With the interconnection standard federally mandated, utilities and providers of distributed generation work toward implementation at the local level to increase DG penetration.
As the world around the US electricity infrastructure changes, it is becoming necessary to adapt to a new environment of increasing energy demand and growing potential for catastrophes. The US Department of Energy (DOE) quantifies the nation’s gigantic—and inherently vulnerable—electric grid as having over 5,000 power plants with 882 gigawatts of capacity producing 4,055 gigawatt-hours of electricity each year and about 100,000 transformers, 63,000 substations and 160,000 miles of high-voltage transmission lines that continuously provide electricity to 138 million customers across the country.
In addition to its ever-increasing size, the electric grid has not kept pace with surging demand. Electricity demand has increased from 1,500 billion kWh in 1970 to over 3,700 billion kWh in 2004, and is projected to reach 5,600 billion kWh by 2030. Distributed generation (DG) can greatly assist in both safeguarding the grid and meeting greater demand, but increasing the penetration of DG is a gradual process that is not proving to be free of challenges.
In 1999, concerned members of the Institute of Electrical and Electronic Engineers (IEEE) Professional Society realized this and started developing the IEEE 1547 Standard for Interconnecting Distributed Resources with Electric Power Systems (approved and published by the IEEE Standards Board in 2003), the primary standard of requirements for interconnection to the electrical grid which, like all IEEE standards, is to be reaffirmed every five years. Building on that accomplishment, the federal government, recognizing that standardization of interconnection requirements and procedures is necessary to achieve the many benefits of increased DG penetration, required states to consider the IEEE 1547 standards and establish best practices with the Energy Policy Act signed into law in 2005.
“New types of [distributed] generators, like wind, solar, and biodiesel, have different mechanical and electrical properties that interact differently with the grid, compared with traditional [central station] generators, such as coal-fired plants,” notes Tim Poor, vice president of Westborough, MA–based American Superconductor Corp. “Transmission system operators have been rolling out brand-new interconnection criteria worldwide over the last few years that are specific to renewable and alternative types of generation. These new criteria are designed to ensure stable operation of the grid and include strict requirements for continuous voltage control and dynamic voltage support of the grid.”
DG is any type of electrical generator located close to the point of use and producing alternating current that either has the capability of parallel operation with the utility distribution system or is designed to operate separately from the utility system and can feed a load that can also be fed by the utility electrical system. It includes small-scale (less than 20 MW) electrical generation and, in contrast to central power plant generation, DG combined heat and power (CHP) systems utilize the waste heat from the generation process as an additional form of energy for space or process heating, dehumidification, or for cooling through absorption refrigeration.
The reasons for facilitating proper, standardized interconnection of DG to the grid are many:
- Improved grid/EPS asset utilization. DG can enable customers to better customize their energy supply for their unique needs. For example, space heating (and cooling) often requires both thermal and electric energy. An onsite CHP system allows commercial or industrial customers to capture the waste heat and use it for local thermal needs.
- The provision of ancillary services, such as voltage support or stability, volt-ampere reactives, contingency reserves, and blackstart capability. DG can be used to provide ancillary services, particularly those that are needed locally, such as reactive power, as well as those that contribute to the reliable operation of the entire system, such as backup supplies and supplemental reserves.
- Clean energy. In CHP mode, DG has the potential to dramatically reduce industrial and commercial sectors’ carbon and air pollutant emissions and increase source energy efficiency.
- Lower-cost electricity. According to a study by JBS Energy for the Mid-Atlantic region, power consumption is reduced, particularly during peak periods, decreasing the market price of electricity for all consumers.
- Greater reliability and power quality. Some utilities have programs that provide financial incentives to customer owners of emergency DG units to make them available to electric system operators during peak demand periods, or when otherwise needed. In addition, several regions have employed “demand response” programs, where financial incentives and/or price signals are provided to customers to reduce their electricity consumption during peak periods. Some customers who participate in these programs rely on DG for power during peak periods.
