THE PJM INTERCONNECTION STATE OF THE MARKET REPORT 2001 Energy - - PowerPoint PPT Presentation
THE PJM INTERCONNECTION STATE OF THE MARKET REPORT 2001 Energy Market Committee Joseph E. Bowring June 19, 2002 Manager PJM Market Monitoring Unit Energy Markets Basic tests of competition: Net revenue Price-cost mark up
Joseph E. Bowring Manager PJM Market Monitoring Unit Energy Market Committee June 19, 2002
– Net revenue – Price-cost mark up – Market structure – Prices
Figure 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 Revenue Net Revenue 1999 Net Revenue 2000 Net Revenue 2001
Figure 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 Revenue Total Net Revenues: 2000 Total Net Revenues: 2001 Total Net Revenue: 1999
– 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
– 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: $88,212/MW-year
– 1999 net revenues from all sources greater than adequate to cover annual fixed costs of new peaker – 2000 net revenues from all sources almost equal to cover annual costs of new peaker – 2001 net revenues from all sources greater than adequate to cover annual costs of new peaker – Overall: net revenue results consistent with finding that there was no systematic exercise of market power in the energy market in 2001, while there was a finding of market power in the capacity market in 2001
Figure 3: 2001 Average Monthly Load Weighted Mark Up Indices
0.00 0.25 0.50 0.75 1.00 January February March April May June July August September October November December Month Index Mark Up Adjusted Mark Up
Figure 6: Type of Marginal Unit
29% 71% 36% 64% 41% 58% 0% 10% 20% 30% 40% 50% 60% 70% 80% CT STM Type of Unit Percent 1999 2000 2001
– Mark up index calculations consistent with conclusion that energy market was reasonably competitive in 2001 – Complexities: opportunity cost not included in cost – Complexities: scarcity rent not reflected
– HHI < 1000 : Unconcentrated – 1000 < HHI < 1800 : Moderately concentrated – HHI > 1800 : Highly concentrated
Figure 9: 2001 PJM Hourly Energy Market Minimum HHI
500 1000 1500 2000 2500 Jan-01 Feb-01 Mar-01 Apr-01 May-01 Jun-01 Jul-01 Aug-01 Sep-01 Oct-01 Nov-01 Dec-01
– HHI < 1000 : Unconcentrated – 1000 < HHI < 1800 : Moderately concentrated – HHI > 1800 : Highly concentrated Table 4. 2001 PJM Hourly HHIs by Segment Base Intermediate Peak Maximum 1725 4575 9080 Average 1525 2925 5140 Minimum 1325 1270 1200
– Aggregate HHI results show that PJM energy markets are moderately concentrated – Aggregate HHI results do not give reason for confidence during times of high demand – HHI levels indicate highly concentrated segments of the supply curve at times – HHI levels indicate highly concentrated markets in areas defined by specific transmission constraints
PJM Average Hourly LMP ($/MWh) Year Over Year Percent Change Average LMP Standard Deviation Average LMP Standard Deviation 1998 21.72 31.45 1999 28.32 72.41 30.4% 130.2% 2000 28.14 25.69
2001 32.38 45.03 15.1% 75.3%
Table 5: PJM Load-Weighted Average LMP ($/MWh) Year Over Year Percent Change Average LMP Median LMP Standard Deviation Average LMP Median LMP Standard Deviation 1998 24.16 17.60 39.29 1999 34.06 19.02 91.49 41.0% 8.1% 132.9% 2000 30.72 20.51 28.38
7.8%
2001 36.65 25.08 57.26 19.3% 22.3% 101.8%
Table 6: Load-Weighted, Fuel Cost Adjusted LMPs ($/MWh) 2000 2001 % Increase Average LMP 30.72 33.05 7.6% Median LMP 20.51 23.49 14.5% Standard Deviation 28.38 55.34 95.0%
Table 7: Comparison of Real-Time and Day-Ahead Market LMPs ($/MWh) Day- Ahead Real- Time Average Difference Percent Over Real-Time Average LMP 32.75 32.38
1.1% Median LMP 27.05 22.98
17.7% Standard Deviation 30.42 45.03 14.6
PJM Average Hourly System LMP
Day Ahead and Real Time Markets 2001 Market Day Ahead Real Time
LMP ($/MWh)
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
Figure 1: 2001 PJM Average Hourly Load and Spot Market Volume
5,000 10,000 15,000 20,000 25,000 30,000 35,000 40,000 Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec Month Volume (MW) Average Load Average Spot Volume
Figure 2: Total Import and Export Volume - 2001
1,000,000 1,500,000 2,000,000 2,500,000 3,000,000 JAN FEB MAR APR MAY JUN JUL AUG SEP OCT NOV DEC Month Volume (MWh) Imports Exports Total Net Imports
Net Imports by Tie Line - 2001
500,000 1,000,000 1,500,000 JAN FEB MAR APR MAY JUN JUL AUG SEP OCT NOV DEC Month MWh APS FE NYIS VAPWR
