As stories about the energy transition go, Big Oil going big on solar power in the heart of America’s biggest oil patch is as transitiony as it gets. Besides the symbolism of Exxon Mobil Corp. signing up for 250 megawatts of solar power (plus the same amount of wind power) in the Permian basin, though, it is also part of a big change gathering momentum in the country’s biggest electricity market: Texas.
Despite lots of sunshine and power demand, the state hasn’t embraced solar power in a Texas-sized way. Last year, it ranked sixth in the U.S. in terms of solar generation, just behind Utah. But that appears to be changing. As of the end of November, the state’s solar pipeline was at almost 37 gigawatts, up from less than 25 GW at the beginning of the year, according to the latest monthly report from the Electric Reliability Council of Texas (ERCOT).
Most of this proposed solar capacity will never see the light of day. Still, 4.1 GW of that planned capacity already has an interconnection agreement in hand and should be running by the end of 2020, almost quadrupling the state’s solar capacity:
Renewable energy at scale does weird things to wholesale power markets designed for traditional plants. Because it has no fuel cost, its marginal cost to run is effectively zero (and sometimes negative if subsidies are in play). So when the sun is shining or the wind is blowing, these plants switch on and tend to both suppress the wholesale power price and leave less demand to be met by traditional plants.
California has seen this happen already with solar power. So, too, has Texas with wind power, where the state leads the country. In Texas, generators make a disproportionate share of their profit from a relative handful of hours when demand is high, the grid is strained, and prices can leap from less than $30 per megawatt-hour toward a cap of $9,000. Such hours were easier to come by when there were fewer wind turbines around.
Solar power brings an added dimension. Hot, muggy days can leave wind turbines idle even as air conditioners are maxed out, creating perfect conditions for scarcity pricing. Solar panels, however, come into their own on such afternoons, posing another threat to those windfalls. Back in January, analysts at Bloomberg NEF modeled the impact of adding 5 GW of solar capacity in ERCOT’s region, using expectations for 2018’s summer. They estimated these additional gigawatts, equivalent to less than 7 percent of overall capacity, would cut generators’ revenue by $1.4 billion, or 11 percent.
Blunted peak pricing is a risk for merchant generators, which aim to capitalize on those windfall hours. That’s one reason the likes of NRG Energy Inc. and Vistra Energy Corp. have built up their retail power businesses as a hedge.
Yet they also have another lever to pull: closing down old plants, particularly less-flexible coal-fired ones. Vistra revitalized forward power prices in ERCOT late last year by announcing the closure of several gigawatts of coal-fired capacity.
In its latest projections, also released this month, ERCOT’s projection for coal and gas-fired capacity for summer 2020 has dropped by almost 8 GW compared with two years ago. Meanwhile, projected solar and wind capacity has risen by less than 3 GW. As a result, the margin of spare capacity foreseen for that summer has dropped from almost 20 percent to just 10.7 percent. The figure for 2019 is even lower: 8.1 percent.
Thinner spare capacity offsets the increase in solar power, keeping generators’ hopes of a summer windfall alive (weather permitting; this year’s August was actually less lucrative than anticipated).
Looking ahead, gas-fired capacity, enjoying cheap fuel due to the Permian associated-gas boom and able to ramp up and down relatively flexibly, is better positioned than coal to withstand the threat. The latter should bear the brunt of expanding solar capacity, with more closures likely.
But solar power’s expansion represents a structural challenge to all merchant generators in Texas. This goes back to how the power market works there, eschewing things like capacity payments to reward generators in favor of the lottery of scarcity pricing. Solar power, like wind, is aimed squarely at those lucrative peaks and ultimately flattens them once capacity gets large enough.
Hence, if plant closures cause price spikes, then that will help traditional generators but also encourage more solar projects. While merchant generators have conflicted incentives when it comes to building solar capacity — as money made on those may erode returns on existing thermal plants — that isn’t true for the state’s municipal utilities or, as Exxon’s move demonstrates, commercial and industrial customers seeking to manage price risk.
The same holds true for battery storage that, again, undercuts peak pricing. For the period 2012 through 2016, Hugh Wynne of SSR LLC estimated adding just 500 megawatts of storage to ERCOT would have cut $590 million a year from generator profits, the biggest impact of any of the regional power markets he analyzed. As things stand, however, the same market structure that creates an opportunity for storage in Texas also stymies its deployment. Utilities can’t own it, and the structural pressure on peak pricing from expanding renewables undermines the economics of batteries just as it does for peaker plants. Indeed, the same holds true for solar projects once capacity reaches a level that suppresses power prices enough.
At some point, the falling cost of renewables and storage should force a change in the Texas power market itself. Customers want low, stable prices. As more examples of savings from these two technologies emerge, preserving a pricing structure that pivots on peaks and discourages things that help avoid them will look less tenable. As the power transition gathers force, pricing must ultimately accommodate it and ultimately encourage it.