2003 State of the Market Report

ERCOT Wholesale Electricity Markets

Balancing Energy Prices

• Prices were substantially higher in 2003 than in 2002

• A considerable amount of available energy is not offered into the BES market

• No strong relationship between prices and actual load level, but

• Clear relationship between net balancing deployment and BES prices

Balancing Energy Prices

• Improved correlation between spot market (BES) prices and forward prices, but

• Increased volatility of spot market prices over 2002

• Compared to other regions, ERCOT prices were the lowest in 2002, and remained relatively low in 2003 despite reliance on natural gas

Balancing Energy Prices

• Conclusion:• Inefficiencies in the Balancing Market

because – 1) prices are not correlated with load levels,

and – 2) a substantial amount of available energy is

not offered.

Ancillary Services Prices

• Prices in the A/S market are higher than in other regions and higher than one would expect. Two reasons:– Substantial portion of available capability is

not offered– Sequential design of the A/S market and BES

markets (as opposed to joint optimization) leads to higher costs

Net Revenue Analysis

• Net revenue is the total revenue that can be earned by a new generating unit less its variable production costs, and serves to recover fixed costs

• In 2003, the net revenue is insufficient to make investment profitable

Generator Commitment

• The ERCOT system is often over-committed: between 5000-9000 MW excess on-line capacity plus quick-start units

• This excess capacity commitment is inefficient and is due to the absence of a centralized day-ahead market commitment process

Load Participation

• 35 participant qualified as LaaRs with a total capability of 1200 MW

• LaaRs provided 800 MW of responsive reserves in 2003, or 35% or total RR requirement

• LaaRs were called to reduce consumption through automatic UFR twice in 2003

Interzonal congestion

• To manage interzonal congestion, SPD uses a simplified network model with four zones and three CSCs

• Aaverage flows modeled in SPD across the CSCs are in 2003:– South to Houston: 565 MW– South to North: 137 MW– West to North: 54 MW

Interzonal Flows

• SPD calculated flows are often very different from actual flows, due to simplifying assumptions made in the SPD model

• Simplifying assumptions:– Averaging of widely different generation shift

factors within a zone– Flows that occur through transmission

facilities that are not defined as part of the primary CSCs

Transmission Congestion Rights

• The quantity of TCRs sold over a CSC often exceeds the total modeled flows over the CSC, resulting in insufficient congestion revenues and uplift of the revenue shortfall

• This problem is caused primarily by the inconsistencies between SPD calculated flows and actual flows

• However, reduction in annual TCRs to 40% and increase in monthly TCRs to 60% will should reduce discrepancy between TCR sold and actual flows.

Local Congestion Costs• OOME costs rose by more than 50 percent, and

OOMC costs rose by 95 percent from 2002 to 2003

• The largest source for these costs are OOMC and OOME up in the DFW area and OOME down in the Northeast area

• New Northeast zone has addressed those OOME down costs

• Report recommends creation of a DFW zone in short run, nodal market in long run

Scheduling Patterns

• Load is under-scheduled by an average of 2 percent

• Under peak conditions, load may be under-scheduled by as much as 10-20%

• In the North zone, under-scheduling ranges from 5% in off-peak to 10% on peak

• Under-scheduled load is in large part satisfied by generation offered in the BES market

Hourly Schedule Changes

• Changes in schedules during ramping hours create problems for ERCOT

• Whereas load moves smoothly by 300-400 MW every interval, schedules change hourly, with changes averaging 1000-3000 MW

• Dichotomy between actual load changes and schedule changes creates large fluctuations in balancing deployments from interval to interval, resulting in erratic pricing patterns

Hourly Schedule Change

• Although the report does not mention it, it seems that the inflexible hourly schedule pattern also creates frequency control difficulties for ERCOT: ERCOT often does not pass CPS1 measure in the first interval of an hour (see August ERCOT Operating Report)

Hourly Schedule Changes

• Report recommends that QSEs change their schedule every 15 minutes to address this issue

• The two larger market participants already schedule flexibly and help mitigate the problem

Portfolio Offers in BES Market

• Less than half of available capability is offered in the BES market, rises to 75% at the highest load conditions

• Largest QSE offers much higher share of its available energy than smaller QSEs

• Participants offer a little more than can actually be deployed in a single interval

Portfolio Ramp Rate

• The portfolio ramp rate imposes limitations on deployment that do not exist where there is unit specific bidding and unit specific ramp rates are specified

• The result is reduced ability of the market to fully utilize the generating resources and inefficient BES prices

Ramp Rate recommendation

• Have multiple “sub-QSE” portfolio offers to reduce the ramp limitation effect of the single portfolio ramp rate

• Long run: go with unit specific bidding

Quick Start Capacity Availability• Not all available capacity is offered into the

market, partly because gas turbine capacity (ERCOT has 3000 MW quick start capacity) is difficult to offer in the BES market for several reasons:– Timing of the Balancing market (10 minute notice is

not enough time to start quick start units)– Supplier does not know if a high price will last for

more than 1 or 2 intervals, making it risky to start the unit

– ERCOT validation procedures remove offline gas turbines from portfolio offers

Resource Plan Manipulations

• Units that are frequently committed out-of-merit are regularly indicated as not being on line in the DA RP, yet are voluntarily committed prior to real time whenever ERCOT does not issue OOMC instruction

• 2/3 are located in DFW area

Resource Plan Manipulations

• Units that frequently receive OOME up payments are scheduled lower in RT RP than they actually operate in periods when they receive no OOME instructions

• Result: increased frequency and magnitude of OOMC and OOME payments

Resource Plan Manipulations

• Report Recommendations:– Create new DFW zone– If this is not possible, assign local congestion

costs directly to the load in the constrained area

– Long term: go nodal

Competitive Performance

• Pivotal supplier analysis:– When load obligations are considered,

suppliers in ERCOT are rarely pivotal– However, because so much available energy

is not offered in the BES market, a supplier was pivotal in 10% of all hours and in 24% of hours when load exceeded 40 GW

– Factors that prevent the full utilization of the available energy make market vulnerable to manipulations

Competitive Performance

• No general trends or patterns indicating physical or economic withholding was found

• Potential for localized instances of physical or economic withholding was not analyzed