DG can also be used to decrease the vulnerability of the electric system to threats from terrorist attacks and other potentially catastrophic disruptions, and to increase the resiliency of other critical infrastructure sectors as defined in the Department of Homeland Security’s National Infrastructure Protection Plan (NIPP), such as telecommunications, chemicals, agriculture and food, and government facilities. Many customers in these sectors have used DG to maintain operations when the grid has been down during weather-related outages and regional blackouts. The National Academy of Sciences’ National Research Council recently recommended development of technology for an intelligent, adaptive, flexible power grid—an area in which DG will play a major role.
Electric system planners and operators can use DG to improve reliability both directly and indirectly. For example, DG could be used directly to support local voltage levels and avoid an outage from excessive voltage sag, as well as increase the diversity of power supply options. DG can improve reliability indirectly by reducing stress on grid components; for example, reducing the number of hours that a substation transformer operates at elevated temperature levels. Power failures from overloaded components are reported to account for about 10% to 30% of all outages.
Businesses that are based on electronics can be harmed not only by outages but also by unstable power quality. Very brief sags in voltage or harmonic distortions can be particularly devastating to customers using sensitive electronics, such as Web servers, and biotech and semiconductor laboratories. Redundant systems can be a cost-effective means of ensuring required power quality and reliability levels.
- Energy and load management. Installation and use of DG systems can reduce peak load electricity requirements. Because most investment decisions for new plant and equipment in the electric power industry are driven by peak load requirements, reductions in peak load can displace or defer capital investments. In addition, reductions in peak load that typically occur during hot weather, can reduce electricity costs in situations where the last power plants to be dispatched from the “resource stack” are also the most expensive.
- CHP synergies. In CHP mode, overall energy effectiveness is enhanced, with CHP converting 80% or more of the fuel into usable energy to produce electricity and usable byproduct thermal energy.
- Reduced land use for power generation. Under certain circumstances, DG can have positive land-use benefits, including smaller land mass requirements, savings on acquisition costs and rights-of-way, and land retention for open space, agriculture, or public purposes. DG systems that are incorporated into buildings, in an engine room, on a rooftop, or adjacent, yield a smaller land use footprint.
IEEE 1547 Standards
The IEEE 1547 standard itself is one in a series of IEEE 1547 standards. IEEE 1547 establishes the technical specifications and requirements for DG interconnection along with IEEE 1547.1, which includes the test procedures for conformance to 1547. The additional standards in the IEEE 1547 series are guides or recommended practices related to special topics or cases of interconnection or DG. Currently, only the IEEE 1547.3 guide is completed and the others are still in development. Having been in effect for nearly its first five-year period, IEEE 1547 is currently scheduled for reaffirmation in 2008.
Thomas Basso, an engineer in the Distributed Energy Systems Integration section of the Electric Systems Center at the National Renewable Energy Laboratory (NREL) in Golden, CO, and secretary for IEEE SCC21, 1547, P1547.2, P1547.3, P1547.4 and P1547.6 standards development, points out that the IEEE 1547 standard is not a prescriptive approach to interconnection; neither does it prescribe specific equipment required for interconnection. Rather, 1547 provides universal, functional technical interconnection requirements that should be sufficient for most installations.
“There’s no single best way to implement the 1547 requirements when interconnecting with the grid,” Basso says. “But more importantly, no single best approach to support the grid exists. Further, if the grid has a disturbance on it and the voltage drops, the distributed generator could support the voltage–bring it up–but that’s not the current version of 1547. There are a number of ways to do that, and it’s known how to do that, but there’s not a universal way to do that. That’s a technical opportunity with various ways to achieve it, and it’s discussed in IEEE P1547.2. Additionally, I’m particularly excited about grid modernization—utilities using distribution automation, getting more power electronics into the grid, and getting more communications infrastructure inherent in the grid.”
Of special note, IEEE P1547.2, Draft Application Guide for IEEE 1547, which facilitates the use of 1547, was to be balloted by IEEE voters in late 2007. This guide is intended for practicing engineers, engineering consultants, and knowledgeable individuals in the field of DR. The IEEE P1547.2 Working Group of the IEEE Standards Coordinating Committee 21 on Fuel Cells, Photovoltaics, Dispersed Generation, and Energy Storage held numerous meetings to compile input for this key guidance document, which provides application details to support the understanding of IEEE 1547 and is intended to serve DR owners and operators as well as area electric power system staff.
