Memorandum. This is a status report only. No Board Action is required. Executive Summary

Transcription

1 California Independent System Operator Memorandum To: Operations Committee From: Anjali Sheffrin, Ph.D., Director of Market Analysis cc: ISO Board of Governors; ISO Officers Date: June 8, 25 Re: Market Analysis Report for April and May 25 This is a status report only. No Board Action is required. Executive Summary Weather in April and early May was unseasonably cold and wet, causing loads to follow patterns typical of winter. In mid-may, temperatures across California began to increase to levels characteristic of early summer. Loads climbed to a peak of 36,369 megawatts (MW) on May 25. During April and May, energy schedules were short of actual load by approximately 2.5 percent. Meanwhile, uninstructed deviations, resulting in over-generation, more than compensated for the moderate under-scheduling. Consequently, the real-time market was characterized overwhelmingly by the need for decremental dispatches during this period. Decrementing generation, in addition to strong hydroelectric production during the spring runoff period, caused prices for both day-ahead bilateral and real-time balancing energy prices to remain low, relative to the magnitude of loads and current high fuel prices. Prices for real-time balancing energy averaged $37.52 and $29.1 per megawatt-hour (MWh) in April and May, respectively. Real-time intertie dispatch volumes have returned to levels seen prior to the settlement problem associated with inter-tie bids in the deployment of the Real-Time Market Application (RTMA) under Phase 1B. The Federal Energy Regulatory Commission s (FERC) acceptance of Amendment 66 to the CAISO Tariff on March 24 immediately addressed the identified issue. The costs of managing real-time intra-zonal congestion for the first five months of 25 totaled approximately $64 million, or half that for the same period in 24. The CAISO committed a smaller number of resources under the Must-Offer Obligation, as high levels of generation and transmission resource availability provided it with the ability to meet moderate loads. Minimum-load cost compensation fell to $5 million in April 25, compared to $18 million in April 24. Out-ofsequence re-dispatch premium costs to mitigate intra-zonal congestion were $3 million in April 25, compared to $5 million in April 24. The ancillary services markets have exhibited periods of bid insufficiency. Few units have been able to provide reserves, as spring seasonal runoff forces hydroelectric resources typically heavy suppliers of ancillary services to choose either to generate power or to spill water. Thermal units Created by: CAISO Last Update: ISO DMA/drb 151 Blue Ravine Road 6/9/25 Folsom, California 9563 (916)

2 are frequently at or near minimum loading levels in the spring months. As a result, there has often been little unloaded capacity available to provide regulation and spinning reserve services. Day ahead and hour ahead inter-zonal congestion costs were low in April, totaling $.8 million, but increased significantly in May to $6.7 million. These costs largely were the result of scheduled maintenance and deratings on COI and Path 26. I. Market Trends Affecting Electricity Demand and Supply Loads were moderate through early May; and higher thereafter Moderate under-scheduling was offset by uninstructed deviations Path upgrades and new generation should help meet summer peak load Hydroelectric resources supply large amounts of energy during spring runoff Loads. Loads in April 25 did not rise to the extent of those in March and April 24 resulting from that season s spring heat wave. April 25 experienced mild weather, as loads averaged 24,896 megawatts (MW), 2.2 percent below the 25,445 MW level seen in April 24 when temperatures were approximately 5 degrees warmer on average. Average April 25 loads were 5.5 percent above the average of 23,598 MW of April 23, which was unseasonably cool. Temperatures and loads from April 1 through April 22, 25, were similar to the same period in 24; loads were.4 percent lower than in 24. The daily average trough (minimum) load, a measure that tends to be resistant to changes in weather, was.3 percent lower in April 25 than in April The following chart compares hourly loads in April 25 to those in April Loads prior to 25 are adjusted by day of the week and for the exit of WAPA-served load from the ISO Control Area. Baseline loads in both 23 and 24 are adjusted using 24 estimated WAPA loads, as 23 WAPA loads were not available. ISO DMA/drb Page 2 of 27

3 Figure 1. California ISO Actual Loads, April 25 v. April 24 4, Apr 25 Actual Loads Apr 24 Actual Loads 35, 3, MW 25, 2, 15, 3-Apr 29-Apr 28-Apr 27-Apr 26-Apr 25-Apr 24-Apr 23-Apr 22-Apr 21-Apr 2-Apr 19-Apr 18-Apr 17-Apr 16-Apr 15-Apr 14-Apr 13-Apr 12-Apr 11-Apr 1-Apr 9-Apr 8-Apr 7-Apr 6-Apr 5-Apr 4-Apr 3-Apr 2-Apr 1-Apr Loads in May were moderate until approximately May 12, at which point the temperature warmed rapidly and loads increased. The high temperatures persisted through the last week in May. Overall, the average May 25 load of 26,91 MW was 2.5 percent below the average May 24 load, and 3.1 percent above the average May 23 load. The decrease in average trough of 1.1 percent from May 24 to May 25 was the sharpest decline since May 22 to May 23, another mild-weather season. The chart immediately below compares loads in May 25 to those in May 24. The table that follows shows load growth trends for months through May 25. Figure 2. California ISO Actual Loads, May 25 v. May 24 5, May 25 Actual Loads May 24 Actual Loads 4, MW 3, 2, 1, 31-May 3-May 29-May 28-May 27-May 26-May 25-May 24-May 23-May 22-May 21-May 2-May 19-May 18-May 17-May 16-May 15-May 14-May 13-May 12-May 11-May 1-May 9-May 8-May 7-May 6-May 5-May 4-May 3-May 2-May 1-May ISO DMA/drb Page 3 of 27

