The Bright Future of Solar Energy in New England

By Eleanor Saunders

Experts expect global market dynamics for solar energy to change dramatically in the next year, with two important results. The price of solar photovoltaic cells (PVs) could fall by as much as 25 percent, and solar developers from Europe are setting their sights on the U.S. as the next best market opportunity. Although California and the Southwest come to mind first when thinking about energy from the sun, it is Northeastern states, with their high electricity prices, large concentrations of customers and support for renewable energy, that may be the most attractive region for developers. And within the region, Massachusetts is the state that has developed an incentive structure for solar energy that many believe may become a national model.

This viewpoint was consistently expressed by solar-energy experts who spoke last month at the Restructuring Roundtable, a forum that meets six times a year in Boston to discuss trends and policies affecting the energy industry and the power grid throughout New England. Despite the present controversy over the bankruptcy of Solyndra LLC – the manufacturer of solar panels that failed after receiving a $535 million federal loan guarantee —  prognostications about the future of solar are bright, said professionals representing both the public and private sectors.

Relevant Global Conditions

The background to this shift in market dynamics was laid out by Chris Porter, a lead analyst with the consulting company Photon Energy. Over the period 2005 – 2011, there was a sixteenfold increase in sales of PVs, fueled chiefly by generous government incentives in Germany, Spain and Italy.  As a result of the heated market, a disconnect developed between the actual cost of producing PVs and their list prices, with the latter rising in response to the policy-driven spike in demand, said Porter.  Buyers continued to purchase PVs despite high price tags, because incentives drove down purchasers’ out-of-pocket expenses, he said.

Porter explained further that a bottleneck in the supply of polysilicone, a key component in the PV manufacturing process, also made an important contribution to the market imbalance.  In response, industry began investing to boost its production of the compound, which is now expected to expand fivefold by 2015 from where it was in 2009, he said.[1]

But just as the industry was kicking into high gear, circumstances in European began to dampen demand for PV. The important German market reached a saturation point after having installed about 25 gigawatts of solar power, the equivalent of approximately 15 to 20 percent of the country’s generating capacity and 30 percent of its peak load demand.  And other European countries like Spain and Italy, who previously had expanding solar markets, are not able to take up the slack because of Europe’s continuing financial crisis, said Porter.

Porter anticipates that 2011 will see the first leveling or even contraction of demand, which should cause prices to fall to between about $1.20 per watt (for low-cost solar panels) and $1.50 per watt (for more expensive, high- efficiency U.S.-made panels).

With European markets less active and the Chinese market largely closed to outsiders, many large solar developers are planning to expand into the U.S., and one of the most attractive regions is the Northeast because of its high electricity rates and large market size, said Porter.  The challenge for U.S. policymakers will be a classic “Goldilocks problem”: how to prevent the market from getting too “hot” as it did in Spain, Italy and other European countries, while not letting it become too “cold,” he said.

An Answer to the “Goldilocks Problem” in Massachusetts

Many experts believe that the new Massachusetts approach to expanding PV installations will achieve the sort of balance that Porter recommends. Through the careful design of the Solar Carve-Out component of its Renewable Portfolio Standards, the state should be able to create a market that is neither “too hot” nor “too cold,” said Dwayne Breger, director of the renewable and alternative energy division at the Commonwealth’s Department of Energy Resources. The carve-out is a market-based incentive program that aims to support residential, commercial, public and nonprofit entities in developing 400 megawatts (MW) of solar power across the Commonwealth. The carve-out should contribute the bulk of the nearly 500 MWs of electricity that the state’s combined solar programs [2] are expected to create by 2016-2017, a target well beyond the initial 250 MW solar goal set by Gov. Deval Patrick in 2007.

Like other states, Massachusetts has a requirement for utilities to hold a certain amount of solar power within their electricity portfolios, either by developing their own solar projects or providing an alternative compliance payment through the purchase of Solar Renewable Energy Credits (SRECs) from projects that have been qualified by the state’s Department of Energy Resources (DOER).[3] The SRECs, which represent one megawatt-hour of produced solar energy, are a source of financial support for project developers that comes from the private sector rather than from state government.

Beginning in 2010, the carve-out program set an initial annual minimum standard of solar generation, equivalent to 30 MWs of capacity, that was divided among utilities according to their market share within the state, Breger said. Each year, the minimum standard increases by approximately 30 percent, until generating capacity reaches a cap of about 400 MWs, at which point new project applications will be fed into the regular RPS structure, he said.

But beyond these basics, the Commonwealth’s program design differs from other states’ approaches through a two-tiered market structure for SRECs, which contains innovative self-correcting mechanisms that experts believe should resolve the “Goldilocks problem.”

In the first-tier market, the state offers SRECs, good for a one-year term, at a ceiling price that cannot be lowered by more than 10 percent annually, a figure that DOER has recently proposed be revised downward at the behest of market participants. [4]  The system’s pricing structure provides sellers with reasonable certainty about the income they will derive from SREC sales. Utilities may choose to purchase however many of the available SRECs they want at this price, which in 2010 was $600 and in 2011 $550.

