For the wholesale power markets, summer and winter typically grab the bulk of traders’ attention as loads can push the limits, which can result in bouncing power prices.
This past summer, temperatures in the lower 48 states came in as the fifth warmest in the 122-year period of record, tying 2006, according to the National Oceanic Atmospheric Administration.
So one might expect hot weather drives demand, which in turn, translates over to power prices.
However, that was not the case in many parts of the US over past couple of months.
Let’s first start with Texas, where everything is bigger.
Peak demand in the Electric Reliability Council of Texas not only climbed year over year this summer, but hit record levels several times during August and peaked above 71 GW August 11.
But if you were sitting on a trading desk expecting prices to follow that record load, you would have been sorely disappointed.
Peak power prices for ERCOT North Hub on August 11, during the record demand, averaged near mid-$40s/MWh, hardly a level one might expect when compared with events in the past as prices were seen moving up and sometimes in triple-digit territory for real-time markets.
But let’s give Texas the benefit of the doubt; maybe everyone covered their loads properly so there were no worries in real-time.
Let’s jump to the Midwest, where on July 21 the Midcontinent ISO experienced a generation shortage event.
In most cases, if a market is short on supply, the situation presents an opportunity or incentive — most likely an economic one — for someone to step up to fill in a gap.
In this case, the market should function to trigger the next generation resource available, and that typically involves prices moving up.
But just like Texas, MISO power prices that day peaked lower than some may have guessed, in the mid-$30s/MWh.
In a recent presentation to the MISO board, MISO independent market monitor and Potomac Economics President David Patton touched on the event and said the low prices during one of the hottest days of the year “caused a little concern among some people.”
The market needed generation, yet prices sat still: what?
A real head-scratcher, some industry stakeholders have said in contemplating these events.
So what’s going on? Is it low natural gas prices? Is there too much generation? Is there something with the markets themselves?
“All of the above would be the best answer,” said Gary Ackerman, executive director of the Western Power Trading Forum. “Traders who bought long assuming higher prices got stuck holding the bag because those higher electricity prices never materialized.”
Ackerman goes on to explain that out in California the combination of milder-than-anticipated weather with excess supply from thermal capacity, utility-scale renewables and rooftop solar kept things in check.
John Shelk, president and CEO of the Electric Power Supply Association, said this past summer represents the perfect example of “why [the Federal Energy Regulatory Commission] needs to take price formation more seriously and on a much faster timetable than has been the case to date.”
Shelk noted there has been some progress on price formation reform, and appreciates the work FERC has done on this front, “but the situation is now far worse than it was when we and others urged them to take up energy price formation three years ago.”
“Now, as this summer indicates, markets are not reflecting fundamentals untainted from out of market actions and subsidies.”
Now heading into the fall, power markets are left to wonder what is waiting down the road. Is everyone marching into new territory wondering where is the risk? What’s winter going to bring? If it is cold, will the markets react as they have in the past? Where are natural gas prices headed? What about next summer?
“I can assure you that marketers and traders are walking into term deals for 2017, especially QIII, not sure how to price it,” Ackerman said.