4 Table 1. Monthly Year-to-Year Load Growth Indices through May 2 Avg. Hrly. Load Avg. Daily Peak Avg. Daily Trough Monthly Peak June-4 6.6% 6.9% 6.1% -4.7% July-4.7%.3% 1.9% 4.% August-4 1.%.6%.6% 5.2% September-4 3.4% 3.5% 3.4% 1.1% October-4-1.4% -2.8% 1.5% -5.9% November-4 4.2% 3.9% 3.9% 6.6% December-4 4.4% 4.1% 6.5% 3.4% January-5 1.8% 2.8% 1.2% 5.% February-5 1.5% 1.8% 2.2%.3% March-5-2.3% -2.2% -.6% -5.2% April-5-2.2% -3.6% -.3% -22.9% May-5-2.5% -2.9% -1.1% -9.3% Underscheduling and Uninstructed Energy. As we reported in recent Market Analysis Reports, the real-time market has operated overwhelmingly in the decremental direction, despite schedules that were short of actual load through early May 25. Real-time over-generation historically has occurred during periods of forward schedules in excess of actual load. In this case the surplus of generation is largely due to the significant volume of uninstructed energy. The actual volume of uninstructed energy is technically difficult to capture; however, the following discussion includes measures of settled uninstructed energy from resources that have entered into participating generation agreements (PGA) with the CAISO. In particular, settled uninstructed energy excludes uninstructed energy from many qualifying facility (QF) generators, which are nonparticipating generators. To provide an example of settled uninstructed energy contributing to over-generation, the following chart compares hourly actual load to generation other than real-time in-sequence dispatches, for March 24, 25, one of the most recent days for which settled uninstructed energy data were available at the time of writing. 2 Until 7/1/3: Actual loads at top of hour. Since 7/11/3: Hourly average loads. ISO DMA/drb Page 4 of 27

5 Figure 3. Hourly Load v. Non-RTMA-Dispatched Energy, March 24, , Scheduled Volume Must-Offer MW OOS/OOM Energy Settled Uninstructed Energy Ramping energy Self-fulfilled schedule losses 35, Real-time RMR Actual Load 3, 25, 2, 15, MW 2-May Date and Hour Ending This situation, in which settled uninstructed energy averaged approximately 7 MW in afternoon and evening hours, came at a time when the CAISO Control Area was already awash with energy. This has been the case through April and early May, as hydroelectric resources generate large volumes of energy during the spring runoff season. Meanwhile, many thermal resources ramp upward to meet contracted generation schedules between 6: and 7: a.m. This leaves few units available to reduce generation output in these hours. This is especially problematic during the spring, as load pull times vary due to changes in daylight hours, and loads tend to be low. As a result, the load pull is not synchronized with the generation ramp, and operators have been scrambling to balance generation to meet load. We can attribute the settled uninstructed deviations to two primary groups of generators. Qualifying facilities, which account for approximately 24 percent of metered in-state generation, produced 42 percent of the settled uninstructed energy 4 between January 1 and March 26, 25, the most recent time period for which metered generation data are available. We attribute most of the remainder of settled uninstructed energy to large generation facilities. These generators provide approximately 72 percent of metered generation overall, and 47 percent of uninstructed energy. Portions of their generation are not modeled in the real-time market application (RTMA) software algorithm and is considered uninstructed. For example, the RTMA software does not calculate expected energy when a unit is just starting up and ramping to its officially filed minimum load, or conversely and when a unit is ramping below minimum load as it is being shut down, despite the fact that the generators continue to produce energy at these times. 3 Uninstructed energy calculations are available on a 45-day (or longer) lagged basis. 4 Percentages of uninstructed energy and metered generation exclude units whose ownership category is not specified in the CAISO Master File. ISO DMA/drb Page 5 of 27

6 This accounts for the bulk of generation, particularly during the startup ramp between 6: and 7: a.m., signaling the beginning of the peak hour period. Municipally owned generators account for the remainder of uninstructed energy. Total uninstructed energy has been estimated to be in the neighborhood of 5 to 1, MW, depending on the time of day. This suggests that unaccountable uninstructed energy, primarily from the non-participating QFs, may be as much as 75 percent or more of total uninstructed energy. Non-participating generators will not be subject to uninstructed deviation penalties if and when they go into effect. The following chart shows settled uninstructed energy from participating generators, by ownership category and time of day, for January through March, 25, the most recent period for which data are available. Figure 4. Settled Uninstructed Energy by Participating Generator Ownership Category January 1 through March 26, Average of STTL_UIE 25 2 Megawatts Hour of Day UNIT_CATEGORY Major Unit Muni QF OPR HR Outages and New Generation. Path 26 has been intermittently derated as work progresses on an upgrade that, when combined with updated remedial action schemes (technical maximumthroughput studies) and associated equipment, ultimately will raise the path rating to a maximum of 4, MW. The Miguel Import Limit one of the CAISO grid s primary causes of intra-zonal congestion -- is also in the process of being upgraded with the new Miguel Mission #2 23 kv line. The upgraded 5 Uninstructed energy calculations are available on a 45-day (or longer) lagged basis. ISO DMA/drb Page 6 of 27

7 line should become operational by June 6, 25. This will raise the binding constraint at the Miguel Substation, for a net increase of approximately 4 MW. On May 5, Calpine s Pastoria combined-cycle generation facility (769 MW total) began an initial phase of commercial service, providing 25 MW. When fully deployed, Pastoria will be one of the largest base-load gas-fired power plants in Southern California. Pastoria is connected to the Southern California Edison grid south of Path 26, serving SP15 directly. Calpine s Metcalf Energy Center, a 62 MW combined-cycle plant near San Jose, became commercial on May 27, 25. Two mothballed combustion-turbine generators in Southern California, Mandalay 3 (132 MW) and Goleta Ellwood (56 MW), have returned to operation. This should help to provide additional peaking capacity when needed during the upcoming summer. The following chart shows weekly average outages by type and peak load through May. 2, 18, Figure 5. Weekly Average Outages v. Weekly Peak Load, through May 25 Forced Planned Approved Must-Offer Waiver Load (right axis) 1, 9, 16, 8, 14, 7, 12, 6, MW Outages 1, 5, MW - Load 8, 6, 4, 2, 6-Jun-4 13-Jun-4 2-Jun-4 27-Jun-4 4-Jul-4 11-Jul-4 18-Jul-4 25-Jul-4 1-Aug-4 8-Aug-4 15-Aug-4 22-Aug-4 29-Aug-4 5-Sep-4 12-Sep-4 19-Sep-4 26-Sep-4 3-Oct-4 1-Oct-4 17-Oct-4 24-Oct-4 31-Oct-4 7-Nov-4 14-Nov-4 21-Nov-4 28-Nov-4 5-Dec-4 12-Dec-4 19-Dec-4 26-Dec-4 2-Jan-5 9-Jan-5 16-Jan-5 23-Jan-5 3-Jan-5 6-Feb-5 13-Feb-5 2-Feb-5 27-Feb-5 6-Mar-5 13-Mar-5 2-Mar-5 27-Mar-5 3-Apr-5 1-Apr-5 17-Apr-5 24-Apr-5 1-May-5 8-May-5 15-May-5 22-May-5 4, 3, 2, 1, Hydroelectric conditions. The robust 25 California hydroelectric season is in full swing. Production has averaged above 4, MW in recent weeks. In comparison, the 24 hydro season peaked early due to a spring heat wave, and had already begun to decline by late April. The following chart shows weekly average hydroelectric production through May. ISO DMA/drb Page 7 of 27

