1. Marginal Cost Pricing: Why Is It Important? Have We Achieved It?
Massachusetts Restructuring Roundtable
January 18, 2002
John G. Farr
Farr Consulting

2. 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

3. 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

4. Fixed Cost as % of Total Costs Over Life of Typical Units
Advanced Combined Cycle
Conventional Steam
Combustion Turbine
40% to 50%
50% to 70%
75% to 95%

5. 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 one- third 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)

6. 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”

7. Illustrative Energy Bid Stack with All Generation in Merit
Price ($ per Megawatt)
Marginal unit
ECP
Bid Payment
Surplus Payment
Capacity Bid Into Pool (MW)
Capacity not Producing Energy
Energy Clearing Price

8. 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
Price ($ per Megawatt)
ECP (Figure 1)
 ECP (Lost Ability to Cover Fixed Costs)
ECP Actual
Bid Payment
Uplift Payment
Capacity Bid Into Pool (MW)
ECP Actual
Surplus Payment
Capacity Not
Producing Energy
ECP (w/o out of merit order operation)

12. 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

13. Impact of “Out-of-Merit” Order Generation on Prices
Few Hours, Very Large Impact on Price
Many Hours, Significant Impact on Price

14. Problems Identified by Patton are Not Unique to Summer Peak Hours

15. 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 ISO-NE 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