the pjm interconnection state of the market report 2001 joseph e. bowring manager pjm market...
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THE PJM INTERCONNECTION
STATE OF THE MARKET REPORT 2001
Joseph E. BowringManagerPJM Market Monitoring Unit
Federal Energy Regulatory CommissionJune 26, 2002
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State of the Market 2001-Conclusions
• Energy markets: – Reasonably competitive
• Capacity markets: – Period of market power
– Subsequently reasonably competitive
• Regulation market: – Competitive
• FTR auction market: – Competitive
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Energy Markets
• Basic tests of competition:– Net revenue
– Price-cost mark up
– Market structure
– Prices
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Net RevenueFigure 1: PJM Energy Market Net Revenue - 1999, 2000, and 2001
$0
$50,000
$100,000
$150,000
$200,000
$250,000
10 20 30 40 50 60 70 80 90 100 110 120 130 140 150
Unit Marginal Cost
Net
Rev
enue
Net Revenue 1999 Net Revenue 2000 Net Revenue 2001
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Net RevenueFigure 1A: PJM Markets Total Net Revenue - 1999, 2000, and 2001
$0
$50,000
$100,000
$150,000
$200,000
$250,000
$10 $20 $30 $40 $50 $60 $80 $100 $120 $140
Unit Marginal Cost
Net
Rev
enue
Total Net Revenues: 2000 Total Net Revenues: 2001 Total Net Revenue: 1999
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Annual Net Revenues
• CT at $40/MWh– 2001: $59,238/MW-year from energy market
– 2001: $36,700/MW-year from capacity market
– 2001: $7,126/MW-year from ancillary services and operating reserves
– 2001 Total: $103,064/MW-year
• CT at $50/MWh– 2001: $44,386/MW-year from energy market
– 2001: $36,700/MW-year from capacity market
– 2001: $7,126/MW-year from ancillary services and operating reserves
– 2001 Total: $88,212/MW-year
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Net Revenues
• Conclusion– 1999 net revenues from all sources greater than adequate to cover annual
fixed costs of new peaker
– 2000 net revenues from all sources less than adquate to cover annual costs of new peaker
– 2001 net revenues from all sources greater than adequate to cover annual costs of new peaker
– Overall: net revenue results consistent with finding that there was no systematic exercise of market power in the energy market in 2001, while there was a finding of market power in the capacity market in 2001
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Mark upFigure 3: 2001 Average Monthly Load Weighted Mark Up Indices
0.00
0.25
0.50
0.75
1.00
January February March April May June July August September October November December
Month
Inde
x
Mark Up Adjusted Mark Up
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Mark-Up Index
• Conclusion– Mark up index calculations consistent with conclusion that energy market
was reasonably competitive in 2001
– Complexities: opportunity cost not included in cost
– Complexities: scarcity rent not reflected
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Energy Market Structure
• FERC/DOJ HHI test:– HHI < 1000 : Unconcentrated
– 1000 < HHI < 1800 : Moderately concentrated
– HHI > 1800 : Highly concentrated
Table 2. 2001 PJM Hourly HHIsOverall
MinimumOverall
MaximumMaximum 1885 2140Average 1375 1565Minimum 975 1275
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Energy Market StructureFigure 9: 2001 PJM Hourly Energy Market Minimum HHI
0
500
1000
1500
2000
2500
Jan-01 Feb-01 Mar-01 Apr-01 May-01 Jun-01 Jul-01 Aug-01 Sep-01 Oct-01 Nov-01 Dec-01
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Energy Market Structure
• FERC/DOJ HHI test:– HHI < 1000 : Unconcentrated
– 1000 < HHI < 1800 : Moderately concentrated
– HHI > 1800 : Highly concentrated
Table 4. 2001 PJM Hourly HHIs by SegmentBase Intermediate Peak
Maximum 1725 4575 9080Average 1525 2925 5140Minimum 1325 1270 1200
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Market Structure
• Conclusion– Aggregate HHI results show that PJM energy markets are moderately
concentrated
– Aggregate HHI results do not give reason for confidence during times of high demand
– HHI levels indicate highly concentrated segments of the supply curve at times
– HHI levels indicate highly concentrated markets in areas defined by specific transmission constraints
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Energy Market Prices
