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There is a significant potential for small renewable energy systems to contribute to our nation's electricity supply, and to avoid the environmental impacts of using electricity generated from fossil fuel, nuclear, and even large-scale renewable energy power plants. For a variety of reasons, there are relatively few small renewable energy systems that produce electricity connected to the electricity transmission and distribution system or "grid." However, large increases in electricity prices in some regions of the country, growing public recognition of the environmental benefits of renewable energy, and attractive financial incentives offered by some state governments, are contributing to an increase in grid-connected systems on residences and businesses.
For the purposes of this discussion, a small renewable energy system (SRES) is one that converts renewable energy resources such as wind and solar energy, the energy in moving water (hydropower), or biomass or biofuels, to electricity, and that is under 100 kilowatts in capacity. These systems may be cogeneration systems in that they also produce heat or steam for space or water heating and agricultural or small industrial processes, or to create mechanical energy. These systems may also be classified as "distributed generation," as they can be located throughout the grid.
There are three general categories of ownership for grid connected SRES. The first is an electric power producer, being either a public or municipal "utility," an electric cooperative, an independent power producer, which installs a SRES on their own property, or on property that they rent or lease, and sells the power from the system to someone else. The electricity from the system is the "property" of the system owner who sells the electricity to any customer of the power supplier. The second type is that a property or building owner purchases, operates, and maintains a SRES. The system owner uses all or most of the electricity that the system generates, and any excess is put into the grid. The distinction between these two categories is that in the second, the SRES owner is not primarily a power producer or supplier. A third category is something in between the other two. An example is where two separate companies, such as an energy service company or independent power producer and a commercial building or manufacturing plant, share ownership and/or the sales of energy produced by a SRES located on the property of the building or plant. Cogeneration or combined-heat-and-power plants are examples of this type of SRES.
This information brief provides a general overview of issues for grid-connected SRES owners, according to the regulatory conditions that exist as of June 2003. This information is only a general guide, and is not a substitute for experienced legal and technical counsel for anyone considering a grid-connected SRES. Note: if your intention is to install a SRES with a generating capacity of less than 50 kilowatts, and are not intending to sell the power produced by the system, then the sections on Net-Metering and Utility Interconnection Requirements below will be the most relevant.
Legal Access to the Grid
The ability to legally connect a SRES to a grid will depend on federal, state, and local government rules and regulations. They are of two general categories: those that allow connection and those that determine how the physical connection is done. The legal "right" to connect to the grid is provided for in federal laws such as the Public Utilities Regulatory Policies Act (PURPA) of 1978, and by state government "net metering" statutes. PURPA allows grid access to small, independent power producers who want to sell power. Net metering allows grid connection for systems that generally do not produce more power than the system owner uses over a one-month period.
PURPA and Other Federal Laws
PURPA requires "regulated" utilities (investor owned companies) to purchase electricity generated by a Qualifying Facility (QF). A QF is a power plant that uses renewable sources of energy such as biomass, geothermal, hydroelectricity, solar (thermal and photovoltaic), and wind, or is a cogenerator that produces both heat and electricity using any type of fuel, and which has a generation capacity of less than 80 megawatts (MW). PURPA requires utilities to purchase electricity from a QF at a rate approved by a state utility regulatory agency [commonly called a Public Utility Commission (PUC) or Public Service Commission (PSC)], under federal guidelines. PURPA also requires utilities to sell electricity to these producers at just and reasonable rates. Some states have developed their own programs for implementing PURPA. Municipal utilities and electric cooperatives are exempt from PURPA. They are not regulated by state government agencies.
The Federal Energy Regulatory Commission (FERC) is the U.S. government agency that has authority over interpretation and implementation of PURPA. To obtain QF status, the system owner, operator, or their legal designees or representatives of a QF should file either a notice of self-certification, or an Application for Commission Certification of Qualifying Status with FERC. The choice of whether to certify the facility through a notice of self-certification (for which there is no fee) or to apply for Commission certification (for which a fee of over $12,000 is charged) is up to the applicant. Contact info for FERC is provided below. Obtaining FERC QF status does not allow the QF to avoid meeting the conditions of the grid owner and local laws and regulations that define the conditions for physical grid connection (discussed below).
