Power Markets

During the cold wave in the middle of November, wind generation output decreased by 40 GWh while solar generation output was same as last year despite an addition of 18 GW of solar capacity additions. Wind generation in Pacific Northwest was zero (out of 5 GW capacity) for multiple days. The result was higher natural gas generation output and strong natural gas basis (PGT Malin basis realized $2.5/MMBTU while TETCO M3 basis was at $2/MMBTU), which resulted in strong moves for December and January natural gas basis (+$3.5/MMBTU in PGT Malin December basis and +$2/MMBTU in January TETCO M3 Basis). Clearly, this dependence in natural gas system will only get worse as the rest of coal generation retires and are replaced by renewable generation (and short duration BESS).

Every year the day demand in New England is 300 - 400 MWh lower. Given that night demand is almost flat in the last few years. this can be explained mostly by behind-the-meter solar panel additions. ISO indicates that year on year addition is around 800 MW , which explains most of the demand reduction. Given ISOs forecast (done before IRA), that should continue to the foreseeable future.

The impact of BESS in ERCOT ancillary market became more obvious during this month.

1. Despite higher power prices, all of the ancillary prices were lower, breaking the fundamentally driven correlation between them.

2. The biggest hit was to prices of the RRS in which the overbidding strategy by BESS is still rampant. Its price is now lower than the price for the Reg-up service.

3. Prices for Non-spin service (a product that will rarely be called) were the highest as BESS were not allowed to participate in it anymore (which may be due to NPRR 1096)

4. The reg down, "get-paid-to-charge service", continued its trend toward zero.

The wind generation in Pacific Northwest (PNW) is the most volatile, and probably, the least predictable in the US. It can swing from 3 GW to 0 within a day and can stay at low levels for multiple days. Given the output swings versus the demand in that region, its impact in Mid C prices is substantial. It ranges from 2 to 4 heat rates depending on the demand and hydro levels. That impact is actually muted because BPA and other hydro operators adjust their hydro output to the wind generation levels while Southwest pulls less power from PNW during low wind periods. The wind generation capacity factors in that region barely reaches 20%. As a result of this unreliability and low capacity factors, there has been very little capacity addition in the last 5 years despite renewable power and clean energy standards in Oregon and Washington.

Despite the higher power prices, the coal generation in PJM is lower than last year and that is still not helping to build coal stocks.

The major problem seems to be the coal deliveries to PJM system. Despite the persistent high power prices, the deliveries are not higher than last fall.

Given how much PJM is exporting to SERC as well as MISO, the low coal stocks may not be the problem in PJM.

PJM real time market provided the best energy revenue in June. Despite similar price levels to MISO, PJM system was more volatile due to low coal generation due to lack of coal stocks.

High DART spread in ERCOT resulted in lower real time revenue compared to the day ahead market. Although for the year the real time revenue is higher, the spread may not be high enough to justify real time bidding due to higher unpredictability of real time prices.

Northeast state prices were lower compared to other ISOs and also a lot less volatile, partially due to oversupply and low temperatures.

Although the power prices in ERCOT doubled compared to last year, the change in revenue was minimal or negative.

Three fold higher prices in PJM resulted in plenty of volatility to double the revenue.

SP15 prices and the volatility may reflect the impact of the new battery additions.

ERCOT peak demand growth looks to be around 4 GWs (about 6 %) compared to last year, which is incredible for a region with peak demand of 75 GW and 392 TWh of total consumption in 2021. ERCOT power demand ranks 11, just below France. Only two countries (China and India) in the top ten have electricity demand growing faster than ERCOT and EIA expects the world electricity demand to grow around 3.5% this year.

The growth is driven by crypto miners (40%-50%), migration (20% - 25%), drilling in the west (15%) and Industrial growth (10% - 25%).

30% - 40% of this demand growth is located in the Houston area, 30% is in the Dallas area, 20% is coming from the Permian Basin and the rest is in the Austin and San Antonia areas. It is interesting that despite the reports that crypto miners are located in central and west Texas, Houston area demand growth dominates the other areas. This begs the question if there are some crypto miners around Houston.

Unabated migration, high oil and natural gas prices, and new planned industrial facilities should continue to keep the demand growth healthy for the next few years while the crypto miners will be the biggest source of uncertainty.