Solar Subsidies The main subsidies for solar energy are the federal investment tax credit, the rapid deprecation allowed for solar installations and state quotas for renewable energy.
Investment Tax Credit (ITC) - This is a credit against federal income taxes. Currently it is 30% for projects started in 2019 and it is scheduled to ramp down to 10% by 2022 and thereafter. For example, if the project costs $100 million, the ITC will be $30 million. This credit may be used to reduce federal income taxes by $30 million. The solar interests had been telling congressmen and senators that they were fine with the phase down of the ITC, but in July, 2019 they suddenly reversed course and are now asking for another 5-year extension of the full ITC subsidy.
Tax Equity Finance - Solar projects are granted 5-year depreciation by special dispensation. A natural gas generating plant, in contrast, must use 20-year depreciation. A common model for a solar project is a developer and a tax equity investor in a partnership. The investor is a highly taxed corporation. The tax benefits are funneled to the investor, including the ITC and depreciation. In return the investor puts up part of the initial capital, typically 40%. If the project cost is $100 million, $40 million is contributed by tax equity investor. The tax equity investor receives the ITC, depreciation and a share of the electricity sales. The tax equity investor gets his money plus a return on his investment over 5 years. The depreciation allows the investor to pay less federal tax.
State Renewable Portfolio requirements - About 30 states impose ramping quotas for renewable energy. For example, in Nevada, 20% ramping to 50% by 2030. The effect is that the utility, in order to acquire renewable energy, (usually wind or solar) it must sign a long term power purchase agreement (PPA). Further, it must accept erratic power that depends on weather conditions. Because the utility has a good credit rating and because it has agreed to take the power at a fixed rate for 25-years the developers of the solar installation are willing to accept a lower rate of return, or equivalently, the project is worth more because a guaranteed market exists for the electricity.
In order to assess the value of the subsidy created by this mandate, one has to know what the solar electricity is worth absent a PPA. In order to assess the worth of solar electricity we examine the operation of an imaginary company that generates and sells solar electricity without subsidies or guaranteed markets.
Why would a utility want to purchase erratic electricity? Utilities need electricity in steady supply that they can count on. There is a reason why this erratic electricity would be interesting to the utility if the price is right. The utility can use its existing plants to compensate for the comings and goings of the solar electricity. The solar electricity cannot be used to replace existing plants, because solar is often not there, particularly in the early evening when demand often peaks. So, the utility can accept the solar electricity at times if it wants to. The reason it might want to use the solar electricity is that while the solar electricity is flowing, the existing plants are throttled back and are using less fuel. The solar electricity displaces some fuel. The cost of fuel, with some regional variation, is roughly $20 per megawatt hour, so that is what the utility would be willing to pay, at most. But if we set up our imaginary company, an enterprise with uncertain markets and various risks, what rate of return is required to make the investment. A good guess is that the company should get 8% return on investment over a 10-year period. Certainly the investors don't want to count on circumstances beyond 10-years. Too many things can change. Given what solar installations cost to build it is straightforward to calculate that the imaginary company would have to sell its electricity for $100 per megawatt hour to justify the investment. But the utility only wants to pay $20. Unless someone provides a subsidy of $80 per megawatt hour, there is no business. The existing direct federal subsidy is only $40 per megawatt hour. Not nearly enough.
Now consider a different situation. The company has a 25-year power purchase agreement (PPA) with a financially solid utility that guarantees price and acceptance of everything that can be expected to be generated. Now the company is not an enterprise with foggy prospects. It more like a government bond or a commercial real estate property with a 25-year lease by an A-rated tenant. Now instead of demanding an 8% return, the investors will be satisfied with a 4.5% return over 25 years. Banks are overflowing with low cost money and 4.5% looks good if the risk is tiny. These deals can absorb a lot of money, hundreds of millions. The risk and marketing expense has been greatly reduced by the PPA. In this circumstance a calculation of the required sale price of electricity yields a number of about $44 per megawatt hour. If the current 40% direct federal subsidy is still in place, the the required sale price would be about $26 per megawatt hour. If the direct federal subsidy is reduced to 20% (ITC plus depreciation benefit) as scheduled, then the required sales price would be $35 per megawatt hour. The utility is only really moderately interested in paying $20 per megawatt hour, but the utility has a quota to meet. It can't get the renewable power unless it offers terms that will cause someone to build the installations. So, at the current time the best contracts are in the range of $26 per megawatt over 25 years. If half the direct subsidy is phased down, to 20%, then it will have to raise its price to $35 per megawatt hour over 25 years after the subsidy is reduced. But, remember, the cost of unsubsidized solar electricity is $100 per megawatt hour. That is what has to be paid the make it viable in the absence of subsidies and quotas. For a solar plant to be viable it needs to sell electricity for $100 but it is only worth $20 to the customer. So, the subsidy is $80 per megawatt hour. With the current situation, $40 of subsidy comes from the direct federal subsidies, The other $40 represents risk assumed by the utility and passed on to the utility customers. The contract is similar to debt and will use up part of the utility's capacity to borrow at a particular interest rate. If the cost of fuel decreases, the contract will become a burden, forcing the utility to buy solar electricity that is worth much less than it costs, that loss being passed on to the customers. This is not theoretical as the price of natural gas has been declining for years. Nuclear fuel costs less than half what natural gas costs. Nuclear is not currently viable in the U.S., but may become so in the future.
The effect of the renewable energy quota is that the utility and customer has to pay whatever it takes. An it takes enough to provide a nice profit for the solar industry.
Risks to the Solar Promoters Even though a 25 year contract seems pretty solid, things can happen. The California utility PG&E is in bankruptcy and the judge has said it can cancel $40 billion worth of renewable energy contracts. The bankruptcy was caused by a fire started by electrical lines that burned up whole cities.
Another risk, is the risk of curtailment. The contracts I've seen don't provide any compensation to the solar developer if he is ordered to curtail delivery of electricity. Curtailment happens for technical reasons when there is too much solar electricity, usually in the middle of the day when solar production is high and peak demand has not yet arrived. Logically the utility would curtail the highest price contracts first, creating a large problem for the developers with the highest price of electricity.
Installing very large lithium batteries to move midday electricity to early evening is a new technique. There is a danger of very large fires driven my the massive amount of energy stored in the batteries. There have been several fires involving utility-scale lithium batteries. Then there is the question of wear out. Wear out depends on a number of factors, such as the number and depth of discharge cycles and the ambient temperature. The batteries may be half the cost of the battery system and a fourth the cost of the entire installation. Replacing them will be expensive, but a failure to replace them will result in loss of premium peak revenue and possible midday curtailment. The record of early adoption of new techniques is not necessarily good, as shown by the experience of the Ivanpah and Tonopah thermal solar plants. In nevada there are already many gas turbine peaker plants that still have a long life. It makes no sense to replace these with solar charged batteries that will produce more expensive and less reliable electricity.