It is important to note that the electric utility industry is undergoing a process of "restructuring" (also called "deregulation," which, actually, it is not). The basic goal for this process is to reduce electricity prices by opening the generation and supply of electricity to greater competition on a wholesale and retail level. This process is occurring within the regulatory jurisdiction of both federal and state government agencies. Seventeen states and the District of Colombia have initiated retail competition or have set dates for when it should start. The experience in California during 2000 and 2001 dampened enthusiasm for restructuring. California suspended its restructuring efforts, and four other states put theirs on hold. The remaining states are not pursuing restructuring. Numerous versions of national restructuring legislation have been put forward by members of both houses of the U.S. Congress, and the President.
Related to this process is an effort by some members of the U.S. Congress to modify or even repeal PURPA, and/or to replace it with some other mechanism to ensure that the use of renewable energy resources will continue or even expand. These include a renewable ("green") power "portfolio standard," which means that a percentage of electricity must be generated from renewable resources by specific categories of power generators. Net metering for SRES owners (discussed below) is also included in some of the national energy proposals. Many states already have some of these mechanisms in place. Whatever the outcome of federal energy legislation and state restructuring efforts, it is likely that grid connected SRESs will be allowed, or even encouraged.
As this restructuring process proceeds, ownership or control of the grid is evolving. The FERC also has jurisdiction over electric power transmission in interstate commerce and when utilities make sales for resale in interstate commerce. In 1996 FERC issued Order Number 888, which established a set of principles for ensuring open access to such power transmission by independent power producers.
Order 888 did not directly address interconnection issues and FERC is now working on developing standard interconnection procedures. On April 24, 2002, FERC issued a Notice of Public Rulemaking (NOPR): Standardization of Generator Interconnection Agreements and Procedures (Docket No. RM02-1-000), in which FERC proposes to amend its regulations to require public utilities to file a standardized interconnection agreement and procedures that FERC will adopt, and to take and provide interconnection service. On August 16, 2002, FERC issued Advance Notice of Proposed Rulemaking (ANOPR) Standardization of Small Generator Interconnection Agreements and Procedures (Docket No. RM02-12-000), in which FERC proposes to adopt separate standard interconnection agreements and procedures for small generators below 2MW in size and for those from 2 to 20MW. As of June 2003, FERC was still considering comments on the above NOPR and ANOPR.
Net Metering or Billing
Many states and some individual utilities have established so-called "net metering" or net billing. This means that the SRES owner is only billed for the net amount of electricity that it consumes over a billing cycle (typically one month, but longer in some states). The SRES owner effectively obtains the same value for the output from the SRES within the billing period as it pays for electricity from the utility. If at the end of the billing period, the SRES has produced excess power, the excess is either "given" to the utility, or bought by the utility at a specified price or rate, which is usually much lower than the retail price.
As of June 2003, there were 33 states with state net metering statutes: Arizona, Arkansas, California, Connecticut, Delaware, Georgia, Hawaii, Idaho, Indiana, Iowa, Maine, Maryland, Massachusetts, Minnesota, Montana, Nevada, New Hampshire, New Jersey, New Mexico, New York, North Dakota, Ohio, Oklahoma, Oregon, Pennsylvania, Rhode Island, Texas, Utah, Vermont, Virginia, Washington, Wisconsin, and Wyoming. Individual utilities in Colorado, Florida, Illinois, and Kentucky offer net metering. Net metering is under consideration in several other states and the District of Columbia. Each state has restrictions on the types of technologies or fuels, the type of customer, and the capacity of the generating source that net metering applies to. Net metering provisions are also included in some of the utility industry restructuring bills being considered in the U.S. Congress.
