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Money and the Sun

Feb. 1, 2015
With state-level debates raging over net-metering and other incentives for residential solar systems, keep an eye on the economics to anticipate how quickly distributed generation may take hold in your market.

As the sun breaks through the clouds, its rays fall on racks of solar panels on rooftops across the neighborhood bringing a surge of electricity onto the grid. As another bank of clouds glides in and the houses return to drawing power from the grid for their occupants’ needs, the utility must have power plants ready to provide that power, and must have systems in place to handle the change.

The money side of that phenomenon — for instance, how building owners with rooftop solar panels pay for the systems and how much they are compensated for the power they provide the grid, as well as how the utility funds construction and maintenance and upgrades to the system to allow two-way flow of power — leads to some of the key questions about the growth of distributed generation. The answers vary from state to state and from utility to utility, and in the midst of several highly politicized legislative and regulatory battles, they can change from month to month. But the eventual shape of those answers will do a lot to determine where and how quickly distributed generation will make its impact felt in the electrical industry.

Electrical distributors, manufacturers and reps need to pay attention to how these battles play out in their local markets, because the outcome could shape demand for electrical products as new options for distributed generation systems emerge. Keep an eye on changes in policies regarding federal and state incentives, utility net-metering, interconnection and access to capital.

At this point, policies regarding distributed generation primarily apply to rooftop solar systems, but similar concerns accompany efforts to build markets for other distributed generation systems using everything from small-scale wind turbines and fuel cells to campus- or neighborhood-sized microgrids.

The most recent battles over setting rates and tariffs for connecting small-scale solar power to the electrical grid are playing out in a setting that is extremely contentious and inevitably turns on local politics and balances of power. Therefore, drawing hard conclusions on a national scale will be difficult for a time, but it’s not too soon to see how the various possible outcomes might affect the market for residential and commercial power systems.

A study by GreenTechMedia’s research group estimates that best-in-class residential solar systems will be installed for less than $3 per watt this year. Average systems, still estimated below $3.50 per watt, cost more because of higher costs in labor and supply-chain management.

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Federal and state incentives, most in the form of tax credits and rebates, provide a base incentive to help offset the cost of a solar system. The cornerstone of these incentives has been the federal government’s solar investment tax credit (ITC), a 30% tax credit for solar systems on residential and commercial properties. It was implemented in 2006 and extended in 2008. Unless given another extension, it now expires in 2016.

According to the Solar Energy Industries Association (SEIA), the ITC has helped annual solar installations grow by over 1,600% since its inception (a compound annual growth rate of 76%), and has provided market certainty for companies to make the kinds of long-term investments that drive competition and technological innovation, which in turn lowers costs for consumers.

The growth of solar, boosted by the ITC, has produced widespread benefits to the solar power sector, to the extent that employment in solar has been one of the biggest success stories in the recovery from the Great Recession.

More than 31,000 new solar jobs were created in the U.S. in 2014, bringing the total to 173,807—a 21.8% increase in employment since November 2013, according to The Solar Foundation. This made 2014 the second consecutive year that solar jobs have increased by at least 20%. In the U.S., there are now twice as many workers in the solar industry than there are coal miners, according to a story in Fortune magazine.

State incentives vary widely, and this is where major changes are being debated now. According to the latest data available from DSIRE (Database of State Incentives for Renewables and Efficiency), a goldmine of data operated by the N.C. Clean Energy Technology Center at North Carolina State University, 43 states and the District of Columbia have adopted statewide net-metering policies, 41 states have loan programs for renewables, at least 24 states have policies authorizing solar power purchase agreements, 38 states have property tax incentives for renewable power systems, 24 states offer tax credits for renewables, and 16 states have rebate programs. (Go to to explore this further.)

The past few years have also seen a flourishing of options for paying for a rooftop solar system. For many years, power purchase agreements (PPAs) by companies such as SolarCity received the warmest reception among those who wanted a solar system on their homes. But there are signs that PPAs are declining in popularity as more home owners prefer to own the systems outright.

In an interesting study titled “Banking on Solar: An Analysis of Banking Opportunities in the U.S. Distributed Photovoltaic Market” researchers David Feldman and Travis Lowder of the National Renewable Energy Laboratory (NREL) in Golden, Colo., take a deep dive on the evolution of financing for rooftop solar and the recent rise in popularity of owning the power system instead of leasing or paying a third party through a power-purchase agreement (PPA).

“A solar loan financing arrangement differs from third-party ownership (TPO) in several key aspects, including: the retention of ownership rights by the system host and its associated tax benefits and other incentives; the fixed nature of its monthly payment (similar to a lease but not a power purchase agreement [PPA]); and the variability in the size of payments based on the interest rate and tenor of the loan (i.e., individual payments spread over a longer period will be smaller in size).

“Several analysts and industry stakeholders have indicated that solar loans will increasingly capture market share relative to the TPO model in the coming years.”