– Prices are a good general indicator of competitive conditions – 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
– Net revenue: energy market reasonably competitive in 2001 – Price-cost markup: energy market reasonably competitive in 2001 – Market structure:
– Prices: energy market reasonably competitive in 2001
– Additional actions to increase demand side responsiveness – Retention of $1,000 offer cap – Investigate incentives to reduce incentives to exercise market power
– Market structure – Outage rate performance – Prices
– HHI < 1000 : Unconcentrated – 1000 < HHI < 1800 : Moderately concentrated – HHI > 1800 : Highly concentrated
2001 PJM Capacity Credit Market HHIs Daily Monthly Maximum 5500 10000 Average 2700 3800 Minimum 1100 1700
Figure 2: Equivalent Demand Forced Outage Rate 1994 - 2001 0% 2% 4% 6% 8% 10% 12% 1994 1995 1996 1997 1998 1999 2000 2001
Figure 15: Capacity Obligation January 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 [Solid Lines]
1,000 2,000 3,000 4,000 MW [Dashed Lines] Installed Capacity Unforced Capacity Obligation Net Excess Net Exports
Figure 4: January Through December 2001 Daily and Monthly Capacity Credit Market Performance
25,000 50,000 75,000 100,000 125,000 150,000 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 Volume of Credits Transacted (Unforced MW) $0 $50 $100 $150 $200 $250 Weighted Average Capacity Clearing Price ($/MW-day) Daily CCM (MW) Monthly CCM (MW) Wtg Avg Price Monthly ($/MW) Wtd Avg Price Daily ($/MW)
January 2000 Through December 31, 2001 Daily vs Monthly Capacity Credit Market Performance
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 Volume of Credits Transacted (Installed MW-days)
50 100 150 200 250
Weighted Average Capacity Clearing Price ($/MW-day)
Daily CCM (MW) Monthly CCM (MW) Wtg Avg Price Monthly ($/MW) Wtd Avg Price Daily ($/MW)
Figure 6: PJM Unforced Capacity, Total LSE Obligation, Net PJM Position
50,000 51,000 52,000 53,000 54,000 55,000 56,000 57,000 58,000 10/1/00 11/1/00 12/1/00 1/1/01 2/1/01 3/1/01 4/1/01
Date
Unforced Capacity or LSE Obligation (MW)
500 1,000 1,500 2,000 2,500 3,000 Net PJM Position (MW) Unforced Capacity Total LSE Obligation PJM Position
Figure 12: Entity1 Supply and Residual Demand
500 1,000 1,500 2,000 2,500 1 / 1 / 1 1 / 1 / 1 2 / 1 / 1 / 1 / 1 2 / 1 / 1 3 / 1 / 1 4 / 1 / 1 Date MW Entity1 Offers Residual Demand
Figure 5: Daily Capacity Credit Market Clearing Price
$0 $50 $100 $150 $200 $250 $300 $350 $400 10/1/00 11/1/00 12/1/00 1/1/01 2/1/01 3/1/01 4/1/01
Date Clearing Price ($/MW-Day)
Daily Capacity Capacity Credit Market Clearing Price
– 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
– Continue competitive enhancements to capacity market design – Adopt a single market design – Incorporate explicit market power mitigation rules
– Market structure – Availability – Performance – Price
Figure 1: Regulation MW Offered Versus MW Purchased
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
Figure 3: Daily Regulation Cost Per MW 1999 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 $/MW Regulation Rate 2001 Regulation Rate 2000 Regulation Rate 1999
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
– 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
– Retain $100 offer cap in regulation market
– Activity levels – Prices
Figure 4 FTR Monthly Auction Volume Cleared and Net Revenue
2,000 4,000 6,000 8,000 10,000 12,000 14,000 16,000 M a y
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9 J u l
9 A u g
9 S e p
9 O c t
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9 D e c
9 J a n
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a r
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F e b
M a r
A p r
M a y
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MW-Months $0 $200,000 $400,000 $600,000 $800,000 $1,000,000 $1,200,000 $1,400,000 $1,600,000 Net Revenue ($) Cleared FTRs Revenue
Figure 5 FTR Monthly Auction Bid and Offer Count and Average Bid Clearing Price
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 Number of Bids/Offers $0 $100 $200 $300 $400 $500 $600 $700 Bid Offered Average Buy Bid Clearing Price
– FTR auction market was competitive in 2001 – FTR reassignment process constitutes a barrier to retail competition
– 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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