Utility Interconnection Requirements
While local building and electrical code officials will refer to the National Electric Code (NEC) to approve a SRES, most utilities will have other requirements. The Institute of Electrical and Electronics Engineers (IEEE) has developed a standard (IEEE 929-2000) for the physical interconnection of photovoltaic (PV) systems with a grid. The IEEE is working on a standard (IEEE P1547) for grid intertie of "distributed generation" technologies, which includes most types of renewable energy systems and fuel cells. It is likely that many utilities and/or state government regulatory agencies will refer to IEEE 929-2000 and IEEE P1547 (when completed). However, an individual utility (or all the utilities in a specific state) may have other and/or additional requirements. The prospective SRES owner should contact the utility to determine its specific requirements and the application procedure.
Utilities are required (under PURPA) to make standard power purchase contracts available to QFs with system capacities less than 100 kW. Despite this, some utilities may be difficult to work with, or require the same application and connection procedures for a small system as a multi-megawatt, independent power production facility. The process of negotiating a power purchase/sale contract with the utility could be very expensive. Even then, the utility could charge miscellaneous fees that could greatly reduce the financial feasibility of a grid-connected SRES. The FERC order (see discussion above), if passed, could help reduce the complications for a QF when seeking grid connection.
There are several basic system requirements that must be met for most utilities to accept electricity from a SRES. The power must be of acceptable quality (as defined by the utility); have fault and voltage protection; and the SRES must automatically disconnect from the grid in the event of a power outage on the grid. Some utilities also require a lockable, manual inverter disconnect accessible only to utility personnel.
A SRES that produces direct current (DC) electricity must use an inverter certified for utility intertie application to change the DC electricity to utility grade alternating current (AC) electricity. The essential feature of grid intertie inverters is automatic disconnect to prevent the electrocution of service personnel working on the grid. The utility may require the installation of an inverter (and other system components) listed by the Underwriters Laboratory (UL), or other nationally recognized testing laboratory using UL standards, for grid interactive operation. Electricity code officials may require system components to be UL listed or recognized. Wind or hydroelectric turbines that have induction generators, and which require the grid to operate, may or may not need an inverter, depending on the characteristics of their power output and the utility's requirements.
There are two basic arrangements for metering a grid connected SRES with standard electro-mechanical kilowatt-hour (kWh) meters. Generally, the utility decides which one to use, but some state net metering legislation defines the metering arrangement. The first is to have one, non-ratcheted meter that runs forward when the SRES owner consumes the utility's electricity, and backward when the SRES feeds (excess) power into the grid. This is usually the least expensive arrangement. The second metering arrangement is to install two kWh meters: one for metering power from the grid, and the other for metering output from the SRES. Both meters move in a forward direction only. This allows the utility and the SRES owner to monitor how much power the SRES is putting into and how much the SRES owner is taking out of the grid. The utility may require this even in a net metering or billing situation. The SRES owner may have to pay to install and rent both meters, unless state law says otherwise. Some state net metering law requires the utility to pay for extra meters and/or manual disconnects, if the utility wants them.
It is generally the SRES owner's responsibility to meet and pay for the equipment requirements of the utility, unless the net metering provisions say otherwise. The utility may also charge additional costs for connection, billing, metering, switching, transmission and distribution upgrades, and miscellaneous administrative costs. The utility will probably require a liability insurance policy. It may be possible to add a rider covering the system to an existing home or business insurance policy.
Power Purchase/Sale Rates and Arrangements
PURPA requires utilities to purchase electricity from a QF at a rate approved by a state utility regulatory agency under guidelines established by FERC. PURPA also states that these rates are to be just and reasonable to the consumer and utility, in the public interest, and nondiscriminatory for the QF. FERC established the concept of "avoided cost" as the basis for utility power purchase rates. This is the rate that it costs the utility to generate power itself, or to purchase it from another provider. Remember that this may change according to any state or federal restructuring legislation or modification of PURPA and related state legislation. In many states with net metering laws, a utility is not required to purchase net excess generation in net metering situations.
The state utility regulatory agency determines the method for calculating the avoided cost rate. The utility uses the method to determine their rates based on their costs to generate or purchase power. The utility must then submit the rate(s) to the agency for review and approval. Therefore, each utility has its own power purchase rate(s). Typically these are much lower than the "retail" rate at which they sell power. It may be possible, however, for the SRES/QF owner to negotiate its own rate with the utility.
