# Presentation: 747556

## 2004 State of CAISO Markets  Federal Energy Regulatory Commission MeetingMay 4, 2005Anjali Sheffrin, Ph.D.Director of Market Analysis

## Outline

- Market Performance
- Stable costs to serve load
- Demand and supply fundamentals
- Market competition and revenue sources to sustain new entry
- Key Market Issues Reviewed
- New real-time market software installed in Oct 2004
- Rising real-time congestion costs in southern California
- Ancillary Services market bid insufficiency
- Summer 2005 Outlook

##  Overview of Control Area 

- 11 million households served in PG&E, SCE, and SDG&E and some municipal utilities
- 2004 Peak Load of 45,597 MW
- 43,460 MW of available generation capacity at peak after derates for hydro and outages
- 9,116 MW net imports on peak hour
- California ISO Markets
- Real-time balancing
- Day Ahead and Hour  Ahead Reserves
- 	(Reg-Up, Reg- Dn, Spin, Non-spin)
- Day Ahead zonal congestion management
- No Day Ahead Energy Market

- Imperial Valley

- Miguel

- N.Gila

- Palo

- Verde

- Devers

- Lugo

- Mohave

- Eldorado

- McCullough

- Market

-  Place

- Sylmar

**Pac DC**

- Mead

- Vincent

**SF**

**NP15**

**ZP26**

**SP15**

***Path 26***

***COI***

***AZ3***

***Path 15***

***Mexico***

***LA4***

***LA2***

## Third year of stable market performance Total Cost $12.8 billion in 2004, v. $11.4 billion in 2003; Increase in costs affected by natural gas pricesWholesale Energy and Ancillary Service Costs, 1998-2004

## 2004 All-in price of wholesale energy: $53.46/MWh 

***2004 All-in price of wholesale energy: $53.46/MWh****** ***

- ISO
- Market
- Costs

## Competitive Market Outcomes  in 2004 

***Price-to-cost markups for short term energy 5.2% in SP15; 4.9% in NP15***
**Short-Term Markup Indices:  SP15**

## Real-time Energy Prices Rise in Q4 of 2004  2002-2004 Wtd. Average Monthly Real-time Energy PricesPeak Hours

## 2004 Monthly Average Ancillary Service Prices

## Demand Supply Fundamentals 

- 2004 load growth  increased around 3.7 % from 2003 levels due to economic growth
- 2004 net generation additions slowed to lowest level in past three years  but expected to pick up in 2005
- 2004 net imports increased 5% with sharp increase in Southwest imports

## Major paths with Day Ahead interzonal congestion costs2004 Interzonal Congestion Revenues on Selected Paths 

## Net generation additions slowed considerably in 2004 compared to previous three years

**2001-2005 Generating Capacity Additions and Retirements**

## Transmission constraints result in large regional differences in reserve marginsNP 15 and SP 15  Reserve Margins during southern Calif peak  on Sept 10, 2004 

## High RSI levels in 2004 indicate a healthy market with suppliers pivotal in fewer than 22 hours in the yearHourly Residual Supplier Index 1999-2004  

***High RSI levels in 2004 indicate a healthy market with ******suppliers pivotal in fewer than 22 hours in the year*****Hourly Residual Supplier Index 1999-2004*** *

## Revenue contribution from ISO markets for a new typical combined cycle generation unit fell 4 percent in 2004, combustion turbine unit profits increased 24 percent*Net Revenue Analysis, 2002 through 2004

- *Net revenue analysis based on units selling solely into ISO imbalance energy and ancillary service markets including # of starts.  Typically, a significant portion of fixed cost recovery would covered by a long-term bilateral contract.

## Key Market Issues

**New Real-time Market Software Installed in Oct 2004 - Real-time Market Application (RTMA)**
**Rising intra-zonal congestion costs in southern California**
**Chronic Ancillary Services market bid insufficiency**
**Summer 2005 Outlook**

## 1. Market Redesign Phase 1B: Real-time Market Application

- Automated real-time dispatch  to insure feasible  instructions in real-time market:
- Automatically balances electricity requirements in 5 min dispatch intervals, single Market Clearing Price
- Dispatches units for ramping up to 2 hours in advance
- Dispatch instructions considers specific generation unit capabilities
- Economic dispatch – clears transaction to allow additional flexibility to exchange costly energy dispatch for less expensive energy
- Uninstructed deviation penalties shown but not applied
- Recent concern with inter-tie bidding resulting from incentives from settlement rule of “bid or better”

## 1. New Real-time Market Software InstalledOctober 2004

- Automated real-time dispatch  to insure feasible  instructions in real-time market
- Better Operator Control resulting in fewer CPS violations
- Reduced need for Regulation Service
- Elimination of declined dispatch instructions
- Some benefits from  illustrating potential impact of uninstructed deviations penalties
- More price volatility
- Software tuning and enhancement continues to incorporate better unit information and known load and generation deviations

## 2. Real-time Intra-zonal Congestion

- Annual real-time congestion costs increased from $151 million in 2003 to $426 million in 2004:
- Results from sustained derates for transmission upgrades
- More efficient, cheaper generation available from southwest scheduled in forward markets to meet southern California load may not be feasible in real-time
- Zonal congestion management market does not account for intrazonal congestion and allows infeasible forward schedules resulting in significant real-time congestion
- Transmission enhancements and new LMP market design are long –term solutions to address  real-time congestion costs

## 3. Ancillary Services Market Bid Insufficiency

- The frequency of insufficient AS market bids to meet reserve requirements has increased over the past year
- First became problematic in 2002 when a significant amount of capacity signed up as condition 2 RMR and no longer able to participate in AS markets
- Exacerbated in 2004 by locational procurement of AS and increased amount of capacity committed by ISO
- 2004 market changes implemented to mitigate severity of AS market bid insufficiency
- Amendment 60 provided that ISO committed units could sell into the AS market and retain their commitment payments- July 11
- ISO commitment timeline moved forward so that committed units could participate in DA AS markets—increased market capacity by 12 percent – early Sept

## 4.  2005 Summer Outlook

- ISO 2005 Summer Assessment
- 13% reserve margin (without interruptible load) to meet demand for expected “1-in-2” or average conditions—southern California margins are thin
- Challenges for southern California for “1-in-10” or high load condition
- 2005 State Preparedness Plan
- Summer peak-hour simulation to assess  how much market is going to rely on ISO redispatch in real-time