8 Figure 6. Weekly Average Hydro Production in the CAISO Control Area: 24-5 v Hydro Generation 24 Hydro Generation Average Hydro Generation (MW) Nov 7-Dec 14-Dec 21-Dec 28-Dec 4-Jan 11-Jan 18-Jan 25-Jan 1-Feb 8-Feb 15-Feb 22-Feb 29-Feb 7-Mar 14-Mar 21-Mar 28-Mar 4-Apr 11-Apr 18-Apr 25-Apr 2-May 9-May 16-May 23-May 3-May Week Beginning Natural Gas Prices. Gas prices spiked in early April, following trends nationally in prices for natural gas as well as other fossil fuels such as petroleum. This occurred despite the fact that gas storage conditions remain above five-year averages. Spot prices have followed trends in futures contracts. This is likely due, in part, to global and domestic concerns for high future demand for natural gas, as most new and planned power plant construction uses natural gas technology. Prices reached highs in excess of $7 per million British Thermal Units (MMBtu) at PG&E Citygate on April 3. Since that week, prices retreated by late May to the lowest seen in 25, closing at approximately $5/MMBtu as the hydro season and mild weather alleviated reliance on natural gas. The following chart shows weekly gas prices at regional delivery points through May. Figure 7. Weekly Average Natural Gas Prices through May $8. PG&E Citygate (Northern CA) Henry Hub (National) SoCal Border (Southern CA) $7. $6. $5. 11/28/24 12/5/24 12/12/24 12/19/24 12/26/24 1/2/25 1/9/25 1/16/25 1/23/25 1/3/25 2/6/25 2/13/25 2/2/25 2/27/25 3/6/25 3/13/25 3/2/25 3/27/25 4/3/25 4/1/25 4/17/25 4/24/25 5/1/25 5/8/25 5/15/25 5/22/25 5/29/25 Price ($/MMBtu) Week Beginning ISO DMA/drb Page 8 of 27

9 Regional Day-ahead Electricity Prices. Day ahead bilateral trade prices peaked for the year on April 1. They ranged between $55 and $6/MWh regionally, and then fell steadily as a result of moderate loads and abundant hydro energy. Mid-Columbia posted a low of $34.28/MWh the week of May 22. Bilateral prices largely tracked natural gas prices until the hydro generation caused an increase in supply. While Pacific Northwest supply conditions have been tight, 6 the region s limited storage capacity results in significant energy production this time of year, despite the below average snow pack. The following chart shows weekly average bilateral power prices in California and at neighboring delivery points through mid-may. Figure 8. Weekly Average Day-Ahead Bilateral Electricity Prices through mid-may $9 Northern California Peak Price Southern California Peak Price M id-colum bia Peak Price COB Peak Price Palo Verde Peak Price $8 $7 Price ($/MWh) $6 $5 $4 $3 31-Oct-4 7-Nov-4 14-Nov-4 21-Nov-4 28-Nov-4 5-Dec-4 12-Dec-4 19-Dec-4 26-Dec-4 2-Jan-5 9-Jan-5 16-Jan-5 23-Jan-5 3-Jan-5 6-Feb-5 13-Feb-5 2-Feb-5 27-Feb-5 6-Mar-5 13-Mar-5 2-Mar-5 27-Mar-5 3-Apr-5 1-Apr-5 17-Apr-5 24-Apr-5 1-May-5 8-May-5 15-May-5 Week Beginning II. Real-Time Market Performance Real-time activity was primarily decremental, as uninstructed deviations more than offset under-scheduling Must-Offer and intra-zonal congestion were low through April Market-clearing prices (MCPs) for real-time balancing energy exhibited wide swings in April and May. Prices were noticeably large in the negative direction, frequently reaching -$25/MWh, during periods of over-generation. During these instances, real-time dispatched generators receive payment of $25 for each megawatt-hour not generated. These low prices occur especially during the morning and evening load ramps, and to a lesser extent during the generation downward ramp between 9: and 11: p.m., when loads tend to be quite low. The CAISO often runs into decremental bid insufficiency during these periods, and may have to dispatch reliability must run and/or out-of-market decremental dispatches to meet load. The insufficiency tends to occur within 6 Natural Resources Conservation Service (U.S. Department of Agriculture), Weekly Report: Snowpack/Drought Monitor Update, May 19, 25, ftp://ftp.wcc.nrcs.usda.gov/support/drought/dmrpt pdf. ISO DMA/drb Page 9 of 27

10 NP15, but is sometimes system-wide. For the most part, the incentives to provide decremental bids exist, but units are not available to provide them. Several factors come into play to cause this lack of decremental bid sufficiency : Hydroelectric resources are producing significant energy from run-off. They often must spill water when decremented, or may face other water management constraints unrelated to power production. While thermal generators provide power during daytime peak hours, many are shut off at night. As they ramp toward scheduled operating targets during the morning ramp, they cannot be decremented, as this would cause them to miss their schedules. As a result, they often are operating below certified minimum load during this period. Path 26 has been derated in the north-to-south direction for upgrade work. As loads have begun to increase in southern California, transmission of power from NP15 to SP15 has frequently reached the path limit. In that case, NP15 units, which are disproportionately hydroelectric, must reduce generation output wherever possible, as SP15 energy is incremented. A small number of resources have been submitting decremental energy bids priced below $/MWh. Some of these units are hydroelectric, and bid in this manner to avoid dispatch for water management reasons during the hydro runoff season. The Department of Market Analysis has confirmed that one unit, in particular, bids a decremental price of -$25/MWh in an attempt to avoid frequent dispatches, as this unit apparently requires a manual process to be dispatched. The following tables show monthly average prices and total energy in peak, off-peak, and all hours, for in-sequence and out-of-sequence dispatched real-time balancing energy, for April and May. The tables also show average loads and under-scheduling. As we noted earlier, decremental dispatches in the presence of under-scheduling are due primarily to uninstructed energy. ISO DMA/drb Page 1 of 27

