Understanding How Each State’s Interconnection Standards for Distributed Generation Installations Differ

Feb 1, 2009 12:00 PM, By Beck Ireland, Staff Writer

Inside interconnection standards for each state, how EPAct 2005 encourages adoption of renewable energy technologies, and the difference between interconnection and net metering

Until recently, a major barrier to the widespread adoption of grid-connected cogeneration and small power production, otherwise known as distributed generation (DG), in the United States has been the inconsistent implementation of codes, standards, and regulations. Despite a 30-year federal law requiring electric utilities to buy power from independent companies that can produce power for less than what it would have cost the utility to generate the power, there is still very little renewable energy on the grid. Only about 7% of the nation's electricity came from renewable sources in 2007, with 1% from wind, according to the Energy Information Administration, Washington, D.C. Currently, there are only 20 electric utilities in the country that have more than 100 photovoltaic (PV) systems in their service territories, with only Pacific Gas & Electric (PG&E) in California as the exception, which touts more than 25,000 PV installations.

Wind farms pose interconnection issues that vary widely from distributed solar systems.

Before the development of national technical standards and the adoption of interconnection rules and procedures by the majority of states, electric utilities determined the technical and engineering requirements, as well as the policies, rules, and terms governing the interconnection process of DG projects. This gave the utilities the authority to decide how many systems could connect to the grid and under what circumstances.

This arrangement led many of renewable energy's proponents to cry foul over what they perceived as a conflict of interest, which often resulted in hefty processing fees, tariffs, and rates, as well as requirements for unreasonable amounts of liability insurance and redundant impact studies that caused considerable delays. “If you wanted to interconnect with the utility, unless you were a qualified facility (QF), you had to negotiate with them,” says Keith McAllister, P.E., distributed generation program manager, North Carolina Solar Center, North Carolina State University, Raleigh, N.C. “It was rarely the same process twice.”

In the absence of third-party standards, the fox was guarding the henhouse, despite the best efforts of the Federal Energy Regulatory Commission (FERC), Washington, D.C. In a survey taken in 2000 of 65 DG projects, ranging in capacity from 500W to 26MW, the National Renewable Energy Laboratory (NREL) discovered that all but seven of the 65 project owners encountered at least one significant interconnection barrier. In addition, 16 projects were either stopped completely or reconfigured as stand-alone systems.

Since that time, the Federal Energy Policy Act of 2005 (EPAct 2005) prompted many states to consider new standards or to reevaluate existing ones. “The lack of standards has changed dramatically over the last four or five years,” McAllister says. “In North Carolina, for example, even four years ago, there was no interconnection standard.”

In addition, with President Barack Obama's “New Energy for America” plan aiming to ensure that 10% of the nation's electricity will come from renewable sources by 2012 — and 25% by 2025 — many more states are adopting standards and policies in conjunction with the implementation of a new renewable portfolio standard (RPS) or the expansion of an existing RPS. Yet, policies and standards still need to be streamlined. “On the whole, distributed integration isn't really a huge problem until you start to get significant penetration on any one distribution line,” says Mike Taylor, director of research and education, Solar Electric Power Association (SEPA), Washington, D.C. “But as we get to really high numbers, will some of the requirements or guidelines be practical? Will the electric utility need to go out and inspect every single system? If there's a standard, if everything's UL-listed and the installer that's working on it has done dozens of these without any problems, can that person be short-listed — and instead of doing every system maybe they do a random sample?”

Although most recently adopted standards are favorable toward wind, solar, and other renewable technologies, they don't stop electric utilities from seeing these types of DG systems as thorns in their sides. “They see these projects as making their load balancing and their voltage regulation in the system difficult,” says Richard McComish, president and CEO of Billings, Mont.-based Electrical Consultants, Inc. (ECI). “It will always be difficult to schedule a wind project because you can't predict entirely when the wind is going to blow. So that means in certain areas of the country, like Hawaii, for example, they will have extremely constraining requirements on the amount of ramp down and ramp up of the wind for protection of the integrity of the power supply on the island.”

Accordingly, McComish also expects stricter constraints connected with permission to interconnect alternative energy projects in the future, as these types of installations become more popular.

National standards

Interconnection standards adopted by jurisdictions throughout the United States vary widely, although equipment used for interconnection are approved under two national standards: Piscataway, N.J.-based IEEE's 1547, “Standard for Interconnecting Distributed Resources with Electric Power Systems,” and Northbrook, Ill.-based Underwriters Laboratories' (UL) 1741, “Inverters, Converters, Controllers, and Interconnection System Equipment for Use With Distributed Energy Resources.” Without these national standards, DG equipment manufacturers would be forced to develop devices and protection equipment according to individual electric utility safety requirements. “The best devices that comply with those two standards are inherently safe and certainly recognized,” McAllister says.

Many states model their own policies on interconnection procedures developed by: FERC; the Interstate Renewable Energy Council (IREC), Latham, N.Y.; the Mid-Atlantic Distributed Resources Initiative (MADRI) working group, Washington, D.C.; and stand-out rules developed by states leading the way in renewable energy DG, such as New Jersey and California's Rule 21.

EPAct 2005 contains provisions for state public utility commissions to consider adopting time-based electricity rates, net metering, smart metering, uniform interconnection standards, and demand-response programs (see Interconnection Vs. Net Metering). It also empowered FERC as the primary entity responsible for setting reliability standards for the bulk power grid in North America. “Since then, FERC has taken on primary responsibility for setting new reliability standards,” says Michael Goggin, electric industry policy analyst for the American Wind Energy Association (AWEA), Washington, D.C.

Although not mandatory for state adoption, the commission has stated that it hopes states will adopt its rules to promote a more unified interconnection policy around the United States. The organization has established standard interconnection agreements and procedures for large generators (20MW or larger in capacity) and small generators (up to 20MW in capacity). “We wanted to standardize the process,” says Barbara Connors, spokeswoman for FERC. “We laid out everything necessary to connect to the grid. It's uniform, whether you're in Massachusetts, South Dakota, or Oregon.”

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