8 Western Energy Imbalance Market
On November 1, 2014, the California Independent System Operator Corporation (CAISO) and Portland based PacifiCorp fully activated the Energy Imbalance Market (EIM). This real-time market is the first of its kind in the West. The Energy Imbalance Market allows balancing authorities outside of the CAISO balancing authority area to voluntarily take part in the imbalance energy portion of the CAISO locational marginal price-based real-time market. PacifiCorp, the CAISO, and market participants participated in market simulations prior to the start of the Energy Imbalance Market on November 1, including parallel production from October 1 to November 1.
The EIM uses state-of-the-art software to analyze regional grid needs and make available low-cost generation to meet demand every five minutes. It can bring many benefits to the West such as cost savings, improving the efficiency of dispatching resources, facilitating the renewable integration, more reliability, etc.
On December 1, 2015, NV Energy, the Nevada-based utility successfully began participating in the western Energy Imbalance Market (EIM). With the addition of NV Energy, the EIM expands into Nevada, where the utility serves 2.4 million customers.
On October 1, 2016, Phoenix-based Arizona Public Service (AZPS) and Puget Sound Energy (PSEI) of Washington State successfully began full participation in the western Energy Imbalance Market. With the addition of Arizona Public Service and Puget Sound Energy, The EIM is serving over 5 million consumers in California, Washington, Oregon, Arizona, Idaho, Wyoming, Nevada and Utah.
On October 1, 2017, Portland General Electric Company (PGE) became the fifth western utility to successfully begin full participation in the western Energy Imbalance Market. PGE joins Arizona Public Service, Puget Sound Energy, NV Energy, PacifiCorp and the ISO, together serving over 38 million consumers in eight states: California, Arizona, Oregon, Washington, Utah, Idaho, Wyoming and Nevada.
On April 4, 2018, Boise-based Idaho Power (IPCO) and Powerex of Vancouver (BCHA), British Columbia successfully entered the EIM, allowing the ISO’s real-time power market to serve energy imbalances occurring within about 55 percent of the electric load in the Western Interconnection. The eight western EIM participants serve more than 42 million consumers in the power grid stretching from the border with Canada south to Arizona, and eastward to Wyoming.
On April 3, 2019, Sacramento Municipal Utility District (SMUD), part of the Balancing Authority of Northern California (BANC), successfully began full participation in the Western EIM, becoming the first publicly owned agency to be an EIM entity in the Western EIM.
On April 1, 2020, Seattle City Light (SCL) and Salt River Project (SRP) successfully joined the Western EIM. The two utilities serve about 1.5 million customers in the West’s first real-time energy market. Together with Salt River Project and Seattle City Light, the current EIM participants represent 61 percent of the load in the Western Electric Coordinating Council (WECC).
On March 25, 2021, the Turlock Irrigation District (TIDC) and the Balancing Area of Northern California (BANC) Phase 2, comprised of the Modesto Irrigation District, the City of Redding, the City of Roseville, and the Western Area Power Administration – Sierra Nevada Region, began participating in the West’s first real-time energy market.
On April 1, 2021, Los Angeles Department of Water and Power (LADWP) and the Public Service Company of New Mexico (PNM) joined the Western Energy Imbalance Market (EIM). PNM’s entrance into the Western EIM expands the real-time energy market into New Mexico.
On June 16, 2021, NorthWestern Energy (NWMT) began participating EIM. With the addition of NorthWestern Energy, Western EIM extends its footprint to Montana and serves consumers in ten states, including portions of Arizona, California, Idaho, Nevada, New Mexico, Oregon, Utah, Washington, Wyoming, and Montana.
On March 2, 2022, Avista Utilities (AVA) and Tacoma Power (TPWR) became the new members of the Western Energy Imbalance Market (WEIM), with both utilities serving a combined 600,000 electric customers in the Pacific Northwest.
On May 3, 2022, the Bonneville Power Administration (BPAT) and Tucson Electric Power (TEPC) both formally joined the WEIM, becoming the new participants in the WEIM. The WEIM now has 19 participants serving 77% of the demand for electricity in the Western United States.
