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ANALYSIS: Central US power prices plunge as winter weather, gas prices weaken

Power prices in the Central US slid across the board in February compared to January, pushed lower by the much milder weather especially in the second half of the month, along with weaker gas prices.

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Out of the nine hubs in the Central US analyzed monthly by S&P Global Platts, day-ahead on-peak locational marginal prices at PJM AEP-Dayton Hub led the decrease, by moving lower by more than 50% month on month to the high $20s/MWh, while prices at other hubs moved down 25%-45% over the same time.

The Electric Reliability Council of Texas North Hub, ranking second in terms of price drop, fell by about 44% to average in the mid-$20s/MWh in February. Heating degree days in the ERCOT footprint in February sank by more than 46% from January and were about 13% below seasonal norms.

Likewise, Midcontinent Independent System Operator HDDs in February were down 20% from January but about 2% above seasonal averages.

Southwest Power Pool's HDDs in February fell by more than 24% from January but were 6% above seasonal norms.

Additionally, ERCOT and SPP registered about 19 and five cooling degree days respectively in the latter half of February, while they normally have zero in February.

ERCOT daily peakload was down by about 11% from January to average 43.2 GW, with MISO down by 8% to 83.5 GW and SPP down by 6% to 33.7 GW.

Freezing temperatures in January had pushed energy use in the area to new highs, as ERCOT demand reached a new winter high of 66 GW, with the MISO South region of Arkansas, Louisiana, Mississippi and Texas reaching 32 GW and the SPP counterpart topping 43 GW.

In comparison, ERCOT systemwide demand only topped 55 GW in February, MISO topping 93 GW and SPP topping 38 GW.

On the supply side, mild temperatures in February also kept a lid on the surging gas prices that started the new year, as spot gas prices at Houston Ship Channel fell by more than 35% on the month to average $2.629/MMBtu.


Rising wind generation in the central US also helped keep power prices in check, following a strong start in January, with SPP and ERCOT showing growth of 9% and 6% in February outputs over last year, respectively.

February wind generation in ERCOT averaged 197 GWh/d, the highest output in a February, and fourth highest month on record. During that month, wind generation accounted for 28% of total generation -- 3% more than the three-year average.

The highest daily output for wind generation was observed on February 19 at 365 MWh, the same day ERCOT set a new wind hourly generation record of 17.5 GW, surpassing the previous record of 17.4 GW set in January.

SPP wind output averaged 193 GWh/d in February, accounting for about 26% of total generation, which was the highest on record for February since Platts started tracking it in 2010.

The high wind pattern seemed to sustain into March as SPP set a wind penetration record of 58.1% on March 5, topping the previous record of 56.3% set on December 4.


ERCOT summer forward prices kept setting record highs in February, due to supply tightness expected this upcoming summer caused by generation retirements.

ERCOT North Hub August on-peak forwards started to jump in the last week of February, reaching an all-time high of $135/MWh on February 22 and breaking the years-old record of $133/MWh set in 2013, according to Platts M2MS data.

The August contract eventually settled at about $174/MWh on February 28, representing a jump of about 57% in February and a hike of about 79% in 2018.

So far in March, the firmness remains, as the August package settled at a staggering $194/MWh on March 6, rising $20, or 11% from the end of February.

In its latest Seasonal Assessment of Resource Adequacy report for the summer months of June through September, the grid operator projected peakload to reach around 73 GW, higher than the current all-time high of 71.1 GW set on August 11, 2016.

ERCOT expected total available generation resources to top 77.6 GW this summer, resulting in a reserve capacity of 4.9 GW, the difference between total available generation capacity and forecast peak demand, down from 8.7 GW for last summer.

The dwindling reserve capacity was mostly caused by several major generation resources retirements taking place before the summer.

More than 5 GW of fossil fueled generation were approved for retirement, based on dire economics for high-cost, less-efficient units. The bulk of retirements are coal-fired from Vistra Energy: 1.8-GW Monticello plant, 1.2-GW Sandow plant and 1.2-GW Big Brown plant.

-- Mark Watson and Jeff Zhou,
-- Edited by Matt Eversman,