11 Table 2. Real-Time In-Sequence and Out of Sequence Average Prices and Total Energy, Average Loads, and Under-scheduling, for April 25 In-Seq. RT Dispatch OOS/OOM Dispatch Total Dispatch Average Loads and % Underscheduling PEAK OFFPEAK ALL $ /MWh $ 12.1 /MWh $ /MWh 27,165 MW (9.5) GWh (92.4) GWh (182.9) GWh 2.1% $ /MWh $ 1.73 /MWh $ /MWh 21,781 MW (27.6) GWh (35.9) GWh (63.5) GWh 2.8% $ /MWh $ 9.13 /MWh $ /MWh 24,896 MW (118.1) GWh (128.3) GWh (246.4) GWh 2.4% Table 3. Real-Time In-Sequence and Out of Sequence Average Prices and Total Energy, Average Loads, and Under-scheduling, for May 25 In-Seq. RT Dispatch OOS/OOM Dispatch Total Dispatch Average Loads and % Underscheduling PEAK OFFPEAK ALL $ /MWh $ /MWh $ 29. /MWh 28,778 MW (214.1) GWh 12.7 GWh (21.4) GWh 2.4% $ /MWh $ /MWh $ /MWh 22,682 MW (67.8) GWh 3.1 GWh (64.7) GWh 2.8% $ /MWh $ /MWh $ 29.1 /MWh 26,91 MW (281.9) GWh 15.8 GWh (266.1) GWh 2.6% The following charts show hourly profiles of net real-time dispatch and average prices in April and May. Figure 9. Hourly Profile of Real-Time Average Prices and Dispatch: April 25 Net Dispatch (MW) Net In-Seq. M W h Net OOS/OO M M W h Net In-Seq. Avg. Price Net OOS/OOM Avg. Price Hour of Day ISO DMA/drb Page 11 of 27

12 Figure 1. Hourly Profile of Real-Time Average Prices and Dispatch: May 25 Net Dispatch (MW) Net In-Seq. MWh Net OOS/OOM MWh Net In-Seq. Avg. Price Net OOS/OOM Avg. Price Hour of Day Price Volatility. The decremental price spikes tend to be punctuated by rapid swings in prices during the morning, evening, and end-of-peak ramps. Loads move rapidly during these periods, and often are not synchronized with generation ramps. Loads tend to fluctuate with changes in weather and daylight, while generation schedules are hourly, and many are in fixed blocks from 6: a.m. to 1: p.m. Thus, a price can move, say, from -$25/mwh to $169/mwh between two adjacent intervals as load overtakes a schedule (plus uninstructed and other energy) in the middle of an hour, and RTMA switches from dispatching the entire decremental bid stack to dispatching the entire incremental bid stack, or vice-versa. On May 14, a technical problem caused a large unit in SP15 to increment from a zero schedule to 371 MW between midnight and approximately 6:3 a.m., contributing to generation in excess of load of approximately 1, MW. Meanwhile, the RTMA market-clearing price ranged between - $.1 and -$25/MWh almost continuously between 3: and 7: a.m., as the decremental bid stack was fully dispatched. Control area frequency peaked at 6.14 hertz at 6:16 a.m. The CAISO issued an over-generation emergency, enabling neighboring control areas to purchase energy out of market, reducing the excess generation. The CAISO contracted an in-state unit to decrement out of market, and also manually instructed the unit that was above schedule down to zero output, which it did so by 6:3 a.m. Real-Time Imports. Amendment 66 to the CAISO tariff has been in effect since March 24, 25. As a result of this rule change, which addressed a market flaw, dispatched bids from system resources (imports and exports) in the real-time market are now paid as bid, and do not receive the market-clearing price. Since its implementation, import dispatch volumes have diminished substantially, while export volumes appear to be consistent with those prior to implementation of the Amendment. This has the effect of returning total dispatch volumes approximately to the range ISO DMA/drb Page 12 of 27

13 seen prior to the implementation of RTMA on October 1, 24, when dispatches also were largely in the decremental direction. For more information on real-time import bidding behavior, please refer to the section on Amendment 66 in Issues under Review. The following chart shows weekly average real-time dispatched volume from in-state generation and imports. Figure 11. Weekly Average Real-Time Dispatch Volume from Imports and Internal Generation through May Volume (MW) Incremental Internal Generation Imports Decremental Internal Generation Exports May-4 Jun-4 Jul-4 Aug-4 Sep-4 Oct-4 Nov-4 Dec-4 Jan-5 Feb-5 Mar-5 Apr-5 May-5 Month Intra-zonal (within zone) congestion. Total intra-zonal congestion costs in the CAISO control area consist of the summation of three different cost components. 1. MLCC costs are incurred day-ahead as units are constrained on so as to be available to provide energy if called upon. 2. RMR costs are incurred in real-time as RMR units are the first to be dispatched to relieve intrazonal congestion. 3. Re-dispatch costs are also incurred in real-time if the RMR dispatches are not sufficient to alleviate the constraint. In March, incremental OOS dispatch volumes were largely unchanged from February. CAISO operators called a total of 1,164 MWh of incremental energy out-of-sequence (OOS) by to address intra-zonal congestion in April. The average price paid was $65.1/MWh in April, and the net cost (re-dispatch premium) in excess of the market clearing price (MCP) was approximately $12, or $1.71/MWh in April. Total OOS dispatch volume was 133 GWh (INC plus DEC) and the average re-dispatch premium was $22.79/MWh. This was an increase from the March average. These figures are shown graphically in the chart below for recent months. 7 7 OOS net cost or re-dispatch premium is calculated as total re-dispatch cost minus unconstrained dispatch cost, which is the equivalent dispatch cost at the zonal MCP. The premium reflects the increased cost of re-dispatch and any potential mark-up above marginal cost. ISO DMA/drb Page 13 of 27

