Weekly Energy Market Updates by Region - Archive




Issue week: August 21st, 2020  (Wk 34)





WEST Record-breaking temperatures along the entire West Coast have driven extreme demand and very high spot prices over the past week. Because tempera-tures have been high everywhere in the West, California has had to rely less on imported electricity and more on in-state physical generation. Consequently, the Day Ahead average in SP15 since last Thursday is $214/MWh. Forward prices also continue to rise in all regions because of the searing heat and expected lack of natural gas during the upcoming winter and next summer.

ERCOT  Term prices climbed higher this week, mainly because of rising term natural gas prices. The real-time market also surged over the past seven days, particularly over the weekend, which featured several hours of triple-digit prices. Moreover, the ORDC adder is now averaging just over $10/MWh for the month, raising the average for real-time prices to the low $30s/MWh in all zones but the South, where the average is near $80/MWh. All eyes will be on the development of the tropical systems in the Gulf of Mexico for their effect on next week’s activity.

EAST Prices have remained largely steady in the Northeast this week. PJM has seen the most action, Real Time prices there spiking to $115/MWh last evening because of underperforming demand in the Mid-Atlantic, which yielded strong north-south congestion on Bagley-Graceton. In PJM West Hub, yesterday’s Real Time on-peak average was $32/MWh, $8/MWh over the Day Ahead on-peak av-erage.









As the summer heat intensifies in the western United States, energy usage and prices are climbing. California’s grid is being particularly taxed. CAISO has already declared multiple Stage 2 and Stage 3 emergencies in the face of power deficits relative to peak loads. Essentially, regional utilities have been instructed to turn off power to whole areas of the state for specified periods to compensate for the lack of generation. The Golden State is clearly growing more vulnerable, especially in the late-evening hours, when solar generation dissipates and demand for electricity swells. CAISO’s infamous “duck curve,” shown below, high-lights just how much higher demand is after solar goes away. Moreover, the state’s overreliance on imported power is exposed whenever trans-mission is restrained and neighboring states endure their own heat waves. Compounding California’s problems, CAISO reported that the amount of dispatchable capacity in the state decreased by 200 megawatts for the 12 months from June 2019 to June 2020. It will probably continue to shrink, testing the state’s increased reliance on renewables and batter-ies. Although larger-scale battery farms on the horizon will add flexibility, the inevitable mothballing of additional generators may minimize their benefits. The bulk of new dispatchable capacity in California will come from batteries connected to renewables, but those green technologies are not likely to eliminate the need for rolling blackouts by themselves. They help the state meet its renewable-energy standards but inherently offer less flexi-bility for extended use at all hours of the day. Until that ideal solution presents itself to expand the supply of electricity at all times of spiking demand, building appropriate contingencies into a company’s energy portfolio can help shield it from the volatile energy prices common during these stretches.  




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