This is something the CEO of one of America's largest independent power producers, or IPPs, said on a results call on Tuesday morning:
I believe the IPP model is now obsolete and unable to create value over the long term.
To understand why the CEO of NRG Energy Inc. wasn't exactly cheerleading for the IPP business, it pays to look at one of the markets where NRG operates -- which also happens to be the biggest electricity market in the U.S.: Texas.
In one respect, Texas looks like a haven for America's power providers:
Selling power and selling power profitably are two different things, though. After all, if power demand has held up so well in Texas, then why have prices done this?
Across the country, wholesale electricity prices have been pulled lower by the shale-induced collapse in natural gas prices, and Texas is no exception to that. But there are other forces at work in the state, too.
If you ever happen to find yourself in the Port of Corpus Christi, you may be surprised to see, alongside the oil tanks and pipelines, rows of giant blades and sections of towers destined to be put together at wind farms inland. The blades, which can reach around 200 feet in length each, have to be moved on special trucks and railcars.
Corpus Christi is the largest port handling wind-energy equipment on the Gulf of Mexico and just had its best year ever for that business, the port's executive director John Larue told me on Monday.
Wind energy has -- forgive me -- blown through Texas' electricity market.
Despite rapid growth, wind power still constitutes just 13 percent of Texas' electricity generation. But don't let that fool you.
Renewable energy has a particularly pernicious effect on wholesale power prices because of the way they are set. As you might expect, the last source of generation to be switched on in order to meet demand is the most expensive one. Back in the day, this so-called "merit order" generally ran like this: nuclear first, then coal, then maybe some natural gas, and finally, if there was a sudden surge of demand, a "peaker-plant" burning gas or even oil.
Renewables mess with this because, once built, their fuel is generally free. So, as long as the wind is blowing or the sun is shining, they will run first, displacing higher-cost sources of power. This tends to depress the whole market, as that last kilowatt-hour of supply needed to meet demand comes from a lower-cost source (this is also why cheap natural gas has savaged demand for coal).
You can see in this chart comparing daily Texas electricity prices and wind output since the start of 2015 how prices start to really drop off as more turbines start turning:
In its most recent outlook, released in December, the Electric Reliability Council of Texas raised its estimates for demand growth over the next five years, reducing the forecast level of spare generating capacity. For example, ERCOT now expects spare capacity in 2018 to be 20.2 percent of peak summer demand, down from last May's estimate of 25.4 percent.
Even so, 20 percent is still a large cushion of spare capacity (the rule of thumb is that 15 percent is adequate).
Moreover, in a report published last May, William Nelson of Bloomberg New Energy Finance pointed out that ERCOT's calculations of wind capacity tends to understate the actual amount available. Wind is intermittent, of course, and ERCOT assigns an average utilization factor of 14 percent to onshore wind turbines. Yet BNEF estimates that turbines in west Texas and the Panhandle -- where the majority of onshore capacity lies -- can achieve levels of more like 30 or 40 percent.
One silver lining of those lower prices for power generators getting squeezed in Texas is that they should help to slow the development of new power plants there, wind turbines included. And given that the wind doesn't always blow when you need it, this raises the chance of getting some stifling afternoons with air conditioners cranked up but turbines sitting idle.
Given how the Texas electricity market operates, these are the days when prices for electricity can shoot briefly into thousands of dollars per megawatt-hour, providing a jackpot for owners of traditional gas-fired or coal-fired plants. For example, BNEF estimates that, for power plants selling into ERCOT's North Hub, just 10 percent of the top-priced hours in 2016 accounted for more than a fifth of all potential revenue available for the entire year.
If that sounds like playing Texas hold 'em with the weather, that's because it is. And the odds are moving out of traditional generators' favor.
Federal tax credits and state renewable portfolio standards have been crucial to the expansion of wind power. But technological progress is now acquiring its own momentum. Speaking on an analyst call last month, Jim Robo, CEO of Florida-based utility Nextera Energy Inc., said he expects wind energy to be effectively competitive with traditional sources by 2020, even without federal subsidies.
Solar power isn't far behind, either -- which is particularly important for Texas. Solar projects barely figure in the state's energy mix right now. As they appear, though, they will strike directly at those high-priced hours that can now make or break a power plant's profitability. As BNEF's Nelson points out, even if turbines aren't necessarily cranking out power on a hot day in Houston, solar panels surely will.
It is little wonder, therefore, that Mauricio Gutierrez, NRG's CEO, emphasized on Tuesday's call that three-quarters of the company's gross margin this year is expected to come from sources that aren't directly exposed to swings in wholesale power prices, such as the company's retail business and contracted power plants. It helps that he now also has activists on board who will push him to pull other levers, such as cutting costs and selling assets.
The wider message is that, for listed IPPs at least, shale gas and now renewable energy spell doom for their traditional business. Texas is exhibit A, and a big exhibit at that.
This column does not necessarily reflect the opinion of Bloomberg LP and its owners.
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