14 Decremental dispatch volumes decreased. This resulted in a decrease in the combined incremental and decremental re-dispatch premium. The decrease in decremental premium was more pronounced. April OOS dispatches resulted in a re-dispatch premium of approximately $3. million. Figure 13. Out-of-Sequence Volume and Average Re-dispatch Premium 6 Volumes and Premiums Decremental MWh (Left Axis) Incremental MWh (Left Axis) Decremental Avg Premium (Right Axis) Incremental Avg Premium (Right Axis) Thousands of MWH $/MWh Apr-4 May-4 Jun-4 Jul-4 Aug-4 Sep-4 Oct-4 Nov-4 Dec-4 Jan-5 Feb-5 Mar-5 Apr-5 While over-generation in the real-time market in 25 has been due primarily to uninstructed deviations, the excess in 24 was largely due to generation from units held at minimum load pursuant to the Must-Offer Obligation. This Must-Offer energy is now accounted for by the RTMA software. Units held at minimum load per Must-Offer are entitled to cost compensation for this generation. Must-Offer procurement in April and early May 25 was minimal, given the availability of generation resources and moderate loads. Beginning approximately May 13, the first week of 25 with warmer weather, the CAISO began committing units actively by declining applications to the Must-Offer Obligation in order assure that generation would be available to meet high loads and manage intra-zonal congestion. 8 OOS net cost or re-dispatch premium is calculated as total re-dispatch cost minus unconstrained dispatch cost, which is the equivalent dispatch cost at the zonal MCP. The premium reflects the increased cost of re-dispatch and any potential mark-up above marginal cost. ISO DMA/drb Page 14 of 27

15 The Department of Market Analysis has estimated total costs associated with intra-zonal congestion through May 25. These estimates indicate that costs due to intra-zonal congestion in the first five months of 25 totaled $64 million, approximately half that in the same period in 24. The following chart shows monthly total costs attributed to intra-zonal congestion through May 25. Figure 16. Intra-Zonal Congestion Costs through May 25 9 $5 $45 Real-time Out-of-Sequence Redispatch Premium Minimum-Load Cost Compensation (Must-Offer) Reliability Must-Run $4 $35 Costs ($ Millions) $3 $25 $2 $15 $1 $5 $ Jan-3 Feb-3 Mar-3 Apr-3 May-3 Jun-3 Jul-3 Aug-3 Sep-3 Oct-3 Nov-3 Dec-3 Jan-4 Feb-4 Mar-4 Apr-4 May-4 Jun-4 Jul-4 Aug-4 Sep-4 Oct-4 Nov-4 Dec-4 Jan-5 Feb-5 Mar-5 Apr-5 May-5 Month III. Ancillary Services Markets Performance Increase in bid insufficiency from April to May. April s ancillary services (A/S) markets bid insufficiency metrics increased only slightly over the March postings. This proved, however, only to be the calm before the storm as spring rains and snow melt played heavily on May bid insufficiency levels. The number of bid insufficient hours increased by six from 7 hours in March to 76 hours in April. The total for May reached 131 hours, the highest level since January MLCC: January - March 25 are based on settlement figures. April and May 25 are both based on Market Quality estimates with an empirically-based -2% correction for non-compliance. May 25 is based on data from only the first 12 days of the month, inflated to represent the entire month. RMR: January - May 25 are based on Market data for RMR real-time dispatches. Variable cost consists predominantly of fuel cost payments; other incidental variable costs may be included in settlement statements. Values are variable cost net of SC Payments at the ISO Settlement-level Price. R-T Redispatch: January - May 25 are based on Market data for Out-of-stack dispatches. Redispatch cost is defined as the excess payments beyond the resource specific price for an out-of-stack dispatch. ISO DMA/drb Page 15 of 27

16 The graphic below displays the count of bid insufficient hours for each service in the day-ahead markets for April and May. Figure 14. Count of Bid Insufficient Hours in April and May 25 Count of Hours Apr 3-Apr 5-Apr 7-Apr 9-Apr 11-Apr 13-Apr 15-Apr 17-Apr 19-Apr 21-Apr 23-Apr 25-Apr 27-Apr 29-Apr 1-May 3-May 5-May 7-May 9-May 11-May 13-May 15-May 17-May 19-May 21-May 23-May 25-May 27-May 29-May 31-May Hours_NS Hours_SP Hours_RD Hours_RU Market Supply. Overall supply of capacity to the A/S markets progressively increased from March to April and into May. Most notably, bid volumes in the regulation and non-spin reserve markets all increased between 12.5 and 45 percent. The seemingly disparate existence of an increase in both supplied capacity and bid insufficiency primarily in the regulation markets -- occurs because hydroelectrics, which typically supply A/S, must generate or spill water, and thus cannot efficiently provide A/S. Some of the units that have stepped in to bid in the A/S markets are mid-range (steam and combined-cycle) and peaking units. That portion of mid-range thermal participating in the capacity markets lacks the dynamic capabilities of the usual hydro A/S market supplier and tends to be scheduled primarily for on-peak periods. Consequently, the markets are offering a flexibility premium during the off-peak ramps, at times in excess of $9 per MW. DMA will fully confirm this market effect upon the completion of an A/S capacity study that is underway. ISO DMA/drb Page 16 of 27

