With climate change legislation pending and an influx of stimulus-funded tax incentives, many entities are considering the benefits of installing rooftop solar photovoltaic (PV) systems. These systems generate on-site “green” electricity, which can be used to comply with both the likely carbon cap-and-trade regime as well as state and federal renewable energy standards. Despite these positives, however, significant hurdles to widespread adoption remain.
Most of the tax incentives are in the form of tax credits, which require an entity to have some form of tax liability. Many buildings that could be perfect for rooftop solar PV systems are owned by public entities, which do not bear tax liability, such as schools or jails. To leverage these tax credits as a financing mechanism, tax-exempt public entities across the country have sought to partner with taxable investors through the use of third party power purchase agreements (PPA).
In the third-party PPA model, a public entity such as a school would lease its rooftop space to a developer installing solar generation equipment, who would partner with an investor capable of using the tax credits. In turn, the solar generator would enter into a long-term (typically 15-20 year) PPA with the public entity, which would purchase the power and use it to offset some of the electricity use at its facility.
In theory, the third-party PPA model sounds like a sure-fire way to allow public entities to enjoy the benefits of renewable energy without encountering many of the installation or O&M headaches. In practice, however, significant state and federal regulatory intricacies threaten to complicate and derail these proposals. On the state level, state public service commissions regulate the retail sale of electricity, which is the sale of electricity to an end-use customer. On the federal level, the Federal Energy Regulatory Commission (FERC) regulates the wholesale sale of electricity, which is any sale for subsequent resale.
In the third-party PPA model, the rooftop solar generator entity sells electricity directly to the on-site end-use customer. In most states, this type of transaction falls within the general state regulatory reach and potentially subjects the solar generator to regulation as a public utility. Even a small generator with a PV system on the order of 500 kW runs the risk of being subject to all the regulatory requirements of the state public service commission. When dealing with installations on such small scale, the costs of regulatory compliance may outweigh the financial benefits of installing the system, discouraging such development.
Recognizing such obstacles, many states have enacted “safe harbors” such as net metering programs. These programs typically allow an entity to “net meter” with the local utility, offsetting its own electricity generation against what it receives from the utility, and only paying for the total net amount provided by the utility. A handful of states, most notably Oregon, have specifically endorsed the third-party PPA model, while many states have taken other steps in the direction of scaling back state regulation to encourage renewable development.
Though net metering promises to ease some of the state regulatory hurdles, it implicates an entirely different set of federal regulatory issues. In particular, in a net metering arrangement, at certain times electricity may flow from the on-site end-use customer back to the grid. This electricity is presumably resold elsewhere. An argument could be made that this subsequent resale renders the original sale a sale for resale—that is, a FERC-regulated wholesale sale. If so, any net metering arrangement for which there were a possibility of “running negative” at any point could potentially trigger FERC regulation.
FERC recently provided some clarity on this issue and confirmed that it would not exercise jurisdiction over certain net metering arrangements with rooftop solar PV installations.
A solar PV developer, Sun Edison LLC, requested a declaratory order that its retail sale facilities were not FERC-jurisdictional. Sun Edison installed solar PV systems and then sold that energy output to the on-site end-use customer, which subsequently entered into net metering relationships with local utilities. Sun Edison sought a declaratory ruling that FERC would not assert jurisdiction over the flow of power to the grid occurring under the auspices of a state net metering program as long as there was no net sale over the course of the relevant billing period.
FERC agreed and held that as long as there was no net sale back to the utility over the relevant, one month billing period, the sale of electric energy by Sun Edison to the end-use customer was not a sale for resale, and the transaction was not FERC-jurisdictional. The Sun Edison decision provides clear, bright line rules for solar developers and removes one potential hurdle to rooftop PV development.
In a field with so much confusion and uncertainty, such clear guidelines from FERC and from state public service commissions can enable investors to make long-term decisions about installing solar PV systems. As regulatory bodies continue to clarify jurisdiction and provide accessible standards, the public can expect to see accelerating deployment of rooftop solar PV systems.
Thomas McCann Mullooly is a partner in the Milwaukee office of Foley & Lardner LLP and is the vice chair of the Energy Industry Team. He can be reached by phone at (414) 297-5566 or by e-mail at email@example.com.
Trevor D. Stiles is an associate in the Milwaukee office of Foley & Lardner LLP and is a member of the firm’s Energy Industry Team and Environmental Regulation Practice. He can be reached by phone at (414) 319-7346 or by e-mail at firstname.lastname@example.org.