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Simple average prices
PJM Average Hourly LMP ($/MWh)Year Over YearPercent Change
AverageLMP
StandardDeviation
AverageLMP
StandardDeviation
1998 21.72 31.451999 28.32 72.41 30.4% 130.2%2000 28.14 25.69 -0.6% -64.5%2001 32.38 45.03 15.1% 75.3%
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Load Weighted Average Prices
Table 5: PJM Load-Weighted Average LMP ($/MWh)Year Over YearPercent Change
AverageLMP
MedianLMP
StandardDeviation
AverageLMP
MedianLMP
StandardDeviation
1998 24.16 17.60 39.291999 34.06 19.02 91.49 41.0% 8.1% 132.9%2000 30.72 20.51 28.38 -9.8% 7.8% -69.0%2001 36.65 25.08 57.26 19.3% 22.3% 101.8%
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Fuel Cost Adjusted Average Prices
Table 6: Load-Weighted, Fuel Cost Adjusted LMPs($/MWh)
2000 2001 % IncreaseAverage LMP 30.72 33.05 7.6%Median LMP 20.51 23.49 14.5%StandardDeviation
28.38 55.34 95.0%
Excluding High Demand Week:Load-Weighted, Fuel Cost Adjusted LMPs ($/MWh)
2000 2001 % IncreaseAverage LMP 30.72 29.98 (5.7%)
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Day Ahead/Real Time Average Prices
Table 7: Comparison of Real-Time and Day-Ahead MarketLMPs ($/MWh)
Day-Ahead
Real-Time
AverageDifference
Percent OverReal-Time
AverageLMP
32.75 32.38 -0.37 1.1%
MedianLMP
27.05 22.98 -4.1 17.7%
StandardDeviation
30.42 45.03 14.6 -32.5%
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Day Ahead and Real Time LMP
PJM Average Hourly System LMPDay Ahead and Real Time Markets
2001
Market Day Ahead Real Time
LM
P (
$/M
Wh)
10
20
30
40
50
Hour
1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24
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Energy Prices
• Conclusion– Energy prices in 2001 consistent with a competitive energy market
– Net imports provide source of competition
– Pattern of prices across hours illustrates potential for demand side price sensitivity
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Energy Market
• Conclusion– Net revenue: energy market reasonably competitive in 2001
– Price-cost markup: energy market reasonably competitive in 2001
– Market structure:• Moderate overall concentration
• High supply curve segment concentration
• High regional concentration
– Prices: energy market reasonably competitive in 2001
• Recommendations– Additional actions to increase demand side responsiveness
– Retention of $1,000 offer cap
– Investigate incentives to reduce incentives to exercise market power
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Capacity Markets
• Basic tests of competition:– Market structure
– Outage rate performance
– Prices
• Market power issue
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Capacity Market Structure
• FERC/DOJ HHI test:– HHI < 1000 : Unconcentrated
– 1000 < HHI < 1800 : Moderately concentrated
– HHI > 1800 : Highly concentrated
2001 PJM Capacity Credit Market HHIsDaily Monthly
Maximum 5500 10000Average 2700 3800Minimum 1100 1700
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Forced Outage Rates
Figure 2: Equivalent Demand Forced Outage Rate1994 - 2001
0%
2%
4%
6%
8%
10%
12%
1994 1995 1996 1997 1998 1999 2000 2001
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Supply and Demand
Figure 15: Capacity ObligationJanuary through December 2001
50,000
52,000
54,000
56,000
58,000
60,000
1/1/01 2/1/01 3/1/01 4/1/01 5/1/01 6/1/01 7/1/01 8/1/01 9/1/01 10/1/01 11/1/01 12/1/01
Date
MW
[Sol
id L
ines
]
-1,000
0
1,000
2,000
3,000
4,000
MW
[Das
hed
Lin
es]
Installed Capacity Unforced Capacity Obligation Net Excess Net Exports
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Capacity Markets
Figure 4: January Through December 2001Daily and Monthly Capacity Credit Market Performance
0
25,000
50,000
75,000
100,000
125,000
150,000Ja
n-01
Feb
-01
Mar
-01
Apr
-01
May
-01
Jun-
01
Jul-
01
Aug
-01
Sep
-01
Oct
-01
Nov
-01
Dec
-01
Month
Vol
ume
of C
redi
ts T
rans
acte
d (U
nfor
ced
MW
)
$0
$50
$100
$150
$200
$250
Wei
ghte
d A
vera
ge C
apac
ity
Cle
arin
g P
rice
($/
MW
-day
)
Daily CCM (MW) Monthly CCM (MW) Wtg Avg Price Monthly ($/MW) Wtd Avg Price Daily ($/MW)
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Capacity MarketsJanuary 2000 Through December 31, 2001
Daily vs Monthly Capacity Credit Market Performance
0
25,000
50,000
75,000
100,000
125,000
150,000
Jan-
00
Feb
-00
Mar
-00
Apr
-00
May
-00
Jun-
00
Jul-
00