Tied to this trend-change, a recent study by the Lawrence Berkley National Laboratory looked at the impact of solar systems on home resale values. In “Selling Into the Sun: Price Premium Analysis of a Multi-State Dataset of Solar Homes,” the researchers concluded that installing a solar system can boost the value of a home.

“Home buyers consistently have been willing to pay more for a property with PV across a variety of states, housing and PV markets, and home types. Average market premiums across the full sample of homes analyzed here are about $4/W or $15,000 for an average-sized 3.6-kW PV system.”

The most active, and contentious, side of the distributed generation money equation comes where a building owner wants to tie into the electrical grid and sell his or her excess power to the utility. The basic idea is hard to argue with: the owner wants to offset power that would otherwise be generated by a central power plant running on coal, gas, nuclear, and replace those electrons with power generated from distributed renewable resources. The devil in the details, however, speaks to how that transaction – known as net metering – should be compensated, and how the utility will continue to recover the costs of system construction, maintenance, upgrades and administrative overhead.

Early policies tended to give producers credit at full retail rates, hence the name net metering: power supplied to the grid less power drawn from it gives you the net.

Some utilities and their allies in the 43 U.S. states that have net-metering policies on the books are now pushing back against that arrangement. They argue that by receiving full retail rates for power fed back to the grid, distributed power system owners are being subsidized for the cost of the grid’s upkeep by other utility customers without such a system, including those lower on the economic scale.

In more practical terms, the utilities’ job is to provide reliable power to their customers, and the rapid introduction of intermittent sources of power onto the grids raise issues for grid stability.

Solar advocates characterize the move by utilities to roll back retail-rate net metering policies as an attempt to cling to the perks of a government-enforced monopoly in the face of new competition. They frame it as a moral question about whether the state governments, utility commissions and other rate-setting bodies support clean energy. The real rub is the loss of revenue and the likelihood that if net metering becomes less lucrative, fewer systems will be installed.

The battles over net metering involve more than just the rate applied. Other nuances include whether metered power will be calculated and “trued up” on a monthly or annual basis, the latter of which is prevalent at the moment. Utilities are pushing for monthly settlements while solar advocates enjoy the annual payment, which allows solar customers to bank credit for excess generation for a full year rather than a month.

There’s also the question of limits on the amount of distributed generation that will be allowed to join net-metering programs. Just over half of states with net metering policies today include caps on net metered capacity, and several states without caps have triggers that when reached enable net metering to be reviewed, according to another NREL study, “Status of Net Metering: Assessing the Potential to Reach Program Caps.”

“Currently, most states are substantially below their net metering caps or trigger levels, with the exception of New Jersey and Hawaii. Some utilities in Massachusetts and Vermont recently reached caps, prompting legislative action. New Jersey has exceeded its trigger level, where a review of net metering could be undertaken, but there is no binding net-metering program cap. Hawaii has placed restrictions on the availability of net metering and makes the determination based on penetrations at individual circuits.”

The issue of capacity limits as well as other aspects of net metering policies are being decided now in a number of markets, but a good leading indicator of how these debates may play out can be seen in Hawaii where the solar has already hit the roof. The cost of rooftop solar is already at parity with grid power there due to the high electricity rates in the islands. The result has been an influx of solar systems. Hawaii now has over 51,000 solar system owners.

On Oahu, Hawaii’s most populous island, for example, photovoltaic penetrations now exceed 75% of peak load on many of the Hawaiian Electric Company’s (HECO’s) distribution circuits, according to a study by the Solar Electric Power Association (SEPA) and the Electric Power Research Institute (EPRI), titled “Utility Strategies for Influencing the Locational Deployment of Distributed Solar.”

“Roughly 45% of the utility’s feeders contain PV penetrations that range from 75% to more than 120% of daytime minimum loads. These high penetration levels have created operational reliability concerns and led HECO to impose a moratorium on new grid connections in many parts of its service territory so it can reconstruct the interconnection process.”

The plan submitted to state regulators last fall by HECO, which serves the islands of Oahu, Maui, and Hawaii, calls for getting 65% renewables, tripling distributed solar and cutting customers’ bills 20% by 2030. To get there without breaking the bank, HECO’s proposal includes a cut in net-metering rates from full retail rate of $0.295 cents per kilowatt-hour to $0.147 per kWh on Oahu similar changes on the other islands. The reduction in payment has angered solar advocates, but HECO also increased the potential for solar penetration. After a third-party engineering evaluation of its circuits, the utility said it will increase the circuit threshold from 120% of daytime minimum load (DML) to 250% of DML.

Other states to keep an eye on include California, Hawaii, Massachusetts, Minnesota and New York.

No matter how these net-metering debates turn out, the persistent march of technology will again change the calculus down the road. The biggest potential disruptor is energy storage. Studies show that customers tend to prefer solar-plus-storage in markets where the value of excess solar generation has been reduced below retail rates. In fact, some argue that net metering is really only necessary in absence of storage options. Nobody has good storage options yet. Many are working on it.