All renewable energy project developers, from first-time rooftop solar customers to seasoned municipal wind developers, must ask themselves: "how much does each kilowatt-hour (kWh) have to be worth for this investment to pay off? Can $0.15/kWh support a 2 megawatt (MW) photovoltaic array? Can $0.05/kWh? And what if there's no assurance which rate the project will receive until its completion?" Many prospective renewables developers are currently grappling with this last question in Massachusetts, and the state's Department of Public Utilities (DPU) holds the key to its resolution.
Current federal law, under the Public Utility Regulatory Policy Act of 1978 (PURPA), requires distribution companies to accept electricity from certain distributed generation sources, called "qualifying facilities," and to pay for that electricity at "avoided cost" (a wholesale electricity rate set by each state equal to the marginal cost of new generation). In Massachusetts, however, the state's "net metering" policy allows retail customers who own certain distributed generation facilities to receive retail rates for the electricity they produce in the form of credits against their electric bills. Because cost recovery through net metering is structured as a credit, its value is highly dependent on the use case. Customers with high on-site demand whose electricity requirements do not fully consume their generation stand to gain the most from net metering. Net metered facilities often use renewable energy but have historically included small, gas-fired combined heat and power projects as well. Massachusetts is not the only state to offer net metering, but while the Federal Energy Policy Act of 2005 strongly recommends that states mandate net metering as an option to utility customers, there is no federal requirement to do so. So far, over 40 states have acted on this recommendation, though the exact parameters of each state's net metering laws and regulation vary widely.
The Massachusetts Legislature first adopted net metering for renewable energy facilities in 1982—well in advance of federal encouragement. As in most states, the legislature placed responsibility for its implementation with the state public utilities regulatory agency, DPU. A burgeoning policy emphasis in recent years on the deployment of renewable energy has precipitated expansion of both allowable individual system capacities and mandated distribution company purchases under net metering structures throughout the United States. Massachusetts is a good example, as the state considerably increased allowable facility capacities with comprehensive energy legislation in 20081 and continues to refine its programs through DPU stakeholder proceedings.
Current Massachusetts law distinguishes between net metered facilities (a) owned or used exclusively by municipalities or other government entities, (b) owned by or serving the energy needs of ten or more residential customers in a neighborhood, and (c) owned by other private electricity customers. DPU regulations also classify net metered facilities and project proposals based on their generating capacity; Class I covers facilities of 60 kW or less, Class II above 60 kW but no more than1 MW, and Class III facilities of greater than 1 MW but no more than 2 MW.3 Furthermore, municipalities and other government entities may own or use an aggregate of 10 MW of generation capacity that is eligible for net metering, though each net metering facility must be of a capacity within the Class II or Class III range.
Distribution companies must reserve 3% of their respective historic peak loads for net metering customers, of which 1% is reserved for private projects, and 2% for public projects.2 A facility's capacity as well as its technological and input requirements determines its eligibility for net metering payments. For Class I facilities, any generation technology is permitted. For Class II and III facilities, only: (a) an RPS Class I or RPS Class II4 renewable energy generating source that is providing energy to an agricultural business and located on land owned or controlled by such business, or (b) a solar- or wind-powered facility is eligible for net metering. The framework's inclusion of both ownership and use in determining categories allows participants to choose ownership structures that make the most economic sense, whether that means customer ownership of the facility or a third-party ownership model.
The final layer of the Massachusetts net metering structure is the calculation of credits for customers. Each eligible project earns credits on one of three calculation schedules. The lowest schedule applies only to Class I facilities that are not agricultural, solar, or wind facilities, and uses the regional average monthly wholesale electricity clearing price. The middle schedule applies to certain Class II or Class III projects owned by "neighborhood associations" and any privately owned Class III facility; that price is the sum of the default service, transmission, and transition charges. The highest schedule covers all other eligible projects, and sets the price as the sum of the default service, transmission, transition, and distribution charges.
As net metered project capacity grows, so does the ceiling for project cost and complexity. Larger projects, those close to 1 MW and above, pose unique challenges to retail electricity consumers compared to the 30 kW rooftop solar arrays originally envisioned by net metering policies. The financing model often used for small generators, purchasing the system outright and recouping the relatively modest investment over the course of several years in the form of lower electricity bills, does not always scale well. The upfront cost of purchasing a large system is often prohibitive, and the difficulty of operating and managing a larger net metered facility often calls for outside expertise.
Project developers seeking financing must assure banks and other lenders that excess generation will be compensated at a rate sufficient to assure debt repayment. Because the aggregate capacity of net metered facilities is capped for each distribution company, it is not enough that the project developer has complied with all requirements. Eventually, eligible projects could be barred from these incentives because the cap has been met. The only true assurance that a project will receive net metering benefits is acknowledgement of eligibility and reservation of capacity by a distribution company. Massachusetts provides this assurance through the "net metering queue."
The precise substance and process for determining a project's queue eligibility is the basis for the Massachusetts DPU's current proceedings. Since February 2011, DPU has held ongoing stakeholder hearings to discuss the specifics of the queue and in late April issued its "Staff Proposal." This proposal instructs distribution companies to allow a project developer to occupy a place in its queue, reserving a stated amount of capacity within the strict aggregate cap, upon submission of a complete application to interconnect as a net metering facility. There will be strict deadlines for exiting the queue (i.e. when a project becomes operational or fails to achieve its required development milestones) that will likely vary based upon project specifics such as energy type, facility Class and ownership.
Under the DPU proposal a complete application would include: (a) an executed interconnection service agreement tendered by the distribution company, (b) adequate site control (a sufficient interest in real estate or other contractual right to build the facility at the location specified in the interconnection service agreement), and (c) all necessary governmental permits and approvals to construct the project. The last of these allows an exception for "ministerial permits," such as a building permit (notwithstanding the pendency of any challenge to the granting of any such permit or approval). While this proposal provides some of the assurance project developers seek, it is lacking in one important respect; project developers may not extend the reservation period beyond that granted by the DPU, and may not make material changes to the project without losing the allocation. Should these restrictions remain project development may suffer, as such minor delays and changes are the norm in renewables development of this scale.
Ultimately, it is unclear whether DPU will create new regulations based on its proposal, and discussions with the industry. It is clear, however, that project developers, and their lenders, are in need of the assurances that such regulations would provide. If DPU does provide new regulations it will have to undergo the rulemaking process, including notice and opportunity to comment. Prospective project developers are well advised to keep abreast of DPU activity in this area.
Footnotes
1 The Green Communities Act. Mass. Gen. Laws ch. 25A § 11F.
2 In May 2011, an additional 1% set-aside was proposed in the legislature for privately-owned projects of agricultural entities, which would raise the overall cap to 4%. See Amendment #549 to H03400.
3 220 C.M.R. 18.02
4 RPS refers to Massachusetts' Renewable and Alternative Energy Portfolio Standard, which requires all utilities to obtain certain percentages of their electricity supply from renewable and alternative sources. RPS Class I and RPS Class II generation technologies and inputs are defined in Mass. Gen. Laws c. 25A § 11F(c)-(d).
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