Transcript Marginal Cost Pricing: Why Is It Needed? Are We Doing It?

Marginal Cost Pricing:
Why Is It Important? Have We Achieved It?
Massachusetts Restructuring Roundtable
January 18, 2002
John G. Farr
Farr Consulting
Goals of Presentation
• Illustrate key challenge that fixed costs
pose to successful electric industry
restructuring
• Provide context for why Patton Report
findings are important
• Further assess performance of New
England electric energy market
2
Fixed Costs of
Generating Capacity
• Installation
–
–
–
–
Siting
Permitting
Construction
Transmission
Interconnection
– Etc.
• Financing
– Interest
– Return on Equity
• Operating
–
–
–
–
–
Staffing
Scheduled Maintenance
Insurance
Property Taxes
Etc.
• Other
– Capital Improvements
– General and Administrative
– Etc.
3
Fixed Cost as % of Total Costs
Over Life of Typical Units
• Advanced Combined Cycle
40% to 50%
• Conventional Steam
50% to 70%
• Combustion Turbine
75% to 95%
4
Role of ICAP Market
• Also important source of revenue to cover fixed
costs
• Historical NEPOOL prices severely depressed
as result of market interventions
• Avg. PJM price (1/99 – 9/01):
$2.21/kW-mo1
• Levelized cost of peaking
capacity per ISO-NE study :
$6.15/kW-mo2
 ICAP market revenue may cover roughly onethird of fixed costs of lowest-cost resources
1 – Weighted average cost of all ICAP auctions administered by the PJM Interconnect, Inc.
2 – Study conducted for ISO-NE by e-Accumen Advisory Services (Final Report, Oct. 8, 2001)
5
Revenue to Cover Most
Fixed Costs Must Come from
the Energy Market
• Single price clearing auction format
• Units with variable costs less than energy clearing
price (ECP) earn contribution toward fixed costs
• Provides best incentives for units to bid variable
costs
• At outset of NEPOOL markets, it was assumed that
such contributions toward fixed costs generally
would exist for “all but the marginal unit”
6
Illustrative Energy Bid Stack
with All Generation in Merit
Marginal unit
ECP
Capacity Bid Into Pool (MW)
Bid Payment
Surplus Payment
Capacity not
Producing Energy
Energy Clearing
Price
7
Illustrative NEPOOL Energy Bid Stack
with “Out of Merit” Order Generation
Capacity
operating
“out-of merit”
Capacity backed down
due to out-of-merit
generation
ECP
(Figure 1)
ECP
Actual
 ECP (Lost Ability to
Cover Fixed Costs)
Capacity Bid Into Pool (MW)
Bid Payment
Uplift Payment
Surplus Payment
ECP Actual
Capacity Not
Producing Energy
8
ECP (w/o out of
merit order operation)
Price Duration Curve in New England Since Market Opening
ISO-NE Administered Hourly Markets, 5-1-99 to 9-30-01
Energy Clearing Price ($/MWH)
250
200
150
98.8% of Prices Below $100/MWH
100
82.5% of Prices Below $50/MWH
50
0
0%
10%
20%
30%
40%
50%
60%
70%
80%
90%
100%
Percent of Hours at or Below Price
Source: Electricity prices from ISO-NE (http://www.iso-ne.com)
9
Price Duration Curve in New England Since Market Opening
ISO-NE Administered Hourly Markets, 5-1-99 to 9-30-01
(adjusted for variations in fuel price)
Energy Clearing Price ($/MWH)
250
200
150
100
Unadjusted Curve
50
Adjusted Curve
0
0%
10%
20%
30%
40%
50%
60%
70%
80%
90%
100%
Percent of Hours at or Below Price
Note: Energy Clearing Prices are divided by a fuel price index to account for changes in underlying fuel costs during the period. Index
constructed using equal weighting of oil and gas.
Source: Electricity prices from ISO-NE (http://www.iso-ne.com). Fuel prices are Boston prices from Natural Gas Week (Gas) and Platts (Fuel Oil
2, 1% sulphur)
10
Revenue Contribution Toward Variable v. Fixed Costs Variable Costs
ISO-NE Administered Hourly Markets, 5-1-99 to 9-30-01
(example unit w/ $30/MWH variable costs, adj. for variations in fuel price)
Energy Clearing Price ($/MWH)
250
200
150
100
Hours Not Operating
(No Revenue)
Revenue Contributing Toward
Fixed Costs
Revenue Covering
Variable Cost
50
98%
95%
91%
88%
84%
81%
77%
74%
70%
67%
63%
60%
56%
53%
49%
46%
42%
39%
35%
32%
28%
25%
21%
18%
14%
11%
7%
4%
0%
0
Percent of Hours at or Below Price
Note: Energy Clearing Prices are divided by a fuel price index to account for changes in underlying fuel costs during the period. Index constructed
using equal weighting of oil and gas.
