Last week was a tough one for distributed solar markets in several states, as a remarkable number of renewable energy incentive programs hit their budget or capacity caps, or are shrinking in scope:
- San Diego Gas & Electric’s allocation of non-residential solar incentives under the California Solar Initiative ran out.
- The Los Angeles municipal utility solar incentive program is fully subscribed for 2010-11.
- The Illinois state rebate program is fully subscribed for FY 2011.
- The Long Island Power Authority municipal utility solar rebate program for commercial, government, and nonprofit participants if fully subscribed.
- North Carolina’s statewide green power program, NC Green Power, reduced both the maximum size of eligible solar systems from 10 kW to 5 kW and reduced the REC purchase price from 15 cents to 10 cents per kilowatt-hour.
The source of funds wasn’t a distinguishing factor – some programs used ratepayer dollars, others were state-funded, and one is financed through voluntary contributions. But in each case, the likely result is the same: a significant downturn in the distributed solar market. And it’s a result that has played out in various renewable energy markets for years. 
For wind, the federal Production Tax Credit expired no fewer than 3 times in 5 years, creating a boom-bust cycle of development each time Congress has let the incentive lapse. Since the last lapse in 2004, the policy has been renewed at the last minute twice, again leaving developers hanging.
For solar the problem isn’t just the inconsistency of federal policy (although we can see that in the inexplicable $2,000 cap on federal solar tax credits for residential solar that were lifted just last year), but rather a fragmentation of incentives between utilities and federal, state, and local governments. There’s probably no better illustration than the rainbow of incentive levels shown in this chart of state solar policies from SolarPowerRocks.com.
The result is a balkanized market for solar power, where a few states have very favorable policies and robust markets, and others lag. Until next year, when one state’s budget for solar falls and another’s rises.
The Byzantine array of solar policies across states fails to create the certainty required for renewable energy developers to grow the market to its maximum potential (or the most cost-effectively). And the inconsistency falls hardest on small developers, whose locally-owned projects deliver a bigger economic punch per kilowatt than the larger projects.
We can do better.
For starters, renewable energy incentives that have to compete with other budget priorities are doomed. State governments switch partisan control or face significant fiscal problems with regularity, and energy incentives are often seen as frosting on the cake. But even more importantly, state solar incentives too often involve incredibly rich rebates ($3.00 to $4.00 per Watt) with a very limited budget. Solar projects rush to market to get the incentive and then the entire business dries up.
Federal incentives are marginally better for consistency, if only because they use off-budget tax credits instead of cash payments. But tax credits also create market inefficiencies and constrain participation to those with large tax liability.
The effective formula for consistent renewable energy policy is a legal mandate for renewable energy production that puts the onus on utilities to support wind and solar from ratepayer funds.
Renewable portfolio standards (RPS), for example, create long-term market certainty. However, an RPS won’t let solar compete with wind, or encourage utilities to purchase distributed power when it’s more convenient to request proposals from a few large developers to meet their state mandate.
The California Solar Incentive (CSI) goes a bit further, stacking a long-term incentive structure funded by ratepayers on top of the state RPS mandate. But as seen in the news, funds for certain portions of the CSI have started to run out.
There’s a reason we often finish our posts here with feed-in tariffs. Unlike the fragmentation that currently plagues American energy policy, they provide a long-term market structure with less political meddling and fewer budget constraints. Unlike tax-based incentives, they allow for broader participation and more distributed generation. Like any policy, feed-in tariffs can be done poorly, as illustrated in the Spanish government’s overpayment for solar and abrupt retrenchment. But the problem was policy details, not the policy itself:
the Spanish tariff, with its high rates, created an artificial market, developers said. And unlike Germany, Spain had no system built in to reduce tariff rates if its capacity targets were exceeded. Indeed, there were no stepped reductions, or degressions, at all. There was no ability to react.
Feed-in tariffs can also become more effective through iterations, as seen in Germany and Ontario, where early issues were ironed out to make the policies more cost-effective and consistent. Price declines in those regimes have simply followed the falling costs of renewable energy systems.
Feed-in tariffs are a relatively new concept to American energy policy, but the experience is growing with policies enacted in Vermont, Oregon, and Gainesville, Florida. They may not be ready to supersede all other energy policies in America, but it’s worth aspiring to a more cost-effective and consistent market for renewable energy.
