Wind turbines in the Permian Basin. Wind accounts for 26% of electricity generation in the Texas market.
Photo: nick oxford/ReutersIt is a great time to be an energy company in Texas. No, not for the ones pumping oil and gas—it is power generators that have reason to be excited.
The Electric Reliability Council of Texas, the grid operator for roughly 90% of Texas’s electric load, expects to set another record for peak electricity demand this summer season: 75.2 gigawatts. That is even as overall U.S. summer electricity demand is expected to fall to the lowest level since 2009, according to projections published Wednesday by the Energy Information Administration.
Demand growth is somewhat built in for Texas. Unlike many other places in the country, the state’s electricity consumption has been on an upward trajectory as its population continues to grow alongside a booming energy industry.
Still, the resilience in demand is surprising given the weakness in oil and gas. The hydrocarbon industry’s expansion had played a big role in the state’s electricity-consumption growth. The western part of Texas, home of the prolific Permian basin, was the region that logged the steepest electricity-load growth in the past two years, primarily driven by the expansion of exploration-and-production activity, according to a report from Potomac Economics, the market monitor for Texas’s power market.
Last year, that region’s average electricity load grew by 13% compared with a year earlier. It is possible that the grid will register oil-and-gas impacts later in the year: Rigs themselves rarely draw on the grid, and the new wells that do likely won’t be connected to the transmission system for at least six to nine months after drilling, according to Travis Whalen, power analyst with North America power analytics at S&P Global Platts.
That makes for another exciting summer season for those generating electricity in Texas: Pair a very hot day with little wind—wind accounts for 26% of electricity generation in the market—and generators can earn up to $9,000 per megawatt-hour. Hypothetically, it would take only about 15 hours at that price level for a natural-gas combined-cycle power plant to meet its annual earnings need, notes Ryan Hardy, energy market expert at PA Consulting. By comparison, day-ahead average power prices overall were $38 per megawatt-hour in 2019.
This bodes well for companies with large exposure to the market such as Vistra Energy, VST 2.29% which owns more than 18 gigawatts of generating capacity in the market and relies on it for some 70% of adjusted earnings before interest, taxes, depreciation and amortization, as well as NRG Energy, which owns almost 12 gigawatts in the market.
Some observers are even more bullish about summer demand than ERCOT, the grid operator, despite the pandemic’s effects.
“We did see a dip in loads, but not a huge dip versus what we would have expected without the coronavirus impact,” said Manan Ahuja, manager of North America power analytics at S&P Global Platts, who thinks the operator’s forecast is too low.
There is another variable that could contribute to a tighter supply-demand situation than the one ERCOT expects: A higher-than-usual share of capacity being counted toward supply remains under construction. More than 2% had yet to come fully online as of May—more than double the share logged in the previous two years, according to Mr. Ahuja. Moreover, those projects could experience delays because of the supply-chain issues that affected developers earlier on in the pandemic, he added.
The other data point to watch is the so-called operating reserve demand curve, a market mechanism under which wholesale electricity prices automatically increase when operating reserves decline below threshold levels. This year, the grid operator has shifted that curve by a quarter of a standard deviation, which Vistra’s chief executive noted in last month’s earnings call could lead to a faster escalation of power prices during moments of electricity scarcity.
All of this adds more variability to a market that already has a lot of moving parts. Texas is the only U.S. power market that is close to letting real-time supply and demand dictate prices. Most others have built-in mechanisms that incentivize power plants just for being available. That free-market approach is the reason why Texas typically has lower reserve margins—the cushion between available electricity sources and peak demand—and consequently, why its summers can be a bonanza.
It might be hard to beat last year’s heat and profitability: It was tied for fourth as the hottest summer on record, and this year is expected to rank only within the top 20. Still, compared with their peers selling other types of energy, it should be a gusher.
Write to Jinjoo Lee at jinjoo.lee@wsj.com
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