For SRECs that haven’t been sold at the ceiling price, there is a second option, an annual state-run auction.  Any project may choose to put its remaining certificates into an auction account that has a life of up to 10 years. The auction market sells SRECs from these accounts at a set floor price of $300 per megawatt-hour, and the purchased certificates have a shelf-life of two years versus the one- year term in the first-tier market.  Utilities’ bids correspond to the number of SRECs they want to purchase.  The auction ends when either all certificates are sold or no more bids are forthcoming.  If SRECs are unsold at the end of round one, another round of bidding takes place, with the remaining SRECs reminted as three-year certificates.

But if the second auction doesn’t exhaust the remaining SRECs, then one of the key adjustment mechanisms kicks in.  It allows for the existing minimum standard of solar generation to be increased by the exact amount that would oblige utilities to buy all the unsold certificates.  Thus, a “too cold” market is warmed so that project developers are not left with unsold SRECs and a financial gap.

A second fine-tuning mechanism permits the state to adjust the number of years that new qualified projects may be part of the auction market.  Because of the time lag in getting projects up and running, there are more buyers than sellers at present, said Breger, and the opt-in term has been set at 10 years, giving developers a long-term financial guarantee.  But projects are coming on line rapidly and that term could be adjusted accordingly, he said.  If too many projects are being built, a shortened term would weaken the financial guarantees for developers, and the “too hot” market should cool down.

Once the carve-out program has been operating long enough for its fine-tuning mechanisms to be triggered, it will be possible to see whether the Massachusetts solution works as well in practice as in theory.

Broader New England Prospects

Spokesmen from Constellation Energy and the Solar Energy Business Association of New England completed the picture of solar’s prospects in New England as a whole.  Both agreed that the policies set up by Massachusetts had generated substantial activity, but need some adjustments to maximize growth.  With respect to the rest of the region, they described the potential for growth as moderate to optimistic for Connecticut and Vermont but low for New Hampshire and Maine, given existing policies. Rhode Island, though a small market, could prove interesting because of a recent unexpected legislative move, the business association spokesman said.

With 59 MWs of solar installed, 353 MWs in the interconnection queue [5] and an undersupply of SRECs from qualified projects for the alternative compliance market, Massachusetts is likely to continue its growth, said Dan Leary of Nexamp, a company that builds, owns, and operates renewable energy projects.  That growth is reflected in the more than 200 solar installation and development companies active in its market, he said.

But Leary, also president of the Solar Energy Business Association of New England, and Bryan Miller, a vice president of energy policy at Constellation Energy, concur that some policy snags will hold back projects.  These include uncertainties created by the expiration of tax exemptions associated with SREC costs from 2017 on, the cap on net-metering credit as it is currently set, and ambiguities or contradictions in net-metering regulations that may unintentionally disadvantage public entities interested in hosting solar installations.

Connecticut

Next to Massachusetts, Connecticut’s solar market offers the brightest outlook in the region, following the passage of sweeping energy reform in June through SB1243, speakers said.  The law expands the resources that can go into the state’s Clean Energy Fund and creates a quasi-public authority, the Clean Energy Finance and Investment Authority (CEFIA), to oversee it.  CEFIA will be responsible for developing programs to finance and support clean-energy investment, manufacturing, research and development, and for creating a program for zero-and-low emissions renewable energy credits (ZRECs or LRECs).  The law also mandates the creation of a residential PV program to produce 30 MWs of installed solar energy by 2022, and directs electric companies to develop long-term contracts by late 2012 for the purchase of ZRECs from clean-energy projects. They include solar installations that are one MW or less in size, with preferences given to technology originating in Connecticut.

Since the program is just being rolled out, many details remain to be filled in.  Miller says that the state would benefit from making several small changes at the outset, such as instituting a ZREC cap per entity to prevent market domination by a few players, establishing a property tax exemption for projects and allowing municipalities to receive net-metering credit for solar power installed through Power Provider Agreements or leases.

Vermont

Vermont is the other New England state that both Miller and Leary say will offer a moderate level of growth, consistent with its feed-in-tariff, which was established by legislation enacted in 2009.  But Miller said that only two or three out of a dozen awarded Vermont projects are actually under construction because of financial disadvantages associated with the state’s current tax structure. He suggested several fixes such as a property tax exemption, an alteration of the tax basis like the one available for wind and hydro projects, or the provision of grants in lieu of tax incentives.

Rhode Island

Leary also expressed interest in the Rhode Island market, based on its potential for growth in distributed generation. This opening was created by the June passage of a law that establishes a limited feed-in-tariff for 40 MW of distributed generation from wind energy, solar PVs, and aerobically produced biogas.  The law instructs the state to develop standard offer contracts for any such projects under five MWs in size, with the initial contracts for five MWs worth of generation to be ready by the end of 2011 and final contracts that meet the goal of 40 MWs overall to be concluded in 2014. Pricing for each type of renewable resource will be determined by an oversight board, and project costs may be recovered from the distribution system’s ratepayers.