17 The chart below summarizes bid volumes by price bin for April and May Figure 18. Ancillary Service Day-Ahead Average Bid Volume by Price Bin <$5 $5-15 $15-3 $3-5 $5-9 >$9 Purchased MW Apr 5 May 5 Apr 5 May 5 Apr 5 May 5 Apr 5 May 5 Regulation Up Regulation Down Spinning Reserve Non-Spinning Reserve Market Prices. Increases in the market clearing prices of the spin and regulation up services, by 56 and 15 percent, respectively, raised the aggregate price of A/S from March values. Regulation down prices fell 2 percent during the same period, while non spin prices were up just 5 percent. The following table reports ancillary service product requirements and average prices for April and May. Table 4. Average Ancillary Service Requirements and Prices Average Required (MW) Weighted Average Price ($/MW) RU RD SP NS RU RD SP NS Apr $ $ $ $ 1.13 May $ 24.4 $ $ $ 1.76 A/S procurement, in total, increased 1.1 percent between March and April, while remaining essentially unchanged through May. The weighted average price of ancillary services dropped slightly from $1.81 in March to $1.76 in April, but bounced up to $12.6 in May, a 17 percent increase month over month. The monthly average cost to load for A/S was flat from March into April at about $1 per MWh, but stepped up, with prices, posting $1.11 per MWh for May, an 11 percent increase. The table below provides a comparison of month over month A/S procurement, while the following chart captures price trends over the most recent six months of market activity. The final chart depicts A/S cost to load for the past two months. ISO DMA/drb Page 17 of 27

18 Table 5. Peak and Off-Peak Ancillary Service Procurement and Pricing Apr 5 May 5 Difference Average AS Procured (MW) Weighted Average Price ($/MW) On-Peak Off-Peak All Hours On-Peak Off-Peak All Hours RU $ 2.29 $ $ RD $ 13.3 $ $ SP $ $ 4.62 $ NS $ 1.24 $.87 $ 1.13 Total $ $ 9.94 $ 1.76 RU $ $ $ 24.4 RD $ $ 27. $ SP $ $ 8.94 $ NS $ 1.93 $ 1.35 $ 1.76 Total $ $ $ 12.6 RU $ 4.12 $ 6.5 $ 4.9 RD $ (.31) $ (4.41) $ (1.72) SP $ 2.34 $ 4.32 $ 2.91 NS $.69 $.48 $.63 Total $ 1.76 $ 1.99 $ 1.84 Figure 16. Weekly Weighted Average Ancillary Service Prices $/MW RU_PRICE RD_PRICE SP_PRICE NS_PRICE Dec Jan Feb Mar Apr May Week Beginning ISO DMA/drb Page 18 of 27

19 Figure 2. Summary Ancillary Service Cost to Load Non-Spin Spin Reg_Dn Reg_Up Monthly Average Apr 3-Apr 5-Apr 7-Apr 9-Apr 11-Apr 13-Apr 15-Apr 17-Apr 19-Apr 21-Apr 23-Apr 25-Apr 27-Apr 29-Apr 1-May 3-May 5-May 7-May 9-May 11-May 13-May 15-May 17-May 19-May 21-May 23-May 25-May A/S Cost to Load ($/MWh) 27-May 29-May 31-May IV. Inter-zonal Congestion Interzonal congestion cost totaled $.8 million in April, slightly lower than the $.9 million in March. Interzonal congestion costs in April were largely due to transmission constraints on the Palo Verde, IPPDCADLN, COI, and Eldorado Interties. Congestion costs increased to $6.7 million in May, due primarily to path derates of the California-Oregon Intertie (COI) and Path 26. Inter-zonal congestion costs totaled $.8 million in April, slightly lower than the $.9 million in March. The vast majority of all congestion in April was on four paths, the Palo Verde branch group (73 percent), the IPPDCADLN branch group (11 percent), the California-Oregon Intertie (COI) (7 percent), and the Eldorado branch group (6 percent). ISO DMA/drb Page 19 of 27

20 Table 6. Inter-Zonal Congestion Costs in April 25 Branch Group Day-ahead Hour-ahead Total Congestion Cost Total Congestion Cost Total Congestion Cost Total Cost Percent Import Export Import Export Import Export Day-ahead Hour-ahead CASCADE $ $ $ $ $ $ $ $ $ % COI $24,96 $ $31,277 $ $56,237 $ $24,96 $31,277 $56,237 7% ELDORADO $45,33 $ $1 $ $45,35 $ $45,33 $1 $45,35 6% IPPDCADLN $82,923 $ $3,36 $ $85,96 $ $82,923 $3,36 $85,96 11% MEAD $ $ $17 $ $17 $ $ $17 $17 % NOB $ $ $9,173 $ $9,173 $ $ $9,173 $9,173 1% OLNDAWAPA $ $ $ $56 $ $56 $ $56 $56 % PALOVRDE $558,531 $ $6,492 $ $565,23 $ $558,531 $6,492 $565,23 73% PATH15 $ $ $5,44 $ $5,44 $ $ $5,44 $5,44 1% PATH26 $ $ $3,96 $ $3,96 $ $ $3,96 $3,96 1% WSTWGMEAD $4,46 $ $ $ $4,46 $ $4,46 $ $4,46 1% Total $715,764 $ $58,947 $56 $774,711 $56 $715,764 $59,453 $775,217 1% The Palo Verde branch group was congested in the import direction (east-to-west) for 2 percent of all hours in the day-ahead (DA) market at an average congestion price of $4/MWh, and 3 percent of all ours in the hour-ahead (HA), at an average congestion price of $18/MWh. Most of the congestion on Palo Verde in DA occurred on April when the line was derated from 2,2 MW (import direction) to 1, MW caused by line de-energizing to change CT ratios. The line returned to normal work starting HE2 on April 17. The rest of the congestion on Palo Verde in DA was due, in large part, to wheeling energy from the southwest to northern California where DA bilateral prices were higher. IPPDCADLN, a new intertie associated with Southern PTOs, became effective January 1, 25 between zone LA5 and LA7. The tie point is at IPPDC_5_ADLNTO, i.e., the IPP Adelanto Schedule Point. IPPDCADLN was congested for 4 percent of all hours in the DA import direction (from LA5 to LA7) at an average congestion price of $4/MWh. IPPDCADLN was congested for 1 percent of all hours in the HA import direction at an average price of $36/MWh. Congestion on IPPDCADLN was mainly due to over-scheduling. COI was congested for 2 percent of all hours in the DA import direction (from Oregon to California) at an average congestion price of $1/MWh. COI was congested for 3 percent of all hours in the HA import direction at an average price of $3/MWh. COI experienced almost daily deratings throughout the month due to various line/capacitor outages and scheduled line work. For instance, DA congestion cost on April 1 st was caused by derating on COI in import direction from 48 MW to 3 MW from HE8 to HE1 due to scheduled work on Round Mountain-Table Mountain #1 5kV line. DA congestion on COI also occurred on April 16th and when the path was derated due to the Round Mountain-Table Mountain #1 5kV line being cleared for re-insulation and installation of shunt splices. COI was derated again on April 27 because of a Round Mountain- Table Mountain #2 5kV line scheduled outage. The Eldorado branch group also experienced significant congestion cost in DA import direction. Most of the congestion cost was caused by line deratings. For instance, congestion on Eldorado in ISO DMA/drb Page 2 of 27

