It’s been two years since Texas’ last rolling blackout — a freaky February storm — and a near-miss during 2011’s extraordinarily hot and dry summer. And the state is still without a solution to projected electricity shortages in the future.
The state’s consultants warn that wholesale electricity prices are too low to spur new investment in power plants or prompt conservation. But officials continue to debate the issue while waiting for Gov. Rick Perry to break the tie at the three-member Public Utility Commission with a third appointee.
The utility commission has raised the cap on wholesale electricity prices, knowing that alone won’t solve the problem because wholesale prices spike only during an emergency or for a few hours on summer afternoons when air conditioning strains the system.
Every long-term solution involves getting more revenue into the wholesale electricity market.
In other words, your electricity rates will be going up eventually.
What’s really being debated now at the utility commission is who pays, who gets paid, when is it paid — and whether it ensures adequate electricity reserves to protect from rolling blackouts.
Ensuring adequate electricity reserves is a like buying insurance. The more you are willing to pay, the more insurance you can afford.
Not only is the utility commission split, so are owners of power plants who stand to benefit.
Currently, generators only get paid when they sell electricity.
In the summer, every plant — including old coal plants that are mothballed the rest of the year — is running when wholesale prices are highest. In the winter, however, there is about twice the generating capacity actually needed.
That’s a lot of turbines not earning money for a significant portion of the year. That causes havoc with what you might consider the traditional supply and demand model — because supply easily exceeds demand except for about 2 percent of the year.
To address the problem, most power providers favor an additional “capacity” payment atop what they earn from selling electricity. In a capacity market, the regulators decide how much a surplus they need and then accept bids to have that amount of generating capacity on standby.
Ratepayers pay for it whether they use the electricity or not.
In one form or another, that’s what the rest of the country does. But that capacity market model is not without its detractors.
One concern is having ratepayers pay for capacity that might never be used. The other is that 50-year-old coal plants with reliability and pollution issues won’t be retired and replaced, because plant operators will extend their lives to collect capacity payments.
Rob Minter, a senior vice president with GDF Suez, a global energy provider, likens it to paying farmers because they own a farm and not because they are the best farmers.
GDF Suez is promoting a different option that regulators have dubbed Hogan B+ ORDC. (This is what happens when the electricity nerds are in charge.)
Actually, the concept can be explained without tongue-twisting acronyms.
Most electricity is sold under long-term contracts, but the state’s power grid manager — the Electric Reliability Council of Texas — is also running a daily spot wholesale market. In that market, power generators submit bids and utilities and electricity retailers purchase the cheapest power first. As the demand rises, higher and higher bids are accepted.
On a summer day, prices might be rocking along at $30 per megawatt hour until Texans start turning up their air conditioners. Then the price literally can rocket — think a vertical climb — towards the wholesale cap of $5,000 per megawatt hour. (In two years, the cap will be $9,000.)
It’s rare for wholesale prices to hit the cap and they can nosedive as fast as they climb because ERCOT is sometimes forced to deploy its operating reserves to keep the grid up and running. Some power plants aren’t fully generating before the prices can start falling. Once again, turbines aren’t turning and earning.
In 2011, prices hit the cap — $3,000 at the time — for only 28.4 hours. Last year, it was 1.5 hours. This year, so far, it’s a matter of minutes.
GDF Suez, which owns seven power plants with slightly less than 5 percent of ERCOT’s generating capacity, wants to replace that steep vertical climb and fall of prices with a gentler slope. Instead of a rocket, think of an airliner taking off and landing.
The net effect, the theory goes, is that generators can make more money taking longer to get to and from the cap. It also allows generators to make more money during the spring and fall.
In essence, the GDF Suez option is a capacity payment that is paid during times when supplies are scarce and turbines are turning. By comparison, a true capacity payment is paid year round whether a power plant is running or not.
That’s why the state’s largest industries oppose a capacity market.
Industrial customers can shut down factory lines during times of shortages and get paid by ERCOT for their conservation. But when capacity payments are paid year round, industrial customers can’t avoid higher costs. And, in effect, they would be subsidizing homeowners because they are paying a greater share of the capacity payment.
Several owners of power plants worry that adopting the GDF Suez idea would delay — or kill — their hopes for a capacity market.
Most of these debates break down into what kind of power plants you own.
Minter admits the GDF Suez proposal would favor his company’s fleet of gas-fired plants that can ramp up and down better than its competitors’ technologies, whether it is coal, nuclear or wind.
Some, including generators with older power plants, counter that any solution should be technology neutral. Others say the GDF Suez proposal won’t solve the long-term projections of dwindling electricity reserves.
Minter’s ace in the hole is speed. He said the proposal could be implemented within six to eight months, hopefully sending signals to investors that new plants could be profitable.
Minter argues that it also buys the state time. He said it could be an intermediate step while the utility commission contemplates a capacity market — a much more rigorous exercise that could take years to design and for investors to respond.
Two years after the state’s last rolling blackout, Minter said, “We need a vote now.”
Gov. Perry has let more than five months go by because he didn’t want the Texas Senate’s advice and consent on his third utility commission appointee. With the Legislature finally gone, the governor can finally act, but it’s unlikely the appointee will want to vote without first absorbing the details of the debate.
We could be weeks, if not months, from sending a signal to investors on what kind of wholesale market they can expect to invest in.
If ERCOT keeps the lights on, there is no harm.
But if there are rolling blackouts in our future, Perry will have created another oops moment for himself.