Source: Electricity prices from ISO-NE (http://www.iso-ne.com). Fuel prices are Boston prices from Natural Gas Week (Gas) and Platts (Fuel Oil
2, 1% sulphur)
11
Significance of Patton Report
• Shows extent to which use of “out-of-merit” order
operation altered prices in very high load hours this past
summer
• Shows that Summer 2001 energy prices did not nearly
reflect the marginal cost of meeting additional load
– Marginal cost ≠ marginal benefit (i.e., fails key criterion for
economic efficiency)
• Significance: Suppliers denied essential opportunity for
fixed cost recovery
– Competitive suppliers dependent on markets to cover fixed costs
– Essential to viability of suppliers that markets function efficiently
– Substantial implications for attracting generation to the New England
region
12
Impact of “Out-of-Merit” Order
Generation on Prices
Example NEPOOL Bid Stack
(6/23/00)
500
400
Bid Price ($/MWH)
300
Few Hours, Very Large
Impact on Price
200
Many Hours, Significant
Impact on Price
100
0
-
5,000
10,000
15,000
20,000
25,000
30,000
-100
Capacity Available to Pool (MW)
13
Problems Identified by Patton are
Not Unique to Summer Peak Hours
Impact of Out-of-Merit Generation on Energy Clearing Price for Sample of 20 Hours
(ISO-NE Data, 9-1-00 to 6-30-01)
Period Analyzed
Date Day Hour
9/1/2000
Fri
16
9/7/2000 Thu
15
9/13/2000 Wed
9
9/21/2000 Thu
14
10/3/2000 Tue
20
10/15/2000 Sun
20
10/18/2000 Wed
19
11/6/2000 Mon
18
11/7/2000 Tue
18
12/4/2000 Mon
10
1/8/2001 Mon
18
2/12/2001 Mon
19
3/15/2001 Thu
19
3/20/2001 Tue
12
4/9/2001 Mon
11
4/16/2001 Mon
21
4/18/2001 Wed
12
5/31/2001 Thu
12
6/11/2001 Mon
19
6/23/2001
Sat
13
Average
Max
Min
Load
Out of Merit Generation (MWH)
Actual ECP
(MW) "Economic" Congestion
Total ($/MWH)
21,530
2,089
991
3,080
$59.78
16,347
773
852
1,625
$44.02
17,385
1,120
643
1,763
$58.02
17,549
2,734
1,250
3,984
$37.35
17,045
623
576
1,199
$67.07
14,659
847
586
1,433
$75.38
16,979
917
480
1,397
$50.58
17,597
809
393
1,202
$69.30
17,189
1,340
335
1,675
$60.62
17,549
433
370
803
$84.23
19,297
370
140
510
$81.26
19,501
603
861
1,464
$50.38
17,104
745
20
765
$57.88
15,450
979
325
1,304
$50.14
15,565
615
114
729
$43.44
14,956
491
111
602
$52.63
16,057
354
248
602
$44.43
15,479
371
375
746
$33.99
16,611
1,314
1,048
2,362
$56.31
16,917
180
682
862
$50.87
17,038
885
520
1,405
$56.38
21,530
2,734
1,250
3,984
$84.23
14,659
180
20
510
$33.99
Price Adjusted for
Out-of-Merit MWH ($/MWh)
"Economic"
Both
$73.47
$86.83
$47.00
$47.14
$59.62
$61.00
$51.00
$53.42
$69.74
$76.25
$94.29
$94.93
$63.00
$67.77
$76.14
$91.13
$71.30
$73.05
$94.00
$99.11
$85.00
$85.65
$53.82
$58.98
$60.76
$60.76
$59.44
$60.80
$46.67
$46.67
$54.00
$54.00
$45.27
$46.39
$34.75
$36.33
$61.46
$70.65
$54.99
$57.80
$62.79
$66.43
$94.29
$99.11
$34.75
$36.33
% Change in ECP
"Economic"
Both
22.9%
45.2%
6.8%
7.1%
2.8%
5.1%
36.5%
43.0%
4.0%
13.7%
25.1%
25.9%
24.6%
34.0%
9.9%
31.5%
17.6%
20.5%
11.6%
17.7%
4.6%
5.4%
6.8%
17.1%
5.0%
5.0%
18.5%
21.3%
7.4%
7.4%
2.6%
2.6%
1.9%
4.4%
2.2%
6.9%
9.1%
25.5%
8.1%
13.6%
11.4%
17.6%
36.5%
45.2%
1.9%
2.6%
Notes: MW of economic uplift based on daily totals and hourly factors based on average for that weekday for that month
Prices adjusted based on actual bid stack for all resources that are not self-scheduled
14
What Remedies are Required?
• Principles
– Energy price should equal the cost of serving additional load
– Cost of serving additional load is reflected in bid price of
resources utilized by ISO to serve load on the margin, subject to
rules for market monitoring and mitigation
– Price setting criteria must respect reserve requirements of ISONE operators. Bid prices of capacity held in reserve (i.e., that
operators do not dispatch for energy) do not reflect cost to serve
additional load when operators dispatch more expensive
resources in order to maintain reserves
• Specific Remedies
– Changes required in market rules used to set price
– ISO-NE’s proposals currently under consideration in NEPOOL
15