EIM Prices
Figure 36, and Figure 37 show daily simple average ELAP prices for PACE, PACW, NEVP, AZPS, PSEI, PGE, IPCO, BCHA, SCL SRP, BANC, TIDC, LADWP, PNM, NWMT, AVA, TPWR, BPAT and TEPC for on-peak hours, and, off-peak hours respectively in FMM. Figure 38 show daily simple average ELAP prices for PACE, NEVP, AZPS, PSEI, PGE, IPCO, BCHA, SCL SRP, BANC, TIDC, LADWP, PNM, NWMT, AVA, TPWR, BPAT and TEPC for all hours in FMM. On September 1 and 6-8, the prices for most EIM entities were elevated due to high system-wide load driven by the heat wave.
Figure 36: EIM Simple Average LAP Prices (On-Peak Hours) in FMM
Figure 37: EIM Simple Average LAP Prices (Off-Peak Hours) in FMM
Figure 38: EIM Simple Average LAP Prices (All Hours) in FMM
Figure 39 shows daily simple average ELAP prices for PACE, PACW, NEVP, AZPS, PSEI, PGE, IPCO, BCHA, SCL SRP, BANC, TIDC, LADWP, PNM, NWMT, AVA, TPWR, BPAT and TEPC for on-Peak Hours in RTD. Figure 40, and Figure 41 show daily simple average ELAP prices for PACE, PACW, NEVP, AZPS, PSEI, PGE, IPCO, BCHA, SCL SRP, BANC, TIDC, LADWP, PNM, NWMT, AVA, TPWR, BPAT and TEPC for off-Peak hours, and all Hours, respectively in RTD. On September 1 and 6, the prices for most EIM entities were elevated due to high system-wide load driven by the heat wave.
Figure 39: EIM Simple Average LAP Prices (On-Peak Hours) in RTD
Figure 40: EIM Simple Average LAP Prices (Off-Peak Hours) in RTD
Figure 41: EIM Simple Average LAP Prices (All Hours) in RTD
Figure 42 shows the daily price frequency for prices above $250/MWh and below $0/MWh in FMM. Prices are for PACE, PACW, NEVP, AZPS, PSEI, PGE, IPCO, BCHA, SCL SRP, BANC, TIDC, LADWP, PNM, NWMT, AVA, TPWR, BPAT and TEPC ELAPs. The cumulative frequency of prices above $250/MWh increased to 2.83 percent in September from 1.41 percent in August. The cumulative frequency of negative prices edged up to 0.61 percent in September from 0.50 percent in August.
Figure 42: Daily Frequency of EIM LAP Positive Price Spikes and Negative Prices in FMM
Figure 43 shows the daily price frequency for prices above $250/MWh and below $0/MWh in RTD. Prices are for PACE, PACW, NEVP, AZPS, PSEI, PGE, IPCO, BCHA, SCL SRP, BANC, TIDC, LADWP, PNM, NWMT, AVA, TPWR, BPAT and TEPC ELAPs. The graph may provide a trend of price spikes over time. The cumulative frequency of prices above $250/MWh increased to 1.63 percent in September from 0.82 percent in August. The cumulative frequency of negative prices increased to 0.98 percent in September from 0.66 percent in August.
Figure 43: Daily Frequency of EIM LAP Positive Price Spikes and Negative Prices in RTD
EIM Transfers
Figure 44 shows the daily volume of EIM transfer for CAISO in FMM. “Import” represents the total EIM transfer from other BAs into CAISO. “Export” represents the total EIM transfer out of CAISO to other BAs in FMM. Figure 45 shows the daily volume of EIM transfer for PACE. Figure 46 shows the daily volume of EIM transfer for PACW in FMM. Figure 47 shows the daily volume of EIM transfer for NEVP in FMM. Figure 48 shows the daily volume of EIM transfer for AZPS in FMM. Figure 49 shows the daily volume of EIM transfer for PSEI in FMM. Figure 50 shows the daily volume of EIM transfer for PGE in FMM. Figure 51 shows the daily volume of EIM transfer for BCHA in FMM. Figure 52 shows the daily volume of EIM transfer for IPCO in FMM. Figure 53 shows the daily volume of EIM transfer for BANC in FMM.
