The Southwest Power Pool (SPP) Market Monitoring Unit on Jan. 16 published the SPP State of the Market report for fall 2018, noting, for instance, that the hourly average load of fall 2018 was up around 4% from fall 2017. Overall, the hourly average load for fall 2018 was nearly 29,000 MW, which was up about 4% from fall 2017.
Average monthly real-time generation increased by about 5% from fall 2017 to fall 2018, the report said, adding that the percent of total generation provided by coal-powered resources continued to fall, accounting for 42% of energy produced in fall 2018, which is down from 50% in fall 2016, and from 45% in fall 2017. During that same period, wind resources accounted for 23% of total generation, which is up from 20% in fall 2016, but down from fall 2017 when wind resources accounted for 26% of total generation, the report said.
The percentage of total generation provided by combined-cycle and simple-cycle natural gas resources have remained consistent from 2016 to 2018, the report said, adding that due to the spike in wind and nuclear generation in fall 2017, the increased generation from those resources tended to offset generation by gas resources.
Wind capacity in the footprint continues to grow steadily, with nameplate wind capacity increasing from 15,200 MW at the end of November 2016, to just under 20,000 MW at the end of November 2018, the report said.
The wind capacity factor in the real-time market dropped from 42% in fall 2017 to 35% in fall 2018, while the day-ahead wind capacity factor dropped from 33% to 28% during the same period. The report added that lower wind generation totals, coupled with increased wind capacity, drove that drop in capacity factor. The spread between the real-time and the day-ahead wind capacity indicates a disconnect in the amount of wind in the real-time market, compared to the forecast wind in the day-ahead market, the report said.
The report also noted that during fall 2018, the average day-ahead price was $27/MWh, an increase of 35% from fall 2017, and an increase of 11% over fall 2016. The report said that the average real-time prices mirrored the trend of day-ahead prices, with nearly identical prices. Higher loads, increasing natural gas prices, and lower wind output were factors in increasing prices during that period compared to previous years, the report said.
Discussing external transactions, the report noted that its Integrated Marketplace has more than 6,000 MW of AC interties with the Midcontinent ISO (MISO) to the east, 810 MW of DC ties to ERCOT to the south, and more than 1,000 MW of DC ties to the Western Electricity Coordinating Council (WECC) to the west. In addition, SPP has more than 1,500 MW of interties with the Southwestern Power Administration (SPA) in Arkansas, Missouri, and Oklahoma, and more than 5,000 MW of AC interties with the Associated Electric Cooperative (AECI) in Oklahoma and Missouri.
The report also noted that it began the market-to-market (M2M) process with MISO in March 2015. That process allows the monitoring and non-monitoring RTOs to efficiently manage market-to-market constraints by exchanging such information as shadow prices, and using the RTO with the more economic dispatch to address flows, the report said. The shadow price indicates the marginal value of an additional increment of relief on a congested constraint in reducing the total production costs, the report noted.
Each RTO is allocated property rights on market-to-market constraints, with those rights known as firm flow entitlements (FFE). Each RTO calculates its real-time usage, known as market flow, the report added, noting that RTOs exchange money – market-to-market settlements – for redispatch based on the non-monitoring RTO’s market flow in relation to its FFE. The non-monitoring RTO receives money from the monitoring RTO if its market flow is below its FFE, the report said, adding that the non-monitoring RTO pays the monitoring RTO if its market flow is above its FFE.
For fall 2018, market-to-market payments were nearly even between SPP and MISO at a total of $363,000 paid to SPP. Total payments from MISO to SPP were $3.2m, while payments from SPP to MISO were $2.9m, the report added, noting that that is down from fall 2017, when total payments from MISO to SPP were nearly $15m, primarily due to high levels of congestion on the Neosho-Riverton for the loss of the Neosho-Blackberry constraint. That constraint has been less congested over the last several months, the report said.
Of market prices, the report noted that following an extended period of gas prices averaging between $2/MMBtu and $3/MMBtu, the November 2018 average gas price at the Panhandle Eastern hub climbed to $3.67/MMBtu, which is the highest gas price at the Panhandle Eastern hub since November 2014. The fall 2018 average gas price of $2.86/MMBtu represents an 11% increase over the fall 2017 price. The report added that during fall 2018, the average day-ahead energy price was $27.22/MWh, and the average real-time price was $27.36/MWh, with those prices representing a 35% increase for the day-ahead market, and a 33% increase for the real-time market over the fall 2017 energy prices.
The increase in energy prices from 2017 to fall 2018 of 33% and 35% outweigh the 11% increase in gas prices during that same period, the report said, adding that there are additional factors causing prices to increase, including higher loads, a decline in wind generation, and a reduction in the frequency of negative prices.
The areas with highest prices in the footprint for fall 2018 are concentrated in three areas – the southeast corner of the SPP footprint, northwest North Dakota, and northwest Kansas – the report said, adding that the lowest prices in the footprint for fall 2018 were found in western Nebraska. Congestion in those areas contributed to the high and low prices, the report said.
Further discussing congestion, the report noted that during fall 2018, the most congested flowgate was found in the Tulsa area – TMP270_23432 (Cleveland-Cleveland AECI 138-kV (GRDA-AECI) – for the loss of Cleveland-Tulsa North 345-kV (GRDA-CSWS). The next most congested flowgate was found in North Dakota – TMP269-23661 (Charlie Creek-Watford 230-kV ftlo Charlie Creek-Patentgate 345-kV (WAUE), SPP said, adding that three of the top 10 most congested flowgates were near Hays, Kan.
The most congested flowgate over the past 12 months has been Vine Tap-North Hays 115-kV for the loss of Post Rock-Knoll 230-kV, displacing the Neosho-Riverton 161-kV for the loss of Neosho-Blackberry 345-kV constraint, SPP said. While the Vine Tap-North Hays 115-kV flowgate was highly congested up through November 2018, an upgrade was energized in that area in early December 2018. Vine Tap-North Hays 115-kV continues to appear with congestion after the upgrade, but now appears on the Knoll 230/115-kV transformer constraint, SPP noted.
Overall, real-time market congestion decreased from the last fall period, with nearly 20% of intervals having no congestion in fall 2018, up from 16% in fall 2017, and 2% of all intervals in fall 2016. SPP added that the Woodward-Tatonga-Matthewson 345-kV project, which was completed in February 2018, has helped reduce congestion in the western portion of the footprint.
Among other things, SPP said that during fall 2018, load-serving entities earned $73m in congestion payments, SPP said, adding that those payments did not exceed their day-ahead congestion cost of $103m. Real-time congestion costs aided load-serving entities, reducing the total congestion cost to $100m. SPP added that when compared to fall 2017, the 2018 shortfall between congestion payments and total congestion costs decreased by 46%, from nearly $50m to $27m.
The shortfall between the congestion payments and the day-ahead congestion cost shows that overall, for the quarter, load-serving entities did not fully hedge congestion through the congestion hedging market, SPP said. However, the effectiveness of the positions will ultimately be evaluated over the full course of the 2018 Transmission Congestion Right (TCR) year, SPP said, adding that day-ahead congestion costs for load-serving entities decreased 8% when compared to fall 2017.