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.
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.
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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The FERC standards address voltage and frequency ride-through requirements for wind-powered generators in particular. “These standards require the wind plant to remain online through system faults on the larger grid that can cause swings in the voltage and frequency at the point of wind-plant interconnection,” Goggin says. “The intent of these standards is to ensure that a fault does not cause a cascading system failure by causing generators to trip off-line when they experience momentary voltage and frequency deviations.”
Reactive power standards are also a common issue for wind plants, according to Goggin. The standards also require the reactive power output of the plant to remain within a certain range relative to the real power output of the plant.
The FERC standards establish a time line for each step of the application process, as well as determine reasonable fee levels through an extensive compromise and negotiation process. However, some states that have adopted interconnection standards have allotted a shorter time for the read-through of an application with small generators using UL-listed equipment.
Still, under FERC's standards, it's left up to the regional electric utilities to commission studies to determine reactive compensation requirements. “That ruling said that the regional operators of the transmission systems will do additional studies for every wind farm and every generator that gets connected, renewable or not,” says Timothy Poor, vice president, Global Sales & Business Development, American Superconductor Corp. (AMSC), Devens, Mass. “Frankly, it's not that difficult. You get the system impact study and go.”
However, Poor agrees that the requirements would benefit from a national standard instead of case-by-case studies. “That would make things a little simpler for the developers because it would be known up-front,” he explains. “It wouldn't be contingent upon waiting for a study.”
Whereas the federal government generally has jurisdiction over non-utility generating systems that are connected to electric transmission lines, individual states regulate the process whereby a small-scale, renewable energy system is connected to the electric distribution grid. Although the federal government has provided some degree of guidance to states on interconnection policy, interconnection standards vary widely from state to state.
As of September 2008, 37 states have adopted statewide interconnection standards, according to the 2008 edition of the Network for New Energy Choices (NNEC) report, “Freeing the Grid,” which rates states on the best and worst practices in their net metering policies and interconnection standards. According to NNEC, the best state renewable energy policies are those that maximize credit for excess electricity sent to the grid, reduce unnecessary and burdensome red tape/special fees, set clear goals/targets, and provide incentives to encourage homeowners/businesses to install renewable energy systems. If not designed well or enforced fairly, these policies can cause excessive time and monetary costs to the development of customer-sited renewable energy and other forms of DG.
Customers considering grid-tied renewable energy systems in states with well-designed interconnection standards have the advantage of a process that is transparent and equitable, and that often involves separate tiers of analysis depending on a system's size and complexity, similar to the IREC DG interconnection plan. “Under these tiered approaches, a reasonable cost structure and reasonable time frames are laid out,” McAllister says.
These tiers often involve a “fast track” for interconnecting well-understood systems, such as PV systems sized 2MW or less. “There's a recognition that the small inverter-based systems that comply with UL codes are inherently safe and don't need a lot of study,” McAllister says. “As you move up to larger systems, that changes. But at least there's a process.”
However, not all statewide interconnection standards in the 37 states that have adopted them are created equal. In fact, 13 states have not adopted statewide standards at all (see Map). States that perform poorly have policies that discourage homeowners and businesses from investing in renewable energy systems, for example, by requiring well-established, proven technologies to undergo rigorous, time-consuming, expensive reviews that dramatically increase the costs of the systems and the amount of time it takes for them to pay for themselves, according to the NNEC guidelines. In some cases, the interconnection process is so lengthy, arduous, and expensive that it stops the development of customer-sited DG. Historically, this has been highly problematic for potential developers of small DG systems. “States that do not have that — it's a real barrier to net metering and interconnection,” McAllister says. “Not just PV or wind, but any distributing generation.”
The complexity of the interconnection process depends on the size of the generator relative to the section of the grid to which it will connect and the ratings of the protection equipment. Every interconnection is different, but all interconnections share some fundamental characteristics. Electrical networks traditionally have been designed for one-way energy flow from large, remote power stations to urban centers. The use of intermittent renewable energy generators is more likely to result in bidirectional flow and may either help or burden the grid with issues of voltage regulation, unintentional islanding, protection coordination, and fault management. (For more on how renewable energy may be good for the grid, read “The Potential Benefits of Distributed Generation and Rate-Related Issues that May Impede Their Expansion” on the FERC Web site at http://www.ferc.gov/legal/fed-sta/exp-study.pdf).
