An interesting debate is playing out. The Center for American Progress (CAP) has put out a policy brief that argues that green energy purchase mandates do not raise local electricity prices. The Renewable Portfolio Standard (RPS) requires that a state's utilities purchase a given percentage of their power from low carbon sources such as wind, solar and hydro. In California, the RPS is set to rise to 33% by the year 2020. As of 2009, 12% of California's power comes from renewables. Is the CAP correct that further ramping up of the RPS will offer environmental benefits without imposing costs on electricity consumers?
For the CAP to be correct, it must be the case that the cost of generating renewable power is falling sharply over time. There is also the issue of "insurance". Given the variability of wind and sunshine, power producers must have alternative backup generators ready to produce. Given that good batteries for storing excess power do not exist, there has to be some slack in capacity to be prepared for contingencies such as when its a cloudy day or a day when the wind isn't blowing. These "backup plans" have costs to maintain them.
It is also the case that renewable power takes a fair bit of land. Is the opportunity cost of the land that renewables are being located on being incorporated into the cost of providing renewable power?
What the CAP article does not discuss is the incidence of the RPS standards. Are the public utility commissions by shielding consumers from price hikes simply lowering the profits of the electric utilities? One way to study this would be to conduct an event study and see if publicly traded electric utilities experience a drop in their stock price when new news about a more aggressive RPS is revealed. Such a finding would indicate that the stock market believes that their profits will fall because their cost of acquiring electricity has gone up.
If introducing the RPS neither raises consumer prices nor lowers the utility's profits, then such an RPS is a free lunch! That would puzzle the typical economist!
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From the inbox:
“I can’t vouch for CAP’s calculations, but the results are plausible.
First, in states that have separated generation from transmission and distribution, the wholesale price of electricity is set by “merit-order dispatch”. This works like an Econ 101 supply and demand diagram. The “load serving entities” project their demand a day ahead. Generating companies submit bids for the price at which they will supply electricity to meet that load. Generators are dispatched in order of increasing bids until the dispatched supply matches the projected load. (There then has to be some fine tuning when the next day arrives, but that doesn’t affect the matter at hand.) The wholesale price is the last bid accepted, and all generators receive that price. For this reason, there is an incentive to bid one’s marginal cost or slightly above, and in the absence of market power, the wholesale price will be roughly the marginal price of the marginal generator. Studies have shown that this is in fact about how it works out at least in PJM, the biggest of the regional transmission organizations (RTOs).
For present purposes, the point is that the only generating costs that matter for wholesale prices are those of the marginal generators, and other things being equal, it will go up or down as load increases or declines. It therefore is higher at 2 pm on an August afternoon than at 3 AM on a mild April night. Now consider what happens when one adds wind or solar. These generating technologies have close to zero marginal costs and therefore will be dispatched at the beginning. For other generating technologies it is as if there is a reduction in demand, and as with any other reduction in demand, the result is a lower wholesale price. The decline has nothing to do with whether wind or solar is cheap or costly. It does not rest on a change in total generation costs but rather on a wealth transfer from generators to consumers.
Second, while an RPS is likely to increase total generating costs (as distinguished from wholesale prices), that impact is likely to be very small. The reason stems from three features of a typical RPS: (1) The statute usually doesn’t require that a state’s electricity suppliers actually buy renewable-generated electricity but rather that they hold renewable energy certificates. These are tradable (like emissions allowances in C&T) and are created when electricity is generated by a qualifying renewable. (2) There is an alternative compliance payment that in effect places a cap on the price of RECs. (3) While a statute may ultimately call for, say, 20% renewables, this is reached by a ramp and most (or maybe all) states are still a good distance down the ramp.
So, suppose (1) the ACP is $0.02/kWh and RECs are selling at that level, (2) that the current RPS requirement is 5% of the electricity supply, and that (3) the average retail rate is (to make the arithmetic easy) $0.10/kWh. The average impact then would be 5% x $0.02 = $0.001/kWh, or 1% of the average bill. If the state has reached the 5% level over five years, the average additional rate increase stemming from the RPS would be 0.2%/year.
I would note that some states have a “solar carve-out” for which the ACP is much higher. However, the percentage of electricity supply subject to the carve-out also is a lot smaller, so the net result is about the same.
Finally, I would note that the above calculations probably overstate the reality. RECs often do not sell for the ACP. This in particular true in Maryland – I teach (as an adjunct) at Johns Hopkins and Maryland – because the state law does not require that the renewable-generated electricity be from new plants. As a result, the standard appears now to be satisfied mostly by diverting hydro from Pennsylvania and lumber-waste generated electricity from Virginia. The good news is that the rate impact therefore is VERY low. The bad news is that the contribution to the development of renewables is at least equally low.”
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