Integrated with eastern grid
– Summers 98-99: no major structural change
– Six main firms vertically integrated
• Generation, transmission, and distribution
• Imperfect integration (net positions in market)
– Highly inelastic demand
4
PJM Market-wide Marginal Cost Curve
$100
Hydroelectric (3%)
Oil
Nuclear (23%)
Coal (35%)
Marginal Cost ($/MWh)
$80
Natural Gas
Natural Gas (18%)
Oil (21%)
$60
Oil
Natural Gas and Oil
$40
Natural Gas
Coal
Hydroelectric
$20
Nuclear
$0
0
10,000
20,000
30,000
40,000
Quantity Supplied (MWh)
50,000
60,000
5
PJM Market-wide Marginal Cost Curve
$100
Hydroelectric (3%)
Oil
High Demand
Nuclear (23%)
Coal (35%)
Marginal Cost ($/MWh)
$80
Natural Gas
Natural Gas (18%)
Oil (21%)
$60
Oil
Natural Gas and Oil
$40
Natural Gas
Coal
Hydroelectric
$20
Nuclear
$0
0
10,000
20,000
30,000
40,000
Quantity Supplied (MWh)
50,000
60,000
6
PJM Market-wide Marginal Cost Curve
$100
Hydroelectric (3%)
Oil
Nuclear (23%)
$80
Marginal Cost ($/MWh)
Low Demand
Coal (35%)
Natural Gas
Natural Gas (18%)
Oil (21%)
$60
Oil
Natural Gas and Oil
$40
Natural Gas
Coal
Hydroelectric
$20
Nuclear
$0
0
10,000
20,000
30,000
40,000
Quantity Supplied (MWh)
50,000
60,000
7
Cross-firm Production Inefficiencies:
Implications for PJM Vs. California
• PJM
– Marginal fuel types: coal, oil, or natural gas
– Dominant firms reduce output from their most
expensive operating unit (often coal)
– Fringe firms produce more from even more
expensive units (often gas)
– Exercising market power reduces emissions
• California
– Marginal fuel: only natural gas
– Dominant firms reduce from cheaper, cleaner units
– Exercising market power increases emissions
8
Technique
• Compare actual and competitive counterfactual
• Simplified model
– Determine the perfectly competitive price by
• Constructing MC curve (produce at full capacity if P>MC)
• Estimating residual demand from net import responses
• Intertemporal model
– Firms face intertemporal constraints
• Min and max operating capacities
• Starting up costs
• Ramping rates and minimum down time
– Optimize w.r.t. more than just current hour’s price
– Econometric model of firm production based on
competitive behavior pre-restructuring
9
Market Power: Price-Cost Margins
• Market imperfections increased the cost of power purchases in the
spot market by 41% in the summer of 1999
• Substantial price-cost margins at average demand levels
1
Lerner Index
.75
.5
.25
0
20000
25000
30000 35000 40000 45000
System Demand (MW)
50000 55000
10
Market Power: Firm-level Analysis
• Firm incentives
– Price elasticity of residual demand
– Net position (generation less load)
– Contract position
Firm
GPU, Inc.
Public Service Electric
PECO Energy Co
PP&L Inc
Potomac Electric Power
Baltimore Gas & Electric
Other
Capacity
Generation
18%
16%
14%
14%
12%
11%
15%
20%
14%
19%
18%
10%
13%
6%
Generation
to meet Peak
16%
18%
21%
15%
11%
11%
8%
Demand
Served
20%
19%
15%
13%
11%
12%
10%
• PECO and PPL exercise market power
– Positive correlation price-cost margin and net position
– Consistent with incentives
11
Welfare Implications From
Production Inefficiencies
• Comparing summer 1998 to summer 1999
• Actual production costs: $1.7 to $2.1 billion
• Intertemporal competitive model
– Costs increased - $275 million
– Welfare loss - $158 million
– About 8% of competitive cost estimates
• Simplified competitive model
– Ignore intertemporal constraints
– Welfare losses - $387 million
12
Hourly Average Tons of Emissions in PJM
Pollutant
1998
1999
SO2 Observed
137.5
%
Change
123.0 -10.5%
SO2 Intertemporal
135.8
127.5
-6.2%
NOx Observed
36.8
30.9 -15.9%
NOx Intertemporal
35.4
30.6 -13.7%
41% Market
Imperfections
14% Market
Imperfections
Value of permits saved
• Aggregation of (Daily Price * Emissions Change)
• $6.2 million from SO2 reductions
• $6.7 million from NOx reductions
13
Environmental Policy Implications
• Pollution taxes vs. tradable permits in secondbest setting
• Permit prices may be endogenous, but not
taxes
• PJM case
– Reduce permit demand
– Reduce dominant firms’ costs by more
– Preference for cap - feedback effect
• California case
– Increases fringe’s costs by more
– Preference for cap - feedback effect
14
Conclusions
• Evidence of Market Power by Net Selling Firms
• Welfare Effects from Market Imperfections
– Market power increased production costs by $160 million
– DWL is 8% of total production costs
• Environmental Effects from Market Imperfections
– 41% of SO2 reductions; 14% of NOx Reductions; $13 M
• Policy implications
– Tradable permits mitigate market power, and
may lead to greater welfare than using environmental taxes
15