The Solar Northeast is heating up. To stay current this summer we’ll be giving updates on Wednesdays, covering what is new and exciting from various markets found in the Northeast. We think solar makes excellent beach reading.

First up: Connecticut

Connecticut – A hard earned win

The Background: With the highest electricity rates in the country, new generation and transmission being hard to site, and very few other instate renewable choices, solar was always a nice fit for the nutmeg state.

In 2008 a group of stakeholders, of which Vote Solar was a member, convened to get recommendations for costs, benefits and best approaches for the future. We even got a study out of it. (Sound familiar?)

By the close of the next session in 2009 we had a bill that called for approx ~ 300 MW of solar. Unanimous passage in the House, but stalled in the Senate.

In 2010 we had unified support in both the House and the Senate and very similar bill structure. Late hour votes in both houses passed the bill. Unfortunately, it was vetoed by the Governor. We are told largely because of matters not related to the solar provisions.

Which brings us to this session. With a new governor set to make energy a big priority, advocates felt optimistic.

The Bill: SB1243 passed. And it is a doozy. Have a look for yourself (pdf, and hefty one at 180+ pages).

There are some important provisions and issues related to solar. Everything will hinge on the implementation process, and Vote Solar aims to be at the table.

* Residential Market: provides for 30 MW by 2022. It should turn out to be a nice steady market, but consistency will be important.

- The is a call for CSI style installation block program. That is, as certain megawatt targets are met, the incentives drop down. This is a responsible approach to building this market segment. However, the entity known as the Connecticut Clean Energy Fund (which will merge with other agencies as a result of the bill) has the ability to monitor and change this on an annual basis. We feel pretty strongly that too much tinkering with any market leads to disruption.

- Residential solar customers have a choice:

A) Participate in the rec market

or

B) Take an upfront rebate

But they can’t take both. Local installers are unclear so far as to which is preferred and this will be something to watch.

* The so called Z-REC Market (Zero Emissions)

Here is where things get tricky. First of all you have to understand this: legislators in Connecticut – as so many states – are extremely concerned with solar’s ability to meet goals and targets in a least cost fashion. (Despite having shown this here, here, and well you get the point).

So what the meat of this boils down to is the legislature saying, “Put your money where your mouth is.”

- RECs have a two-year life

- Price cap of $350/REC in 2012; regulators can lower price cap by 3% to 7% annually between 2013 and 2017

- Spending requirements for companies (essentially $8 million a year)

* 2012 – $8 million
* 2013 – $16 million
* 2014 – $24 million
* 2015 – $32 million
* After year 4, regulators will consider several factors to determine future spending requirements (stipulated guidelines are provided)

- Procurement solicitations

* Up to 100 kW
* 100 to 250 kW
* 250 to 1,000 kW

- Preference given to competitive bidding for systems above 50 kW ranked in terms of NPV

- Systems up to 50 kW are eligible to receive REC price equal to the weighted average accepted bid price in most recent solicitation for systems between 50 and 200 kW, plus an additional 10%

- Noncompliance fees in effect

Here’s the rub. First, we expect the RECs to trend very closely to the compliance payment price. Second, with a fixed price set to spend each year to procure solar, essentially the only growth in the market will occur with price declinations in solar.

Our conservative estimates paint this as — at least — a 20 mw per year market. But two things could blow that estimate way out of the water.

1. Connecticut will be one of the first states to reach retail grid parity.

2. Solar will have to continue to get cheaper in order for this to work.

Like we said, the solar northeast is heating up.

Vote Solar is a non-profit grassroots organization working to fight climate change and foster economic opportunity by bringing solar energy into the mainstream.

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What does solar cost? Pricing on utility contracts is often opaque–and there are some good reasons for this (e.g. to promote competition). An exception to this is in Nevada, where there are legal requirements to reveal contracts. Our friends at Evolution Markets recently sent out an email that culled some publicly available data.

NV Energy has applied for approval of several bundled PPAs, PEC-only purchases, and amendments. The highlights are as follows.

Doc: New PEC Contracts (Pecos Solar)
Price: $40/MWh + 1% Esc.
Provisions:5-yr term, 0.5 MW
Development Security = $13,610, Operating Security = $27,220; COD is 15 mos post PUCN approval.

What can we learn from this? Wholesale solar at this scale (20 to 30 MW) is around 12 cents/kWh (with 1% escalation). That’s a very competitive, scalable price for a lot of clean energy.

And the REC-only contracts are also a great deal from a ratepayer perspective. With these contracts, a customer installs a solar system designed to primarily serve on-site load. The main value of the system comes from reducing utility bills. In this scenario, the RECs are a marginal subsidy on top of the retail utility rate savings–they make up the difference to where the investment is economically viable for the customer. And in this instance, the ratepayers are making a very small investment–just $40/MWh, or 4 cents/kWh–to enable North Las Vegas Water Reclamation facility to get at 1 MW solar plant to treat LV’s effluent (insert jokes about clean energy for a very dirty job here). As the customer makes the bulk of the investment, this model is a very efficient use of limited incentive funds.

When we talk about creating both retail and wholesale markets, this is what we mean, and this is one of the reasons it matters.

Vote Solar is a non-profit grassroots organization working to fight climate change and foster economic opportunity by bringing solar energy into the mainstream.

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While recent news about renewable energy layoffs raise questions about wind and solar in the near future, there remains a healthy commitment in the US to creating strong incentives to move renewable technologies forward.

With most states and the federal government struggling to meet aggressive Renewable Portfolio Standards (“RPS”), regulatory agencies and governmental leaders are considering robust incentives to boost renewable energy production.

