Reliable vs. Intermittent Generation: A Primer (Part I)

“Why should a thermal plant spend money in a government-rigged market that threatens a reasonable profit? Why should the plant even remain in the market under these conditions?”

This two-part post is a follow-up to Robert Bradley’s recent IER article, “Wind, Solar, and the Great Texas Blackout: Guilty as Charged.” His article discussed how regulatory shifts and subsidies favoring Intermittently Variable Renewable Energy (IVRE) producers resulted in prematurely lost capacity, a lack of new capacity, and upgrade issues with remaining (surviving) traditional capacity. These three factors–‘the why behind the why’–explain the perfect storm that began with (or was revealed by) Storm Uri.

Part I below describes how the market was originally meant to work–but has not worked given the governmentally redesigned responsibility of power generators. The change was caused by:

  • Investment monies lured away from developing baseload capacity by government subsidies and special tax incentives, and
  • Operating opportunities lured away by “first-use” mandates. First-use mandates are especially pernicious as grid operators must purchase from IVREs whenever producing, leaving the reliable generators idle.

The Distortion

Imagine a billion dollars on the table for building a nuclear, coal-fired, or natural gas-fired generation facility. Your financials require a return on investment (ROI) to obtain your capital providers (investors and/or shareholders).

You built the facility in good faith, based on robust grid modeling that suggested a significant opportunity to profitably sell your energy over the operating life of the plant. You did your due diligence on this opportunity against the cost, and the ROI was good enough to get signoff on a Final Investment Decision (FID), so the plant was received financing and was built. Great.

Assume under the business case that X units of electricity were to be sold into the grid. Based on satisfactory plant performance, the project is statistically certain to sell, say, at least 50 percent of X (obviously making up numbers here but you get the point) and to break even. At a high level, the variables to manage are:

  1. Fuel price
  2. Labor costs
  3. Maintenance costs

This is a normal market–the way it used to be. The utility had an ‘obligation to serve’ and had the ratebase incentive to key capacity above peak-demand scenarios.

Enter government intervention….

IVRE “first-use” mandates. Not only do these mandates require grid operators to buy power from IVERs “first” if they are generating, but these mandates also often require grid operators to pay a premium for IVER power over any other source.

Your business case has now been kneecapped with a double-whammy: not only are you losing business because IVERs must sell “first”, but there is absolutely nothing you can do to make your power more commercially attractive, since IVERs not only have very low short-run marginal costs (in that the next electron that they can generate is extremely cheap, since wind and solar (and falling water for hydro) are “free.”

In this scenario, due to other political externalities, the price of your fuel (if you are using natural gas or coal) is rising.

Doesn’t look too good for you now, if suddenly the volume of power that you are competing for (that is, market demand) has shrunk because IVERs can “cut in line” in front of you at any time, doesn’t it?

Not to mention that with few exceptions, your ability to shut down when demand has dropped (and thus limit your operations and maintenance costs (O&M) is very limited – especially if you are expected to have power ready to sell if demand suddenly ramps up.

Thus comes the double-edged sword of IVERs: their ability to produce can drop just as quickly as it rises. When that happens, grid operators expect baseload to be ready to sell, often with only a short notice. This means that baseload operators cannot shut down when they aren’t selling; rather, they have to keep their plants warm and turbines spinning in case they are called upon to sell when IVERs cannot.

This condition that baseload operators are forced to wait in is called “spinning reserve” – meaning the plant is operating but not generating any saleable electricity. But it is piling up fuel, labor and maintenance costs (see the list above).

Therefore if fuel costs are rising, and I am running my generation facility on a skeleton crew, what’s left for me to cut?


Rather than spend money on scheduled maintenance, the generator will try to shore up the red ink by deferring maintenance.

The more I am forced to do this (with the alternative being bankruptcy or exiting the market), the more I am playing a game of “Russian Roulette” with my ability to operate. Planned maintenance is scheduled on the basis of statistical modeling, so I can operate my plant safely and produce saleable energy. I can stretch these statistics by implementing condition monitoring (“con-mon” for short), but eventually I have to maintain the plant if I do not want to risk a failure.

But if I cannot afford to perform the maintenance, I’ll start deferring items that I think I can get away with, like equipment used to operate the plant in extremely low temperatures, since weather rarely gets “that cold” here in Texas. And what is said about climate change moderating winter lows.

Statistically my risk is pretty low, right?

Until the proverbial holes in the layers of “swiss cheese” line up (some may recall the safety model using this graphic) and suddenly it’s very cold, and IVREs are not generating enough to make up the gap.

And, having deferred maintenance, my plant tries to generate saleable power, but it breaks.

Whose fault?

Yes, in this example, my baseload plant broke. This is the first “why” that the IVRE advocates point out–but dare not go further. The layers below the initial “why” all involve government having fundamentally “altered the deal” for baseload generators after the fact: IVREs attract investment dollars and are allowed to cut the line for market demand whenever they are generating.

For IVRE’s its a no-risk deal, with markets guaranteed and taxpayers country-wide adding profits. But what about the need for reliable power?


Why should a thermal plant spend money in a government-rigged market that threatens a reasonable profit? Why should the plant even remain in the market under these conditions?

This is where we find ourselves today: the market is broken, and the risk is that the ‘insurance’ for IVREs, covering the reliability gap (not enough sun or wind for prolonged periods, thus negating any advantage that battery storage might offer them) will fail. After all, the baseload plants are either crippled by deferred maintenance, or else sold to buyers on the cheap that have even less incentive to maintain them. And much needed new capacity is not built at all (phantom plants).



The nature of IVREs will continue to push baseload generators out of business – and IVREs will continue to blame baseload for these problems even as its mandates kill the security that baseload provides. Authors Tom Stacy and George Taylor have written a detailed submission to FERC (the US Federal Energy Regulatory Commission) on this topic:

The post Reliable vs. Intermittent Generation: A Primer (Part I) appeared first on Master Resource.

via Master Resource

March 1, 2023 at 01:09AM

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