21 DA occurred on April 4 th, HE1 when the path was derated from 1555 MW to 455 MW due to the Eldorado-Moenkopi 5kV line being de-energized to repair a line reactor at Moenkopi. Table 7. Inter-Zonal Congestion Prices and Frequencies in April 25 Percentage of Hours Being Congested (%) Day-Ahead Market Average Congestion Price ($/MWh) Percentage of Hours Being Congested (%) Hour-ahead Market Average Congestion Price ($/MW h) Import Export Import Export Import Export Import Export CASCADE _BG 1 $ COI _BG 2 $1 3 $3 ELDORADO _BG 2 $6 1 $9 IPPDCADLN_BG 4 $4 1 $36 MEAD _BG 2 $ NOB _BG 2 $4 OLNDAWAPA_BG $5 PALOVRDE _BG 2 $4 3 $18 PATH15 _BG $5 PATH26 _BG $25 SUMMIT _BG $ WSTWGMEAD_BG 2 $3 Inter-zonal congestion costs increased to $6.7 million in May, significantly higher than the $.8 million in April. The vast majority of all congestion in May was on five paths, Path 26 (44 percent), BLYTHE (15 percent), the California-Oregon Intertie (COI) (12 percent), NOB (11 percent), and Palo Verde (11 percent). Table 8. Inter-Zonal Congestion Costs in May 25 Branch Group Day-ahead Hour-ahead Total Congestion Cost Total Congestion Cost Total Total Cost Congestion Percent Cost Import Export Import Export Import Export Day-ahead Hourahead BLYTHE $97,713 $ $ $ $97,713 $ $97,713 $ $97,713 15% CASCADE $ $ $1 $ $1 $ $ $1 $1 % COI $778,385 $ $19,723 $ $798,18 $ $778,385 $19,723 $798,18 12% IPPDCADLN $482,366 $ $5 $ $482,371 $ $482,366 $5 $482,371 7% NOB $732,97 $ $11,971 $ $744,68 $ $732,97 $11,971 $744,68 11% PALOVRDE $743,696 $ $2,139 $ $745,835 $ $743,696 $2,139 $745,835 11% PATH26 $ $2,992,823 $ -$68,271 $ $2,924,552 $2,992,823 -$68,271 $2,924,552 44% TRACYWAPA $ $ $ $7 $ $7 $ $7 $7 % TRCYWSTLY $ $ $2 $ $2 $ $ $2 $2 % WSTWGMEAD $889 $ $91 $ $98 $ $889 $91 $98 % Total $3,77,257 $2,992,823 $33,839 -$68,264 $3,741,96 $2,924,559 $6,7,8 -$34,425 $6,665,655 1% Path 26 was congested for 8 percent of all hours in the DA export direction (north-to-south) at an average congestion price of $33/MWh. Path 26 was congested for 6 percent of all hours in the HA export direction at an average price of $22/MWh. Congestion on Path 26 was due to path deratings that occurred from May 18 HE6 to May 22, HE17. During this time period, the Midway- Vincent #3 5kV line was removed from service for scheduled tests and line work and Path 26 ISO DMA/drb Page 21 of 27

22 transfer capability was derated from 34 MW to 19 MW north-to-south and from 3MW to 698 MW south to-north. Table 9. Inter-Zonal Congestion Prices and Frequencies in May 25 Day-Ahead Market Hour-ahead Market Percentage of Hours Being Congested (%) Average Congestion Price ($/MWh) Percentage of Hours Being Congested (%) Average Congestion Price ($/MWh) Import Export Import Export Import Export Import Export BLYTHE _BG 4 $177 2 $42 CASCADE _BG 3 $ 5 $ COI _BG 14 $5 1 $12 IPPDCADLN_BG 2 $68 2 $14 NOB _BG 18 $3 13 $21 PALOVRDE _BG 1 $6 1 $11 PATH26 _BG 8 $33 6 $22 COI was congested for 14 percent of all hours in the DA import direction (from Oregon to California) at an average congestion price of $5/MWh. COI was congested for 1 percent of all hours in the HA import direction at an average price of $12/MWh. COI experienced almost daily deratings throughout the month due to various line/capacitor outages and scheduled line work. For instance, DA congestion on COI on May 13 was caused by deratings due to the Round Mountain- Table Mountain #2 5kV line being out of service. NOB also experienced high congestion cost in day-ahead and hour-ahead in the import direction, due in part to path deratings. For instance, NOB has been derated since May 14 due to Celilo- Sylmar 1 kv converters 3 and 4 at Celilo being cleared for scheduled work. There was also other line work and testing on the NOB related part of the system. COI Usage. The COI transmission system consists of three 5kV AC lines (2 PACI and 1 COTP). The COI branch group is part of the COI/NW-Sierra and PDCI north-to-south operating nomogram (AC/DC Nomogram), which conforms operation to the WECC Minimum Operating Reliability Criteria and protects the WECC system during heavy export conditions from the northwest to the southwest. The CAISO and BPA system dispatchers operate the AC/DC Nomogram in coordination. For the past several months, COI experienced almost daily deratings due to various scheduled line work/outages. The following chart shows the actual final hourly flows on COI on April this year compared to April last year. It shows on average the usage of COI in April this year is lower than last year. In fact, the total final flow on COI was 1,13,51 MWh last April and 93,167 MWh this April. ISO DMA/drb Page 22 of 27

