Weekly Energy Market Updates by Region - Archive




Issue week: July 30th, 2020  (Wk 31)





WEST High temperatures in the Pacific Northwest and California have pushed index prices up over the past week. In California, they have peaked above $100/MWh since Tuesday. In con-trast, forward prices keep trending down on the back of strong natural gas inventories amid increased reliance on natural gas pipelines to meet daily demand.

ERCOT  Having opened July around $40/MWh, real-time prices will end up averaging around $20/MWh for the month to highlight the potential benefits of having at least some in-dex exposure, even during volatile summer months. Despite high loads in the middle of the month, 4CP load curtailments and high wind output helped maintain sufficient reserve mar-gins. Although real-time prices have continued to average below $20/MWh over just the past week, outages related to Tropical Storm Hanna increased congestion in the South Load Zone to raise its average to $25/MWh. August 5x16 has fallen by approximately $30/MWh over the past month and, at $65/MWh, now presents a compelling buying opportunity for customers with remaining open positions for next month. In the forward market, the prompt 12-month 7x24 curve is now around $29/MWh, eliminating much of the steep backwardation present less than a month ago. The prompt 12-month strip is trading at a premium of only $1/MWh to 12-month strips down the curve.

EAST During the summer heatwave punishing the Northeast, DA and RT prices have stayed relatively stable, mostly in the mid-$20s/MWh, since last week. The largest increase is in ISO-NE, where DA prices are printing $4/MWh over last week and RT prices are printing $7/MWh over last week. In MISO, RT prices spiked at $313/MWh on Tuesday evening because of underperforming wind generation but, for the week, are averaging only $4/MWh above last week. Meanwhile, DA prices are lower than last week by $1/MWh.









Under normal circumstances, summertime is already rife with uncer-tainty for the energy industry, so this summer of COVID is especially tricky, not only for energy companies but also for other sectors of the economy. Indeed, the country is not yet fully operational, yet, as the midsummer report for Calpine Energy Solutions’ Capacity Obligation Reduction Effort (CORE) program reveals, loads have nonetheless been rather strong, thanks not so much to industrial electricity usage but more to the increase in residential consumption. Each of MISO, NYISO, ISO-NE, and PJM has already had multiple alerts of potential peak loads, and, although MISO’s peaks for this summer so far have lagged behind last year’s, the drop-off has not been nearly as large as expected, despite the ongoing shutdowns. Meanwhile, in PJM—which uses the highest coincident-peak hour on each of its five highest peak days to determine capacity charg-es—the five highest coincident peaks for the year to date are actual-ly 1 percent over the 2019 average. Moreover, as shown in the ta-bles below, the single highest coincident peak in PJM last year was more than 8,000 MW above the next highest, whereas the difference between any other two consecutive peaks on the list never topped 2,000 MW. Therefore, this one outlier is essentially all that separates this year from last year. Although 2020 has held surprisingly steady, two months remain in the CORE season. Still higher peaks may occur, and Calpine Ener-gy Solutions’ CORE team stands ready to send additional notices as needed. 




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