Figure 44: EIM Transfer for CAISO in FMM
Figure 45: EIM Transfer for PACE in FMM
Figure 46: EIM Transfer for PACW in FMM
Figure 47: EIM Transfer for NEVP in FMM
Figure 48: EIM Transfer for AZPS in FMM
Figure 49: EIM Transfer for PSEI in FMM
Figure 50: EIM Transfer for PGE in FMM
Figure 51: EIM Transfer for BCHA in FMM
Figure 52: EIM Transfer for IPCO in FMM
Figure 53: EIM Transfer for BANC in FMM
Figure 54 shows the daily volume of EIM transfer for CAISO in RTD. Figure 55 shows the daily volume of EIM transfer for PACE. Figure 56 shows the daily volume of EIM transfer for PACW in RTD. Figure 57 shows the daily volume of EIM transfer for NEVP in RTD. Figure 58 shows the daily volume of EIM transfer for AZPS in RTD. Figure 59 shows the daily volume of EIM transfer for PSEI in RTD. Figure 60 shows the daily volume of EIM transfer for PGE in RTD. Figure 61 shows the daily volume of EIM transfer for BCHA in RTD. Figure 62 shows the daily volume of EIM transfer for IPCO in RTD. Figure 63 shows the daily volume of EIM transfer for BANC in RTD.
Figure 54: EIM Transfer for CAISO in RTD
Figure 55: EIM Transfer for PACE in RTD
Figure 56: EIM Transfer for PACW in RTD
Figure 57: EIM Transfer for NEVP in RTD
Figure 58: EIM Transfer for AZPS in RTD
Figure 59: EIM Transfer for PSEI in RTD
Figure 60: EIM Transfer for PGE in RTD
Figure 61: EIM Transfer for BCHA in RTD
Figure 62: EIM Transfer for IPCO in RTD
Figure 63: EIM Transfer for BANC in RTD
EIM Cost Allocation
Figure 64 shows daily real-time imbalance energy offset cost for PACE, PACW, NEVP, AZPS, PSEI, PGE, IPCO, BCHA, SCL SRP, BANC, TIDC, LADWP, PNM, NWMT, AVA, TPWR, BPAT and TEPC respectively. Total RTIEO in September dropped to -$4.40 million from $7.15 million in August.
Figure 64: EIM Real-Time Imbalance Energy Offset by Area
Figure 65 shows daily real-time congestion offset cost for PACE, PACW, NEVP, AZPS, PSEI, PGE, IPCO, BCHA, SCL SRP, BANC, TIDC, LADWP, PNM, NWMT, AVA, TPWR, BPAT and TEPC respectively. Total RTCO charge rose to $22.96 million in September from $5.76 million in August.
Figure 65: EIM Real-Time Congestion Imbalance Offset by Area
Figure 66 shows daily bid cost recovery for PACE, PACW, NEVP, AZPS, PSEI, PGE, IPCO, BCHA, SCL SRP, BANC, TIDC, LADWP, PNM, NWMT, AVA, TPWR, BPAT and TEPC respectively. Total BCR inched down to $4.23 million in September from $5.22 million in August.
Figure 66: EIM Bid Cost Recovery by Area
Figure 67 shows the flexible ramping up uncertainty payment PACE, PACW, NEVP, AZPS, PSEI, PGE, IPCO, BCHA, SCL SRP, BANC, TIDC, LADWP, PNM, NWMT, AVA, TPWR, BPAT and TEPC respectively. Total flexible ramping up uncertainty payment in September increased to $458,695 from $328,618 in August. Figure 68 shows the flexible ramping down uncertainty payment PACE, PACW, NEVP, AZPS, PSEI, PGE, IPCO, BCHA, SCL SRP, BANC, TIDC, LADWP, PNM, NWMT, AVA, TPWR, BPAT and TEPC respectively. Total flexible ramping down uncertainty payment in September fell to -$5,863 from $4,751 in August. Figure 69 shows the flexible ramping forecast payment PACE, PACW, NEVP, AZPS, PSEI, PGE, IPCO, BCHA, SCL SRP, BANC, TIDC, LADWP, PNM, NWMT, AVA, TPWR, BPAT and TEPC respectively. Total forecast payment in September edged up to $210,894 from $203,409 in August.
