Marginal Cost Pricing: Why Is It Important? Have We Achieved It?

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 • Etc.

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 fromthe 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 Marginal unit Price ($ per Megawatt) 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