The natgas power plant you’re referring to is the one on I-84 near Sand Hollow, Langley Gulch, right? I can’t think of a reason why not to run that thing unless it’s maintenance related. But if it’s usually 600 or 800 MW, there are more plants than just that one. Langley Gulch is ~300 MW: Langley Gulch Power Project I’ve seen 250, 275, and 300 MW; probably it’s 250 MW which can bump to 300 MW when you fire (add extra natgas to the exhaust) the HRSG.
My reading of the plot right now (2021-04-08) is that they’re running the evening peak after PV is down with the natgas as a peaker. But it’s a combined cycle GT, which means it’s not really designed to be a peaker, but maybe it’s more capable of peaking plant operation than our ancient coal-fired plants. But between high wind, sunny days, and melting snow, we’re a very renewable state these past few days.
I know most of the peakers are not the combined cycle turbines, but is there a particular reason you can’t run a combined cycle as a peaker/load following plant?
Peakers are meant to be cheap and fast. Combined cycles are expensive, though not really slow. They do need time to generate sufficient steam pressure (and condensing vacuum) for the bottoming cycle steam turbine, so they tend to be spinning reserve instead of start and peak. It’s just the wrong tool for the job, but California often shovels using rakes, because they have so many rakes. Idaho may have fallen into the same trap, but Idaho Power only has 3 natgas plants total.
I puzzled over that and did some reading, as I would have guessed the opposite - that power from peakers would be the most expensive because you are paying for flexibility, and power from base load plants would be cheapest because otherwise you would replace them with an option that was both cheaper and more flexible.
I think the answer is it depends on which costs are being considered: peakers don’t run as long or don’t produce as much output, so there isn’t as much production to amortize fixed costs over. Thus fixed costs are kept lower and variable costs are higher. Likewise base load plants have more output, so it makes sense to incur higher fixed costs to enable lower variable costs.
power from peakers would be the most expensive because you are paying for flexibility
Sorry, I indeed meant first-cost expensive, not running costs. But if you assume 85% Capacity Factor (CF) for your fancy combined cycle GT over its 20 year life and then solar/wind cut that to 60% CF, your amortization schedule gets all screwed up. Or, if you built a 52% efficient CCGT in 1999, but someone else built a 56% eff unit in 2005, you aren’t gonna run nearly as baseloaded as expected.
Siemens’s customers lost lots of money on it’s 60.5% eff CCGTs in the 2010s because baseload was taken by nukes and less flexible coal plants, renewables took their load, and they couldn’t amortize costs:
It seems like CCGT efficiency numbers stalled around 2011, but we should pat ourselves on the back for doubling power plant efficiency from ~30% in 1950 to 60% 60 years later. I wonder if we’ll double it again in the next 60 years… /s
I just read this WaPo article on the Texas Freeze affecting utilities in Minnesota:
"Minnesota’s second-largest gas company, Xcel Energy, also wants to spread the recovery of costs over two years — but said it would not charge interest, which it said would amount to $24.7 million on borrowing to cover its expenses. The company, based in Minneapolis, predicted a charge of about $250 per residential customer. Minnesota Energy Resources said it would hope to recover about $225 per customer. The smallest commercial utility, Greater Minnesota Gas, said it had enough of a supply in storage in February and was able to avoid the spot market.
(The largest, Centerpoint, lost $500-800 million!) It seems like the FERC could invoke the interstate commerce clause to regulate Texas’s energy industry now if there are these large impacts on other states’ utility customers. But I’m no constitutional expert…