It took a few weeks of real weather to remind market participants that spot prices in power drive forwards, and that they do not always go down. This is more true in ERCOT, where demand and price records were broken, reinvigorating summer 2020 and beyond. While in the East, a warmer-than-normal July and resulting spark spread gains helped at least stabilize forwards.
A string of hot days in Texas is not unusual, especially in August, but temperatures during the stretch from 13–26 August were technically above normal, and reawakened concerns about meeting peak demand next summer and beyond if demand continues to rise at its current pace.
As the heat finally reached Texas, after scorching the east coast in July, demand records fell in ERCOT and prices realised at the ISO-set cap for more than an hour, helping pull spot prices up to double what forwards had been for August 2019 earlier in the spring. With no significant volatility last August, and one of the coolest springs on record in Texas, the market had clearly settled into complacency, setting up for the rebound in prices since the start of this month. There may not be blood on the streets of Houston yet, but there is a nagging question over who, if anyone, was harmed by the high real-time prices and resulting surge in 2020 and 2021 forwards.
As expected, after a modest rebound in forwards through mid-July, there has been little movement in forward prices in the eastern markets, which are now largely in line with our view for summers, and overvalued in New England and PJM in winter. Anticipation over the upcoming changes to fast-start dispatch rules in PJM as well as memories of gas price spikes during prior years’ cold snaps could be underpinning forward winter values. The fast-start rules could be approved and implemented for a January start assuming the ISO meets its upcoming deadline and FERC approves the rules swiftly. FERC though, which starts September with only three commissioners filling five available seats, has other key market reforms in front of it as well, including those surrounding the delayed PJM capacity auction, which could delay or muddle anticipated energy price decisions.
Market prices in PJM and the Northeast, however, continue to limp along at levels representative of a very efficient, unconstrained gas-driven market, at least in summer. And demand levels outside of peak cooling load in the Mid-Atlantic region have been anaemic, posing further risk for forward prices. PJM itself lowered again, at least preliminarily, its forecast for demand through the mid-2020s, by an average of 1.3 GW. Structural load declines are not new in PJM, or the surrounding markets, and summers are clearly not pricing in any significant growth and resulting peak spikes, unlike in Texas.
The economic backdrop to this includes concerns about the impact of the trade war on growth, which would further limit any gains in electricity usage, especially in coastal and southern states heavily involved in exports. But regional industrial activity, after slowing last spring, has at least stabilised based on New York and Philadelphia Federal Reserve manufacturing surveys (Fig 30).