23 MW Figure 22. Actual Hourly Final Flow on COI in April 24 and Hour MW Figure 24. Actual Hourly Final Flow on COI in May 24 and Hour V. Firm Transmission Rights A firm transmission right (FTR) is a right that has the attributes of both financial and physical transmission rights. FTRs entitle their owners to share in the distribution of usage charge revenues received by the CAISO (in the day-ahead and hour-ahead markets) in connection with inter-zonal congestion during the period for which the FTR is issued. FTRs also entitle registered FTR holders to certain scheduling priorities (in the day-ahead market) for the transmission of energy across a congested inter-zonal interface. FTR Scheduling. FTRs can be used to hedge against high congestion prices and to establish scheduling priority in the day-ahead market. As shown in the following table, a high percentage of FTRs were scheduled on a few paths in April (74 percent on ELDORADO, 65 percent on IID-SCE, 5 percent on PALOVRDE, 96 percent on SILVERPK, and 24 percent on Path 26). Southern California Edison Company and municipals primarily own the FTRs on these paths. ISO DMA/drb Page 23 of 27

24 Table 1. FTR Scheduling Statistics for April 25* Branch Group Direction MW FTR Auctioned Avg. MW FTR Sch. Max MW FTR Sch. Max Single SC FTR Sch. % FTR Schedule COI _BG IMP % ELDORADO _BG IMP % IID-SCE _BG IMP % IPPDCADLN_BG IMP % MEAD _BG IMP % MEADTMEAD_BG IMP % MKTPCADLN_BG IMP % MONAIPPDC_BG IMP % NOB _BG IMP % PALOVRDE _BG IMP % SILVERPK _BG IMP % VICTVL _BG IMP % WSTWGMEAD_BG IMP % MKTPCADLN_BG EXP % NOB _BG EXP % PATH26 _BG N->S % *only those paths on which 1% or more of FTRs were attached are listed. ** The FTRs on these paths were awarded to municipal utilities that converted their lines under the ISO operation and there were not released in the primary auction. In May, FTRs were scheduled on more paths than in April. Again a high percentage of FTRs were scheduled on a few paths in May (77 percent on ELDORADO, 74 percent on IID-SCE, 43 percent on PALOVRDE, 1 percent on SILVERPK, and 29 percent on Path 26). ISO DMA/drb Page 24 of 27

25 Table 11. FTR Scheduling Statistics for May 25* Branch Group Direction MW FTR Auctioned Avg. MW FTR Sch. Max MW FTR Sch. Max Single SC FTR Sch. % FTR Schedule BLYTHE _BG IMP % COI _BG IMP % ELDORADO _BG IMP % IID-SCE _BG IMP % IPPDCADLN_BG IMP % MEAD _BG IMP % MEADTMEAD_BG IMP % MKTPCADLN_BG IMP % MONAIPPDC_BG IMP % NOB _BG IMP % PALOVRDE _BG IMP % PARKER _BG IMP % SILVERPK _BG IMP % VICTVL _BG IMP % WSTWGMEAD_BG IMP % ELDORADO _BG EXP % MEAD _BG EXP % MEADMKTPC_BG EXP % MKTPCADLN_BG EXP % MONAIPPDC_BG EXP % NOB _BG EXP % PATH26 _BG EXP (N->S) % *only those paths on which 1% or more of FTRs were attached are listed. ** The FTRs on these paths were awarded to municipal utilities that converted their lines under the ISO operation and there were not released in the primary auction. FTR Revenue per Megawatt. The following table summarizes the FTR revenue collected starting April 1, 25. Only Palo Verde (Import direction) had significant positive FTR revenues, $3,936/MWh, due to a higher occurrence of congestion. IPPDCADLN has the second highest FTR revenue, $399/MWh. This was also due to higher occurrence of congestion. ISO DMA/drb Page 25 of 27

26 Table 12. FTR Revenue Per MW ($/MW) Net $/MW FTR Rev Branch Group Direction April May Cum. Net $/MW FTR Rev Pro Rated Net $/MW FTR Rev Auction Price BLYTHE IMPORT 5,143 5,143 3,861 6,714 COI IMPORT 159 2,81 2,24 13,438 18,69 ELDORADO IMPORT ,71 IPPDCADLN IMPORT 399 2,241 2,639 15,836 MEAD IMPORT 1 18,174 NOB IMPORT 35 3,674 3,79 22,256 2,79 PALOVRDE IMPORT 3,936 3,963 7,899 47,397 27,425 PATH15 IMPORT ,56 VI. Issues under Review Intertie Bid Sufficiency. The CAISO filed Amendment 66 on March 24, 25 with FERC to modify the settlement rules for intertie bids under RTMU Phase 1B. As part of MRTU Phase 1B implemented on October 1, 24, hourly pre-dispatched energy from system resources financially settles based on a bid or better concept. More specifically, incremental (decremental) energy settles for each applicable hour based on the higher (lower) of the resource s hourly bid price or the simple average of the 12 five-minute dispatch interval zonal Ex Post prices (MCP). In Amendment 66, the CAISO proposed to modify the CAISO Tariff so that bids for incremental and decremental energy on inter-ties with neighboring control areas that are pre-dispatched by the CAISO are settled under a pay as bid" rule. With this modification, bids would be paid (or pay the CAISO) their original bid price, rather than the bid or better in effect since October 1, 24. In its April 7, 25 order on Amendment 66, FERC approved the pay as bid settlement rule effective as of March 24 until the earlier of September 3, 25 or the effective date of a long-term solution filed and accepted by the Commission. FERC also ordered the CAISO's Department of Market Analysis (DMA) to file weekly reports on the market effects of these interim tariff provisions, including the liquidity and sufficiency of bids at the inter-ties until the earlier of the effective date of a future tariff change implementing a long-term solution or September 3, 25. DMA observed that the volume of inter-tie bids received by the CAISO dropped slightly immediately after implementation of Amendment 66, but has subsequently increased to a level approximately equal to or greater than the level in the week prior to Amendment 66. The following chart shows the monthly average daily incremental and decremental bid volume since October 24. DMA will continue monitoring and analyzing the issues of inter-tie bid sufficiency and liquidity over a longerterm basis. ISO DMA/drb Page 26 of 27

27 Figure 26. Monthly Average Daily Incremental and Decremental Bid Volume 1 5 MW Oct-4 Nov-4 Dec-4 Jan-5 Feb-5 Mar-5 Apr-5 Month Avg. Daily Inc Bid Volume Avg. Daily Dec Bid Volum e ISO DMA/drb Page 27 of 27