This is important because it is generally more expensive for utilities to generate and supply electricity during periods of high or "peak" demand. Peaks occur daily and vary according to the types of customers a utility has, and on climate and weather conditions. The highest peaks for utilities and regional grids generally occur on summer afternoons and winter mornings. Many utilities have rate schedules for commercial, industrial, and even residential customers and/or additional charges based on the size of a customer's individual peak demand and when it occurs. Typically rates and charges are higher during the utility's total demand peaks, and lower during off-peak periods. (This is often referred to as Time of Use Rates and Real Time Pricing). Electricity production by the SRES during the peak demand period is potentially more "valuable" to the SRES owner. It may lower, or avoid altogether, the amount of electricity the SRES owner has to purchase from the utility at the higher, peak rate. It may be possible for the SRES/QF owner to negotiate a higher price for the excess electricity it produces during the peak period, or to be paid a capacity credit for avoiding or reducing peak power demand. This requires more sophisticated and expensive meters, and additional billing and administrative expenses for the utility, which may pass them on to the SRES owner. The SRES owner will have to determine if this is a cost-effective option, if it is even possible.
Several utilities, and recently the state of Georgia, have initiated programs that allow SRES owners to obtain favorable prices for their excess power. For example the City of Aspen, Colorado, actually pays for output from a SRES at a "green" power rate. Georgia's Cogeneration and Distributed Generation Act of 2001 allows a SRES owner to receive the market rate for their green kilowatt-hours (kWh), which during peak periods could be more than 20 cents per kWh. The SRES owner is even given a choice of metering arrangements. The SRES can be interconnected on it's side of the meter and have a bi-directional meter to measure flows in each direction, or it can send all of the power from the SRES directly to the grid by connecting ahead of the meter. The latter allows the SRES owner to sell all the power it generates, rather than meeting on-site load with part of the energy and then selling any excess generation. Other utilities/jurisdictions with similar programs are Tampa Electric Company, the City of Ashland, Oregon, and San Juan County, Washington. In Pennsylvania, a green power cooperative, offers its members 20 cents/kWh for power from residential photovoltaic systems owned by it's members.
The economics of a grid connected SRES depends on numerous factors. These include the costs of purchasing, installing, and connecting the system to a utility, operating the system, purchasing electricity from the utility when necessary, and the value of any net electricity production sold to the utility. The value of power sales, the cost of electricity purchased from the utility, and the interconnection and transaction costs charged to the SRES owner by the utility, depend on the results of negotiations with the utility, as discussed above. There are a variety of methods for evaluating the cost and value of the SRES production. These include using standard discounted cash-flow techniques to determine the net present value and internal rate of return of the investment. Another way is to calculate the levelized life-cycle cost per kWh (LLCC) of the SRES's power production, and compare this with the rates at which the utility will buy and sell power. The LLCC is the total cost associated with the system over the life of the system (discounted to present value) divided by the total power output of the system (in kWh) over the system life. Utilities use sophisticated versions of this technique to calculate their kWh rates. Obviously, variables that have to be estimated, such as the life of the system, can have a significant impact on the estimated LLCC.
One advantage of a grid-connected SRES is that electricity storage capacity (such as a battery bank) is not necessary (though it may be desirable). The grid supplies power when the renewable energy resource is not available or cannot meet all the power requirements of the SRES owner. For example wind speeds, and thus the availability of wind power, are highly variable on a daily and seasonal basis in most locations, and the sun only shines during the day. In a situation where the SRES owner can obtain higher rates for production during peak demand periods, or for "green power," it could be economical to include energy storage capacity to dispatch power to the utility on demand. A small amount of storage capacity can also provide power in case the utility service goes down.
A variety of federal and state financial incentives are available for SRES depending on the type of the system and legal status of the SRES owner.
Credits: US Department of Energy (http://www.eere.energy.gov/consumerinfo/factsheets/ja7.html)