ILSR Senior Researcher John Farrell gave this presentation remotely to the Ontario Power Perspectives conference on April 16, 2012. He was supposed to be there in person, but he forgot to renew his passport. The presentation highlights how Ontario's "buy local" rule, bonuses for community ownership and focus on distributed generation make their feed-in tariff program very worthwhile.

Utilities often claim that allowing customers to run their meter backward (by generating electricity on-site, e.g. from rooftop solar) can affect their bottom line because these customers don’t pay enough to cover the cost of maintaining the grid.  In at least one case, however, a utility’s cost-benefit analysis of net metering was turned on its head in an independent review.

Presenting as part of Vote Solar’s Data Not Drama webinar on net metering last month, Interstate Renewable Energy Council’s (IREC) Joe Wiedman showed the Public Service Company of New Mexico (PNM) erred in proposed standby charge of 5.3 cents per kWh for net metering customers.  The utility asserted that this charge – ostensibly to backup these on-site generators – would allow the utility to recover its costs from these customers busily spinning back their meters.  IREC’s review of their analysis, however, showed that net metering was actually a net benefit to the utility.

The differences were substantial. While PNM had given almost no value to net metering systems, IREC’s review found that the on-site generation helped the utility avoid energy costs, line losses, capacity upgrades, and transmission costs worth over 15 cents per kWh.  Even when balance against the transmission and distribution costs, and power generation costs to the utility of supporting net metering, the policy had a net benefit of 7.8 cents per kWh, a 13-cent difference!

The following chart illustrates, with the perceived costs shown in red (positive) and perceived benefits in green (negative).

The lesson for advocates of distributed generation is clear: challenge utility valuation of net metering and of distributed renewable energy.  You can never be sure what they overlook.

In this April 2 presentation to the Pedernales Electric Cooperative of Johnson City, TX, I pointed out how solving the clean local energy puzzle requires much more than a consideration of cost per kilowatt-hour.  Instead, cooperatives, municipal utilities and others considering developing local clean power should consider issues of scale, value and ownership. 

Whether German feed-in tariffs or U.S. tax incentives, opponents of solar rail at its perceived high cost. But a story making rounds this week, "why power generators are terrified of solar," presents a powerful image that may flip this conventional wisdom on its head. Building lots of solar power can actually reduce electricity prices, to the dismay of utilities.

The story comes from Germany, where a decade of consistent policy has resulted in thousands of megawatts of distributed solar installed on urban rooftops and rural barns. This year, it was noted that the surge of "solar PV was cutting peak electricity prices by up to 40%." The following graphic of prices on the German electricity exchange – which Craig Morris calls "the afternoon dip" – illustrates the effect. The default view is 2008, showing steady, high prices in the market throughout the afternoon. Mousing over shows the same time period in 2012, where an abundance of solar has sharply cut afternoon power costs.

German Solar Shaves Afternoon Peak Electricity Price

What's happened is the "merit order effect." Because utilities have purchased all this solar capacity on long-term contracts, there is effectively zero marginal cost to taking the solar electricity onto the grid. And in Germany, there's enough solar electricity on sunny afternoons to completely offset the traditional spike in electricity demand created by air conditioning. So, instead of taking electricity from expensive gas peaking power plants or diesel generators, utilities have low-cost solar filling the gap, undermining the previous price peaks.

The fall in wholesale power costs from so much solar represents a delicious irony. For years, solar advocates have justified high prices as necessary to help the market mature and – because solar is such a small part of total power generation – that solar will cost the average ratepayer very little. The truth is that the impact of solar may be large, but in the opposite direction.

Ontario just completed a revision of their landmark feed-in tariff program and rates for renewable electricity generation and prices fell sharply: 30% for solar and 15% for wind power.  This continues a trend of falling costs for renewable energy around the world.   

As a bit of background, Ontario's feed-in tariff gives wind and solar producers (and many other technologies) long-term contracts at premium prices to support deployment of new renewable energy.  In a unique marriage of environmental and economic goals, the province also provides price bonuses to community-based projects and requires wind and solar projects to source much of their labor and materials within Ontario (for more on this, see our 2011 report).

Modeled after Germany's landmark program, Ontario is starting to see the price declines as their renewable energy market matures.  Here's a quick look at how the new prices stack up against world-leader Germany, as well as against two of the prominent feed-in tariff programs in the United States, Vermont and Gainesville.

For solar, Ontario pays a rate comparable to other North American jurisdictions, but all of them pay much more than Germany.  When converted to U.S. dollars, adjusted for the solar resource, contract length (for Vermont), and for the 30% federal tax credit (U.S. programs), Germany pays just half of what North American feed-in tariff programs do for the same size solar project.

For wind power, Ontario pays less than Vermont (which caps wind projects at just 1.5 megawatts), but still more than Germany's mature wind market.  Unlike its North American counterparts, Germany's tariff adjusts based on the quality of the wind regime.  In the reference scenario (~6 meter per second wind at a height of 50 meters), Germany's price paid is a full 2 cents per kWh less than American producers.  In a high wind scenario (7 meter per second wind), Germany pays even less.  Only in a low-wind regime does Germany's tariff price compare to Ontario.

Ultimately, the test of success for Ontario's clean energy program is its outcomes and public support.  Despite public outcry about high prices paid to renewable energy producers, the prospect for over 43,000 jobs and nearly 5,000 megawatts of clean energy sustained feed-in tariff supporters in the government and the program will continue. 

I suspect that these new lower prices will bolster support for Ontario's renewable energy program.

In their excellent interactive graphic, Bloomberg Energy Finance calls solar grid parity (when electricity from solar costs less than grid power) the "golden goal."  It's an excellent illustration of how the right energy policy can help a nation go gold on solar or wallow in metallurgical obscurity.  In the case of the U.S., it may mean delaying grid parity by eight years.

In the screenshot below, countries in purple have reached the golden goal in 2012, based on the quality of their solar resource and the cost of grid electricity, as well as a 6% expected return on investment for solar developers. (Note to Bloomberg graphic designers - countries meeting the golden goal could be colored gold)

By 2020, the universe of countries has expanded significantly, and includes the United States.*

*But this picture isn't accurate, because the type of solar policy influences investors' expected rate of return and solar policies vary significantly across countries.  In Germany, their feed-in tariff policy offers long-term, fixed-price contracts for solar.  This certainty and policy transparency means lower risk and investors accept a modest 6% return on investment. 

In the U.S., however, there is high uncertainty.  Incentives for renewable energy have a habit of expiring based on the vagaries of federal and states legislatures.  Incentives come in the form of tax credits, leaving developers dependent on a fluctuating market for tax equity partners to "monetize" the credits.  This higher risk means solar developers want higher returns (more like 10% than 6%).  (I wrote about this in a report last fall).

The 4% higher expected rate of return means another eight years of waiting for the golden goal, delaying solar grid parity in the U.S. from 2020 to 2028.

This highlights a huge irony in U.S. energy policy.  There's a strong bias toward "market-based" policy (auctions, renewable energy credit markets, etc), on the assumption that cutthroat competition to deliver solar will give ratepayers the best deal.  But the high risk to developers means an expectation of higher returns, so that the winning bids are likely higher than could be proffered in a low risk environment.

High risk means Americans will pay more for solar than their international counterparts.  It probably explains why Germans – with a decade of low-risk under their feed-in tariff – are installing solar for half the cost in America ($2.60 per Watt compared to $5.20).  It undermines the opportunity for local ownership, a key tool for spreading the economic rewards of and political support for solar power. 

Reaching the golden goal is inevitable, but a country's time of arrival depends heavily on its choice of solar policy.