This document provides technical background, application details and guidance, rationale, schematics and examples to facilitate the use of IEEE 1547 and enhance user understanding of 1547. Whereas a number of the topics in IEEE 1547.2 are beyond the scope of the mandatory requirements in IEEE 1547, topics in the guide are integral to DR project implementation. The guide includes illustrative approaches to IEEE 1547, although alternative approaches could be equally applicable.
The 1547.2 chapter 8 topics closely parallel those of IEEE Std 1547 chapter 4 interconnection requirements and specifications with each chapter topic quoted and accompanying application guidance provided. The 1547.2 chapter 9 covers IEEE 1547 chapter 5 test specifications and requirements and 1547.2 chapter 10 provides an overview of the interconnection process—information that is beyond the scope of 1547 but important to DR project implementation. Annexes in 1547.2 provide additional information and include a bibliography, glossary, and more detailed information about interconnection systems, DR and EPSs.
Voting on IEEE 1547.2 is conducted by the IEEE Standards Association (SA) through an open, consensus ballot process. Consensus means that no one category of balloting members amounts to more than 50% of the total ballot group, with voters designating themselves according to IEEE SA categories of producer, user, general interest, government, or other. The IEEE “open process” allows any interested individual to ballot, whether or not they are IEEE members, but that they respond responsibly, i.e., indeed vote if joining the ballot group. Also, voting responsibly means, especially if voting negatively, providing written comment(s) and suggested resolution(s) which, if used in a revised draft, would result in a change in vote to affirmative.
IEEE ballot registration is processed online, with each voter receiving an e-mail notification to submit a completed ballot, typically within a 30-day ballot period. After the first ballot, all votes are reviewed and each negative comment receives a written response and a revised draft incorporating certain comments that are recirculated to all balloters. The balloters then have the opportunity to change their votes based on the document revisions or the comments that did not result in revisions. If necessary, the ballot process is then repeated until at least 75% voter affirmation is achieved. Finally, IEEE SA reviews the final affirmed ballot document, all of the voting documentation and the ballots for its concurrence and approval.
National and State Progress
In major developments for interconnection standardization, a number of groups have established model approaches and procedures that can serve as a starting point for jurisdictional authorities to establish their own rules and procedures for DG interconnection technical requirements and protocols for DG project implementation.
First, the DOE’s Office of Energy Efficiency and Renewable Energy (EERE) and Office of Electricity Delivery and Energy Reliability (OE) offered best practices for consideration on March 15, 2007:
“EERE and OE recognize the importance of electric utilities adopting procedures for implementing interconnection requirements that allow for simple connection of distributed energy technologies to the electric grid. Promoting distributed interconnection furthers administration policy of modernizing our nation’s electric grid and can be accomplished in a manner that is fair to interconnecting generators, utilities, and ratepayers.
“Section 1254 of the Energy Policy Act of 2005 (EPAct) requires each state regulatory authority for its jurisdictional electric utilities (and non-state regulated utilities) to have commenced consideration by August 8, 2006, of whether to require interconnection service to any consumer the utility serves who has onsite generation and to complete its determination by August 8, 2007. The service is to be based on the Institute of Electrical and Electronics Engineers Standard 1547 for the Interconnecting Distributed Resources with Electric Power Systems. Several States have already established interconnection procedures, while other organizations have developed model procedures.
“Although EERE and OE do not endorse the model interconnection procedures of any single external organization, EERE and OE do encourage state and non-state jurisdictional utilities to consider the following ‘best practices’ in establishing interconnection procedures that follow.
“First and foremost, EERE and OE note that EPAct requires that agreements and procedures for interconnection service “shall be just and reasonable, and not unduly discriminatory or preferential.” As such, generators and utilities should be treated similarly in terms of state requirements.
