Wholesale power prices for this summer likely less than market expects: analysts

Despite relatively strong weather-adjusted power demand, wholesale power prices for the remainder of the summer may be weaker than market forwards for much of the US, primarily resulting from gas-to-coal switching and stronger reserve margins, S&P Global Platts Analytics experts said July 21.

Under the heading "North America Power Mid-Summer Update: Are grid operators sweating reliability concerns?," power market analysts described the fundamentals at work in markets across the Lower 48 states, highlighting the following factors:

• Drought across the Western Interconnect and fires in the Pacific Northwest exacerbate weak hydro conditions, strong loads and burdening gas-fired generation.
• Weak wind output in the Southwest Power Pool and the Electric Reliability Council of Texas drive increased reliance on fossil generation.
• Surprisingly large generation outages in ERCOT pose upside risk for power prices.

Weather-adjusted power demand has grown at a 2.7% rate so far in 2021, up from year-on-year decreases of 1.7% in 2020 and 1.4% in 2019, analyst Kieran Kemmerer noted.

However, loads so far in July have matched Platts Analytics' pre-pandemic models, at the lower end of the recent five-year range.

Prices so far this summer

And Platts Analytics' August wholesale power price forecasts have been substantially below market expectations, judging from August forwards.

For example, New York Independent System Operator Zone J's August 2021 on-peak power settled July 20 at almost $54/MWh, substantially higher than the Platts Analytics' forecast around $40/MWh and about double the Aug. 20 average day-ahead on-peak locational marginal price of less than $27/MWh.

Similarly, ERCOT North Hub August 2021 on-peak packages settled July 20 around $120/MWh, about double Platts Analytics' forecast and the August 2020 average day-ahead on-peak locational marginal price of $51.30/MWh.

In the West, Mid-Columbia August 2021 on-peak packages settled on July 20 at almost $157/MWh, substantially more than the Platts Analytics forecast around $125/MWh and more than quadruple the August 2020 average of around $37/MWh.

"We have now seen three months of fairly strong recovery," said Morris Greenberg, Platts Analytics senior manager of North American power analytics, coinciding with a decrease in net dependable hydro capacity of about 3.9 GW, because of low inflow and reservoir levels.

Lower hydro power and coal retirements are joining heavier loads in boosting natural gas-fired generation, despite higher gas prices, Greenberg said, but the California ISO's resource adequacy rules have limited volatility to less than half the ranges seen at the Mid-Columbia and Palo Verde pricing points, which have spiked above $300/MWh and $400/MWh, respectively.

However, the devastating fires in the Pacific Northwest, should they expand in southern Idaho and Montana, could threaten the ability to deliver power to loads, posing upside price risk, Greenberg said.

Supply tightness in ERCOT

In ERCOT, low wind output in mid-June combined with unexpectedly large thermal generation outages to create tight conditions, prompting ERCOT to call for energy conservation in the market, said Giuliano Bordignon, a Platts Analytics analyst covering central US markets.

"In June 13-14, for example, the wind capacity factor was low, but nothing new," Bordignon said. "It is not all on wind. The other element is outages. ... ERCOT was quite surprised by them."

Therefore, ERCOT increased the amount of ancillary services capacity maintained in reserve from about 3.5 GW in 2019 to at least 6.5 GW, Bordignon said.

Placing generation in the AS category takes it out of the energy supply, which would tend to increase prices, but it also increases the reserves, which tends to decrease the effect of ERCOT's Operating Reserve Demand Curve adder, thus decreasing prices.

"On balance, because of the ORDC effect, the downside effect on prices overtakes the upside," Bordignon said. "The market price of $120/MWh currently for August is probably not supported by the facts."

Two other factors limiting upside risk in ERCOT are the lack of drought conditions in the state and the reduction in the systemwide offer cap from $9,000/MWh in February to $2,000/MWh this summer.

"If a heat wave developed in August, the heat would be partly absorbed by water in the soil," Bordignon said.

PJM's unique geography

In the East, the PJM Interconnection's unique geography atop the Marcellus and Utica shale formations has mitigated power price increases from this spring's significantly higher natural gas prices resulting from the mid-February freeze, Kemmerer said.

"We have seen some gas-to-coal switching, but not to the extent as seen elsewhere in the country," Kemmerer said.

Asked whether Platts Analytics expects continued load growth in the second half of 2021, Kemmerer noted that recent pandemic news has indicated another wave is a significant risk, but the hurricane-plagued summer of 2020 featured relatively mild temperatures.

"With a return to more normal ... the question is, do you have enough underlying demand growth?" Kemmerer said. "I think our answer to that question is no on a US aggregate level."