> All energy costs a positive amount of dollars to produce. Thus, in the long run, the price of electricity must be such that generators recoup their fixed costs, recoup their variable costs, and make some profit that makes the whole endeavor worthwhile.

The only type of cost that strictly determines a price floor is the variable cost. Recuperating fixed costs and profits are based on a revenue prediction which may or may not come true, but once the investment is made it rationally operates until prices descend past the variable cost barrier, regardless of whether long term ROI is positive or not.

What I don’t understand is why prices must go negative. A price of zero should be enough to turn off capacity, modulo switching costs (the cost to start or stop a turbine?)

It can take a long time to turn some capacity on or off, and not all generators throttle cleanly to zero. Hydro plants can have rough running ranges that cause excessive wear. or might have run-of river flow requirements. Coal plants have huge parasitic loads in the crushers and pulverisers and blowers, and/or poor ability to throttle below a minimum limit.

For any of those reasons, it may make sense for a generator to pay someone else to temporarily take their excess capacity, rather than shut the generator down.

Many kinds of power generation can't be easily started and stopped (nuclear, say). It might be cheaper to create an incentive for someone to use your excess power for a short period than it is to absorb the cost of a long shutdown and restart.

In the U.S., the main reason prices go negative is because of the production tax credit. Wind producers get a subsidy per MWh produced. Since the unsubsidized marginal cost of production is zero, the result is a negative effective production cost. So if wind is the marginal energy producer, the clearing price goes negative.

I don't know how things work in Germany, but I'd be surprised if the negative prices there had much to do with the costs of starting/stopping conventional units. In most electricity markets, participants have to bid in their marginal cost. Even if you're an inflexible nuke, your marginal cost is positive. You usually need genuinely negative marginal cost units to drive the clearing price negative. That only really happens when subsidies are part of the picture.

> The only type of cost that strictly determines a price floor is the variable cost. Recuperating fixed costs and profits are based on a revenue prediction which may or may not come true, but once the investment is made it rationally operates until prices descend past the variable cost barrier, regardless of whether long term ROI is positive or not.

Only variable costs will drive the short-term decision of whether to stay on or not. But the price of electricity in relation to fixed costs and profit will factor into the long-term decisions regarding building new plants and decommissioning ones that need refurbishment/upgrades. In the long run, the price of electricity has to be high enough to ensure sufficient capacity to meet demand.

(That's something of a simplification, as I said. In reality, the incentive for building new capacity comes from both the electricity market, and so-called capacity markets: https://business.directenergy.com/understanding-energy/manag...)

> What I don’t understand is why prices must go negative. A price of zero should be enough to turn off capacity, modulo switching costs (the cost to start or stop a turbine?)

It can take a coal plant ~4-8 hours to reach maximum output after even a warm restart.

After investors get burned a couple times, the revenue predictions get updated to account for the measured risk. So, thinking longer term, fixed costs do have to be taken into account.

To be precise, negative energy prices are good for consumers with flexible energy usage (and bad for other consumers). For example, if you have a battery at home, you could charge it when energy prices are negative and use the battery when energy prices are high. Ideally, such a system of incentives would reduce peak consumption, making the energy market overall more efficient.

... assuming that you can get wholesale rates rather than retail rates. Dynamic pricing for cost is something that California is working on. https://www.caiso.com/Documents/FlexibleResourcesHelpRenewab... describes some of the initiatives:

> ) increasing demand by expanding the ISO control area beyond California to other states so that low cost surplus energy can serve consumers over a large geographical area; 2) increase participation in the western Energy Imbalance Market in which real-time energy is made available in western states; 3) transition our cars and trucks to electricity; 4) offer consumers time-of-use rates that promote using electricity during the day when there is plentiful solar energy and the potential for oversupply is higher; 5) increase energy storage; and 6) increase the exibility of power plants to more quickly follow ISO instructions to change its generation output levels.

#4 (time of use rates) and #5 (storage) are aspects you are thinking of. That isn't the case in all markets.

The chart in the graph shows an 11k MW demand ramp up for 2016 from the lull in the early afternoon to the early evening peak demand. The market needs to be efficient - and also be able to properly handle the oversupply.

Another part of the "ug, this is complicated" comes into the cost of power hookups. Typically, that's done as a service fee on the power bill. But, if you have residential solar, you are demanding less power from the grid and paying less of the constant cost of the upkeep of the utility. This increases the service fees on the people who don't have residential solar. Also, there is the challenge of managing the residential solar as part of the smart grid - people may not want to curtail their solar mid day even if they're only making pennies - that solar investment that they made isn't going to pay itself off if it isn't generating.