Aug
-00
Sep
-00
Oct
-00
Nov
-00
Dec
-00
Jan-
01
Feb
-01
Mar
-01
Apr
-01
May
-01
Jun-
01
Jul-
01
Aug
-01
Sep
-01
Oct
-01
Nov
-01
Dec
-01
Month
Vol
ume
of C
redi
ts T
rans
acte
d (I
nsta
lled
MW
-day
s)
0
50
100
150
200
250
Wei
gh
ted
Ave
rag
e C
apac
ity
Cle
arin
g P
rice
($/
MW
-day
)
Daily CCM (MW) Monthly CCM (MW) Wtg Avg Price Monthly ($/MW) Wtd Avg Price Daily ($/MW)
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Capacity Markets
• Conclusion– Capacity markets were subject to the exercise of market power in 2001
– MMU identified issues and PJM modified rules to reduce incentive to exercise market power
– Concentration levels high
– Positive outage rate results
– Contribution to reliability
– Potential exercise of market power remains a concern
– Market design issues remain a concern
• Recommendations– Continue competitive enhancements to capacity market design
– Adopt a single market design
– Incorporate explicit market power mitigation rules
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Regulation Market
• Basic tests of competition:– Market structure
– Availability
– Performance
– Price
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Regulation Market
Figure 1: Regulation MW Offered Versus MW Purchased
0
200
400
600
800
1,000
1,200
1,400
1,600
1,800
Jun-
00
Jul-
00
Aug
-00
Sep
-00
Oct
-00
Nov
-00
Dec
-00
Jan-
01
Feb
-01
Mar
-01
Apr
-01
May
-01
Jun-
01
Jul-
01
Aug
-01
Sep
-01
Oct
-01
Nov
-01
Dec
-01
MW
Total MW Offered Average Hourly Purchase Max Hourly Purchase
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Regulation Market
Figure 3: Daily Regulation Cost Per MW1999 vs 2000 vs 2001
$0
$100
$200
$300
$400
$500
$600
$700
$800
$900
Jan
Feb
Mar
Apr
May Jun
Jul
Aug
Sep Oct
Nov
Dec
$/M
W
Regulation Rate 2001 Regulation Rate 2000 Regulation Rate 1999
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Regulation Market
Figure 5: Percent of Hours Within Required PJM Regulation Limits
24%
39%
44%
64%
39%
73% 75%
86%84% 85%
91% 91% 90%
94%91%
86%
76% 74% 74%
81%
89%
94%98%
90%
0% 1% 1% 1% 1%
8%
16%
22%
6% 8%
14%
41%
11%9%
6% 6%8%
4% 5%
9%11%
16%
11%
15%
0%
10%
20%
30%
40%
50%
60%
70%
80%
90%
100%
Jan-
00
Feb
-00
Mar
-00
Apr
-00
May
-00
Jun-
00
Jul-
00
Aug
-00
Sep
-00
Oct
-00
Nov
-00
Dec
-00
Jan-
01
Feb
-01
Mar
-01
Apr
-01
May
-01
Jun-
01
Jul-
01
Aug
-01
Sep
-01
Oct
-01
Nov
-01
Dec
-01
Percent of Hours Meeting Minimum Regulation Requirement Percent of Hours Exceeding Regulation Requirement
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Regulation Market
• Conclusion– Concentration levels between 1700 and 1800
– Supply substantially greater than demand
– Prices were moderate
– Performance improved after introduction of market and maintained level of performance in 2001
– Regulation market was competitive in 2001
• Recommendation– Retain $100 offer cap in regulation market
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FTR Auction Market
• Basic tests of competition:– Activity levels
– Prices
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FTR Auction Market
Figure 4FTR Monthly Auction Volume Cleared and Net Revenue
0
2,000
4,000
6,000
8,000
10,000
12,000
14,000
16,000
MW
-Mon
ths
$0
$200,000
$400,000
$600,000
$800,000
$1,000,000
$1,200,000
$1,400,000
$1,600,000
Net
Rev
enu
e ($
)
Cleared FTRs Revenue
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FTR Auction Market
Figure 5FTR Monthly Auction
Bid and Offer Count and Average Bid Clearing Price
0
2,000
4,000
6,000
8,000
10,000
12,000
14,000
Jun-99 Sep-99 Dec-99 Mar-00 Jun-00 Sep-00 Dec-00 Mar-01 Jun-01 Sep-01 Dec-01
Nu
mb
er o
f B
ids/
Off
ers
$0
$100
$200
$300
$400
$500
$600
$700
Bid Offered Average Buy Bid Clearing Price
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FTR Auction Market
• Conclusion– FTR auction market was competitive in 2001
– FTR reassignment process constitutes a barrier to retail competition
• Recommendations– FTR reassignment process should be modified to eliminate barrier to retail
competition
– Develop an approach to identify areas where transmission expansion investments would relieve congestion where congestion may enhance market power and investments are needed to support competition
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IF YOU HAVE QUESTIONS
Contact the PJM Market Monitoring Unit
• (610) 666-4536 Phone• (610) 666-4762 FAX• [email protected] Email• www.pjm.com Internet