“Create simple, transparent (1- or 2-page) interconnection applications for “small generators” (equal to or less than 2 MW), as noted in the FERC Order 2006.
“Standardize and simplify the interconnection agreement for “small generators” and, if possible, combine the agreement with the interconnection application.
“Set minimum response and review times for interconnection applications. Provide expedited procedures for certified interconnection systems that pass technical impact screens.
“Establish small processing fees for ‘small generators,’ otherwise the interconnection request must be accompanied by a deposit that goes toward the cost of the feasibility study, per FERC Order 2006.
“Set liability insurance requirements commensurate with levels typically carried by the respective customer class.
“Require compliance with IEEE 1547 and UL 1741 for safe interconnection.
“Avoid overly burdensome administrative requirements, such as obtaining signatures from local code officials, unless such requirements are standard practice in a jurisdiction for similar electrical work.
“Develop administrative procedures for implementing interconnection requirements on a statewide basis through a rulemaking or other appropriate regulatory mechanism for state-jurisdictional utilities to apply uniformly to all regulated electric distribution companies in the state. Where practical, state interconnection administrative procedures should reflect regional best practices and be comprehensive in scope. Administrative procedures should also be transparent to both small generators and electric distribution utilities.”
Two other approaches were established prior to signing of the EPAct.
The Mid-Atlantic Distributed Resources Initiative (MADRI)—a cooperative effort established in 2004 by the public utility commissions of Delaware, the District of Columbia, Maryland, New Jersey and Pennsylvania, along with the DOE, the EPA, FERC, and PJM Interconnection—published its Model Interconnection Procedures (www.energetics.com/madri) in 2005. Two key considerations of the procedures are to establish common requirements for DG interconnection, based largely on IEEE 1547 standards, and establish common rules and agreements for DG interconnection implementation. The model procedures are a starting point for each jurisdictional authority to complete the details and interpret or address technical queries on their own. A major motivation behind establishment of the procedures is relying on precertification and other means of adherence to IEEE 1547.1 to expedite interconnection.
In February 2004, NREL developed a precertification and certification model program for interconnection systems in which NREL offers to provide technical expertise and testing support on a case-by-case basis, develop test methods and standards and conduct round-robin testing to verify that every testing entity is conducting the tests as prescribed in IEEE 1547 and 1547.1. The program consists of four stages. In Step 1, interconnection systems are precertified by a Nationally Recognized Testing Laboratory according to IEEE 1547.1 criteria. In Step 2 (certification), the local distribution utility reviews the interconnection system for compatibility to the area EPS according to IEEE 1547 criteria. Step 3 consists of installation per the National Electric Code and local codes and a commissioning test that adheres to IEEE 1547. Step 4 prescribes additional requirements and conformance for utility operation needs in areas such as monitoring and metering.
During the development of the 1547 standards, Basso documented several important details about interconnection that the standards developers deemed significant but should be addressed beyond the IEEE technical standards level:
- Jurisdictional authorities need to clearly establish uniform and transparent details related to stating technical requirements, testing protocols and conformity assessment, and protocols to interpret and address queries.
- Lab accreditation and certified equipment are not universally accepted, which leads to the question of who decides and how.
- Should technical or other issues arise, no individual or group has been designated to resolve these issues, receive a formal query or dispute or to conduct a study.
- Decisions would have to be made regarding the accommodation of technology evolution and grid
modernization. - Jurisdictional authorities should strive for uniformity and transparency and that should help expedite national or international harmonization and reciprocity for testing, certification and conformity assessment for interconnection.
Models such as those of MADRI and NREL, and DOE best practices offer hope for standardization but, to date, standardization progress continues unevenly at various levels of jurisdictional implementation. Progress at the state level can be determined by visiting www.eere.energy.gov/de/state_reg_activities.html and the DOE provides the status of its latest research online at www.eere.energy.gov/de/interconnection_activities_issues.htmll. Several states have determined that managing interconnection policy at the utility level is unworkable and have developed statewide interconnection standards; however, many others have made little progress toward reducing barriers to DG interconnection.