One incentive structure, which has played an instrumental role in driving solar investment in Germany and Spain, and wind in Denmark, are feed-in tariffs (“FITs”).  Originally experimented with in the US following the 1979 Energy Crisis, feed-in tariffs are starting to gain serious traction in the US.

This post highlights the Solar Electric Power Institute’s Feed-in Tariffs: The Good, the Bad, and What Utilities Need to Know seminar (a “how-to” guide for utilities) held on Thursday to discuss the pros and cons of FITs, design considerations, what utilities need to know about implementation, as well as case studies.  The seminar featured presentations from Wilson Rickerson (Rickerson Energy Strategies), Karin Corfee (KEMA), and John Crider (Gainesville Regional Utilities).

What are FITs?

A FIT is a legislative tool used to encourage the adoption of renewable energy by overcoming the expensive upfront costs of installations.  It goes something like this: renewable energy generation systems are built, utilities pay an (inflated) fixed price for the electricity produced, the price of the tariff decreases each year until ultimately, the renewable technology “stands alone” at the end of a predetermined feed-in period.

The primary goal of FITs is to encourage investment in renewables by smaller utility customers who then operate as distributed generators.  Imagine a distributed generation network of roof-top solar panels, wind turbines on farms, and fuel cells across a community — generated electricity (or stored excess) is sold back to the grid at a fixed cost guaranteed by the utilities.  With the introduction of smarter grid apps and innovative aggregation models, the business and economic benefits associated with distributed generation increase.

Why FITs?

Wilson Rickerson noted that FITs offer an effective way to achieve RPSs (for the US: 10% by 2012 and 25% by 2025), illustrated by the fact that Germany already surpassed its target of 12.5% RPS by 2010 riding FITs since 1990.  The California Energy Commission recognizes this fact and has suggested using FITs to close the gap between net metering and the state’s aggressive RPS (20% by 2010 and 33% by 2020).

FITs also guarantee long-term contracts (usually 15-20 years) and stable prices for those who install renewable technologies. They are also gaining traction of late because of the financial crisis — providing investor security in a period of uncertainty regarding tax equity financing.  And unlike tax rebates, they are revenue/income neutral allowing for wider participation.

The end result (in theory) is increased uptake for otherwise expensive renewable technologies via a legislatively mandated “boost” that puts the technology on an even playing field with cheaper default options.

Not All FITs Are Created Equal

In order to increase effectiveness and ensure incentives have the greatest impact, FITs should differentiate by technology (wind, solar, biomass, etc.), application (i.e. ground installations versus rooftop installations), and size.  These considerations are important when setting prices and contract lengths, but represent the greatest challenge.

In Europe, a split between FITs and Renewable Energy Credits (“RECs”) has sparked debate, though some countries are moving towards a hybrid model.  In the US, there is also wide differentiation between FIT proposals.  In the states considering FIT legislation, Rickerson explains that much of the debate revolves around what is actually being bought and sold: just electricity in Michigan, electricity plus RECs in California, just RECs in New Jersey.  There is also a difference of opinion about whether a premium should be paid only for excess generation (Hawaii legislation), or in Gainesville, whether FITs should interact with net metering structures (ultimately FITs replaced net metering).

FIT Buzz

Much of the attention at the seminar centered around Gainesville, Florida’s recent implementation of a municipal FIT, which is set to begin March 1, 2009.  John Crider’s presentation highlighted how the Gainesville Regional Utilities (“GRU”) got there.  He noted that it began with the discovery that upfront rebate payments and net metering structures didn’t provide the greatest incentive for larger customers (with the biggest roofs and largest potential solar installations) and provided low ROIs (which provided a poor investment vehicle).  So GRU sought to replicate the German model to increase renewable uptake in their municipal area by increasing solar incentives.

They began by coupling a local FIT with federal tax incentives, and created a simplified “seller friendly” contract to increase participation.  The result is a solar FIT that offers a fixed price for 20 years, assures competitive ROIs for system owners, and a tariff rate decrease (degression) with prices reevaluated annually to account for market realities.

Speakers were quick to note that FITs in Germany also started on the municipal level and spread across the country before national legislation was passed in 1990.

Lessons Learned

Rickerson noted that governments have proven to be better at setting prices than making assumptions about supply and demand, which makes FITs particularly useful.  Of course, setting the appropriate price is not always easy.

Karin Corfee’s presentation about the FIT policy analysis conducted in Hawaii is worth noting:

A FIT is best suited for renewable energy projects that lend themselves to the use of standardized energy payment rates and power purchase contract terms and conditions, and which can be developed and interconnected to the utility grid in a relatively predictable and systematic manner.

While the Hawaiian FIT proposal was developed with Hawaii’s unique island geography in mind, the policy considerations are illustrative.  It concludes that tariff rates should differentiate between technology type, project size, and project location.  Rates should also be cost effective and allow for a reasonable profit to be made.  Contract durations generally should depend on industry standard assumptions on the service life of the installation and recent contracting experience.

Corfee also discussed the FIT policy drivers (ranked by priority) identified by the California Energy Commission (“CEC”):

1. Increasing pace of renewable energy development to meet RPS objectives
2. Providing increased market certainty and financial security to help developers bring new projects online
3. Promoting a diverse mix of technologies (increased system reliability)
4. Develop a self-sustaining renewable energy industry
5. Insulate generation from fluctuations in price of natural gas
6. Help meet other policy objectives (e.g. biomass development)

Read here for a good discussion about the FIT policy debate in the US.

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