Weekly Energy Market Updates by Region - Archive




Issue week: July 1st, 2021  (Wk 26)





WEST  Excessive heat warnings have driven demand up across the Western Interconnec-tion and, for reliability purposes, forced CAISO to cut exports to the Desert Southwest, where the highest Day Ahead prices have been logged because of insufficient regional capacity to meet peak demand. The Palo Verde trading hub in Arizona and Mead hub in Nevada have had to send price signals high enough to incentivize non-CAISO-sourced power to flow into their regions. Consequently, the on-peak Day Ahead LMP cleared around $1,420/MWh today.

ERCOT  The wet weather and subnormal temperatures across the state have kept the 7x24 real-time average in the upper $20s/MWh this week. However, despite being relatively small, actual loads are still surpassing forecasts, and wind output has been low. Consequently, real-time price volatility remains possible, as evidenced by yesterday’s 7x24 average of more than $40/MWh. As the early part of July looks mild and wet, peak prices for July/August are off by approximately $3/MWh from last week but still above $100/MWh. Forward CY strip prices are up by $0.50-$1.00/MWh from last week on contin-uing strength in natural gas prices.

EAST After some record-breaking heat this week, Day Ahead and Real Time prices have unsurprisingly risen by as much as $20/MWh since last week in some zones. Calpine Energy Solutions’ CORE team issued its first alerts of the season in the PJM and ISO-NE regions. The PJM alerts for Monday-Wednesday very well may make it into the top five peaks for the summer. Similarly, the ISO-NE alert on Tuesday may end up the peak if no other heatwaves transpire this summer.







Natural gas is fast becoming a flashpoint in the ongoing conundrum that is U.S. energy policy and infrastructure as legislators weigh its stigma as a fossil fuel against its established versatility and reliability. Indeed, Tom Di-Christopher, reporting for S&P Global Market Intelligence last month, notes that, whereas six states have passed or plan to pass bans on the use of natural gas in buildings, 22 other states have passed or plan to pass legislation actually banning bans on gas use in buildings. The six states on the “ban” side account for roughly 25% of U.S. heating demand; the 22 states on the “no ban” side ac-count for roughly 45%. Moreover, although most of the current bans focus on new buildings, some governments are planning to require electrification retrofits for existing buildings.

New York and California top the list for residential and commercial gas demand, and their desire for (in the case of the former state) and adoption of (in the case of the latter) gas bans could turn out to be a case of “Be careful what you wish for!” In the last few years, California has endured some very high and volatile power prices as a result of its emphasis on building a more renewable but intermittent power grid. New York has not yet experienced such a price spike, but the freezing weather in Texas in February is a reminder of just how wild power prices can become with a large enough share of renewables on the grid.

As states continue to increase the share of renewables in their generation mixes and leave natural gas behind, the added burden of electrification driven by some form of gas ban may amplify the unpredictable impact of the absence of the fuel on power prices, particularly under stressed market conditions. Meanwhile, states that prohibit banning gas use in buildings may enjoy relatively greater grid and price stability by simply giving them-selves more options. Clearly, this nationwide controversy has broad implications for the future not only of the natural gas sector but also the broader electricity market.




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