By Tom Kleckner

SPP’s winter real-time prices increased 4.6% from the previous year, according to the Market Monitoring Unit’s latest quarterly State of the Market report.

The report said real-time prices averaged $25.69/MWh, compared with $24.57 the previous winter, when prices jumped 37.9%. Day-ahead prices this winter averaged $24.07/MWh, 7 cents shy of the 2017 average.

The MMU reviewed the report, which covered December 2017 to February 2018, with market participants during a webinar Friday.

Also last week, the MMU released its annual State of the Market report, saying SPP’s market showed increasing flexibility and improving efficiency during 2017. The MMU had shared a draft with the RTO’s Board of Directors in April. (See “MMU Shares Draft of State of the Market Report,” SPP Board of Directors/Members Committee Briefs: April 24, 2018.)

The quarterly report noted average gas and electricity prices — which have historically been highly correlated — diverged slightly this year, with gas dropping from $3.08/MMBtu in 2017 to $2.64/MMBtu in 2018. Panhandle Eastern hub prices ranged from $2.50 to $2.80/MMBtu from February 2017 until January, when they spiked to $3.23/MMBtu during a cold snap.

SPP set three new winter peaks Jan. 16-17, topping out at nearly 43 GW. Oil-fired units set prices during the period that “routinely exceeded” $400/MWh in western Arkansas, eastern Texas and southern Missouri.

SPP and MISO were forced to use market-to-market redispatch Jan. 16-18, resulting in SPP collecting $2.66 million during that time. The Neosho-Riverton flowgate was responsible for most of the costs, as it has been since the two RTOs began the M2M process in March 2015. Congestion on the flowgate has resulted in $26.5 million in payments to SPP, more than half of the $51.4 million M2M charges MISO has incurred.

The MMU said the flowgate also caused Empire District Electric and the Missouri cities of Carthage and Springfield to see the highest winter prices in SPP’s footprint, with Carthage seeing average real-time prices of slightly more than $50/MWh.

Other highlights from the report include:

• An increase in the occurrence of negative price intervals, with winter 2018 levels higher than previous years.
• A nearly 7% increase in the hourly average load for winter 2018 from winter 2017. December 2017 was at a similar level to the prior year, but January and February 2018 average loads were nearly 11% higher, driven primarily by lower-than-normal temperatures.
• A 7% increase in average monthly real-time generation from winter 2017 to winter 2018. Coal-fired generation its downward trend, accounting for only 46% of energy produced during the winter. Wind resources accounted for 26% of total generation.
• A 36% day-ahead wind capacity factor, which increased to 46% in the real-time market. The disparity between day-ahead and real-time capacity factors contributed to the increase in negative price intervals.