Contact Steve Walton



	Eric Hirst <Eric@EHirst.com>
	11/10/2000 10:03 AM
		 
		 To: Skean@enron.com (Steve Kean)
		 cc: 
		 Subject: Outline for Project on Real-Time Markets

Dear Steve,

Once again, I call on you for advice. Who, within Enron, should I talk with 
about a new project I am working on, related to real-time balancing 
operations and markets (all the messy stuff that causes so many problems 
within all the existing ISOs)?

Here is the outline for the project. Can you send me your suggestions on 
revising the outline, other people at Enron (and elsewhere) to contact 
related to these markets, and written materials on how the various ISO 
markets operate. 

Thanks.

Eric
----------------
ISSUES TO DISCUSS FOR PROJECT ON:
REAL-TIME BALANCING OPERATIONS AND MARKETS
November 6, 2000

1. Introduction: Importance of real-time operations and markets 
Essential for reliability, especially security 
Basis for all forward contracts (hour- and day-ahead, block monthlies, 
bilaterals) 
Real-time prices motivate generation-capacity decisions: new construction, 
repowering, retirements 
Ensure equitable treatment for &new8 intermittent and distributed resources 
2. Physical Requirements and Operations 
Balance generation to load in near-real time (intrahour) 
Normal conditions (frequency response, CPS1, CPS2) 
Contingency conditions (DCS) 
In neither case is it necessary for generation to exactly balance load over 
short time periods (e.g., 10 minutes), but must balance energy over longer 
intervals 
Benefits of aggregation 
Performance and characteristics of individual generation and load resources: 
random fluctuations, energy level, ramp rate, acceleration rate, startup 
time, minimum run time, block loading, energy-limited characteristics of 
hydro units, etc 
Control-area balance vs individual-schedule balance, good vs bad inadvertent 
interchange 
NERC and FERC requirements 
3. Operations with Vertically Integrated Utilities 
Unit commitment 
Economic dispatch 
Regulation 
Contingency reserves 
Control area forecasts of loads and resources, effects of forecasts on unit 
commitment and dispatch 
Treatment of (payments and penalties for) energy imbalance and inadvertent 
interchange 
4. RTO Operations and Markets 
Generation not owned by RTO, RTO must purchase outputs from generation and 
load resources 
Relationship between real-time operations and markets, how are resources 
dispatched (and by whom) and how are they compensated 
Time interval (1, 5, 10, or 15 minutes) for dispatch and price setting; what 
are the tradeoffs in choosing among these intervals 
Single market-clearing price in each interval vs pay-as-bid for each resource 
Pay for energy only or pay also for maneuverability (e.g., ramp and 
acceleration rates); how do resource constraints determine which resources 
are permitted to set the market-clearing price and which aren't, and why? 
Set prices ex ante or ex post? If prices set ex ante, what is the basis for 
the value? 
Should unit commitment (resource scheduling) be done by individual suppliers, 
by RTO, or both? 
Relationship between real-time markets and ICAP and RMR requirements, and RTO 
requirements to ICAP and RMR units to bid resources into real-time market 
Treatment of exports and imports, rules governing interchange scheduling 
(number of schedule changes per hour permitted, ramp rates for schedule 
changes) 
To what extent does the RTO make short-term forecasts of load and generation, 
how far into the future (10 minutes to 24 hours), how does the RTO use these 
forecasts? Should the RTO commit and dispatch resources on the basis of 
expected future conditions (i.e., beyond the current and next interval)? Who 
pays for these RTO decisions? 
Should RTO publish prices and let demand and supply respond to the price 
signal, or should RTO dispatch resources up and down based on supplier bids? 
If the RTO explicitly dispatches resources, should uninstructed deviations be 
treated differently, in terms of payment or penalties, from instructed 
deviations? What about a resource,s failure to follow instructions? 
Under what circumstances should RTO go &out-of-market8 for resources? What 
should set the price of (payment to) these resources? 
Under what conditions, if any, are penalties appropriate, for what kinds of 
behavior, what determines the magnitude of the penalty? Should penalties 
apply to generation only or to loads also? 
How, if at all, should capacity assigned to ancillary services (especially 
the reserve services) be incorporated into real-time operations and markets? 
For example, should the capacity assigned to contingency reserves be set 
aside and used only when a major outage occurs? Or should such reserves be 
used routinely whenever it is economic to do so, as long as sufficient 
capacity is available to meet the NERC reserve requirements? 
How should intermittent resources (e.g., wind) be treated in real-time 
operations and markets? Should they be treated any differently from a large, 
volatile load? 
Can retail loads participate in real-time markets? How? 
5. Case Studies of U.S. ISOs 
California 
PJM, New York, and New England 
ERCOT 
 6. Conclusions and Recommendations 
Key features of operations and markets 
What works 
What are the options 
What problems still remain 

----------------------------------------------
Eric Hirst
Consulting in Electric-Industry Restructuring
106 Capital Circle
Oak Ridge, TN 37830
865-482-5470 (phone & fax)    Eric@EHirst.com
http://www.EHirst.com/