Figure 67: Flexible Ramping Up Uncertainty Payment
Figure 68: Flexible Ramping Down Uncertainty Payment
Figure 69: Flexible Ramping Forecast Payment
The ISO’s Energy Imbalance Market Business Practice Manual describes the methodology for determining whether an EIM participating resource is dispatched to support transfers to serve California load. The methodology ensures that the dispatch considers the combined energy and associated marginal greenhouse gas (GHG) compliance cost based on submitted bids. The EIM dispatches to support transfers into the ISO were documented in Figure 70 and Table 12 below.
Figure 70: EIM Transfer into ISO by Fuel Type
| Month-Year | Coal (%) | Gas (%) | Water (%) | Other Non-Emitting (%) |
|---|---|---|---|---|
| Apr-2020 | 0.2% | 17.8% | 82.0% | 0 |
| Apr-2021 | 0.7% | 53.5% | 45.8% | 0 |
| Apr-2022 | 0.2% | 30.1% | 69.7% | 0 |
| Aug-2020 | 2.4% | 49.9% | 45.9% | 1.8% |
| Aug-2021 | 0.5% | 54.1% | 38.6% | 6.7% |
| Aug-2022 | 0.2% | 38.3% | 54.9% | 6.6% |
| Dec-2019 | 0.5% | 43.3% | 56.3% | 0.0% |
| Dec-2020 | 0.0% | 30.5% | 69.5% | 0 |
| Dec-2021 | 0.3% | 45.9% | 53.9% | 0 |
| Feb-2020 | 0.3% | 33.5% | 66.2% | 0 |
| Feb-2021 | 1.8% | 33.7% | 64.5% | 0.0% |
| Feb-2022 | 0.1% | 27.8% | 72.0% | 0 |
| Jan-2020 | 0.2% | 28.2% | 71.6% | 0.0% |
| Jan-2021 | 0.0% | 27.8% | 72.1% | 0 |
| Jan-2022 | 0.0% | 23.4% | 76.6% | 0 |
| Jul-2020 | 0.4% | 24.1% | 75.2% | 0.4% |
| Jul-2021 | 1.1% | 56.9% | 35.7% | 6.3% |
| Jul-2022 | 3.3% | 30.4% | 59.2% | 7.1% |
| Jun-2020 | 0.0% | 16.7% | 82.5% | 0.7% |
| Jun-2021 | 0.1% | 55.7% | 41.9% | 2.3% |
| Jun-2022 | 3.3% | 15.9% | 65.2% | 15.6% |
| Mar-2020 | 3.6% | 25.5% | 70.9% | 0.0% |
| Mar-2021 | 0.4% | 33.7% | 65.9% | 0 |
| Mar-2022 | 0 | 15.1% | 84.9% | 0 |
| May-2020 | 0.7% | 19.1% | 80.2% | 0 |
| May-2021 | 0.3% | 50.7% | 47.8% | 1.2% |
| May-2022 | 0.5% | 25.3% | 69.3% | 5.0% |
| Nov-2019 | 1.4% | 47.7% | 50.9% | 0.0% |
| Nov-2020 | 0.1% | 33.4% | 66.5% | 0 |
| Nov-2021 | 0.5% | 49.0% | 50.5% | 0 |
| Oct-2020 | 0.7% | 50.8% | 48.5% | 0 |
| Oct-2021 | 1.2% | 51.6% | 45.8% | 1.5% |
| Sep-2020 | 0.4% | 46.5% | 50.7% | 2.4% |
| Sep-2021 | 0.2% | 53.7% | 39.3% | 6.9% |
| Sep-2022 | 0.1% | 46.5% | 48.4% | 5.0% |