Standards must include engineering requirements with respect to voltage, frequency, waveform purity, be able to rapidly isolate faulty equipment from the rest of the industry (see Kill Switch), and have a reasonable ability to withstand abnormal system operating conditions, such as fault ride-through. Depending on the context, there may be additional technical requirements with respect to control over output level and the ability to actively contribute to voltage management.
Improvements in renewable energy technology itself can play a large part in streamlining the interconnection approval process. Wind turbine technology, for example, has evolved over the last several years. “Most turbines sold today are able to comply with ride-through requirements without the need for external compensation,” Goggin says.
Smart Grid technology may also make a difference. “A game changer in the last five to 10 years is the advent of multi-function digital devices that take the place of all those protection devices,” McAllister says. “Now, you have one little box that does it all. It's much simpler for someone who knows what they're doing to design a protection scheme that meets the utility criteria.”
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Forecasting is also an important issue for all renewable energy resources, particularly those that are not storable. “Today, there is no proven, reliable, and cost-effective way to store the energy out of a wind project other than traditional storage means, like pumped hydro,” says McComish.
Therefore, wind farms may require network augmentation and possibly additional interconnectors to avoid flow constraints. “The places for the development of wind are not near where the population centers are that are using the energy,” Connors says. “So then it relies on grid development and interconnection.”
With estimates for a refurbished, renewable energy-friendly transmission grid at $100 billion, any technology that could accommodate that power is welcome.
Sidebar: Interconnection Vs. Net Metering
Although interconnection and net metering policies are often discussed together, they are separate issues. “Interconnection” refers to the technical and practical aspects of connecting a generator to the grid, whereas “net metering” is the provision of a state's law that allows customers to receive credit for the energy they produce when they are connected to the grid. Net metering is a market-based incentive — typically created as a commission rule, a state law, or a combination of the two — that establishes the process for crediting owners of customer-sited, grid-tied distributed generation (DG) for excess electricity fed into the grid to encourage small-scale, renewable energy generation. Where net metering exists in the United States, photovoltaic (PV)-generated electricity can be used on-site or delivered to the grid.
Under the Energy Policy Act of 2005 (EPAct 05), states were encouraged to adopt a net metering standard by August 8, 2008. As of September 2008, 40 states have statewide net metering programs.
Net metering laws establish how a set of electric utilities must treat the power produced by a grid-connected system. Under a net metering agreement, electricity that is fed back into the grid is credited based on a percentage of the utility tariff. Thus, customers who produce some or all of their power on-site from solar energy only pay for their net energy consumption during a set period.
“Some states true it up on a monthly basis, other states true it up on an annual basis,” says Mike Taylor, director of research and education, Solar Electric Power Association (SEPA), Washington, D.C., who explains that the annual basis time frame is more accommodating to the solar system. “Honestly, in most cases, solar systems are not sized to be anywhere close to annual consumption. It's more common to be something between 20% and 50% of annual consumption. So even on a monthly basis it doesn't happen that much, but just in case there's that delineation.”
System eligibility and procedures for handling net excess generation across billing periods vary by state and electric utility net metering policies.
“In some states you lose it, in others you get wholesale cost, and in a few states you actually get retail or a rate higher than wholesale cost,” Taylor says. “There are essentially 50 different states and 50 different solar markets. It has nothing to do with how much you pay for electricity or how much sun you have. It's essentially the business environment and the incentives that are available.”
Sidebar: Kill Switch
A 2008 report, “Utility-Interconnected Photovoltaic Systems: Evaluating the Rationale for the Utility-Accessible External Device Switch,” by the U.S. Department of Energy's (DOE) National Renewable Energy Laboratory (NREL), Washington, D.C., concluded that a redundant external disconnect switch only adds an economic burden on the customer and an administrative burden on the electric utility. The report goes on to say that UL-listed inverters for small interconnected generators already provide the desired safety functions. You may download the full report from the NREL Web site at http://www.nrel.gov/docs/fy08osti/42675.pdf.