1. The Policy Instrument: Two Laws, Two Maps

The German wind story is a tale of two regimes. The 1991 Stromeinspeisungsgesetz (StrEG) established a uniform purchase obligation—a clear revenue floor that turned a niche technology into an investable asset. A uniform tariff, however, behaves like a spotlight: it shines brightest where nature already provides the highest yield. Unsurprisingly, the early expansion clustered along the northern coast.

In the 1990s, the outcome was visible in the aggregate: wind capacity rose from roughly 106 MW (1991)to about 4,435 MW (1999). That’s the power of a guaranteed price—and also the distributional consequence of a policy that does not differentiate by resource quality.

The 2000 Erneuerbare-Energien-Gesetz (EEG) kept the guarantee but changed its logic. Under the “reference yield” mechanism, the effective support becomes location-aware: windy sites receive a shorter period of high remuneration, while lower-wind sites get a longer high-tariff phase. In plain language, the EEG tried to compress the return distribution—less windfall rent in the north, more viability inland.

Later revisions added sharper edges. One notable example: a minimum performance rule that effectively made very low-yield sites ineligible. That sort of threshold can look like a footnote in a law—and act like a cliff in the investment calculus.

2. Data & Empirics: Why a Tobit, Not a Straight Line

Wind investment at the county level is a classic “many zeros” process: in most years, most places do not build. That is not noise—it is the decision margin. The paper therefore uses a panel Tobit approach, treating observed additions as a censored outcome where the latent desire to invest only becomes visible once it crosses zero.

The key idea is to separate endowment from incentive. Wind potential is geography. Tariff revenue is policy. Grid density proxies connection costs (at least before regulation moves those costs around). With those pieces, the model asks: what makes a county flip from “no build” to “build”—and by how much?

3. What Moves Investment: Prices, Then Rules

The results point to a steep policy elasticity. Translating coefficients into aggregate marginal effects, the paper finds that a 1 €-cent/kWh increase in the FIT rate corresponds to roughly 764 MW additional annual capacity (1996–2010), and about 1,528 MW per year in the later 2005–2010 window. The mechanism is consistent with a demand-pull story: once revenues are guaranteed, capital becomes abundant.

There is also evidence of “regulatory kink” behavior: when eligibility hinges on clearing a cutoff, developers don’t just respond to prices—they optimize around the boundary.

But the more interesting result is not about prices—it is about who pays for the grid. In the StrEG era, grid density is a positive siting factor: developers gravitate to places where connecting is easier. After 2000, that relationship collapses. When upgrade costs are shifted toward grid operators, the private scarcity signal fades. Investment becomes less tethered to local network reality.

4. Uniform vs. Differentiated: A Trade-off You Can Quantify

The EEG’s design looks inefficient if you only care about raw output per turbine: concentrating in the windiest areas yields more MWh for the same installed GW. A uniform policy calibrated to match total capacity delivers slightly higher total generation.

Yet the differentiated EEG can still win on euros per outcome. By paying less to infra-marginal, high-yield locations and reserving the higher effective support for marginal inland sites, the policy reduces windfall rents. In the paper’s counterfactual comparison, the EEG achieves modestly better output-per-euro and meaningfully better CO₂ abatement efficiency per euro.

5. The Grid Blind Spot: When “Deployment” Outruns “Integration”

There is a strategic lesson here that travels well beyond Germany: a subsidy that ignores networks treats the grid as a “copper plate.” That fiction can accelerate early deployment—but it accumulates physical debt. If investors are insulated from congestion costs, siting becomes subsidy- and resource-driven, not system-driven. The long-run bill arrives as curtailment, redispatch, and corridor politics.

The cleanest critique is simple: the EEG had an elegant answer to heterogeneous wind quality, but no comparable answer to heterogeneous transmission scarcity. The result is an energy transition that is statistically successful and operationally stressed.

6. Takeaways: Design the Signal, Not Just the Subsidy

Feed-in tariffs can be remarkably effective in mobilizing private capital. But the details matter: the “reference yield” design shows how a policy can shape spatial equilibria, not just national totals.

The next iteration of “smart support” should treat the grid as part of the market design. Whether via locational pricing, connection charges, or explicit coordination with network investment, the goal is the same: keep the revenue certainty that unlocks financing, while reintroducing the scarcity signals that keep the system buildable.

Citation: Hitaj, C., Schymura, M., & Löschel, A. (2014). The Impact of a Feed-In Tariff on Wind Power Development in Germany. ZEW Discussion Paper No. 14-035.